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November 14, 2024

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Gulf of Maine OSW Auction Results in Four Leases Worth $21.9M

The first-ever offshore wind lease auction for the Gulf of Maine resulted in the sale of four offshore lease areas to two developers, bringing in a total of about $21.9 million.

The auction offered eight lease areas in total, with the potential to provide 13 GW of power. (See BOEM Announces Gulf of Maine Offshore Wind Lease Sale.) The four sold lease areas could host enough offshore wind generation to power 2.3 million homes, the U.S. Department of the Interior said in the Oct. 29 announcement.

Avangrid Renewables and Invenergy NE Offshore Wind each provisionally won two lease areas, which range in size from 97,854 acres to 124,897 acres.

Avangrid CEO Pedro Azagra said the company’s leases provide for the potential development of about 3 GW of floating offshore wind.

“Securing these lease areas provides a unique opportunity to advance our growing business at a significant value and reinforces our unwavering commitment to helping the New England region meet its growing need for reliable, clean energy,” Azagra said.

“With today’s lease sale building on earlier deepwater auctions on the West Coast, the United States is truly on track to become a global leader in floating offshore wind technology,” said Anne Reynolds, vice president for offshore wind at American Clean Power.

While all commercial offshore wind farms currently under construction or in operation in the U.S. feature fixed-foundation technology, farms developed in the deeper waters in the Gulf of Maine will need to rely on floating technology.

Although floating offshore wind technology is in its early stages — the world’s largest floating installation has an 88-MW nameplate capacity — its development will be key to meeting state and federal clean energy goals, due to the limited availability of viable fixed-bottom locations.

The U.S. Bureau of Ocean Energy Management (BOEM) in August approved a floating wind research lease for the state of Maine, which eventually could provide the state with 144 MW of offshore wind. (See Maine Approved for Floating Wind Research Lease.)

The $21.9-million price tag is significantly less than BOEM’s 2022 California lease sale, which also was centered around floating technology. The California leases, which cover a smaller overall footprint than the Gulf of Maine leases, brought in $757 million. (See First West Coast Offshore Wind Auction Fetches $757M.)

The offshore wind industry’s struggles to scale up over the past two years may have cooled bidder interest in new lease areas. An Oregon offshore wind lease auction scheduled for Oct. 15 was postponed due to a lack of interest from potential bidders, while BOEM canceled a Gulf of Mexico auction planned for September. (See BOEM Postpones Oregon Offshore Wind Auction and BOEM Cancels Gulf of Mexico Wind Lease Auction.)

Avangrid’s lease areas (OCS-564 and OCS-568) are located about 34 miles from Massachusetts and feature “strong wind speeds” along with “relatively shallow waters within the limits of existing floating wind technology” and multiple potential interconnection points, Avangrid said.

While Avangrid’s lease areas are located adjacent to each other east of Massachusetts, Invenergy’s lease areas bookend the northeast and southeast corners of the wind energy area. Invenergy’s southern lease (OCS-567) is located about 25 miles east of Massachusetts, while its northern lease (OCS-562) is located southeast of Portland, Maine, about 53 miles offshore.

Reynolds specifically praised Maine Gov. Janet Mills (D) for the state’s “proactive approach to floating offshore wind technology.”

In 2023, Maine passed legislation (LD 1895) authorizing the procurement of at least 3,000 MW of offshore wind power “in proximate federal waters” by the end of 2040. The law directs the Governor’s Energy Office to submit its first solicitation to the Public Utilities Commission by July 2025, with the PUC set to issue a request for proposals in January 2026.

Massachusetts also is well located to purchase power from the Gulf of Maine areas, and the state has indicated it will need to procure at least 10 GW of power from offshore wind in the Gulf of Maine to meet its climate targets.

Developers recently broke ground on a new offshore wind terminal in the city of Salem, Massachusetts, which is located in relatively close proximity to the southern Gulf of Maine lease areas. (See Mass. Breaks Ground on Salem Offshore Wind Terminal.)

The availability of future leases in the area could be affected by the outcome of the presidential election in November, as Republican nominee Donald Trump has expressed hostility toward offshore wind. The Department of the Interior has another lease auction scheduled for the Gulf of Maine in 2028.

