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November 5, 2024

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FERC Orders More Refunds from 2020 Western Heat Wave

FERC on Thursday continued to tell utilities to refund premiums they earned on top of extraordinarily high prices in August 2020 during a heat wave that strained the Western grid and caused blackouts in California.

The commission ordered Uniper Global Commodities North America, Tri-State Generation and Transmission Association, and Brookfield Renewable Trading and Marketing to refund premiums earned above the average index prices at the Palo Verde hub in Arizona and other market hubs on Aug. 18-19 (ER21-62, ER21-65 and ER21-59).

The average index prices at Palo Verde of $1,400.50 on Aug. 18 and $1,639.60 on Aug. 19 resulted from scarcity conditions. Premiums above the index prices were unjustified, even though buyers offered the premiums as an inducement to sell to them, FERC said.

Tri-State, for example, sold 150 MW of electricity to Arizona’s Salt River Project for $1,500/MWh on Aug. 18 and for $1,700/MWh on Aug. 19, more than the average prices at Palo Verde.

In contrast, the average price at Palo Verde from June to August 2020, excluding the high prices of Aug. 18-19, was $52/MWh, Southern California Edison and Pacific Gas and Electric said in protests to FERC.

“Tri-State’s rationale for its sales above the index price is that Tri-State was a price-taker, the sales were consistent with published market index prices, and the prices reflected emergency conditions due to record high temperatures in the Southwest,” FERC wrote. “However, the Palo Verde price index already reflects scarcity conditions, evident based on a comparison of the index prices on the days of Tri-State’s sales to the index prices for other days in August 2020.”

Sellers in the Western Interconnection, excluding CAISO’s footprint, are required to justify prices above WECC’s $1,000/MWh soft price cap, including premiums.

FERC said Macquarie Energy had failed to justify premiums above hub index prices and in some cases had failed to justify sales above the WECC soft price cap (ER21-64).

The commission denied motions by Macquarie and other sellers to raise WECC’s soft price cap to $2,000/MWh, the same as CAISO’s soft cap, saying the question was outside the scope of the proceedings.

It ordered all four sellers to make appropriate refunds within 30 days of the orders.

Thursday’s decisions followed seven similar orders in April for utilities to refund premiums for sales into CAISO on Aug. 18-19 as the ISO struggled to keep the lights on following rolling blackouts on Aug. 14-15. (See FERC Tells PacifiCorp to Refund Premiums and Sellers Urgse FERC to Raise WECC Soft Price Cap.) In those cases, FERC also denied motions to raise WECC’s soft price cap.

Commissioner James Danly dissented both in the April cases and in the latest batch, contending that FERC does not have the authority to “abrogate a contract to sell electricity pursuant to market-based rate authority when the contract price is above a commission-imposed ‘soft’ price cap, absent a finding that the public interest so demands,” Danly wrote in each case.

In all four cases decided Thursday, “buyers willingly purchased power during a reliability crisis at a modest premium above prevailing market index prices … [and] there is no showing in the record that these prevailing market prices seriously harmed the public interest,” he said. “Any such argument appears absurd on its face, particularly when internal CAISO prices are capped at levels much higher than the … contract price[s]” in the August 2020 heat wave.

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Corporate Buyers Decry Renewable Caps in Southeast, Renew Call for Market

ATLANTA — Utilities in the Southeast are cleaning up their generation fleets, but large consumers say the monopolies remain an obstacle to their decarbonization goals.

Kenneth Shriver, Southern Co.’s (NYSE:SO) chief economist insisted at the RE+ Southeast conference last week that his company is on the side of renewable developers and companies that have adopted net-zero goals. Southern’s generation mix was 70% coal 15 years ago, but it has reduced that to less than 20%, Shriver said.

“We are generating 50% less … carbon emissions today than we were in 2007,” he said. “We committed to that [goal by] 2030. We’re eight years ahead. And we’re on a path to net zero by 2050. That’s what our customers are wanting, and that’s what they are asking us for.”

“We all have the same goal, to get to net zero,” Shriver said. “We had some differences in our timeframes of when we want to do that. And the question mark now is, we’re trying to really work with customers to figure out, ‘Hey, you want to go earlier? How do we work with you and leverage that to the benefit of all customers?’”

Shriver said the company’s desire to ensure renewables benefit all customers “makes us focus on a lot more on more utility scale solutions, and solutions that can fit all customers, not just one particular group. As we work with individual customers, especially for the large C&I [commercial and industrial] customers, we have better economies of scale [and] we have generally found that we can deliver renewable solutions to customers, meet their needs, and then also have benefits to the overall grid.”

Solar-in-the-Southeast (Southern Alliance for Clean Energy) Content.jpg
Southeast utility solar portfolios (2020) | Southern Alliance for Clean Energy

Shriver said Southern’s shift to renewables — it claims to be the fourth-largest operator of solar in the U.S. — shows that mandates are unnecessary when the economics are right. In the integrated resource processes for Southern’s utilities, utility-scale solar penciled out as the most economic source of new generation, he said.

Capped Programs

But some renewable advocates and C&I customers say Southern and other utilities backing the Southeast Energy Exchange Market (SEEM) and opposing an RTO are slowing the transition to a carbon-free grid.

