FERC ordered hearing and settlement procedures in a dispute over capacity obligations in an area of Northern Maine separate from ISO-NE (ER17-192).
The dispute concerns the Northern Maine Independent System Administrator, whose transmission system is not directly connected with the rest of New England and whose market participants are not subject to ISO-NE’s jurisdiction and do not participate in the New England Power Pool.
At issue is the ISA’s request to eliminate a requirement that market participants prove the deliverability for resources located outside Northern Maine but within the New Brunswick balancing authority area, of which the ISA is a part.
NMISA said the deliverability assurance requirement in its market rules is no longer needed because its rebuild of Line 691 and planned spring 2017 upgrade of the Tinker transformer at the New Brunswick-Northern Maine interface will eliminate the transmission constraint into the area.
The request was protested by ReEnergy Biomass Operations, which owns the 37-MW Fort Fairfield and 39-MW Ashland generating plants in Aroostook County, within the NMISA control area.
Ashland Generating Station | ReEnergy Holdings
ReEnergy contends that even after completion of the upgrade, as much as 140 MW of load in Northern Maine could be reliant on 98 MW of available transmission capacity from New Brunswick. It said the upgrade was required to support 74 MW of existing firm reservations, meaning the upgrade would only add 24 MW of additional firm transmission capacity. Eliminating the deliverability requirement would impact reliability and distort price signals, it added.
NMISA disputes ReEnergy’s calculations, saying its 140-MW load estimate includes Eastern Maine Electric Cooperative, which should not be counted because it is not connected to New Brunswick via the Emera Maine-New Brunswick interface.
It said that the total Emera Maine capacity requirement for summer 2016, including reserve margin, was 124 MW, below the 129-MW total summer transfer capability from New Brunswick to Northern Maine once the upgrade is complete.
The authority said ReEnergy opposes the changes because it wants to maintain a competitive advantage in the area. If the requirement were maintained, market participants would be incented to hoard firm transmission capacity, preventing other resources from competing in the market, it said. The authority’s position was backed by the Maine Public Utilities Commission, which also said it feared reduced competition and higher prices if the rule remained.
FERC’s Dec. 22 order accepted NMISA’s proposed change subject to refund but suspended it, saying it needed more information to resolve the factual dispute over how much capacity will be provided by the upgrade.
“NMISA has not demonstrated that the Tinker upgrade located at the New Brunswick-Northern Maine interface will relieve the constraint at this interface, or that capacity located inside and outside of the Northern Maine transmission system is capable of meeting Northern Maine’s peak load capacity requirements before and after the Tinker upgrade,” the commission said.
FERC has issued a deficiency notice requesting more information from PJM on its proposal to incorporate more seasonal resources under Capacity Performance (ER17-367).
PJM has until Jan. 22 to respond to the Dec. 23 notice, which asks for more detail and specific examples about its plan to integrate seasonal resources into capacity auctions and incorporate them into operational protocols. The proposal would relax the current prohibition on seasonal resources aggregating across locational deliverability areas. In October, the RTO angered some stakeholders when staff announced at the annual meeting of the Organization of PJM States Inc. that it was filing its proposal despite a lack of stakeholder consensus. (See PJM to Seek FERC OK for Seasonal Capacity Proposal.)
Unadilla Solar Project | Allco Renewable Energy
“The proposed [Open Access Transmission Tariff] revisions appear unclear as to how PJM will determine which Seasonal Capacity Performance Resource offers clear an auction and which do not, and how PJM will ensure least-cost capacity procurement,” the commission wrote.
It asked if offers will be put in auctions individually or paired with a resource from the opposite season with an aggregated offer price. FERC also asked how PJM’s optimization algorithm will compare seasonal and annual resources, at what price the algorithm would stop clearing seasonal resources and how it will break ties if multiple seasonal resources submit identical offer prices.
The RTO’s proposal would allow resources to aggregate beyond LDA borders, with unmatched resources moving up to the next LDA level until a match is found.
FERC wanted more detail on how PJM’s cross-LDA aggregation concept would affect operational procedures, noting that the current proposal allows a seasonal resource to clear an auction, be counted toward the reliability requirement of an LDA other than the lowest level one in which it’s located and receive a clearing price less than that of the lowest-level LDA.
