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November 24, 2024

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Dominion Reports More Data Center Growth, Offshore Wind Progress

Dominion Energy reported net income of $953 million in the third quarter this year as it continued to see load growth from data centers, made progress on its offshore wind project and repaired damage from Hurricane Helene. 

The storm caused significant destruction of the company’s infrastructure, knocking out power to nearly 450,000 customers, including nearly half of those Dominion serves in South Carolina, CEO Robert Blue told investors. 

“The restoration involved replacing over 1,000 transformers, 2,300 poles and 7,000 spans of wire,” Blue said. “Although we’ve not completed our final accounting, our preliminary estimate of restoration costs, including capital expenditures, is in the range of $100 (million) to $200 million.” 

Dominion’s Coastal Virginia Offshore Wind (CVOW) is 43% complete and remains on schedule and on budget, Blue said. The firm just completed a season of monopile installations, having installed 78 for the project’s turbines and an additional four pin piles for related transmission substations. 

“Additionally, we’ve laid the first two of nine marine deep water export cables ahead of schedule,” Blue said. “I’m very pleased with our progress during this first season. Not only did we achieve our installations target, we also gained invaluable experience and process expertise that will make the next installation season even more productive.” 

The rest of the monopiles are being produced and delivered to Portsmouth, Va., while Dominion expects nacelle and blade production to start in the first quarter of next year. 

To help with offshore wind construction, Dominion is building a ship called Charybdis, which will be compliant with the Jones Act, a law that limits shipments inside U.S. waters to domestic vessels. The ship is 93% complete and should be operational by early 2025, Blue said. 

“The project’s expected LCOE [levelized cost of energy] has improved to approximately $56 per megawatt hour,” Blue said. “The primary driver being forecasted REC [renewable energy certificate] prices, which have increased in value considerably.” 

Dominion serves the largest data center market in the world, and so far this year, it has interconnected 14 of the facilities, with two more expected to come online before the end of 2024, Blue said. 

“We’re currently studying approximately 8 GW of data center demand within the substation engineering letters of authorization stage, which means a customer has requested the company to begin the necessary engineering for new distribution and substation infrastructure required to serve the customer,” Blue said. “There are also about 6 GW of data center demand that have executed construction letters of authorization, which are contracts that enable construction of the required distribution and substation electric infrastructure to begin.” 

In total, the firm had about 21 GW of data centers in the more advanced stages of its planning process as of July, which was up from 16 GW a year earlier, he added. 

“These contracted amounts do not contemplate the many data center projects that are in development phase and have not yet reached a point in the service connection process where a contract is executed,” Blue said. 

Dominion owns the Millstone nuclear plant in Connecticut, which could benefit clean energy legislation in New England, as neighboring Massachusetts is considering legislation that would authorize long-term contracts with it. (See Mass. Clean Energy Permitting, Gas Reform Bill Back on Track.) 

“We’ve continued to engage with multiple parties there to find the best value for Millstone. In addition to state-sponsored procurement, we’re exploring the idea of supporting incremental data center activity as well,” Blue said. “We feel strongly that any data center option needs to be pursued in a collaborative fashion with stakeholders in Connecticut. At this point, we don’t have a timeline for any potential announcements, but this remains top of mind for us.” 

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FERC Dives into Data Center Co-location Debate at Technical Conference

A common refrain at FERC’s technical conference on the co-location of data centers held Nov. 1 was that the issue is just part of the broader problem of how to meet growing demand as older power plants retire and new ones are often delayed from coming online (AD24-11). 

While many speakers made that argument, co-location itself could either help or hinder the industry’s efforts to ensure resource adequacy. 

Chair Willie Phillips opened the conference by laying out how ensuring data centers are built in the U.S. is a major policy priority, alongside reshoring manufacturing. 

“In my opinion, data centers, artificial intelligence [and], indeed, the full panoply of information-related technologies that are transforming the world are national resources with generational significance and vast national security and national economic consequences,” Phillips said. “They belong in the United States, and I believe that the federal government, including this agency, should be doing the very best it can to nurture and foster their development.” 

Large data centers are willing and able to pay for the new capacity needed to integrate them reliably, he added. The sector could help anchor the infrastructure that the grid needs to maintain reliability, he argued. 

But they are coming online on a grid with a shrinking reserve margin, with Commissioner Mark Christie noting that PJM has warned it could be short on supply by 2030. 

“One of the big issues here, of course, is resource adequacy,” Christie said. “And one of the questions to be asked is, if you’re taking dispatchable resources — and when we talk nukes, we clearly are talking dispatchable resources — if you’re taking them out of the supply stack, what does that do to resource adequacy? That’s a huge issue that needs to be explored.” 

Another issue is fairness to consumers, such as whether they will pay the non-bypassable charges all retail customers face if they are behind the meter at a nuclear plant, Christie said. 

Pulling resources off the generation stack to serve data center load can have major cost impacts on the rest of the market, Maryland Sen. Katie Fry Hester (D) said. She quoted an analysis from PJM’s Independent Market Monitor estimating the cost of redirecting 1,000 MW from the Calvert Cliffs plant to serve a data center. 

“They found that removing 1,000 MW of power from Calvert Cliffs, which was their approximation for a co-located data center, would increase the cost to Maryland in the 2025/26 [capacity auction] by $332 million,” Hester said. “I mean, that is a shocking number. And when the companies sit up here and say they’re paying their fair share, they may be paying for their immediate energies, but they’re not taking into account what it’s going to cost us to build the transmission for everybody else who’s no longer served by this power.” 

Google: Speed to Market the Main Reason for Co-location

Google is not trying to avoid the costs of plugging into the grid with its exploration of co-location deals, said Brian George, the company’s U.S. federal lead on global energy market development. 

“Co-location in the context that we’re talking about right now is really just a response to a market inadequacy, right?” George said. “We’re trying to figure out how we can get new loads onto the system in a way that meets our growth objectives. And so, I think that is important because it’s driven by the need to access the market.” 

Google is not trying to avoid transmission and distribution costs by locating data centers behind the meter at power plants, he added. 

“It is really kind of our preference to see the grid planned in a way that meets our needs, in collaboration with our utility partners, with our RTO partners; that it’s baked into forecasts. We’re sending resource adequacy signals,” George said. “That is where we want to go.” 

Constellation Energy, the owner of Calvert Cliffs and the largest fleet of nuclear plants in the U.S., sees the growth in data centers and co-location as a way to ensure those assets stay profitable and producing power for decades, said Mason Emnett, senior vice president for public policy. It was only recently that nuclear plants were starting to retire because of low wholesale power prices. 

“That led to a number of state programs and then ultimately a federal program that will be rolling off right as 40% of our fleet is turning over their 20-year licenses,” Emnett said. “So, from our perspective, the opportunity to serve this critically important load creates a long-term commercial pathway to relicensing.” 

