[Federal Register Volume 68, Number 85 (Friday, May 2, 2003)]
[Notices]
[Pages 23448-23454]
From the Federal Register Online via the Government Publishing Office [www.gpo.gov]
[FR Doc No: 03-10816]


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DEPARTMENT OF ENERGY

Federal Energy Regulatory Commission

[Docket No. ER03-563-000]


Devon Power LLC, et al.; Order Accepting, in Part, Requests for 
Reliability Must-Run Contracts and Directing Temporary Bidding Rules

Issued April 25, 2003.
    Before Commissioners: Pat Wood, III, Chairman; William L. Massey 
and Nora Mead Brownell.
    1. In this order, we will deny the requests filed by Devon Power 
LLC, Middletown Power LLC, Montville Power LLC, Norwalk Power LLC 
(collectively Applicants) and NRG Power Marketing Inc. (NRG) for 
Reliability Must-Run (RMR) contracts that recover the full cost-of-
service, and instead permit these RMR agreements to recover only 
certain going-forward maintenance costs. In addition, we direct ISO New 
England, Inc. (ISO-NE) to establish temporary bidding rules that permit 
selected RMR peaking units to raise their bids so as to recover their 
fixed and variable cost-of-service through the market, and change, as 
necessary, the market rules to allow these bids (when accepted) to set 
the energy price. These temporary rules are to remain in effect until 
ISO-NE makes a filing and places into effect certain changes to the 
market prior to the 2004 summer peak season as identified below. This 
action will benefit the New England market by establishing locational 
prices that more accurately reflect the value of additional supply, 
transmission, and/or demand response resources into the marketplace.

Background

    2. On September 20, 2002, the Commission issued an order accepting 
a new Standard Market Design for New England (NE-SMD) which replaces 
New England Power Pool's (NEPOOL) former market rules with a new Market 
Rule 1.\1\ Appendix A to Market Rule 1 includes an approach for 
monitoring and mitigating market power.\2\ The Commission stated that 
this approach identifies resources potentially exercising market power 
by comparing their current energy supply offers with a proxy for what 
the resources would bid if they had no market power. The Commission 
added that when a supply offer significantly exceeds the proxy

[[Page 23449]]

(referred to as the reference price), an investigation is triggered 
that may result in mitigation. The Commission further contended that 
the degree to which a supply offer may exceed the reference price 
before triggering an investigation depends on whether transmission 
constraints affect a unit's dispatch or whether it is located in a 
chronically constrained area identified as a Designated Congestion Area 
(DCA).
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    \1\ New England Power Pool and ISO New England, Inc., 100 FERC ] 
61,287(2002) (September 20 Order).
    \2\ September 20 Order at PP 16-18.
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    3. In the September 20 Order, the Commission noted that units 
within DCAs which must be run at certain times to alleviate 
transmission congestion, and so are likely to have market power at 
those times, may be classified as RMR units. The Commission accepted a 
CT Proxy proposal that sets a DCA threshold to serve as a safe harbor 
bid.\3\ The Commission added that if RMR units are not adequately 
compensated under the CT Proxy safe harbor price, they may apply for a 
special compensation arrangement under specified RMR contracts. Exhibit 
4 to Appendix A of Market Rule 1 contains a pro forma cost-of-service 
agreement. The Commission also found that RMR fixed costs represent the 
costs of relieving congestion in specific regions and therefore should 
be reflected in the cost of energy in those regions.\4\
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    \3\ The CT Proxy proposal, described in Appendix A to Market 
Rule 1, is based on the estimated price to recover the annual cost 
of a new combustion turbine unit (CT) for the region over the number 
of hours it is expected to operate during the year (estimated to be 
the number of hours the DCA is constrained). This CT Proxy serves as 
the safe harbor bid for all units in the DCA.
    \4\ September 20 Order at P 61.
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    4. On December 20, 2002, the Commission issued an order \5\ that 
granted in part and denied in part requests for rehearing filed in 
response to the Commission's September 20 Order. The Commission also 
accepted two compliance filings made in response to the September 20 
Order.
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    \5\ New England Power Pool and ISO New England, Inc., 101 FERC ] 
61,344(2002) (December 20 Order).
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    5. In the December 20 Order, the Commission approved the CT Proxy 
proposed by ISO-NE that the CT Proxy price may serve as a safe harbor 
during all hours, and bids that exceed the CT Proxy safe harbor will be 
subject to the mitigation review that applies to transmission-
constrained periods.
    6. Also in the December 20 Order, the Commission reiterated that 
ISO-NE has the authority to negotiate RMR agreements as are needed to 
ensure system reliability. The Commission noted that the conditions 
under which the ISO may enter into RMR agreements are, of necessity, 
flexible in order to meet the changing demands of the markets. The 
Commission expected ISO-NE to exercise vigilance to ensure that only 
those units that are needed to ensure reliability receive RMR 
contracts, and that those contracts will not be in effect indefinitely 
but will be limited to the periods during which the units are needed 
for reliability. The Commission further stated that RMR agreements will 
be filed with the Commission in accordance with the Commission's rules 
and regulations and will be effective on the date approved by the 
Commission.\6\
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    \6\ December 20 Order at P 33.
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    7. On February 26, 2003, the Applicants filed four cost-of-service 
agreements, negotiated between NRG and ISO-NE, that pertain to 
generating units designated by ISO-NE as RMR units. The agreements 
cover 1,728 MW of capacity located within the Connecticut and Southwest 
Connecticut (SWCT) DCAs. Applicants contend that while the effort to 
keep these generators operating arose under the prior NEPOOL rate 
regime, the recently activated NE-SMD market may not adequately allow 
these generating units to recover their investments, due in-part to the 
lack of a locational resource adequacy mechanism and the use of the CT 
Proxy market mitigation mechanism within DCAs.
    8. On March 25, 2003, in response to an emergency motion filed by 
Applicants, the Commission issued an order that allows ISO-NE to begin 
collecting funds that are to be disbursed to the Applicants to perform 
specific maintenance projects so that the units remain available for 
the upcoming summer peak period.\7\
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    \7\ Devon Power LLC, 102 FERC ] 61,314 (2003).
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Notice of Filings, Protests, and Interventions