The commission also asked how a resource could be subject to a performance assessment hour in the LDA where it’s located, but receive the clearing price and help with the reliability requirement for the LDA in which it cleared the auction. It wanted to know how PJM plans to apply performance-related charges and credits and what rates will apply.
FERC also asked if the RTO intends for fixed resource requirement capacity plans that include seasonal resources to have equal quantity of summer and winter resources.
The commission wondered why PJM created a way for summer demand response to offer into auctions, but not for winter resources. “Why does PJM propose to exclude a winter-period demand resource from participating as a seasonal Capacity Performance resource?” it asked.
FERC also showed interest the differences between seasonal resources, asking PJM to opine on whether resources from one season or the other make a bigger difference on system reliability. It asked about any documentation PJM has on the topic.
WILMINGTON, Del. — A proposed revision to credit requirements for financial transmissions rights participants received significant stakeholder debate before the Markets and Reliability Committee and withered under the scrutiny.
The proposal was supported by FTR holders who complained that the “undiversified credit adder” applied to net counterflow portfolios caused over-collateralization of some FTR portfolios. The proposal, approved by the Credit Subcommittee, eliminates the adder in exchange for increasing the historical adjustment factor in underlying credit calculations for historically counterflow paths from 10% to 25%.
The adder was created following the $52 million credit default by Tower Research Capital’s Power Edge hedge fund in 2007. Members agreed to review it following a 2013 survey of issues of concern to the Credit Subcommittee.
Exelon’s Sharon Midgley had complained at the Dec. 14 Market Implementation Committee meeting that the change would increase her company’s credit costs, but the committee approved the change 88-34. (See “Credit Limit Changes Pass Despite Exelon Objections,” PJM Market Implementation Committee Briefs.)
That changed in the sector-weighted vote at the MRC on Dec. 22, where it won a majority of only one sector (69% of Other Suppliers), scoring only a 1.25 out of 5.
Exelon’s Jason Barker criticized how the credit increases would be implemented, saying it would be taking large “chunks” of credit from overcollateralized portfolios and “peanut-buttering” it over other undercollateralized ones. “We think that the balance is certainly off,” he said.
“From a customer perspective, I think it’s difficult to take the chance as we know the facts today,” said Susan Bruce of the PJM Industrial Customer Coalition. “I’m not in a position to take a chance, but I’m willing to talk more about this.”
PJM’s Stu Bresler said the RTO “doesn’t have a dog in the fight” over whether members are willing to accept potential defaults. But he said it does have a long-term concern.
“Even if the members are willing to accept additional risk … we have to consider the effect and potential ramifications,” he said. “I think it goes beyond reputation. It goes to the confidence to participate in the markets if [a default] were to occur again.”
Under current rules, collateral held by PJM would have covered all of the $52 million in FTR net counterflow portfolio losses in 2007-8. Under a proposed rule change, only $8 million of the losses would have been covered, leaving PJM members to reimburse $44 million, according to stress tests by the RTO.
Opponents of the changes, including the Independent Market Monitor, preferred to maintain the current protections against events like the Tower default. “I’d prefer that something like that never occur again,” American Municipal Power’s Ed Tatum said. “I haven’t seen an upside for the stakeholders but for those who are performing these transactions.”
Bruce Bleiweis of DC Energy called the proposed changes “good policy” that “right-sizes” credit portfolios. He also questioned whether the incident that precipitated the changes could occur again given rule changes that have been implemented in the interim.
“We don’t think that’s an accurate stress test because we don’t think that the Tower portfolio would have occurred,” he said. Tower wouldn’t have taken the position because its bid collateral would be more than $35 million today, he theorized.
FERC denied Berkshire Hathaway Energy’s request to rehear a ruling prohibiting the company’s subsidiaries from selling electricity at market-based rates in four neighboring balancing authority areas in the West.
