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Notice

Devon Power LLC, et al.; Order on Compliance Filing and Establishing Hearing Procedures

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Start Preamble Issued June 2, 2004.

Before Commissioners: Pat Wood, III, Chairman; Nora Mead Brownell, and Joseph T. Kelliher

I. Introduction

1. On March 1, 2004, ISO New England Inc. (ISO-NE) submitted a filing in compliance with the Commission's directive in Devon Power LLC, et al. that a locational installed capacity (LICAP) market or deliverability requirements be implemented in New England by June 1, 2004.[1] Installed Capacity (ICAP) obligations are intended to ensure that there is sufficient capacity to supply system peak load under all contingencies taking into account events such as generator outages. In this order, the Commission establishes hearing procedures regarding ISO-NE's filing, and delays the implementation of a LICAP market until the conclusion of those proceedings. The Commission will direct the presiding judge to issue an initial decision by June 1, 2005. The Commission will defer implementation of the LICAP proposal, as modified in this order, until January 1, 2006. The Commission believes that deferring implementation until then will not only allow for a comprehensive examination of the issues at hearing but will also allow for completion of needed infrastructure upgrades in New England's constrained areas. Consistent with the recent policy on Reliability Compensation Issues, the Commission's goal in establishing these hearing procedures is to arrive at a final LICAP market design that will appropriately compensate generators needed for reliability and attract and retain necessary infrastructure to assure long-term reliability. Along with deferring the implementation date, the Commission directs ISO-NE to file reports updating progress made in the siting, permitting and construction of transmission and generation upgrades within the New England control area, with particular emphasis on progress within Designated Congested Areas (DCAs). ISO-NE is directed to file these reports every 90 days, beginning 90 days after the date of this order.

2. In this order, the Commission agrees with two broad concepts in ISO-NE's proposal. First, the Commission finds it appropriate to establish ICAP regions, but is concerned that the specific regions proposed by ISO-NE do not adequately reflect where infrastructure investment is needed, especially with regard to the constrained area of Southwest Connecticut (SWCT). Based on the analytical approach to Reliability Compensation Issues established in the May 6, 2004 PJM Order [2] , the Commission believes that a separate ICAP region for SWCT may be appropriate, and is considering revising ISO-NE's proposal to incorporate a separate SWCT region. Accordingly, this order directs ISO-NE to submit a further filing addressing whether the Commission should revise ISO-NE's proposal to create a separate import-constrained ICAP region for SWCT. Additionally, ISO-NE has indicated that an ICAP region cannot be a subset of an energy load zone. The Commission acknowledges this potential problem, and finds that the institution of a separate energy load zone for SWCT in advance of the implementation of LICAP may be appropriate, as it would send more appropriate price signals and more appropriately distribute reliability costs to those who benefit from them. Thus, the Commission also institutes an investigation and paper hearing in Docket No. EL04-102-000 regarding whether a separate energy load zone should be created for SWCT, and whether it should be implemented in advance of the implementation of LICAP.

3. Second, the Commission agrees with the overarching concept of a demand curve, but finds that more information is necessary to appropriately set the parameters of the demand curve for each ICAP region and is establishing a hearing for that purpose. For example, ISO-NE has proposed a methodology that may understate the level of capacity that may be transferred between ICAP regions. The Commission finds that, as a result, ISO-NE has not justified its proposed method for calculating the Capacity Transfer Limits (CTLs). The hearing established by the Commission, in addition to determining the demand curve parameters, shall also determine the proper method for calculating CTLs, the appropriate method for determining the amount of Capacity Transfer Rights (CTRs) to be allocated, and the proper allocation of CTRs.

4. Until LICAP is implemented, the Commission will extend the Peaking Unit Safe Harbor (PUSH) mechanism, and will consider reliability-must-run (RMR) contracts to ensure that market participants are appropriately compensated for reliability services in the short-term. This order benefits customers by ensuring that there is sufficient generation available in New England to meet current and long-term needs.

II. Background and Procedural History

A. Procedural History

5. This proceeding began on February 26, 2003, when Devon Power LLC, Middletown Power LLC, Montville Power LLC, Norwalk Power LLC and NRG Power Marketing Inc. (collectively NRG) filed, pursuant to section 205 of the Federal Power Act (FPA),[3] four cost-of-service RMR agreements covering 1,728 MW of generating capacity located within Connecticut and the SWCT DCAs. These agreements were negotiated between NRG and ISO-NE in accordance with New England Power Pool (NEPOOL) Market Rule 17.3 to provide compensation for generating units (and associated reliability projects) necessary for reliability in SWCT and Connecticut. NRG contended in its filing that the recently-approved New England Standard Market Design (NE-SMD) market would not provide Start Printed Page 33002adequate compensation to the units covered by the contracts.

6. On March 12, 2003, NRG filed an emergency motion seeking expedited issuance of an order accepting the RMR agreements for filing. In that motion, it contended that without assurance of cost-recovery, needed maintenance projects on the generating units could not be completed before the summer peak season. On March 25, 2003, the Commission issued an order accepting only a portion of the RMR agreements, which allowed NRG to collect funds for needed summer maintenance through a tracking mechanism administered by ISO-NE.[4]

7. The April 25 Order addressed the entirety of the RMR agreements. In that order, the Commission rejected the RMR agreements, and allowed collection of only going-forward maintenance costs through the tracking mechanism approved in the March 25 Order. In so doing, the Commission expressed concerns about the effect RMR contracts have on the competitive market, and stated that ISO-NE, “rather than focusing on and using stand-alone RMR agreements, should incorporate the effect of those agreements into a market-type mechanism.” [5] Pursuant to section 206 of the FPA,[6] the Commission directed revisions to NEPOOL Market Rule 1 to lessen the need for RMR agreements. These revisions allowed low-capacity factor generating units operating in DCAs to increase their bids to recover their fixed and variable costs, and allowed the energy bids of peaking units to determine the locational marginal price (LMP) by creating the PUSH bidding mechanism. The Commission also eliminated the CT Proxy mechanism for mitigation. Additionally, the Commission directed ISO-NE “to file no later than March 1, 2004 for implementation no later than June 1, 2004, a mechanism that implements location or deliverability requirements in the ICAP or resource adequacy market * * * so that DCAs may be appropriately compensated for reliability.” [7] In its order on rehearing, the Commission affirmed PUSH bidding, and clarified its section 206 finding.[8] During the time-period in which these orders were issued, the Commission also rejected similar RMR contracts filed by PPL Wallingford Energy LLC, reiterating the concerns expressed in the April 25 Order and the revisions directed by that order.[9]

8. In early 2004, NRG returned to the Commission to again seek RMR agreements for the Devon, Montville and Middletown generating units. NRG also asked the Commission to extend the tracking mechanism for collecting going forward maintenance costs for an additional year. In an order issued March 22, 2004, the Commission accepted the RMR agreements, set the costs included in the agreements for hearing, and conditioned them to terminate on the day a LICAP market or deliverability requirement is implemented in accordance with the April 25 Order.[10] The Commission reasoned that accepting the agreements for a limited term was appropriate given the poor performance under PUSH of uniquely situated and aging Devon, Montville and Middletown generating units.[11] In an order issued on April 1, 2004, the Commission also accepted an extension of the tracking mechanism for maintenance costs, and conditioned the mechanism to terminate the day a LICAP market or deliverability requirement is implemented.[12] Again, the Commission reasoned that continuing the tracker is a reasonable interim measure until market changes could be put into place.[13] In both orders, the Commission expressed confidence that once the market changes directed in the April 25 Order were implemented, out-of-market arrangements like RMR agreements and cost trackers would no longer be necessary.[14]

B. ISO-NE's Compliance Filing

9. In compliance with the April 25 Order, ISO-NE filed a LICAP proposal on March 1, 2004. New England currently has a non-locational ICAP mechanism in place. In meeting its ICAP requirement currently, a load-serving entity (LSE) may procure resources located anywhere within the NEPOOL control area.[15] However, because of transmission constraints, not all energy produced from qualified ICAP resources can be physically deliverable to all loads in New England.[16] ISO-NE's LICAP proposal would take account of transmission constraints by imposing separate ICAP requirements for each of four regions: Maine (classified as an export-constrained region), Connecticut and Northeastern Massachusetts/Boston (NEMA/Boston) (classified as import-constrained regions), and the remainder of New England (Rest of Pool). The amount of capacity that LSEs in one region could procure from another region would be limited by the CTLs established by the ISO between the two regions. ISO-NE states that the CTLs would be set at levels based on planning criteria that may be below the actual amount of real-time electric flow that the transmission interface is capable of accommodating.

10. Currently, an LSE is required to procure a specified amount of ICAP each month based on its projected peak demand. All LSEs within New England can procure the resources from any units that are eligible to sell ICAP. ISO-NE proposes through the use of a demand curve to move from this set amount of monthly ICAP to an amount that can vary monthly within certain parameters. Additionally, ISO-NE proposes to impose certain limitations, based on the location of the resources, that can be used to satisfy an LSEs obligation to procure ICAP. To implement these restrictions, ISO-NE proposes to use four zones for ICAP. The price of ICAP for each of the four regions would be determined monthly through the interplay of ICAP supply bids and an administratively-determined demand curve in a monthly ISO-administered capacity auction. In essence, the ICAP requirement in a region and the regional ICAP price would be established at the point where supply (as reflected in suppliers' bids) and demand (as reflected in the administratively-determined demand curve) clear. The demand curve is designed to allow for more predictable ICAP revenues and more gradual price movements. It also ensures that the region will compensate ICAP resources above and beyond 100 percent of the current capacity requirement (referred to as the Objective Capability) in New Start Printed Page 33003England, which is 112 percent of peak load.

11. When a demand curve is used to determine LSEs' ICAP obligations, the amount and price of that ICAP will be determined based on the height and slope that is used for the particular demand curve. The design of the demand curve—its height and slope—requires selection of two points. The selection of these points will affect the price and quantity of ICAP that LSEs must procure. The first point sets the ICAP price at the point where average surplus capacity is equal to the cost of new entry. ISO-NE calculated the average surplus as 106.7 percent of the capacity requirement. ISO-NE states that this figure is intended to reflect the average surplus since 1989, when New England became a summer peaking system. ISO-NE believes it is reasonable to assume that, on average, there will be surplus capacity in the electricity market over time. ISO-NE uses $6.66 per kilowatt month, the current ICAP deficiency charge in the current capacity market, as the cost of new entry. The ISO proposes to adjust the demand curve downward to account for infra-marginal revenue from the energy market and ancillary service market. This moves (lowers) the first point lower, from $6.66 per kilowatt month to $4.56 per kilowatt month. ISO-NE derived this amount based on the annual average infra-marginal revenue for a gas turbine over the period of May 1999 through December 2003 which is estimated as $2.10 per kilowatt month.