    9. Notice of Applicants' filing was published in the Federal 
Register, 68 Fed. Reg. 11541 (2003), with comments, protests, or 
interventions due on or before March 12, 2003. Timely motions to 
intervene were filed by PPL Wallingford Energy, LLC; PPL EnergyPlus, 
LLC; Pinpoint Power, LLC; and PG&E National Energy Group LLC.
    10. Timely motions to intervene with protests were filed by ISO-NE, 
the Connecticut Department of Public Utility Control (CT PUC), the 
Connecticut Attorney General's Office (CTAG), Dominion Energy Marketing 
Inc. (DEMI), Connecticut Industrial Energy Consumers (CT IEC), National 
Grid USA (National Grid), Northeast Utilities Service Company (NU), The 
United Illuminating Company (UI), NSTAR Electric & Gas Corporation 
(NSTAR), New England Consumer-Owned Entities (NE COE), and the 
Connecticut Office of Consumer Counsel (CT OCC). NU also filed a 
supplement to its protest.
    11. Timely motions to intervene with comments (or limited comments) 
were filed by NEPOOL, PSEG Companies, and Mirant Americas Energy 
Marketing L.P. On March 25, 2003, KeySpan-Ravenswood LLC (KeySpan) 
filed a motion to intervene out of time. The notices of intervention 
and the timely, unopposed motions to intervene serve to make the 
intervenors parties to this proceeding. See 18 CFR 385.214 (2002). 
Given the early stage of this proceeding and the absence of undue delay 
or prejudice, we find good cause to grant the untimely, unopposed 
intervention of KeySpan and accept their comments. Additionally, the 
Commission rejects a motion filed by DEMI to consolidate this 
proceeding with PPL Wallingford Energy LLC, et al., Docket No. ER03-
421-000, which is currently pending before the Commission.
    12. Applicants, pursuant to Rules 212 and 213 of the Commission's 
Rules of Practice and Procedure, 18 CFR 385.212 and 385.213 (2002), 
filed an answer to the protests filed by NU, CT PUC, NE COE, CT IEC, 
UI, and DEMI on March 12, 2003. Rule 213 of the Commission's Rules of 
Practice and Procedure, 18 CFR 385.213 (2002), generally prohibits the 
filing of an answer to a protest. Accordingly, we are not persuaded to 
allow the Applicants answer and we will reject it.

Discussion of RMR Issues

Demonstrated Need

    13. CT PUC, UI, CTAG, CT IEC, NE COE, National Grid USA (National 
Grid) and NSTAR urge rejection of these agreements by the Commission. 
Intervenors--CTAG, NSTAR--argue that in order to receive approval for 
cost-of-service treatment the prospective generator must show that: (1) 
the unit(s) are needed for reliability; and (2) the unit(s) would be 
retired if no RMR contract were approved. CTAG and NSTAR assert that 
the Applicants have not shown that they intend to retire units in the 
absence of cost-of-service agreements and that the ISO-NE letter does 
not specify a need for the Applicants' units. CTAG states that covering 
NRG's entire Connecticut fleet with these RMR agreements would remove 
40 percent of the generation in SWCT from the market. Furthermore, CTAG 
argues that NRG's Interconnection Agreement with CL&P requires NRG to 
operate its Norwalk and Cos Cob units until fall 2003--well past the 
effective date of the proposed cost-

[[Page 23450]]

