ERCOT will continue its reliability-must-run agreement with NRG Energy’s Greens Bayou Unit 5 after a solicitation produced no viable alternatives.
The Texas grid operator had solicited proposals for must-run alternatives (MRAs) after it entered an RMR contract with NRG Texas Power for its Houston-area unit, a 371-MW gas-fired plant, on June 2. (See ERCOT Seeks Alternatives to Houston-Area RMR Unit.) The contract is projected to cost the market $60 million.
ERCOT said the proposed MRAs it received by the Aug. 24 deadline would not “adequately meet the reliability need served by the Greens Bayou 5 unit.” The ISO received eight offers from four qualified scheduling entities (QSEs) with a combined capacity of 385.9 MW for most of the contract months, but it said some of those offers did not qualify as eligible MRA resources and the others did not provide an “acceptable solution to the reliability concern” necessary to replace Greens Bayou.
Greens Bayou Source: NRG Energy
The Greens Bayou RMR agreement addresses reliability concerns on a Houston-area transmission line. Under the agreement, the unit will remain available during summer peak demand periods through June 2018 to support system reliability under certain critical operating conditions.
ERCOT has said the $590 million Houston Import Project, scheduled to be completed by summer 2018, will solve the reliability concern.
RMR Rule Changes Proposed
Meanwhile, the Protocol Revision Subcommittee last week advanced three nodal protocol revision requests (NPRRs) related to ERCOT’s RMR procedures. They will be taken up next week by the Technical Advisory Committee, which in July rejected an NRG request to allow the economic dispatch of RMR units. (See “Pricing Change on RMR Units Rejected, Appealed to ERCOT Board,” ERCOT Technical Advisory Committee Briefs.)
NPRR788 modifies the RMR planning studies to include forecasted peak loads and introduces a new requirement that a potential RMR unit must have “a meaningful impact on the expected transmission overload” to be considered for an agreement.
NPRR795 creates a mechanism to refund capital expenditures funded by ERCOT under an RMR agreement, if the agreement is terminated. The refund would be based on the expenditures’ depreciated book value if the resource returns to commercial operations; otherwise, it would be based on the salvage value.
NPRR793 would clarify the reliability unit commitment process to ensure RMR units are not accidentally committed as a reliability unit before other resources. The revision request adds several responsibilities for RMR unit owners, revises RMR formulas and adds further clarifications.
Luminant, Calpine Notices
ERCOT, which already has more than 81,000 MW of capacity to meet the fall and winter’s expected peak demand of less than 59,000 MW, recently got news of an additional resource.
Luminant notified ERCOT on Sept. 14 that its 805-MW coal unit at Martin Lake in East Texas, which had been running only from May to late September, will now be available for year-round dispatch. The status change is effective Oct. 1.
The Texas grid operator has also reviewed Calpine’s notice that it would be suspending operations at its 400-MW, gas-fired Clear Lake Power Plant and determined the five steam and gas turbines are needed to support transmission system reliability. ERCOT will issue a final determination by Oct. 10.
ALBANY, N.Y. — A Rochester-area farm family scored unusual concessions on Thursday when state regulators approved a plan for a substation and power lines that removed previously approved facilities from their property (11-T-0534).
The New York Public Service Commission approved a modified Certificate of Environmental Compatibility and Public Need for the Rochester Area Reliability Project south of the city. The original plan approved by the PSC in 2013 would have taken arable land out of production from the Krenzer family farm, according to the family’s rehearing petition.
The plan also would have taken the most valuable land on the property used for farm infrastructure, according to the family. The family grows wheat, corn and soybeans on more than 3,000 acres.
$37M Increase
Avangrid, whose Rochester Gas & Electric is building the project, said the delays and changes will increase the project’s cost by $37 million to $291 million. The company said $23 million is related to changes in site costs, routing and structure types, with $14 million linked to the delay and extended construction timeline.
RG&E began eminent domain proceedings in 2011 to route the project through the farm.
The family says it was unaware of the proceedings for about a year, a charge RG&E denied. The family said it had informal meetings with RG&E representatives in their home in November 2011, but no definitive plans were discussed that indicated their property would be condemned.
