MISO wants to exclude its intermittent class of resources from providing ramp capability by midyear.
The grid operator said last week that, in practice, dispatchable intermittent resources have not “assisted in ramping needs,” referring to wind generation that’s often trapped behind transmission congestion.
The RTO’s ramp capability product’s current design doesn’t account for a resource’s deliverability, staff said, adding that ensuring a deliverable ramp product will produce better price signals.
Senior Market Engineer Chuck Hansen said during a Market Subcommittee meeting Thursday that MISO wants to file with FERC in February to disqualify intermittent resources from ramp eligibility by June.
Some stakeholders argued that wind can provide upward ramping and said MISO seems to be treating certain resource types unfairly because of system congestion.
Hansen said the action is prudent in today’s operating environment, but it doesn’t have to be a “forever change.” He said staff can revisit ramp eligibility as the fleet evolves.
In early December, Clean Grid Alliance’s Natalie McIntire pointed out that ramp-capable hybrid resources with storage capability currently are forced to register as dispatchable intermittent resources because MISO doesn’t yet have a hybrid resource market participation model.
MISO also wants to disable its downward ramp capability product by setting the product’s demand curve price to zero. The grid operator overwhelming needs up ramping, not down ramping.
Hansen said devaluing downward ramping is a “way of turning it off without throwing it away.”
“We’re not ready to remove it permanently,” he said. “But this is a way to disconnect the clutch, to use a metaphor.”
Hansen said staff will still track down ramping in its markets but won’t price it. He said from 2018 to 2022, MISO paid $542.80 in real-time payments for the downward product.
“It’s not that it has not been sending useful pricing signals. It’s really that it’s been sending no pricing signals,” Hansen said in December.
A MISO analysis showed that if it priced its downward ramp capability at zero, only 18 of 70,000 five-minute market settlement intervals would have been short on down ramp in the first eight months of 2022.
“We have an abundance of ability to ramp down. It’s physics; it’s always easier to ramp down,” Hansen said. “We don’t want to pay for something that’s inherent to the system.”
Less than a year after debuting availability-based accreditation, MISO is proposing to reformulate how it accredits its resources.
Stakeholders aren’t happy.
MISO wants to accredit all resources based on their performance during predefined resource adequacy hours, or tight operation conditions. It will then adjust unit accreditation by a capacity value determined by loss-of-load expectation. The equation’s LOLE piece would replace the grid operator’s use of unforced-capacity values that rely on forced outage rates.
The new design is also intended to replace MISO’s current accreditation method for renewable energy, which uses a unit-level effective load-carrying capability calculation based on a peak hour contribution. It would also have staff fashioning new planning reserve margin requirements based on coincident loss-of-load hours rather than coincident peak load hours.
Jordan Bakke, director of policy studies, told stakeholders during a Resource Adequacy Subcommittee (RASC) meeting Wednesday that MISO’s goal is to create a single, “comprehensive resource adequacy accreditation reform” filing with FERC by next year, though the requested effective date is up for debate.
“We’re not trying to seek immediate implementation,” he said.
Bakke said the grid operator wants to shift its accreditation philosophy from “peak load-based” to “risk-based” under a sampling of the system’s riskiest hours.
Multiple stakeholders said they had serious concerns with the proposal, arguing that a direct loss-of-load approach should be applied to all resources. They contended a loss-of-load approach will only rely on a limited number of forecasted hours that are too small a sample to use for accreditation.
Invenergy’s Sophia Dossin asked how the approach will help MISO. She said a forced-outage value is broader and based on more reliable historical — rather than forecasted — information.
Bakke said a probabilistic loss-of-load approach is better suited for the tighter operating reality MISO is facing. He said the past is not an indication of the future conditions and resource mix.
Staff said using a direct loss-of-load calculation produces similar accreditation values to unforced capacity calculations.
“My reaction to that is, ‘So what?’ That’s almost a tautology,” resource adequacy consultant Michael Milligan said.
WEC Energy Group’s Chris Plante wondered whether MISO and stakeholders would be better served if they reexamined the tariff’s Schedule 53, which defines the RTO’s seasonal accreditation calculation.
