PJM began its first RTO-wide solicitation for black start service July 1, with proposals accepted through Sept. 30.
Respondents to the request for proposals (RFP) must be capable of: starting without an outside electrical supply; closing their output circuit breakers to a de-energized bus within three hours or less; maintaining frequency and voltage under varying load, and maintaining rated output for a specified time, typically 16 hours.
Existing black start providers do not need to submit proposals.
The RFP is one of the recommendations of the System Restoration Strategy Task Force, which also increased the pool of potential resources through revisions to the definitions for black start units and critical load to be served by them.
PJM expects to lose some existing black start capacity by 2015 as a result of the planned retirements of coal-fired generators squeezed by EPA regulations and low natural gas prices.
PJM announced this morning that the Board of Managers has approved a new contract with Monitoring Analytics, PJM’s independent market monitor. The contract, which must be approved by the Federal Energy Regulatory Commission, runs through 2019.
The contract ends — for the time being, at least — the latest dust-up among PJM and its stakeholders over the independence of the market monitoring function.
In March, states, industrial consumers and cooperatives protested the board’s plan to issue a request for proposals for monitoring services. The stakeholders said the board’s proposed RFP contained language that would undermine the independence and quality of the monitoring function. They also expressed concern that PJM would suffer a loss of institutional knowledge if it replaced Monitoring Analytics, LLC, which has been operating as the Market Monitor under the terms of a 2008 FERC settlement (EL07-56).
The board responded in April by announcing it was negotiating a new contract with the company and dropping plans to put the contract out for bid.
On July 2, however, the Organization of PJM States, which represents state regulators, sent a letter to the board complaining that it had not been consulted in the drafting of the new contract.
“We are frankly baffled by an apparent reluctance on the part of the board to consult with OPSI on the new contract language prior to the execution of the contract,” wrote Maryland Public Service Commissioner Lawrence Brenner, chairman of OPSI’s market monitoring committee. “…As a procedural matter it is doubtful that FERC created the OPSI Advisory Committee if the only beneficiary of its advice was to be the commission itself.”
Brenner told RTO Insider today that OPSI received a copy of the 19-page contract after it was signed July 8. He said OPSI may work with PJM and the monitor to address its concerns in PJM’s filing seeking FERC approval of the contract.
“There are a couple areas where we’ve suggested that some clarification would be helpful,” he said. He declined to go into specifics, saying he was speaking for himself and not OPSI.
Asked what OPSI’s exclusion from the negotiations said about its relationship with PJM, Brenner said “I wouldn’t read too much into it. We have a pretty good relationship with the board.
PJM President and CEO Terry Boston said in a statement that “robust, independent monitoring services are essential to PJM’s ability to administer fair and efficient wholesale electricity markets.
“The competency, integrity and analytical capability of the Monitoring Analytics staff is well known and appreciated at PJM and we look forward to continuing to work productively with them for the benefit of the region we serve.”
Monitoring Analytics President Joseph Bowring also issued a statement, saying “We look forward to a productive relationship with the board, with PJM and with PJM members in the coming years.”
A Ph.D. economist, Bowring has served as PJM’s market monitor since 1999. At a FERC technical conference in 2007, Bowring accused then-PJM President Phil Harris and his allies of attempting to muzzle him by squelching his reports and cutting his budget. Following an investigation, Harris resigned and FERC approved a settlement in which Bowring formed Monitoring Analytics and was awarded a six-year contract. The contract was worth about $10 million per year.
Brenner said yesterday that OPSI will be looking closely at the new contract provisions that govern the balance between the monitor’s independence and the board’s right to provide oversight of its performance.
“Both the market monitor and PJM tell us that the negotiations were very respectful and not contentious,” Brenner said. “All those things are a change from some years ago.”
PJM’s first competitive transmission project under FERC Order 1000 attracted proposals from five utilities and three independent developers.
Salem and Hope Creek Nuclear Reactors on Artificial Island. Photo Taken By Peretz Partensky from San Francisco, USA [CC-BY-2.0 (http://creativecommons.org/licenses/by/2.0)], via Wikimedia Commons
The proposals – to correct stability issues at Artificial Island, home of the Salem and Hope Creek nuclear plants, in Hancocks Bridge N.J. – ranged from a new 230 kV line and station (estimated cost $116 million) to two new 500 kV lines (a projected $1.5 billion price tag).