The kind of long-term deals that data center clients are interested in could help provide the financial backing to eventually add new nuclear plants to the grid, he added. 

Constellation wants to serve more customers through traditional power purchase agreements as well, and Emnett said co-located load should pay its fair share. 

“What does ‘fair’ mean for a load that has no ability to pull power from the grid?” he said. “It’s not gross load. … We can have a conversation about that, but when you have litigation positions that are so far apart, then it makes it difficult, and ultimately, it’s the job of the regulator to call balls and strikes.” 

That litigation involves the firm that Constellation was spun off from in 2022, Exelon, with the two and other generators and utilities lining up on opposite sides of pending FERC cases on co-location. (See Exelon, Constellation at Loggerheads over Data Center Co-location.) 

Co-location’s Impacts on Resource Adequacy

Exelon supports co-location, which is not a new process, said Vice President of Transmission Strategies David Weaver. 

But the issue is that the recent deals Constellation has pursued in Exelon utility territories have not followed the rules in their tariffs. 

Proposed data centers can range in demand up to 1 GW, while each of Exelon’s utilities on average serve about 6.4 GW of load. 

“There’s a number of potential reliability impacts and reliability studies that have to be performed, right?” Weaver asked. “You’ve got not only the thermal flow issue that the protection is in place for, but you’ve got stability issues … short-circuit issues, and all those things that have to be considered.” 

Ultimately, even resources behind the meter at a nuclear plant rely on the grid, and Weaver argued they should have to pay their fair share of its costs. 

PJM Monitor Joe Bowring also said co-location does not mean the plants are off the grid and agreed that the issue is a sideshow to the main issue facing the RTO now. 

“The issue is reliability,” Bowring said. “At the moment, PJM is right on the edge and talking about … adding 10 [thousand MW] or 20,000 MW of load on a system that is already very tight.” 

PJM is working on rules to help get more supply onto the system, including a process to get power plants that can increase reliability to the front of the queue. (See Stakeholders Divided on PJM Proposal to Expedite High-capacity Generation.) 

“It makes sense to think really hard and try to be effective about getting new resources online,” Bowring said. “But from a static perspective, it does not make sense to add 10,000 MW of load behind some of the most critical generators on the system, the nuclear power plants.” 

Adding 20 GW of data centers would represent most of PJM’s nuclear capacity, which are important facilities around which the entire grid has been planned, he added. 

Co-located load brings up questions such as whether the customer is using the transmission system, how much the facility benefits from ancillary services and whether a retail sale is involved, said Copper Monarch Principal Vincent Duane, former general counsel for PJM. But that misses the bigger question of what impacts such deals are having. 

“Whether we have a data center connecting in front of the meter, or whether we’re connecting that data center behind the meter, we are going to see more or less similar impacts and consequences on the system, whether we’re talking about reliability impacts or the supply-and-demand impacts, or the system needs, including the need for new transmission upgrades,” Duane said. 

Data center load growth in Virginia and power plant retirements in Maryland led to billions of dollars of need for new transmission in PJM’s most recent regional plan. The impact of taking capacity from an existing plant to serve a data center is functionally equivalent to a retirement, Duane said. 

Independent Consultant Mike Kormos, who wrote a paper for Constellation filed in one of the dockets noticed in the technical conference, said co-location deals already take many of those issues into account. 

“The risk is on the generator in the data center,” said Kormos, former COO of PJM and senior vice president for Exelon. “They are obligated to pay for network service upgrades.” 

PJM has been clear that it will turn down co-location arrangements if they do not deal with reliability issues on the power grid, he added. For data centers that plug into a utility’s distribution system, the RTO has no such power. 

Co-location’s Impact on Grid Operations

Some have questioned whether data center load can truly be isolated from the grid; Talen Energy Executive Vice President Cole Muller said that was certainly possible.  

His firm’s Susquehanna nuclear plant has a co-located data center owned by Amazon, the expansion of which brought the debate before FERC. (See Talen Energy Deal with Data Center Leads to Cost Shifting Debate at FERC.) 

Before Muller was at Talen, he worked on nuclear submarines for the U.S. Navy. 

“We had protective relays in place to protect the reactor in case extraordinary circumstances happen and really high-consequence scenarios,” Muller said. “And so, if we are able to rely on relay schemes for a national security asset like a ballistic missile submarine, we should be able to rely on these kind of schemes for protecting the grid from co-located load.” 

Even if the data centers are only taking power from the nuclear plants, they can still have operational impacts on the grid, said Howard Gugel, NERC vice president of regulatory oversight. 

“What happens if you lose the load, that generation is now over-generating on the system?” Gugel said. “What do you do then? Do you back down the generation? Do you trip the generator? How do you restore from that? So there’s other scenarios I think that need to be taken into account here.” 

Large data center loads operate very differently than other kinds of load, Gugel said. He compared them to inverter-based resources, which NERC has been dealing with for years and can have cascading events where many go offline at once, exacerbating grid disturbances. This summer, a single line-to-ground fault on a 230-kV transmission line took out 1,550 MW of nearby data centers. 

“It was interrupted normally on the line, at 1/28 of a second the breakers operated; the line was taken out,” Gugel said. “But because of that voltage perturbation that occurred, you had a significant amount … of load, over 25 substations and about 60 different providers, that saw the impact from that. All the interruptions occurred behind the meter. It wasn’t any action that was taken by any utility or any ISO.” 

Until the industry gets better modeling and more experience operating the grid with more data center load, it is going to be difficult to understand their impact on reliability, he added. 

Figuring out how data centers are going to impact the grid is more difficult because the facilities differ significantly. 

“I think one of the things that I’m very concerned about is each one of these data centers is going to be a snowflake,” MISO Vice President of System and Resource Planning Aubrey Johnson said. “And so, they’re going to have their own design, their own issues, their own concerns, their own configuration that they’d like to meet.” 

Most have backup generation, even those behind the meter at a nuclear plant, but that comes with questions on how long that can run under state air permits. The design of an interface between a co-located data center and the grid can have a major impact too, such as whether it just blocks power from serving the load or whether it can also let power flow out in a demand response situation, Johnson said. 

“So, if we want to think about a set of rules, I think they either need to be very, very specific and start creating a formulaic approach to how you work behind the meter, and/or you have to think about making them broad enough to be simply a set of guidelines we should already be paying attention to,” Johnson said. “I think fundamentally we ought to lean in on reliability and have that be the basis upon which we build off.” 

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WINDPOWER: Industry Brainstorms on Beating Back Misinformation

ATLANTIC CITY, N.J. — Did anyone really expect the opposition to skip an offshore wind industry conference on the Jersey Shore, a focal point for protest and opposition?

If so, they haven’t been paying attention.

A cluster of protesters carrying signs and chanting slogans greeted nearly 2,000 attendees as they arrived at Offshore WINDPOWER 2024 on Oct. 29.