Jamey Goldin, Google’s (NASDAQ:GOOG) energy regulatory counsel for global energy markets and policy, said the Southeast will be the most difficult region in the U.S. for Google to deliver on its climate goals because of the region’s monopoly utility structure. He dismissed SEEM as “a nothing burger.” (See Southern Co. Takes Heat over SEEM, Opposition to RTO.)

Steve Levitas 2022-05-11 (RTO Insider LLC) FI.jpgSteve Levitas, Pine Gate Renewables | © RTO Insider LLC

Steve Levitas, senior vice president for regulatory and government affairs for Pine Gate Renewables, said renewable programs in the vertically integrated monopolies of the Southeast are insufficient for C&I customers’ “infinite appetite for clean energy.”

“These programs are almost always limited in size with pretty severe caps, like a gigawatt at the outside of North Carolina,” Levitas said. “So, then the question arises, how do you allocate limited capacity of these programs? … Say you come into a state like Georgia with all kinds of corporate headquarters and data centers and the like and you put up a 600-MW program. It’s not going to go very far.”

North Carolina has allocated on a first-come, first-served basis, while other states use lotteries.

“The way that makes no sense to me … is a pro rata allocation,” he said. “That would mean that if you had 600 MW of capacity available, and you have 3 GW of load that is seeking to participate … everybody gets 20% green energy,” he said. “I don’t know if anybody you worked with would find that very satisfying.”

Pining for a Southeast Market

“Extending an organized wholesale market into the Southeast would go a long way towards solving these problems, so we can structure transactions the way we do in other parts of the country,” Levitas added. “That’s a political hot button and is probably not on the horizon anytime soon. But it would create more opportunities for customers who are trying to accomplish these goals. And I won’t even talk about going to retail choice, but that fully solves the problem.”

Dmitri Moundous, senior manager of storage business development for Cypress Creek Renewables, acknowledged a full wholesale market, or an energy imbalance market, is “obviously wishful thinking.” But he said  SEEM is “really not going far enough at all.”

SEEM’s savings from reduced curtailments of renewables is “measured in single millions,” Moundous said. “When you go to an energy imbalance market, there’s multiple studies that show that you can [obtain] savings into the hundreds of millions of dollars — so, an entire order of magnitude higher.”

“That is something that can really catalyze energy storage in the Southeast,” he said. “In markets like the Pacific Northwest, where you have corporates that have commitments to 100% clean energy goals [and] time-matched renewables, that sort of storage is valued a lot more.”

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Solar Advocates Cheer Florida Net Metering Win, Brace for Next Battle

ATLANTA — Solar advocates last week celebrated the defeat of a Florida bill that would have phased out the state’s net metering program — while warning the battle is far from over.

The bill (HB 741), which Florida Power and Light (NYSE:NEE) said was needed to address cost shifting, cleared the House and Senate by wide margins but was vetoed last month by Gov. Ron DeSantis (R). It would have gradually reduced net metering rates until reaching the avoided-cost rate in 2029.

Jim Purekal, manager of market development and policy for rooftop solar company SunPower (NASDAQ:SPWR), told the RE+ Southeast conference that DeSantis vetoed the bill because of rising inflation, a rate increase that followed FPL’s acquisition of Gulf Power (which “drove hundreds of phone calls and emails into the governor’s office”) and a provision that would allow FPL to charge ratepayers for lost revenue from competition with solar.

“The battle is not over yet,” Purekal told the conference, sponsored by the Solar Energy Industries Association (SEIA) and Smart Electric Power Alliance (SEPA). “The fight is really just kind of beginning at this point, because we know that Florida Power and Light is licking their wounds, rolling up their sleeves, and they’re going to be back again. And I don’t know what that … looks like just yet,” he said. “But we do know that what happened over the last couple of months has shown that the solar industry in Florida is here to stay, and we are a formidable force.”

Will Giese, Southeast regional director for SEIA, said that “when this bill was first introduced, it was like the immediate and sudden death of the solar industry,” and [proponents] wanted to get it through before the legislative session even started in January.

“I think it’s a credit to folks like Jim and a number of other solar advocates that were down there [in the state capitol],” Giese said. “I mean, there was somebody down there every single week until the end of the legislative session from the solar industry, walking the halls, educating people.”

Giese said the industry’s warning that 40,000 jobs were at stake also was a factor in DeSantis’ decision.

“It’s important to remember that Florida is the only state other than California to have installed over 100 MW of residential solar in one quarter. That’s huge,” Giese said.

Yet Florida has fewer rooftop solar installations than New York, said Purekal. “It’s not because New York has more solar insolation. That’s not the case: Florida is the Sunshine State. To me, it comes down to policy.”

Other States

Autumn Proudlove, senior policy program director at N.C. Clean Energy Technology Center, said that while North Carolina and Florida have traditional retail-rate net-metering programs, other states have chosen different compensation structures.

Dmitri Moundous 2 2022-05-11 (RTO Insider LLC) FI.jpgDmitri Moundous, Cypress Creek Renewables | © RTO Insider LLC

“Net metering reforms are under consideration in states all across the country, including many of the Southeastern states,” she said, citing results from the center’s recent report, The 50 States of Solar.

Mississippi regulators recently considered a change to the state’s program, which credits customers at a rate between the retail rate and the avoided-cost rate. The Public Service Commission ultimately decided to keep the current structure while adding a solar rebate for residential customers to try to spur the market, Proudlove said.