The Federal Energy Regulatory Commission’s Order 1000 eliminated incumbent utilities’ Right of First Refusal on construction and operation of new transmission projects, opening the business to competition from independent transmission developers.
The diversity of technical solutions and cost estimates submitted for the Artificial Island project appears to validate FERC’s prediction that competition could reduce costs and increase innovation in transmission development.
In all, 26 proposals were submitted, led by PSE&G with 14 alternatives. Transource Energy, a partnership between American Electric Power and Great Plains Energy (owner of Kansas City Power & Light Co.), submitted four proposals, while Virginia Electric and Power Co. submitted three and LS Power offered two. FirstEnergy Corp., Atlantic Wind Connection and a partnership between Pepco Holdings Inc. and Exelon Corp. each made a single proposal.
PJM planners will evaluate the proposals through analyses including thermal and short circuit studies.
Here is a summary of the proposals which were outlined to the Transmission Expansion Advisory Committee on Wednesday:
Atlantic Wind: Install a HVDC converter station near Artificial Island; Install a SVC at the new Artificial Island HVDC station; Install a HVDC converter station near the existing Cardiff 230 kV; Install a 320 kV HVDC facility from the Artificial Island HVDC station and the HVDC station near Cardiff 230 kV. Cost: $1.012 billion.
FirstEnergy: Install a new, New Freedom – Smithburg 500 kV line with a loop into the Larrabee 500 kV; Install two new 500/230 transformers at Larrabee; Install a Hope Creek – Red Lion 500 kV line. Cost: $452.3 million (cost submitted does not cover entire project).
LS Power: Two proposals:
Least Expensive: Install a new Salem – Silver Run 230 kV line with a 500/230 kV transformer at Salem; Install a new 500/230 kV station that taps the existing Red Lion – Cedar Creek 230 kV and Red Lion – Cartanza 230 kV lines. Cost: $116 to $148 million.
Most Expensive: Install a new Salem – Red Lion 500 kV line. Cost $170 million.
PHI/Exelon: Install a new Peach Bottom – Keeney – Red Lion – Salem 500 kV line; Remove existing Keeney – Red Lion 230 kV circuit; Reconfigure the existing 230 kV line from Hay Road – Red Lion (23020) to terminate at Keeney instead of Red Lion; Re-conductor the Harmony – Chapel Street 138 kV line. Cost: $475 million.
PSE&G: 14 proposals.
Least expensive: Install a new New Freedom – Deans 500 kV line; Install a new Salem-Hope Creek 500 kV line. Cost: $692 million.
Most expensive: Install new New Freedom – Whitpain North 500 kV line; Install a new Salem-Hope Creek-Red Lion 500 kV line. Cost: $1.548 billion.
Transource: Four proposals.
Least expensive: Install a new Salem – Red Lion 500 kV line. Cost: $123 to $156 million.
Most expensive: Install a new New Freedom – Lumberton – North Smithburg 500 kV line with new 500/230 sub east of Lumberton. Cost: $788 to $994 million.
Virginia Electric and Power: Three proposals.
Least Expensive: Install a new 500 kV line from Salem 500 kV to a new station in Delaware; Install a new station in Delaware that taps the existing Red Lion – Cartanza 230 kV and Red Lion – Cedar Creek 230 kV lines. Cost: $126 million.
Most expensive: Install a new 500 kV line from Hope Creek 500 kV to a new station in Delaware; Install a new station in Delaware that taps the existing Red Lion – Cartanza 230 kV and Red Lion – Cedar Creek 230 kV lines; Install a new Salem – Hope Creek 500 kV line. Cost: $202 million.
There’s an important PJM meeting today — but you’ll have to listen in yourself if you want to know what happens.
The Liaison Committee’s irregular meeting with the Board of Managers will be held at 4 p.m. EDT today in Chicago. The meeting is open only to PJM members and regulators. No public. No press.
“The members felt that they needed to have a forum where they could hold candid, informed and informal discussions with the Board,” committee secretary Dave Anders, manager of stakeholder affairs, explained in an email.
Anders noted that no decisions are made at these meetings, which are “simply opportunities for discussion.”
The fact that no decisions are made does not negate the import of these sessions, however. They are one of the few opportunities for members to observe and interact with the board: From 2009-2012, the Liaison Committee met an average of three times per year. And the four issues on today’s agenda have been the subjects of considerable controversy:
The Markets and Reliability Committee approved a charter for a task force it created in March to study potential reliability problems resulting from PJM’s increasing dependence on gas-fired generation.
