NYISO power prices jumped sharply in December on the back of sharp gains for natural gas stemming from extreme cold weather at the end of the month.
Locational-based marginal prices (LBMPs) averaged $52.63/MWh for the month, up 58% from November and nearly 20% from the same period a year ago, Robert Pike, NYISO director of market design and product management, told the ISO’s Business Issues Committee (BIC) on Wednesday.
The ISO’s year-to-date monthly energy prices averaged $36.56/MWh in December, a 7% increase from a year earlier. The average daily sendout was 444 GWh/day, compared with 403 GWh/day in November and 433 GWh/day a year earlier.
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New York natural gas prices surged 260% over the previous month, averaging $7.59/MMBtu at the Transco Z6 hub. Prices were up 73% from a year ago. Natural gas prices for the month peaked at $31.16/MMBtu on Dec. 29, five days into a severe cold snap.
Distillate prices gained 20.1% year on year, with Jet Kerosene Gulf Coast averaging $13.47/MMBtu, up from $13.04 in November. Ultra Low Sulfur No. 2 Diesel NY Harbor averaged $13.91, compared with $13.70 a month earlier.
The ISO’s local reliability share was 9 cents/MWh, down from 20 cents/MWh from the previous month, while the statewide share dropped 18 cents/MWh from the previous month to -78 cents/MWh. Total uplift costs were lower than in November.
Ongoing JOA Dispute with New Jersey
Reviewing the Broader Regional Markets report, Pike noted that the New Jersey Board of Public Utilities last month filed a complaint with FERC against PJM, NYISO, Consolidated Edison, Linden VFT, Hudson Transmission Partners and the New York Power Authority. The complaint challenges the implementation of the mutual benefits provisions of the Joint Operating Agreement between NYISO and PJM and requests amendments to it.
Pike said the ISO last month jointly filed with the other respondents to request an extension of the Jan. 11 answer deadline to Feb. 23. The commission granted the extension, which was unopposed by the BPU.
The report also noted the ISO is taking further steps to improve modeling consistency between real-time commitment (RTC) and real-time dispatch (RTD) and examine changes to look-ahead evaluations to improve scheduling and price convergence. The ISO published a white paper on the topic last month and will further explore RTC-RTD convergence this year.
BIC Recommends ICAP Manual Revisions
The BIC also recommended revisions to the Installed Capacity (ICAP) Manual covering deliverability requirements for capacity imports from PJM, effective May 1.
Zachary Smith, NYISO manager of capacity market design, told the committee that the ISO finished modifying the documentation requirements for capacity imports across the PJM AC ties. His report outlined changes that would require PJM-based ICAP suppliers to provide NYISO with evidence of firm transmission service for all capacity import obligations on the day Spot Market Auction results are posted.
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Suppliers that fail to provide documentation by the deadline would be subject to penalties and deficiency charges. Monthly deadlines, which will be posted on the ICAP event calendar, would be the same for all imports.
The committee will continue evaluating deliverability requirements for other interfaces and imports.
New Price Correction Deadlines
The committee also approved modifying price-correction deadlines by using business days rather than calendar days in the period calculation. If approved by NYISO’s Management Committee and Board of Directors, the Tariff revision would reset deadlines to four business days after the market day for real-time prices, and two business days after the market day for day-ahead prices. The change is subject to FERC approval.
Michelle Gerry, the ISO’s price validation supervisor, told the BIC that ISO-NE allows five business days for real-time price corrections and three days for day-ahead, while PJM stipulates 10 calendar days for both categories.
NYISO would continue to provide notice as soon as any price correction is processed and post a detailed correction within 10 days of each correction, as well as the quarterly price correction report recapping all corrections for each quarter.
NYISO Applies Wind Forecast Fee to Solar
The BIC voted to recommend Tariff changes that would charge New York’s utility-scale solar facilities for acquiring solar forecasts, similar to how the ISO currently recovers the costs for wind forecasts.
The changes would be implemented in mid-2018 and would also apply to meteorological data requirements. The ISO will next year pursue Tariff modifications for the economic dispatch of solar.
In a report on solar integration, David Edelson, NYISO operations performance and analysis manager, explained that the grid operator procures a centralized solar forecast for each of its 11 load zones, for both behind-the-meter and individual utility-scale resources.
Edelson said the new cost recovery mechanism is modeled on the ISO’s wind forecasting fee, which is $500/month for each resource, plus $7.50/MW (nameplate) per month. The proposed Tariff changes would modify the forecasting fee rate to $6.20/MW (nameplate) per month for both wind and solar resources so that the fees remain in line with the costs NYISO incurs to develop the forecasts.
Applying these rules to front-of-the-meter solar resources will improve NYISO’s ability to reliably integrate higher levels of solar onto the grid, Edelson said.