of-service agreements--thus effectively ruling out retirements before 
then.\8\
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    \8\ CTAG Protest at 10.
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    14. DEMI, UI, National Grid and CT OCC state that the only evidence 
to support the need for the RMR proposal is a letter from ISO-NE, which 
provides no more detail than stating that largely all of Connecticut's 
existing generation resources are needed for reliability.\9\ NE COE 
emphasizes that ISO-NE did not analyze whether Applicants' cost 
recovery under NE-SMD would enable them to operate and maintain the 
units. CTAG argues that any proposal for cost-of-service rate treatment 
should apply only to generating units that are absolutely necessary, 
not to entire generating fleets. Similarly, CT OCC speculates that some 
of NRG's units may merit RMR status but questions whether NRG's entire 
fleet requires such status.
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    \9\ Attachment 1 to the Applicants' proposal is a letter, dated 
February 26, 2003, from Kevin Kirby of ISO-NE to Joseph M. DeVito of 
NRG Energy, Inc. It states: ``* * * the ISO-NE has conducted a 
reliability assessment for Connecticut for the years 2003 and 2006 
and has determined that absent any transmission improvements or new 
resources, largely all of the existing resources in Connecticut are 
needed for reliability, including the NRG units.''
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    15. Intervenors further submit that the Applicants' proposal fails 
to discuss system conditions that justify the proposed cost-of-service 
agreements and fails to identify potential alternatives. DEMI argues 
that the Commission should require the Applicants to produce evidence 
supporting the ISO's determination and such evidence should identify 
the specific reliability concern, the number of days in which this 
concern is present, as well as the specific manner in which each NRG 
units responds to the reliability need.
    16. UI argues that cost-of-service agreements do not ensure 
generation owners return on investment. UI and others assert that NRG's 
economic hardship is due primarily to its own investment decisions made 
in the competitive marketplace and that retail customers or suppliers 
of standard offer service should not be responsible for poor investment 
decisions. NE COE submits that a more appropriate analysis would 
examine whether the DCA CT Proxy threshold price would be sufficient to 
cover the Applicants' going forward costs, enabling them to operate the 
facilities needed for reliability.

Market Implications

    17. Numerous intervenors--CT OCC, NE COE, CT DPUC, UI, CT IEC, 
CTAG--are concerned that approval of NRG's proposal will create 
incentives for other generation owners to file for cost-of-service 
agreements, which could have ramifications for Connecticut and NEPOOL 
wholesale electric markets. Moreover, several intervenors including 
National Grid argue that having a large percentage of Connecticut's 
generation operating under cost-of-service agreements could compromise 
and mute the price-signals needed to induce the expansion of 
generation, transmission, and demand resources in areas such as 
Southwest Connecticut. CT IEC argues that approval of the agreements 
could significantly increase rates of Connecticut consumers. PSEG 
argues that NRG's proposal will create an ``unlevel'' playing field 
among generators, placing generating units that are not subject to 
cost-based ratemaking at a competitive disadvantage.
    18. PSEG urges the Commission to direct ISO-NE and NEPOOL to file 
on or before June 2003, for implementation as soon as possible, but not 
later than January 1, 2004, market rules establishing locational 
capacity requirements similar to those already in effect in the New 
York ISO.
    19. DEMI states that it was able to reduce its exposure to 
congestion charges through the acquisition of FTRs or other mechanisms 
as were other entities contracted to supply standard offer load for the 
balance of 2003. However, there is no such protection from the costs 
associated with cost-of-service agreements. DEMI argues that this would 
unfairly saddle it and others with costs they did not cause and--given 
that standard offer entities are prohibited from passing the additional 
costs through to load--would not serve to signal new investment. DEMI 
submits that the solution would be for the Commission to consolidate 
this proceeding with Docket No. ER03-421-000 and comprehensively 
address the circumstances that lead to ISO-NE's conclusion that largely 
all generation in Connecticut should be subject to cost-of-service 
agreements.
    20. CT PUC urges the Commission to approve under RMR agreements 
``only an amount sufficient to maintain system reliability''--which 
would only cover deferred and scheduled maintenance outages to ensure 
dispatch availability for the Summer 2003 peak season. CT PUC asserts 
that the costs associated with the major maintenance outage expenses 
should be, on a very short-term basis, socialized through ISO-NE, but 
only to keep the units operating as a resource when needed for 
dispatch. Thus the CT PUC ``urges the Commission to expeditiously grant 
approval to allow ISO-NE to provide NRG with up to $25 million for 
reliability investments in addition to going forward costs necessary to 
ensure operation of the units and reliability of the system in SWCT.'' 
\10\
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    \10\ CT DPUC Motion at 6.
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    21. CT IEC argues that an RMR revenue stream should include: (1) 
Compensation only for going-forward costs of operation; (2) payments 
for deferred maintenance administered via a mechanism that provides 
proper oversight that the maintenance is critical for reliability and 
not for economic purposes; and (3) provisions conditioning the 
continuance of RMR revenues upon the improved reliability of the 
generation units.
    22. NSTAR argues that cost-of-service pricing should not be 
available to merchant facilities and the Commission should require the 
Applicants to reapply for market-based rates if the units are not 
retired at the conclusion of the cost-of-service agreements. NSTAR 
further argues that, should prices rise and Applicants take advantage 
of DCA bidding safe harbor provision, credits may well exceed ISO-NE's 
payment obligation, in which case, Applicants would retain the 
revenues. NSTAR argues that it is wrong for merchant generators to 
collect market prices in good years and resort to cost-of-service 
guarantees in lean years.\11\
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    \11\ NSTAR Protest at 8.
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    23. NSTAR argues that the Applicants fail to identify a duration 
for the reliability need of these facilities. NSTAR asserts that the 
agreements should not be subject to automatic annual extension without 
action from ISO-NE. Moreover, NU and NSTAR submit that these contracts 
must be subject to annual review by the Commission and not allowed to 
continue indefinitely.
    24. UI argues that the cost-of-service agreements do not give the 
ISO sufficient flexibility to respond to changing circumstances, for 
example, implementation of NE-SMD or new resources being introduced 
into SWCT. UI and NU urge the Commission to reduce the termination 
notice period from 120 days, as proposed by the Applicants, to 60 days 
in order to permit the ISO to terminate the agreement if there is no 
longer a need for the resources. NSTAR asserts the cost-of-service 
agreements should list identical provisions for ISO-NE termination 
(Sections 2.1.2 and 2.2.1 of the Applicants' proposed cost-of-service 
agreements stipulate 60 days and 120 days notice, respectively) and in 
any case 60 notice is reasonable, as was found in Sithe New Boston.\12\
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    \12\ Sithe New Boston LLC, 98 FERC ] 61,164.
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    25. CT DPUC asserts that the Commission should direct ISO-NE and

