New resources that clear ISO-NE’s Forward Capacity Auction will be able to begin supplying capacity earlier than the usual three-year lead time under a package of Tariff revisions approved by FERC last week (ER16-2451, AD16-26).
The changes are intended to enhance liquidity in the RTO’s capacity market: Resources that are completed prior to the beginning of their commitment periods would not have to sit idle until then. Under the revisions, filed by ISO-NE in August, qualified resources could participate in the RTO’s reconfiguration auctions and begin supplying capacity as soon as four months after they clear the FCA. Imports would be allowed to begin as soon as one year after the FCA.
That last provision did not sit well with NYISO, which had asked FERC to delay the revisions by one year.
The ISO said it did not object to the revisions themselves, but it worried that they would negatively affect capacity prices in its own market because of a single power plant, Castleton Commodities International’s Roseton 1. The 1,242-MW dual-fuel generator, located 43 miles north of New York City in NYISO’s capacity import-constrained G-J locality, is committed to supply about half of its capacity to ISO-NE for the 2018/19 and 2019/20 periods. Under the revisions, Roseton would be able to supply capacity beginning next June for the 2017/18 delivery year.
Roseton | Google
NYISO said this could increase costs to New York consumers by as much as $341 million. Under current ISO rules, when a resource is committed to export capacity, it is treated as if it no longer exists when the ISO runs its own, one-year forward auction. If Roseton decides to participate in ISO-NE’s 2017/18 commitment period, NYISO would procure unnecessary replacement capacity, as Roseton would still be providing reliability services for the G-J zone, the ISO argued.
Market Monitor David Patton identified the problem in his 2015 State of the Market report, recommending that NYISO act quickly to recognize the reliability value of generators in import-constrained zones to avoid a rise in capacity prices. NYISO is currently hammering out Tariff changes and hoped to file them so they were in place before the beginning of the 2018/19 period.
FERC, however, said it was “not persuaded that the potential behavior of New York suppliers provides a sufficient basis to reject ISO-NE’s filing in this case.”
“Deferring the effective date of an otherwise just and reasonable proposal would be inconsistent with the notice provision in Section 205 of the” Federal Power Act, it added.
The commission ordered NYISO to make an informational filing by Nov. 4 addressing its progress in finalizing its Tariff revisions.
FERC last week approved CAISO’s use of a natural gas price index included in temporary Tariff provisions the ISO implemented last spring in response to the closure of the Aliso Canyon storage facility (ER16-1649).
The ISO revised its index rules to ensure gas-fired generators in Southern California accurately reflect their fuel costs in the event that pipeline restrictions imposed following the loss of Aliso Canyon caused market volatility.
The California grid weathered the summer without supplies from the Aliso Canyon gas storage facility, but CAISO hopes to extend its gas restriction response plan for another year. | California Office of Emergency Services
Prior to the revision, the ISO Tariff required gas generators to base the fuel component of their day-ahead unit commitment costs on the previous day’s day-ahead gas index published by the Intercontinental Exchange (ICE).
The updated rule allows those generators to instead use a same-day index produced by ICE by 9 a.m. PT, just before the ISO’s day-ahead market run. ICE’s “official” same-day index is typically posted at 11:30 a.m.
CAISO reasoned that a shorter time lag between the publication of the index and the submission of day-ahead energy bids would reduce the likelihood that generators could lose money under unexpected tight supply conditions by gas price spikes revealed after the market run.
The commission’s June 1 order approving the Aliso Canyon response plan accepted the new index with the qualification that it must be shown to conform to FERC’s policy statement on natural gas price formation, which outlines standards for trade data reporting. (See FERC Approves CAISO’s Aliso Canyon Response Plan Ahead of Summer.)
In August, CAISO asked FERC to extend a previous waiver and allow it to continue using the new index provisions. While the ISO said it could not state that the index conformed with the policy statement, it noted that the volume-weighted average price ICE makes available before 9 a.m. is calculated in the same way as the official index published later in the morning.
In its decision last week, the commission agreed with the ISO’s assessment, pointing out that ICE is a FERC-approved index developer and that the new index meets the minimum threshold for trading volume.
“Based on CAISO’s representations that the volume-weighted average price is generated by ICE between 8:00 a.m. and 9:00 a.m. PT, we expect that the new index, which will include trades between 5:00 a.m. and at least 8:00 a.m. PT, will have sufficient activity to conform to the liquidity requirements of the policy statement,” the commission concluded.