The task force is expected to continue work last through the 2016/2017 delivery year, during which PJM expects the significant additions of gas-fired generating capacity to replace coal retirements.
All PJM stakeholders may appoint representatives to the task force. Sean McNamara will be the chairperson and Rami Dirani the secretary.
PJM and MISO have a communication problem. “We talk past each other,” David Patton, MISO’s independent market monitor, told the Federal Energy Regulatory Commission June 20.
The topic was the way PJM models cross border transmission deliverability, which MISO says is unfairly limiting its generation from competing in PJM’s capacity market.
MISO says its generators sold only 900 MW into PJM’s capacity market for 2014/15, less than a quarter of what it says PJM could safely import. PJM’s market monitor says MISO’s export sales for 2014/15 are more than 2,100 MW.
The RTOs’ inability to agree on even this baseline data is why FERC summoned them to the unusual commission meeting last month. In the Q&A below, RTO Insider summarizes the capacity deliverability issue and tells what’s at stake.
Q. What is the factual dispute?
The central issue is whether the PJM modeling rules reflect actual transmission constraints or unfair barriers to entry.
MISO says the Total Transfer Capability from MISO to PJM is 5,300 MW to 6,300 MW. Actual capacity sales from MISO to PJM, however, were only about 400 MW (net) for the 2014/2015 delivery year. As a result, it says “at least 4,000 MW of transfer capability has not been used despite available resource and strong economic incentives.”
That additional generation, MISO said, would reduce PJM’s clearing capacity price enough to save PJM consumers about $1.1 billion for the year.
MISO’s Independent Market Monitor, David Patton, supports MISO’s complaint. Patton said PJM’s transmission reservation processes allows participants to hoard long-term firm transmission into the RTO.
Patton said PJM’s generation owners have avoided discussing the issue for five years because additional capacity imports “would lower the inflated clearing prices that generators currently enjoy.”
The Ohio Consumer Counsel agreed. “PJM generation interests may not be eager to face the additional competition that would result from removing barriers to capacity transfers between RTOs.”
PJM Response
PJM says MISO’s complaints are belied by PJM’s 2016/17 capacity market auction in May, in which 4,700 MW of MISO capacity bid, all of it clearing. That was more than double the volume that bid in last year’s base auction; about one quarter of the total came from territory new to MISO, including the Entergy transmission system.
PJM Capacity Imports from West (Source: PJM Interconnection LLC)
The barriers MISO is asking FERC to eliminate, PJM says, “are in fact actual physical constraints and reliability limits.”
PJM Independent Market Monitor Joseph Bowring told FERC that PJM’s capacity market “is physical and it is linked to specific units. It’s not slice of system or liquidated damages.” What MISO calls barriers are “key attributes” of the PJM system, he said.
Bowring said MISO’s voluntary capacity market is not competitive and “doesn’t monetize IPPs (independent power producers) and unregulated generation. That’s why they want to sell into PJM.”
The dispute highlights the differences in the wholesale markets and state regulatory schemes between the two regions: Most of the states in MISO have traditional cost-of-service regulation while PJM’s development over the past 15 years was largely driven by its states’ embrace of retail choice.
Those differences also are seen in the divergent interests of stakeholders in the MISO-PJM Joint and Common Market initiative. MISO members identified capacity deliverability as one of the highest priorities among the more than two dozen matters pending before the group; PJM’s stakeholders listed the issue as a low priority.
In fact, of 28 issues under consideration by the JCM, the two sides disagree on the prioritization for all but 10. The two also are at odds over a key issue in their Order 1000 compliance filing on interregional transmission planning, due July 10.
Q. What is MISO’s proposal?
MISO said it and PJM can increase transfers between their systems by replacing the current point-to-point transmission service with a cross border product that functions like network service. Modeling of transfer limits in capacity auctions would be done by zone rather than by individual generators. MISO likens the process to the way in which RTOs integrate new balancing authorities.
PJM Response
But PJM says that kind of coordination would require a single day-ahead dispatch — an idea the RTOs previously rejected because the costs would exceed benefits. The logical extension of MISO’s proposal, Bowring says, is a single market. “That’s really what’s being talked about. That’s really the ultimate market without seams.”
PJM says MISO’s “zonal deliverability” proposal shifts costs because transmission upgrades needed to ensure deliverability would be billed to PJM loads as base line upgrades in the Regional Transmission Expansion Plan (RTEP), instead of being allocated to MISO generation.