“I think we’ve gone in the opposite direction of what stakeholders have intended,” he said. “I think we need to ask what it is we want out of our resource adequacy construct. Do we want it to tell us when to construct generation or do we want it to tell us the reliability value of the existing fleet? And I think it should be the latter.”
“I think what you’re hearing in this meeting today is there’s not support for this proposal. And yet, you’re moving forward with it anyway,” Clean Grid Alliance’s Natalie McIntire said.
McIntire asked why staff is proposing to change thermal resource accreditation so soon after winning approval of its availability-based method. Were they revisiting accreditation because they “didn’t get it right,” she asked.
“We need more. We need more here from MISO. And I think we need to take a step back and see what’s needed from the stakeholder process … rather than MISO completely driving this train,” McIntire said.
“I share what a lot of other stakeholders are feeling in this process: Are we going to be railroaded?” Southern Renewable Energy Association’s Andy Kowalczyk said.
Staff said they will devote more time to the topic during future RASC meetings.
FERC last year approved MISO’s seasonal capacity accreditation, which assigns accreditation based on a generating unit’s past performance during expected tight conditions. That accreditation only applies to MISO’s thermal generators; MISO has yet to file a separate, availability-based accreditation for its renewable generators. (See FERC OKs MISO Seasonal Auction, Accreditation, MISO Adding Availability-based Renewable Energy Accreditation.)
During a Jan. 17 discussion before the subcommittee, market participants complained about the difficulty of making minor adjustments to planned generator outages without taking hits to their resource accreditation. Representatives from Minnesota Power and WEC Energy Group said they have either started an approved outage early or extended it by a few days, only to entirely lose their outage exemption and negatively impact their accreditation.
Stakeholders said MISO is unfairly decrementing their availability-based accreditation for the outage’s entirety and not for just the few days tacked on. They asked staff to rectify the situation and make it easier to modify existing planned outages in MISO’s nonpublic interface.
FERC last week granted a waiver to several renewable energy projects that allows their developers to circumvent MISO’s fee distribution after one of the projects dropped out of the RTO’s interconnection queue.
The commission said in its Jan. 20 order that it granted the waiver because the project negotiations with MISO resulted in a “mutually agreeable solution” that makes the other projects whole for any increased upgrade costs after EDP Renewables withdrew its Shullsburg Wind Farm (ER23-404).
EDP challenged MISO’s calculation of the monetary harm inflicted on three other wind farms with its withdrawal and termination of its generator interconnection agreement with the RTO and American Transmission Co. (ATC) in 2020.
When a generation project in MISO’s queue withdraws, staff analyzes the financial impact on remaining interconnection requests in the same study cycle by calculating network upgrades costs that are shifted to those projects. The grid operator then uses the milestone payments made during the definitive planning phase or payments made by interconnection customers to reimburse remaining projects for any upgrade costs caused by the withdrawal.
MISO determined that five other projects hoping to interconnect to ATC’s system were financially affected by the withdrawal. Two of those waived their rights because their projects were insignificantly affected.
The Shullsburg facility contested MISO’s calculations and initiated an alternative dispute resolution process in 2021. Shullsburg ultimately reached a confidential agreement between it and the three remaining projects, the companies said.
MISO said it has some reservations about the agreement because the three remaining projects aren’t guaranteed reimbursement unless they “make a certain type of sales to certain customers.” However, the grid operator said it supports the agreement because it allows the distribution of agreed-upon harm payments to the projects.
The RTO also said the agreement allows it to hold in escrow the payments Shullsburg made while in the queue until the three projects become operational.
Acting FERC Chairman Willie Phillips presided over his first open meeting Thursday, announcing a roundtable on environmental justice and his key staffers.
“I have to tell you, never in a million years would I think that somebody like me would lead an agency for the United States government, [coming] from a place like where I am from,” Phillips said.
Phillips is just the fourth African American to serve on the commission, and he often talks about his upbringing in rural Alabama and how it influences his work as a regulator. His priorities remain reliability, transmission, and environmental justice and equity issues, he said.
Phillips plans to move forward with FERC’s work on improving its transmission planning policies that started under his predecessor, Richard Glick, including efforts to improve the interconnection queues, changes to regional planning, cost management and interregional transfer capability.