12. The second point is the point where the price of capacity is equal to zero, which is where the demand curve itself crosses the x axis. ISO-NE set this point at 118 percent of the capacity requirement. ISO-NE selected this value for several reasons. First, it contends that planning studies showed that additional capacity has little impact on system reliability after achieving 18 percent surplus. Second, ISO-NE believes that the demand curve should include all surplus capacity conditions that are likely to occur and that there is little likelihood that the surplus capacity will exceed that level. Finally, ISO-NE asserts that the 118 percent value also makes New England's demand curve consistent with the NYISO's statewide ICAP demand curve.[17] The demand curve is thus constructed by drawing the linear function that intersects the two points. ISO-NE states that the linear demand curve provides a good first approximation of several different functional forms and has as well a moderate slope that may deter the exercise of market power by making it more difficult to withhold output in order to increase price.

13. Finally, the proposed curve becomes horizontal to the left of 95 percent of the capacity requirement. Thus, the ICAP price would be the same for all capacity levels between 0 percent and 95 percent of the capacity requirement. ISO-NE believes that this last feature is unlikely to affect prices.

14. ISO-NE proposes to phase-in the demand curve over five years for import-constrained regions, in part to avoid significant price shocks there.[18] During the phase-in period, prices derived by application of the demand Start Printed Page 33004curve in these constrained sub-regions would be capped at $1.00 per kilowatt month in the first year, and would increase by $1.00 per year to $5.00 in the fifth year. After the fifth year, prices in the four regions would be determined without the use of price caps. The five-year period coincides with the projected completion of key transmission projects in Connecticut and NEMA/Boston which, the ISO believes, provides sufficient time for the development of additional capacity.

15. During the five year transition period, generating units in NEMA/Boston and Connecticut that had capacity factors of 15 percent or less in 2003 and that are needed for reliability would be paid “transition payments” of $5.34 per kilowatt month.[19] A resource would actually receive the transition payment minus the spot auction clearing price for the constrained region. Thus, the transition payment would function as a cap on the revenues above variable costs that a unit would be able to earn. ISO-NE argues that the use of transition payments would allow for the elimination of the PUSH mechanism entirely, and would allow for the phase-out of RMR contracts. A unit that qualifies for the transition payment that is not operating under an RMR contract would receive the transition payment until the end of the phase-in period or until ISO-NE determines the unit is no longer needed for reliability. The costs of the transition payments would be allocated to network load within each ICAP region, the same manner in which the costs of RMR contracts are allocated currently. As a result, ISO-NE states that “one of the unfortunate features of the transition payments is that they cannot be hedged because they are an additional above-market payment needed to maintain reliability.” [20] Thus, a customer in an import-constrained region (NEMA/Boston and Connecticut) would still incur the costs of transition payments even if that customer has contracted bilaterally for ICAP.

16. Under ISO-NE's proposal, a generator selling ICAP would be paid the market clearing price in the region in which the resource is located; a participant serving load would buy ICAP at the market clearing price in the region where the load is located. When the transfer capability between regions limits the ability to import capacity into one region in the ICAP market, the ICAP prices in the two regions would differ. The difference in regional prices represents a type of ICAP congestion charge, similar to the congestion charge that arises when transmission capacity is congested in the spot energy market. ISO-NE proposes to create Capacity Transfer Rights to allow market participants to hedge these ICAP congestion costs. Capacity Transfer Rights in the ICAP market are similar to financial transmission rights (FTRs) in the spot energy market. The holder of a Capacity Transfer Right between two regions would receive congestion revenue—i.e., the difference in ICAP prices—between the two regions, just as the holder of an FTR receives congestion revenue from the spot energy market. ISO-NE proposes to allocate these ICAP congestion revenues to entities holding Capacity Transfer Rights in the export and import constrained regions. Capacity Transfer Rights would be allocated to loads in import-constrained regions (i.e., NEMA/Boston and Connecticut) and to generators in export-constrained regions (i.e., Maine). In addition, Capacity Transfer Rights allocations would be made to original holders of entitlements to municipal utility resources constructed as pool planned units with life-of-the-unit contracts. Pursuant to section 8.9.6 of Market Rule 1, this “special allocation” of Capacity Transfer Rights would be made to certain municipal utility resources constructed as pool planned units in import-constrained regions. Finally, any transmission upgrades not funded through pool transmission rates that result in additional transfer capability that is associated with additional Capacity Transfer Rights would be allocated to the entities that pay for the upgrades.

17. As part of the LICAP proposal, ISO-NE revised Market Rule 1 to include corresponding mitigation provisions. Based on the limited competition situation in the import-constrained ICAP regions, the mitigation measures would apply to all resources in such regions that are authorized to sell capacity. ISO-NE proposes to evaluate and deny requests by participants in import-constrained ICAP regions to cease selling ICAP within New England (delisting).

Chiefly, the resource requesting to cease or reduce its ICAP sales would need to demonstrate that this was an economic decision for that unit. To do so the resource must demonstrate that the expected revenue or the expected cost savings associated with the external sale or lack of a sale will exceed the expected ICAP revenues, applicable transition payments, and other market revenues that the resource would otherwise receive.

18. ISO-NE also proposes conduct and market impact thresholds for the LICAP market in import-constrained ICAP regions.[21] ISO-NE's proposal would employ a conduct and impact test and a reference level-based mitigation scheme. The ICAP reference level could be established in one of three ways: (1) The ISO would be authorized to determine the reference level based on a resource's estimated going-forward costs net of expected market revenues; (2) a resource may submit a proposed reference level with supporting documentation for review by the ISO; or (3) where no reference level is submitted or there is inadequate information to set a level, a default ICAP reference level of $1.00 per kilowatt month, which is intended to roughly account for a resource's costs of providing ICAP rather than being delisted. ISO-NE would utilize a conduct threshold of $1.00 per kilowatt month in import-constrained regions to identify economic withholding and a market impact threshold of $1.00 per kilowatt month.[22] Prior to mitigating a resource's offer, the ISO would attempt to contact the resource owner to provide an opportunity to explain the observed behavior. In the event mitigation is necessary, a default offer is established as the greater of $1.00 per kilowatt month, the ICAP reference level, or the estimated ICAP clearing price in the Rest of Pool region. Modifications have also been made to the energy market mitigation thresholds applicable to units receiving transition payments. In import-constrained regions, such units would be subject to a reduced energy offer price threshold of $12.50/MWh, and tighter start-up and no-load thresholds of 25 percent. These units will also face a tighter operating reserve credit threshold of 50 percent.

19. Finally, ISO-NE states that the submitted proposal is “not intended to be the final word on resource adequacy in New England.” In conjunction with the LICAP process, the ISO initiated a Regional Dialogue, which includes a more general initiative to address Start Printed Page 33005regional resource adequacy and to work toward a long-term solution. This forum includes market participants and state regulators. The ISO recognizes that the current LICAP Proposal may be modified or replaced by a different long-term regional resource adequacy mechanism. Thus, ISO-NE commits to continuing the Regional Dialogue for at least 18 months from the date of implementation to continue to work toward a long-term regional resource adequacy mechanism. ISO-NE will evaluate the performance of LICAP after one year of operation, and eighteen months after implementation will be prepared to file a plan regarding long-term regional resource adequacy in New England that could affirm, modify, augment, or replace the instant proposal.

20. ISO-NE requests that the Commission provide guidance on the issue of what entity should bear the responsibility for longer-term capacity procurement and long-term reliability. ISO-NE states that the Regional Dialogue has not yet produced a consensus as to which entity should be responsible for ensuring long-term resource adequacy. ISO-NE's view is that the state regulatory officials, and the distribution companies within each state regulated by those officials, are best positioned to fulfill this role. ISO-NE believes that Commission guidance on this issue would significantly narrow the issues that must be addressed by New England's stakeholders in the Regional Dialogue.

III. Notice of Filing, Protests, Comments and Interventions

21. Notice of Applicants' filing was published in the Federal Register,[23] with comments, protests or interventions due on or before March 22, 2004. The entities filing timely motions to intervene, or who are parties to this proceeding by virtue of their earlier intervention in this docket and submission of a protest or comments regarding the instant filing, are listed in Appendix A to this order. Several parties filed protests, comments, or motions to reject the filing. These parties are listed in Appendix B to this order.

22. On April 2, 2004, ISO-NE filed a motion for leave to answer. On April 6, 2004, National Grid USA (National Grid) filed a response to certain comments and protests made by other parties, and The Indicated Suppliers (Indicated Suppliers) [24] filed a motion for leave to answer and answer to certain of the comments and protests previously submitted. On April 12, 2004, Consolidated Edison Energy, Inc. (ConEd) filed an answer to ISO-NE's answer. On April 16, 2004, FPL Energy, LLC (FPL) filed a motion for leave to answer and answer to ISO-NE's answer. On April 19, 2004, Calpine Eastern filed an answer to National Grid's response, and PSEG Energy Resources & Trade LLC filed a motion for leave to answer and answer to Indicated Suppliers answer. On April 26, 2004, the Long Island Power Authority (LIPA) filed a motion for leave to respond and response to ISO-NE's answer.

23. Additionally, on April 26, 2004, the New England Suppliers Coalition (Suppliers Coalition) [25] filed a motion to lodge in the record a press release issued by ISO-NE on April 16, 2004 regarding the results of its Gap Request for Proposals (Gap RFP) to procure reliability products and services in SWCT for a four-year period beginning in June 2004. On April 29, 2004, the Connecticut Department of Public Utility Control (CT DPUC) and the Connecticut Office of Consumer Counsel (CT OCC) filed a joint answer in opposition to the motion to lodge. On May 11, 2004, Fitchburg Gas and Electric Light Company and Unitil Energy Systems, Inc. filed a response to the motion to lodge.

24. On May 20, 2004, several entities, including National Grid, NSTAR Electric and Gas Corporation, and various state governmental entities, jointly filed supplemental comments and a motion to lodge.[26] The motion seeks to lodge in the record in this proceeding an Ancillary Services Market Enhancements White Paper prepared by ISO-NE.