PJM also criticized MISO’s proposal that it eliminate its Capacity Benefit Margin (CBM), a portion of PJM’s emergency import capability that is deducted from Total Transfer Capability to determine Available Transfer Capability.
Eliminating CBM will increase capacity costs, PJM contends, because it would increase PJM’s reliability requirement for the 2015/2016 RPM auction by about 2,766 MW — resulting in a $300 million increase in PJM capacity costs.
“Reckless”
PJM said a key part of MISO’s proposal — that capacity deliveries between PJM and MISO can maximized by assuming simultaneous counter-flow offsets —is “reckless.”
“This assumption is only valid if PJM and MISO would always enter into capacity emergency conditions at the same time so the counter-flows will always exist when they are needed to minimize transfers,” PJM said. “However history has proven that most capacity emergency events occur in one RTO or the other but not in both simultaneously.”
Q. What happens next?
While individual state regulators have taken sides in the dispute, the organizations representing them — the Organization of PJM States, Inc. (OPSI) and the Organization of MISO States (OMS) — have tried to stay out of the fray.
In a February filing, OPSI and OMS said they were “confident that the capacity deliverability issue will receive, in the JCM process, the attention that it deserves on a schedule it deserves.”
But in a June 13 filing, the groups said the RTOs should hire a consultant to mediate and conduct fact finding if they are unable to come to an agreement. The consultant would help select methodologies for determining transfer capability between the RTOs and the amount of capacity that can be bid into each other’s markets. It also would determine the feasibility and cost effectiveness of potential rule changes.
Possible FERC action
MISO asked FERC to set deadlines on the resolution of the issue, “What we’re asking is for the commission to give us the same kind of nudge you gave us to create the JCM,” said Clair Moeller, MISO executive vice president of transmission and technology.
PJM, however, asked FERC to close the docket, saying that putting this issue on a separate track from others before the JCM would be “disruptive.”
By their comments at the June 20 meeting, FERC commissioners indicated they would likely increase their scrutiny of stakeholder proceedings on the issue, if not going so far as to set deadlines.
Commissioner Philip Moeller said the talks could benefit from the “discipline of a deadline.”
Commissioner John R. Norris said MISO may be correct in its complaint that PJM rules are artificially restricting capacity imports below physical transport limits. “My sense is, there is a there there.”
Generator representatives Thursday voiced their opposition to a proposal to set earlier deadlines for seeking exemptions from participation in PJM’s capacity market auctions.
The joint PJM-Market Monitor proposal would require generators seeking exemption from the “must-offer” requirement to file notice by Sept. 1 for the annual base residual auction (BRA) and 120 days before incremental auctions. The exemptions apply to generators that will be unable to provide capacity because they plan to retire.
The Capacity Senior Task Force approved the change by a narrow 65-63 vote. To ease the transition, PJM subsequently amended the proposal allow a Nov. 1 deadline for next year’s 2017/18 BRA. The Sept. 1 deadline would take effect with the 2018/19 BRA.
The Markets and Reliability Committee will consider the change at its next meeting.
PJM Vice President of Market Operations Stu Bresler told the MRC Thursday that the current rules, which require 120 days’ notice before the opening of the auction, don’t give PJM enough time to analyze the impact of plant retirements on system operations.
Staffing Concerns
John Horstmann, director of RTO affairs for Dayton Power & Light, said the proposed change could cause staffing problems at generators that will be forced to announce retirements earlier. “It’s hard to keep people working” when they know they are on borrowed time, Horstmann said.
Horstmann said the change also doesn’t differentiate between retirements of large plants with a major impact on the system and those of small plants in large zones, where there would be minimal impact.
John Citrolo, markets director for PSEG Energy Resources and Trade, LLC, said the proposal is discriminatory to “existing megawatts” because new resources and demand response can wait until seeing PJM’s planning parameters — for example, identification of Locational Deliverability Areas — to decide whether to enter the auction.
A Big Deal
Neal Fitch, of NRG Energy, called the change an overreaction, saying PJM has enough resources to respond to late deactivations without harm to reliability. “We’ve seen the shrugging shoulders that [suggests] `it’s not a big deal.’ It is a big deal,” Fitch said.
Reem Fahey, vice president of market policy for Edison Mission Marketing and Trading, said PJM’s proposal will burden generators without addressing the RTO’s concerns. “It creates a financial obligation on the generation owner,” she said. “You’re not allowing new entry to come into the market and replace it.”