[[Page 23451]]

NEPOOL to make filings, on an emergency/expedited basis, to revise or 
amend NE-SMD in order to ensure adequate levels of compensation for 
generators providing needed reliability products and to incent market 
participants to build infrastructure, implement demand-side management 
programs, or take other appropriate measures to reduce the need for 
NRG's units or provide for appropriate compensation to these units.
    26. CT DPUC further argues that since Connecticut ratepayers will 
pay most, the Commission should order that the ISO NE be required to 
examine the reliability need for any of these units upon written 
request by the CT DPUC and issue a finding within 60 days of such a 
request.

Commission Response

    27. The RMR agreements filed by the Applicants in this proceeding 
were negotiated with ISO-NE in accordance with MRP 17.3. The Applicants 
state that they are not required to establish the need for these 
agreements because they were negotiated under the authority of ISO-
NE.\13\ ISO-NE states that it has conducted a reliability assessment 
for Connecticut for the years 2003 and 2006 and has determined that, 
absent any transmission improvements or new resources, largely all of 
the existing resources in Connecticut are needed for reliability.\14\ 
ISO-NE further states that the appropriate format to be used for cost-
of-service agreements is the pro forma RMR agreement that is a part of 
Market Rule 1.\15\
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    \13\ Application at fnt.6.
    \14\ Application at Attachment 1.
    \15\ Market Rule 1, Appendix A, Exhibit 4, Original Sheet Nos. 
260-287. Market Rule 1 was approved by the Commission as part of the 
September 20 Order approving NE-SMD (100 FERC ] 61,287 (2002)).
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    28. ISO-NE is concerned that, under its current market rules and 
mitigation policies, some generators needed for reliability in load 
pockets--i.e., in DCAs--may be unable to recover their full fixed and 
variable costs and not be available for reliability. Ultimately, New 
England proposes to allow for such cost recovery with a combination of 
scarcity pricing and location-specific capacity payments. Until these 
features are implemented, however, ISO-NE has proposed (and the 
Commission has accepted) relaxed mitigation rules for units in DCAs 
with the intent to provide for sufficient cost recovery. In particular, 
under Market Rule 1, generators in DCAs would be permitted to submit 
bids up to the level of the fully allocated cost-of-service of a new 
combustion turbine, the ``CT Proxy'' bid. This safe harbor bid includes 
a fixed cost adder designed to recover the fixed costs of a new CT over 
the total number of hours of congestion in the DCA. However, NRG states 
that its units operate during far fewer hours, and if it receives only 
the CT Proxy price for the power it supplies, it will fail to recover 
its costs.\16\ NRG asks the Commission to approve temporary RMR 
contracts for its units that would pay them their full cost-of-service 
until ISO-NE is able to implement locational ICAP or some other form of 
locational capacity requirement.
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    \16\ NRG states that the average overall capacity factor of the 
facilities subject to the proposed agreements is 8 percent. Filing 
at 5.
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    29. RMR contracts suppress market-clearing prices, increase uplift 
payments, and make it difficult for new generators to profitably enter 
the market. That is because under current market rules, generators 
operating under a cost-of-service RMR contract must offer power under a 
Stipulated Bid Cost that includes stipulated marginal, start-up and no-
load costs. The units are then entitled to a monthly fixed cost payment 
to the extent that revenues earned from the energy market, including 
any payments for start-up and no-load costs, do not recover allowable 
capacity costs and fixed O&M costs. As a result, expensive generators 
under RMR contracts receive greater revenues than new entrants, who 
would receive lower revenues from the suppressed spot market price. In 
short, extensive use of RMR contracts undermines effective market 
performance. In addition, suppressed market clearing prices further 
erode the ability of other generators to earn competitive revenues in 
the market and increase the likelihood that additional units will also 
require RMR agreements to remain profitable. Therefore, we believe 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.
    30. The Commission discussed the subject of RMR agreements when 
ruling on the NE-SMD proposal in the September 20 Order. The order 
reaffirmed previous rulings that ISO-NE has the authority to enter into 
cost-of-service RMR agreements, the flexibility to address specific RMR 
situations when entering into agreements, and the requirement to file 
the agreements for review by the Commission.\17\ In the December 20 
Order the Commission added that it expects ISO-NE to enter into RMR 
agreements with only those units that are needed for reliability and 
that the Commission expects that the agreements will be in effect only 
for the period during which the units are needed for reliability.\18\
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    \17\ 100 FERC ] 61,287 at P 50.
    \18\ 100 FERC ] 61,344 at P 33.
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    31. The Commission believes that RMR agreements should be a last 
resort and that the proliferation of these agreements is not in the 
best interest of the competitive market as they affect other suppliers 
participating in this market, especially those suppliers operating 
within the same DCA. Implementation of NE-SMD provides some of the 
needed price signals in this regard; however we believe, as many 
commenters in this proceeding as well as the NE-SMD proceeding have 
noted, a location-specific capacity requirement or a deliverability 
requirement is needed so that energy markets alone are not the only way 
for suppliers in DCAs to recover costs.\19\ We believe that the current 
situation in NEPOOL may not allow suppliers in DCAs an adequate 
opportunity to recover their costs and that a location-specific 
capacity requirement must be in place. ISO-NE and NEPOOL need to 
expeditiously address the issue of resource adequacy within the DCAs as 
well as other transmission constraints in New England that include 
areas affected by export constraints as well.
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    \19\ In the September 20 Order we directed NEPOOL to develop a 
locational mechanism together with the other Northeastern ISOs. At 
that time, the assumption was that the region was pursuing a 
Northeastern RTO. Consequently, the Commission did not provide a 
date certain when it expects the mechanism to be in place, only that 
it be implemented in accordance with a final SMD rule.
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    32. On the basis of the foregoing discussion, we will deny the 
Applicants' request to recover their full cost-of-service through an 
RMR contract and instead: (1) Direct the recovery of only forward 
maintenance costs through the RMR; and (2) direct ISO-NE to modify its 
market power mitigation mechanism to permit selected high cost but 
seldom run units in DCAs to raise their bids so as to recover their 
fixed and variable costs through the market (a Peaking Unit Safe Harbor 
Bid). These temporary rules are to remain in effect until ISO-NE makes 
a filing and places into effect certain changes to the market prior to 
the 2004 summer peak season as identified below. In this regard, we 
have changed only the form in which the Applicant's will be able to 
recover their fixed and variable costs, i.e., use of a safe harbor bid 
within the market rather than an RMR contract.
    33. Upon further review of Market Rule 1, we will, pursuant to 
Section 206