Just as it projected a day earlier, ERCOT set a new winter peak of 65.73 GW Wednesday morning. The demand was almost 3 GW higher than the previous record of 62.86 GW on Jan. 3. (See SPP Resets Winter Peak Record, ERCOT Set to Follow.)
The ISO said historic low temperatures in Texas resulted in multiple new peaks before demand settled on the new record between 6 and 7 a.m. Single-digit temperatures extended from North Texas to the Gulf Coast overnight, stranding trucks on icy highways.
ERCOT said it has sufficient generation resources to meet forecasted demand, but it also issued a news release Wednesday offering conservation tips to consumers.
SPP also set yet another winter peak when it recorded demand of 43.58 GW at 7:23 a.m. Wednesday. That surpassed the Jan. 16 record of 42.71 GW.
MISOtweeted late Wednesday night that MISO South had also set a new winter peak but did not say the exact figure.
CARMEL, Ind. — Amid growing complaints about the sluggishness of its redesigned interconnection queue, MISO is rolling out a new way for stakeholders to voice their concerns about the process.
RTO staff on Tuesday introduced a new feedback form designed specifically to capture stakeholder opinions on issues discussed during Interconnection Process Task Force (IPTF) meetings, in addition to other advice related to the queue.
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“If there are any areas of the process that you see need improvement, we want to make sure that we have a channel for stakeholder voices to be heard,” Arash Ghodsian, MISO manager of economic studies, said during a Jan. 16 IPTF meeting.
MISO will accept stakeholder submissions for about three weeks after IPTF meetings and post responses to the feedback on its public website, Ghodsian said.
Developer EDF Renewable Energy on Jan. 4 filed a FERC complaint against MISO’s year-old interconnection queue process, contending that the procedure is still too slow to ensure the company’s wind projects will beat the 2020 federal production tax credit deadline.
EDF argued that its projects can only meet the tax credit deadline if MISO completes interconnection studies by June 2019 to allow for the average 18-month construction of a wind farm. Otherwise, wind developers could risk forfeiting “tens of billions” of dollars, the company said. It urged FERC to consider a fast-tracked queue progression for vetted projects. (See Renewables Developer Escalates MISO Queue Design Dispute.)
“MISO will file a response to that complaint in the coming days or weeks,” Corporate Counsel Michael Blackwell said.
MISO Queue as of Nov. 2017 | MISO
Meanwhile, the RTO has updated its timetable for when it expects projects that entered the queue’s definitive planning phase (DPP) during the past two years to execute generator interconnection agreements. The most recent predictions, divided by region, have projects clearing the DPP as late as July 3, 2019, in the wind-heavy MISO West region. In all other regions, the August 2017 cycle of projects are expected to wrap up in February or March 2019, except in the Upper Peninsula area of MISO East, where projects are slated to finish this December.
MISO’s queue reform was intended to reduce the number of days that interconnection customers spend in the DPP from an average of 589 days to 460. Customers that entered the August 2017 cycle of projects are currently predicted to spend an average of 579 days in the DPP before entering an interconnection agreement.
RTO staff and IPTF leadership will also assess the need for a February task force meeting based on stakeholder requests. Wind on the Wires consultant Rhonda Peters campaigned for the additional meeting, saying a conference call was needed between now and the next scheduled meeting on March 13, considering the queue’s tight timeline.
MISO will accept new generator interconnection requests until March 12 for the April 2018 DPP cycle of projects and until Jan. 22, 2019, for the March 2019 cycle.
FERC Commissioner Neil Chatterjee says a former FERC general counsel attempted to privately lobby him last week in a proceeding for which he appeared to have prior knowledge of a pending order.
Chatterjee reported the ex parte communication by Gibson Dunn attorney William S. Scherman in a memo filed in the docket Friday, shortly before the commission rejected FirstEnergy’s request to transfer ownership of a struggling coal-fired merchant generator to a regulated affiliate (EC17-88).
Scherman (left) and Chatterjee | Gibson Dunn, FERC
FirstEnergy merchant affiliate Allegheny Energy Supply had requested permission to transfer ownership of the 1,159-MW Pleasants Power Station to regulated affiliate Monongahela Power, with the latter assuming a $142 million obligation for pollution controls Allegheny installed at the plant. The commission’s unanimous Jan. 12 order concluded the deal was not in the public interest because it resulted from an “overly narrow” solicitation. (See FERC Blocks FirstEnergy Sale of Merchant Plant to Affiliate.)
Chatterjee reported that Scherman called him on Jan. 11, “indicating his concern that the commission would shortly issue an order adverse to the interests of Monongahela Power. Mr. Scherman also stated that he would prefer that the commission set the issue for hearing instead of issue an adverse order. As soon as I realized that Mr. Scherman’s communication concerned the merits of the contested proceeding, I terminated the communication and did not respond to Mr. Scherman’s statements. I then drafted this memorandum to memorialize the ex parte communication for the record.”