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Federal Judge Tosses Out Texas’ ROFR Law in Non-ERCOT Regions

A federal judge found Texas’ law instituting a state right of first refusal (ROFR) law violates the Commerce Clause and prohibited its enforcement in non-ERCOT regions, in an order issued Oct. 28. 

Judge Robert Pitman of the U.S. District Court for the Western District of Texas in Austin handed down the ruling on remand from the 5th U.S. Circuit Court of Appeals in the case of NextEra Energy Capital Holdings v. Kathleen Jackson in her official capacity as a commissioner of the Public Utility Commission of Texas. (See 5th Circuit Finds in Favor of NextEra’s ROFR Appeal.) 

The 5th Circuit decision also was appealed to the Supreme Court, which declined to take up the case in December 2023. (See SCOTUS Won’t Take up Texas Appeal of ROFR Law.) 

The Texas Legislature passed SB 1938 after FERC Order 1000 removed federal ROFRs but required ISO/RTOs such as MISO and SPP, which serve the parts of Texas in the Eastern Interconnection, to respect state ROFR laws. 

The law caused NextEra to lose a transmission project in East Texas that it had won in MISO’s competitive planning process and another project it had tried to buy from an incumbent in SPP’s territory.  

The Commerce Clause of the U.S. Constitution gives the federal government the power to regulate interstate commerce. State laws can get around it if they have legitimate policy reasons. But the judge knocked down all the arguments ROFR supporters brought up in the case. 

Texas claimed the law codified existing practices. But NextEra was able to build in the state prior to enactment of the ROFR law, as it did in the Competitive Renewable Energy Zone law. Another justification was to clean up statutory language after the CREZ lines were opened to out-of-state firms. The judge found that was not a valid reason to get around the Commerce Clause. 

Texas also wanted to avoid federal rate regulation, but the judge shot down that reasoning. 

“Balkanizing a state from interstate commerce is the very problem the Commerce Clause is meant to guard against … and so Texas’ desire to avoid the interstate market — and the federal regulation that comes with it — is not a legitimate local interest,” the court ruling said. 

The final reason was an alleged impact to reliability because the competitive bidding process adds time to transmission development. But SPP transmission lines that are needed quickly can get around the competitive process. And MISO does not have a competitive process for lines that are needed solely for reliability. 

“The federal bidding process does not undermine reliability by substantially delaying projects because these projects already take years to plan,” the court ruling said. “The type of transmission lines defendants are concerned about are proposed through federal regional planning bodies to promote long-term transmission development. Even without a competitive bidding process, the procedure for identifying those types of regionally planned transmission lines is time consuming.” 

Texas can ensure reliability with the PUC’s certificate process, and the regulator continues to have authority when lines are in service to ensure they are operated reliably, the judge said. 

“If those processes are insufficient to ensure reliability, then Texas could enact new laws that add reliability mandates,” the decision said. “The constitutional solution to Texas’ issue of ensuring reliability is to evenhandedly increase reliability standards, not to treat all out-of-state entities as necessarily unreliable.”

When it comes to competitive processes, FERC requires transmission planners to consider reliability. MISO found NextEra’s proposal for the Hartburg-Sabine project had adequate plans and infrastructure in place to ensure reliable operation. NextEra has a pending case before the D.C. Circuit Court of Appeals to try to get that project back, though MISO and FERC have since said it is no longer needed. 

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EPRI Launches DCFlex Initiative to Help Integrate Data Centers on the Grid

The Electric Power Research Institute has launched its “DCFlex” initiative that will explore how data centers can support the grid, enable better asset use and support the clean energy transition.

The initiative’s founding members include Compass Datacenters, Constellation Energy, Duke Energy, ERCOT, Google, Meta, New York Power Authority, NRG Energy, NVIDIA, Pacific Gas and Electric, PJM Interconnection, Portland General Electric, QTS Data Centers, Southern Company and Vistra.

DCFlex will coordinate real-world demonstrations of flexibility in a variety of existing and planned data centers and electricity markets, creating reference architectures and providing shared learnings to enable broader adoption of flexible operations that benefit consumers.

The EPRI initiative announced Oct. 29 will set up five to 10 flexibility hubs, demonstrating strategies that enable operational and deployment flexibility, streamline grid integration and transition backup power solutions to grid assets. Demonstration deployment will start in the first half of 2025 with testing running through 2027.