[[Page 23452]]

of the Federal Power Act, 16 U.S.C. 824e, revise that Market Rule. 
Specifically, first, we find that Market Rule 1 shall include temporary 
mitigation rules to be effective June 1, 2003 that increase the safe 
harbor energy bids (used in the mitigation process in determining 
acceptable bids) to a level that includes both a variable cost 
component and a fixed cost adder for capacity in each DCA that had a 
capacity factor of 10 percent or less during 2002 (Peaking Units). The 
fixed cost adder for each such unit should be designed to recover the 
unit-specific fixed costs (adjusted downward, in the case of units 
covered by RMR contracts, to account for the costs recovered in the RMR 
contract) over the number of megawatt hours supplied in the preceding 
year. The safe harbor energy bids for these units would be the sum of 
the unit's variable cost and the adjusted fixed cost adder.
    34. Our reason for increasing the safe harbor energy bids of these 
units is to provide a market mechanism for high cost, seldom run units 
to recover their fixed costs. Since ISO-NE dispatches energy in order 
of energy bids, capacity with a capacity factor of 10 percent or less 
for the year is likely to be among the most expensive energy-producing 
capacity in the DCA. When such capacity is called upon to produce 
energy, demand is likely to be pressing upon the total capacity in the 
DCA, and thus, higher prices are likely to be economically justified. 
The current CT Proxy is designed to allow a new CT to recover its fixed 
costs over all hours of congestion in a DCA. Units that produce energy 
in substantially fewer hours, such as the Applicants' units, are not 
likely to be able to recover all of their fixed costs under the current 
CT Proxy.
    35. Second, we find that the Market Rule shall provide that the 
energy bids of peaking units are eligible to determine LMP. As a 
result, when a peaking unit is called, all sellers will be able to 
receive a high market price and recover fixed costs. This feature will 
encourage entry by new generators. We will direct ISO-NE to make 
compliance filings to reflect these changes in Market Rule 1.
    36. Third, we will eliminate the current CT Proxy mechanism. Under 
our modified mitigation approach, energy bids above a unit's safe 
harbor energy bid would be subject to possible mitigation. However, 
since our new Peaking Unit Safe Harbor energy bid mechanism will permit 
higher bids and prices during the small number of hours when demand 
approaches total capacity, we find there is no need to permit other 
generators to bid up to the current CT Proxy in order to attract new 
investment. Moreover, permitting these other generators to bid up to 
the current CT Proxy could permit them to exercise market power by 
increasing prices when supplies are not scarce. Therefore, we will 
eliminate the current CT Proxy mechanism. By eliminating the current CT 
Proxy mechanism, we expect energy prices to be lower during periods of 
ample supply, when the units eligible for the higher Peaking Unit Safe 
Harbor energy bids are not needed.
    37. Additionally, we will direct ISO-NE to file no later than March 
1, 2004 for implementation no later than June 1, 2004,\20\ a mechanism 
that implements location or deliverability requirements in the ICAP or 
resource adequacy market as discussed in the September 20 Order so that 
capacity within DCAs may be appropriately compensated for reliability.
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    \20\ This date coincides with the start of the Capability Year 
for assigning UCAP requirements to NEPOOL participants.
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Discussion of RMR Agreements