FirstEnergy spokesman Todd Myers declined to answer questions about the incident, referring a reporter to Scherman.
Scherman insisted Tuesday that he had done nothing wrong and said the commission should change its ex parte (on one side only) rules, which prohibit private communications with commissioners in contested case specific proceedings.
“Based upon my experience, I do not believe I engaged in any ex parte communications,” Scherman said in an email to RTO Insider. “But as I wrote about nearly three years ago [in a commentary published in The Energy Daily], and as this and other episodes over the years have shown, the ex parte rules are mostly gray, difficult to enforce, and serve to cut off federal and state commissioners from vital information. The time has come to revise the rules.”
Scherman also had kind words for Chatterjee.
“In the 30 years I have been involved with FERC, I have known almost every FERC commissioner,” he said. “Based upon his short time at FERC, it is apparent to me that Neal [sic] Chatterjee will be one of the finest members the commission will ever have. He is thoughtful and dedicated to doing what is right for the American people. He is a great American.”
Commissioners Cheryl LaFleur, Robert Powelson, and Richard Glick said they had not been contacted by Scherman. Chairman Kevin McIntyre did not immediately respond to a query about whether Scherman had attempted to contact him.
Scherman, who chairs Gibson Dunn’s Energy, Regulation, and Litigation practice group, served as FERC’s general counsel, chief of staff, and senior legal and policy advisor between 1987 and 1993. He joined Gibson Dunn in 2013 after 20 years as a partner at Skadden Arps.
Scherman and his firm were not listed as representing FirstEnergy in the Pleasants Power Station proceeding. However, Scherman submitted FirstEnergy’s comments in response to the Department of Energy’s proposed rulemaking to benefit coal and nuclear plants last October (RM18-1). He also has represented the utility in proceedings before the West Virginia Public Service Commission in 2012.
A pugnacious litigator, Scherman has been a vocal critic of FERC’s enforcement officials since leaving the agency, making his case in congressional testimony, a law review article, a Wall Street Journal op-ed, and a National Association of Regulatory Utility Commissioners conference. Senate Republicans quoted from his critique during the 2014 confirmation hearings for former FERC Commissioner and Enforcement Director Norman Bay. (See FERC Enforcement Process Under Fire in House Hearing.)
In his Energy Daily commentary, written with Gibson Dunn associate Jennifer C. Mansh, Scherman conceded the need for prohibiting ex parte communications in contested legal proceedings. “Prohibitions on ex parte communications are meant to protect litigants from secret discussions and perceptions of unfairness,” they wrote. “It isn’t fair, for example, for a plaintiff to communicate alone with the judge, without any record of what was said and without allowing the defendant to respond.”
However, they said the situation is different for FERC, which “is simultaneously acting in an adjudicatory and rulemaking capacity.”
“Topics in contested proceedings frequently overlap with major public policy issues before the commission. FERC’s ex parte rules thus often prohibit the people who have the best information available from sharing highly relevant information with decision-makers,” they said.
Although FERC bars ex parte communications in case-specific, contested proceedings (18 CFR 385.2201(a), (b), (c)(1)(i)) the rules do not apply in rulemakings (18 CFR 385.2201(a), (b), (c)(1)(ii)), according to the commission.
Scherman and Mansh also wrote that FERC’s ex parte rules “are unfair to investigation targets and hinder the settlement of FERC enforcement cases.”
PJM staff will recommend that the RTO’s Board of Managers approve its own capacity repricing proposal next month, ignoring an endorsement vote scheduled for Jan. 25 on an alternative proposal that had garnered more stakeholder support.
PJM CEO Andy Ott announced the decision Tuesday in a letter to stakeholders.
In addition to describing revisions to PJM’s proposal, Ott made the case for why the RTO’s proposal needs to be filed for FERC approval now and is superior to the proposal from PJM’s Independent Market Monitor.
“I do not make this recommendation lightly, recognizing valid concerns arise with any course of action PJM may take, including capacity repricing,” Ott wrote. “Despite all of our collective efforts in the stakeholder process, a workable consensus solution — or even a shared agreement on the nature and extent of the problem to be solved — appears unlikely.”
The filing would be the culmination of the Capacity Construct/Public Policy Senior Task Force (CCPPSTF) that dominated PJM stakeholder work in 2017. PJM said its plan would accommodate generator offers from state-subsidized plants by allowing them to bid into capacity auctions but ensure they don’t suppress competitive prices by removing those offers in a second “repricing” stage of the auction.