“One of the key areas where people are talking a lot, but not doing a lot, is the area of understanding how flexible data centers can be, and how we actually make that happen,” EPRI’s Principal Technical Executive Tom Wilson said in an interview. “And so that was the motivation.”

EPRI is a nonprofit that works to address challenges in the energy industry. The DCFlex initiative was born out of discussions at the U.S. Secretary of Energy’s Advisory Board about how it could help power data centers. EPRI spoke with 50 experts from the power industry and the data center industry, Wilson said.

Data centers can respond to signals in the grid in two ways — some of their computational tasks can be shifted around in time and to other data centers, and backup power generation at the facilities can be used instead of the grid, Wilson said. Diesel generation dominates their backup power now, but cleaner options more regularly could respond to grid signals without violating state air permits.

“In terms of computational flexibility, I’d say, you know, if you’re at an ATM trying to get money out, and you get the answer that you can’t get your cash until the electricity prices are lower or there’s more electricity available, you won’t be happy,” Wilson said. “And so, there are a lot of functions of data centers that you do have to have real time. Basically the customer-facing things that data centers do. Other things like indexing the web and activities like that are potentially more flexible in where they occur and when they occur.”

The customer-facing aspects of artificial intelligence also need to be ready for use whenever, but AI models require training, and that energy-intensive process can be shifted in time, Wilson said.

Google, for example, has shifted computing demand to where cheap, clean power is available at its different data centers for the past five years, he added.

“At Google, we see this moment as a generational opportunity for the public and private sector to work together to meet energy demand responsibly and unlock significant benefits for people, the economy and the planet,” Google’s Global Head of Energy Market Development and Innovation Caroline Golin said in a statement. “Through the leadership, expertise and convening power of EPRI, DCFlex will be an important collaboration vehicle to align our common goals, as we work together to build a stronger electrical grid for all.”

Data centers have helped transform the demand for power. The U.S. had flat growth for roughly two decades, but with data centers being added in the hundreds of megawatts, reshoring of industry and efforts to electrify other uses of energy, that has changed dramatically in the past year, Wilson said.

It used to be easy to plug a data center into the grid, but the growing demand has slowed the process. In 2022, Dominion put a moratorium on new connections in its territory, which includes the largest concentration of data centers in the world, called Data Center Alley in Loudon County, Va., Wilson said.

A 500-MW data center is equivalent to tens of thousands of homes being added to the grid much more quickly than more granular demand growth from an expanding population or a growing economy. Flexibility can help the grid absorb major new loads more quickly.

“In many cases, if you have transmission issues, it may just be that I can provide the power you want for 350 days a year,” Wilson said. “For 15, I can’t guarantee it for every hour in those days because of congestion, peak temperatures or higher, low — different issues. And if you have that response, is there a way to get around providing that powerful 15 days for the data centers in order to connect it now?”

When it comes to data flexibility, being able to dial back the demand from a 500-MW data center offers a significant source of demand response for the grid, he added.

“Or if it’s able to turn on backup generation and take its load entirely off the grid, that’s a huge amount of capacity that can come online,” Wilson said. “Historically, we’ve seen this with aluminum smelters and other large industry right where they’ve traditionally gotten a phone call that said, ‘can you guys turn off these hours, these days?’”

Another key is better planning around when and where data centers want to connect to the grid, said Wilson. It takes time to stand up a new data center.

“Better coordinating those ramp up schedules is really important for an understanding where both parties really are in terms of their needs and ability to respond,” Wilson said. “Because, you know, if you’re talking a gigawatt data center or 500-MW data center that’s a large amount of load, and it can be in over eight years or three years or two years. It makes a big difference.”

Constellation, which has worked with Microsoft to reopen a Three Mile Island nuclear plant to serve a Microsoft data center and has discussed co-locating data centers at its other nuclear plants, welcomed EPRI’s initiative.

“Data centers are integral to our daily lives, economy and national security,” Constellation CEO Joe Dominguez said in a statement. “Our energy system is built to handle the extreme demands of our hottest summer days and coldest winter nights but is often underutilized. The real challenge isn’t a lack of energy for data centers but managing the peak demand hours. The ability of data centers to flex during these critical periods is crucial.”

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MISO and TVA Strike Emergency Energy Purchase Agreement, Request FERC OK

MISO and the Tennessee Valley Authority hope to implement an emergency energy purchase framework by Christmas Eve.  