Changes to the Pro Forma Agreements

    38. ISO-NE opposes two revisions made by the Applicants to the pro 
forma agreement: (1) The Reliability cost-of-service Tracker as 
described in section 5.1.3 and (2) the non-performance penalty, 
outlined in section 3.4. In both cases the ISO urges the Commission to 
suspend the filing to permit the parties to devise an acceptable 
provision through settlement discussions.
    39. National Grid states that section 3.1.2 of the Applicants' 
proposed tariff appropriately protects against the receipt of revenues 
in excess of the cost-of-service and regulated return via an offset 
provision. However, National Grid believes that Section 3.3.2, which 
specifies the actual revenue crediting mechanism, references an offset 
of only those amounts received from the NEPOOL market. National Grid 
argues that the Commission should require modifications to Section 
3.3.2 which make clear that it does not limit the scope of the revenue 
offsets provided for in Section 3.1.2.
    40. NU states that the Applicants have revealed in this filing, for 
the first time, that they have been collecting revenue since September 
2001 as part of unfiled Voluntary Mitigation Agreements (VMAs). NU 
argues that the Applicants should be required to divulge the exact 
amounts of payments, where those used to maintain plants, and whether 
the VMAs should be considered as offsets to the operating costs of the 
plants. NU also argues that the Applicants owe in excess of $10 million 
for station service to plants. NU asserts that permitting the 
Applicants to collect for station service would violate cost causation 
principles in the cost-of-service agreements.
    41. DEMI lists several instances where provisions of the cost-of-
service agreements proposed by NRG diverge from those of the pro forma 
cost-of-service agreements, which was approved in the NE-SMD 
proceeding.\21\ DEMI argues that NRG neither identified nor offered an 
explanation or justification for these differences. DEMI submits that 
these changes may be unjust and unreasonable and urges the Commission 
to review the proposed agreements' provisions to determine if they are 
just and reasonable.
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    \21\ Section 2.5 of the cost-of-service agreements acknowledges 
that the unit owner, its agent and certain affiliates may file a 
petition under Chapter 11 of the Bankruptcy Code during the term of 
the cost-of-service agreements and specifies certain provisions that 
would apply in the event that such a petition is filed.
    1. Section 3.1.2 of the cost-of-service agreements amends the 
pro forma RMR agreement's treatment of installed capacity (ICAP) 
revenue credits and instead specifies price levels for certain time 
periods in lieu of the pro forma contract's requirement that all 
ICAP revenues be offset against payments to the resource under the 
agreements.
    2. Section 3.2.2 of the cost-of-service agreements amends the 
pro forma agreement's definition of Fuel Index Price, which is a 
component of the Stipulated Bid cost-of-service, by allowing NRG and 
ISO-NE to renegotiate the Fuel Index Price if either party believes 
the Fuel Index Price calculated by ISO-NE does not accurately 
reflect NRG's actual cost of fuel.
    3. Certain provisions of the cost-of-service agreements depart 
from the pro forma by allowing NRG to substitute performance by one 
unit when another unit is unable to perform, see section 5.2.2(b), 
and, in certain circumstances, to recover from the ISO the costs of 
bringing a substitute unit into service, see section 5.2.2(e).
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    42. CT IEC and National Grid oppose granting Applicants the right 
to terminate their cost-of-service agreements. CT IEC states that this 
is fraught with potential for abuse in that the Applicants' units are 
strategically located and are important for preserving reliability. CT 
IEC argues that the Applicants may be tempted to exploit their position 
and threaten termination of the cost-of-service agreements in an effort 
to squeeze additional revenues from Connecticut load.
    43. NSTAR and DEMI argue that section 6.2 of the pro forma cost-of-
service agreements provides for ISO-NE discretionary termination if a 
force majeure event continues in excess of thirty days whereas the 
cost-of-service agreements proposed by the Applicants have no such 
provision.
    44. National Grid states that Section 2.2.3 of the Applicants' 
proposed cost-of-service agreements--which is not contained in the pro 
forma agreement--permits the Applicants to terminate the

[[Page 23453]]

cost-of-service agreement, subject to consent of ISO-NE. National Grid 
argues that the proposed agreements offer no specific terms or 
conditions as to when the agreements may be terminated and no 
justification for departure from the pro forma agreement. National Grid 
believes that this appears to enable the Applicants to terminate the 
agreements when they so desire.
    45. NE COE protests the absence of a provision preventing 
Applicants from delisting a resource. NE COE states that under Market 
Rule 1, generators are permitted to delist a resource from the day-
ahead and real-time markets, which a generator typically undertakes to 
be able to sell in New York markets. NE COE argues that generators 
receiving support under cost-of-service agreements should not be 
permitted to remove the relevant facilities in seeking sales outside of 
New England. Moreover, NE COE submits that the Applicants' units are 
needed to meet reliability and thus there is no reason to permit 
Applicants to delist.

