FERC on Friday approved a series of updates to ISO-NE’s Inventoried Energy Program (IEP), replacing the IEP’s fixed forward and spot rates with indexed rates intended to reflect natural gas price changes (ER23-1588).
The commission sided with ISO-NE over the protests of the official consumer advocates for Massachusetts, Connecticut, New Hampshire and Maine, as well as a group of environmental nonprofits, which argued that the changes would increase electricity costs for consumers.
“The revisions maintain the overall structure of the commission-approved Inventoried Energy Program, while updating the tariff to help ensure that the Inventoried Energy Program can fulfill its purpose of incenting resources to maintain inventoried energy during periods when reliability is most threatened,” the commission wrote, making the revisions effective Aug. 4, as requested.
The goal of the IEP is to pay generators — mostly oil and gas power plants — to keep up to three days of stored fuel on-site during the winter to ensure reliability for the region.
“Current fuel prices exceed these fixed payment rates, which could reduce incentives to participate in the Inventoried Energy Program,” FERC said.
In joint comments to FERC opposing ISO-NE’s IEP proposal, the Sierra Club, the Conservation Law Foundation and the Union of Concerned Scientists argued that the changes to the program would lead to substantially increased costs for ratepayers. The organizations noted the IEP updates could increase the total cost of the program from $300 million to $800 million over two years according to the upper-bounds analysis of ISO-NE, “all for suggested, but deeply uncertain, benefits to consumers.”
The state consumer advocates pressed the commission to consider the high costs of the Mystic cost-of-service agreement before authorizing the likely increase of costs related to the IEP. (See Public Power Groups Seek Information on Mystic Agreement.)
“The commission cannot and should not ignore the magnitude of impact that the Mystic COSA has had on consumers in determining the justness and reasonableness of the IEP Redesign,” the consumer advocates wrote. “The IEP Redesign includes very little support despite imposing potentially massive costs on ratepayers, which is especially egregious in the context of the COSA’s similarly massive costs.”
The commission said it had already settled many of the issues the protestors raised.
“The proposed revisions at issue here reflect only narrow modifications and provide no basis to revisit past findings related to the Inventoried Energy Program’s core structure, which will remain unchanged,” it said.
FERC also disagreed with the contentions that ISO-NE did not adequately demonstrate the need for the IEP, that the IEP could result in windfall payments for oil generators and that the costs to consumers would likely outweigh the benefits.
‘Funny Fuel Supply’
ISO-NE applauded the commission’s ruling.
“With the commission’s acceptance, we’re moving forward on promptly implementing these updates into the upcoming winter,” the grid operator said in a statement to RTO Insider, adding that the updates “will align the program with current market conditions.”
Meanwhile, the Sierra Club, the Conservation Law Foundation and the Union of Concerned Scientists expressed displeasure with the ruling.
“CLF is disappointed by the commission’s decision, which approves changes to an ISO-NE program that extends our region’s overreliance on expensive, imported and polluting fossil fuels at a time when we need to be deploying clean energy resources,” Phelps Turner, senior attorney for the Conservation Law Foundation, told RTO Insider.
“The fossil-fuel-fired generators that it seeks to incentivize appear to already have a legal obligation to be fuel-ready and, in any event, they have substantial economic incentives to be ready and to perform, without the need for consumer subsidy,” Turner added.
Casey Roberts, senior attorney for the Sierra Club, said the FERC-approved changes could ultimately amount to a handout to the gas and oil generators covered in the IEP.
“A major vulnerability of gas and oil generators … is that they have this funny fuel supply situation that it can be challenging to get their fuel during the times it matters most,” Roberts said. “FERC is basically compensating them for that, instead of having those generators bear that risk and pay those true costs.
“That really distorts the market.”
Roberts and Turner said the environmental groups are still considering next steps, including whether to file a request for rehearing.
The ERCOT grid continues to operate under normal conditions, the grid operator said Monday, even as this summer’s peak demand is 4.3% higher than last summer’s.
The Texas grid operator recorded a new high for hourly peak demand average of 83.59 GW on Aug. 1. On Saturday, it recorded an unofficial high for weekend peak demand when load averaged 83.46 GW during the interval ending at 5 p.m.
In comparison, ERCOT set a then-record for peak demand of 80.15 GW last summer. Average hourly demand has exceeded that mark 90 times this summer, through Sunday.