In November, the North Carolina Sustainable Energy Association and  the Southern Environmental Law Center announced a  compromise with Duke Energy (NYSE:DUK) on proposed new net-metering rules, similar to an agreement approved last year by the South Carolina Public Service Commission.

Lon Huber, vice president of rate design and strategic solutions for Duke, said the proposal includes some non-bypassable charges to ensure full funding of low-income and energy-efficiency programs, and a “minimum bill to ensure recovery of the distribution system [costs].”

Lobbying for Policy Changes

Carson Harkrader, CEO of Carolina Solar Energy and vice chair of the Carolinas Clean Energy Business Association, urged the industry to make political contributions and educate legislators and regulators about the industry’s needs in the Southeast.

Jeff Pratt 2022-05-11 (RTO Insider LLC) FI.jpgJeff Pratt, Green Power EMC | © RTO Insider LLC

“Those conversations might be different for public or private companies … and for municipalities, but those conversations are really important,” she said. “All of us on this panel are pushing hard on this. We all have government affairs teams, and we’re very focused on the policy because we know how important it is,” she said on a panel with representatives from Pine Gate Renewables, Origis Energy and Sol Systems. “But when the energy buyers — all the energy buyers — become more vocal, it will only help propel this momentum around energy purchases [and make it] faster and better for the customers.”

Jeff Pratt, president of Green Power EMC, a nonprofit that helps 38 Georgia electric membership corporations obtain renewables, called for civility and patience.

“Listen, bear with, engage, be friendly and courteous to one another as we work through these processes. The disruption is real. There’s opportunity in disruption for utilities; there’s [also] threats to utilities. There are opportunities for convenience stores with disruption, and there’s threats as well,” Pratt said. “Let’s be kind and courteous and helpful to one another and, and work through these bumps. We’re going to be fine. It’s just going to take us another decade or so to get there.”

Giese said that although net metering has been crucial to the growth of the rooftop market, “there are ways to evolve these tariffs … that aren’t sudden and devastating. There are ways to get there incrementally. And I think sometimes there’s a knee-jerk reaction from the industry, in some ways to say, ‘Oh, no, we don’t want this,’ in the same way that the utility does. And so, if both of those folks can come to the middle and say, ‘Hey, there’s a way to move forward,’ I think that would be the ideal.”

Risk of Backsliding

Dmitri Moundous, senior manager of storage business development for solar and storage developer Cypress Creek Renewables, urged renewable advocates to continue participating in in state policymaking, saying he fears “letting short-term market volatility on the supply side drive decisions that are 15 years out.

“One pretty big risk is that we might see a walking back of state policies or utility commitments, or just slipping timelines, slipping numbers and commitments on renewable deployments [or] carbon targets. It’s like, ‘Oh, we can’t really accomplish this, so we’re going to wait for 2040 technology based on some cost curve that we saw,’” he said.

“That’s not to be negative, but that’s just motivation to stay engaged at the state level … because I think that’s where the energy transition happens, at the state level.”

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FERC Partially Rejects NERC CMEP Changes

FERC on Thursday handed down a mixed decision granting partial approval to the ERO Enterprise’s proposed changes to NERC’s Rules of Procedure (ROP) meant to revise the agency’s Compliance Monitoring and Enforcement Program (CMEP) and other elements of its operations (RR21-10).

NERC and the regional entities submitted the revisions to FERC last September, proposing to update the following areas of the ROP:

      • Section 400 — Compliance and enforcement
      • Section 600 — Personnel certification
      • Section 900 — Credential maintenance program
      • Section 1500 — Confidential information
      • Appendix 2 — Definitions used in the ROP
      • Appendix 4C — CMEP

The changes to sections 600, 900 and 1500 concern NERC’s Personnel Certification and Credential Maintenance Program, and are intended to improve the governance and integrity of the System Operator Certification Program. They would also move responsibility for credential maintenance from NERC’s Reliability and Security Technical Committee to the Personnel Certification and Governance Committee.

The remaining proposed revisions relate to the CMEP and are intended to “further enhance the risk-based approach to the CMEP” and remove “unintended or unnecessarily burdensome limitations” found in the current ROP. The planned changes include “eliminating the three-year audit cycle for reliability coordinators, balancing authorities and transmission operators; removing the public posting requirements for certain reports; revising evidence retention periods; [and] modifying reporting of minimal risk compliance.”

NERC and the REs claimed in their proposal that the elimination of the fixed audit cycle would allow responsible organizations to prioritize compliance activities focused on areas of high risk rather than locking them into performing certain activities at certain times. In addition, the petitioners said the revised evidence retention requirements recognized that not all violations of reliability standards “require the same type of processing and documentation.”

In its Thursday order, FERC accepted all of the non-CMEP proposals without exception. However, while the commission also accepted several portions of the CMEP changes, it found that not all the revisions were “just, reasonable, not unduly discriminatory or preferential, and in the public interest.”

Among its objections, FERC noted that some of the ERO Enterprise’s proposed changes would “remove from commission review much of the ERO’s enforcement of reliability standards.” For example, the commission said that removing the three-year audit cycle was inconsistent with FERC’s requirement of “rigorous audits of compliance,” a problem “exacerbated” by the relaxation in evidence retention requirements.