Cost-of-Service Tracker

    46. Numerous intervenors express opposition to the Applicants' 
proposed section 5.1.3, entitled Reliability Projects that is not 
included in the pro forma agreement. This Section provides a cost 
tracking provision to compensate the Applicants for the costs of 
specifically identified Reliability Projects to ensure that the 
Applicants complete this needed maintenance in order to keep the 
facilities in operation so that they are available when called upon by 
the ISO. Generally speaking, intervenors do not oppose the theory 
behind the tracker. However, many parties object to the lack of 
oversight, which, if in place, could ensure that the funds are spent on 
the intended maintenance and will also serve to protect the funds 
collected by ISO-NE in the event of an NRG bankruptcy petition. DEMI 
opposes the absence of prior review or approval of the costs; CT DPUC 
and NU urge the Commission to direct that funds be placed in escrow; CT 
IEC states that there are no measures to ensure funds will be dedicated 
to necessary expenditures; and National Grid argues that costs flowing 
through the tracker should be identified and that the tracker mechanism 
should be modified to limit the Applicants to recovery of an amortized 
portion of any multi-year maintenance or capital investment. NEPOOL, 
while not taking a formal position on the proposed reliability 
agreements, asks the Commission to carefully consider the implications 
of a potential bankruptcy filing by one or more of the applicants on 
the advance payment provisions for the major maintenance expenses.

Commission Response

    47. The Commission addressed the cost-of-service tracking mechanism 
for Reliability Projects in the March 25 Order. The units under the 
proposed RMR agreements are needed this year for reliability. They need 
to undergo maintenance in order to operate, and NRG may not be able to 
raise the funds to pay for maintenance costs without an assured revenue 
source, such as would be provided by an RMR contract. However, it 
appears that these units do not need to be guaranteed their full cost-
of-service to remain in operation. The cost-of-service tracking 
provisions contained in section 5 of these agreements assures payment 
only of going forward maintenance costs. This is a provision that may 
not be applicable to all RMR agreements; however, we consider it 
applicable here because the Applicants may not otherwise be in a 
financial position to fund maintenance in advance of revenue. The 
escrow modification we ordered in the March 25 Order will alleviate 
concerns that the funds collected from participants are used for 
maintaining these units. While we deny the remainder of the RMR 
agreements, this provision will ensure the units are maintained and 
operational. Because the bid ceiling discussed above would provide the 
units with an opportunity to recover their fixed costs, we direct ISO-
NE and the Applicants to modify the agreements so that the amounts paid 
by NEPOOL participants in accordance with section 5, Reliability 
Projects will be credited against the fixed cost-of-service portion of 
the new reference price bid ceiling.

Delivery Standard

    48. Several intervenors take issue with NRG's proposal to reduce 
the delivery standard according to section 3.4.2 of the proposed cost-
of-service agreements.\22\ ISO-NE indicates that it cannot accept the 
proposed standard absent empirical evidence that such a revision is 
appropriate.\23\ NU submits that ratepayers should not be required to 
pay for RMR service if they receive a diminished reliability benefit 
and further suggests considering a reduction of the Applicants cost-of-
service recovery if they cannot meet the ISO-NE designated performance 
standards. CT OCC asserts that NRG's request is completely 
inappropriate especially in the context of the company's rather high 
cost-of-service recovery requests. CT IEC concludes that NRG hopes to 
secure the most amount of money for the least amount of output based on 
NRG's statement that the facilities may not be able to meet the reduced 
performance standard. CT IEC argues that in order to ensure reliability 
in Connecticut, which is the goal of cost-of-service agreements, the 
Applicants' generating units must meet their performance goals and any 
failure to do so must be strictly penalized. NSTAR argues that the 
Applicants must not be allowed to undermine ISO-NE's need to know what 
it can count on and when in a constrained dispatch. NEPOOL, without 
taking a formal position, asks the Commission to carefully consider the 
deviation from the pro-forma agreement with regard to the diminished 
performance standard.
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    \22\ Section 3.4.2 of the Applicants proposed cost-of-service 
agreements states that a unit shall be deemed to be in full 
compliance if the unit delivers in any hour at least 95% of the 
requested MW or not more than 5 MW less than the requested MW. The 
pro forma cost-of-service agreement, provides for at least 97% and 
not more than 2 MW less than the requested MW.
    \23\ ISO-NE states that necessary evidence has not been provided 
and supports the 97% or not less than 2 MW standard required in the 
pro forma agreement in Market Rule 1.
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Commission Response

    49. The Commission is not convinced by the Applicants' statements 
that the non-performance penalty standards contained in section 3.4.2 
of the agreements need to be changed from the pro-forma agreements. We 
therefore deny this change.