ERCOT on Monday extended through Friday a weather watch, its fourth of the year, that it had issued for Sunday and Monday because of forecast higher temperatures and demand and the potential for lower reserves. It projected demand to break 86 GW on Monday and peak demands above 84 GW and higher through Friday.
Weather watches are issued when possible significant weather is expected along with high demand. They do not require public conservation. However, several utilities have been asking customers to reduce their usage.
“Grid conditions are expected to be normal,” ERCOT tweeted.
“Copy and paste. More heat and more sun,” Space City Weather said Friday in warning that Texas’ oppressive heat won’t break until next week at the earliest. “Any changes that take place in the weather pattern would not materialize before next weekend. So, buckle in.”
The sprawling Houston region finds itself underneath the brutal heat dome that is causing abnormal problems for vehicles. The National Weather Service issued excessive heat warnings for several counties in the region Friday as heat indexes soared as high as 113 degrees Fahrenheit.
However, during a recent presentation last month in San Antonio to the Texas Public Power Association, ERCOT CEO Pablo Vegas said he is concerned about the grid’s long-term reliability, given the continued influx of wind, solar and storage resources. At the same time, he credited renewable energy with helping staff meet record demand.
“Peak demand kept growing,” Vegas said. “We’re in a place now where we are dependent upon renewables to meet demand.”
Solar resources produced a record 13.46 GW of energy Wednesday and, with wind, accounted for more than 31 GW of energy last month, according to GridStatus. ERCOT has more than 55 GW of solar and wind capacity and an additional 3.5 GW of battery storage.
Thermal outages have averaged around 6 GW in recent weeks. Still, prices settled as high as $2,886 at 5 p.m. Friday and didn’t drop from quadruple digits until after 8 p.m. Prices briefly reached $26.25 Sunday evening.
FERC on Friday partially approved new rates from Niagara Mohawk for its portions of the AC Transmission Public Policy Transmission Project, which is designed to increase transfer capability across central east New York.
To pay for its share of the project (LS Power and the New York Power Authority are building most of it), the National Grid subsidiary proposed to include a new rate in its transmission service charge, called Rate Schedule 20.
The project, which is expected to be completed later this year, includes changes to some of Niagara Mohawk’s facilities. The firm plans to spend between $38 to $55 million upgrading a substation and reconductoring some transmission.
FERC accepted the firm’s cost-allocation proposal, which is in accordance with the 25/75 method used in NYISO where 75% of the costs go to zones that directly benefit from such lines and the last 25% is allocated across the entire market.
The much larger, $1.2 billion project mostly involves new infrastructure, but utilities retain the right to add any upgrades to their systems required by such projects. While FERC already had found that utilities had that right back in 2019, the NYISO tariff did not include language to implement generally, so the developers executed the “Segment A” agreement with Niagara Mohawk to make the required upgrades.
The cost-allocation method is in line with what FERC has approved for public policy lines, but the commission said the rest of the proposal has not been shown to be just and reasonable and set the matter for hearing procedures to gather more information.
The charges Niagara Mohawk proposed went into effect Aug. 5 but are subject to change and refunds based on the outcome of the hearings.
The utility said its proposed charges would lead to the same returns on all its other transmission investments under its transmission service charge (TSC). But since its Segment A charges were on top of those, the revenue from it would be credited to the standard TSC to avoid double counting.
FERC sent a deficiency letter to the utility seeking answers on its proposal, including whether ratepayers would continue to pay a return on investment once the facilities are fully depreciated.
Niagara Mohawk said its carry charge uses average systemwide cost ratemaking, and that leads to ratepayers paying a return as calculated over its useful life. The method is not precise, but the utility said tracking and calculating the costs of specific low-capital assets (like the $38 million it would spend on Segment A) can be administratively burdensome and lead to higher costs for ratepayers.
In the order Friday, FERC still questioned why the carrying charge included retirement obligations, which generally are not permissible in transmission rates. The utility said it would make another filing removing the retirement fees, but FERC said it was not clear whether that approach was appropriate.
The fact that the small segments Niagara Mohawk is building will be recovered using an average of its entire transmission base means that Segment A will never fully depreciate for rate purposes, and the utility failed to show it would ensure its costs are recovered in a systematic and rational manner.
While FERC set the matter for hearing, it encouraged a settlement and will wait to pick an administrative law judge for 45 days to give a chance for settlement talks to occur.