The commission’s June 9 decision restricted Berkshire-owned utilities PacifiCorp and NV Energy and 19 other affiliates from offering power at market rates in the PacifiCorp East (PACE), PacifiCorp West (PACW), Idaho Power and NorthWestern Energy areas based on concerns about horizontal market power. (See Berkshire Market-Based Rate Sales Restricted in 4 BAAs.)
FERC denied the Berkshire Hathaway Energy request to rehear a decision that revoked the ability of the company’s subsidiaries from selling power at market-based rates in the IPCO, NWMT, PACE and PACW balancing authority areas.
In its Dec. 21 order, the commission rejected Berkshire’s contention that the June ruling had denied the company due process because of FERC’s failure to convey “newly announced standards for determining market power” ahead of the company’s initial “change in status” filing, which was triggered by the 2013 acquisition of NV Energy (ER10-2475, et al.).
“We clarify that the June 9 order did not create new criteria for obtaining or retaining market-based rate authority,” the commission said. “Rather, in the June 9 order, the commission identified areas where the [Berkshire companies’] analysis fell short of existing requirements and, where appropriate, provided suggestions for meeting the requirements.”
The commission did approve the Berkshire subsidiaries’ revised market-based rate tariffs filed in compliance with the June order and clarified that the companies are entitled to propose new cost-based rates for making sales into the four areas, rather than being limited to relying on default cost-based rates.
The commission also terminated the Section 206 proceeding on the matter.
In its June 9 order revoking market-based rate authority, the commission found that the Berkshire companies failed to provide reliable delivered price test (DPT) analyses rebutting the presumption of market power in the four balancing authorities.
FERC policy allows companies to submit a DPT after failing the indicative “pivotal supplier” and “wholesale market power” screens for initially assessing horizontal market power within a balancing area.
The DPT offers a company the chance to provide more granular market power assessment that factors in native load commitments to determine a supplier’s “available economic capacity” — energy available for offer in the open market.
The commission’s decision to revoke Berkshire’s market-based rate authority ultimately rested on what the commission called a “flawed” DPT analysis from the company. The commission pointed to Berkshire’s failure to calculate unique season and load levels for each of the four areas, instead relying on assumptions based on data for only the PACE area.
In its July 11 request for rehearing, Berkshire countered the commission’s findings by arguing that each of its 57 “unique” DPT analyses “was prepared in accordance with the commission’s previously announced requirements and each was similar in form and substance to” analyses the commission had previously approved. (See Berkshire Contests Market-Based Sales Restriction in West.)
“The [Berkshire companies] failed to provide any historical transmission data, eTag or otherwise, to corroborate the results of their DPTs as required by section 33.3(c)(6) of the commission’s regulations,” the commission responded in its Dec. 21 order. Furthermore, based on its own review of transmission data, the commission said it was unable to corroborate the DPTs.
The commission also noted its longstanding policy of requiring companies to compare actual trade patterns with DPT results.
“This is not a new standard or a higher threshold test; it is the obligation the commission has required for DPTs since 1997,” the commission said.
The commission also rejected Berkshire’s contention that it had failed to follow past practice by not allowing the company opportunity to correct mistakes in its original submittal.
“The [Berkshire companies] were given many opportunities to correct errors in their DPT,” the commission said, citing a Dec. 9, 2014, order describing “multiple deficiencies” in the supporting data for the tests. The commission pointed out that FERC staff met the Berkshire representatives to discuss that order.
The commission additionally dismissed Berkshire’s claim that the commission failed to make a “definitive finding” that the company possesses market power in all four regions before revoking market-based rate authority, as required under FERC Order 697. After failing the initial market power screens, Berkshire, not FERC, had the burden of proof, the commission said.
“If the commission cannot revoke market-based rate authority in areas where sellers fail to rebut the presumption of market power created by a failure of the indicative screens, then sellers could deliberately submit inadequate evidence for the commission to analyze and thus be allowed to keep their market-based rate authority in perpetuity,” the commission said.
The New York Public Service Commission turned aside numerous challenges to its adoption of a Clean Energy Standard and its subsidy for upstate nuclear power generators, rejecting 17 petitions for rehearing and/or reconsideration.
Most of the petitions were dismissed by the commission. Several others, regarding “eligibility issues” for some resources, warrant further investigation by the PSC but do not warrant rehearing, the Dec. 15 order said (15-E-0302).