FERC also objected to the proposal to eliminate reporting of self-logged lower-risk violations, on the grounds that the commission’s regulations require NERC and the REs to report self-reports “promptly” along with investigations undertaken by the ERO Enterprise. In addition, the commission warned that entities will have fewer incentives for compliance if the likelihood of being audited is lower and they are not required to keep records that might bring instances of noncompliance to light.

FERC’s order directed NERC to reinstate multiple requirements of its ROP that it had proposed for revision or elimination, including:

      • that all violations be reported to NERC and the commission, no matter how they are disposed;
      • that entities retain evidence to demonstrate compliance for the entire audit period, or the time mandated by the relevant standard;
      • that NERC and the REs establish a program for auditing responsible entities and verifying the findings of previous compliance audits;
      • that independent audit reports be made public.

The commission also ordered NERC to submit a compliance filing within 60 days of the date of the order confirming that the ROP sections had been reinstated.

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State Regulators Weigh in on New England Pathways Study

State utility regulators in New England are cautiously optimistic about the path forward to fixing the region’s energy markets.

Several utility commission leaders on Wednesday addressed the preliminary results of ISO-NE’s draft Pathways Study, which compares region-wide options to incentivize clean energy, including carbon pricing and a forward clean energy market (FCEM).

“We’ve said yes to the ISO to go on a date with them to fix the markets, but we still have to go on the date,” said Matthew Nelson, chair of the Massachusetts Department of Public Utilities. “It’s not over yet, so that’s where we are.”

Nelson and other regulators spoke on a panel at the New England Energy Conference and Exposition hosted by the Northeast Energy and Commerce Association and the Connecticut Power & Energy Society.

The study draft, commissioned by ISO-NE and written by the consulting firm Analysis Group, was released in March. It did not make any formative conclusions about the four policy approaches it weighs, aside from their theoretical ability to achieve “substantial” levels of decarbonization, but it offered insight into the tradeoffs that would come with each. (See Draft Study Weighs Tradeoffs of CO2 Pricing, FCEM for ISO-NE).

The New England States Committee on Energy put out a measured statement in which it reserved judgment on the study, saying the committee looks forward to working with the RTO and others to pick a pathway.

The states are interested in continuing to look at the development of a centralized FCEM, NESCOE said.

Maine Public Utilities Commission Chairman Philip Bartlett echoed NESCOE’s statement on Wednesday.

“I think there is broad agreement around the region about the potential benefits of a FCEM,” he said. “I think we all recognize if we continue to contract this aggressively, we’re going to effectively destroy the regional markets.”

As one of the other options under consideration for the region, a carbon tax is “economically attractive,” Bartlett said, but the policy carries with it challenges for garnering political support.

“I urge folks not to get ahead of where most of our states are politically, which is that a carbon fee of any kind is going to be extraordinarily hard to add into this market politically,” Bartlett said.

The panel addressed the need to develop a more cohesive system for attracting new clean energy resources than state power purchase agreements.

“Massachusetts needs a lot of clean energy to meet our growing load,” Nelson said. “And I think that is something that we say, ‘OK, we’re siting 20-year PPAs now, but is there a better way to do that?”

Policy makers like contracting, Bartlett said.

“It’s something where you can pass legislation, set clear parameters and then be able to point to or take credit for the generation that comes out of that,” he said. “The real work will be convincing policy makers to step back from contracting and let [markets] work.”

More discussion of the pathways study and next steps is expected at the New England Conference of Public Utilities Commissioners Symposium in Massachusetts next week.

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Summer Forecasts Spark Warnings of ‘Reliability Crisis’ at FERC

FERC commissioners expressed alarm Thursday over forecasts of potential supply shortfalls this summer in the West, ERCOT, MISO and SPP.

A day after NERC issued a sobering Summer Reliability Assessment, FERC staff presented its Summer Energy Market and Reliability Assessment, concurring that drought, wildfires, plant retirements and transmission outages have elevated risks of load sheds this summer in much of the country. (See West, Texas, Midwest at Risk of Summer Shortfalls, NERC Says.)

“We’re heading for reliability crisis. That’s what came through the NERC report yesterday,” Commissioner Mark Christie said at the commission’s monthly open meeting. “It isn’t the first time NERC has been warning us about this.”

Quoting from the NERC report, Christie said the “the nation’s grid reliability is deteriorating, because utilities are switching too rapidly from baseload power plants to intermittent renewables. … There is clear, objective, conclusive data indicating that the pace of our grid transformation is out of sync with the underlying realities and physics of the system.”

State Decisions

Christie said the problem is the result of state policymakers adopting overly aggressive renewable portfolio standards and climate goals.

“The decision about what generating resources get built or retired is a state decision,” he said. “Utility regulators, believe me, they know this is coming. It’s the state policymakers and legislators that are driving a lot of this. [You] need to really start paying attention to the resources in each state, what you’re building and what you’re forcing to retire, and start listening to experts like NERC.”

Christie’s fellow Republican, Commissioner James Danly called it a “grim assessment,” faulting FERC’s market policies for failing to provide “the correct price signals to ensure the orderly entry and exit of the resources that are required.”

He also said FERC had failed to encourage investment in natural gas infrastructure and criticized what he called an overreliance on electric transmission expansion.