Dominion brought in $599 million in net income during the second quarter, despite mild weather and some unexpected outages at the Millstone Nuclear Plant in Connecticut, the firm reported Friday.
While Dominion reported on some of the recent issues its business faced, it also said it is wrapping up a business review, with plans to host an investor day by the end of September laying out a new long-term plan.
“I’m pleased with the progress we’re making toward delivering a compelling repositioning of our company to create maximum long-term value for shareholders, employees, customers and other stakeholders,” CEO Robert Blue said. “As I’ve said before, I’m as excited as ever for the future of our company.”
The second quarter had some of the mildest weather Dominion has seen in half a century, enough to cut into its earnings by 8 cents/share, said CFO Steven Ridge.
“With regard to Millstone, we experienced both an increase to the duration of a planned outage at Unit 2 and an extended, unplanned outage at Unit 3, which taken together amounted to an additional 8-cent headwind during the quarter,” Ridge said. “These outages are uncharacteristic for Millstone, which has a strong history as the largest zero-carbon electricity resource in New England, exemplary safety and reliable performance.”
Dominion recently hired Eric Carr from PSEG Nuclear as its new chief nuclear officer, and senior leadership are working on a review of the plant’s operating procedures to ensure it is reliable in the years to come, Ridge added.
Dominion Virginia Power last month implemented a rate cut for customers — with the average monthly bill dropping $14 — that was authorized as part of legislation passed earlier this year in Virginia that changed how the utility is regulated. (See Virginia Legislature Passes Utility Regulation Bills Backed by Dominion.)
The firm is seeking to spread out recent unrecovered fuel costs to avoid swamping that recent rate cut with a $15/month bill increase, Blue said.
The 2.6-GW Coastal Virginia Offshore Wind project remains on track and on budget, despite some of the issues other major offshore wind developments are running into.
“We continue to work closely with the Bureau of Ocean Energy Management and other stakeholders to support the project’s timeline,” Blue said. “BOEM received comments from all agencies on the draft of the final EIS [environmental impact statement] and is on schedule to deliver the final EIS by the end of September and the record of decision by the end of October. We continue to be encouraged by the administration’s timely processing of offshore wind projects.”
The Virginia State Corporation Commission recently approved an updated rider for the project, which will pay the utility $271 million for its efforts for a year. The project’s costs, excluding contingencies, are now 90% fixed, said Blue. Procurement processes are well underway, and the first monopoles should be delivered to the Port of Virginia by the end of the year.
“Despite trends we see elsewhere in the offshore wind market, we do not see anything that changes our confidence in delivering the project on time and on budget,” Blue said.
PORTLAND, Ore. — It’s taken CAISO’s Western Energy Imbalance Market (WEIM) nearly nine years to expand to cover about 80% of the load in the Western Interconnection since being launched with PacifiCorp as its first participant.
But after a little more than a year of outreach, SPP is contesting much of that ground as it hustles to attract participants to Markets+, a fast-rising competitor that is drawing strong interest in the West just as CAISO moves to broaden the real-time WEIM into the long-awaited Extended Day-Ahead Market (EDAM).
The near-term issue for the region’s electric industry participants is which day-ahead market to choose, but their decisions likely will set the course for the eventual development of a Western RTO — or multiple RTOs.
“Once we move to a day-ahead market, that is a much larger footprint [of energy transactions]. It is much harder to transition from one day-ahead market to a separate [market] to get to an RTO/ISO,” Alex Swerzbin, director of transmission and markets for PNGC Power, a Portland-based generation and transmission cooperative, said during a July 14 meeting to kick off the Bonneville Power Administration’s (BPA) effort to choose a day-ahead market.
The deep interest in Markets+ was evident at a packed June meeting SPP hosted at BPA’s Portland headquarters.
Attending the two-day event were about 60 people representing utilities and other organizations from across the West, including Arizona Public Service, Black Hills Energy, BPA, Portland General Electric (PGE), Puget Sound Energy, Salt River Project, Tacoma Power, The Energy Authority, Renewable Northwest and Northwest Energy Coalition (NWEC), among others.
Notably absent was PacifiCorp, which already has committed to CAISO’s EDAM. The Portland-based utility controls more than 17,000 miles of transmission and 11,500 MW of generation in six states.