IV. Discussion

A. Procedural Matters

25. Pursuant to Rule 214 of the Commission's Rules of Practice and Procedure,[27] 18 CFR 385.214 (2003), the notices of intervention and timely, unopposed motions to intervene serve to make the entities that filed them parties to this proceeding. In addition, several of the entities listed as parties in Appendix A are proper parties to this proceeding by virtue of their previous interventions in the instant docket.[28] Motions to intervene out-of-time were filed by several entities.[29] Pursuant to Rule 214(d) of the Commission's Rules of Practice and Procedure,[30] given the interest of these entities in this proceeding and the absence of any undue prejudice or delay, the Commission finds good cause to grant their untimely, unopposed motions to intervene out-of-time. Rule 213(a)(2) of the Commission's Rules of Practice and Procedure [31] prohibits an answer to a protest and answer unless otherwise ordered by the decisional authority. We will accept the answers filed in the instant proceeding because they provided information that helped us in our decision-making process. Additionally, in the interest of developing a full record for consideration during the subsequent procedures directed in this order, the Commission will grant the motions to lodge filed by the Suppliers Coalition and National Grid, et al.

1. Applicable Statutory Standard of Review

26. As noted above, ISO-NE submitted the instant filing as a compliance filing pursuant to Rule 1907 of the Commission's Rules of Practice and Procedure,[32] in response to the Commission's directive in the April 25 Order to “establish a mechanism implementing location or deliverability requirements in the Installed Capacity * * * or resource adequacy market, in a manner that reduces reliance on Reliability Must Run * * * agreements.” [33] Several entities have raised issues in their comments and protests regarding the propriety of submitting the instant filing as a compliance filing, and whether section Start Printed Page 33006205 [34] or section 206 [35] of the FPA should apply.

27. Several parties question whether ISO-NE properly filed the instant proposal as a “compliance filing.” The CT DPUC and CT OCC, for example, moved to reject the instant filing as an improper compliance filing, arguing that the comprehensive nature of the market changes proposed in the filing, and the rate increase ISO-NE acknowledges may result, should not be approved by the Commission through a compliance filing because to do so would “depriv[e] potential objectors of the protections normally accorded for tariff increases.” [36] They also contend that ISO-NE's filing is an improper compliance filing under 18 CFR 154.203(b) (2003) [37] because it proposes to increase rates, which they argue the April 25 Order did not authorize. United Illuminating (UI) similarly states that the transitional payments included in the instant proposal amount to a new rate, which it argues cannot be proposed and approved through a compliance filing.

28. Additionally, many of the parties to this proceeding generally raise the issue of whether ISO-NE should have submitted the instant filing under section 205 or section 206 of the FPA. Of the entities raising this issue, most contend that section 206 should apply. CT DPUC and CT OCC, for example, contend that the only possible basis for the instant filing is section 206, noting that ISO-NE does not have exclusive rights to make a section 205 filing and that the Commission's original direction to make a compliance filing was issued pursuant to section 206. Several other parties, including the Attorneys General of Massachusetts and Rhode Island, the Massachusetts Division of Energy Resources and Rhode Island Commission, and the New Hampshire Office of Consumer Advocate similarly contend that the standards of section 206 should apply to the instant proceeding.[38]

29. Commission Response. The Commission will apply the standards of section 206 of the FPA to the instant proceeding. In the April 25 Order the Commission directed revisions to NEPOOL Market Rule 1 “pursuant to section 206 of the Federal Power Act.” [39] Specifically, the Commission directed ISO-NE to file “a mechanism that implements location or deliverability requirements in the ICAP or resource adequacy market * * * so that capacity within DCAs may be appropriately compensated for reliability.” [40] In the July 24 Order on rehearing, the Commission clarified that it was taking action under section 206 of the FPA, formally stating that it “found that Market Rule 1 * * * created an unjust and unreasonable result, requiring a revision in the rule to solve these problems.” [41] In light of these findings, the Commission finds it appropriate to continue to apply the standards of section 206 in its consideration of the instant compliance filing.

30. Applying the standard of section 206 of the FPA, the issues here are whether the current market rules for ICAP in New England are “unjust, unreasonable, unduly discriminatory or preferential,” and whether new market rules approved or ordered by the Commission are just and reasonable.[42] As noted above, the Commission has already satisfied the first requirement in this proceeding, finding in the April 25 Order and July 24 Order that Market Rule 1 as it then existed “created an unjust and unreasonable result.” As discussed in more detail below, ISO-NE's proposal must be modified to achieve a just and reasonable long-term solution. Therefore, in the interim the Commission will retain the PUSH mechanism and allow for the filing of RMR contracts where justified until the LICAP market is implemented. The Commission finds that this provides a just and reasonable method of solving the Reliability Compensation Issues present in New England.

31. Additionally, we are not persuaded by the contention that the instant filing is an improper compliance filing. First, given the use of the section 206 procedures in this case, the Commission has not deprived any party of an opportunity to comment or protest, contrary to the assertions of CT DPUC and CT OCC. Notice of the ISO-NE's filing was published in the Federal Register, and a large number of parties submitted written comments or protests at the invitation of that notice. The Commission has carefully considered all of the comments and protests, and as a result has provided substantial due process to all the parties before it, in accordance with section 206 of the FPA. Furthermore, we do not accept the assertions of CT DPUC and CT OCC, among others, that the instant filing is an improper compliance filing because of its comprehensive nature and possibility for increased rates. The Commission rule cited by CT DPUC requiring that compliance filings “include only those changes required to comply with the order,” and prohibiting such filings from including “other rate or tariff change filings,” is inapplicable to the present proceeding.[43] Additionally, we note that here, ISO-NE was directed to file “a mechanism that implements location or deliverability requirements in the ICAP or resource adequacy market.” [44] The tariff and rate changes included in the filing, while extensive, are directly related to the directive, and are not separate rate or tariff changes. Therefore, rejection of the filing is not warranted.

B. Analysis of ISO-NE's Proposal and Commission Response

32. The Commission agrees with two broad concepts: ICAP regions and the use of a demand curve. The Commission rejects the transition mechanism, directs ISO-NE to submit a further filing addressing whether the Commission should revise its proposal to create an additional ICAP region for SWCT, establishes an investigation and paper hearing regarding the establishment of a separate SWCT energy load zone in advance of LICAP, and establishes a hearing before an Administrative Law Judge regarding the parameters of the demand curve and related issues. As a result of these changes we will delay full implementation of the LICAP market until the conclusion of these proceedings. We anticipate that this will permit implementation of LICAP in New England by January 1, 2006. We Start Printed Page 33007discuss our reasoning for this decision in the analysis that follows.

33. In the PJM Order, the Commission outlined an analytical approach it intends to follow in addressing Reliability Compensation Issues such as those at issue in this proceeding. This process begins with posing the question: does this organized market exhibit material short-term or long-term Reliability Compensation Issues? [45] Short-term Reliability Compensation Issues relate principally to the appropriate compensation for units that are needed for reliability and are subject to mitigation with the result that the units are receiving non-compensatory revenue impacting their ability to provide service. Long-term Reliability Compensation Issues relate principally to local capacity shortages identified in the organized market's reliability-based planning process resulting from the reasonably expected retirement of units or the need for new infrastructure that is not anticipated to be installed.

34. If the inquiry shows that the organized market exhibits material Reliability Compensation Issues, the next step is to evaluate whether market design improvements can be implemented that will work to resolve the issues. Conversely, if the inquiry does not find that the organized market exhibits material Reliability Compensation Issues and the issue is of sufficiently narrow scope, then significant focus on general design issues is not required and targeted approaches (such as unit specific contracts or compensation schemes) may be appropriate. Such demonstration must include a showing that the revenue produced by the proposed solution is adequate to actually solve the problem at hand and that the proposed solution includes safeguards to prevent the unwarranted exercise of market power beyond the recovery of such necessary revenue.

35. In the case of ISO-NE, the Commission determines that it exhibits both short and long-term Reliability Compensation Issues. These issues have been clearly demonstrated in the filings for RMR contracts in NEMA/Boston and SWCT. These contracts were filed by ISO-NE because these units were not able to earn sufficient revenues through the markets to justify their continued operation. In NEMA/Boston these reliability concerns have been limited to the need for RMR contracts for a limited number of specific units that are needed to satisfy reliability because of the location of these units. The RMR contracts were filed because specific units were needed, not because there were inadequate resources within NEMA/Boston in general. As such, reliability compensation appears to be more of a short-term issue in NEMA/Boston.[46]

36. In contrast, the reliability problems in SWCT have involved the need to retain all or nearly all units within this region to maintain reliable service.[47] Many of these units are old and inefficient and are unable to receive sufficient funds through the operation of the markets to justify their continued operation. Thus, the concerns regarding SWCT are long-term in nature.

37. Under the policy developed in the PJM Order, the next step is to examine whether market design improvements can be implemented within New England to resolve these issues.[48] As discussed further below, we believe that while the record is unclear on whether market design changes could resolve the issues within NEMA/Boston, market design changes could be implemented to resolve the Reliability Compensation Issues within SWCT.[49] One market design change that was suggested in the PJM Order was the use of locational markets for installed capacity or operating reserves for the constrained area. The Commission believes that designing and implementing a well-functioning and equitable LICAP market represents a significant step in resolving Reliability Compensation Issues. In fact, we have identified locational installed capacity as a market design feature that can serve as a solution.[50] The New England market as a whole appears to have adequate capacity. At the same time, nearly all existing units within SWCT are needed for reliability. Additionally, ISO-NE has also recently conducted a Request for Proposals to obtain additional resources in SWCT. Thus, the use of a local capacity market would better reflect the value of capacity in SWCT than the existing system-wide capacity market. Thus, the use of a locational capacity market could be a solution to the Reliability Compensation Issues in SWCT.

38. ISO-NE has filed a proposal that contains a locational capacity market. The Commission believes that ISO-NE's LICAP proposal has elements that would help resolve the Reliability Compensation Issues in New England. In particular, the concept of a demand curve for installed capacity has merit. Additionally, the use of separate prices for capacity in different areas in New England also moves toward a LICAP market. However, as discussed further below, we find that there are factual questions regarding certain elements of this proposal that need to be further explored at hearing.

39. The Commission finds that there are other elements of ISO-NE's proposal that do not satisfy the criteria outlined in the PJM Order. Specifically, the Commission is concerned that certain elements of ISO-NE's proposal rely on non-market solutions to attempt to resolve these Reliability Compensation Issues and that the regions chosen for the LICAP may not match the specific areas where capacity is constrained within New England. Thus, the regions may not sufficiently value capacity within the constrained areas.

40. First, under the Commission's policy, the market design changes should provide sufficient revenues to satisfy the Reliability Compensation Issues. The Commission cannot reasonably determine that ISO-NE's proposed transition payments together with its proposed five-year phase-in of LICAP will yield sufficient revenues for all generating resources during the phase-in period. Under the proposal, ISO-NE would cap the price that would be available to generators in the constrained areas during the phase-in period. In the first year, the price caps would be $1.00 per kilowatt month. This would not be a sufficient amount to resolve the Reliability Compensation Issues within the constrained areas.