Several proposals like PJM’s arose to address perceived flaws in the concept, but the IMM’s proposal — fueled by concerns that PJM would unilaterally file its proposal without a clear stakeholder mandate — was the only one to receive endorsement to move forward, albeit slowly. The IMM’s “MOPR-Ex” proposal would extend the minimum offer price rule to all units indefinitely. (See MOPR-Ex Faces Uphill Battle as PJM Declines Recommendation.)
Ott’s Argument
Ott said PJM needed to seek approval quickly because of growing threats to PJM’s markets. He cited FERC’s rejection of the RTO’s 2012 MOPR compromise, the failure of a court challenge to Illinois’ zero-emissions credits program, and the “distinct potential” for additional state subsidies this year — likely a reference to New Jersey legislators’ consideration of a ZEC-style program. (See On Remand, FERC Rejects PJM MOPR Compromiseand NJ Lawmakers Pass on Nuke Bailout in Lame Duck Session.)
Ott said he agrees with the Monitor that MOPR-Ex “offers the most economically sound response to the issue” and “the most direct and effective means to preserve price integrity” necessary for the capacity market to work. But he said PJM’s proposal is superior to MOPR-Ex because it is “substantially less punitive and less likely to frustrate the operation of state programs.”
“PJM believes it is vital for the regional market design to respect individual state interests while protecting consumers in other states from potential cost shifts,” Ott wrote. “While MOPR-Ex would not prevent state programs from providing support to individual generators, it would most likely exclude generators obtaining this support from clearing the PJM Capacity Market. PJM believes this approach is not sustainable and does not strike an appropriate balance between legitimate state interests and wholesale market integrity.”
IMM Response
In an emailed response, the Monitor said it agrees with PJM that there is a conflict between state subsidies and competitive wholesale power markets.
“But the IMM disagrees with PJM’s conclusion that PJM must reflect state interests even when state subsidies conflict with the operation of a competitive wholesale power market,” Monitor Joe Bowring said. “PJM’s capacity repricing proposal would permit state subsidized resources to push competitively offered resources out of the capacity market. That outcome is inconsistent with competition.”
Bowring took issue with Ott’s characterization of MOPR-Ex, saying that it’s not punitive to require competitive offers and “prevent subsidized, uneconomic resources from pushing competitive, economic resources out of the market.”
He reiterated his oft-repeated refrain that “subsidies are contagious.”
“If one subsidy program is permitted to undermine the PJM capacity market, others will follow,” Bowring wrote. “The MOPR-Ex approach would provide a disincentive for subsidies and would require individual states to bear the costs of state subsidies rather than spreading the costs across the other states in PJM.”
Next Steps
Ott said PJM would request FERC approve its proposal for an effective date after the 2021/22 Base Residual Auction in May. He promised that “PJM will actively listen, consider, and engage on alternative design suggestions that stakeholders might offer in the course of the FERC proceeding.”
WASHINGTON — FERC Commissioner Neil Chatterjee acknowledged Tuesday he has suffered some growing pains in his transition from Capitol Hill partisan to FERC commissioner, saying he hadn’t fully appreciated the commission’s “fact-based, evidence-based approach.”
In a panel discussion, Chatterjee and Commissioner Cheryl LaFleur discussed the commission’s Jan. 9 ruling dismissing Energy Secretary Rick Perry’s Notice of Proposed Rulemaking (RM18-1) and previewed the docket the panel created to investigate RTOs’ resilience practices (AD18-7).
The session, sponsored by the Bipartisan Policy Center, attracted an audience that included the heads of groups representing the nuclear and coal industries, merchant generators, and state regulators. (See DOE NOPR Rejected, ‘Resilience’ Debate Turns to RTOs, States.)
Chatterjee, a Kentuckian and former energy advisor to Senate Majority Leader Mitch McConnell (R-Ky.), had pushed for “interim” financial relief for struggling coal and nuclear generators pending further proceedings but ultimately joined LaFleur and their three colleagues in the unanimous ruling.
“During my time in the legislative branch I had spent time with lawmakers of all political stripes who stressed the importance of fuel diversity and the need for an all-of-the-above energy strategy,” Chatterjee, a Republican, said. “And so initially I did express some sympathy for what the secretary had laid out. … That said I was also very clear that if the commission were to take any action, it would have to be legally justified, and that it would not distort markets.”
“As we went through the process I came to really appreciate the fact-based, evidence-based approach that the commission takes. I was aware of it prior to my confirmation, but once you really get in there and start doing the work, you realize we do things in a cautious, steady, legally defensible manner. As we … went through the record and did the analysis, I came to the conclusion that my colleagues did, which is that while I feel Secretary Perry asked the right question, he proposed the wrong remedy.”