The two have filed an agreement before FERC for permission to be able to transact energy with one another during emergencies by Dec. 24 (ER25-197).  

MISO and TVA have never had an agreement to mutually supply the other with emergency power, and they said they traditionally had “other arrangements” that seemed sufficient to meet the needs of their regions.  

However, the two said the late December 2022 winter storm changed their views. 

“Due to the changing configuration of the grid and recent emergency events, like Winter Storm Elliott, MISO and TVA have become increasingly focused on the need for additional coordination and planning to better ensure reliability in an emergency,” MISO Managing Senior Corporate Counsel Amy Thurmond wrote to FERC in a transmittal letter. “To that end, each has identified the need to purchase emergency energy from the other to maintain the reliability of each individual transmission system and, more generally, the integrity of the Eastern Interconnection.”  

MISO and TVA have contemplated an agreement since MISO supplied up to 5 GW at times during the storm Dec. 23, 2022, to the Tennessee Valley Authority, SPP, Associated Electric Cooperative Inc. and the Southeast planning region. MISO’s exports that day played a role in forcing its own maximum generation event. After, MISO leadership lamented that though MISO could assist TVA during dire straits, TVA was prohibited from returning the favor when MISO encountered precarious operations. (See MISO, TVA to Enter Agreement on Emergency Purchases and MISO Defends Energy Exports During December Storm.)  

TVA’s ability to provide power to parties outside of its service territory is limited by the TVA Act. The federal utility can supply power only to parties that held exchange power arrangements as of July 1, 1957, and their successors. TVA for years interpreted the TVA Act as a barricade to selling power directly to MISO.  

MISO is less restricted in the balancing authorities it can sell to or purchase emergency energy from. The RTO’s tariff requires only that there be an agreement between MISO and another BA.  

MISO noted that two of TVA’s neighboring electric systems included in the 1957 agreement — Ameren and Entergy — joined MISO years ago. MISO and TVA share a seam in Mississippi and along the Arkansas-Tennessee state line.  

Ameren and Entergy as Avenues for Trade

The freshly filed agreement involves Ameren and Entergy granting authority to MISO to act on their behalf to buy emergency energy from TVA. MISO said the emergency energy it coordinates and directs from TVA on behalf of Entergy and Ameren would be used for the “sole purpose of maintaining electric reliability.” 

Terms of the agreement stipulate that TVA and MISO can share power up to the transfer limits in use between the two when one is experiencing an emergency. The two said supply to the other shouldn’t come at the expense of the “safe and proper operation” of their own transmission systems and service to their own customers and shouldn’t impede obligations they might have with other parties.  

MISO and TVA said one or the other should be experiencing a NERC-defined Energy Emergency Alert Level 2 before an offer to supply emergency energy can be made. Offers would be recallable up to 10 minutes ahead of time, and MISO and TVA said they would make efforts to ensure that an emergency energy transaction “continues only until it can be replaced by a commercial transaction.” All emergency energy transactions would be metered and billed based on scheduled deliveries. Emergency energy charges from the delivering BA to the receiving BA would be calculated based on a two-part formula that includes an energy portion and any transmission charges to an agreed-upon delivery point.  

When MISO was the delivering BA, the rate per megawatt hour would be either 150% of the hourly locational marginal price at the buses near the point of exit, 110% of the verifiable cost of the resources used to supply the power or $100/MWh, whichever is greater. When TVA was delivering megawatts, the rate similarly would be the greatest of either 150% of the hourly LMP at the points of injection in either the Ameren or Entergy service territory, 110% of the verifiable cost of the resources used to supply the power or $100/MWh.  

MISO and TVA plan to use an invoice system with rules that allow one or the other to collect interest on delinquent payments or raise billing disputes. MISO added that though it would be sourcing emergency energy on behalf of Ameren and Entergy, under no circumstances would the two members be liable for the RTO’s obligations under the agreement.  

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Changing Dynamics of Clean Energy Transition Debated at Aurora Energy Conference

NEW YORK — Despite some recent hiccups with supply chains and higher interest rates, the clean energy transition is set to accelerate with long-term policy support, panelists said Oct. 24 at the Aurora Energy Transition Forum. 

The offshore wind industry in the U.S. has had issues with project delays and cancellations and the recent construction accident at Vineyard Wind 1, but the industry has moved projects through the permitting process, and construction is due to pick up soon, Vineyard Offshore CEO Alicia Barton said. 