Andy Ott, PJM senior vice president for markets, said the rules will create incentives for generation owners doing plant retirement analyses “to make the decision a few months earlier.”
The Markets and Reliability Committee Thursday approved two changes to the modeling of Financial Transmission Rights — an effort PJM hopes will reduce the risk of FTR funding shortfalls.
The changes make FTR modeling more consistent with that used in the energy markets and reduce or remove infeasibilities in the FTR model, allowing increased counterflow FTRs to clear.
The Financial Transmission Rights Task Force chose the two changes from more than 20 options.
Under the first change, PJM “may model normal facility capability limits, if possible, for all Stage 1A over allocated facilities in FTR Auctions.”
The second change will allow PJM to “model normal facility capability limits, if possible, on facilities which are infeasible as a result of modeled transmission outages in monthly FTR Auctions.”
PJM’s Tim Horger said the RTO hadn’t quantified the impact of the changes, although an analysis for one constraint found more than a $15 million improvement in FTR adequacy.
Wind farms that fail to follow PJM’s electronic dispatch signals will no longer receive lost opportunity cost payments under a tariff amendment outlined to the Markets and Reliability Committee Thursday.
The MRC approved a problem statement that — in a departure from normal practice — was accompanied by the proposed tariff change. The tariff change will be brought to a vote at the next MRC meeting.
PJM proposed adding language to Section 3.2.3 of Tariff Schedule 1 to deny lost opportunity credits to pool-scheduled or self-scheduled wind generators that fail to follow PJM dispatchers’ electronic instructions to reduce output.
“We have (wind) operators not following the economic basepoints,” PJM’s Dave Souder told members. “They’re waiting for PJM to call them.”
Having to issue manual dispatch instructions delays generators’ responses, causing less efficient market operations and a potential risk to system reliability, PJM says.
PJM proposed the new language as a Tariff change in response to a May 29 Federal Energy Regulatory Commission order that rejected its earlier proposal to incorporate the new rules in the Operating Agreement. The commission said the OA language “failed to provide any detail or tariff language describing the specific circumstances under which compensation would be reduced or how the compensation would be reduced.”
Robert O’Connell, vice president of J.P. Morgan Ventures Energy Corp., said the rules were unfair because they were “developed behind closed doors” and would treat wind differently than other generation. O’Connell also objected to the inclusion of the tariff language in the problem statement. “Anything that comes with tariff language is a solution,” he said.
Mike Kormos, PJM senior vice president for operations, said PJM already had rules penalizing other forms of generation for not following dispatch instructions. “We’ve had this in the rules for eternity,” he said.
Market Monitor Joseph Bowring supported PJM’s proposed tariff change as “exactly right.
“This is a narrow problem that needs to be addressed,” he said.
O’Connell’s motion to return the problem statement to the Market Implementation Committee without the tariff proposal was ruled out of order by Kormos, the chairman of the MRC. Kormos said it would set a precedent to prevent a vote on a problem statement.
In a rare move, O’Connell appealed the parliamentary ruling to the members. His appeal received less than 15% support in a sector-weighted vote, far below the two-thirds needed to overturn the ruling.
The problem statement was approved with three abstentions and no objections.
If it’s the last Thursday of the month it’s meeting time for PJM’s two senior committees – and likely a vote on at least one problem statement directed at demand response resources.
At last week’s session, the Markets and Reliability Committee approved one problem statement and deferred a vote on a second that would change rules affecting DR. Meanwhile, the Members Committee approved a tariff change that increases DR providers’ documentation requirements.
The problem statement approved by MRC will explore changes to the way PJM calls on DR. The deferred issue would look at ways to ensure that DR and other resources offered into the capacity market show up in their delivery year.
“There’s been a freight train of changes for the DR market that have happened without evaluation of [the impact of] prior changes,” Dan Griffiths, of DR aggregator Comverge, said during a discussion on the first issue.
In a discussion on the second problem statement, Griffiths used a different metaphor, saying he was “disturbed by the sort of layer cake of similar issues that are being brought before us.” He cited the earlier problem statement as well as DR issues before the Capacity Senior Task Force. He urged PJM staff to review all pending inquiries affecting DR and seek a more coordinated approach.
DR as an Operational Capacity Resource
PJM told the MRC it wants to begin treating DR as “operational” capacity resource, subject to economic dispatch.