The utility said it had a series of meetings with family members to discuss the project and produced a June 2011 letter sent to a family member that indicated financial compensation for the acquisition of the substation site.
After granting rehearing, the PSC appointed an administrative law judge in 2013 and conducted hearings in 2014, but efforts to negotiate a compromise were unsuccessful.
Negotiations restarted earlier this year, which culminated in a joint proposal filed in July. It was endorsed by the family, RG&E, PSC staff, and the state departments of Environmental Conservation and Agriculture and Markets.
Marie Krenzer told RTO Insider that Thursday’s order prompted “a lot of mixed emotions, but we were pleased with the outcome.” The family spent “well into six figures” on attorneys’ fees and other costs through the process, she said, money that they will not recoup.
“We didn’t know what we were taking on when we started this, but we knew this wasn’t right,” she said.
‘An Example of Government Working’
PSC officials lauded the outcome as an example of regulators responding to competing interests in a difficult case. “This is an example of government working,” PSC Chair Audrey Zibelman said at the meeting. “The commission listened to the Krenzers and took their concerns seriously” while also fulfilling its obligation to preserve system reliability.
“We didn’t really understand the nature of the local opposition,” Commissioner Gregg Sayre, a Rochester-area native, said at the meeting. “But once we did, I think we came up with a good result.”
Several local and state officials became involved, including U.S. Sen. Charles Schumer.
The affected property would have totaled about 670 acres. The substation would have taken 12 acres, while the remaining land would have been used for a “zig-zag” pattern of transmission lines across the farm’s productive fields, which would have cut the farm in half.
The order approved Thursday moves the substation from the Krenzer farm about 1 mile east to vacant land across the Genesee River. The routing of two new 115-kV lines eliminates the zig-zag route through the property and instead will go through land with a U.S. Department of Agriculture conservation easement to reach an existing New York Power Authority line.
The project calls for the construction of approximately 23 miles of new 115-kV transmission lines, reconstruction of 2 miles of an existing 115-kV line, a new 1.9-mile 345-kV line, a new 345 kV/115-kV substation and the improvement of three existing substations.
The new substation site will damage or destroy existing wetlands, so 17 acres of the Krenzers’ property will be used for site mitigation.
Maine regulators last week proposed a 15-year phase-out of net metering for current rooftop solar systems and a 10-year limit for new systems.
The proposal came as a part of a rulemaking process that the Maine Public Utilities Commission hopes to complete by the end of the year and implement in 2017.
“In light of changes in the technology and costs of small renewable generation, particularly solar PV, we felt that opening a rulemaking process to consider changes to the rule was the prudent course of action to ensure that all ratepayers are treated fairly,” Chairman Mark Vannoy said in a statement.
The rulemaking also proposes gradually reducing compensation for new solar customers, increasing the size of an eligible customer facility by more than 50%, from 660 kW to 1 MW, and additional consumer protections.
House of Representatives Assistant Majority Leader Sara Gideon, a solar proponent who helped craft a compromise solar power bill that was vetoed by Gov. Paul LePage in April, blasted the PUC proposal.
“Maine needs a comprehensive solar policy. Unfortunately, the PUC’s narrow focus on a single part of the broader solar policy doesn’t help our state’s ability to open new markets that create jobs and lower costs for homeowners, businesses and communities,” Gideon said. “This past session’s solar bill did not simply look at net metering in isolation but was crafted to help our constituents who are clamoring for access to community, commercial and municipal solar. That responsiveness and broad view is why policymaking should be left to lawmakers.”
The net metering review was automatically triggered by a PUC rule after solar exceeded 1% of Central Maine Power’s installed capacity. The utility reported solar at 1.04% at the end of 2015.
ST. PAUL, Minn. — MISO’s 2016 Transmission Expansion Plan recommends 394 projects totaling $2.8 billion.