Tariff provisions related to the Aliso Canyon response plan are set to expire at the end of November, but CAISO this month asked the commission to extend most the measures for an additional year. A decision on that request is pending. (See CAISO Seeks to Extend Aliso Canyon Gas Rules Through Winter.)
MISO and PJM will have 65 days to evaluate the impact of generator retirements under joint operating agreement language drafted to comply with a FERC directive.
The subject of a briefing at MISO’s Reliability Subcommittee meeting last week, the JOA language requires the RTOs to notify each other of retirements and exchange the most up-to-date modeling data.
The results of the retirement impact studies and possible transmission upgrades will also be shared. Projects in one RTO that have benefits or impacts in the neighboring RTO will be evaluated by the Joint Regional Planning Committee and the Interregional Planning Stakeholder Advisory Committee (IPSAC).
Alternatives to transmission upgrades will include market-to-market coordination to use external resources, as well as operating guides and procedures involving the adjacent RTO.
| MISO
In response to a complaint by Northern Indiana Public Service Co., FERC required the RTOs to file language coordinating their generator retirement studies and dispatch assumptions by Dec. 15, 2016 (EL 13-88).
The commission cited NIPSCO’s testimony that PJM used unrealistic dispatch assumptions in its study of the retirement of the Crawford and Fisk generating plants in the Commonwealth Edison territory, “which caused PJM to fail to identify required upgrades and masked potential problems within MISO, including overloads on NIPSCO’s system.” (See FERC Orders Changes to MISO-PJM Interregional Planning.)
Joe Reddoch of MISO’s System Support Resource Planning Group said MISO focused on appropriate communication between the RTOs and reviewed its existing retirement process to make sure it was still relevant.
Reddoch commented on the 65-day deadline for evaluating retirements.
“Currently, it’s more or less open-ended. We don’t necessarily have a deadline to get back to them with study results that would factor into their retirement studies,” Reddoch said.
He added that supplying such information would be more vital to PJM, which — unlike MISO — cannot force generators to stay online as must-run resources.
Reddoch said transmission projects the RTOs identify as a result of their analyses might not be detailed or polished.
“Each RTO would conduct a retirement analysis to determine the impacts to their system and possible transmission projects. We won’t necessarily have those projects defined,” he said.
Reddoch said MISO would look to PJM’s information to update its modeling information, but directly involving PJM staff in retirement decisions would be too complex. “They won’t necessarily be involved in study scope discussions,” he said.
In comments to MISO, NIPSCO said it was generally supportive of the proposed changes, but it asked the RTOs to devise a timeline for retirement studies that is similar to MISO’s multistep interconnection queue studies. MISO responded that an interconnection format isn’t feasible because its generator retirement studies are “conducted on an ad hoc basis,” and studies can vary.
NIPSCO also asked MISO for examples of how identified transmission projects become approved under the new process. MISO said the issue would be discussed at a future IPSAC meeting.
Reddoch asked for stakeholder input by Nov. 1 and said MISO would share final JOA language at the Nov. 15 Joint and Common Market meeting with PJM.
FERC last week approved a settlement allowing independent transmission developer TransCanyon to collect a 9.8% base return on equity for any projects it builds under CAISO’s FERC Order 1000 competitive solicitation process (ER15-1682).
TransCanyon asked the commission last May for a 10.6% ROE if it were selected to build and operate a 115-mile, 500-kV transmission segment linking Southern California Edison’s Colorado River substation with Arizona Public Service’s Delaney substation. The commission set the request for hearing and settlement procedures in July 2015.
CAISO ultimately awarded the economically driven $300 million Delaney-Colorado River project to a joint venture between Abengoa and Starwood Energy.
Delaney – Colorado River Project Map | CAISO
Still, last week’s order will enable TransCanyon to incorporate the 9.8% ROE into its transmission owner tariff’s formula rate template — the basis for calculating a yearly transmission revenue requirement to be included in the ISO’s transmission access charge.
Participants in the settlement were SoCalEd; the cities of Anaheim, Azusa, Banning, Colton, Pasadena, Riverside and Santa Clara; the California Department of Water Resources; the M-S-R Public Power Agency; and Modesto Irrigation District.