41. However, since the price caps would result in lower prices than those generated by the demand curve, ISO-NE also proposes to pay a transition payment to low load-factor units within the constrained areas. The transition payments are set at $5.34 per kilowatt month for the first five years of the market.[51] The $5.34 figure is based on the average cost of PUSH units in Connecticut and NEMA/Boston. There was significant debate among intervening parties over whether or not this aspect of the proposal provides sufficient revenues. Since the payment is based on an average of the PUSH limits, it may not work to provide Start Printed Page 33008sufficient revenues for all generating units. In particular, the units within SWCT had a much higher cost than those located within NEMA/Boston. Since ISO-NE would still allow RMR contracts for individual units, its proposal may only appeal to those units whose costs were at or below the average PUSH limits. For other more expensive units, it would appear that they would still have the option of obtaining RMR contracts.

42. More importantly, the transition payments create an unhedgeable cost to LSEs in import-constrained regions. In other words, the transition payments would be a non-market cost to LSEs within the import constrained areas. The Commission stated in the PJM Order that ideally, the market should encourage LSEs to engage in long-term bilateral contracting and locational requirements for ICAP could promote such contracting.[52] However, ISO-NE's transition payment proposal will not adequately promote bilateral contracting and in fact may discourage it. ISO-NE's proposal requires those parties who have contracted bilaterally for ICAP to pay the same transition payments as those LSEs that have not contracted bilaterally for ICAP. Thus, the transition payments do not provide adequate incentives for LSEs to contract for supplies locationally to reduce their total costs. The allocation method will also penalize LSEs that have already entered into bilateral arrangements. The Commission does not believe that a non-market solution such as the transition payments is consistent with the policy developed for Reliability Compensation Issues in the PJM Order. Therefore, the Commission does not believe that ISO-NE's proposal provides a market solution that is consistent with the criteria discussed in the PJM order.

43. The Commission is also concerned that the proposed configuration of import-constrained regions may not be appropriate. ISO-NE proposes a single ICAP region for the entire State of Connecticut. This is consistent with its current market design. However, there is a clear and extensive record that demonstrates a distinction, in terms of reliability, between SWCT and the other parts of Connecticut. This record includes reports and filings that detail the difficulties SWCT faces with regard to reliability. For example, ISO-NE concluded that “the existing southwestern Connecticut electric power system does not meet North American Electric Reliability Council (NERC), Northeast Power Coordinating Council (NPCC) and NEPOOL reliability performance standards.” [53] Furthermore, when ISO-NE developed DCAs with special measures for mitigating market power, it classified SWCT as a DCA distinct from the remainder of Connecticut. ISO-NE provides no justification for failing to acknowledge this distinction in its LICAP proposal. The Commission is concerned that ISO-NE's proposal may not adequately recognize the value of resources within SWCT. It also may result in customers in other parts of Connecticut subsidizing customers within SWCT. Therefore, the Commission is not convinced that a single import-constrained area in Connecticut would produce incentives to locate infrastructure in SWCT, the location where it is most needed. Additionally, it may not provide adequate compensation for resources to remain in SWCT, thus failing to satisfy Reliability Compensation requirements of the Commission's policy.

44. Thus, the Commission finds that while a market design solution would provide a reasonable solution to the Reliability Compensation Issues in SWCT, ISO-NE's proposal must be revised to meet that objective.

45. Consequently, the Commission will adopt a market design solution for New England but will defer implementation of the LICAP proposal until the conclusion of the hearing proceedings established in this order. The delay in implementation will allow time for a hearing to resolve the contested issues regarding the LICAP mechanism. In addition, it will also provide a firm timeline for implementation and thus an incentive to participants in the constrained areas to develop resources or transmission alternatives to help mitigate the rate impact of a LICAP mechanism. In the interim, to compensate resources within the constrained areas, the Commission will continue the operation of the PUSH mechanism to reduce the impact of the mitigation measures on units that run infrequently. Additionally, the Commission will continue the use of RMR contracts for units that are needed for reliability but cannot earn sufficient revenues from the markets to continue operation.

46. Finally, the Commission believes that there may be merit in the early implementation of a separate energy load zone for SWCT.[54] The use of the entire State of Connecticut may diminish the price signals in the constrained portion of the state. Since the cost of RMR contracts will also be paid by all load within the zone, the use of a larger zone may result in some customers in Connecticut subsidizing others. Therefore, as discussed further below, the Commission will institute an investigation and paper hearing in Docket No. EL04-102-000 regarding whether a separate energy load zone should be created for SWCT, and whether it should be implemented in advance of the implementation of LICAP. ISO-NE is directed to address whether a separate energy load zone should be established for SWCT and implemented before LICAP.

47. The Commission addresses specific comments, protests, and issues related to the proposed LICAP mechanism in the paragraphs which follow.

1. ICAP Regions

48. As noted above, ISO-NE's proposal includes four regions for purposes of setting ICAP prices: Maine, Connecticut, NEMA/Boston, and the remainder of New England. Connecticut is defined as an import constrained ICAP region equal to the Connecticut load zone. However, some parties argue that SWCT should be its own import-constrained ICAP region. LIPA argues that ISO-NE has not justified why Connecticut and SWCT were combined as one import-constrained region. Moreover, LIPA argues that studies used during consideration of this proposal clearly justify creating a separate region for SWCT. LIPA asserts that maintaining Connecticut as a single constrained region distorts the market signals that LICAP is intended to send. LIPA argues that additional ICAP resources need to be located within SWCT to truly satisfy reliability concerns. PPL Parties argue that, in establishing an import-constrained region for Connecticut as a whole, ISO-NE's proposal would equate the locational value of a unit in severely constrained SWCT with the locational value of a unit in the relatively unconstrained areas in the rest of Connecticut, thus undervaluing units in the most needed locations and providing no incentive to direct new generation entry to the most critical sites.

49. Commission Response. The two geographic areas in New England that have reliability problems are NEMA/Boston and SWCT, which currently are identified as DCAs. While ISO-NE's Start Printed Page 33009proposal separates NEMA/Boston into its own region, there is significant evidence that SWCT is the most heavily constrained area within New England. Recently, the state of Connecticut has stressed the need to focus on potential reliability problems in SWCT. In a July 3, 2002 report, the CT DPUC stated that “inadequate local generation and transmission congestion in SWCT make the region vulnerable to reliability problems in the event that demand is higher than expected or generation units or transmission lines serving the area are unavailable.” [55] In December 2003, the Connecticut Siting Council (CSC) submitted a ten-year forecast of loads and resources within the State which reported that “some sub-regions such as SWCT are threatened with supply deficiencies and voltage instability problems due to insufficient transmission and inadequate resources within the region.” [56] That report also notes that “[i]t is increasingly important for resources to be strategically located on the grid to ensure electric supply can technically and economically serve pockets of high demand.” [57] Additionally, in its comments in this proceeding, NRG points to the Gap RFP, through which ISO-NE procured reliability services which it could call on during possible emergency situations. In this submittal ISO-NE stated that “as in years past, the ISO expects that the combination of electric load and operating reserve requirements in SWCT will exceed the resources available for the sub-region in the summer of 2004.” [58] NRG also notes a recent ISO-NE-commissioned study which concluded that while New England has sufficient capacity available to it in aggregate, the capacity is not optimally located in the areas where it is needed for reliability. Specifically, SWCT is identified in that study as an area where the amounts of capacity are verging on deficient. The study concluded that capacity shortages in constrained areas of New England are most severe in SWCT, and are much more severe than NEMA/Boston.

50. Based on the assessments conducted by the state of Connecticut and ISO-NE, as well as the comments and protests considered by the Commission in the instant proceeding, the Commission is concerned that the ICAP regions proposed by ISO-NE do not adequately reflect where infrastructure additions are needed most. The infrastructure problem in SWCT has been accurately defined, but the proposal submitted by ISO-NE does not appear to the Commission to create the incentives needed to remedy this problem. Grouping SWCT with the rest of the State unfairly burdens Connecticut customers that are not affected by limitations in transmission capacity in SWCT. With this proposal, for example, capacity would be priced the same outside of SWCT as it is in SWCT. This price signal sends the inaccurate message to potential investors that capacity is needed just as much in outside of SWCT as it is needed in SWCT. Additionally, the Commission fails to understand why NEMA/Boston, as a DCA in New England, is classified as a separate LICAP region while SWCT is not.

51. Based on the foregoing, the Commission believes that a separate SWCT ICAP region may be appropriate, to ensure that the LICAP market in New England achieves the goals we outlined in the PJM Order. As a result, ISO-NE is directed to submit a further filing in Docket No. ER03-563-030 addressing whether the Commission should revise its proposal to create a separate import-constrained ICAP region for SWCT. The Commission will require ISO-NE to submit this filing within 30 days from the date of this order, and will permit responses to ISO-NE's submittal to be filed within 21 days from the date ISO-NE makes its filing. Furthermore, the Commission notes that ISO-NE states in its answer that creating a separate ICAP region for SWCT would also involve creating a separate load zone in SWCT for pricing energy. As noted above, the Commission believes that creating this separate load zone could have significant benefits, even in advance of the implementation of LICAP. As a result, pursuant to section 206 of the FPA, the Commission will institute an investigation and paper hearing in Docket No. EL04-102-000 regarding whether a separate energy load zone should be created for SWCT, and whether it should be implemented in advance of the implementation of LICAP. The Commission will require ISO-NE to address the issue of whether a separate energy load zone should be created for SWCT, and whether it should be implemented in advance of the implementation of LICAP, in a filing to be made within 30 days from the date of this order in Docket No. EL04-102-000. The Commission will issue notice of ISO-NE's filing, and permit interested parties to intervene and file responses within 21 days of the date ISO-NE makes its filing.

52. In cases where, as here, the Commission institutes a section 206 proceeding on its own motion, section 206(b) requires that the Commission establish a refund effective date that is no earlier than 60 days after publication of notice of the Commission's investigation in the Federal Register, and no later than five months subsequent to expiration of the 60-day period. We will establish the statutorily-directed refund effective date, in this context for the determination of regions in Connecticut, 60 days after publication in the Federal Register of this order initiating the Commission's investigation in Docket No. EL04-102-000. In addition, section 206 requires that, if no final decision has been rendered by that date, the Commission must provide its estimate as to when it reasonably expects to make such a decision. Given the times for filing identified in this order, and the nature and complexity of the matters to be resolved, the Commission estimates that it will be able to reach a final decision by October 31, 2005.