“Go home!” one woman screamed.

Later that morning, a chief commercial officer drew a laugh from her audience as she recalled the comments directed at her: “I apparently have sold my soul.”

Opposition to offshore wind is much more widespread than the two dozen or so protesters outside the Atlantic City Convention Center.

Countering opponents’ messages and building public support was one of the central themes of the conference.

Many speakers said getting steel in the water and electricity flowing to land would be the best countermeasure, because open-minded skeptics will recognize the economic and environmental benefits.

But amid industry struggles, such tangible progress has been slow to materialize. Until it does, most agreed, the best strategy is to get ahead of the curve, countering misinformation early rather than reacting after it festers.

Speakers at multiple panels explained how they are trying to do this.

Dan Fatton, clean energy partnerships director at the New Jersey Economic Development Authority, said: “The reality is that there is a vocal minority who have concerns. Some of those concerns are legitimate and some of those concerns are based on misinformation. And so part of the state’s approach has been to share factual information and try to dispel some of the misinformation that’s been purposefully spread.”

Just in the past few weeks, a website has been established to serve as an information hub for the various state agencies involved in offshore wind development; their datasets had been dispersed and could be hard to find.

But as many others noted, Fatton said promises kept are more convincing than promises made.

“I think for years — and myself, I’m guilty of this as well, as an advocate — we’ve promised to deliver jobs through offshore wind, and we need to make that a reality and not just a talking point or rhetoric.”

Megan Daly, chief commerce officer at the Port of Albany, N.Y., recounted a similar experience with the wind tower factory that was planned and then canceled on the riverfront. The site is sandwiched between one of the most affluent communities in the region and one of the least affluent. Opposition came mainly from the wealthier side.

“It was interesting to us what the different priorities were,” Daly said. “First, we received feedback related to traffic mitigation and transportation and really very basic concerns for people that live there, in addition to job opportunities, and just in addition to, ‘What does this mean for us, what does this mean for our community?’”

From left: Frank Macchiarola of the American Clean Power Association, Megan Daly of the Port of Albany, Dan Fatton of the New Jersey Economic Development Authority and Sid Nathan of Rise Light & Power discuss ways to change hearts and minds in the community during Offshore WINDPOWER on Oct. 29. | © RTO Insider LLC 

Sarah Salati of National Grid Ventures, the chief commercial officer heckled outside the convention hall, said her company recently introduced Doorstep, an app that customizes information about energy infrastructure projects to the community level, so people can see exactly what is planned near them and can actively participate.

It also has developed WhaleWatch, which allows the public to track migration of whales and see that the company’s offshore efforts are designed to minimize impact on the leviathans.

High technology is not just for the generation and transmission sectors of the power industry, Salati said. It can foster a better connection to communities and stakeholders: “There’s a lot of room to leverage that digital marketplace and digital forum for the benefit of our industry.”

For the record, there actually were two demonstrations outside the convention on opening day: offshore wind opponents shouting from a distance (police kept them on the far side of the driveway) and smiling proponents handing out bright green T-shirts at a table right outside the front door.

Frank Macchiarola, chief policy officer of the American Clean Power Association, looked at this as a good sign for the wind power industry.

“If you don’t have people either standing up or asking questions, then your projects and whatever it is you’re doing, you’re not relevant to the people,” he said.

Sid Nathan, vice president of external affairs at Rise Light and Power, described the company’s efforts to engage the community near its Ravenswood Generating Station — which, as the largest fossil fuel plant in New York City, is not popular with many neighbors.

For its first 60 years, Nathan said, Ravenswood was a wall and a barbed-wire fence to outsiders. Then Rise began bringing the public and stakeholders inside to see the operation, and started sharing redevelopment plans, which notably include retiring the fossil generation and using the waterfront site as a point of interconnection and logistics hub for offshore wind.

These efforts had a reset when an offshore wind proposal was withdrawn in mid-October, but they did not end. “We had the community basically on speed dial to ensure that they understood the steps that we’re going to take to move forward,” Nathan said.

Stephanie McClellan, executive director of Turn Forward, suggested “giving people the facts and not just trying to persuade them and sort of bulldoze over their concerns.”

The message matters, she added:

“The audience is persuadable based on exposure to both positive and negative messaging. We know that we can move an audience from opposition to support, 20 points to the good, with the right messages, we see that in our polling and message setting, but we also see that they go right back [with a] negative message.”

From left: Rosanna Maietta of the American Clean Power Association, Stephanie McClellan of Turn Forward, Michael Muller of Muller Public Strategies and Julie Tighe of the New York League of Conservation Voters discuss influencing public support for offshore wind during Offshore WINDPOWER on Oct. 30. | © RTO Insider LLC 

Julie Tighe, president of the New York League of Conservation Voters, pointed to health effects as an influencer.

“We’ve actually found the public health messaging is super effective. People really respond to that. That’s true across all environmental issues,” she said.

Cost also is persuasive, Tighe said: “You have no idea what gas is going to cost tomorrow, needless to say five years from now; you know what offshore wind is going to cost you 10 to 20 years from now, because they have locked in contracts.”

Equity for disadvantaged communities — a tandem goal of many policymakers pushing offshore wind development — is not a goal that wins over many people, Tighe added. Pursue equity, she urged, but do not count on it to be an opinion-maker.

Longtime New Jersey political strategist Michael Muller, president of Muller Public Strategies, said the conference was being held in the “epicenter of noisy activism” against offshore wind.

Donald Trump himself joined a boardwalk rally against the giant turbines earlier this year, near the southern tip of the Jersey Shore.

“One of the more important things is that just because there’s a noisy opposition doesn’t mean that they’re winning the day, but that is one of the challenges we’ve had,” Muller said.

Jobs and energy affordability are important kitchen-table issues, he added, but they can be countered by images of dead dolphins on New Jersey beaches.

“We sometimes have a little bit of a harder argument on the support side, because we do have to explain some of the benefits,” Muller said.

Rosanna Maietta, American Clean Power’s chief communications officer, summed up in a sentence what Muller and many other speakers explained at much greater length:

“If you’re on defense, you’re losing — you’ve got to be on offense all the time.”

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WINDPOWER: Looking for Common Ground in the Water

ATLANTIC CITY, N.J. — The friction between the fishing and offshore wind industries was a recurring topic at Offshore WINDPOWER 2024, where multiple discussions examined approaches that have sought to smooth the relationship. 

One panel featured representatives of the two sectors along the southern New England coast. 

Moderator Ed Anthes-Washburn of Coast Line Transfers said the work of all four panelists intersected in New Bedford. He is a former director of the city’s port, which calls itself America’s most lucrative fishing center but also has become an important offshore wind hub. 