“We’ve seen setbacks, no doubt about it,” Barton said. “When we look ahead, though, over the next — and I’m not talking like the 10 years; I’m talking about 2025 — we are going to see something like 8 GW of projects actively under construction in the United States.” 

The industry is starting to put steel into the Outer Continental Shelf, but it already has gotten eight to 10 projects through the permitting process, and it will start sending significant power to the grid in two to three years. 

“We actually are seeing this industry, I think, at a very different scale,” Barton said. “And I think that actually does get lost, even on people that are spending all their time on energy, because you hear so much negative news about offshore wind.” 

Some projects have had to cancel their initial contracts, but they have been able to sign new ones for higher returns because many of the East Coast states supporting offshore wind need the power, Barton said. 

“In New England, increasingly, there is a recognition that offshore wind is the resource that will address long-term winter reliability,” she added. “But of course, we need to start showing up sooner … in terms of the number of years that it has taken thus far to get projects done.” 

Solar and batteries have come to dominate interconnection queues, but the economic issues of the past few years have impacted them as well, as 2022 and 2023 saw slight price increases because of the supply chain, said Samuel Scroggins, managing director of Lazard’s Global Power, Energy & Infrastructure Group, which tracks the levelized cost of energy (LCOE) for different generation technologies in annual reports.

The latest LCOE numbers declined slightly, though the days of regular cost declines are in the past. 

“The costs have come down so much for wind and solar in particular that we’re at a point now where there needs to be some incremental technology advancement to see continued cost decline,” Scroggins said. “The model is relatively straightforward. The inputs are pretty clear.” 

Bringing down capital expenditure is getting difficult because the industry already has used many of the best sites, so those that remain are not the “nice, flat, square” pieces of land that are easy to develop, he added. 

The Inflation Reduction Act has given financers and developers a long enough runway to get projects with 10 years of certainty for tax subsidies, which in the past sunsetted much sooner than that, said Allan Marks, a partner with law firm Milbank. It has spread the money around enough that the policy likely will survive regardless of what happens in the elections Nov. 5. 

“If you look at congressional districts, two out of the three jobs created in the manufacturing plants are in red or red-leaning congressional seats,” Marks said. “So, there are good reasons why 18 Republican members of Congress wrote a letter to the speaker and said, ‘Please do not repeal IRA.’” 

While the money likely still will flow from tax credits, the White House switching parties would lead to changes on how the law is implemented with changes at federal agencies, he added. 

Nora Mead Brownell, co-founder of consultancy Espy Energy Solutions and a former FERC commissioner, also noted the IRA’s funding of major projects in conservative states gives it staying power, but she also argued that other policies need changes. 

“We did not change the regulatory model at the federal and the state level,” Brownell said. “We are not rewarding the right things. We have evasive utilities who are terrified of change, who are not introducing their own solutions [and] adding technology efficiency that would give more transparency.” 

That can change with the rate structure of utilities, with Brownell saying performance-based rates should be widely adopted to encourage utilities. 

“We reward great, honking projects that may or may not solve the solution,” Brownell said. “We do not reward innovation. We do not allow people to take risks. We do not enforce data to be shared with people who could create those demand response programs, both at the commercial and retail level, that could make a huge difference.” 

Ideally, more power over the industry would be shifted to the federal level, and states would have more uniform rules because a patchwork makes things harder, she said. 

“I think we have to have a larger conversation about, ‘Yes, this is going to be expensive, but we’re making it more expensive,’ and we need to speak in terms that real people can understand,” Brownell said. 

The Rapid Growth of Batteries in the 2020s

Just a few years ago, the grid hardly had any storage capacity, but now it makes up about 40% of the queues across the country, with significant deployments in CAISO and ERCOT, Jupiter Power CEO Andy Bowman said. 

“It’s become the kind of firm dispatch that we have traditionally looked for natural gas plants to provide,” Bowman said. “And I think the growth opportunity for storage increasingly is not as some kind of ancillary renewable technology; it is for firm clean power. Firm clean power that can be dispatched very quickly. Firm green power that can provide a lot of valuable grid services.” 

Years ago the price for batteries was $4,000/kW, which made them irrelevant, but by 2019 that came down to $400/kW, said Spearmint CEO Andrew Waranch. With tax subsidies and plenty of financing available, the price of a 100-MW, two-hour battery in Texas is down to just $10 million. 