SPP officials running the meeting quickly got deep into the weeds, with the first day consisting of exhaustive lessons on organized market concepts (such as reliability unit commitment, co-optimization, settlements and virtual transactions), peppered by back-and-forth among participants about what they would seek in the early stages of a rollout. An outside observer could be excused for assuming Markets+ already was a going concern.
“I sent some information to CAISO saying, ‘Hey, you know, they’re so interested in this stuff that they’re considering virtuals as a starting proposition,’” Scott Miller, executive director of the Western Power Trading Forum, told RTO Insider in an interview shortly after the meetings.
“I think it has a lot of momentum,” said one meeting participant, who is not authorized to speak on behalf of their employer, a Western utility. “They may not beat WEIM to a day-ahead market, but they have more momentum for a Western RTO.”
“I think if there was one word to describe the Markets+ zeitgeist, it’s ‘momentum,’” Miller agreed.
“SPP is making a lot of progress,” he said. “Its stakeholder process has so charmed people that it’s added to that momentum.”
Not all attendees were caught up in the zeitgeist.
“I can’t see how we can have two markets in the West, particularly with PacifiCorp going with EDAM — and possibly PGE,” one attendee said on the sidelines. That attendee also pointed out that California is by far the region’s biggest player and that two competing markets would put “a big seam” in the West.
But as Miller pointed out, governance continues to be a stumbling block for CAISO’s effort to expand into a Western RTO. Under California law, the ISO’s governing board must be appointed by the state’s governor, an unacceptable political arrangement for other Western states that bristle at prospect of yielding control of their grids to the biggest state in the nation.
California lawmakers have three times failed to pass bills authorizing an independent board, and yet another bill to address the issue has stalled in committee during the current session.
The governance problem took on a new sense of urgency last month when BPA launched its day-ahead market stakeholder process, committing to making a decision in the first quarter of next year.
“With EIM, we watched that market develop for several years before we even began our process of evaluating whether to join,” Russ Mantifel, BPA director of market initiatives, said at the July 14 kick-off meeting. “That is very much explicitly and intentionally not what Bonneville is doing here. Our intent here is to try to be proactive, as much as possible, both in the development of these markets, and in terms of making a decision at an earlier point, in order to position ourselves to join a market earlier in the lifecycle of these markets.”
In other words, with 15,000 miles of transmission and nearly 17,500 MW of generating capacity in the Northwest, BPA wants a seat at the head of the table for planning a market that likely will become the foundation for a full RTO. And for statutory reasons, CAISO’s state-run governance is a clear non-starter for the federally operated BPA.
Changing Expectations
But even if California lawmakers do act on governance, Miller said, that no longer may be the pivotal issue for BAs considering a commitment to CAISO. Market participants will seek deeper cultural shift in the ISO, one that would transform its staff-driven policy process into a stakeholder-driven one like those in other multi-state RTOs such as SPP, MISO and PJM.
“Now they’ve been exposed to a stakeholder process that the stakeholders run, and there still hasn’t been a stakeholder process [in CAISO] that is developed much differently, even in the context of the EIM,” Miller said. “So, CAISO hasn’t figured out that everybody’s expectations have changed, because they haven’t had a chance to yet because they’ve been so focused on writing their [EDAM] tariff — understandable — and trying to work with the legislature to see if they can get the governance change.”
But not every Western stakeholder is so charmed by SPP’s stakeholder process. Vijay Satyal, deputy director of Western energy markets at Western Resource Advocates (WRA), a Colorado-based environmental non-profit, thinks that process doesn’t give fair play to perspectives from outside the electric sector.
“They’re taking all the feedback of market participants, but the definition of market participants for SPP is the people who bring generation or load or both — that are utilities or customers,” Satyal said in an interview. “But in the Cal ISO process, anybody can bring any issues to the table and they get addressed, and then we get responses back.”
Satyal pointed out that the WEIM’s Regional Issues Forum (RIF), a stakeholder body he chaired last year, will exercise new authority under EDAM “to deliberate on trending issues before they become stakeholder proposals” in CAISO.
“Can you find me a RIF design in Markets+? There isn’t one conceived yet. That’s an area we want to push,” he said.
Satyal also offered a more generous take on CAISO’s existing governance, pointing out that the WEIM’s Governing Body consists of five members who are not selected by California’s governor but elected by stakeholder sector committees.
“That’s independence. That’s parallel authority. That has truly not yet been appreciated,” he said.