“Over the course of our tenure, I think we sort of stumbled into a really good model that we think really needs to be told,” he said. “It’s a great model of really early engagement, understanding the science and commercial opportunities for commercial fishermen.” 

In summary, the relationship eases some of fishers’ economic concerns by putting them to work at offshore wind construction sites as supporting players. 

These crews, with their extensive knowledge of local waters and the local maritime industries, are a great asset for solving or preventing problems. 

“It’s added value, because you have that local knowledge,” said Crista Bank, fisheries liaison for Vineyard Wind. “I can’t talk about how many times our scout vessel in Massachusetts was really key in our cable installation going off without a hitch, and it wouldn’t have happened without that.” 

Fishers can fish legally only so many days a year, and the extra income when their boats otherwise would be idle helps keep the fleet and workforce intact, panelists said. 

There are benefits on land, too. Panelist Michael Quinn of Shoreline Offshore is a second-generation scallop fisherman but also operates two onshore facilities with about 50 employees. He saw the increasing activity around offshore wind around 2018 and decided to be part of it. 

Several years later, his company fabricated a fender for the first crew transfer vessel at the Vineyard Wind work zone two weeks before cable work started. It is a small example, but one that can be replicated extensively. 

“In a lot of ways, local content is just content when you’re local, but engaging and knowing who that person is that can actually deliver something on time and quickly and high quality is really important,” Anthes-Washburn said. “And there’s a lot of folks in a lot of these ports up and down the East Coast that can be helpful.” 

James A. Morris Jr., NOAA | © RTO Insider LLC

New London, Conn., fisherman Mike Theiler said in the 2000s he visited a Northern Ireland port that had suffered the collapse of its fishing industry and diversified to other marine commerce in response. 

Theiler still fishes, but now also is managing director of Quintham, a software company focusing on fishing safety. 

“I lived through a fisheries disaster with the collapse of lobster stock in southern New England and the die-off of ’99 and it was a great opportunity for these fishermen to diversify,” he said. 

Bank said Vineyard has paid for 179 fishermen to go through the safety training or boat captain certification needed to operate at an offshore wind project and has paid for any safety upgrades needed to lift their boats above the standards for fishing vessels.  

Forty-five separate local vessels have worked on the projects, and they are not in competition, Bank said: They are put on a rotating schedule and paid equally. 

Vineyard Wind’s high-profile blade failure this summer gave an example of the economic and personal relationship that had formed between the developer and the local fishers. 

“When we all of a sudden needed some extra vessels on the waterfront to help to pick up some marine debris, our fishing vessels were the first ones out there,” Bank said. “Then I had phone calls from multiple other fishermen with different-sized vessels, like, ‘What do you need? Can I get out there? How can I help?’” 

“Crista is so well known on the waterfront,” Anthes-Washburn said. 

Then he turned to the elephant not in the room: Not every fisher has such a good relationship with offshore wind. Some are fighting it tooth and nail.  

Anthes-Washburn asked the panel: “Are fishermen who support offshore wind seen as traitors by other fishermen?” 

“That’s definitely something that you have to deal with,” Quinn said. “I would say I got a lot more flack in the beginning, before I was getting contracted out there and people working, because it’s easy to put something down that you’ve never seen happen.” 

He added: “I want to have a seat at the table and say, ‘How can we do this the right way together, and come up with a process that works for both sides, where we can all benefit long term?’” 

Gulf of Maine

Another panel looked farther north in New England, to the Gulf of Maine, where a lengthy process culminated in exclusion of key fishing areas for offshore wind leasing consideration, including Lobster Management Area 1. 

James A. Morris Jr., a NOAA ecologist, said the agency did something it had considered previously in other regions: It drew a model excluding every area where one stakeholder or another objected to wind power development. 

The entire Gulf map was colored red when they were done. 

“The point is that ultimately there will always be compromise, there’ll always be some, because there is no space in our coastal ocean that is free of conflict,” he said. “We’ve looked — that really doesn’t exist.” 

Close engagement, however, drills down on the motives and thinking behind opposition to wind turbines at particular sites. It can range from nowhere-no how-never to “just not where we fish,” Morris said. 

“Those are challenging conversations, and they’re not conversations that can happen fast. There’s a certain level of relationships that can be built, and trust has to be built.” 

windpower

Celina Cunningham, Maine Governor’s Energy Office | © RTO Insider LLC

Celina Cunningham, deputy director of the Maine Governor’s Energy Office, said those conversations and relationships can produce results. 

“There are plenty of people in the Gulf of Maine region who will never support offshore wind,” she said. “That’s fine; we expect that. There are a lot of people who do. And what I have learned from our work is that when you take the time and you share the data and you have those conversations, you can actually, I think, get some respect for the process.” 

Morris said a lingering problem is creating an accurate model of impacts to present to the fishing industry and other maritime stakeholders — regulatory and scientific agencies are using past data, hindcasting instead of forecasting. 

“We do not have available, accurate, defensible, high-quality data for future ocean conditions,” he said. “We have to invest more into future-casting of ocean conditions, ocean characteristics.” 

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FERC Rejects Expansion of Co-located Data Center at Susquehanna Nuclear Plant

FERC on Nov. 1 rejected a proposed amendment to Talen Energy’s interconnection service agreement (ISA) with PJM and PPL that would have allowed for the expansion of co-located load at its Susquehanna nuclear plant in Pennsylvania (ER24-2172).

The amendment would have let a 300-MW data center owned by Amazon Web Services — already operating behind the fence at the nuclear plant — expand from 300 MW to 480 MW. Controversy around the proposed expansion contributed to FERC hosting a technical conference on co-located load Nov. 1. (See related story, FERC Dives into Data Center Co-Location Debate at Technical Conference.)

The order was approved by only Commissioners Mark Christie and Lindsay See: Chair Willie Phillips dissented, while Commissioners David Rosner and Judy Chang did not participate. The majority found that the changes would have led to reliability concerns and novel legal issues. FERC can accept ISAs that do not conform with Order 2003, but parties filing such deals face a high legal burden to justify and explain that the changes are necessary, they said.

Many of the nonconforming provisions of the proposal relied heavily on the generally applicable PJM Guidance Document, which is not part of the RTO’s tariff, so FERC has not approved it, the majority said. In a footnote, the commissioners said they made no determination on whether the document is just and reasonable.

“This raises questions regarding whether PJM intends to offer these terms to all similarly situated interconnection customers,” FERC said. “We conclude that these provisions demonstrate that PJM has not met its burden to show that these provisions are necessary for any interest unique to the interconnection of the Susquehanna customer facility.”

The record indicates other data centers are considering similar deals with other nuclear plants, which shows the provisions from the document do not meet FERC’s standards for alternatives to Order 2003.

“This filing leaves multiple important questions unresolved,” FERC said. “Nevertheless, given that we have already found that PJM has failed to meet its burden, as described above, we need not further opine on whether PJM has met that burden with regard to the proposed nonconforming provisions herein, or otherwise address the amended ISA.”