The preliminary MTEP 16, unveiled at the Sept. 13 System Planning Committee of the Board of Directors, proposes:
114 baseline reliability projects valued at $734 million;
27 generator interconnection projects at $123 million, nine of which will be cost-shared;
One transmission delivery service project at $350,000;
One market efficiency project, the Huntley-Wilmarth 345-kV line project in southern Minnesota projected to cost $81 million; and
251 other projects driven by local needs at $1.8 billion.
Vice President of System Planning and Seams Coordination Jennifer Curran said the top 10 priciest projects in MTEP 16 are evenly distributed between MISO North and MISO South. Spending under MTEP 16 includes more projects than MTEP 15’s 334, but total spending would be $6 million less.
The projects are spread across all MISO quarters, with 33% in MISO South, 39% in MISO West (in parts of northwestern Illinois, Montana, South Dakota and Michigan’s Upper Peninsula and all of North Dakota, Minnesota, Wisconsin and Iowa), 22% in MISO East (in northern Indiana and Michigan’s Upper Peninsula) and the remaining 6% in MISO Central (in parts of Missouri, Illinois, Indiana and Kentucky).
The projects are also varied by type, with 44% of projects dedicated to upgrading substation equipment, 28% dedicated to transmission line upgrades, 20% dedicated to the installation of new transmission lines, 5% dedicated to transformer upgrade and replacement and 3% dedicated to voltage control improvements.
Curran said the lone market efficiency project submitted for approval, the Huntley-Wilmarth 345-kV line, will accommodate wind additions in Iowa and Minnesota. Curran said the cost of the project, which was recommended by North/Central Market Congestion Planning Study and has benefit-to-cost ratio of 2, would be spread 20% across the MISO North and Central regions, with the rest allocated to the local zone. MISO South does not yet share in cost allocations for market efficiency projects.
Board member J. Michael Evans asked why the project wasn’t built 20 years ago if it was meant to handle wind power. Curran said the project will be constructed primarily for new wind buildout.
Board Chair Judy Walsh asked if the MTEP would always involve an expensive bundle of transmission upgrades that chases new generation locations. Vice President of Transmission and Technology Clair Moeller said MISO’s multi-value project category seeks to predict the location where transmission is most needed.
Curran said if approved, MTEP 16 may contain a hitch because the $80.9 million Huntley–Wilmarth line project is located wholly inside Minnesota, which has a right-of-first-refusal statute. Curran said that while the project “by definition is eligible for the competitive transmission process,” Order 1000 and MISO’s Tariff respect state and local laws.
MTEP 16 also includes four economic projects resulting from MISO’s South Market Congestion Planning Study:
An $88 million 230-kV line and substation in southeastern Louisiana with a 1.96 to 3.40 B/C ratio, to be in service by 2022;
The $1.9 million Minden–Sarepta 115-kV line upgrade in northwestern Louisiana with a 1.83 B/C ratio to be in service by 2020;
The $7.6 million Trumann–Trumann West 161-kV line project in northeastern Arkansas with a 13.4 B/C ratio to be in service by 2018; and
The $6.7 million Lakeover 500/230-kV transformer upgrade in southeastern Louisiana with a 1.4 B/C ratio to be in-service by 2020.
Costs for the four projects will be assigned to the local zones that they benefit.
MISO’s Planning Advisory Committee members will vote on the MTEP 2016 report in October. A MISO review of sector feedback will begin in November before the board votes at its December meeting.
“You know, Ernest Hemingway wrote his best novels when he was young, but MTEP keeps getting better. MTEP 16 is better than MTEP 15,” Evans said.
SARATOGA SPRINGS, N.Y. — Gavin Donohue, CEO of the Independent Power Producers of New York, opened the group’s fall meeting last week by declaring as its top priority NYISO’s reset of the installed capacity demand curve.
Donohue noted the ISO’s prediction that New York’s Clean Energy Standard will significantly increase the need for reserve capacity and highly dispatchable resources.
“Combined with the uptick in announced plant retirements, it has never been more critical to get the demand curve reset right,” Donohue said. “The demand curve is responsible for setting reference prices. It will determine what resources enter the market over the next four years.”