Furthermore, Satyal questioned the independence of the Markets+ Independent Panel (MIP), the body SPP established earlier this year as “the highest level of authority for decisions related to Markets+.” He noted that the five-member MIP includes two SPP board members: Steve Wright, a former BPA administrator, and John Cupparo, previously a senior executive with Berkshire Hathaway Energy and PacifiCorp. MIP decisions are, in turn, still subject to approval by the full SPP board.
Echoing Satyal’s concern was Fred Heutte, a senior policy associate with the Northwest Energy Coalition.
“Are we the only ones who are concerned about the fact that Markets+ has a process going forward where the Markets+ board and the SPP board, neither of which have had any voice whatsoever in their selection from the West, will be actually making the decisions in this initial phase?” Heutte said at BPA’s July 14 meeting. “Are there governance issues on both sides?”
The Matter of Seams
NWEC and WRA share another key concern: the impact of dividing the West into two separate markets that potentially would be cut through by a tangle of seams, depending on where various BAs choose to put themselves.
Both organizations have long been advocates for creating a single West-wide RTO that includes California to realize the full potential of sharing renewables across the region, in order to avoid curtailments and ensure a maximum reduction of greenhouse gas emissions. In that scenario, California’s daytime solar surpluses are seen as a complement to a potentially vast buildout of wind energy resources in other parts of the West, as well as the existing hydro resources in the Northwest.
“We want one large market in the West,” Satyal said. “There is tons of evidence that one large market will eliminate extra transaction costs, information management and different business practices where the different definitions exist in two markets.”
WPTF’s Miller said the seams issue could be managed by an enforceable agreement between the two markets.
“FERC would force whatever entities there are to have a joint operating agreement so that you could still sell either day-ahead or energy imbalance into each other’s systems,” he said.
But Heutte is skeptical about such an arrangement.
“The evidence from the East is very strong: that seams agreements are big, complicated things that never reach perfection, require a considerable amount of attention [and] include transaction costs and so forth,” he told BPA officials at their July meeting.
For Satyal, the economic case for a single RTO can be found in the 2021 state-led market study that estimated that the U.S. portion of the Western Interconnection could realize $2 billion in savings a year by 2030 if it adopted one market. The study’s two-market scenarios yielded considerably lower savings for the region as whole. (See Study Shows RTO Could Save West $2B Yearly by 2030.)
But results from a company-specific study, conducted by the Western Markets Exploratory Group (WMEG), paint a more complicated picture, industry sources have told RTO Insider. Those findings, released last month to individual entities, remain confidential, but the sources said they indicate California would be the biggest beneficiary of a single market, while others — but not all —actually could reap greater economic benefits from a two-market solution.
Individual utilities are expected to make those results public at their own discretion, with some required to disclose the data to their regulators before a public release, one source said. Andy Meyer, a public utility specialist with BPA, told attendees at the July 14 meeting that BPA might begin to “trickle out” its own study results starting in September, but he offered no guarantee.
“The state-led market study had a very thorough public review,” Heutte said at the meeting. “Given the nature and potential impact of this decision, we hope that Bonneville will put all your cards on the table, not just the ones that lead one way or the other, whichever way, because it’s really important for us to have a full understanding of what the consequences could be.”
Lifeline for CAISO?
With CAISO stymied on governance, it’s unclear whether the proposal last month by a group of Western utility commissioners to create an independent RTO based on the ISO’s operating framework will gain traction. (See Regulators Propose New Independent Western RTO.)
Under the plan, laid out in a July 14 letter to the chairs of the Western Interstate Energy Board (WIEB) and the Committee on Regional Electric Power Cooperation (CREPC), “a non-profit entity governed by representation from across the West would be formed” to contract for RTO services with CAISO, “including eventual assumption of the Extended Day-Ahead Market (EDAM) and the Energy Imbalance Market (EIM).”
The letter, signed by regulators from Arizona, California, New Mexico, Oregon and Washington, emphasized the transaction cost benefit of avoiding seams. Among the signatories was Washington Utilities and Transportation Commission member Anne Rendahl, who sits on the Markets+ State Committee and formerly chaired the WEIM’s Body of State Regulators. Rendahl declined to comment for this story, saying her commission may be asked to weigh in on the market proposals in future utility proceedings.
The Western utility source who spoke to RTO Insider not for attribution said some industry participants outside California are skeptical that their interests would have equal footing with those of the most populous U.S. state under the arrangement.