“I think that there is, in the minds of some, an idea that that as long as we get the transmission issue correct, everything will eventually solve itself. I’m simply a skeptic,” Danly said. “Not only is transmission itself expensive, and not only does it have a long timeline, but we are constrained by the law as to how we’re going to allocate costs.

“My grave, grave fear here is that what’s going to have to happen to focus people’s attention on the solutions that are necessary to ensure resource adequacy and infrastructure reliability is going to be some catastrophic event,” Danly said.

Christie initially called the reports a “wake-up call,” before disavowing the phrase as “cliché.”

But Commissioner Willie Phillips, a Democrat, said Christie was spot on.

“I don’t think it’s too far [off] to say it’s a bit of a wake-up call,” Phillips said. “I mean, I think the alarm has been going off. We’ve just been hitting snooze.”

FERC Chair Richard Glick and Commissioner Allison Clements, both Democrats, also expressed alarm.

“There is no longer a shoulder month [when] we can kind of take a deep breath and allow for regularly scheduled maintenance outages to shore up for the for the next season,” Clements said. “We’re always bracing for the next extreme weather event.”

Glick said much of the problem is extreme weather linked to climate change.

“I was in Texas earlier this week, and someone said they were in their 22nd year of drought. [They said], ‘These things come and go every 20 years or so.’ Well, we don’t know that anymore,” Glick said. “The extreme weather events that we’re seeing around the country, whether it be extreme heat, extreme cold … drought, obviously, hydropower reductions, but also wildfires … these issues aren’t going away.”

Hyperbole?

In a press conference after the meeting, Glick responded to his Republicans colleagues’ comments.

“Regarding Commissioner Danly’s comment, I mean, he’s prone to hyperbole, and so I think I don’t really think there’s much there,” he said.

He responded at length to Christie’s comments on the pace of the generation transition.

“There’s no doubt we have challenges on our hands, but I think that argument about going back to the way it used to be 30 years ago, that’s not going to happen,” Glick said. “We’re moving forward. Going forward has nothing to do with FERC. We’re moving forward because decisions are made elsewhere about the resource mix. We’re addressing those challenges, and we’re taking them seriously, trying to address them head on.”

During the meeting, Glick announced the commission will host a forum in Burlington, Vt., on Sept. 8 to discuss New England’s gas-electric winter reliability challenges (AD22-9).

He also took note of two orders approving new gas infrastructure, saying they showed critics were wrong when they said FERC’s proposed policy statements on gas permitting and greenhouse gas emissions would make it impossible to approve new pipelines. (See EBA Panel Hits FERC Pipeline Permitting.)

One order approved Kern River Gas Transmission Co.’s application for a 36-mile pipeline in Utah that will provide up to 140,000 dekatherms of gas per day to allow Intermountain Power Agency’s plan to convert an existing coal-fired generator to a gas-fired combined cycle plant (CP21-197).

“In this particular case, there’s actually net negative emissions,” Glick said.

In the second order, FERC approved ANR Pipeline Co.’s proposed Wisconsin Access Project to provide an additional 50,707 dekatherms of gas daily for six shippers (CP21-78).

Glick said he supported that project even though he concluded it would result in “significant” additional GHG emissions.

“Nonetheless, in my opinion, the benefits of the project outweighed the impact of those particular significant emissions on the environment,” he said. “The aim is to try to address this issue in a way that understands that we can follow what the courts tell us to do on greenhouse gas emissions. … and at the same time, pursue our responsibilities under the Natural Gas Act.”

Gas Market Manipulation?

Glick also expressed concern that the increase in natural gas prices, which have spurred higher power prices, may not be entirely explained by market dynamics.

FERC’s summer assessment said futures prices are higher at every major U.S. trading hub, with Henry Hub prices averaging $7.06/MMBtu for June 2022 through September 2022, up 88% from last summer’s average of $3.75/MMBtu.

“I’ve had a couple of CEOs suggest that they don’t think the market fundamentals support the current natural gas pricing,” Glick said. “They may or may not … [and] that’s something we need to consider and take a look at.”

He elaborated in the press conference. “FERC has authority over natural gas market manipulation as we do on electric market manipulation. And so that’s something we’re taking a look at. But I don’t want to suggest that we’ve found anything. I don’t want to suggest we haven’t found anything. It takes a while to do these investigations.

“That’s just good regulatory practice to make sure that the markets that we oversee aren’t being manipulated,” Glick said.

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ISO-NE’s Order 2222 Filing Earns FERC Deficiency Letter

FERC issued a broad deficiency letter Wednesday in response to ISO-NE’s Order 2222 compliance filing, asking the grid operator for more information on a myriad of topics.

The order requiring RTOs to implement rules letting aggregations of distributed energy resources (DERs) take part in organized electricity markets has stirred debate in New England — as in every region of the country. DER advocates have challenged ISO-NE’s filing, saying it doesn’t do enough to pave the way for DERs. (See ‘Beautiful Symphony’ or Bust on Order 2222, Advocates Say).

Order 2222 requires grid operators not to accept market bids from DER aggregators that aggregate customers of small utilities (distributing 4 million MWh or less annually) unless the relevant electric retail regulatory authority (RERRA) of the utility allows those customers the choice to “opt in” as part of aggregation.