Phillips argued that because the ISA is the first of its kind, it presents the sort of specific reliability concerns and novel legal issues that justify its acceptance.

“In failing to accept the agreement, we are rejecting protections that the interconnected transmission owner says will enhance reliability while also creating unnecessary roadblocks to an industry that is necessary for our national security,” Phillips wrote.

PJM showed that the extra 180 MW of demand would not require any transmission upgrades and the provisions included “several important, reliability-based belts and suspenders,” Phillips said. Those provisions would have ensured that no power flowed from the grid to the data center, provided generator shutdown and automatic tripping data to PPL, and notified PJM and PPL of equipment malfunctions.

Phillips also argued that failing to approve the amended deal puts national security at risk, as there is a clear bipartisan consensus that maintaining leadership in artificial intelligence is vital to the national interest.

“Maintaining our nation’s leadership in this ‘era-defining’ technology will require a massive and unprecedented investment in the data centers necessary to develop and operate those AI models,” Phillips wrote. “And make no mistake: Access to reliable electricity is the lifeblood of those data centers. I am deeply concerned that in failing to demonstrate regulatory leadership and flexibility, we are putting at risk our country’s pole position on this critically important issue. That is simply unacceptable.”

Data center co-location brings up a host of challenging, multifaceted issues that FERC will have to wrestle with, which is why it held the technical conference, Phillips wrote. “But the technical conference casts a far wider net than the matter that is before us today and was never intended to defer judgment on this application, which I believe has thoughtfully and creatively addressed the factors that justify approval of these nonconforming provisions. …

“We are on the cusp of a new phase in the energy transition, one that is characterized as much by soaring energy demand, due in large part to AI, as it is by rapid changes in the resource mix. Ensuring reliable and affordable supplies of electricity throughout the coming period of increasing demand and changing supply will require pragmatic leadership that facilitates that transition. If we instead throw up roadblocks to that transition, as I am concerned today’s order does, we will only deprive our country of the resources needed to ensure our continued economic prosperity and national security.”

In a concurrence, Commissioner Christie emphasized the rejection was without prejudice and that Phillips’ arguments about national security are unproven by the record before FERC.

He agreed that co-location arrangements present complicated issues that could have huge impacts on reliability and consumer costs, which is why FERC held its technical conference.

“Given these ramifications, the commission truly needs to ‘get it right’ when it comes to evaluating co-location issues,” Christie said. “And make no mistake. Were we to approve this proposal at this time, as the dissent advocates, we would be setting a precedent that would be used to justify identical or similar arrangements in future cases.”

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SPP Board Approves $7.65B ITP, Delays Contentious Issue

LITTLE ROCK, Ark. — SPP’s Board of Directors has approved the grid operator’s “historic” $7.65 billion package of transmission projects but delayed a decision on a need date for two of the 89 projects after stakeholders pushed back on staff’s staging recommendations. 

Stakeholders argued that the two projects in question be staged as soon as possible, with two working groups voting to classify winter-weather projects as persistent operational solutions in approving winter-weather need dates. 

Staff recommended using analysis and staging methodology consistent with the tariff and transmission planning manual. They added a Year 2 winter-storm model late in the planning process to calculate December 2028 need dates for the two projects. 

Following more than three hours of discussion over two days among themselves and with staff and stakeholders, the directors on Oct. 29 took a Solomonic approach by agreeing to delay a decision on the projects’ need dates to no later than their Dec. 9 board meeting. They rejected the original proposal to set the deadline before their February meeting. 

Until then, stakeholders will continue the staging discussion in the working groups. The Markets and Operations Policy Committee (MOPC), which endorsed the 2024 Integrated Transmission Plan (ITP) with 95% approval, also plans to hold a conference call before the December board meeting. 

Evergy’s Derek Brown, chair of the Transmission Working Group, said the disconnect between staff and stakeholders emerged over the projects’ need dates. That led stakeholders to endorse the larger projects that make up much of the transmission package’s size. 

“We have the models and the inputs, and we spent months building those to support the justification for when these projects are needed … and that got us to the five-year model,” he told directors and stakeholders. “We have projects coming in service. We have load growing. We have generation retiring. We need to look out at least five years to be able to right-size the solutions. So, when we looked at that five-year model, surprise! Things get worse. 

“At least from a transmission planning standpoint, all those projects are part of the packaged solution, so they should all have need dates as soon as possible. If the system had shown things get better in Year 5 and we don’t need all of those projects, we wouldn’t be recommending them today.” 

“Nothing’s ever easy, and it probably shouldn’t be with this large of a portfolio,” said SPP’s Casey Cathey, vice president of engineering. He noted that the Integrated Transmission Planning (ITP) manual does not have processes for creating historical winter weather models or to determine a need date for projects from past events. 

Because staff’s winter-weather models were based on previous extreme conditions during February 2021 and December 2022, stakeholders voted to stage projects as persistent operational projects.  

“It became apparent about two months ago that not only is the winter-weather staging not outlined in the manual … but it’s not easily defendable when you look at the governing language,” Cathey said, pointing to multiple sections in the manual and tariff. “If you map all of that, you have to use a Year 2 model to interpolate and determine what the staging needs are.” 

The two projects in question are the Tobias-Elm Creek 345-kV transmission line on the western side of SPP’s footprint, an 85-mile segment valued at $887.46 million, and the 154-mile, $484.09 million Buffalo Gap-Delaware 345-kV line from Kansas into Southwest Missouri. The projects were identified in the Winter Storm Uri and Elliott models, respectively. 

The first project is expected to increase transfer capability from SPP North to SPP South and decrease the chances for load shed. The second brings a new EHV source into Missouri to support system voltage and transfers from SPP. 

Three other projects related to the winter storm projects were given need dates of December 2025 or upon being issued a notification to construct. 

The 2024 ITP portfolio is SPP’s largest in both size and value in its 20 years as a transmission planning coordinator, it said. The plan includes 89 transmission projects, representing 2,333 miles of new transmission and 495 miles of rebuilds — including 1,900 miles of the RTO’s first 765-kV lines — to address increasing load growth and changes in the region’s generating fleet. SPP expects the portfolio’s benefits to exceed costs by a ratio of at least 8-to-1. 

Despite the package’s cost, MOPC approved the ITP with 95% approval and little discussion of staging. The issue has since bubbled up in the working groups. (See SPP Stakeholders Endorse Record $7.65B Tx Plan.) 

The Members Committee approved the board’s motion to delay the staging date for the two projects in their advisory vote, 17-5 with one abstention, with renewable interests providing the opposed votes. They also cast four votes against the portfolio’s approval, expressing concern over the lack of transparency into delayed projects. 