The commission granted a petition by Exelon seeking the elimination of a condition related to its acquisition of the James A. FitzPatrick nuclear plant, noting that the sale has already been approved. (See FERC Approves FitzPatrick Sale to Exelon.)
The CES mandates New York to acquire 50% of its energy from clean resources by 2030 and seeks to further that goal by providing zero-emission credits to support nuclear plants, which were in danger of closing.
Generators and some environmental advocates said the ZEC program — which some critics say will cost more than $7 billion over its 12-year lifespan — goes beyond the authority granted to the PSC by state law. (See CES Under Attack on Multiple Fronts in Rehearing Requests.)
The commission disagreed, saying “the ZEC requirement the commission adopted in the CES order is the best way to preserve the affected zero-emissions attributes while staying within the state’s jurisdictional boundaries.”
Complaints that the ZEC program intrudes on wholesale markets under FERC jurisdiction were similarly dismissed. “As explained in the CES order, neither the ZEC requirement nor any other aspect of the CES program inappropriately intrudes on the wholesale market or interferes with interstate commerce,” the PSC said.
Tannery Island Hydroelectric facility | Ampersand Energy Partners
Owners of existing resources, including hydropower developers, said the CES order failed to properly measure their environmental benefits under the state-operated market for renewable energy credits. New large-scale hydropower projects are ineligible for ZEC payments under the order. Some smaller hydropower, wind and biomass resources built before 2015 that are eligible for smaller REC payments under previous state programs said they were in danger of closing because of extraordinarily low natural gas prices.
Staff has been directed to further study eligibility requirements, the order states, instead of waiting for a triennial review as established in the CES order in August.
The commission also dismissed petitions that claimed that state procedures were violated during the compressed time frame under which the ZEC program was open for public comment.
RENSSELAER, N.Y. — The NYISO Management Committee on Wednesday approved an agreement with PJM to end the 1,000-MW Con Ed-PSEG wheel next year while maintaining an operational base flow (OBF) of 400 MW that will be reduced to zero by 2021.
Consolidated Edison said it would not renew its contract with PJM when the current agreement expires next spring because it is no longer needed to deliver upstate power into New York City. But the OBF is needed to maintain system reliability in northern New Jersey, says PJM. (See “Con Ed-PSEG ‘Wheel’ to Reach 0 MW Baseflow by 2021,” PJM PC/TEAC Briefs.)
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The vote was unanimous with five abstentions, one from Public Service Enterprise Group.
“We don’t agree with PJM that the operational baseflow is needed,” PSEG’s Ken Carretta said.
NYISO COO Rick Gonzales declined to respond to that objection, which was raised repeatedly. “I’m not going to opine on what PJM has determined,” he said.
The wheeling service was implemented by modeling 1,000 MW flowing from NYISO to PJM over the JK (Ramapo-Waldwick) interface and from PJM to NYISO over the ABC (Hudson-Farragut and Linden-Goethals) interface.
Under draft language for the NYISO-PJM Joint Operating Agreement, the wheel will be temporarily replaced by an operational base flow — “an equal and opposite megawatt offset of power flows” over the Waldwick and ABC phase angle regulators to account for natural system flows over the JK and ABC interfaces.
Last week’s modifications more definitively set the size of the OBF and fixes the start and end date. “The initial 400-MW OBF, effective on May 1, 2017, is expected to be reduced to zero megawatts by June 1, 2021,” it says.
An annual review of the baseflow will be conducted starting next year, which then gives the grid operators two years’ notice to end it, unless they establish an earlier date.
PJM has said that the 2021 deactivation target materialized because it was the date that planning analyses determined the OBF was unnecessary. “With the projects that are expected to go into service, we aren’t seeing any operational need for an OBF,” PJM’s Paul McGlynn said at the Dec. 15 Transmission Expansion Advisory Committee meeting.
The revised JOA was reviewed Thursday at PJM’s Markets and Reliability Committee meeting. PSEG’s Alex Stern confirmed that PJM would clarify in the meeting minutes that the JOA can’t supersede the PJM transmission operators’ agreement.