TransCanyon is a joint venture between Berkshire Hathaway Energy, which owns PacifiCorp and NV Energy, and Pinnacle West Capital’s Bright Canyon Energy. Arizona Public Service is Pinnacle’s primary subsidiary.
COLUMBUS, Ohio — Three economists, two lawyers and an electrical engineer walk into a bar…
Actually, they appeared on stage here for the latest installment in PJM’s ongoing debate over the role and value of financial transactions.
Independent Market Monitor Joe Bowring and the Massachusetts Institute of Technology’s John Parsons, both economists, explained to the annual meeting of the Organization of PJM States Inc. why they are critical of PJM’s current system for auction revenue rights and financial transmission rights.
Parsons cited the Monitor’s finding that PJM load has lost out on $1.7 billion in unreturned congestion surpluses over the past five years. That total, an average of almost $335 million a year, represents the difference between what load paid for ARRs and FTRs and what was returned to it. (See Table 13-37 in the Monitor’s second-quarter State of the Market report.)
Harvard economist William Hogan, whose theories have provided the basis for the structure, said he’s not sure of Bowring’s math, but he said it fails to capture all the dynamics of the system.
Hogan said ARRs and FTRs were not designed to return congestion revenue to load as Parsons and Bowring contend, but to solve the “dynamic efficiency” problem — a way to hedge congestion costs in recognition that physical transmission rights are impossible under an open access transmission system. “If you want to have open access and nondiscrimination [in an electricity transmission system], this is the only way to do it,” he said.
PJM’s system is designed so demand customers pay their LMPs and power generators are paid their own LMPs. Load overpays by design, and the surplus in those congestion payments is supposed to be returned to load customers through FTRs and their associated ARRs, Parsons and Bowring contend. ARRs are created when the rights to FTR payments are auctioned off to hedge against the variability of FTRs. It’s through these markets that the differences between customers’ congestion payments and the FTR/ARR offsets they receive are created.
While some FTR buyers no doubt are speculators hoping to pay less than they’ll receive in congestion payments, Hogan said they are still providing fixed-price hedges to sellers looking for predictability. “The beneficiaries of the ultimate transmission congestion are the people on the load side, not the FTR holders.”
Parsons countered that the system is not “confronting honestly” how random and imprecise — or “stochastic,” as he put it — capacity can be on a transmission system. “The system is designed to kill two birds with one stone, but … have you ever seen anybody who can actually kill two birds with one stone?”
‘Fairy Tale’
“What you have right now is a fairy tale FTR system where rights are designed upfront, but you don’t know the right capacity of the system,” he continued. “You don’t have a product that actually reflects the true congestion and the true capacity under a point-to-point system. It would be better to step back and structure the system so that actually reflects the true congestion revenues and risks and the true capacity and risk.”
Bowring repeated his longstanding position that the benefits of financial trading to the market have not been proven — a statement that brought a scowl to the face of attorney Noha Sidhom of Inertia Power, a financial firm that trades FTRs.
The nodal concept using LMPs came about to address the inability to control the flow of electricity across the network, Bowring said. However, that’s the point when explicit point-to-point contract paths — the concept on which FTRs are based — became obsolete, he argued.
Stu Bresler, PJM senior vice president for operations and markets, acknowledged that FTRs were a design choice made in 1999, long before its full implications could be known.
“Joe’s correct that it was a simpler time back then,” said Bresler, the electrical engineer in the group. “The implementation of the monthly FTR auction was intended to give market participants the ability to have additional choices with what to do with their allocated rights.”
The economists’ theoretical debate was juxtaposed with real-world experience from Sidhom and attorney Marji Philips of Direct Energy, a load-serving entity that receives and sells FTRs.
Philips said economists’ idyllic theories don’t account for the vagaries of PJM’s system. Despite all the modeling, market designs don’t account for everything, she said, and what’s left will undoubtedly follow the industry maxim that “load pays.” She cited FERC’s Sept. 15 order directing PJM to allocate balancing congestion to real-time load (EL16-6-001, ER16-121).
“There are causes of congestion that we don’t actually have pure cost causation [for], and the new FERC order says, ‘Well, let’s just stick it to real-time load because we don’t know where they’re coming from, and we think this should be a pure product.’ They have undermined the complete value of FTRs for load, which is to hedge our congestion risk,” she said. “What I love is that FERC says, ‘This is for load.’ Not a single load entity supported it.” (See Monitor Says FERC Erred in PJM FTR Ruling, Seeks Rehearing.)