Cost-of-Service

    50. ISO-NE has not reviewed rate-related information and states 
that it does not take any position on the appropriateness of rates 
requested by the Applicants. However, ISO-NE does confirm that the 
units specified ``are necessary to support reliability in Connecticut 
and [the ISO] is prepared to execute cost-of-service agreements with 
the Applicants.'' \24\ Further, the ISO is prepared to ``execute the 
Agreements in substantially the same from as they have been 
submitted,'' subject to any changes ordered by the Commission.\25\
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    \24\ Comments of ISO-NE at 3.
    \25\ The Commission notes that the ISO-NE raises concerns 
regarding the deviations from the pro-forma RMR agreement that the 
applicants proposed in the filing--the Cost Tracking mechanism and 
the reduction in the performance standard.
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    51. Numerous intervenors--DEMI, NU, CT CPUC, CT IEC, CTAG, NSTAR 
and CT OCC--believe NRG's proposed rates exceed the bounds of ``just 
and reasonable'' ratemaking and call for suspending the filing and 
setting it for hearing. Intervenors also address specific items of 
NRG's filed cost-of-service including the proposed return

[[Page 23454]]

on equity of 14 percent, cost of capital (NRG proposes 9.05 percent 
cost of credit), accumulated deferred income taxes, depreciation (NRG 
uses 6.6 years to calculate accumulated depreciation), net negative 
salvage value (NRG has increased its depreciation base by $92,420,000), 
operations and maintenance expenses, interconnection rights, and 
recovery of an acquisition premium.

Commission Response

    52. Applicants filed proposed rates to recover the costs of all 
subject generating units in each power plant, i.e., separate rates for 
Devon, Middletown, Montville, and Norwalk. Under this approach all of 
the units under each RMR Agreement would have received the same rate 
regardless of which unit(s) run at the plant. The rejection of the 
agreements and the Commission's changes to the mitigation rules 
discussed above renders as moot the cost-of-service analysis for the 
original intended purpose of developing specified rates for the 
recovery of fixed and variable costs of each plant. Under the 
Commission's directive, a Peaking Unit Safe Harbor bid ceiling with a 
fixed cost adder will need to be developed for each unit or plant to 
replace the CT Proxy for these peaking units based on the amount of 
generation produced during the previous year, i.e. 2002. The cost-of-
service analyses filed by the Applicants will therefore need to serve 
as the basis for the determination of the Peaking Unit Safe Harbor.
    53. Interveners have raised several issues regarding the cost-of-
service analysis including rate of return, depreciation rates, and 
accumulated deferred income taxes (ADIT). In addition, the Commission 
performed a cost-of-service analysis for each Agreement based on the 
information provided in the filing. The Commission identified several 
cost-of-service items that were not fully supported by the Applicants 
in their filing and made adjustments as follows: A return on equity of 
13.39% (based on Commission Staff's preliminary analysis), the addition 
of ADIT, and the elimination of net negative salvage and associated 
depreciation expenses. The Commission's analysis supports fixed charges 
of: $21,154,792 for the Devon units; $17,687,684 for the Norwalk Harbor 
units; $19,327,732 for the Montville units; and $45,262,975 for the 
Middletown units. These values, subject to adjustment for all revenues 
received from other sources, are to be used to develop fixed cost adder 
and the initial Peaking Unit Safe Harbor bid ceilings for these units.
    54. Issues that are driving how the Commission will deal with the 
filed costs-of-service include: The need for intervenors to comment; 
the need for the Peaking Unit Safe Harbor to be implemented in short 
order; and the inability to order refunds because of the interaction 
between Peaking Unit Safe Harbor and the market price of electricity. 
The safe harbor bids by definition are approximations; and therefore, 
the Commission will provide an avenue for intervenors to comment in 
order to accommodate the above driving factors. The Commission will 
allow the costs-of-service with the adjustments discussed above to 
serve as the basis for developing initial Peaking Unit Safe Harbor to 
be placed into effect with the market mitigation measures described 
above. We will allow parties to comment specifically about the costs-
of-service as they pertain to the development of the Peaking Unit Safe 
Harbor bid levels as well as to allow the Applicants to comment on and 
to support the items that the Commission adjusted in developing the 
above fixed charges within 30 days. The Commission will set an 
expedited timetable for the resolution of any issues. Changes to the 
costs-of-service resulting from this process will be reflected in 
recalculated reference prices that will go into effect on a going 
forward basis from the date of an order that establishes revised 
Peaking Unit Safe Harbor levels.
    The Commission orders:
    (A) The proposed agreements are hereby accepted for filing, as 
revised as directed in ordering paragraph B below, suspended to become 
effective February 27, 2003, subject to refund and the escrow 
arrangements consistent with the March 25 Order.
    (B) Applicants are hereby directed to file revised agreements 
within 30 days of the date of this order, that provide only for the 
recovery of costs related to the Reliability Projects as discussed in 
the body of this order.
    (C) ISO-NE is hereby directed on or before May 30, 2003, to make a 
compliance filing to revise the Proxy CT mitigation measures contained 
in Market Rule 1 and to develop Peaking Unit Safe Harbor bid ceilings 
as discussed in the body of this order.
    (D) ISO-NE and NEPOOL are directed to file revised ICAP rules no 
later than March 1, 2004, as discussed in the body of this order.
    (E) The Secretary is hereby directed to publish a copy of the order 
in the Federal Register.

    By the Commission.
Magalie R. Salas,
Secretary.
[FR Doc. 03-10816 Filed 5-1-03; 8:45 am]
BILLING CODE 6717-01-P