The reset, which has been conducted every three years, is moving to a four-year cycle (with annual updates of some parameters). The ISO staff released its final recommendations Sept. 15 on the new parameters, which include net energy and ancillary services revenues and the gross cost of new entry in addition to reference point prices.
Staff adopted the recommendations of its consultant, The Analysis Group, for reference points for all but the New York Control Area. The firm recommended the reference points for all regions be based on dual-fuel requirements, while staff said the NYCA — the rest of state, excluding Long Island, New York City and the Lower Hudson Valley — should be based on gas only. Staff also shaved the proposed price for NYCA by 4.5%, rejecting the consultant’s proposal of $11.22/kW-month in favor of $10.72/kW-month.
Donohue also noted generators struggled with low load growth and record low gas prices, which he said are “driving previously economic facilities to the brink and resulting in various forms of state intervention.”
“It’s not clear how this effort will play out. But it’s clear that market-based solutions are always preferable to out-of-market solutions in New York state,” he said.
The ISO will accept written comments on the proposed demand curve through Oct. 3, with oral presentations to the Board of Directors on Oct. 17. The board’s finalized parameters will be filed for FERC approval by Nov. 30 with the revised curves taking effect May 1, 2017.
ST. PAUL, Minn. — MISO Steering Committee members are asking if there is a need to formalize the creation and retirement of task teams following the Resource Adequacy Subcommittee’s contentious decision in July to retire the Competitive Retail Solution Task Team.
“There’s no formal process for retiring a task team, and there’s good reason for that. Task teams do not follow the Stakeholder Governance Guide,” Steering Committee Chair Tia Elliott said. “I heard from stakeholders that it’s important to keep that process outside of formalization.”
American Electric Power’s Kent Feliks said he opposed formalizing task team creation and that, like PJM, MISO could use special meetings to discuss issues that would cut down on the number of task teams that parent entities create.
Resource Adequacy Subcommittee Chair Gary Mathis said it may be helpful to insert language into the Stakeholder Governance Guide to define how task teams are formed and dissolved.
Ameren’s Ray McCausland said Robert’s Rules of Order currently govern the creation and disbanding of task teams, because the Stakeholder Governance Guide defers to Robert’s Rules when directions “aren’t otherwise stated.”
Mathis said the bylaws are worded so that only parent entities are required to follow Robert’s Rules, not task teams. Feliks said he preferred leaving the creation and dissolution of task teams up to parent entity leadership.
After discussion, the issue was tabled until the Steering Committee’s Nov. 3 Stakeholder Governance Guide workshop.
Steering Committee members also discussed whether changes are needed to get callers queued up more quickly during meetings. Currently, entity chairs are in charge of recognizing callers with opinions and questions.
Currently, McCausland said, operator-assisted calls are in violation of the governance guide. He said callers should be able to interrupt the speaker directly by deselecting their mute buttons. He argued that people attending in-person have rights that those dialing in do not have.
“It’s a brainer. We have to think about this,” Mathis added.
Elliott said the issue could be handled by MISO with a technology fix, possibly through a function that allows callers to immediately open lines without operator assistance.
FERC last week approved Macquarie Energy’s request to revise its market-based rate tariff to allow the company to engage in short-term simultaneous transactions along a key Pacific Northwest transmission system partly controlled by Puget Sound Energy — a Macquarie affiliate (ER16-2198).
The commission’s decision enables Macquarie to trade energy and capacity with an unaffiliated counterparty on the California Oregon Intertie (COI) north of the California Oregon Border (COB) trading hub while at the same time executing an opposite transaction at the John Day hub in central Oregon.
COB is a major delivery point for wheeling Northwest generation intended for markets in California. The John Day hub is predominantly used to price bilateral transactions involving output from hydroelectric and wind resources in central and eastern Oregon and Washington, often intended for delivery into California.
The John Day Dam and its substations comprise a primary pricing point for bilateral transactions involving output from hydroelectric and wind resources in central and eastern Oregon and Washington — often intended for delivery into California. Photo source: Oregon Dept. of Energy
PSE is one of six holders of capacity on the northern portion of the COI, with Seattle City Light, Pacific Northwest Generating Cooperative, Snohomish County Public Utility District, Tacoma Power and PacifiCorp’s merchant arm making up the rest of the group. The COI’s owners — Bonneville Power Administration, PacifiCorp and Portland General Electric — also control capacity on the system, which consists of three parallel transmission lines.