In its letter Wednesday, FERC asked why ISO-NE’s filing proposes that a DER aggregator “’not be located in the metering domain of a [small] Host Utility,’” (emphasis added) when Order No. 2222 requires that RTOs/ISOs not accept bids from a distributed energy resource aggregator if its aggregation includes distributed energy resources that are customers of small utilities.”

FERC also asked the RTO why its rules give the opt-in power to host utilities rather than RERRAs.

Interconnection

In Order 2222, FERC declined to exercise its jurisdiction over the interconnection of DERs to distribution systems for the purpose of participating in RTO/ISO markets as part of a DER aggregation (DERA).

ISO-NE addressed this by adding to its tariff a category of interconnection not subject to its normal small generator interconnection procedures (SGIP): “a Distributed Energy Resource that will be participating in the wholesale market exclusively through a [DERA].”

FERC asked in its letter whether this would exempt from the SGIP all interconnections of resources participating in the ISO-NE markets exclusively through an aggregation.

The agency also asked how ISO-NE is planning to review service requests for DERs and evaluate their abilities to provide capacity.

And FERC wants to know how certain DERs are able to make use of a provision allowing them to participate in the markets before the full DERA rules come into effect in 2026.

Participation Models

The participation models put forward by ISO-NE, five existing and two new, are central to its filing.

FERC asked in particular about the distinction between two: Demand Response Distributed Energy Resource Aggregation (DRDERA) and Demand Response Resource (DRR).

“Must homogeneous aggregations of demand response resources participate under the DRR model, or may they alternatively participate under the DRDERA model?” the letter says.

The letter also digs deeper into the DRDERA model, asking about possible barriers to its use in the ISO-NE filing.

Other questions on the filing include the RTO’s proposal to prevent double counting in multiple markets, the minimum size requirements for DERAs, locational requirements, and metering and telemetry requirements.

FERC also asked ISO-NE about its implementation timeline, and whether resources would be able take part in FCA 18, scheduled for 2024.

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BOEM Details Gulf of Maine OSW Lease Timeline, Next Steps

The Bureau of Ocean Energy Management expects to issue a request for interest (RFI) by October to restart an engagement process for offshore wind in the Gulf of Maine that began in 2019.

An RFI is an optional initial step that BOEM will take as it develops wind lease areas in the Gulf of Maine for its planned lease sale in 2024, Zachary Jylkka, renewable energy program specialist at BOEM, said Thursday during the agency’s Gulf of Maine Intergovernmental Renewable Energy Task Force meeting.

BOEM took comments from task force members during the meeting on the agency’s RFI development framework in advance of issuing the final request.

The RFI will help BOEM gather information from stakeholders and gauge commercial interest as it prepares calls for information and nominations, which is the first step regulations require the agency to take in the lease development process. Once BOEM issues the RFI, it will hold a 45-day comment period, and Jylkka said the agency anticipates issuing the calls by April 2023.

BOEM has identified a draft RFI planning area that it will finalize based on stakeholder comments before issuing the RFI and refine further for the call.

“The planning area is roughly bounded on the west, north and east by BOEM’s jurisdiction for renewable energy activities on the Outer Continental Shelf, which is three nautical miles from shore to the exclusive economic zone,” Jylkka said. The southern boundary is based on physiographic and oceanographic features, he said

Gulf of Maine Planning Area (BOEM) Content.jpgBOEM’s Gulf of Maine planning area, as seen here, will be consolidated over the next two years into final offshore wind lease areas for auction. | BOEM

In identifying a final RFI area of interest, BOEM will remove spaces from the planning area that are incompatible with OSW development. Those exclusions include the location Maine identified in its unsolicited lease area application to BOEM in October 2021 for the state’s planned floating offshore wind research array.

That application is for a 15-square-mile lease area for 12 floating turbines with a potential nameplate capacity of 144 MW.

As part of the review process for the research application, BOEM must issue a request for competitive interest (RFCI) to determine if any entity, beyond the state of Maine, wants to develop a commercial project in the proposed lease area. BOEM expects to issue the RFCI early this summer, followed by a 30-day comment period, Jylkka said.

If BOEM determines that there is competitive interest, the research lease application will move to a competitive planning and leasing process that could overlap with BOEM’s broader lease area development. And if no one expresses a competitive interest, BOEM will negotiate a research lease agreement with the state of Maine, Jylkka said.

BOEM’s plan for achieving a lease auction by October 2024 includes designating wind energy areas by October 2023 and issuing a proposed lease sale notice by the end of next year and a final sale notice by June 2024.

The Gulf of Maine task force, which is comprised of about 80 federal officials and elected officers of state, local and tribal governments from Maine, New Hampshire and Massachusetts, will continue to meet at “important milestones” in the lease development process, Jylkka said.

BOEM expects to share upcoming engagement opportunities, including draft call area information, this summer.

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FERC Refuses Challenge to SEEM Transparency Changes

FERC dealt critics of the Southeast Energy Exchange Market (SEEM) yet another setback on Thursday, rejecting their request for a rehearing of the commission’s acceptance of proposed changes by the market’s founders (ER22-476).

SEEM’s opponents, two unconnected collections of activist organizations calling themselves the Clean Energy Coalition (CEC) and the Public Interest Organizations (PIOs), have filed several challenges to the SEEM agreement both before and after it took effect by force of law last October. (See SEEM to Move Ahead, Minus FERC Approval.)