On environmental justice and equity, Phillips announced a commissioner-led roundtable that will be held March 29 and is meant to further the goals of FERC’s Equity Action Plan issued last year that aims to reduce barriers to meaningful participation by underserved communities.
“This will provide an opportunity for FERC to hear from stakeholders on how the commission can better incorporate environmental justice and equity considerations,” Phillips said. “Growing up in rural Alabama, I know first-hand the effect that government can have on communities. It is important that we consider the voices of historically disadvantaged communities in our decisions.”
Phillips’ staff is led by FERC’s new chief of staff, Ronan Gulstone; Senior Transmission Counsel Karin Herzfeld; and Senior Legal Adviser Stacey Steep, who will focus on energy projects and permitting. All three worked for Phillips when he was a commissioner, with Gulstone coming over from D.C. government and the other two joining his staff from other offices at FERC.
Commissioners James Danly and Mark Christie briefly offered their congratulations to the new chairman in their opening comments. The meeting began on time and lasted only about an hour; Danly noted that he did not file any dissents on any of the orders issued.
Somber Comments from Clements
Speaking to reporters after the meeting, Phillips was optimistic about advancing the commission’s more controversial initiatives begun under Glick.
“Throughout my whole legal career, I have made a point of making a priority of consensus building,” he said. “That is how I cut my teeth working at NERC; it is a consensus-based organization. … You may have noticed that I haven’t any dissents since coming to FERC. … When I believe something is important to me, I work hard to meet my colleagues where they are and get it in the majority. I think that’s possible because I’ve done it, and I have no doubt that we can do it again, together.”
He also balked at a question of whether the commission would wait for a fifth member to continue work on the natural gas pipeline certificate policy proposals issued under Glick.
“As a global matter, we’re not waiting on anything. We’re moving forward. The commission will not sit on our hands.”
Commissioner Allison Clements, however, was more somber about the situation FERC finds itself in now.
“It’s an unfortunate set of circumstances that leave this chair next to me being empty today,” Clements said. “One thing we’ve learned over the last few months is that, because of the important work FERC does and the issues our jurisdiction spans, this agency has moved beyond the time when it got to stay out of the broader political limelight. So, the question for me, then, is how to bring forward, into this new normal, successful approaches to achieve our statutory responsibilities.”
While most orders FERC issues are done unanimously, the reality is that the hard orders that do lead to disputes among the commissioners are often the cutting edge of a changing industry that has be overseen with an “outdated and undermatched” regulatory framework.
Dealing with those thornier issues is still possible, and Clements said FERC should renew its commitment to technology neutrality and use “data-driven decision-making.”
“Only when we are willing to look at good data and credible studies, no matter the author, can we address reliability and cost issues in concrete terms on a forward-looking basis,” Clements said. “Only when we address reliability and cost issues in concrete terms can we decide whether and how much change is needed, and where any needed change may fall on the spectrum from incremental to wholesale reform.”
FERC should also prioritize the “public” in public interest, which means improving public access to it and ensuring transparency.
“It means fairly considering good arguments no matter which stripe the stakeholder who makes them wears,” Clements said. “And it means being open to the idea of making changes requested by stakeholders, small and large, because they make our decisions better.”
Clements did not respond to a request for an interview about her comments.
Citing the need for “constant monitoring and vigilance” to protect the bulk power system from cyberthreats, FERC directed NERC on Thursday to require utilities to implement internal network security monitoring (INSM) on certain cyber systems at BPS facilities (RM22-3).
The commission approved the draft final rule at its January open meeting, with all four commissioners voting in favor of the measure. Commissioner Allison Clements said the rule would plug a critical “gap in our current cybersecurity standards” and urged FERC to “be vigilant to keep that [regulatory] ground floor strong enough … to counter the evolving threat.”
Acting Chair Willie Phillips predicted that building consensus around a new standard would “not [be] an easy task” for NERC but said it was a job that must be completed.
“I’ve noted — and I know my colleagues have noted many times — that grid security, and cybersecurity in particular, are among our most important responsibilities regarding the [BPS], so I’m very happy to see that we are moving to finalize this rulemaking today,” Phillips said.