2. Demand Curve and Capacity Transfer

53. As described above, ISO-NE's proposed demand curve is structured on the basis of two points. While there are numerous protests addressing the parameters of the demand curve, there appears to be very little objection to the concept of a demand curve. In fact, many parties advocate a downwardly sloping demand curve. The protests focus on the precise points that ISO-NE proposed to determine the height and slope of the demand curve. In general, representatives of LSEs and State government entities recommend changing the parameters in a way that would lower ICAP prices.[59] By contrast, representatives of suppliers either support the ISO-NE's parameters or recommend parameters that would raise ICAP prices.[60] For example, ConEd favors raising the point at which the Start Printed Page 33010ICAP price becomes zero to 127 percent of Objective Capability.[61]

54. Some parties, including Indicated Suppliers and ConEd, urge the Commission to implement a Compromise Proposal that was approved in the New England stakeholder process by the Markets Committee and received a majority (58 percent) vote from the Participants Committee.[62] The major difference between the Compromise Proposal and the proposal ultimately filed by ISO-NE is that the former included price floors for the Maine and Rest of Pool regions as well as higher price caps and transition payments for generators in constrained areas, both of which would result in higher ICAP payments in the relevant areas. The Compromise Proposal is supported by HQ Energy Services, ConEd, and the Electric Power Supply Association (EPSA).

55. A group consisting of state governmental entities and transmission owners in NEMA/Boston (Mass. AG et. al.) filed another alternative proposal, also using a demand curve. Under this option, the locational feature of the ISO's proposal would be removed, and ICAP resources would be bought and sold through a single, region-wide market instead of separate locational markets.[63]

56. National Grid asserts that LICAP will not alleviate the fundamental constraints that cause the formation of load pockets and argues that the best way to ensure transmission adequacy would be to mandate a deliverability requirement across the transmission grid. In its answer, ISO-NE did not take a position on the merits of a deliverability requirement, noting that there is nothing about the LICAP proposal that would preclude the adoption of a deliverability requirement if the stakeholders and the Commission conclude that it would be beneficial.

57. Commission Response. We agree with ISO-NE's overarching proposal to use a demand curve, and in particular a downward sloping demand curve, as part of the eventual LICAP mechanism in New England. The Commission finds that implementing a demand curve for ICAP will allow ISO-NE's market design to more closely resemble that of the neighboring ISO (NYISO) and to contribute to the elimination of seams between the two. NYISO currently uses a demand curve to set ICAP prices within its territory. NYISO also has locational requirement for procuring ICAP for LSEs located within New York City and Long Island. The adoption of LICAP by ISO-NE would make its market design more consistent with that in effect in NYISO.

58. While we agree with ISO-NE's concept of a sloped demand curve, we find that ISO-NE has not justified the specific parameters it proposes to determine the slope and height of the demand curve. Commenters raise important questions about these parameters that cannot be resolved based on the record in this proceeding. These questions include: If the height of the curve is to be determined, at least in part, by the cost of new entry, what is the cost of new entry, and does that cost vary among the regions? What is a reasonable estimate of the net inframarginal revenues that could be expected from the energy markets, and does that revenue vary among regions? Should the ICAP price reflect the cost of new entry (net of inframarginal energy revenues) when capacity equals (i) Objective Capability, (ii) the historical average level of capacity relative to Objective Capability, or (iii) some other level? At what capacity level should the ICAP price fall to $0? Should the height and slope of the curve be based on the cost of new entry or on other factors, such as an estimate of the reliability value to loads of alternative levels of capacity, and if the latter, what are reasonable estimates of such reliability values? To what extent do the parameters of the demand curve used by the NYISO affect the ability of New England to attract ICAP capacity, and thus, how should the New York parameters affect the parameters for New England?[64] The Commission finds that the use of price floors, as proposed in the Compromise Proposal, are non-market mechanisms that may not send accurate price signals and may artificially inflate ICAP prices in regions with more-than-adequate capacity levels.

59. Based upon the foregoing, and the Commission's own preliminary analysis, we find that the parameters underlying the proposed demand curve have not been shown to be just and reasonable, and may be unjust, unreasonable, unduly discriminatory or preferential, or otherwise unlawful. Accordingly, while we agree with the concept of a demand curve for the ICAP market, we will set the parameters which will determine the slope and height of that curve for hearing procedures for the purpose of determining the just and reasonable ICAP demand curve for each ICAP region. These hearing procedures will be limited to one year to ensure that the specific parameters of the curve are in place in advance of the January 1, 2006 implementation date of the LICAP market, so that market participants can adequately prepare. The Commission will direct the presiding judge to ensure that an initial decision or settlement is issued by June 1, 2005. The presiding ALJ should structure the hearing schedule accordingly.

60. Certain parties have argued that the Commission should adopt a deliverability requirement for ICAP supplies in New England rather than adopt a LICAP.[65] The Commission directed ISO-NE to develop “a mechanism that implements location or deliverability requirements in the ICAP or resource adequacy market” in the April 25 Order.[66] ISO-NE elected to pursue a locational ICAP mechanism in the near-term for, among other things, reasons of costs.[67] A reliable and extensive transmission system without substantial load pockets is important for a deliverability requirement. The current transmission system in New Start Printed Page 33011England does not allow for deliverability across the entire region, and the Commission has been given no indication as to when the New England system would be physically capable of supporting a deliverability requirement. The Commission believes that the development of a transmission system that effectively eliminated import- and export-constrained regions in New England is an admirable objective. However, we recognize that the development of such infrastructure will take time and concerted effort. ISO-NE has indicated that acceptance and implementation of the LICAP proposal would not preclude the introduction of a deliverability requirement at some point in the future. The Commission would welcome a proposal to implement a deliverability requirement in New England, if and when ISO-NE and New England stakeholders collectively choose to pursue that. Until such time, the Commission believes that the LICAP proposal, with the modifications discussed in this order represents an appropriate response to the Reliability Compensation Issues we currently observe in New England.

i. Level of Capacity Available for Transfer Between Regions

61. As noted earlier, ISO-NE proposes to establish CTLs between ICAP regions at levels below the actual amount of real-time electric flow that the transmission interfaces are capable of accommodating. NECPUC, Mass. AG et al. and others object to ISO-NE's proposal to underestimate the amount of capacity that can be delivered into the import-constrained regions.

62. In its answer, ISO-NE argues that increasing its proposed CTLs would be detrimental to the market. ISO-NE asserts that setting transfer limits while recognizing excess capacity may depress prices and undervalue the resources within the import-constrained region, which decreases the likelihood of either new generation entry or transmission expansion in the constrained region.

63. Commission Response. The commenters' criticisms of ISO-NE's proposed method for determining CTLs raise issues that the Commission will set for hearing to determine the costs and benefits of understating the amount of transmission transfer capability that is actually available to procure ICAP resources across regions. The presiding judge is directed to consider the appropriate method for calculating CTLs in the hearing that we establish in this order.

ii. Capacity Transfer Rights

64. As noted earlier, ISO-NE proposes to allocate a portion of the Capacity Transfer Rights across the NEMA/Boston Import Interface (the transmission interface between the NEMA/Boston and Rest of Pool) to municipal utilities in NEMA/Boston that have ownership entitlements in pool planned units in Rest of Pool. TransCanada Power Marketing Ltd. (TransCanada) and Indicated Suppliers disagree with the proposal. TransCanada argues that this special award of Capacity Transfer Rights has no direct relationship to the actual load served by the municipal utilities in NEMA/Boston and improperly presumes that the municipal utilities should be given priority rights over the limited transfer capacity into the region. Indicated Suppliers argue that a “special allocation” of Capacity Transfer Rights should be extended to other participants with long-term contracts for capacity located outside of constrained areas. Conversely, Massachusetts Municipal Wholesale Electric Company and Reading Municipal Light Department (MMWEC and Reading) urge the Commission to ensure that the “special” Capacity Transfer Right allocation be maintained as essential to any determination that the LICAP proposal is just and reasonable. MMWEC and Reading believe that any imposition of LICAP in New England should include a proper recognition of prior investments in pool planned units and should minimize the impact of a new regulatory paradigm upon those long-term investments.

65. Duke Energy North American, LLC (Duke) seeks to clarify that generators that have increased transfer capability on constrained ICAP interfaces prior to the proposal's effective date would be allocated Capacity Transfer Rights as described in section 8.9.4 of the proposal. Additionally, MMWEC and Reading have uncovered two problems that they assert must be addressed. First, MMWEC and Reading believe that ISO-NE's proposed text of section 8.9.6 reads as though the allocation is to the pool planned unit itself. Second, in reviewing Table 1 to section 8.9.6, which lists the municipal utilities receiving special Capacity Transfer Rights, MMWEC and Reading believe that it does not include the Wakefield Municipal Gas & Light Department, which is a NEMA-based, municipal utility and thus entitled to a share of whatever Capacity Transfer Rights based on pool planned units allocation is accepted or approved by the Commission.

66. Commission Response. Capacity Transfer Rights should be allocated in a way that allows the benefits of Capacity Transfer Rights to be received by those who ultimately pay the costs of the transmission system, including market participants that have funded specific upgrades that increased transfer capacity. That is because Capacity Transfer Rights depend on the amount of transmission capacity in New England, so those paying for the transmission capacity should receive its benefits. We endorsed a similar policy with respect to the allocation of Auction Revenue Rights (ARRs) in New England in an order issued December 20, 2002.[68] ARRs entitle the holder to receive the revenues from the sale at auction of FTRs, which (like Capacity Transfer Rights) depend on the amount of transmission capacity in New England.

67. This is not to say, however, that Capacity Transfer Rights must always be allocated to those who directly pay for the embedded costs of New England's transmission grid. Indeed, in the December 20, 2002 order, we accepted a proposal to allocate ARRs to “Congestion Paying LSEs,”[69] even though not all Congestion Paying LSEs pay transmission costs. We did so because we expected that such Congestion Paying LSEs would pass on the benefits of ARRs to the retail loads that they serve, and these retail loads would ultimately also bear the costs of the transmission system.[70] Similarly, we would find it acceptable to allocate Start Printed Page 33012Capacity Transfer Rights either to those who directly pay the fixed costs of the New England transmission system or to those who serve the retail loads that ultimately pay these fixed costs. However, as a general matter, we would not find it acceptable to allocate Capacity Transfer Rights to generators in Maine that have not contributed to the cost of the transmission system, although it would be acceptable to allocate Capacity Transfer Rights to generators in Maine (or in other regions of New England) that have contributed to the cost of the transmission system.