That’s a view apparently shared by former WPTF head Gary Ackerman, who in the July 21 edition of his widely distributed Friday Burrito newsletter wrote: “An independent entity with a contractual link to the CAISO will not easily satisfy multi-state governance issues because of the lopsided weight of the CAISO load relative to all the other balancing authorities outside of the CAISO. Sure, it’s worth trying but expectations must be kept in check.”
“The more diversity, the fewer seams you have, the more effective [a market is] going to be — I can’t disagree with that,” BPA’s Mantifel said. “I think … the other reality is what it takes to get there, and sort of the sacrifices and compromises people are willing to make in order to achieve that, and whether that’s ultimately viable.”
SPP will hold meetings of its MIP and Markets+ Participants Executive Committee Aug. 8-9 in Portland. CAISO, along with the Balancing Authority of Northern California, NV Energy, PacifiCorp and Southern California Edison, will host an EDAM forum in Las Vegas on Aug. 30. BPA’s next set of day-ahead market meetings will be held at the agency’s Portland offices Sept. 11-12
NEPOOL approved a set of tariff changes related to ISO-NE’s Day-Ahead Ancillary Services Initiative (DASI) proposal at the August Participants Committee (PC) meeting, held virtually Thursday. The vote gave final NEPOOL approval of the DASI proposal, as the changes previously had been approved by the Market, Reliability and Transmission Committees.
“ISO New England has been working with stakeholders on … DASI for almost a year and we’re pleased NEPOOL approved DASI,” ISO-NE told RTO Insider in a statement following the vote. “We plan to prepare and file our DASI proposal with FERC in October of this year. Our plan is to have DASI integrated into New England’s wholesale markets by March 1, 2025.”
In a July memo, ISO-NE wrote that the current Day-Ahead Energy Market, which clears just one energy product based on supply offers and demand bids, leaves gaps when unforeseen generation and infrastructure issues arise and when the market clears less supply than forecasted load.
“The DASI proposal creates a Day-Ahead Ancillary Services Market that, together with today’s Day-Ahead Energy Market, creates a single, jointly optimized Day-Ahead Market,” ISO-NE wrote. “These new day-ahead ancillary services will encourage reliable resource performance and prepare the system on a day-ahead timeframe with the flexibility needed to manage operational uncertainties.”
While approving the proposal, members of the Markets Committee have asked ISO-NE to reassess the strike price adder when more data is available following implementation. NEPOOL members also have raised concerns related to the DASI’s effects on peaker plants, as well as concerns about the elimination of the Forward Reserve Market (FRM). ISO-NE plans on removing the FRM when DASI takes effect in March 2025.
“The FRM is no longer necessary in its suite of markets, given the development of the new Day-Ahead Ancillary Services and in light of the significant transmission and market improvements that have been made over the last decade to relieve locational constraints and reward resource flexibility and performance,” ISO-NE said.
The D.C. Circuit Court of Appeals on Friday dismissed a review petition filed by Xcel Energy, on behalf of its Southwestern Public Service (SPS) subsidiary, and Kansas Electric Power Cooperative (KEPCo) over FERC’s rejection of their rehearing requests related to SPP’s filed-rate doctrine (20-1429).
FERC last year denied the SPS and KEPCo rehearing requests of SPP’s assignment of network upgrade charges under Attachment Z2 of its tariff. It said the grid operator did not violate the utilities’ service agreements or the RTO’s tariff. (See KEPCo, Xcel Rehearing Requests on Z2 Fail.)
The utilities argued that Attachment Z2 — which awards credits to transmission upgrade sponsors from any upgrade users whose service could not be provided “but for” the upgrade — required using an N-1 contingency analysis, rather than the reservation stack analysis (RSA) that SPP used. They also said the RTO violated the filed-rate doctrine and tariff because the rate was unclear about how much they would be charged, and because it didn’t identify the upgrade facilities that would meet their requests nor provide them with an estimate of the costs.
The D.C. Circuit denied in part and dismissed in part the review petitions because it said FERC correctly concluded that Attachment Z2 “does not plainly require” the N-1 methodology. It also said the commission’s reliance on extrinsic evidence to determine SPP’s tariff allows the RSA methodology was not arbitrary and capricious, as SPS and KEPCo had alleged.
The court also said it lacked jurisdiction to consider the utilities’ filed-rate doctrine argument because they failed to exhaust it at the rehearing stage.