Final Rule Softens NOPR
FERC’s order expanding NERC’s Critical Infrastructure Protection (CIP) standards builds on a Notice of Proposed Rulemaking that the commission issued almost a year ago. (See FERC Proposes New Cybersecurity Standard.) The rule applies to all high-impact bulk electric system cyber systems, regardless of whether they have external routable connectivity (ERC), and to medium-impact BES cyber systems with ERC. “Bulk electric system” refers to those facilities subject to NERC’s reliability standards, a subset of the broader BPS.
FERC gave NERC 15 months to submit new or modified CIP standards requiring INSM in all applicable BES cyber systems. NERC would also need to submit, within 12 months, a report on the feasibility of implementing INSM on low-impact BES cyber systems and medium-impact systems without ERC.
“I’m very pleased that we are directing a firm 15-month deadline for NERC to propose the standards. … It’s hard; the processes take time, but it is imperative that we get this important cybersecurity measure in place as quickly as it is feasible,” Clements said.
The draft rule represents a slight softening of FERC’s original NOPR, which proposed requiring INSM in all high- and medium-impact BES cyber systems regardless of ERC. The commission’s order explained the change as an effort to “strike a proper balance” between commenters such as NERC and the regional entities, which supported the proposal in full, and those that warned about the difficulty and cost of implementing INSM on all cyber systems. (See ERO Backs FERC’s Cyber Monitoring Proposal.)
Order Plugs Cyber Monitoring Gap
Speaking at Thursday’s open meeting, Cesar Tapia of FERC’s Office of Electric Reliability described the proposed standards as a necessary response to events like the SolarWinds hack of 2020, through which thousands of public- and private-sector organizations — including FERC itself — were infected with malicious code. Tapia said the attack “demonstrated how an attacker can bypass all perimeter-based security controls traditionally used to identify malicious activity and compromise” electronic networks believed to be secure.
In response to a question from Phillips, Tapia explained that the classification of BES cyber systems as high-, medium- and low-impact is based on “the functions of the assets housed within each system and the risks they potentially pose to the reliable operation of the” BES. He added that registered entities determine the systems’ impact level themselves.
Asked how the presence of INSM can reduce time needed to discover and respond to a security compromise, Tapia said that attackers who have compromised one device on a network “typically [attempt] to compromise other devices within the network as well,” requiring them to “move from device to device.” Unlike other security controls, INSM can alert security staff to this kind of movement, contributing to a “defense in depth strategy.”
The timelines set by FERC will begin 60 days after the publication of the final rule in the Federal Register.
The Fifth Circuit Court of Appeals told FERC Wednesday that it must explain why it has yet to rule on disputes between state regulators and Entergy that have been pending for up to six years.
The Louisiana Public Service Commission has filed several FERC complaints against Entergy’s (NYSE:ETR) System Energy Resources, Inc. (SERI), which runs plants jointly owned by the firm’s different utilities, notably the Grand Gulf Nuclear Station in Mississippi.
The PSC, along with retail regulators in Arkansas, Mississippi and New Orleans, have submitted several complaints in recent years challenging SERI’s rates — the oldest dating back to January 2017 (EL17-41) and the newest in 2021 (EL21-56). (See Entergy Regulators Ask FERC to Settle Grand Gulf Dispute.)
“The LPSC argues that consumers are over-paying SERI by about $4 million per month due to the activity alleged in one complaint,” a three-judge panel said. “Another complaint alleges that consumers in Louisiana unjustly paid a further $360 million in costs for Grand Gulf.”
The Louisiana commission went to the court to complain that FERC was taking too long in the proceedings, and its inaction was “causing irreparable injury to consumers.”
While Congress never imposed firm deadlines for FERC to resolve Section 206 complaints under the Federal Power Act, “it certainly anticipated greater alacrity than this,” the court said.
The Regulatory Fairness Act of 1998 holds that FERC is supposed to give Section 206 complaints the same priority as Section 205 filings, which come with firm deadlines. FERC is supposed to explain why it has not ruled on a complaint after 180 days, but it regularly ignores that requirement and did so in the Louisiana PSC’s complaints, the court said.
“Despite the RFA’s guidance, Section 206 proceedings before FERC appear to take much longer, costing consumers hundreds of millions of dollars and pressuring parties to settle,” the court said. “The remaining LPSC complaints have gone four to six years without resolution.”