Chatterjee said he was pleased that all five commissioners also agreed “that resilience is something that needs to be explored further. The commission has looked at these kinds of issues throughout the last number of years, but we’ve never had a really hyper-focused analysis on resilience.”
LaFleur, a Democrat, said, “I disagree with Neil a little bit on how much we’ve done on this issue in the past.
“Since I’ve been on the commission for seven and a half years, a large percentage of our work has been driven by relentless changes in the nation’s resource mix. … And I would say that’s been driving our market work, our reliability work, and our transmission work for much of the last decade.”
LaFleur said although the resiliency proceeding is important, “I think we shouldn’t let this swallow everything the commission is doing. We have to continue on all fronts.”
LaFleur said she opposed interim subsidies for coal and nuclear plants because the commission lacked robust factual basis for the action. She likened it to the high burden of proof required of those seeking a preliminary injunction, who must show they have a likelihood of ultimately prevailing.
LaFleur also parted with Chatterjee on definitions, saying she believes resilience is part of reliability.
“I think resilience is distinct from reliability,” Chatterjee said “ … Perhaps the threats of a loss of resilience aren’t as dire as some generators are making them out to be. But they’re certainly not as insignificant as some proponents of new generating sources are making it out to be.”
BPC President Jason Grumet, who moderated the talk, praised the commission and Chairman Kevin McIntyre for their response to the NOPR. “I think for anyone who mistrusts government action, the rigor, the integrity and the independence, and the unanimity that FERC was able to show is really, I think, one of the brightest moments in basic public service that I’ve seen in a while,” Grumet said.
On McIntyre’s handling of the NOPR, Chatterjee and LaFleur were in agreement. “He threaded the needle very well,” Chatterjee said.
With an Arctic cold front rolling through the southern part of its footprint Tuesday morning, SPP set a new winter demand peak of 42.71 GW. The previous mark of 41.01 GW — set Jan. 2 — lasted only two weeks.
The new record came at 7:24 a.m., and wind energy met just over 8 GW of the demand. Energy prices peaked at 11 a.m., with hubs averaging $496.67/MWh in the north and $478.49/MWh in the south.
ERCOT, which manages 90% of the Texas grid, expected to set its third demand record this winter during either the night of Jan. 16 or the morning of Jan. 17. The state has been hit with its second round of snow and ice this year, ranging from San Antonio to Houston.
The ISO’s current winter peak is 62.86 GW, set Jan. 3. That broke the short-lived record of 61.95 GW, set the day before.
Spokesperson Leslie Sopko said ERCOT has sufficient generation and transmission resources to keep up with forecasted demand.
“However, this is a fluid situation, and we will continue to monitor system conditions closely,” Sopko said.
The National Weather Service predicted Houston area overnight temperatures would fall into the teens to lower 20s F, with wind chill values possibly dipping into the single digits.
NYISO’s new five-year strategy calls for the ISO to align its competitive markets with New York’s efforts to promote clean energy and the “wave of change” sweeping the power industry.
All while still keeping an eye on long-term reliability for the state’s grid.
A look inside the NYISO Control Center, fully renovated in 2014 | NYISO
“Our [2018-2022] Strategic Plan reflects an approach of continuous adaptation to shifting market dynamics and a different industry paradigm,” NYISO CEO Brad Jones wrote in foreword to the plan, released Jan. 11. “It reaffirms our commitment to enhancing our markets, operations, and planning activities.”
Jones noted that “ongoing industry transformation” and New York’s “ambitious” energy policies will “redefine” the electricity system and wholesale markets.
“Long-term reliability depends upon finding ways to harmonize the competitive wholesale markets with the state’s actions to promote clean energy,” he said.
The broadly defined plan outlines several initiatives intended to help the ISO meet that goal over the next five years:
Enhancing energy and capacity markets to maintain reliability and improve the efficiency of markets.
Developing the tools necessary to operate the grid with increased numbers of distributed energy resources.
Assuming a pivotal role in integrating public policy objectives while maintaining fair and competitive markets.
Managing the increasingly “complex, costly” systems needed to run the grid and wholesale markets.
Becoming equipped to manage costs “in an environment of decreasing MWh throughput.”
The plan also lays out more concrete steps for NYISO.
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To ensure reliability and competitive markets, NYISO will upgrade its energy management and business management systems and automate the interconnection queue. The ISO also plans to improve cyber security by improving security operations and enhancing perimeter defenses as well as overall security resiliency. (See RTO CEOs Discuss Cybersecurity, Integrating Renewables.)
Grid and market operations will incorporate new capabilities to support the integration of distributed energy resources (DERs) and improvements in wide area situational awareness in smart grid applications, the report said.