“I’ve always said that batteries will be as prevalent as cell phone towers,” Waranch said. “They will be everywhere. They’ll be on every corner. Because even if they’re big or they’re small, they’re affordable. And when you look at how they compete with other assets, relative to CTs [combustion turbines], they’re cheaper, faster, cleaner and stronger and a lot quicker to build.” 

So far, batteries have had major impacts in California and Texas, Bowman said. 

“California, as with just about every new energy technology, leads the way,” he said. “Texas comes in close behind, surpasses them, and I think we’ll be doing that shortly with batteries.” 

But with how quickly the grid is changing and how disruptive batteries have become, Bowman expects energy storage assets will start to grow in every market eventually. Jupiter is working in MISO, ISO-NE, NYISO and PJM on changes that will help grow and integrate batteries into their systems. 

Spearmint is building 1,200 MW of batteries in ERCOT, but its largest development portfolio is in MISO because it and SPP have the most acute needs for the technology now. 

“If they’re telling you that they’re unsolvable in a few years from now, you usually want to listen,” Waranch said. “But at the same time, in between 1997 and 2002, we did build 225 GW of gas in five years, and so you can solve problems with building quickly.” 

The supply-and-demand picture always is important, but EnCap Investments Managing Partner Kellie Metcalf said that to really roll out the technology, the right market designs are needed. 

“That’s what’s so good about California: The resource adequacy charge is huge,” Metcalf said. “In ERCOT, it’s been the ancillary services and the volatility top to bottom that [cause] revenue.” 

MISO does not have anything like those revenue streams, and other markets like ISO-NE have clean peak programs, but that still is in its early days, she added. 

While MISO is not quite ready to see major investments in batteries because it lacks any real construct that can make storage profitable, Waranch argued that could be solved quickly. “Even if they don’t have a construct yet, when the need arises and they are deficient, they will have to create a construct that works.” 

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Mass. Clean Energy Permitting, Gas Reform Bill Back on Track

After negotiations extending well past the end of the formal legislative session, Massachusetts lawmakers are nearing passage of a wide-ranging climate and energy bill including provisions to expedite clean energy siting and permitting, reform gas utility regulation and authorize the procurement of 5,000 MW of energy storage resources.

The 139-page bill, dubbed “An act promoting a clean energy grid, advancing equity and protecting ratepayers,” passed in the Senate on Oct. 24. The bill now sits in the House, where Republicans have stalled its passage by calling for a roll-call vote. Gov. Maura Healey (D) has indicated her support for the bill.

The major focus of the legislative session — and one of the key components of the resulting bill — has been the overhaul of the state’s energy permitting and siting processes.

The bill would consolidate state and local permitting for renewable energy projects and grid infrastructure into a single review process and would cap the review timeline at 15 months for large projects and 12 months for smaller projects.

The permitting reforms “are taking a process that has gone seven to 10 years and bringing it down to 12 to 15 months,” said Rep. Jeff Roy (D), the lead House negotiator on the bill.

Long permitting and siting timelines have slowed the development of clean energy in the state, and reforming the process has been a key priority for a broad coalition of interests.

Following the publication of recommendations from the Massachusetts Commission on Energy Infrastructure Siting and Permitting, top legislators and Healey’s administration reached a general agreement on the permitting language, which was included in separate bills passed in the Senate in late June and House in mid-July. (See Mass. Commission Issues Recs on Energy Project Siting, Permitting.)

In the updated process, the state’s Energy Facilities Siting Board (EFSB) would coordinate and issue consolidated permits for all large projects, which would encompass all required state and local permits. For smaller projects not in the EFSB’s jurisdiction, the bill would allow developers to challenge the denial of a local permit to the EFSB, which could overrule the local decision. (See Mass. Legislature Faces Looming Deadline to Pass Permitting Reform.)

Dan Dolan, president of the New England Power Generators Association, expressed strong support for the bill’s siting and permitting provisions.

“I appreciate that siting remains the centerpiece of this legislation,” Dolan said. “It is a testament to the commitment from the governor to get this done that the legislature is taking extraordinary procedural steps to bring this over the finish line.”