FERC argued against any requirement to act on the case, saying it would allow it to skip the queue of other items pending before it. But the court said that argument concedes that the federal regulator has other Section 206 proceedings that have been pending even longer, meaning many consumers have been paying unjust rates, without hope for a refund, for more than six years.
FERC must make a filing within 21 days explaining why it has taken so long to deal with the regulators’ complaints.
The U.S. economy is experiencing its first taste of high inflation in decades, and that is contributing to delays in new renewable power projects, experts told the Energy Bar Association Northeast Chapter’s Winter Summit on Wednesday.
The 1970s was the last time U.S. industry had to deal with very serious inflation, and it led to major changes in the regulation of the power sector, said the Brattle Group’s Peter Fox-Penner.
This round of inflation seems to be less serious than that of the 1970s, he said. “But it’s still a profoundly impactful one, and the first one in 30 years — in a very, very different industry.”
The two key characteristics of whether industries are impacted by inflation is their ability to set prices and how capital-intensive they are, said 18th Square Managing Member Walter Hopkins, who has advised offshore wind developers on how to bid for power purchase agreements.
Offshore wind farms involve huge upfront investments, which are only estimates when they bid for a contract, and that is paid for by long-term contracts that are include some elements of fixed price.
“Winning an offshore wind project in 2021, for instance, is a bit like if you agreed to pay for a bond that would give you a fixed stream of revenue,” Hopkins said. “But you didn’t know what the price was; you’re going to pay for the bond; and you’re going to have to pay for it a couple years later after inflation kicked in, and the costs of the project rise with inflation.”
That model used to work in the industry, as developers would sign a contract and then benefit from the declining costs of turbines, but with rising costs across the board to build anything, that is no longer the case, he added.
Eversource Energy (NYSE:ES) has signed contracts for offshore wind that are meant to see delivery start later this decade, said its vice president of energy supply, James Daly.
“It’s public information that a number of these projects have stated that they cannot close financing on their current contract prices,” Daly said. “So not surprisingly, developers are citing supply chain, interest rates, commodity and labor costs, as well as uncertainty on regulations stemming from, believe it or not, the Inflation Reduction Act.”
The IRA is meant to offer renewable projects more generous subsidies, but it is still unclear exactly how the law will be implemented, and that adds to uncertainty on project’s ultimate costs, he added.
Massachusetts offshore wind farms have asked the Department of Public Utilities to either change or let them out of contracts they have signed with Eversource and other utilities. Commonwealth Wind, a 1,232-MW project owned by Avangrid, has said it cannot make the deal it signed work and wants to rebid in a new round. Other wind farms have said they face the same challenges because of inflation.
The Mayflower Wind Project, a joint venture between Shell and Ocean Winds (another jointly owned firm from EDP Renewables and ENGIE), won changes for a contract for 804 MW it signed with Eversource and other utilities in a DPU order issued Dec. 30. The project is changing its point of interconnection to the retired Brayton Point Plant and locking in a 30% investment tax credit.
Eversource is not that interested in repricing contracts now, which would only serve to lock in high prices, said Daly. Doing so would be similar to what California did during its energy crisis, when the state signed many high-priced deals to secure supplies to stop rolling blackouts, and that led to decades of litigation, he added.
“It will take some time to work through this, [but] we are seeing a turning of a corner,” said Daly.
Inflation seems to be slowing, supply chains are working themselves out, and the technology is still improving with developers able to use larger, more efficient turbines to build the wind farms than they initially planned for, he added. But some adjustments to state policy might be needed to reflect the new, harsher economic reality.
“When the current targets were set, there was no COVID on the horizon,” said Daly. “And since then we’ve had fairly significant supply chain disruptions.”
Cogentrix Energy Power Management Vice President of Regulatory Affairs Christopher Sherman agreed. His company, a subsidiary of the investment firm the Carlyle Group, owns natural gas plants but is increasingly focused on developing storage.
The largest storage projects Cogentrix is developing are about 400 MW, but they will not be ready to connect to the grid for four years, he said.
“And yet in some of those markets, the state policy pressure is to close those dispatchable resources before that,” Sherman said. “So ultimately, probably what happens is you have increased consumer cost, and you possibly have reliability issues.”
The time frame for some of the transition away from traditional, dispatchable generation needs to be adjusted to reflect the current market conditions, he added.