Sidhom agreed that the market needs some tweaks, such as enhanced modeling, but insisted it provides an important service. She cited a MISO study that concluded optimizing wind into the RTO is saving consumers $316 million to $377 million annually — savings due in part, she said, to the work of financial traders. “Not bad for a 76 cents/MWh cost hedge,” she said. “I think that’s a great deal for consumers.”
“At the end of the day,” she added, “you need those FTR auctions to provide the appropriate pricing.”
WESTBOROUGH, Mass. — ISO-NE’s latest briefing on its ongoing economic study focused on the shortfall of energy market revenues, prospects for storage and the ability to meet increased renewable portfolio standards.
Planners told the Planning Advisory Committee on Wednesday that uplift and capacity revenues will become increasingly important because energy market revenues will be insufficient to support any form of new generation in 2025 or 2030, the two time horizons in the draft study.
“Additional revenue from other sources will be needed to support new resources, as the energy market contribution isn’t sufficient to cover fixed costs,” said Michael Henderson, director of regional planning and coordination at ISO-NE.
In the simulations, energy market revenues are below annual carrying charges for all new generation resources, including wind, solar photovoltaic, natural gas combined cycle and combustion turbines. Units would recover some costs through energy market revenues plus uplift, the study says. Resources also would need “significant revenues” from the capacity market, Henderson added.
The study says the shortfall results because cheap gas-fired units typically set LMPs and higher-cost resources are rarely on the margin.
Another factor is low- or no-cost resources. The region is experiencing little or no load growth as the states have made significant commitments to behind-the-meter solar resources and energy efficiency. Wind and PV that aren’t behind the meter are price takers.
Uplift would be highest in 2025 under scenario 2 — in which all additional capacity needs, including retirements, are met with new renewable and clean energy resources, including nuclear power — hitting almost $179 million assuming no transmission constraints.
The lowest uplift — $88 million — is under scenario 5, in which RPS requirements are met by resources interconnected to the system, under construction or approved as of April 1, 2016, with alternative compliance payments used to meet any remaining RPS requirements. Retired units would be replaced with combined cycle plants to meet installed capacity requirements.
In 2015, uplift payments to resources operated out of merit — typically to ensure power system reliability — totaled $119 million, 2% of the total energy payments of $5.9 billion, according to Internal Market Monitor’s 2015 Annual Markets Report.
Energy Storage
The study found that net revenues for energy storage increase along with more production by renewable resources.
Net revenues would be highest under the “RPS-plus scenario,” which assumes additional renewable and clean energy resources above existing RPS requirements. Annual net revenues — revenue from generation minus the cost of storing energy — are projected to total more than $12 million in 2025 under the scenario, assuming no transmission constraints.
By contrast, storage would show negative net revenues of $1.5 million under scenario 5.
Increasing RPS
The study finds that scenarios 1, 2 and 3 all can meet the projected growth in the new RPS target for 2025 (8,069 GWh) and 2030 (10,806 GWh), although scenario 1 barely meets the 2030 target under a constrained transmission system.
Meeting the RPS targets under scenarios 4 and 5 would require the addition of more renewable resources, imports, alternative compliance payments or reducing RPS targets by adding energy efficiency and behind-the-meter solar.
Below is a summary of the issues scheduled to be brought to a vote at the Markets and Reliability and Members committees Thursday. Each item is listed by agenda number, description and projected time of discussion, followed by a summary of the issue and links to prior coverage in RTO Insider.
RTO Insider will be in Wilmington, Del., covering the discussions and votes. See next Tuesday’s newsletter for a full report.
Markets and Reliability Committee
2. PJM Manuals (9:10-9:20)
Members will be asked to endorse the following manual changes:
A. Manual 14A: Generation and Transmission Interconnection Process. Revisions, recommended by the Earlier Queue Submittal Task Force, include: changes to the assignment of queue priority; timing, including scheduling of deficiency reviews; criteria for inclusion in feasibility studies; and fee structures.
3. Installed Reserve Margin Study Results (9:20-9:30)
Members will be asked to endorse the 2016 Installed Reserve Margin study results. (See “More Granularity Requested on Winter Reserve Targets,” PJM Planning Committee Briefs.)