68. The Commission is unable to determine whether ISO-NE's proposed allocation of Capacity Transfer Rights is consistent with this principle, and thus we will set for hearing the issue of the allocation of Capacity Transfer Rights. In particular, the hearing should determine whether, and to what extent, particular generators in Maine have paid for transmission upgrades that increase transfer capability with the rest of the pool and thus should be assigned corresponding Capacity Transfer Rights. The hearing should also determine the appropriate allocation of Capacity Transfer Rights for those LSEs, including municipal utilities, who are the original holders of life-of-the-unit contracts for pool planned units. The hearing should also address the extent to which LSEs outside of the import-constrained regions should be allocated Capacity Transfer Rights.

3. Implementation Date and Transition Mechanisms

69. ISO-NE's proposal relies on two transition mechanisms: (1) a transition payment of $5.34 per kilowatt month to be paid to those units in constrained sub-regions which had 2003 capacity factors of 15 percent or less, and (2) a series of price caps in import-constrained regions over a five-year phase-in period.[71] After the fifth year (ending May 2009), the caps would expire, leaving prices in all sub-regions determined by the downward-sloping demand curve. During the phase-in period, the constrained sub-regions would clear at the higher of the cap or the price in the Rest of Pool sub-region. Numerous parties argue against the implementation of these transition mechanisms.

70. Commission Response. For the reasons that follow, the Commission will reject the proposed transition mechanisms and the proposed transition payments. Instead, the Commission directs that the LICAP mechanism, when implemented by January 1, 2006, as directed by this order, become effective without the use of the phase-in or transition provisions.

71. Several intervenors argued that the Commission should defer implementation of the LICAP proposal to accommodate the 18 month Regional Dialogue process that ISO-NE proposed. The Commission will defer implementation until January 1, 2006 but does not believe it would be appropriate to direct ISO-NE and stakeholders to develop a modified LICAP proposal in the Regional Dialogue process. The Commission directed ISO-NE and its stakeholders to develop a mechanism in the April 25 Order. However, these discussions did not produce consensus on a mechanism. Further, the Commission does not believe that ISO-NE's proposal, if implemented without modification, would resolve New England's Reliability Compensation Issues. Therefore, the Commission does not believe it is appropriate to delay action on ISO-NE's proposal to allow additional time for stakeholder discussions. Rather, the Commission believes that the approach taken in this order, which is to identify the date when LICAP will be implemented and establish proceedings to address remaining issues, will better address the situation. We believe that deferring the implementation of LICAP until January 1, 2006 will allow participants in import-constrained regions an opportunity to move toward the development of needed infrastructure prior to the realization of full LICAP rates. Infrastructure projects are proceeding in both Connecticut and NEMA/Boston and a deferral of LICAP should provide an incentive for timely completion of the addition of infrastructure in these areas. The Commission finds a delay in the implementation date of LICAP is preferable to the transition mechanisms proposed by ISO-NE, which were in large part simply out-of-market arrangements. To monitor the progress of infrastructure development, the Commission will require ISO-NE to submit a report to the Commission every 90 days, beginning 90 days from the date of this order, updating the progress made in the siting, permitting and construction of transmission and generation upgrades within the New England control area, with particular emphasis on progress within DCAs. While we recognize that ISO-NE is not the entity responsible for siting and permitting decisions, it is in the best position to keep the Commission informed regarding the progress of infrastructure development in New England.

72. Until implementation, the New England market will continue to operate under the existing ICAP rules, as well as the existing PUSH mechanism, and any existing RMR agreements. If additional RMR contracts are needed or require renewal, the Commission expects the parties to those contracts and ISO-NE to negotiate, and file under section 205 of the FPA, one-term contracts, with the single term expiring when the LICAP mechanism is implemented. The Commission will consider the need for these contracts, and the justness and reasonableness of the rates proposed therein, as they are filed. While using current ICAP rules in the period between now and January 1, 2006 is not where the Commission envisioned the NEPOOL capacity market to be, the stakeholder process did not result in a mechanism that is just and reasonable and can be implemented in the near term. Our decision to delay implementation and rely on the existing rules and RMR agreements will produce a just and reasonable result in the short-term, while allowing changes to be made and infrastructure to be built, which will allow the basic LICAP framework we approve in this order to produce a just and reasonable result in the long-term.

4. Miscellaneous Issues

i. Mitigation Measures

73. The mitigation measures proposed by ISO-NE did not elicit many comments or protests. LIPA argues that ISO-NE's proposed tests for de-listing units—which would require that the de-listing resource demonstrate that expected revenues or cost savings associated with the external sale or de-listing would exceed the expected revenues the resource would otherwise receive—will inhibit transactions between markets.[72] LIPA asserts that there are multiple reasons for a resource to de-list beyond short term revenue tests, such as lower revenues that result from a longer-term capacity commitment or the perceived stronger creditworthiness of a commitment with an external party. PSEG requests that the Commission reject this mitigation measure, arguing that it would allow Start Printed Page 33013ISO-NE to employ a market power mitigation measure without any finding that the proposed actions would have a significant market impact, as with other mitigation rules.

74. Commission Response: The Commission will accept the mitigation measures proposed by ISO-NE with respect to reference level calculations and conduct and impact thresholds but rejects the de-listing measures. Under ISO-NE's proposal, participants seeking to de-list any resource in an import-constrained ICAP region would be required to demonstrate to ISO-NE that the expected revenue associated with sale of ICAP outside of the NEPOOL control area or the expected cost savings attributable to de-listing will exceed the expected ICAP revenues and other market revenues that the resource would receive if it did not de-list. Where unable to make such a demonstration, ISO-NE proposes to have the authority to deny any delisting request. The Commission finds that ISO-NE should not have the authority to second-guess a generator's business decisions regarding whether to sell into the ICAP market and thus rejects this provision. Moreover, since participation in the ICAP market is voluntary, it is not appropriate to prohibit or limit a generator's decision to cease participating in the ICAP market. The Commission will not accept additional measures that are designed for the energy markets.[73] These measures are primarily designed for units that receive transition payments. The Commission is eliminating transition payments. Consequently this proposed measure will not apply.

ii. Role of the ISO

75. ISO-NE has sought guidance on the issue of what entity should bear the responsibility for longer-term capacity procurement and long-term reliability. The Commission addressed a similar issue in the PJM Order. As a general matter, the Commission believes that the market design of the RTO or ISO should be structured to send appropriate price signals and thus provide an incentive for load to procure capacity to meet their long-term requirements. Through the regional transmission planning process and the determination of the appropriate ICAP requirements for LSEs, ISO-NE's role is to establish the infrastructure levels needed for the system to operate reliably. However, it is LSEs that have the primary responsibility for longer-term capacity procurement and obtaining sufficient supplies to ensure long-term reliability. The role of the RTO or ISO in this process is, at most, to provide a backstop to these efforts. However, the Commission is concerned that if an RTO or ISO negotiates contracts to procure power, it may assume an interest in market prices which could sacrifice its independence and change its incentives. Thus, the Commission would only consider a backstop role for the ISO or RTO after a showing that appropriate changes to the market design had been implemented and had not proven sufficient to solve the problem or that market design changes are infeasible.

iii. Local Scarcity Pricing and a Co-Optimized Market for Energy and Operating Reserves

76.0 We noted in the PJM Order that “recognizing short-term scarcity of operating reserves may be a valuable component of an overall market design. * * * The inclusion of such a feature could also in part reduce generator reliance upon unit specific agreements in situations where units needed for reliability are not recovering their costs and are eligible for a contract.”[74] High locational prices in ISO-NE's spot markets can signal when and where there is a need for additional capacity. ISO-NE recently added a scarcity pricing feature to spot market rules for its markets whereby spot market prices would be increased, at times up to $1,000/MWh, during periods of scarce supplies, when New England as a whole is experiencing shortages of operating reserves.[75] This pricing feature is valuable because it sends a strong signal when capacity is tight that capacity is needed. The resulting high prices also provide revenue to owners of generation capacity that is operated during a limited number of hours of very high demand, and thus, may reduce the need for RMR contracts for units that otherwise receive insufficient market revenue to support their operations.

77. ISO-NE's scarcity pricing is triggered only by New England-wide reserve shortages. However, because of transmission constraints, scarcity conditions may arise in smaller areas within New England (reflected in an inability to fully meet local reliability requirements) even when capacity throughout New England as a whole is sufficient to meet load and operating reserves. Any scarcity conditions that arise in smaller areas within New England do not trigger the scarcity pricing provisions. This feature may limit the ability of spot market prices to signal the need for additional capacity in local areas. Modifying ISO-NE's scarcity pricing mechanism so that prices would automatically increase in local areas that experience local scarcity conditions might improve the market's price signals and increase the ability of generators needed for local reliability to recover their costs in the market. Such a modification could complement and reinforce a LICAP mechanism. For example, local scarcity pricing could further encourage LSEs in a capacity-tight region to enter into contracts with resources in order to hedge against possible high spot energy prices. However, local scarcity pricing may be easier to implement in the presence of a locational operating reserves spot market that is co-optimized with the spot energy market, which would recognize operating reserve requirements in local areas. ISO-NE does not currently operate a locational operating reserves market, but it has indicated that it is planning to implement co-optimized energy and reserves markets in 2005.

78. We wish to ensure that a broad array of options is considered for addressing New England's locational needs for capacity. Therefore, we will require ISO-NE to consider the advantages and disadvantages of modifying its existing scarcity pricing mechanism so that it would trigger as a result of local scarcity conditions. ISO-NE's process should include stakeholder input and consideration of stakeholder proposals. We will require ISO-NE to file a report on this investigation and the results of the stakeholder process within 180 days of this order. If ISO-NE files to implement co-optimized energy and reserves markets within 180 days of this order, it may elect to include the report on scarcity pricing as part of the filing.

The Commission orders:

(A) Pursuant to the authority contained in and subject to the jurisdiction conferred upon the Federal Energy Regulatory Commission by section 402(a) of the Department of Energy Organization Act and by the Federal Power Act, particularly section 206 thereof, and pursuant to the Commission's Rules of Practice and Procedure and the regulations under the Federal Power Act (18 CFR Chapter I), a public hearing shall be held in Docket No. ER03-563-030 concerning the appropriate methodology for determining capacity transfer limits between ICAP regions, the amount and Start Printed Page 33014allocation of capacity transfer rights for purposes of the LICAP market, and the parameters of the demand curve that will apply in each ICAP region, as discussed in the body of this order.

(B) A presiding judge, to be designated by the Chief Judge, shall, within 15 days of the date of this order, convene a conference in Docket No. ER03-563-030, in a hearing room of the Federal Energy Regulatory Commission, 888 First Street, NE., Washington, DC 20426. Such conference shall be held for the purpose of establishing a procedural schedule. The presiding judge is authorized to establish procedural dates, and to rule on all motions (except motions to dismiss) as provided in the Commission's Rules of Practice and Procedure and is directed to issue an initial decision on or before June 1, 2005.