The plan also highlighted NYISO’s key accomplishments in 2017, which included publishing its DER Roadmap describing how the ISOs expects distributed energy resources to integrate into wholesale markets and working with the New York State Department of Public Service on pricing carbon into its wholesale electricity market. (See NYISO Readies Market for Energy Storage, State Targets.)
Power industry participants got their first “peak” at a potential organized market that could rival CAISO’s efforts to expand its own operations into the rest of the West.
During a conference call Tuesday, Peak Reliability and PJM Connext sketched out details on their proposed new Western electricity market, possibly setting up a battle with CAISO over who will oversee markets and reliability across the broad region.
Vancouver, Wash.-based Peak has for months been developing a proposal to expand its Reliability Coordinator (RC) services into a new West-wide energy market. It has partnered with PJM, which brings extensive experience and sophisticated knowledge from its Eastern market covering 13 states and the District of Columbia. (See PJMUnit to Help Develop Western Markets.)
Peak and PJM officials said the market would be nodal, with locational marginal pricing, real-time and day-ahead energy transactions, financial transmission rights, consolidated credit and market settlement, and optional services if desired by participants. These could include ancillary services such as regulation and reserve markets, demand response, a capacity market, and other features.
“Together we have climbed quite a mountain if you will, and this is the next logical step,” said Brett Wangen, Peak’s chief engineering and technology officer. He added that members would have a direct say in the market design and governance with the goal of reducing operating costs and improving reliability. “We definitely have been hearing the message that the industry is in need of these tools.”
Peak and PJM say they will leverage existing market tools and services | Peak Reliability
Wangen also addressed CAISO’s own plans to withdraw from Peak and offer its own reliability services to Western participants. (See Horse is Out of the Barn for CAISO RC Effort.) The ISO recently said it plans to allow Peak participants enough time to review its new RC proposal and switch from Peak to CAISO for services by spring 2019.
“This urgency that is being created is a red herring,” Wangen said. “People believe they have to make a decision in the next few weeks … clearly that is not the case.”
Peak said it is fully funded to provide its current reliability services through August 2019 and it could explore full RTO status after it deploys a new market structure. The organization will continue to be funded at current levels through June 2020, assuming no other members withdraw before September 2019.
Peak/PJM’s Concept for new market offering | Peak Reliability
Peak pointed out that participants could keep Peak as their RC whether they join the Peak/PJM market, participate in other markets such as SPP or CAISO, or continue with self-scheduling and bilateral contracts. They can also use Peak’s balancing authority services or continue with separate balancing authorities regardless of market participation.
Peak said it is developing a straw design for its proposed market and will complete a business case by the end of March or beginning of April. It will then lock in a final design and develop a memorandum of understanding for participation.
CAISO cited increased costs when it announced its plans to depart Peak and provide RC services across the West at much lower costs than are currently charged by Peak. During a conference call earlier this month, ISO officials said they plan to quickly transition current Peak members to CAISO services.
CAISO last month also said it will enhance and expand its day-ahead market across the footprint of its Western Energy Imbalance Market. (See CAISO Plan Extends Day-Ahead Market to EIM.) Peak Reliability member Mountain West Transmission Group is also in discussions to join SPP, and has asked SPP to become its reliability coordinator if it links up with that market.
Peak in 2014 split off from the Western Electricity Coordinating Council, a North American Electric Reliability Corp. Regional Entity based in Salt Lake City, Utah.
Peak on Tuesday said that the partnership’s existing capabilities will allow a relatively quicker development of a market and that a multiple state/province market “offers public policy balance.”
VALLEY FORGE, Pa. — PJM’s Tim Horger provided an update on the RTO’s efforts to comply with FERC’s plan on fast-start pricing at last week’s Market Implementation Committee meeting. The commission last month withdrew its Notice of Proposed Rulemaking on fast-start pricing because it said a uniform set of requirements isn’t appropriate for all RTOs and ISOs. Instead, it called on PJM, SPP and NYISO to make changes. (See FERC Drops Fast-Start NOPR; Orders PJM, SPP, NYISO Changes.)
Horger said PJM’s initial response is due Feb. 12 and that a final order is expected on Sept. 30. FERC indicated that PJM should:
Allow for relaxation of all fast-start resources’ economic minimum operating limits by up to 100%, such that the resources are considered dispatchable from zero to their economic maximum operating limit for the purposes of setting prices;
Apply the relaxation of a resource’s economic minimum operating limit to all fast-start resources, not just block-loaded fast-start resources;
Consider fast-start resources within dispatch in a way that is consistent with minimizing production costs, subject to appropriate operational and reliability constraints;
Modify pricing logic to allow the commitment costs of fast-start resources to be reflected in prices;
Include in the definition of fast-start resources a requirement that those resources have a minimum run time of one hour or less;
Include in the definition of fast-start resources a requirement that those resources be able to start up within one hour or less; and
Set forth its rules and practices regarding the pricing of fast-start resources.