FERC on Thursday conditionally accepted a compliance filing by Southern Company revising its formula rate protocols, which FERC said are unjust and unreasonable, and directed the utility to provide a further compliance filing in 60 days on remedying the commission’s concerns (ER22-2642).
Southern had submitted its compliance filing in July 2022 on behalf of its subsidiaries Alabama Power, Georgia Power and Mississippi Power in response to a FERC show-cause order, issued last March, that raised concerns about the formula rate protocols filed in Southern’s tariff. (See FERC Issues Southern Show-cause Order on Rate Protocols.)
The commission ordered the utility to address deficiencies with the protocols in three areas: scope of participation; transparency of information exchange; and ability of customers to challenge transmission owners’ implementation of the formula rate.
Utility Proposed Multiple Changes
In its filing, Southern updated the protocols to clear up each issue.
Regarding the scope of participation, FERC had directed Southern to “provide a definition of the ‘interested parties’ that can participate in customer meetings, information exchange, and challenge procedures.” Southern proposed a definition that would include “customers under the tariff, state utility regulatory commissions, consumer advocacy agencies, and state attorneys general.” It said the wording fit with established commission precedent.
For the information transparency issue, FERC said that interested parties might not be able to access information that would help them evaluate the correctness of the formula rate. In response, Southern suggested adding language that would require its annual informational filings and true-up filings to:
provide formula rate calculations and their inputs, along with supporting documentation;
specify the information that enables interested parties to replicate the calculation of the formula results;
identify all material adjustments made to relevant data in determining formula inputs; and
provide underlying data for formula rate inputs that require greater granularity.
Southern also proposed revisions that would allow interested parties to request information and documents necessary to determine the effect of an accounting change, to see if the annual filing includes appropriate data, and to assess the prudence of costs and expenditures. Additional new language would provide for annual meetings regarding the informational filings and joint meetings with other transmission owners. It would also address reorganizations and mergers that affect the inputs to the formula rate.
Addressing other FERC concerns, Southern added language detailing the issues that can be challenged during the review period, procedures for formal and informal challenges, protocols for appointing representatives to work with parties that submit a challenge, and processes for elevating an informal challenge to a formal one.
Clarification Still Needed
FERC accepted most of Southern’s revisions but identified remaining deficiencies that still must be addressed.
The commission noted that the language related to posting of the annual update filings does not include a provision for notification of the filing via email and ordered Southern to add language to that effect.
FERC also said Southern’s proposed true-up filing timeline seemed to require the filings be published by May 1 of the year following the relevant rate year. The proposed protocols, however, require interested parties to file informational requests by Aug. 1 of the rate year. That would be impossible if the filing was not available until the following year, FERC said. The commission required Southern to correct the error.
Regarding the challenge procedures, FERC said that “the lack of provisions in Southern’s protocols to post all information requests, responses to information requests, informal challenges, and informal challenge resolutions [online] could limit” the ability of interested parties to “fully participate in the formula rate process.” It ordered the utility to add a requirement that all relevant information be made available online.
Finally, the commission said that Southern’s proposed timelines for making formal challenges “may not allow interested parties adequate time” to respond. It directed Southern to “propose a date for any interested party to submit an informal challenge … as well as … a formal challenge … after being given a reasonable period of time to review Southern’s responses to the informal challenges.”
The commission set 15 days as the minimum acceptable time between responses to information requests and informal challenge submission deadlines, and 31 days between responses to informal challenges and formal challenge submission deadlines.
Southern is required to submit its compliance filing within 60 days of the date of the order. The original compliance filing is conditionally accepted, effective July 23, 2022, pending its receipt.
The Texas Public Utility Commission on Thursday unanimously agreed to the principles necessary to replace ERCOT’s energy-only market with a performance credit mechanism (PCM), sending the proposal to an uncertain fate in the legislature.
Chair Peter Lake guided the commission through a discussion and then an editing session of his “underlying foundation” for the mechanism. The commissioners summarized the proposal in a four-page memo attached to the order (Project 53298).
The PCM has been criticized by some as a sop to the market’s generators. It would reward them with credits based on their performance during a determined number of scarcity hours. Those credits must be bought by load-serving entities, based on their load during those same hours, or exchanged by LSEs and generators in a voluntary forward market.