While the permitting and siting agreement largely was in place in time for the end of formal session on July 31, the Senate and the House could not overcome their differences on several key issues prior to the deadline. (See Mass. Lawmakers Fail to Pass Permitting, Gas Utility Reform.)

However, lawmakers continued to work behind the scenes to reach a compromise throughout the summer and into the fall and now say they are happy with the bill that has emerged.

The Senate reconvened a formal session to pass the bill 38-2 on Oct. 24. While the House leadership has attempted to pass the bill via informal session, House Republicans have stalled its passage by challenging the presence of a quorum. Despite the short-term challenges, House leaders have expressed optimism they eventually will send the bill to Healey.

Gas Utility Reform

One of the key disagreements that held up the bill in July centered around how aggressively the state should move away from natural gas.

“We had some differences in opinion as to what should happen with the decommissioning of the gas system,” Roy told RTO Insider. “We thought that the Senate was moving too quickly to decommission gas, so we had differences there that we eventually ironed out. Once we ironed out those differences, it made it easier to come together on everything else.”

Throughout the negotiations, Sen. Mike Barrett (D), the lead Senate negotiator on the bill, emphasized that the permitting and siting reforms could lead to an expensive expansion of the electrical system and therefore must be coupled with efforts to rein in costs from the gas system.

Ultimately, the Senate and House agreed to add language amending the definition of a gas distribution company, explicitly authorizing gas utilities to “make, sell or distribute utility-scale non-emitting thermal energy, including networked geothermal and deep geothermal energy.”

The bill also would update the state’s gas system enhancement program (GSEP), which is intended to reduce leaks from the gas system. GSEP costs have increased in recent years — with an expected total price tag of about $34 billion according to one consultant — spurring concerns from climate and consumer advocates that the new pipes installed under the program will become stranded assets.

While the existing GSEP statute centers around pipe replacement, the bill would authorize pipe retirement as part of the program.

Barrett added that the legislation would amend the “right to gas” in state law, which allows customers to petition for gas service.

This right “was the primary tool used to keep gas infrastructure in place, even as people have started to migrate to cleaner alternatives like heat pumps,” Barrett said, noting that right could enable a single customer to hold up the retirement of an entire segment of the gas distribution system.

“We’ve changed that,” Barrett told RTO Insider. “You can no longer be the hold-out on your block — if you do hold out, you could keep the entire block’s worth of natural gas infrastructure in place at great expense to ratepayers, even if everyone else has migrated to something better.”

The statutory changes were developed in coordination with the Massachusetts Department of Public Utilities (DPU), which ruled in 2023 that the decarbonization of the state’s gas network should center around electrification. (See Massachusetts Moves to Limit New Gas Infrastructure.)

Under the new rules, the DPU would be able to consider the public interest, “including the public interest in reducing greenhouse gas emissions,” when evaluating petitions for gas service.

Cumulative Impact Analysis

The bill would require project developers to submit a cumulative impact analysis, which would consider “any existing environmental burden and public health consequences impacting a specific geographical area in which a facility, large clean energy infrastructure facility or small clean energy infrastructure facility is proposed.”

This requirement was a key priority of environmental justice advocates in the state, who said it is a necessary safeguard to ensure the new permitting and siting process does not exacerbate existing energy infrastructure burdens on vulnerable communities in the state.

While advocates previously expressed concern that the cumulative impact analysis definition included in a prior iteration of the bill fell short, the new bill features “a robust definition of a cumulative impact analysis,” said Claire Karl Müller, coordinator of the Mass Power Forward coalition.

“We got to a good definition through really persistent, thoughtful advocacy,” Müller said. “We’re excited about the bill — it has some really good pieces.”

Clean Energy Procurement

The legislation would authorize a massive procurement of energy storage resources — it directs the state’s electric utilities to contract for 5,000 MW of storage by mid-2030, including 750 MW of 10- to 24-hour storage and 750 MW of storage with a duration greater than 24 hours. The minimum storage duration for the procurement would be set at four hours.

For offshore wind, the legislation would increase the potential length of long-duration contracts, allowing contracts from 15-30 years. Offshore wind contracts currently are capped at 20 years in the state.

It also would enable the state to coordinate with other New England States “to consider competitive solicitations for long-term clean energy generation,” including generation from the region’s two existing nuclear plants.