Horger said PJM plans to “generally support” the suggestions and provide additional feedback, including the definition of “fast start.” It will also supply recommendations on the relaxation method between economic minimum and “integer relaxation” — a pricing method designed to minimize uplift costs.
Day-Ahead Market LMP Confusion
Horger also provided an explanation of a situation that created stakeholder confusion when PJM announced it planned to revise day-ahead market LMPs, then retracted that plan: The aggregate percentages for the IMO interface — the pricing point between PJM and Ontario’s Independent Electricity System Operator — for Dec. 26 to 30 were “slightly off.”
Upon further review, staff determined that the issue was minimal and didn’t violate the Tariff, so they decided to retain the original values instead of disturbing the market.
Stakeholders pointed out that PJM’s series of communications, which initially said a change would be made before later reversing that decision, was confusing.
“Your feedback is on target. … We probably caused some confusion by jumping the gun,” PJM’s Stu Bresler said.
The normal process would be to announce that an issue was found and then later announce revisions will be made once the determination is complete, he said, instead of announcing them both initially.
“Historically, when we think a situation is cut and dry, we combine the first two steps: announcing the issue and saying we’re going to change things,” he explained. “We should have issued the notification that we found something, but not” the announcement that changes would be made.
Market Impacts of Cold Weather
PJM’s Joe Ciabattoni told stakeholders to expect more uplift from the cold snap that occurred over the holiday break, but “nothing near” the market impacts from the cold streak in 2014 known as “the polar vortex.”
“We had a couple of $2 million days,” he said, but “I don’t think that the magnitude will be anything near what we saw in the polar vortex” when there were days of $86 million and $50 million. The difference this time, he said, was that the cold temperatures were sustained.
“In 2014 and 2015, the temperatures were more extreme, though not as long of a time frame,” he said.
Unplanned outages began to “crop up” near the end of the cold period on Jan. 6, but conditions never triggered requirements that maintenance outages close out within 72 hours. Ciabattoni said there were “plenty” of new 30-minute reserves measurements developed to help address gas pipeline contingencies.
“We’re getting [outage] tickets in early, as opposed to the polar vortex, when we were surprised by some outages,” he said.
Stakeholders approved a problem statement and issue charge on remapping financial transmission rights nodes. PJM’s Brian Chmielewski explained that the nodes where FTRs begin or end can be terminated based on changes in load, generation or system topology. When that happens, an “electrically equivalent” node must be identified to replace the terminated one. PJM’s current process for that search “may not guarantee an optimum substitute” that provides the same economic value and might lack transparency.
Direct Energy’s Marji Philips expressed concern with the wording of the problem statement.
“The problem is if PJM can’t find [an electrically equivalent node], it just flat out terminates the FTR,” she said. “I’m not sure the statement actually captures that.”
Rules Endorsed for Enforcing Regulator Requirements on EE
With three abstentions, stakeholders endorsed rule changes that will allow state and local regulators to manage energy efficiency participation within their jurisdiction if they receive FERC approval.
PJM’s Pete Langbein explained the process, which stems from a December ruling in which FERC established its “exclusive authority” over EE participation in wholesale markets while also preserving a carveout it had previously approved for Kentucky utilities. (See FERC Claims Jurisdiction on EE, OKs Ky. Opt-Out.)
Under the new process, PJM must alert all affected electric distribution companies about the impact of any such FERC approvals. EE that cleared the auction but isn’t allowed to deliver into a particular jurisdiction may be relieved of the commitment. EE providers will need to itemize deliveries in American Electric Power and Duke Energy zones whether or not they are in Kentucky. EDCs will review a list of whether that provider is allowed to deliver in Kentucky based on the relevant regulators.
Financial Traders Question IMM on Long-Term FTR Concerns
Seth Hayik of Monitoring Analytics, PJM’s Independent Market Monitor, presented analysis of data that the Monitor argues show that long-term FTRs aren’t improving the market. Financial stakeholders, who trade in the long-term FTR markets, questioned the findings.
Long-term FTRs, which are available for each of the next three planning years or a combination of all three, are intended to provide hedges for transmission congestion by reflecting the conditions expected in the future situations.
“They’re not reliable,” Hayik said. “What comes out of the long-term FTR modeling doesn’t necessarily reflect what’s going to” happen. PJM has taken steps to correct what it could in the model for the nearest planning year, but “I don’t know that there is a solution for those models” for the subsequent years, he said.
Financial traders acknowledged that the risk of erroneous predictions is intrinsic to forward markets.
“Generally, forward markets are forward markets, and you buy in those markets without perfect vision of what will happen when those become spot markets,” Vitol’s Joe Wadsworth said. “That’s true of any future market. You don’t have foresight into what could go right or could go wrong in those markets. You make your decision on value.”