Macquarie Energy and PSE are both subsidiaries of Australia-based investment bank Macquarie Group.
Headquartered in Houston, Macquarie Energy operates as an independent power marketer throughout the U.S. The company does not own or operate generation or transmission assets in the Northwest, controlling only a small amount of generation, in the PJM balancing authority area, through long-term contracts. PSE is a vertically integrated utility serving about 1.1 million electricity customers in northern Washington. The utility also operates a wholesale marketing arm.
In 2012, the commission ruled that “when a simultaneous exchange transaction involves the marketing function of a public utility transmission provider, the public utility must seek prior approval from the commission if the transaction involves its affiliated transmission provider’s system.” Approval of such transactions would be made on a case-by-case basis, the commission said.
Macquarie’s July 14 FERC filing requesting the tariff change contested the need for the company to obtain prior authorization to engage in transactions at COB and John Day. The company said that while it is technically an affiliate of PSE, it does not function as PSE’s wholesale marketer or buyer.
The commission rejected that contention.
“We are not persuaded by Macquarie Energy’s argument that, because Macquarie Energy neither markets any of Puget Sound’s generation nor purchases any power for or on behalf of Puget Sound and only purchases point-to-point transmission from Puget Sound, its affiliate relationship with Puget Sound is not equivalent to acting as the wholesale merchant function of a transmission provider and therefore merits different treatment,” the commission wrote, adding Macquarie could potentially perform PSE’s wholesale market function.
The commission nonetheless authorized Macquarie to engage in the proposed trades, saying the company provided FERC with sufficient information to evaluate the transactions.
“We find that Macquarie Energy has adequately addressed the commission’s concern regarding circumvention of open access requirements and has demonstrated that its proposed transactions are not an attempt to offer transmission service without reserving transmission,” the commission wrote.
More important to the commission was the fact that Macquarie cannot use PSE’s network transmission to engage in the transactions, but must instead purchase point-to-point service in order to move energy between COB and John Day.
“The inability to use network transmission service mitigates the concern that Macquarie Energy’s proposed transaction will allow Puget Sound to earn revenue from both the explicit sale of transmission service and the implicit sale of transmission service via Macquarie Energy’s proposed transactions,” the commission wrote.
Furthermore, given the diverse ownership of capacity on the COI, Macquarie is not limited to purchasing point-to-point service from just PSE.
“Moreover, any transmission service obtained by Macquarie Energy on the COI would be under the [tariff] of the entity providing the service, including Puget Sound,” the commission said.
AARP and the Public Utility Law Project want New York regulators to provide more documentation to justify the Clean Energy Standard’s estimated $2/month rate increase for the average consumer.
The groups wrote to the New York Public Service Commission last week, saying the commission’s Aug. 1 CES order did not explain the costs to keep upstate nuclear power plants operating with zero-emission credits. (See New York Adopts Clean Energy Standard, Nuclear Subsidy.)
“AARP and PULP are very concerned that the Clean Energy Standard implementation (particularly the subsidy for power plants) may have costly impacts on New Yorkers already facing among the highest electricity rates in the nation,” the letter states. “The mention of a potential $2/month residential bill impact from the Tier 3 purchase of zero-emission credits in the order was not accompanied by any details or citation to where such an estimate was derived and fails to provide sufficient cost and bill impact information for each customer class, for each utility, or for the entire 12-year commitment to support these power plants.”
The groups cite estimates by PSC staff that the ZEC program could cost up to $8 billion over its 12-year term.
They also cite other utility programs that will be borne by ratepayers, including a $1.5 billion smart meter program in the Consolidated Edison territory, cost recovery for distributed energy demonstrations projects and $5 billion for clean energy and energy efficiency programs run by the New York State Energy Research and Development Authority.
These cases and the CES “simply cannot be viewed separately,” the groups add.