The commission ordered PUC staff and ERCOT to delay implementation of the PCM “until such time as the 88th Legislature has had an opportunity to render judgment on the merits of the PCM and/or establish an alternate solution.”
The recommendation fulfills the PUC’s statutory obligation under Senate Bill 3, enacted following February 2021’s deadly winter storm. It completes a process that began in December 2021 and involved work sessions, stakeholder feedback and industry criticism. (See Proposed ERCOT Market Redesigns ‘Capacity-ish’ to Some.)
But State Sen. Charles Schwertner (R), author of SB3 and chair of the Business and Commerce Committee, tweeted that the PUC “chose to ignore the clear direction of the [Texas Legislature] by voting to replace the state’s competitive energy market with a costly and complex proposal that is unlikely to deliver the dispatchable generation resources that Texas needs. It’s unacceptable.”
In a letter to the commission last week, Schwertner said it would be “imprudent” for the commission to act without the legislature’s “consultation and collaboration.” (See PUC Closes in on ERCOT’s Market Redesign.)
The commission’s revised memorandum said it would open a project “to evaluate and establish an appropriate reliability standard” based on the PCM concept outlined in a report by consultants Energy and Environmental Economics (E3). The firm evaluated six alternatives but did not recommend the PCM, saying it would be too complex and costly, estimating the credits could cost retailers $5.7 billion a year. (See Proposed ERCOT Market Redesigns ‘Capacity-ish’ to Some.)
“Once implementation is launched at some point in the future subject to consideration and direction of the 88th Legislature, the commission will develop an implementation plan,” the PUC said in its memo.
It said the plan will identify which entity — including among the commission, ERCOT and the Independent Market Monitor — will be responsible for analysis related to each of 17 “decision points,” including such details as the PCM compliance period and the number of hours per compliance period.
“For decision point items relegated to ERCOT analysis, the commission will direct ERCOT to undertake stakeholder evaluation subject to ERCOT board vote for ultimate recommendation for commission approval,” the commission said. “The ultimate authority for all of these and any additional decision points lies with the commission.”
The commission also tasked ERCOT with evaluating “bridging options” to retain existing assets and build new generation until the PCM can be fully implemented. It said the grid operator should report at the commission’s Jan. 26 open meeting with a proposed date for delivering a report detailing the options ERCOT considered, its board’s preferred solution and implementation steps.
“I think this reflects a deliberative process on the part of the commission,” Commissioner Will McAdams said. “I said a year and a half ago that I think our finest hour is to come, and this is part of it. It’s a good product, and we need to be able to defend it.”
“It was difficult to know what they were talking about,” Katie Coleman, who represents Texas Industrial Energy Consumers, said after the meeting but before the edited memo was posted. “The PCM they voted on today is not the PCM in [the consultant’s November] report.”
Coleman, who has testified several times before lawmakers and the commission about market designs, noted various legislative committees have requested in multiple hearings that they be given a construct they can consider.
“They’re trying to redesign a market that’s been in place for two decades on the fly in an open meeting. It needs a lot more work and thought than what’s been put into it so far,” Coleman said. “This proposal … seems to have changed substantially behind closed doors since [November].
“All of the things they discussed today are hallmarks of a capacity market. It’s turning into a game of semantics,” she added.
Stoic Energy’s Doug Lewin labeled the mechanism a “Pretty (much a dressed up, overcomplicated) Capacity Market.”
“ERCOT will have a capacity market replacing the only competitive energy market in the U.S.,” Demand Control 2 founder Chris Hendrix tweeted. Demand Control works with market participants to help them access the wholesale market.
“My other concern with pushing some decisions to ERCOT is that Chairman Lake and the ERCOT board and senior staff do not have any retail electricity expertise,” he told RTO Insider.
TIEC last week asked the PUC to reconsider its December order approving ERCOT’s amended and restated bylaws. The changes limited the ability of corporate members and market participants to recommend policy and procedural changes and to vote on governance matters. (See ERCOT Board of Directors Briefs: Dec. 19-20, 2022.)
Demand Control 2, San Antonio’s CPS Energy and generation investor Eolian on Tuesday also filed a joint rehearing request with the PUC (54444).