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WINDPOWER: Equinor Exec Gives Insight on Empire Wind

ATLANTIC CITY, N.J. — The company planning an 810-MW wind farm off the New York coast gave an update on its projects at Offshore WINDPOWER 2024. 

The annual conference staged by American Clean Power offered a snapshot of the young U.S. offshore wind industry, from its setbacks to its triumphs to the potentially major challenges the upcoming presidential election could present. 

Equinor’s Empire Wind can be seen as a microcosm of these fluctuations — it benefited from strong state and federal support, received key federal approvals, won a state Offshore Wind Renewable Energy Certificate (OREC) contract for both of its phases, saw that contract become financially untenable, severed the Equinor-bp joint venture behind Empire, put Phase 2 on hold and won a replacement contract for Phase 1 at a much higher $155/MWh. 

Notably, Equinor has begun construction of what may be the most visible piece of offshore infrastructure in the nation: an offshore wind hub on the New York City waterfront. 

Molly Morris, Equinor’s president of Renewables Americas, sat down with American Clean Power CEO Jason Grumet for an update. 

“The South Brooklyn Marine Terminal is a 73-acre piece of land right in the heart of Brooklyn. It has the most amazing view of the Manhattan skyline,” she said. “About 63 acres of the land is what we call our staging port. So this is where we will house all the components for our turbines.” 

equinor

American Clean Power CEO Jason Grumet listens to Equinor President Renewables American Molly Morris at ACP’s Offshore WINDPOWER 2024 in Atlantic City, N.J., on Oct. 30. | © RTO Insider LLC 

Grumet noted that transitions such as the one underway in the energy industry are exhilarating at the start and satisfying at the end. It is the middle that can be hard.  

Morris did not disagree. 

“I will say that the last few years have been the hardest of my career — this has been an incredible journey over the last 24 months,” she said. “We hopefully have seen the inflection point and [are] starting to really see improvements. We see it a bit in the economics, although it’s still very challenging. So I don’t want to paint too rosy a picture.” 

The new OREC contract was key, Morris said. “That gave us that launching pad, and really since then, it’s been full speed ahead.” 

Grumet asked about the dichotomy within Equinor — it has been an offshore wind developer for 15 years but has been a major offshore producer of oil and natural gas for much longer. It plans to expand fossil production over the next decade and is “recalibrating” its portfolio of early-phase renewables to cut costs.  

Morris herself spent more than 20 years in oil and gas, most of it with Equinor. She said the company has a strong commitment to offshore wind but also sees a decadeslong need for fossil fuel. 

“We’re really trying to transition into what we call a broad energy company,” Morris said. “So we’re expanding into low-carbon solutions, which is hydrogen, carbon capture and storage, and, of course, renewables.” 

Grumet noted the optics of this. 

“There are certainly some advocates who don’t like the fact that companies with fossil histories are actually leading the clean energy transition,” he said. 

“We have people within our own company that don’t love that we’re trying to build renewables, and that’s OK,” Morris replied. “We also have people who work in renewables that don’t like that.”   

Grumet also noted the value that experienced, well-capitalized companies (such as oil majors) can bring to a new power sector. 

“We love to build very complicated things offshore, and this is what we have done for decades,” Morris said. “So we’re trying to use that strength that we have and bringing that into the offshore wind space.” 

Grumet asked how Equinor’s early offshore wind efforts overseas 15 years ago compared to its attempt to get up and running in the United States. 

“Of course, with any new industry, you’re going to have challenges,” Morris said.  

“There are some fundamental differences between Europe and the U.S. in terms of transmission and points of interconnection, so that is slightly different. I will say, though, the project director that we have for the Empire Wind project, he is a Norwegian, very experienced project director, and he always says to me, ‘There’s the U.S. factor that does make things more challenging.’ And again, I think it’s just being in a new industry that needs to work through the kinks.” 

Grumet noted the impending potential for a “careening federal political environment” and asked Morris for her assessment of state politics. 

“Overall? Very positive,” she said. “You know, the states really are who are driving offshore wind right now. They’re the ones that are putting solicitations up. They’re the ones setting climate targets. We have a very strong partnership with New York state, where we have our offtake for the Empire project. 

“It hasn’t been easy on either side, but there’s very strong commitment from New York, from New Jersey, the entire East Coast, and I think that has been critical.” 

An Equinor spokesperson said later via email that Empire Wind 1 has been sanctioned internally and a final investment decision is expected this year, after financing is finalized. Equinor also is seeking a partner to replace bp. 

The Brooklyn project already is in progress and is a major undertaking. Equinor has not publicized its budget, but Skanska, the construction manager, has said its contract alone totals $861 million. More than 1,000 people have worked on the site in the past six months of construction. 

Preparatory work has begun there for Empire Wind’s point of interconnection, and most work on the port itself is expected to be complete by the first quarter of 2026 — in time to receive the first shipment of turbines from Vestas and perform pre-assembly work in preparation for their installation offshore starting in the summer of 2026. 

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NM PRC Issues ‘Guiding Principles’ for Electricity Market Participation

As New Mexico utilities prepare to choose either CAISO’s Extended Day-Ahead Market (EDAM) or SPP’s Markets+, the state’s Public Regulation Commission has issued a set of principles intended to guide their decision. 

The commission voted 3-0 on Oct. 31 to adopt the guiding principles, which emphasize customer benefits, transparency, stakeholder involvement and tracking of greenhouse gas emissions. 

The guiding principles — which apply to Public Service Co. of New Mexico (PNM) and El Paso Electric Co. (EPE) — are advice rather than a mandate for steps to take in choosing a day-ahead market. And they don’t preclude PNM from making a market choice this quarter, as the utility has said it intends to do, commissioners said. 

“To be clear, there are no requirements in this document,” Commissioner Gabriel Aguilera said. “And there’s nothing in this document that stops PNM from announcing a decision.” 

EPE has said it hopes to make a day-ahead market decision by the third quarter of 2025. 

Some parties had recommended that the commission conduct a rulemaking to establish a process and requirements for market participation. Commissioners opted not to do so, saying they didn’t want to create barriers to PNM making a day-ahead market decision this year. Rulemaking is still an option for the future, the commission said. 

5 Principles

The first of the commission’s five guiding principles is that the primary driver of any market decision must be customer benefits, with economic and reliability benefits as a priority.  

The commission provided a list of factors to use in determining whether a particular market decision will benefit customers. Those include the market’s expected footprint, its governance, and the cost and ease of market entry and exit. 

Other factors are how transmission rights and congestion costs would be handled, and whether EDAM, Markets+ or the status quo show the best results in a cost-benefit analysis. 

In the second principle, the commission said a utility’s market participation should allow for sufficient tracking and reporting of greenhouse gas emissions to demonstrate compliance with the state’s Energy Transition Act. 

Thirdly, the commission said, the day-ahead market should have a fair and transparent decision-making process that “facilitates diverse and meaningful stakeholder engagement and considers stakeholder input fairly.” 