(C) ISO-NE is directed to submit an additional filing in Docket No. ER03-563-030 within 30 days from the date of this order addressing whether the Commission should revise its proposal to create a separate import-constrained ICAP region for SWCT, as discussed in the body of this order.

(D) The parties to Docket No. ER03-563-030 will be permitted to file responses to the additional filing of ISO-NE directed in Paragraph (C) within 21 days from the date ISO-NE makes such filing.

(E) Pursuant to the authority contained in and subject to the jurisdiction conferred upon the Federal Energy Regulatory Commission by section 402(a) of the Department of Energy Organization Act and the Federal Power Act, particularly section 206 thereof, and pursuant to the Commission's Rules of Practice and Procedure and the regulations under the Federal Power Act (18 CFR Chapter I), the Commission hereby institutes an investigation in Docket No. EL04-102-000 regarding whether a separate energy load zone should be created for SWCT, and whether it should be implemented in advance of the implementation of LICAP, as discussed in the body of this order.

(F) ISO-NE is hereby directed to address whether a separate energy load zone should be created for SWCT, and whether it should be implemented in advance of the implementation of LICAP, in a filing to be made in Docket No. EL04-102-000 within 30 days from the date of this order, as discussed in the body of this order.

(G) Any interested person desiring to be heard in the proceedings in Docket No. EL04-102-000 should file a notice of intervention or motion to intervene with the Federal Energy Regulatory Commission, 888 First Street, NE., Washington, DC 20426, in accordance with Rule 214 of the Commission's Rules of Practice and Procedure (18 CFR 385.214) within 21 days of the date ISO-NE makes the filing directed in Paragraph (F) above.

(H) Responses to the submission of ISO-NE filed pursuant to Paragraph (F) above may be submitted within 21 days of the date ISO-NE makes its filing.

(I) The refund effective date in Docket No. EL04-102-000 will be 60 days from the date of publication of this order in the Federal Register.

(J) ISO-NE's requested implementation date of June 1, 2004 is rejected, and delayed until the conclusion of the proceedings established herein or by January 1, 2006, as discussed in the body of this order.

(K) ISO-NE is directed to file a report every 90 days, beginning 90 days from the date of this order, updating progress made in the siting, permitting and construction of transmission and generation upgrades within the New England control area, with particular emphasis on progress within Designated Congested Areas.

(L) ISO-NE is directed to file a report on its investigation of adding a local scarcity triggering mechanism to its existing scarcity pricing mechanism with 180 days of the date of this order, as discussed in the body of this order.

(M) The Secretary shall promptly publish a copy of this order in the Federal Register.

Start Signature

By the Commission. Commissioner Kelliher concurring with a separate statement attached. Commissioner Kelly not participating.

Linda Mitry,

Acting Secretary.

Issued June 2, 2004.

End Signature

Appendix A

American Forest & Paper Association

American National Power, Inc.

Associated Industries of Massachusetts

Calpine Eastern Corporation and Calpine Energy Services, LP

Central Maine Power Company

Central Vermont Public Service Corporation

Attorney General for the State of Connecticut

Connecticut Department of Public Utility Control

Connecticut Office of Consumer Counsel

Connecticut Municipal Electric Energy Cooperative

Consolidated Edison Energy, Inc.

Coral Power, L.L.C.

Dominion Resources, Inc., Dominion Energy Marketing, Inc., and Dominion Nuclear Connecticut, Inc.

Duke Energy North America, LLC

Electricity Consumer Resource Council and American Iron and Steel Institute

The Energy Consortium

Entergy Nuclear Generating Company, LLC and Entergy Nuclear Vermont Yankee, LLC

Electric Power Supply Association

Fitchburg Gas and Electric Light Company and Unitil Energy Systems, Inc.

FPL Energy, LLC

HQ Energy Services (U.S.), Inc.

Independent Energy Producers of Maine

Indicated Suppliers

Industrial Energy Consumer Group

Interconnection Rights Holders Management Committee

Keyspan-Ravenswood, LLC

Long Island Power Authority and LIPA

Maine Public Advocate

Maine Public Utilities Commission

Attorney General of Massachusetts, Attorney General of Rhode Island, and the Rhode Island Division of Public Utilities and Carriers

Massachusetts Department of Telecommunications and Energy

Massachusetts Municipal Wholesale Electric Company and Reading Municipal Light Department

Milford Power Company, LLC

Morgan Stanley Capital Group

National Grid USA

NEPOOL Industrial Customer Coalition

New England Conference of Public Utilities Commissioners

New England Consumer-Owned Entities

New England Demand Response Providers

New Hampshire Office of Consumer Advocate

Northeast Utilities Service Company

NRG Devon Power LLC, Middletown Power LLC, Norwalk Harbor LLC and NRG Power Marketing

New York Independent System Operator

NSTAR Electric and Gas Corporation

NXGEN, Inc.

Potomac Economics, Ltd.

PPL Energy Plus, LLC and PPL Wallingford Energy LLC

PSEG Energy Resources and Trade LLC

Strategic Energy LLC

TransCanada Power Marketing Ltd.

United Illuminating Company

Vermont Department of Public Service

Vermont Electric Power Company

Wellesley Municipal Lighting Plant

Appendix B

Protests

Calpine Eastern Corporation and Calpine Energy Services, L.P.

Attorney General of the State of Connecticut

Connecticut Department of Public Utility Control

Connecticut Office of Consumer Counsel

Connecticut Municipal Electric Energy Cooperative

Consolidated Edison Energy, Inc.

Duke Energy North America, LLC

FPL Energy, LLC

HQ Energy Services (U.S.), Inc.

Independent Energy Producers of Maine

Long Island Power Authority and LIPA

Maine Public Utilities Commission

Attorney General of Massachusetts, Attorney General of Rhode Island, and the Rhode Island Division of Public Utilities and Carriers Start Printed Page 33015

Associated Industries of Massachusetts

Massachusetts Department of Telecommunications and Energy

Massachusetts Municipal Wholesale Electric Company and Reading Municipal Light Department

Milford Power Company, LLC

NEPOOL Industrial Customer Coalition

New England Conference of Public Utilities Commissioners

New Hampshire Office of Consumer Advocate

NRG Devon Power LLC, Middletown Power LLC, Norwalk Harbor LLC and NRG Power Marketing

NSTAR Electric and Gas Corporation

PPL Energy Plus, LLC and PPL Wallingford Energy LLC

PSEG Energy Resources and Trade LLC

United Illuminating Company

Vermont Department of Public Service

Vermont Electric Power Company

Wellesley Municipal Lighting Plant

Comments

Coral Power, L.L.C.

Dominion Resources, Inc., Dominion Energy Marketing, Inc., and Dominion Nuclear Connecticut, Inc.

Electricity Consumer Resource Council and American Iron and Steel Institute

The Energy Consortium

Electric Power Supply Association

Fitchburg Gas and Electric Light Company and Unitil Energy Systems, Inc.

Independent Energy Producers of Maine

Industrial Energy Consumer Group

Keyspan-Ravenswood, LLC

Maine Public Advocate

National Grid USA

New England Consumer-Owned Entities

New England Demand Response Providers

Northeast Utilities Service Company

Potomac Economics, Ltd.

TransCanada Power Marketing Ltd.

Devon Power LLC, et al.

Issued June 2, 2004

Joseph T. Kelliher, Commissioner concurring:

I am writing separately to explain my views on the implementation date of a locational installed capacity (LICAP) market in New England.

I concur with the order that a LICAP market should not be implemented before January 1, 2006. The purpose of establishing a LICAP market is to ensure there is adequate electricity generation in New England, particularly in Southwest Connecticut and Northeastern Massachusetts/Boston. The record shows that there is insufficient generation in these two areas of New England.

For a LICAP market to be effective, the transmission system must be strong enough to permit generation interconnections. Unfortunately, the transmission system in Southwest Connecticut is notoriously weak, and at present cannot accommodate significant generation additions.

It is important to give New England enough time to make necessary transmission upgrades. The order provides for an initial decision from an administrative law judge by June 1, 2005 to define the appropriate methodology for determining capacity transfer limits between ICAP regions, the amount and allocation of capacity transfer rights for purposes of each LICAP market, and the parameters of the demand curve that will apply in each ICAP region. The order also sets an implementation date for LICAP markets of January 1, 2006. I would have deferred selecting a specific implementation date for LICAP markets until after the initial decision. That would have given the Commission the flexibility to select an appropriate date for implementing LICAP based on an understanding of the progress—if any—towards strengthening the transmission grid in Southwest Connecticut and Northeastern Massachusetts/Boston.

Until implementation of a LICAP market, the Commission will extend the Peaking Unit Safe Harbor (PUSH) mechanism, and consider reliability-must-run contracts to ensure generators receive just and reasonable compensation. Experience with the PUSH mechanism has proved disappointing, and reliability-must-run contracts may be the superior means to assure just and reasonable compensation during the interim.

Joseph T. Kelliher,

Commissioner.

End Preamble

Footnotes

1.  Devon Power LLC, et al., 103 FERC ¶ 61,082 (2003) (April 25 Order).

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2.  PJM Interconnection, L.L.C., 107 FERC ¶ 61,112 (2004).

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4.  Devon Power LLC, et.al., 102 FERC ¶ 61,314 (2003) (March 25 Order).

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5.  Id. at P 29.

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7.  April 25 Order at P 37.

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8.  Devon Power Company et al., 104 FERC ¶ 61,123 (2003) (July 24 Order).

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9.  See PPL Wallingford Energy LLC, 103 FERC ¶ 61,185 (2003); PPL Wallingford Energy LLC et al., 105 FERC ¶ 61,324 (2003).

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10.  Devon Power LLC et al., 106 FERC ¶ 61,264 (2004) (March 22 Order).

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11.  Id. at P 18.

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12.  Devon Power LLC et al., 107 FERC ¶ 61,002 (2004) (April 1 Order).

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13.  Id. at P 10.

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14.  See March 22 Order at P 28; April 1 Order at P 10.

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15.  Under certain circumstances that are not relevant to this discussion, an LSE may also procure ICAP from resources that are not located within New England.

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16.  In particular, there are more generation resources within Maine than are necessary to meet local requirements within Maine or that can be exported from Maine. Additionally, ISO-NE has identified two areas Southwest Connecticut and Northeastern Massachusetts as being load pockets. Because of transmission constraints, there are limitations on the amount of power that can be imported into these regions. As a result, at times resources located within the load pockets must be used to meet demand in the load pockets.

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17.  New England's capacity requirement is set at 12 percent above peak, while New York's is 18 percent above peak. New York's demand curve sets the price of capacity to zero at a surplus capacity value of 12 percent above Objective Capability, while New England's sets the value at 18 percent above. In each case the requirement is approximately 1.12 multiplied by 1.18, or about 1.32.