A joint filing is expected at FERC next month with implementation starting May 1.
Con Ed decided in April to end the wheel following a dispute with PJM over the allocation of transmission upgrade costs. (See Con Ed-PSEG ‘Wheel’ Ending Next Spring.)
— PJM correspondent Rory D. Sweeney contributed to this article.
CAISO has kicked off an initiative to explore how it can procure resources equipped to automatically respond to disturbances in grid frequency.
The effort will examine implementation of a new market mechanism to compensate resources for providing primary frequency response — sending power into the grid within moments of a potentially destabilizing frequency event.
The new initiative is in response to NERC reliability standard BAL-003-1, which requires each balancing authority area (BAA) to carry sufficient capability to respond to a frequency event.
System operators seek to maintain the grid at a frequency of 60 Hz to maintain network stability. An uncontrolled drop in frequency creates the danger of cascading blackouts.
Under NERC’s standard, primary frequency response is the ability to respond to a deviation within about 20 to 52 seconds of occurrence. Such a rapid reaction requires that the resource automatically detect under-frequency and autonomously ramp its output without receiving a market signal or manual instructions from the ISO.
CAISO is seeking stakeholder input on developing a market mechanism to compensate resources for responding to frequency dips during the “primary” control horizon — just moments after the onset of the event.
While the initiative is primarily intended to help CAISO meet NERC’s requirement, the ISO hopes the effort will head off an issue expected to become more problematic as California moves to fulfill its ambitious renewable energy mandate.
“The ISO expects frequency response will worsen as nonconventional technologies increase,” Cathleen Colbert, senior market design and regulatory policy developer at CAISO, said during a Dec. 22 stakeholder call to discuss the initiative.
Nonconventional technologies typically have little or no inertial response to momentary changes on the grid; conventional generators have the ability to automatically vary their turbines’ rotational speed and output based on the pull of load. That built-in capability functions as a kind of damper for frequency excursions.
“The goal of introducing a primary frequency service would be, in the short term, to continue to support compliance with NERC’s frequency response requirement, which, without changes, will be more difficult in the long term as the generation mix changes to accommodate a renewable portfolio standard of 50% renewables by 2030,” the ISO said in an issue paper describing the initiative.
Last month, FERC proposed revising the pro forma generator interconnection agreements to require all newly interconnecting facilities, including renewable generators, to have primary frequency response capability (RM16-6). (See FERC: Renewables Must Provide Frequency Response.)
CAISO’s initiative will focus on whether the ISO should compensate resources for capital expenses associated with the equipment necessary to provide the service. It will also examine making payments for opportunity costs related to holding frequency response capacity in reserve and for operating expenses associated with providing response during an event.
Approved by FERC in 2014, BAL-003-1 requires each BAA to achieve specific performance measures to meet its “frequency response obligation” (FRO), which is calculated as the BAA’s portion of the overall obligation for the interconnection — referred to as the “IFRO.” (See FERC OKs Rules on Geomagnetic Disturbances, Frequency Response.)
The IFRO represents the minimum response needed to halt a decline in frequency resulting from the loss of two of the interconnection’s largest generators — the response necessary to head off reaching the “under-frequency load shedding” threshold of 59.5 Hz.
Based on an assessment of its generation and load relative to the rest of the Western Interconnection, CAISO says that its share of the region’s IFRO stands at about 23% — translating into 196 MW/0.1 Hz next year.
In 2015, CAISO determined that it would likely come up short of its obligation under NERC’s requirements, which took effect Dec. 1. To address the shortfall, the ISO filed Tariff revisions enabling it to enter annual contracts to acquire “transferred frequency response” — the transfer of frequency response performance across BAAs within an interconnection.
At the same time, the ISO committed to FERC that it would evaluate whether it could develop a market mechanism to cultivate a diverse set of resources to help the ISO meet the frequency response criteria.
The ISO is proposing a set of guiding principles for developing a primary frequency response market, which include:
Creating an environment in which the ISO fleet is positioned to provide sufficient frequency response;
Eliminating barriers to entry in order to allow all technologies to participate;
Producing price signals that incentivize adequate response; and
Ensuring compensation for frequency response-related capital investments if the capability becomes an interconnection requirement.