Andy Ott, PJM executive vice president for markets, said the change is needed because current rules treat DR as a “homogenous” block that cannot be tapped without declaring an emergency. “We simply can’t be declaring an emergency every time we need to access this capacity,” he said. “… What we want to do is get rid of the cliff and make it more gradual.”
The committee approved an amended version of the problem statement with four objections and 20 abstentions. The amendments were offered by Katie Guerry, representing curtailment service provider EnerNoc, who said the changes gives PJM the more flexible resources it desires “while preserving the flexibility that CSPs need.”
A motion by Bruce Campbell, of EnergyConnect, to add consideration of the impact on CSP’s operating costs was rejected. Campbell said he was “unconvinced” that the changes were needed for PJM operations rather than “an attack on DR.”
Potential outcomes of the inquiry include:
Changes to DR obligations to move from administrative procedures to economic dispatch.
Diversifying notification time requirements based on physical response capability, similar to current requirements for generators.
Allowing DR to operate with a dispatchable range.
Caps on the amount of Limited DR that can be cleared above the quantity specified in the reliability analysis. PJM says current rules allow Limited DR to fill all of the excess supply under the downward sloping demand curve, which hurts its effectiveness as an investment signal for long term resources.
Changes in the way DR is modeled in PJM planning studies.
Griffiths expressed concern that changes ordered now would be effectively retroactive because of CSPs sell their resources into the future. “We sold capacity based on how we believed the market would work. If we knew the rules were going to change we would have sold differently,” Griffith said.
However, he said the increased flexibility being considered “is actually good for us” because it provides more options for sales.
Physical Delivery of Capacity
DR providers had more luck slowing down the “freight train” when the MRC rejected a request by Jason Barker of Exelon to immediately vote on his problem statement to modify the design of the Reliability Pricing Model to ensure physical delivery of resources that clear the capacity auction. The issue will be brought to a vote at the next MRC meeting.
Barker said the current design lacks sufficient penalties for those who offer capacity resources but fail to produce them in the delivery year.
He said the problem statement was needed to address reliability concerns caused by the increase in non-firm, planned resources clearing in the past three base residual auctions — including uncontracted demand response, planned internal generation, and existing and planned external generation that lacks firm transmission service.
A failure of more than 16% of these “prospective” resources would leave PJM below its target reserve margin, Barker said.
He noted that more than a third of generation imports clearing in May’s 2016/17 BRA lacked a complete firm transmission path. He also cited a report from the Market Monitor that found more than one-quarter of DR purchased replacement capacity in incremental auctions for the 2012/13 Delivery Year.
Increasing Concern
Andy Ott, PJM executive vice president for markets, acknowledged that PJM has “not historically seen high non-delivery rates.” But due to the increasing amount of new entry and imports, he said, “there has been increasing concern that the physical nature of the RPM needs to be emphasized.”
Barker said current rules encourage marketers to purchase replacement capacity in the interim auctions to lock in profits.
The market monitor’s report concluded that the current penalties for failing to deliver — the seller’s weighted average resource clearing price for the resource plus the higher of 0.20 times the clearing price or $20 per MW‐day — are not enough of a disincentive.
Barker also said PJM should develop milestones to track the progress of prospective or planned resources.
Susan Bruce, an attorney representing industrial consumers, said she was concerned “we’re looking at the tail of the dog, not the whole dog,” noting that PJM’s load forecasts have been higher than reality. Barker said although PJM’s load forecast has been 5% or more too high, it doesn’t eliminate the issue.
Aaron Briedenbaugh, of EnerNoc, said he supported the inquiry because it will look at generation in addition to DR.
Members Committee Action
Later Thursday, the Members Committee endorsed tariff changes in response to FERC’s April order that the RTO seek commission approval for new rules requiring demand response providers to provide officer certifications and additional information on their customers.
FERC said the changes required amendments to the PJM tariff and not just its manuals. Tariff changes require commission approval while manual changes don’t.
The rules require curtailment service providers seeking to participate in capacity auctions to file “Sell Offer Plans,” including information about the provider’s customers. CSPs also must have a company officer sign a certification attesting to the company’s intent to physically deliver MWs.
![Salem and Hope Creek Nuclear Reactors on Artificial Island. Photo Taken By Peretz Partensky from San Francisco, USA [CC-BY-2.0 (http://creativecommons.org/licenses/by/2.0)], via Wikimedia Commons](/ext/resources/2013/09/Salem_and_Hope_Creek_Nuclear_Reactors_7238282472.jpg)