A fourth principle states that a utility’s decision to join a regional market should include stakeholder input. The utility should make the study assumptions and results it is relying on available to regulators and stakeholders. 

In the final principle, the commission asked utilities to provide updates on their market participation, including any major changes to the market and opportunities for stakeholder involvement.  

After a utility has joined a day-ahead market, the commission would like quarterly reports for the first two years and annual reports thereafter. 

Yearlong Process

Adoption of the guiding principles comes after the PRC opened a docket in August 2023 to examine factors PNM and EPE should consider when deciding whether to participate in a regional day-ahead market or RTO.  

The commission held a series of workshops to discuss market participation. During an Aug. 29 workshop, The Brattle Group presented results of a study conducted for PNM and EPE, showing the utilities’ projected benefits from joining either EDAM or Markets+.  

The study modeled a scenario in which three Arizona utilities — Arizona Public Service, Salt River Project and Tucson Electric Power — join Markets+. 

Even with the Arizona utilities in Markets+, projected annual benefits for PNM would be $20.5 million if it joined EDAM, compared with $8 million from participating in Markets+. For EPE, projected benefits were $19.1 million a year for EDAM versus $9.1 million for Markets+. (See Brattle New Mexico Study Shows EDAM Benefits Outpacing Markets+.) 

Aguilera, who led the proceeding, said the process leading to the guiding principles had been successful in creating a forum where utilities, commissioners and stakeholders could learn what each other was thinking in terms of regionalization. 

“The last thing that I wanted was a surprise filing or unexpected press release from the utilities announcing they are joining ‘X’ day-ahead market,” he said. 

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Entergy CEO: Nuclear, Carbon Capture in Equation to Handle Industrial Growth

Entergy CEO Drew Marsh said the utility’s third quarter contained yet more prep work for large industrial customers and development for carbon capture alongside more nuclear and solar generation.    

Marsh estimated Entergy’s compound annual growth rate in industrial sales at 11 to 12%, 300 basis points higher due to a large new industrial customer that recently signed a 15-year electric service agreement with Entergy Louisiana.  

“We don’t disclose specific customer details without their consent, so we can’t provide additional information at this time,” Marsh said during an Oct. 31 earnings call.  

Marsh said the major customer will bring economic activity to a portion of northern Louisiana “that has been economically disadvantaged for decades.”  

Although no docket in the case is available yet at the Louisiana Public Service Commission, Entergy has shared a redacted version of its application for approval of generation and transmission to host an “economically transformative” $5 billion investment the unnamed customer is looking to site in Richland Parish. The utility hopes to build three new combined cycle combustion turbines and a 500-kV line.  

Entergy reported third-quarter earnings of $2.99/share and third-quarter net income of $644.9 million, down year-over-year due to 2023’s exceptionally hot summer in the South.  

However, Marsh said Entergy had a “very productive quarter” marked by higher industrial sales and growing demand for clean energy. 

Marsh said other large industrial customers increasingly are looking to Entergy for zero-carbon energy offerings.  

“Collectively, this means that our preliminary capital plan through 2028 is $7 billion higher than on Analysts’ Day, driven by new transmission as well as incremental new generation investment, including renewables,” he said. 

At Entergy’s annual Analysts’ Day in June, the utility announced a $33 billion, five-year capital plan.  

Marsh noted that Entergy Arkansas’ 100-MW Walnut Bend Solar farm, built in partnership with Invenergy, was placed in service during the quarter, and Entergy Arkansas also closed on its 180-MW West Memphis Solar and 250-MW Driver Solar facilities.  

Marsh said Entergy now has nearly 800 MW of solar resources in service and close to 2.6 GW of solar projects “in process, approved or under regulatory review.”  

Marsh said Entergy plans to build even more customer-driven renewable energy sources, mentioning Entergy Louisiana’s request for proposals to acquire 3 GW of new solar. 

He also noted that Entergy Mississippi announced plans this quarter to build a 750-MW dual-fuel, combined cycle plant, its first new natural gas power station in 50 years. He said the plant will be hydrogen ready and designed to be outfitted eventually with carbon capture technology.  

Marsh said Entergy is gearing up for carbon capture and storage (CCS) to take a role in the clean energy transition and is in “active discussions with customers about “a variety” of low-carbon generation solutions, including carbon capture.  

Marsh said Entergy Louisiana continues its front-end engineering and design study to evaluate the technical and financial feasibility of installing carbon capture at the Lake Charles Power Station, with the company enlisting the help of Crescent Midstream.  

“Once completed, the learnings from this work will benefit future CCS projects. Ultimately, we believe CCS is a critical technology to comply with eventual federal emissions requirements, to help our customers meet their decarbonization objectives and for us to achieve our 2050 net-zero commitment,” Marsh said.  

Marsh indicated Entergy is ready to partake in the nuclear revival taking hold in the country.  

Entergy believes nuclear power will factor heavily in its path to net-zero emissions by 2050 and is “well-positioned to evaluate and ultimately pursue new nuclear options,” Marsh said.  

Marsh said Entergy is actively exploring potential nuclear plant uprate projects that could add as much as 300 MW in capacity at the utility’s Arkansas and Louisiana nuclear plants. 

Marsh also brought up that Entergy since 2007 has held an early site permit from the Nuclear Regulatory Commission for a potential new reactor at its Grand Gulf nuclear site and invoked the utility’s memorandum of understanding with Holtec International to evaluate small modular reactors.  

During the past quarter, the Louisiana Public Service Commission unanimously approved a $95 million settlement with Grand Gulf owner and Entergy subsidiary System Energy Resources to resolve all complaints related to Grand Gulf’s past performance lags. It also unanimously approved an agreement to divest Entergy Louisiana’s share of Grand Gulf energy and capacity to Entergy Mississippi. (See Entergy Touts Louisiana Settlements, Beryl Response in Q2 Earnings.)  

Entergy has submitted additional filings to the Mississippi Public Service Commission and FERC to approve the divestiture. 

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BPA Sticks to Markets+ Leaning Despite Study Showing EDAM Benefits

New findings from a much-anticipated study have “not shifted” Bonneville Power Administration staff’s recommendation that the agency choose SPP’s Markets+ over CAISO’s Extended Day-Ahead Market (EDAM), BPA said Oct. 31 — despite results showing greater financial benefits from EDAM.

“Right now, the economic analysis from production cost model studies leans toward EDAM and the additional analysis from E3 [Energy and Environmental Economics] provides more context and nuance that will be factored into our final decision,” Rachel Dibble, BPA vice president of bulk marketing, said in a press release announcing publication of the study, which is posted on the agency’s website.