“Look how competitive the markets have become,” DC Energy’s Bruce Bleiweis said. “That’s the evolution of a market; they become more and more competitive over time.”
The Monitor said prices have really been driven down by 50% reductions in line congestion, but Bleiweis said its data showed that market alignment has improved by 90%. He credited the long-term FTR market for the additional improvement.
“We support what [the Monitor] is doing,” she said. “We would like to understand the impacts.”
Monitor Joe Bowring said better market structure in the single-year products “doesn’t mean the outcomes are competitive, and the outcomes are what we need to focus on.”
“In a competitive market we would expect to see the excess profits competed away, but that has not happened,” he said.
Stakeholders Battle PJM, Monitor on Market Path Alignment
Stakeholders continued to criticize proposals by PJM and the Monitor on a rule for evaluating designated market paths for energy sales coming into the RTO. The members have called for caveats that would allow them to explain their reasoning for paths PJM or the Monitor find questionable.
Along with their existing joint proposal, PJM introduced one that didn’t include Monitor endorsement. It excludes applying the rule to scheduled long-term path activity — annual, monthly or weekly — but allows for “potential referral” to FERC enforcement if “manipulative behavior” is suspected.
The proposal placated no one.
“The whole point of the original proposal was to have a rule. If there is no enforceable rule … then the rule is meaningless,” Bowring said. “I think the point of the rule is clear: It’s to prevent one participant from taking actions at the same time in different directions, explicitly manipulating the market.”
American Electric Power’s Brock Ondayko complained that the proposals seemed to tell participants “you can’t do this transaction because when we put it together with your other transactions, we see this grander transaction and that’s not allowed even though it might make complete financial sense to do that.”
“I don’t think we’re going to be very supportive of the idea of just prohibiting paths and referring people” or immediately resettling transactions because stakeholders could “get caught in a net,” said Carl Johnson, who represents the PJM Public Power Coalition.
Bowring assured that there’s no “automatic referring” in the joint proposal, but he reiterated that a definitive rule is necessary. “These can occur and will occur if permitted. We know that for a fact,” he said.
“A lot of what PJM [and the Monitor are] suggesting they’re going to do is discriminatory,” said Stephen Kelly of Brookfield Energy Marketing. “Every other company in this room is able to do that transaction.”
He called for allowing stakeholders “to present hard evidence … that these are separate transactions” based on different strategies. “We don’t think that’s asking too much.”
Emergency Pipeline Switching Instructions Sparks Rights Debate
PJM’s Rich Brown presented a proposed problem statement and issue charge on fuel switching that sparked pushback from stakeholders.
The proposal focuses on how gas-fired generators should be compensated if PJM orders them to switch to alternative fuel sources, such as backup oil or a different pipeline. Gas-fired operators argued that PJM’s plan would disincentivize flexibility and fails to recognize or sufficiently compensate operators who have paid extra for guaranteed pipeline capacity.
Being forced to switch fuel sources can decrease unit performance and increase the risk of the plant tripping off, Calpine’s David “Scarp” Scarpignato said, so “I’m actually being put in a worse situation for being more flexible.”
PJM’s Chantal Hendrzak acknowledged the RTO might need to identify other “attributes” for which generators should be compensated.
“There’s a recognition to do that,” she said. “It’s something that we realize that we need to talk about, but not only talk about, but figure out how to do.”
“In general, what you’re trying to do is a good thing,” said John Horstmann of Dayton Power & Light. “Given the fact that you’ve never done this before … what is the rush? … It looks like a short-term reaction with some big implications for generation-ownership rights and financial risk that are unresolved.”
“We have learned a lot,” Brown said. “As we educate ourselves, that has led us to operationalizing gas contingencies.”
Putting it all together, Hendrzak said, “that conversation might take a while.”
Bowring called the proposal “very reminiscent of cost-of-service in its worst sense. … This approach relies on command and control rather than market forces.
“I would ask you to put the market design elements into this,” he said. “How to get gas constraints into the market, that’s the real issue.”
Other stakeholders questioned who would pay for the additional compensation.
“We don’t think the costs should be on load,” said Dave Mabry, who represents the PJM Industrial Customer Coalition. The costs should be on the generators who don’t have guaranteed service to ensure “we are incenting folks to get the fuel supply they need and firm that up if necessary.”
Citigroup Energy’s Barry Trayers noted that the Capacity Performance rules and payments were designed to handle those needs.
PJM staff said they are in contact with pipeline companies to discuss these issues but stopped short of confirming they will be involved in the stakeholder process.
“It would be great if we could get some participation in the stakeholder meetings,” Hendrzak said. “I’m not sure if that will actually happen.”