4. Credit Subcommittee (9:30-9:40)
Members will be asked to endorse proposed clarifications to the credit policy in Tariff Attachment Q that reorganize provisions and make five minor changes to them, none of which affects credit requirements. (See “Attachment Q Modified; Credit Requirements Unaffected,” PJM Market Implementation Committee Briefs.)
5. PJM Capacity Problem Statement / Issue Charge (9:40-10:25)
6. Market Implementation Committee Charter (10:25-10:30)
Members will be asked to approve the updated Market Implementation Committee charter, which removes references to working groups. (See “‘Working Groups’ Removed from MIC Charter,” PJM Market Implementation Committee Briefs.)
Members Committee
Consent Agenda (1:20-1:25)
Members will be asked to endorse:
B. Tariff revisions regarding the release of capacity in the third incremental auction for the 2017/18 delivery year in response to a FERC reporting directive (ER16-532) related to excess capacity procured in the Capacity Performance transition incremental auction. (See “Proposal Chosen for Capacity Release,” PJM Markets and Reliability and Members Committees Briefs.)
The length of MISO’s lone market efficiency project for 2016 will have to be extended, increasing its cost by as much as one-quarter and reducing its benefit-cost ratio.
MISO said the estimated cost of the Huntley-Wilmarth 345-kV project has jumped by $20 million from the original $81 million as a result of having to reroute the line to bypass the Mankato, Minn., area.
| MISO
MISO staff told the Oct. 19 Planning Advisory Committee meeting that the new benefit-cost ratio on the project may be as low as 1.5-to-1, down from the original 2-to-1.
MISO Senior Manager of Competitive Transmission Administration Brian Pedersen said the original line length was estimated at 38.5 miles. It’s unclear how many miles the reroute will add to the project, which is slated for completion in 2022.
Putting aside misgivings about the cost increase, a majority of PAC sectors approved a motion recommending that the 2016 Transmission Expansion Plan report proceed to the System Planning Committee of the Board of Directors for consideration. After that, the report will go before the Advisory Committee and Board of Directors for approval in December. (See MTEP 16 Proposes 394 Projects at $2.8 Billion.)
In a first round of feedback on MTEP 16, stakeholders urged MISO to competitively bid the line, despite Minnesota’s right-of-first-refusal statute, which would designate the project to incumbents Xcel and ITC.
“This is an issue we see no matter who does it,” an Xcel representative told stakeholders. “It’s still an urban area; it still needs to be addressed. This is the difference between the planning estimate and what the route actually is.”
Hwikwon Ham of the Minnesota Public Utilities Commission “strongly” urged Xcel to come before the state’s Department of Commerce — which advocates to the PUC on behalf of consumers — to discuss the change.
Steve Leovy of WPPI Energy asked why MISO had not presented a more accurate cost estimate when it initially rolled out MTEP 16.
John Lawhorn, senior director of policy and economic studies at MISO, said the RTO does “the best job it can.”
“Cost estimates and actual costs can vary, as you know, so we have variance analysis built into our Tariff,” Lawhorn said.
“We constantly hear MISO pushing openness in the process, and here it is again that we don’t have all the details. At a minimum, an MTEP report should at least present the best cost estimate possible,” said George Dawe, vice president of Duke-American Transmission Co.
However, Ham said he was pleased that Xcel came forward with the increased price before MTEP 16 is approved. “I’m happy to see this number came in ahead of time,” he said.
| MISO
The MTEP report says the Huntley-Wilmarth project will give load more access to lower-cost generation because it “completely mitigates” congestion on the Huntley-Blue Earth 161-kV line near the Iowa-Minnesota border. The line has been stressed by large amounts of wind capacity and low-cost coal generation in northern Iowa.
“Further worsening congestion is the increase in wind capacity in Iowa that is assumed over the next 15 years,” the report says. “Finally, expected coal retirements near the Minneapolis/Saint Paul area such as Sherco 1, Sherco 2 and Clay Boswell 3 tend to increase the need for power to flow from northern Iowa to the Twin Cities via the Lakefield to Wilmarth 345-kV path. As a result, for the loss of this high-voltage transmission path, the low-voltage parallel path of Huntley to Blue Earth 161-kV becomes congested.”
FERC last week eliminated the must-offer obligation in effect throughout the Western Electricity Coordinating Council region since the tail end of the California energy crisis of 2000-2001.