Release of the E3 analysis comes three weeks after The Brattle Group published a study — not commissioned by BPA — estimating that, by 2032, the agency would earn $65 million in benefits from participating in EDAM versus an $83 million net loss in Markets+. (See Brattle Study Finds EDAM Gains, Markets+ Losses for BPA, Pacific NW.)

“We continue to believe Markets+ is a superior market design for Bonneville and our customers, which includes a truly independent governance model,” Dibble said, reemphasizing a point agency staff made in issuing its “leaning” in favor of the SPP market in April. (See BPA Staff Recommends Markets+ over EDAM.)

Dibble said BPA “understands the gravity” of its day-ahead market decision “and remains committed to an open and transparent evaluation of market options.”

BPA plans to discuss the results during its Nov. 4 day-ahead market participation workshop, the first such meeting since announcing it would delay its market decision until 2025 and since the resignation of the executive leading its day-ahead efforts, former Director of Market Initiatives Russ Mantifel. (See BPA Markets+ Support Intact Despite Exec’s Resignation, Agency Says.)

The new study consists of “supplemental production cost modeling analysis and sensitivities of cost benefit results regarding BPA’s potential participation” in either market, BPA said in its release.

The analysis builds on the 2023 Western Markets Exploratory Group (WMEG) study E3 performed for BPA last year. (See Study Shows Uneven Benefits for California, Rest of West in Single Market.)

The 2023 study offered a mixed picture, with BPA expected to incur financial losses compared with the status quo from participating in either market due to an expected sharp reduction in wheeling revenues. BPA questioned that finding, contending that most of those revenues derive from long-term contracts likely to be maintained for the foreseeable future. By restoring those wheeling revenues into the study’s modeling, BPA found it would realize gains from participating in either market and that its net benefits from EDAM would exceed those in Markets+ by nearly $106 million annually.

Supplemental Scenarios

The 2023 WMEG study for BPA examined two scenarios, including an “EDAM Bookend” case in which the entire West participates in the EDAM, and a “Main Split Footprint” scenario, which assumed EDAM membership for only PacifiCorp, Los Angeles Department of Water and Power, Balancing Authority of Northern California, Turlock Irrigation District and Imperial Irrigation District, with the rest of the West joining SPP’s Markets+. Both scenarios were measured against a “Business as Usual” (BAU) case in which CAISO’s Western Energy Imbalance Market retains its current membership and day-ahead trading in the West outside CAISO continues to occur in the bilateral market.

A presentation prepared by E3 for BPA’s Nov. 4 workshop shows the new supplemental study retains the BAU and Main Split cases, while the EDAM Bookend case is renamed “Westwide Market” and refers to a scenario in which nearly all of the Western Interconnection, excluding British Columbia and Alberta, participates in a single, unspecified market.

The supplemental also includes three other scenarios:

  • “Alt Split 2NV,” in which the EDAM includes California, NV Energy, PacifiCorp and the entire Pacific Northwest, including BPA.
  • “Alt Split 4A,” in which the EDAM includes California, NV Energy, PacifiCorp, Portland General Electric, Seattle City Light and Idaho Power, all of which either have committed to or are likely to join the CAISO market.
  • “Non-CA Westwide M+,” in which only California entities participated in EDAM while the rest of the West joins Markets+.

The study estimates BPA’s benefits under each scenario for 2026, 2030 and 2035.

In its press release, BPA said the analysis shows “a wide range of outcomes, with results pointing to Markets+ providing lower load costs and EDAM providing greater generation revenue potential driven by higher prices.”

The agency said the results show “EDAM having greater volatility in benefits than Markets+, although most scenarios still pointed to EDAM having the greatest generation revenue potential. The results also show market benefits declining for both markets in future timeframes, with EDAM depicting a greater decline in benefits, but still maintaining more net benefits than Markets+.”

Slide 18 in the E3 presentation plots out those findings, showing that under the Westwide Market scenario, BPA would realize $251 million in net benefits in 2026, declining to $192 million in 2030 and to $147 million in 2035.

Under the Alt Split 2NV scenario, BPA would earn net benefits of $196 million in 2026, falling to $169 million in 2030, but returning to close to the 2026 level in 2035.

The Non-CA Westwide M+ scenario shows BPA realizing $207 million in benefits in 2026, $182 million in 2030 and $177 million in 2035, although that scenario is unlikely given utilities’ existing and tentative commitments to EDAM.

BPA’s worst outcomes occur in the Alt Split 4A scenario, in which it would see $30 million in benefits in 2026, but incur $23 million and $28 million in costs, respectively, by 2030 and 2035.

The study also includes sensitivity cases for each scenario in 2026 to estimate benefits under “dry hydro” and “stress load” conditions.

“Dry hydro regional conditions reduce quantity of generation that BPA has to sell but increases regional prices; BPA net costs are least sensitive to these changes in Alt 4A,” E3 notes in its presentation.

E3 said also stress load conditions are applied for only two weeks a year and have only “modest impact” for BPA’s net annual costs, although estimated prices “may not reflect full potential scarcity conditions.”

Other sensitivity cases cover improved market-to-market (M2M) coordination between EDAM and Markets+ over time and increased transmission availability between the Northwest and Southwest in the future.

“The results provide BPA with another data point in its day-ahead market decision and will be shared at a Nov. 4 workshop,” BPA said. “Other factors the agency is evaluating include governance, attribution of greenhouse gas emissions to the federal system, statutes and reliability.”

Initial Reactions

Michael Linn, director of market analytics for the Public Power Council (PPC), which has urged BPA to join Markets+, told RTO Insider that while the PPC still is reviewing results of the supplemental analysis, its “preliminary view” is that BPA’s participation in a day-ahead market will provide benefits to the agency’s customer base of publicly owned utilities.

Linn said the various scenarios show “the production cost benefits to BPA can vary wildly depending on a range of assumptions.”

“Varying market footprints and hurdle rates appear to show a two-market footprint with BPA in Markets+ can produce benefits at levels similar to BPA participating in EDAM,” he said. “These results reinforce PPC’s perspective that while production cost studies are important and show directional benefits of day-ahead market participation, when determining the best path for BPA and preference customers, it is equally important to place significant emphasis on real-world differences in market design and governance that have real impacts but may not be readily quantified or reflected in production cost studies.”

Seattle City Light (SCL), which largely has been alone amongst Northwest publicly owned utilities in urging BPA to join EDAM, had a different take.

“BPA has a fiduciary obligation to carefully weigh the variables and impacts to its customers before making any market decision,” an SCL spokesperson said in an email. “BPA’s own analysis shows that Markets+ is $221M in fewer benefits for BPA and its customers. BPA’s statement that the updated E3 results have not shifted its recommendation to join Markets+ indicates that customer benefits impacts are not an important consideration in its [day-ahead market] decision.”

The spokesperson said SCL, which operates its own balancing authority area, has yet to decide on a day-ahead market and will make a choice only after receiving its own benefits study results from The Brattle Group later this year.