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.
| MISO
“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.
| NYISO
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. — Despite stakeholder requests, PJM remains disinclined to create procedures to analyze any other cost containment guarantees beyond construction cost caps, the RTO’s Sue Glatz said at last week’s Planning Committee meeting.
The issue arose during a discussion of proposed changes to Manual 14F that would allow PJM to consider construction cost caps, for which the RTO was seeking stakeholder endorsement. The position created an unusual endorsement vote, which had to be manually counted.
“This is representative of what we’ve decided we’re doing now,” PJM’s Steve Herling said.
The proposal passed with 83 votes in favor, one abstention and 27 votes in opposition, the last of which included LS Power, the Consumer Advocates of the PJM States (CAPS), the PJM Industrial Customer Coalition, American Municipal Power and the Public Power Association of New Jersey.
LS Power’s Sharon Segner was concerned that PJM seemed to have changed its stance from limiting itself to only enforcing construction cost caps because they provide the best opportunity for controlling costs, to deciding it doesn’t have the legal authority to consider other parts of proposals, such as return on equity.
“We think that PJM does have the legal authority. It’s really an issue of will,” Segner said.
“We don’t have the ability to enforce all those other elements. Those are regulatory decisions, and they have to be enforced through regulatory processes. We have the legal authority to do whatever FERC tells us to do,” Herling said. “We believe … based on our perception and our opinion that the most value is in capping the construction costs. … We’ll see what FERC says.”
“Any limit to cost caps … limits the benefit that customers can receive,” AMP’s Ryan Dolan said.
“We certainly want [PJM] more involved in this process,” said Greg Poulos, executive director of CAPS.
PJM’s Alex Worcester informed stakeholders that the Trial 3B cases and contingency errors from the Regional Transmission Expansion Plan were sent to transmission owners Jan. 5 and that all “pre-final” RTEP cases will need to be delivered to the transmission planning division by Feb. 1. Pre-final cases for 2020 RTEP short circuits were sent to TOs on Dec. 22. Final cases will be sent on Jan. 16, along with draft 2023 cases. TO feedback is due Jan. 23, with the pre-final case sent back to TOs on Jan. 29.
Interconnection Agreements
PJM’s proposal to add another installment to its Manual 14 series created concerns for some stakeholders. The RTO is planning to move some information from Manual 14A into a new Manual 14G focused on generation interconnection requests.
The RTO would also change some procedures, including adding a clarification that developers that subdivide a project into multiple projects behind a point of interconnection (POI) will have one interconnection agreement with PJM and a single entity controlling the POI. This change would require all projects to be grouped into a single company, or move the POI closer to each cluster of generating units, rather than grouping them all together.
| PJM
“Moving the point of interconnection gives us pause in a couple of areas,” said John Brodbeck of EDP Renewables. He noted additional construction work and coordination “that adds a whole series of risks,” along with questions about who owns and operates the interconnection lines and whether that entity has regulatory obligations.
“We don’t know why PJM wants to move away from the shared facilities agreement. It works for us, and it seemed to work for you,” he said.
PJM’s Lisa Krizenoskas said the current process creates unnecessary complexity in the contracts and is administratively burdensome because all the agreements have to be updated to reflect later changes. There are also differences in requirements that can be hard to measure.
Brodbeck asked that PJM assure that requests already in the interconnection queue be able to retain their single interconnection agreement.
High-Voltage Solution in Dominion Zone Draws Questions
PJM’s plan to address high-voltage issues in southern Virginia by installing two static synchronous compensators, known as STATCOMs, raised eyebrows among some stakeholders who questioned whether cheaper alternatives were available. A STATCOM is an AC network regulating device that can act as either a source or sink of reactive power.
“I’m just looking at it trying to determine if we are we adding options that we don’t really need,” said Dave Mabry, who represents the PJM Industrial Customers Coalition.
Dolan asked why “optimally” sized shunt reactors weren’t used instead.
“Switching of reactors is a pretty disturbing system event,” PJM’s Mark Sims explained. “We don’t consider the reactors in this situation to be a solution, which is why we’re recommending STATCOMs.”
“The bottom line is the reactor is not an acceptable solution,” Dominion Energy’s Ronnie Bailey said. “I don’t care how many you want to put on the system. … Can it meet the performance required for the job? It cannot meet the performance.”
Sims said that STATCOMs provide a “larger dynamically variable device.” The project is expected to cost $100 million.
PSE&G Project Sparks Prudency Debate
A $546 million project from Public Service Electric and Gas to replace a 50-mile 230-kV line in western New Jersey continued to cause debate at last week’s Transmission Expansion Advisory Committee meeting.