The letter comes days after downstate legislators complained that the ZEC program costs were disproportionately burdensome on New York City-area ratepayers. The PSC pushed back in a reply, saying the economic benefits and reduced emissions benefited ratepayers statewide. (See New York Legislators Question Nuclear Subsidy.)
VALLEY FORGE, Pa. — PJM’s Planning Committee held a special session last week to begin soliciting stakeholder input on changes to the RTO’s selection process for Order 1000 projects.
The goal of the ongoing sessions is to develop consensus on how decisions are made prior to the opening of the Regional Transmission Expansion Plan’s long-term proposal window Nov. 1, said Steve Herling, PJM’s vice president of planning and chair of the committee. The window, for market efficiency projects, will remain open through March 2017.
Eventually, the rules will be incorporated into PJM’s governing documents and receive FERC approval, but Herling acknowledged “there’s no way in the world that we’re going to have this approved at FERC before Nov. 1.”
At the meeting, PJM staff explained their concepts for the process, outlined a workflow diagram and highlighted a variety of examples to help stakeholders understand how PJM is likely to evaluate proposals.
“We’re trying to lay out our past thinking on this,” Herling said, “but … one of the whole points of this exercise is to start collecting metrics that you think need to be” included.
PJM hopes the input will provide perspectives it hadn’t considered so that proposals receive accurate, fair comparisons. While staff is attempting to be holistic in its evaluations, “we can’t say with absolute certainty that there won’t be a question raised by one of you that [shows] we missed some key benefit of one of your projects,” Herling said.
The RTO’s first Order 1000 project, the stability fix for Artificial Island in New Jersey, has been the subject of years of controversy and delay, both over PJM’s developer selection process and the resulting cost allocation. (See PJM Board Halts Artificial Island Project, Orders Staff Analysis.)
For market efficiency projects, PJM factors net load payment benefits, production cost benefits and overall PJM congestion benefits into its evaluation and requires a benefit-to-cost ratio greater than 1.25 to pass. Proposals that pass the B/C test then get evaluated for congestion reductions and overall changes, load payments, production costs and associated sensitivities, such as gas and renewable penetration, carbon policy and import/export requirements.
Stakeholders asked that development cost be considered and requested as much quantitative guidance as possible. They voiced concern about how carbon dioxide assumptions, forecasted long-term benefits and proposals offering cost caps are factored into the evaluation.
“We can’t have economic thinking thrown out the window here once a project crosses the B/C ratio,” Sharon Segner of LS Power said. PJM’s Suzanne Glatz pointed out that projects estimated to cost more than $50 million require independent cost analyses and constructability analyses.
“We do reserve the right to kind of break [proposals] down and put them back together to create a better, more cost-effective solution,” Herling said.
Further meetings on this topic are scheduled for Oct. 3, Oct. 21 and Nov. 11, during which PJM staff will introduce the regional metric for project selections.
SARATOGA SPRINGS, N.Y. — A forward capacity market may have worked for PJM and ISO-NE, but it isn’t the solution for NYISO, the Market Monitor told the Independent Power Producers of New York’s fall conference last week.
PJM and ISO-NE officials told an audience of about 100 that their forward markets have successfully incented new generation to replace retirements in their regions.
But The Analysis Group’s Paul Hibbard said the consulting firm’s 2015 study for the ISO found no compelling benefit to changing from New York’s current monthly prompt auctions. “We couldn’t find in our analysis … a real overwhelming level of support or level of rationale for … going through the effort of moving to a forward capacity market design,” said Hibbard, who moderated the session.
And Pallas LeeVanSchaick of Potomac Economics said instituting a forward market would be a time-consuming distraction from addressing the ISO’s biggest problems.
The Monitor called for “more logical local capacity requirements” and predefined capacity zones “so that resources know that if they come into a particular area to meet a reliability need … that there’s an economic signal that they’ll be rewarded for helping to satisfy.”
“Those would be important whether you have a spot market for capacity or a forward capacity market,” he added.
Robert Ethier, vice president of market operations for ISO-NE, said his RTO was forced to accept the forward capacity model in FERC-moderated settlement talks. “We were actually focused on a monthly market with a sloped demand curve much like you have here in New York,” he recalled.