Stakeholders are being asked to consider whether the ISO’s existing ancillary services market generates sufficient compensation to enable the ISO to meet the NERC’s new reliability requirements.
The most significant argument in favor of developing a new market structure is that the ISO does not currently procure primary frequency response but must still meet NERC’s standard. The existing ancillary services market covers only the requisition of frequency regulation that qualifies as NERC’s “secondary” and “tertiary” control mechanisms following a frequency event — both of which respond to an explicit ISO market signal.
In addition to contracting for transferred response, the ISO relies on unloaded frequency response capability acquired through the current ancillary services procurement, Colbert said. However, resources procured during that process may not have the capability for a sufficiently fast response.
Additionally, the ISO has observed a “deteriorating trend” in its frequency response performance over the past two years when comparing its average capability with its obligation.
“We believe we have received guidance [from FERC] to explore other options,” Colbert said.
Stakeholders must submit comments on the issue paper by Jan. 12, 2017.
FERC rejected a request to rehear its order blocking Tariff changes that would have exempted PJM capacity resources from nonperformance charges under certain circumstances.
The commission’s Dec. 22 order said the challenge by the PJM Utilities Coalition — American Electric Power; Buckeye Power; Dayton Power and Light; Duke Energy Kentucky; East Kentucky Power Cooperative; and Virginia Electric and Power — “does not offer any information or arguments that are new to this proceeding and primarily reiterates arguments advanced in PJM’s prior pleading” (ER16-1336-001).
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The changes, approved by stakeholders following months of debate, would have exempted a capacity resource from penalties if it was following PJM’s dispatch instructions and operating at an acceptable ramp rate during periods of high load. The changes were designed to discourage generators from self-scheduling prior to a performance assessment hour in order to avoid nonperformance charges — behavior that PJM said would pose operational challenges and reliability risks.
The commission rejected the change in May, saying PJM had not shown that its operational concerns justified the proposal, which it said undercut Capacity Performance rules designed to ensure resources are available during a crisis. (See FERC Rejects Ramp Rate Exception in PJM Capacity Rules.)
The commission reiterated its conclusion in rejecting rehearing, saying “the existing incentives in the threat of a nonperformance charge and risk of losses due to self-scheduling were robust enough for resource owners to both properly maintain their units and follow PJM dispatch.”
Rejecting criticism over employee salaries and a lack of detail on other spending, FERC approved PJM’s requested rate increase, saying it was “adequately supported” (ER17-249).
The Dec. 22 order allows PJM to increase its composite rate from $0.3349/MWh to $0.36/MWh for 2017 and 2018, with a 2.5% annual increase in subsequent years through 2024, when the charge will reach $0.41/MWh. The first increase is effective Jan. 1.
The commission said that the financial statements questioned by Public Citizen are “subject to adequate independent review” by stakeholders on the Finance Committee and noted the committee may reject unjustified expenditures and direct refunds to ratepayers.
Public Citizen also complained that the RTO provided no support for its spending on outside services, which the group said may include expenses related to political advocacy. FERC did not address the advocacy question but noted PJM testimony that outside labor services “includes building and ground maintenance, utilities, outside legal fees and cybersecurity monitoring” and said it provided sufficient detail justifying the expenses.
“PJM has implemented cost-control measures, including reducing the number of full-time equivalent contractors, renegotiating telecommunications and utility contracts, expanding PJM’s vendor pool to increase supplier competition, increasing PJM employees’ share of medical insurance costs and modifying PJM’s retirement benefits,” FERC wrote. “PJM further supported the increased compensation levels, documenting that compensation levels were in line with industry averages, and identifying increased staffing requirements.”
The commission acknowledged PJM’s concerns that it needed to restore its depleting financial reserves.
“Nearly two-thirds of the estimated 7.5% increase in the 2017 stated rate proposed by PJM is to restore the reserve to its prescribed level of 6% of annual revenues, with a 2.5% annual increase in 2019 through 2023 and a 0.7% increase in 2024, while 2018 will see no increase,” the order read.