According to PSE&G, the facilities have reached their end of life based on FERC Form 715 criteria and condition assessments, but Dolan and Ed Tatum, also with AMP, questioned how those determinations were made. AMP argued that there’s no standardized analysis for others to confirm PSE&G’s findings, nor any scenario planning to determine if more or less construction is the best route.
PSE&G and PJM agreed the line can’t be removed completely, nor can it be determined — with several southern New Jersey generator closures imminent — what the future power flow will look like.
“We’re property constrained. We have a right of way. To do something out of that right of way would be cost-prohibitive, and we can’t do nothing,” PSE&G’s Alex Stern said.
“If it goes away, you could lose it forever,” Sims said. “We’re going to build it to double [circuit]; we’re going to string one circuit, then we’re going to wait and see.”
“If we’re accounting for scenarios, we should study for those scenarios,” Dolan said. “If the line’s loading [above its rating] … I’m not going to question that [prudence]. I’m just saying show it to us.”
Other stakeholders agreed that the right of way must be maintained.
“I like scenario planning, but it’s hard to get corridors, especially in New Jersey,” Calpine’s David “Scarp” Scarpignato said. “It seems prudent to me. I think it saves ratepayers money in the long run.”
Dolan expressed concern that PSE&G is “gold plating” the system. PJM’s Paul McGlynn said TOs have criteria that they build to.
“You can just thank me for my comment on this one and move on: My sense is you guys haven’t gotten all your homework done on this one,” Tatum said.
“OK. Thank you for your comment,” Sims responded.
“This is a 90-year-old line,” Stern said. “To say that it’s not prudent, that we’re gold-plating or that we haven’t done our homework borders on the absurd.”
PSE&G also addressed questions about whether it delayed presenting the project until it was needed immediately. The question arose from pictures of structural issues on the line that are dated from 2013. PSE&G said that year it did foundation-condition assessments in accordance with its maintenance practices. It reviewed the structure foundations and fixed any issues. However, the analysis confirming the end of life for the tower structures occurred after that and was only recently completed.
The project will be presented to the PJM Board of Managers for approval at its February meeting. Tatum asked if his remaining questions would get answered before the meeting. McGlynn said PJM would attempt to do so.
“I don’t think there’s any outstanding questions … is the facility at the end of its life or not,” Sims said. “It doesn’t change the need for the project or what we’re going to present to the board.”
AUSTIN, Texas — State regulators Thursday agreed to “marinate” on an administrative law judge’s order approving AEP Texas’ request to connect a pair of utility-scale lithium ion battery facilities to the ERCOT grid.
Public Utility Commission Chair DeAnn Walker said she will file a memo in the docket (46368) explaining how she would like to move forward, while Commissioner Brandy Marty Marquez asked for another chance to discuss the matter publicly and said a rulemaking may be needed.
“The PFD [proposal for decision] did make some strong points,” Marquez said. “A lot of what we’re working through is a market that we all love and how to [incorporate batteries]. They are coming, so how does that happen?”
The order is opposed by a “diverse range of market participants,” observed Emily Jolly, legal counsel for Luminant and TXU Energy, which oppose AEP’s proposal. The opponents include Calpine, the state Office of Public Utility Counsel and several consumer organizations, who argue that allowing the assets to be included in AEP’s regulatory base would harm competition.
“The goal of competition is to minimize regulatory facilities, not encourage them to proliferate,” Jolly said. “What the PFD does not explain is why preserving the market structure is beneficial. Competition fosters innovation and efficiency. We’ve seen that play out” in ERCOT.
Attorney Kerry McGrath, representing AEP, said the batteries would be used “very, very infrequently. Twelve times a year, on average.” They would also not be used for commercial activities, he said.
AEP filed its application in 2016. ALJ Stephanie Frazee’s October decision would allow the facilities to be classified as distribution assets and included in AEP’s cost-of-service rates.
The company wants to install the 1-MW and 50-kW battery facilities in remote areas of West Texas, setting them to automatically discharge during an outage or to serve additional loads. It has proposed the energy be accounted for as “unaccounted-for energy (UFE),” which ERCOT defines as the difference between the system’s total generation supply and the total system load plus losses.
“By allowing these facilities to be settled through UFE, you would be charging one set of customers when the battery is charged, then give free energy away to another set of customers,” said attorney Katie Coleman, speaking for the Texas Industrial Energy Consumers trade association. “The settlement mechanism was never intended for this purpose. We’re concerned about distortions to pricing in the market and ratepayer-subsidized facilities participating in the wholesale market.”
PUC staff also intervened, saying the commission should open a rulemaking if it approves the ALJ’s order. OPUC’s Sara Ferris agreed with staff and said the batteries should be classified as generation assets.
“The rulemaking should be sufficiently broad to encompass other alternatives besides batteries,” Ferris said.
“I agree a rulemaking is in order here,” Marquez said. “This is new.”
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.”