So far, the commission has refused to entertain any of their rehearing requests. For example, in March FERC rejected an attempt to overturn its acceptance of key tariff changes needed to deliver the market’s energy transactions. (See FERC Again Rejects Efforts to Overturn SEEM.)

The opponents’ latest attack on SEEM stems from a set of changes that the commission accepted in January. (See FERC Accepts SEEM Revisions on Transparency.) The changes are aimed at closing a gap that FERC identified last year in a deficiency letter expressing concerns about market power and seeking assurances about the transparency of the planned market, but that the commission was unable to address because of how the agreement took effect.

At the time FERC only had four members, who split 2-2 on whether to accept the proposal. Under Section 205 of the Federal Power Act the agreement therefore became effective by default.

Opponents Cite Batavia Order, FERC Precedent

CEC and the PIOs claimed in their rehearing request that the commission had “improperly evaluated the proposed revisions in isolation,” counter to a decision by the U.S. Court of Appeals (Cities of Batavia v. FERC) that requires FERC to review a revised rate “completely to assure that its parts … ensure a ‘just and reasonable’ result.” In this case, the filers claimed that rather than reviewing only the proposed changes, FERC should have reviewed the entire agreement to consider the interactions between the changed and unchanged portions.

The opponents also charged that FERC had failed to properly consider whether the proposal to have most SEEM rules fall under the “just and reasonable standard” rather than the lower Mobile-Sierra public interest standard was lawful. CEC and the PIOs said that “the commission was obligated to determine whether [Mobile-Sierra] is appropriate for the … provisions to which [it] will continue to apply,” and that “a proper review [would] have rejected the proposed revisions … based on precedent where the commission did not” apply Mobile-Sierra in similar cases.

However, FERC concluded that the decision in its January order was appropriate on both counts. Regarding the opponents’ first argument, the commission observed that since the Batavia decision, the Court of Appeals has clarified the application of its requirement to review a revised rate completely. FERC said that the “justness and reasonableness of the [provisions] to which the members do not propose revisions … is not pending.”

Moreover, the PIOs and CEC neglected to explain how the proposed revisions will interact with the agreement’s other provisions to create unjust and unreasonable results. Because FERC could not find any such interactions either, it determined that further review would be unproductive.

The commission also rejected the standard of review argument, stating that the opponents “improperly [focused] on the form of the revisions rather than their substance.” Specifically, FERC said that while the proposed changes list “the provisions of the SEEM agreement for which changes will be subject to” Mobile-Sierra, the revisions do not actually change the standard of review for those provisions; they merely provide an explicit statement of their coverage where none was available before.

Unlike the last time FERC rejected a rehearing request on SEEM, no commissioners filed a dissent. SEEM’s supporters are aiming to launch the market in the fourth quarter, and recently held the first of three planned introductory webinars to introduce existing and prospective participants to the details of its expected functionality. (See SEEM Members Launch Engagement Series for Participants.)

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FERC Denies Rehearing, Clarifies Order 881 on Line Ratings

FERC on Thursday denied rehearing requests from transmission providers and others on Order 881, which requires the use of ambient-adjusted ratings (AARs) for short-term transmission requests for all lines impacted by air temperature.

The commission also clarified its rationale on several issues related to Order 881 (RM20-16-001; Order No. 881-A).

“In this order, we sustain the result of Order No. 881 and continue to find that, because transmission line ratings and the rules by which they are established are practices that directly affect the cost of … wholesale rates, inaccurate transmission line ratings result in commission-jurisdictional rates that are unjust and unreasonable,” FERC said.

The commission in December ordered transmission providers to end the use of static line ratings in evaluating near-term transmission service to improve accuracy and transparency and increase utilization of the grid. (See FERC Orders End to Static Tx Line Ratings.)

The commission said the rehearing requests could be deemed denied by operation of law, but that it was modifying the discussion in Order No. 881, granting clarification in part, but continuing to reach the same result and confirming the effective date of the order as March 14, 2022.  

Petitioners for rehearing and/or clarification included American Transmission Company (ATC); Edison Electric Institute (EEI); ITC Holdings Corp.; MISO Transmission Owners; and Potomac Economics, acting in its capacity as MISO’s independent market monitor.

AAR Requirements

In its 82-page order, the commission discussed the requirement for transmission providers to implement AARs on all transmission lines; the impact of the AAR requirements on transmission line relays; the use of AARs 10 days forward in transmission service and operations; seasonal line rating floors; the minimum AAR temperature range and AAR granularity; and solar heating in AAR calculations. 

FERC said it disagreed with EEI’s argument that the commission assumed, without support, that AARs will ensure that wholesale rates more accurately reflect the cost of the wholesale service being provided, and that the commission should prioritize implementation of AARs on historically congested transmission lines. 

The commission countered that the “inextricable link” between transmission line ratings and wholesale rates reflects the basic economics of the transmission system and that “by design, limiting AARs to only historically congested transmission lines would not address evolving transmission congestion patterns until after potentially costly congestion occurs on previously uncongested lines.”

On cost concerns, the commission referred to the example it cited in Order 881: “During certain single extreme events, the congestion cost savings of AAR implementation would have been substantial enough from that event alone to justify applying the AAR requirements to all transmission lines, instead of just to historically congested transmission lines. For example, in the February 2021 cold weather event, MISO … accrued $773 million in congestion charges in just a few days, significantly in congestion patterns that were neither predicted nor typical in MISO.”