Applying the RSA methodology, SPP imposed upgrade charges in 2016 that had not been specifically mentioned in the utilities’ service agreements. SPS was billed $12.8 million for 101 creditable upgrades, 96 of which were not included in its service agreement. KEPCo was billed $6.2 million for seven creditable upgrades; none were included in its service agreement.
Texas regulators last week endorsed ERCOT’s proposed modifications to the operating reserve demand curve (ORDC) designed to retain and attract dispatchable generation.
“I believe that near-term action is important to retain our long-duration, dispatchable thermal generation assets that I believe are extremely necessary to maintain reliability during extreme weather conditions,” Commissioner Lori Cobos said during the Public Utility Commission’s open meeting Thursday.
Under ERCOT’s multistep proposal, price adders of $20/MWh and $10/MWh will be set when operating reserves hit floors of 6,500 MW and 7,000 MW, respectively. Staff’s analysis indicates the floors would have increased revenues to generators by about $500 million during the 2020 and 2022 pricing years. Thermal generators would have received 80% of those revenues.
ERCOT says the ORDC increasing during substantial operating reserve surplus periods will improve pricing signals, help retain existing assets, add new dispatchable generation and reduce the frequency of reliability unit commitments (RUCs).
Cobos filed a memo before the meeting explaining the need for a “market-based tool” that incents generators’ self-commitment in the real-time market to help reduce RUCs. To ensure the ORDC modification’s goals are met, she also laid out three metrics ERCOT will be required to track and report back to the commission (53298):
The amount of new revenue specifically resulting from the adders;
The specific type of generation resources that received the new revenue; and
Performance data showing whether the adders have reduced ERCOT’s use of RUC.
“I think these metrics will help us keep track of whether or not this action is accomplishing what we set out to do,” Cobos said.
She also recommended the PUC re-evaluate the need for the price-floor adders after ERCOT deploys dispatchable reliability reserve service in December 2024 to check that RUCs are reduced by the amount of the new ancillary service ERCOT procures.
Commissioner Jimmy Glotfelty said he struggled with ERCOT’s proposal but joined the PUC’s unanimous decision.
“It’s not clear to me that we are creating a bridge solution to eliminate RUC or that we’re creating a bridge solution to bridge us to a reliability capacity issue to solve our resource adequacy issue,” he said. “If we want to eliminate RUC, I think we should be looking at all of the solutions that could eliminate RUC, not just one. I know RUC is problematic for generators, but what I don’t want is another out-of-market solution to solve an out-of-market solution that we created which solved a conservative operations out-of-market solution that we created. We’re just piling on by trying to fix the market with other modifications.”
The PUC in January directed ERCOT to propose a bridge to the commission’s proposed market redesign, a performance credit mechanism (PCM). However, the design’s chief proponent, former commission Chair Peter Lake, stepped down from his post in June after Texas lawmakers suggested other market structures during their recent legislative session. (See Texas PUC’s Lake Steps Down as Chair.)
ERCOT’s ORDC values the wholesale market’s operating reserves on their scarcity, reflecting that value in energy prices.
The curve has been modified several times since it became part of the market in 2014. The value of lost load, which is set equal to the system-wide offer cap, was changed from $9,000/MWh down to the $2,000/MWh low-system-wide offer cap after the 2021 winter storm, then back up to $5,000/MWh in January 2022. The minimum contingency level also was increased last year from 2,000 MW to 3,000 MW.
Entergy Texas Gets Rate Increase
In other actions, the PUC approved an unopposed settlement that increases Entergy Texas’ base rate revenues by $54 million, resulting in a nonfuel revenue requirement of $1.23 billion. PUC staff, the Office of Public Utility Counsel and Texas Industrial Energy Consumers were among the signatories to the agreement (53719).
At the same time, the commission severed into a new proceeding two contested issues related to Entergy’s proposed electric vehicle charging riders. The PUC will determine whether it is appropriate for a vertically integrated utility to own EV charging facilities or other transportation electrification and charging infrastructure.
The commission also rejected rehearing requests by Texas Energy Association for Marketers, Alliance for Retail Markets and Texas Competitive Power Advocates over the approval of a partial settlement that reduced CenterPoint Energy’s distribution cost recovery factor by $7.8 million (53442).
The Illinois Commerce Commission last week instituted a Notice of Inquiry over the potential benefits of Ameren Illinois quitting MISO to join PJM.