The Texas Association of Manufacturers said it was “concerned with today’s action by the PUC to approve a novel proposal that is not well understood, and has not been modeled, but appears to be designed to ensure a certain profit level for existing generation.”
The group has proposed additional state-backed financing for dispatchable development, temporary property tax cuts for new or modernized dispatchable facilities and a reliability service that “directly rewards” new, flexible generation. “Specifically, we support proposals that ensure market revenues would remain performance-based, consistent with the current deregulated market design, and would avoid a government-mandated capacity market or other similar electricity taxes or fees to support incumbent generators,” it said.
The Texas Competitive Power Advocates, representing large generators that have promised to build 4.6 GW of additional capacity if the PCM is adopted, commended the commission’s work. In a statement, Executive Director Michele Richmond said the mechanism will make it “economically viable for companies to invest in the new dispatchable generation needed during periods of low renewable output in ERCOT.”
“The PCM builds reliability into the successful competitive market in Texas,” Richmond said. “Paying for the reliability that ERCOT needs to power Texas when the wind isn’t blowing and the sun isn’t shining, but without paying resources for merely existing.”
PUC Coalesces Around PCM
The commissioners signaled their intentions in a filing made Wednesday evening. Lake, McAdams and Kathleen Jackson expressed their outright support for the mechanism, but Lori Cobos and Jimmy Glotfelty offered a little pushback.
“My hesitation with the [PCM] is … we will shift up to $5 billion per year more for something we are getting today: a reliable system. Rising and falling prices are not inherently crisis-based models, but economic principles,” Glotfelty wrote, referencing Lake’s frequent comment that “the cure for high prices is high prices.”
“Over the last 25 years, high prices have led to new investment in transmission and generation all over this state to the benefit of consumers and the environment,” Glotfelty added. “Our ERCOT market has become, arguably, almost too efficient for the value of this much needed commodity.”
During Thursday’s work session, Glotfelty pushed to include evaluating best practices to mitigate market manipulation and guarding against self-dealing and market power abuse in the centrally cleared market.
Cobos focused her comments on “near-term actions to help retain our existing long-duration, dispatchable thermal generation fleet” needed to maintain reliability during multiday extreme weather events. She pushed for replacing reliability unit commitment practices and letting the operating reserve demand curve work “to send market signals for new dispatchable generation investment.”
FERC on Thursday approved the New York Power Authority’s transmission rates for the Smart Path Connect transmission project (SPCP) after the utility showed it received state approval for the project (EL22-15-001, ER22-1014-002).
The commission had approved NYPA’s request fthe abandoned plant incentive (API) in March 2022 — as well as a 50-basis-point return on equity adder and performance-based ROE incentive later in July — but on the condition that the New York Public Service Commission grant the project a certificate of environmental compatibility and need, and approve its environmental management and construction plan (EMCP). These approvals, FERC said, would show the project addresses reliability and congestion, required for the incentives under Federal Power Action 219.
The PSC granted the project, which aims to rebuild about 100 miles of old 230-kV transmission lines in northern New York as 345 kV, the certificate in August 2022 (21-T-0340). But NYPA told FERC that the New York commission has only approved an EMCP for part of the project.
“NYPA explains that, because of the expedited nature of the project, and in consultation with staff from the New York Department of Public Service, the EMCP approval process for NYPA’s part of the project was broken into two segments to enable a timely start to construction of the project,” FERC said in its order. NYPA expects approval of the second segment this February.
NYPA, however, argued that “the EMCP has no bearing on whether the project reduces congestion and saves consumers money,” as those issues were addressed in the certificate. Furthermore, the remaining EMCP approval only relates to how the project will be physically constructed, versus whether the SPCP is needed.
FERC agreed with NYPA. “Upon review of the EMCP approval included with [a] supplemental filing, we agree with NYPA that the EMCP approvals are related to physical construction and do not address reliability or congestion criteria,” it said.
Construction recently began on the project, with an anticipated in-service date of fall 2025, though significant work remains.
NYPA estimates the total capital cost will be $1.1 billion, with the utility responsible for $641.3 million. The PSC found that the project will produce congestion cost savings of approximately $450 million, as it “represents an upgrade to the transmission backbone system of New York that will improve reliability throughout the state.”