WILMINGTON, Del. — Just a month after approving changes that PJM and its Independent Market Monitor felt stripped away important market protections, the Markets and Reliability Committee approved new revisions to reinstate them.
The new revisions are similar to an amendment the Monitor and PJM had proposed for the original changes developed by Citigroup Energy. The amendment never received a stakeholder vote, however, because Citigroup’s proposal passed the MRC in November with enough support to avoid considering alternatives. (See “PJM, IMM Partner on Capacity-Replacement Revision,” PJM Market Implementation Committee Briefs.)
At issue is how quickly after a bid clears an Incremental Auction that the bidder can take credit for the purchase and flatten its position. Citigroup’s Barry Trayers said the change was necessary to allow his company to reconcile its books sooner and avoid excessive credit requirements.
PJM said the change to Manual 18 widened a loophole that allows participants to arbitrage price differences between the BRA and IAs by reselling the replaced capacity. The IMM had filed a complaint with FERC on the change, which several stakeholders credited for convincing them to reconsider their initial support.
The revisions were approved by a sector-weighted vote of 4.39 out of 5, winning near unanimous support from all sectors except for Other Suppliers. The IMM has since filed to withdraw its complaint with FERC.
The approved revisions included a friendly amendment from Mike Cocco of Old Dominion Electric Cooperative that requires PJM to respond to requests for early replacement capacity within 15 days.
Trayers attempted to defend his original changes, reading from a statement that carefully outlined his intentions and explained that the new revisions would reinstate the obstacles he had attempted to address in the first place. Trayers said an anomaly that can result in double counting of PJM participants’ capacity balances would require them to maintain collateral after they no longer have a position to collateralize. “The proposal here today would reinstate double counting,” he said.
Although Citigroup does not participate in the BRA or IAs, it provides receivables financing by purchasing the offsetting capacity positions and the future payment obligations of PJM, Trayers said. The change approved in November “does not alter the responsibility of all capacity market participants to meet their obligations with true physical capacity,” he said.
Task Force on Uplift Directed to Vote Again
Members directed the Energy Market Uplift Senior Task Force to seek consensus on ways to reduce uplift and address cost allocation concerns by revoting on five proposals that had previously received the most support.
While two proposals on uplift and volatility have received majority support, none of the more than 20 proposals on allocation has received such an endorsement.
Although the task force couldn’t agree on a path forward, PJM’s Dave Anders said the voting process indicated “overwhelming support for making a change.” He said several proposals successfully address the cost allocation issue but met resistance from stakeholders pushing for “backtesting” to determine how each package of changes would affect billings.
Anders said backtesting has been done on a few packages, but it would be “extremely complicated” for others. He urged members to focus on overall market design rather than how much each package is going to cost participants. But some stakeholders said they would oppose any reconsideration of the packages without some sort of backtesting.
Monitor Joe Bowring called for action. “There are some participants who have benefited from a delay, continue to benefit from a delay. It’s time to decide,” he said.
Others, including FirstEnergy’s Jim Benchek and Carl Johnson of the PJM Public Power Coalition, also urged the process forward.
“If we come out of this with nothing else, I would like to go to FERC with something that causes them to take action,” Johnson said. “I’m not sure it matters what we suggest to FERC. What matters is getting a [Section] 205 [of the Federal Power Act] action in front of them.”
After PJM committed to providing as much backtesting as possible, members approved directing the task force to revote on the top five packages. Its next meeting is Jan. 25.
Stakeholders Remain Skeptical of Campaign to Revisit CP
American Municipal Power’s Ed Tatum took to the MRC floor for what he noted was his “fourth first read” on a problem statement calling for a holistic review of PJM’s capacity construct.
For several months, Tatum has represented a coalition of stakeholders requesting a review. His arguments have often been met with ambivalence and a reluctance to tinker with the complex market, which is still incorporating the introduction of Capacity Performance requirements. (See No End in Sight for PJM Capacity Market Changes.)
The coalition took a month off after receiving substantial feedback in October, but Tatum said it decided to return to the MRC after being contact by RTO officials. “We got a call from PJM, and we answered the phone,” he said. The feedback resulted in several changes to the proposed problem statement and issue charge, including transferring the focus from addressing potential state public-policy action to generalized governmental action.