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18.  ISO-NE states that, over the first two years, the phase-in reduces the impact on Connecticut and NEMA/Boston by approximately $250 million and $215 million, respectively.

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19.  The $5.34 figure is based on the average cost of service approved by the Commission for PUSH units located in Connecticut and NEMA/Boston.

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20.  Transmittal Letter of ISO-NE at 31.

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21.  Under these measures, mitigation could occur if a unit bid a predetermined amount above a reference price based on historical bids by the unit (conduct test) and if these bids were accepted it would result in a predetermined increase in the market price (impact test). To be mitigated, a unit's bids would have to be sufficiently high and have a sufficient impact on the market price to fail to satisfy both the conduct and impact test.

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22.  The ISO may impose the ICAP Default Offer in an import-constrained region if the offer exceeds the reference level by the applicable threshold and the conduct would affect the market-clearing price by the applicable threshold.

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23.  69 FR 11,611 (2004).

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24.  The Indicated Suppliers include: American National Power, various Entergy parties, Millennium Power Partners, various Mirant parties, and USGen New England.

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25.  The New England Suppliers Coalition includes: American National Power, Inc, Consolidated Edison Energy Inc., Duke Energy North America, LLC, Energy Nuclear Generation Company, FPL Energy, LLC, Mirant Americas Energy Marketing, L.P., Mirant New England, Inc, Mirant Kendall, LLC, Mirant Canal, LLC, Milford Power Company, LLC, NRG Energy, Inc., PPL EnergyPlus, LLC, PPL Wallingford, LLC, PSEG Energy Resources & Trade LLC, and USGen New England, Inc.

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26.  The entities joining in the supplemental comments and motion to lodge are: National Grid, NSTAR Electric and Gas Corporation, Maine Office of the Public Advocate, New Hampshire Office of Consumer Advocate, Rhode Island Office of the Attorney General, Rhode Island Division of Public Utilities and Carriers, Associated Industries of Massachusetts, Strategic Energy L.L.C., and Vermont Electric Power Company.

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28.  See New England Power Pool/ISO New England Inc., et al., 87 FERC ¶ 61,244 (1999).

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29.  These entities include Calpine Eastern Corporation and Calpine Energy Services, L.P., the NRG Companies, and the Energy Consortium.

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31.  18 CFR 385.213(a)(2) (2003).

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33.  Transmittal Letter of ISO-NE at 1.

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36.  See Joint Motion to Reject, Protest, and Request for Hearing and Suspension of Rates of CT DPUC and CT OCC at 6-7.

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37.  18 CFR 154.203(b) provides that compliance filings made by gas pipelines “must include only those changes required to comply with the order [and] * * * may not be combined with other rate or tariff change filings,” and further states that “[a] compliance filing that includes other changes or that does not comply with the applicable order in every respect may be rejected.” This regulation applies only to filings made pursuant to section 4 of the Natural Gas Act and thus does not apply to filings made by public utilities such as ISO-NE.

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38.  See, e.g., Motion to Intervene and Protest of the Attorney General of Massachusetts, Attorney General of Rhode Island, and the Rhode Island Division of Public Utilities and Carriers at 7; Protest by Attorney General of Massachusetts, Attorney General of Rhode Island, Massachusetts Division of Energy Resources, New Hampshire Office of Consumer Advocate, Rhode Island Division of Public Utilities and Carriers, Associated Industries of Massachusetts, NSTAR Electric and Gas Corporation, National Grid USA, Vermont Electric Power (in part) and Strategic Energy LLC (in part) (hereinafter Mass. AG et al.) at 7-8.

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39.  April 25 Order at P 33.

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40.  Id. at P 37.

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41.  July 24 Order at P 33.

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43.  18 CFR 154.203(b) only applies to filings and proceedings held pursuant to section 4 of the Natural Gas Act. See 18 CFR 154.1(a) (2003); see also Cambridge Electric Light Company, 95 FERC ¶ 61,162, 61,523 n. 9 (2001).

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44.  April 25 Order at P 37.

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45.  PJM Order at P 16.

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46.  See Exelon New Boston, LLC, 106 FERC ¶ 61,191 (2004).

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47.  See March 22 Order; see also ISO New England LLC, 105 FERC ¶ 61,236 (2003).

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48.  See PJM Order at P 17.

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49.  PJM Order at P 17. It is not clear if the issues in NEMA are sufficiently narrow in scope so that a market design solution targeted to NEMA is necessary to resolve the Reliability Compensation Issues. If the problem is related to a need for a limited number of specific resources for reliability, unit specific contracts may be more appropriate.

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50.  Id. at P 19.

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51.  ISO-NE states: “The transition payment will be reduced each month by the locational capacity-clearing price in the appropriate import constrained sub-region so that the transition payment will function as a capped price.” Transmittal Letter of ISO-NE at 29.

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52.  PJM Order at P 20.

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53.  See, ISO-NE, Volume I of Southwestern Connecticut Electric Reliability Study, presented by the ISO-NE Southwestern Connecticut Working Group, December 2002.

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54.  ISO-NE, in its answer, states that in order to create an ICAP region covering SWCT, ISO-NE states that Connecticut must also be divided into separate energy load zones, with one load zone for energy covering SWCT.

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55.  See DPUC Investigation into Possible Shortages of Electricity in Southwest Connecticut During Summer Periods of Peak Demand, July 3, 2002.

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56.  See CSC Review of the Connecticut Electric Utilities' Ten-Year Forecasts of Loads and Resources, December 23, 2003.

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58.  See Motion to Intervene and Comments of ISO-NE, Docket No. ER04-335-000.

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59.  For example, the New England Conference of Public Utility Commissioners (NECPUC) argues that the point on the demand curve where the price covers the net cost of a new peaker (net of inframarginal energy revenues) should be where capacity is just equal to New England's Objective Capability, which is less than ISO-NE's proposal. NECPUC also advocates setting the point where the ICAP price becomes zero (i.e., where the demand curve crosses the horizontal axis) at 110 percent of Objective Capability, rather than at 118 percent of Objective Capability as proposed by ISO-NE.

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60.  Motion to Intervene, Protest, Objection to Proposed Effective Date, and Request for Hearing of NECPUC at 20-21.

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61.  Motion to Intervene and Protest of ConEd Energy at 2-3.

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62.  A proposal requires a two-thirds majority to receive approval from the Participants Committee.

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63.  The price at which generators would recover the cost of a peaking unit (net of energy market revenues) would be set at 100% of Objective Capability, rather than at 106.7 percent as proposed by ISO-NE. Second, the MW level at which the ICAP price would become $0 (i.e., where the demand curve crosses the horizontal axis) would be reduced to 112 percent of Objective Capability. This proposal would also impose additional requirements on generators. Finally, the proposal would also adopt locational operating reserve markets and fully integrate new generators receiving ICAP payments into the regional grid.

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64.  We note, for example, that the highest price for capacity in New England under ISO-NE's proposal (after the transition period has expired) would be about $9.28/kW-month, which is the price when the market clears at less than 95 percent of Objective Capability. By contrast, prices higher than $9.28 cleared the capacity market in the monthly auctions held by the NYISO for the summer 2004 capability period for Long Island and New York City. Specifically, the price for capacity on Long Island for June 2004 was $9.50, while the prices for capacity in New York City ranged between $11.16 and $11.42 for the months of June through October. (See, http://www.nyiso.com/​market/​icap_​auctions/​summer_​2004/​june_​2004_​auction.pdf.) The hearing should explore whether regions such as SWCT, which is near New York City and Long Island, would be able to attract adequate capacity under ISO-NE's proposed parameters if prices in New York City and Long Island exceed the highest possible price in New England.

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65.  A deliverability requirement would require the construction of sufficient transmission to ensure that resources are deliverable to load throughout the region. Only units that satisfy the deliverability requirements would be able to sell ICAP in New England.

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66.  “We will direct ISO-NE to file no later than March 1, 2004 for implementation no later than June 1, 2004, a mechanism that as discussed in the September 20 Order.” April 25 Order at P 37.

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67.  In its transmittal letter, ISO-NE concluded that, in the short term, a deliverability requirement is not practical or cost-effective due to the substantial investments, construction, and timeline involved. Transmittal Letter of ISO-NE at 3.

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68.  New England Power Pool and ISO New England, Inc., 101 FERC ¶ 61,344 at P 55-64 (2002).

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69.  A Congestion Paying LSE is defined as “a Participant or Non-Participant that is responsible for paying for Congestion Costs as a Transmission Customer paying for Regional Network Service or Long-Term Firm Point-to-Point Transmission Service under the NEPOOL Tariff, unless such Transmission Customer has transferred its obligation to supply load in accordance with NEPOOL System Rules, in which case the Congestion Paying LSE shall be the Participant supplying the transferred load obligation.” See id. at P 55.

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70.  In New England, Transmission Customers taking Regional Network Service or Long-Term Firm Point-to-Point Transmission Service pay rates that recover fixed transmission costs. However, not all Congestion Paying LSEs are such Transmission Customers who pay for transmission costs. Some Congestion Paying LSEs have taken over the responsibility for serving load from a Transmission Customer, while the Transmission Customer retains the responsibility to provide Transmission Service to the load and to pay the associated transmission costs. The Commission found it acceptable to allocate ARRs to Congestion Paying LSEs that do not pay transmission costs because the retail loads served by the Congestion Paying LSEs ultimately paid the transmission costs, and because the Commission expected that the benefits of the ARRs allocated to the LSEs would be flowed through to these same retail loads. Thus, the retail loads that ultimately paid transmission costs would also receive the benefits of the ARRs.

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71.  The cap during the first year (June 2004 through the end of May 2005) would be $1.00, and would increase by $1.00 each year (i.e., a cap of $2.00 in year 2; $3.00 in year 3; $4.00 in year 4; and $5.00 in year 5).

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72.  PSEG Energy Resources and Trade LLC (PSEG) argues that ISO-NE's market design should permit partial de-listing of capacity resources. In the NE-SMD Order, the Commission addressed the issue of partial de-listing of resources. See New England Power Pool and ISO New England, Inc., 100 FERC ¶ 61,287 at P 110 (2002).

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73.  ISO-NE proposes to subject units receiving transition payments to a reduced energy offer price threshold and tighter start-up and no-load thresholds. Such units would also face tighter operating reserve credit thresholds.

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74.  PJM Order at P 82-83.

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75.  See ISO New England Inc., 104 FERC ¶ 61,130 (2003).

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[FR Doc. 04-12921 Filed 6-10-04; 8:45 am]

BILLING CODE 6717-01-P