The ICC’s NOI focuses on a recent Ameren Illinois study, prepared by Charles River Associates, which concluded that if all MISO Zone 4 utilities left for PJM, it would cost the State of Illinois $3.4 billion over the 10-year period from 2025 to 2034 (23-NOI-01). The firm recommended Ameren Illinois stay on with MISO after it analyzed energy trade benefits, transmission expansion costs, capacity costs, RTO administrative fees, and exit and integration fees.
“Joining PJM did result in some benefits, such as reduced emissions and increased resiliency, but these benefits are outweighed by the significant economic costs,” the study authors wrote.
“Safe, reliable and affordable electricity is always top of mind at the commission, and with the ongoing changes to our power system, it makes sense for the ICC to consider how the workings of our electric grid operators are or are not benefiting Illinois consumers,” ICC Chairman Doug Scott said in a press release. “This study is a helpful resource in determining if continued participation in MISO makes the most sense for Illinois and Ameren Illinois customers.”
The ICC said that without reform, “structural market shortcomings” in MISO could lead to insufficient supply and a spike in bills for ratepayers in central and southern Illinois.
ICC’s NOI includes a three-month comment period for interested parties, with initial stakeholder comments due Oct. 2 and reply comments due Nov. 1.
The ICC said comments will “inform any future or potential commission action regarding the state’s ongoing participation in its two power grid operators.” The ICC emphasized that its NOI proceeding is not a rulemaking. It said the information it receives “may or may not form the basis for the initiation of a formal ICC rulemaking or other purposes.”
On Aug. 3, Ameren reported a profit of $237 million ($0.90/share) for the second quarter, compared with $207 million ($0.80/share) this time last year. It said more significant investments in transmission and distribution infrastructure boosted its fiscal performance.
MISO declined to comment on Ameren Illinois’ cost-benefit analysis, whether it thinks the ICC might have a change of heart on its capacity market structure if it adopts changes such as a sloped demand curve, and whether it will file comments in the NOI.
With its substation now in place off the Massachusetts coast, Vineyard Wind 1 expects the first electricity to start flowing to land before the end of this year.
Avangrid last week provided an update on the landmark offshore wind project, which has been the subject of years of intensive planning but saw its first “steel in the water” only in June.
Several monopile foundations for turbine towers have been fixed to the ocean floor, and Avangrid announced Thursday that the substation has been placed on its four-pile jacket foundation, roughly a dozen nautical miles south of Martha’s Vineyard.
The Danish-built substation now looms over nearby vessels but soon will be dwarfed by the towers nearby.
It will give up nothing in bulk, however, weighing in at more than 6 million pounds.
Manufacturer Bladt Industries said the combined weight with its foundation is roughly 10.4 million pounds — equal to 2,300 of the Tesla Model Y cars Vineyard Wind 1 eventually will help charge.
Avangrid said in a news release that this is the sixth and largest substation in the fleet installed by parent company Iberdrola, which previously has placed units off the coasts of France, Germany and the United Kingdom.
It also is the first offshore wind substation installed in U.S. waters.
Vineyard Wind 1 and South Fork Wind are racking up a series of firsts in the emerging U.S. offshore wind sector this spring and summer as a flotilla of construction vessels large and small plies the waters south of Massachusetts and Rhode Island.
One of the two will become the first commercial-scale offshore wind farm in the U.S. Or perhaps both will claim the honor with an asterisk — first to produce current and first to reach full power.
South Fork has an edge: It is less than one-fifth the size of Vineyard.
(South Fork’s substation is relatively svelte, at only 3 million pounds — but it was the first offshore substation ever built in the US.)
The two are roughly 30 nautical miles apart in the patch of the Outer Continental Shelf that the Bureau Of Ocean Energy Management has divided into multiple wind leases.
Vineyard, a joint venture of Avangrid Renewables and Copenhagen Infrastructure Partners, will have 62 turbines with a nameplate capacity of 806 MW and will feed into the grid in Massachusetts.
South Fork’s 12 turbines will have a capacity of 132 MW and feed into the New York grid. It is a joint venture between Ørsted, the world’s largest offshore wind developer, and New England utility Eversource, which is looking to sell its share of South Fork and other offshore projects.
Avangrid, Ørsted and other developers have run into major financial problems with other offshore wind projects they are pursuing in the Northeast, because of soaring costs and interest rates.
But Vineyard and South Fork already were far along in the process by the time those costs started rising.