Stakeholders suggested a variety of potential revisions that might help gain their support, including word choice.
“I don’t mean to sound like a broken record … but [consider] approaching this from less of a defensive posture and thinking that the states are out to get us, because I don’t think that’s actually what’s going on,” EnerNOC’s Katie Guerry said. “I don’t think that’s a fair representation.”
James Wilson of Wilson Energy Economics suggested reviewing the ISO-NE and NEPOOL documents founding the Integrating Markets and Public Policy (IMAPP) process, which he said are more focused on trying to accommodate state policies.
PJM’s markets don’t reflect the costs of carbon emissions and some states might want to address it, he said. “To the extent that you accept that [carbon is harmful], then PJM’s markets aren’t efficient because they don’t reflect this externality, and what the states are doing is pushing things toward a more efficient result,” he said.
Others asked the coalition to better define its intended scope. “You’re saying, ‘Take everything we do here every day and change it,’” Gabel Associates’ Mike Borgatti said. “If we’re talking all of it, I’m not sure where I’d want to start.”
The Industrial Customers’ Susan Bruce questioned the problem statement’s timeline. “This is a lot of stuff, and to look at having deliverables [by] the third quarter of 2017, that’s ambitious.” she said.
Tatum acknowledged the additional feedback but expressed concern that the focus seems to be moving away from the proponents’ original intent. He solicited stakeholder help in making supportable revisions, but Exelon’s Jason Barker said the proponents needed to better clarify their goals. “We’re stepping on a slippery slope is all Exelon is saying,” he said.
Stakeholders Balk at Applying Tougher External Capacity Rules to Past Auctions
Stakeholders expressed concern that a PJM proposal tightening eligibility requirements for external capacity resources might violate FERC prohibitions on retroactive ratemaking.
The proposal, which won 68% support in a vote of the Underperformance Risk Management Senior Task, would require external resources to have firm transmission service with rollover rights from their native region and to meet “specific operational and market modeling requirements” to ensure that the resources can deliver energy without imposing congestion costs on PJM members.
Stakeholders expressed concern over PJM’s intention to apply the tightened requirements to capacity resources that have cleared in prior auctions. The proposal would allow existing resources that fall short to either build the transmission upgrades required to qualify under the new rules or to be relieved of their requirements without penalty.
“I think everybody should pay an awful a lot of attention to how this is being handled as far as grandfathering or not grandfathering” resource contracts, said consultant Roy Shanker. Calling it “horrible policy,” he said the proposal creates the potential to disqualify a cleared resource and reduce the amount of capacity cleared without adjusting the clearing price.
Other stakeholders, including Johnson and Barker, joined Shanker in voicing concern that it could result in retroactive ratemaking. They suggested that the rules be implemented going forward from the next BRA.
Bowring opposed “PJM’s continued inadequate approach to ensuring that capacity imports be substitutes for internal capacity resources,” including grandfathering existing long-term contracts with external resources and extending the current exceptions for two additional BRAs.
PJM had indicated it would seek votes of the MRC and Members Committee in January.
Changes to the residual auction revenue rights process received little discussion and were endorsed with one objection and two abstentions. (See “Stakeholders Debate ARR Changes,” PJM Market Implementation Committee Briefs.)
Members also endorsed by acclamation revisions to manuals 10, 13 and 14D that were largely administrative in nature. The Manual 13 changes were the result of a periodic review and included updating the Mid Atlantic Dominion primary reserve requirement from a static 1,700 MW to 150% of the area’s largest single contingency. It includes a note permitting the use of deliverable resources outside of the area to satisfy the requirement.
“It really just aligns it with the [rules for the] RTO,” PJM’s Chris Pilong said.
The Manual 14D changes align it with the planned changes to Manual 13 and include revisions to the fuel-limitation reporting section to update seasonal reporting procedures, add a periodic reporting process and remove details on real-time reporting. The reporting focuses on fuel-inventory and environmental-limitations issues. “The reason for the change to both manuals is to better clarify the reporting process,” PJM’s Augustine Caven said.