Despite its origins, and the repeated changes to market rules since then, Ethier said, “it’s working pretty well.” The RTO says it has attracted 4,700 MW of new capacity resources — versus 4,200 MW of retirements — since 2013.
“That’s sort of the bottom line … for a capacity market: Is it getting you new resources to replace the resources that are exiting the market?” he continued. “At that high level, it’s been successful.”
Among the changes ISO-NE made was adjusting the calendar to address a disconnect in the auction timeline.
Retirements had been allowed up to one month before auction, while new resources had to declare their intent to enter the market a year in advance. Because it was impossible for new resources to respond to late-announced retirements, the RTO found itself with capacity shortfalls in Forward Capacity Auctions 8 and 9.
In April, FERC approved rules requiring retiring generators to declare their intention in March rather than October, while moving the “show of interest” deadline for new capacity market entrants from February to April. (See FERC Approves Changes to ISO-NE Retirement Rules.)
‘Not Here to Sell Anything’
Also on last week’s panel was Stu Bresler, PJM’s senior vice president of operations and markets, who responded to LeeVanSchaick’s criticism by making it clear “I’m not here to sell anything” to NYISO. He also acknowledged that PJM’s Reliability Pricing Model is “not immune” to changes, an apparent reference to a call by some stakeholders for an overhaul. (See Proposal to Revisit PJM Capacity Model Receives Tepid Response.)
But he noted that PJM has added almost 17,000 MW of capacity resources in the last five Base Residual Auctions, well in excess of the less than 2,500 MW of retirements announced. “If we didn’t have the forward capacity market, we’d have needed something else” to attract the new supply, he said.
The new resources mean that PJM, unlike NYISO and MISO, has rarely had to rely on reliability-must-run units. “If you define your region and your locational requirements for capacity sufficiently, you may have [only] some extremely localized issues that … will require some minor out-of-market actions.”
Ethier said ISO-NE has never had to invoke “backstop intervention” for reliability and has limited authority to do so. The capacity market, he said, is what ensures reliability.
“It focuses the mind and sharpens the pencil when you’re playing without a net,” he said.
Different Era, Different Needs
LeeVanSchaick said, however, that the concerns that prompted the capacity markers in the neighboring RTOs don’t apply to New York today.
Unlike the rapid load growth eras in which PJM and ISO-NE developed their capacity markets, New York is facing very little load growth, and new renewable resources are entering the market, driven by public subsidies, he said.
LeeVanSchaick also said the one-year commitment with a three-year forward time horizon is a bad fit for existing resources considering making capital investments they expect to pay back in five to 10 years. “And … the time frame in which they would make that decision is not three years ahead; it might be more like one year ahead,” he added. Forward markets don’t “line up well with those investment decisions, certainly not with the time frame in which demand response providers are looking to increase or decrease their position in the market.”
He said the ISO also needs to increase its reliance on the energy and ancillary services markets to recognize the value of more flexible resources needed to supplement intermittent generators.
And he called for tougher rules on buyer-side mitigation and combatting uneconomic retention.
Cost, Time
The Analysis Group’s Hibbard said his firm’s report estimated it would cost $10 million and take three years to create a forward capacity market.
Both Ethier and Bresler said the additional administrative costs of the forward auctions are insignificant given the size of their $3 billion and $7 billion-plus markets, respectively.
Ethier estimated the forward market increased ISO-NE’s administrative costs by about $1 million annually compared to a prompt market. Bresler said seven PJM employees administer the RPM.
But Ethier acknowledged LeeVanSchaick’s concern about the “opportunity cost” of implementing the market.
“It basically slid all our initiatives out a couple of years. We would have had hourly markets much sooner, for example.”
LeeVanSchaick said the rationing of resources to pursue market initiatives suggests “the ISO budgets are lower than maybe the efficient level of funding for an ISO. … There’s often haggling over a small amount of money to develop a new project [even though] any of the projects that we’re talking about could potentially pay for themselves from the social welfare standpoint in a matter of months.”