“In light of the passage of time and significant improvements to California’s wholesale electricity markets over that time, the must-offer requirement established for the WECC in 2001 produces little or no benefits today,” the commission wrote (EL27-16).
FERC implemented the obligation in June 2001 in response to what it called “serious market dysfunction” in California — the effort by some of the region’s generators to withhold power supplies to drive up prices in the now-defunct California Power Exchange. The rule required most generators serving California to offer all capacity not already committed under bilateral agreements into the state’s real-time market.
Last week’s order also ended a requirement that public and nonpublic utilities post a daily log of available capacity on their websites, as well as to a site hosted by the Western Systems Power Pool (WSPP).
The commission also rejected a request by the Edison Electric Institute to retroactively relieve affected industry participants of costs related to the posting requirement, instead affirming Feb. 24, 2016, as the refund effective date — days after FERC initiated a Section 206 proceeding to explore eliminating the must-offer obligation. (See FERC Likely to Eliminate Must-Offer Rule for West.)
While EEI did not specify an alternative date, it contended that the posting requirement became unduly burdensome once California’s market had undergone substantial changes and that FERC should therefore “grant such further and other relief as to the posting requirement that the commission deems necessary or appropriate.”
The must-offer and posting requirements were originally slated to expire in September 2002, but FERC subsequently extended the rules for an unspecified period of time until “long-term market-based solutions” could be fully implemented.
In eliminating the obligation, the commission cited numerous changes to California’s markets over the years, including CAISO’s development of LMP-based day-ahead and real-time energy and ancillary services markets, a day-ahead residual unit commitment process, local market power mitigation measures, reduced reliance on spot markets, and the state’s resource adequacy program.
“These market design improvements have contributed to a well-functioning CAISO market,” the commission wrote, adding that the electricity supply outlook for the West has “significantly improved.”
The commission noted that its ruling only dealt with rules stemming from the energy crisis. This was in response to Pacific Gas and Electric’s argument that termination of the obligation should not be construed as limiting the need for a must-offer requirement for resource adequacy capacity in the CAISO-run Energy Imbalance Market or new ISO transmission owners.
“We are not prejudging any future must-offer proposals related to the Energy Imbalance Market or to new transmission owners joining CAISO,” the commission affirmed.
FERC on Thursday denied Dominion Resources’ request for rehearing of an order rejecting its challenge to ISO-NE’s 2016 Forward Capacity Auction over a paperwork error that excluded capacity from its generating plant in Providence, R.I. (EL16-38-001).
Manchester Street Station | Dominion
The commission on May 2 denied most of Dominion’s February complaint about ISO-NE’s decision to block new incremental capacity from an upgrade to the company’s Manchester Street Station from participating in FCA 10 in February. The three-unit generator boosted its summer capacity by 21 MW to 477 MW.
In September 2015, ISO-NE approved the additional 21 MW for the auction. But the RTO later disqualified the additional capacity because Dominion failed to submit a “composite offer” linking the new capacity and the existing capacity at the plant.
The deadline for composite offers was Oct. 9, 2015. Dominion filed its complaint with FERC just days before the FCA in February.
The commission rejected the complaint in May, finding that the company had received adequate notice of the RTO’s filing requirements in October and November. The commission directed ISO-NE to revise its Tariff to provide greater clarity but denied Dominion’s request to resettle the auction as if the company’s additional capacity had participated.
“We are not persuaded by Dominion’s assertion that the commission erred in determining that ISO-NE did not violate its Tariff and was therefore mistaken in finding that resettlement was not required,” FERC wrote last week. “It would be contradictory to find that ISO-NE’s Tariff was unjust and unreasonable because it failed to provide notice of the filed rate, while also finding that ISO-NE violated the filed rate.”
FERC’s May order did find that ISO-NE’s tariff was “unclear regarding the process for new incremental generating capacity and existing generating capacity at the same resource to participate in the FCA.”
ISO-NE responded with proposed Tariff changes under which it would automatically match new summer incremental generating capacity with excess existing winter qualified capacity at the same resource.
But the commission ordered the RTO on Aug. 30 to further amend its Tariff to automatically match new winter incremental capacity with excess existing summer qualified capacity at the same resource. “We find that there is no reason to limit, based on season, the automatic matching of new capacity with excess existing capacity,” the commission said (ER16-2126).
ISO-NE’s second compliance filing is due by the end of October.