Implementation of AARs also will lower transmission line ratings during extremely high temperatures, reducing the likelihood of inadvertently overloading a transmission line, the commission said.

FERC clarified two aspects of the AAR requirements related to transmission providers’ transmission protection relay settings. “First, if a transmission provider establishes higher transmission line ratings, it will have to evaluate or reevaluate its applicable protection systems for that facility. Second, we clarify that in a majority of situations the relay setting should exceed AAR values,” the order said.

The commission disagreed with MISO TOs’ arguments that requiring use of AARs for a 10-day forward period could adversely impact reliability, countering that transmission providers must implement forecast margins and adjust them regularly for accuracy.

The commission denied MISO TOs and ITC their requested clarification and rehearing on the use of a transmission line rating “floor” whereby no AAR would fall below the lowest seasonal line rating.

“The transmission line ratings resulting from a seasonal line rating floor would be inaccurate and thus would not reflect true system limitations and could create reliability concerns,” the commission said.

The commission rebutted every argument that the plus-or-minus 10-degree range and five-degree maximum increment AAR requirements will force TOs to develop or maintain millions of data points and transmission line ratings across their systems.

“The commission balanced the evidence of the benefits of this granularity in AAR calculations with the burdens imposed by increasing precision. Specifically … that AAR implementation will likely be primarily automated and that implementation costs will primarily be one-time expenses,” FERC said.

EEI asserted that the scope of benefits that flow from incorporating solar heating into AARs by implementing separate AARs for daytime and nighttime periods is unclear, while ITC contended that FERC failed to demonstrate that any potential market efficiencies that flow from this and other requirements outweigh the burden on transmission owners.

The commission said implementation of daytime/nighttime ratings would enhance the accuracy of transmission line ratings and that “none of the arguments contained in the requests for rehearing persuade us to alter that view.”

Transparency, Compliance

The commission also clarified its stance on the annual recalculation of seasonal line ratings, which ITC asserted had no technical or market-driven justification.

To the extent that a transmission provider continues to implement seasonal line ratings for years without reviewing and updating those ratings, transmission system conditions are likely to have changed to such a degree as to render the ratings inaccurate and associated wholesale rates unjust and unreasonable, the commission said.

“Nevertheless, we clarify that the commission did not prescribe the procedure for recalculating seasonal line ratings, including determining which inputs have changed in a year. For instance, a transmission provider could comply with the annual update requirement for seasonal line ratings by recalculating its seasonal line ratings annually to adjust seasonable temperature assumptions, but then also perform a more detailed recalculation every few years using multi-year temperature data to consider temperature patterns that are harder to identify with only a single year of new temperature data,” the commission said.

The commission further clarified that the requirement to engage in an annual recalculation does not require TOs to undertake unnecessary change from year to year. To the extent that relevant inputs have not changed from one year to the next, the annual recalculation may simply result in continuing to use a transmission owner’s existing facility ratings.

On the transparency requirements adopted in Order No. 881, including the data-sharing burden, the commission continued to find that the benefits outweigh the burdens: “making transmission line ratings and methodologies available to a broader range of stakeholders will amplify the expected benefits … further facilitate more accurate transmission line ratings, and facilitate more cost-effective decisions by market participants and state agencies.”

In response to ITC’s comments that the total number of transmission line ratings required to be stored would “quickly become astronomical,” the commission found “the implementation and operation of a database of this type to be well within the normal business scope of a data-intensive entity like a transmission provider. For example, the 3.4 million transmission line rating records that ITC explains it would have to calculate and store every hour would total only about 1.8 terabytes over the entire five-year line rating retention period required in Order No. 881, although the overall storage requirements would be several times that, considering memory for back-ups and data management.”

On OASIS access, the commission clarified that Order 881 requires transmission providers to post transmission line ratings and methodologies-related data to a password-protected section of their OASIS site or another password-protected website. 

“We note, however, that the data posted to either a transmission provider’s website or OASIS must be maintained such that users can view, download, and query data in standard formats, using standard protocols. If the transmission provider chooses to post the data to its own website instead of OASIS, we clarify that users must be able to access the data in a manner that is comparable to if it were posted to OASIS and subject to OASIS access requirements,” the commission said.

On the role of independent market monitors, the commission granted EEI’s request for clarification in part and denied in part. 

“We clarify that nothing in Order No. 881 changes or expands the role or authority of market monitors or the auditing responsibilities of any entity. However, we deny EEI’s request for clarification on other matters. We expect that market monitors may use the transmission line rating information available to them in furtherance of their existing responsibilities, which are set forth in the commission’s regulations and the relevant tariffs of each RTO/ISO,” the commission said.

Lastly, the commission said it was neither persuaded to adopt an earlier implementation, as requested by Potomac Economics, nor a delayed one, as requested by EEI, but to stick with the staggered three-year plan as outlined.

“We expect that the implementation burden is predominantly a one-time investment and that the burden of applying AARs to additional transmission lines is minimal. … Moreover, as a matter of policy, there are administrative efficiencies to requiring implementation of all the requirements adopted in Order No. 881 on the same timeline. Specifically, by maintaining a single implementation timeline, the implementation burdens are lessened in that all transmission line rating recalculations must only be done once,” the commission said.