This provision comes during ongoing discussions about Massachusetts buying power from the Millstone Nuclear Power Plant, which is propped up by Connecticut, in exchange for the state buying power associated with the recent multistate offshore wind solicitation. (See Multistate Offshore Wind Solicitation Lands 2,878 MW for Mass., RI.)

This language also would enable the state to contract for onshore renewable energy in northern Maine. Government officials in Maine are preparing to issue procurements for renewable generation and associated transmission in the northern part of the state. Massachusetts previously committed to buying power from an onshore wind solicitation which later was terminated by Maine. (See Long Road Still Ahead for Aroostook Transmission Project)

While the Senate advocated for a more expansive procurement proposal to give the Department of Energy Resources significant latitude to procure clean energy as needed, these changes ultimately were left out of the compromise bill.

“That’s a compromise in which the House won some important concessions,” Barrett said.

Electric Vehicles

Regarding electric vehicles, the bill directs state agencies to conduct a 10-year forecast of EV demand, enabling the evaluation of sites for charging hubs. After the assessments are complete, the electric utilities would be required to submit infrastructure plans to meet demand.

The legislation would authorize municipalities to buy chargers and electric vehicles, including electric school buses.

It also would direct the state Division of Standards, which regulates gas stations, to develop regulations for electric vehicle chargers “to make sure these charging stations are delivering what they say,” Roy said.

Odds and Ends

The wide-ranging bill includes several other notable provisions, including:

    • Requiring electric utilities to consider advanced transmission technologies (ATTs) and other non-wires alternatives when planning new infrastructure and directing the DPU to investigate the use of ATTs.
    • Adding fusion energy to the state’s definition of clean energy.
    • Creating a commission to study how the clean energy transition is impacting the fossil fuel workforce.
    • Authorizing regulators to update appliance standards “to facilitate the deployment of flexible demand technologies.

There are several key proposals not included in the bill, including regulations targeting predatory competitive electricity supply companies, updates to the state bottle bill and a requirement for commuter rail electrification.

While the Senate and the state Attorney General’s Office have pushed for a full ban on retail third-party electricity suppliers, the House has argued for a more scaled-back reform package.

Larry Chretien, executive director of the Green Energy Consumers Alliance, expressed disappointment about the lack of action regarding competitive retail suppliers, and said reform will be a key priority for the next session.

“Every day that goes by there are more people that are going to be overcharged,” Chretien said.

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Data Center Load Uncertainty Tied to Broader Economy, Google Rep Says

SAN DIEGO — The volume of data center load growth in the U.S. will depend on how things play out in the broader economy, a Google representative told a gathering of Western state energy officials Oct. 23. 

“You should really think about data center demand as sort of an aggregation of the demand for digital services throughout the economy, and this demand is large and growing,” Dylan Sullivan, energy market development strategic negotiator at Google, said during a panel discussion on large loads at the fall joint meeting of the Committee on Regional Electric Power Cooperation and Western Interconnection Regional Advisory Body (CREPC-WIRAB) in San Diego. 

Sullivan kicked off his comments by asking audience members to raise their hands if they’d worked on a shared document or streamed video in the past week — or checked email within the past 15 minutes. 

“That’s everybody,” he said to laughter. “Well, then you used a data center.” 

Sullivan ticked off a list of Google’s online services, from Maps to YouTube to Gmail. He said Google Cloud provides computing services to hospitals, local governments, schools and “some of America’s fastest-growing companies” — including 70% of generative artificial intelligence companies, valued at more than $1 billion. 

As a result, Google’s global electricity consumption reached 25 TWh in 2023 — “equivalent to a North Dakota-sized state” and more than double its 2019 consumption. But he didn’t provide specific figures for Google’s demand in the U.S. or the West. 

And utility commissioners couldn’t pin him down on the company’s projections for future growth in data center load. 

Washington Commissioner Milt Doumit noted the share of U.S. electricity consumption from all data centers is expected to grow from 4% today to 9% by 2030. 

“What is your modeling [showing]? What is growth going to look like beyond 2030, if you can tell us?” Doumit asked Sullivan. 

“There’s some things that we just don’t know the answer to, and I think putting more provisions in place to put more of this forecast uncertainty onto large users is an important way to understand how much we can expect over time, but we don’t know the path of [the use of data] visualization and artificial intelligence in our economy,” Sullivan said. 

Sullivan noted that Google has three operating data centers in the West, including in The Dalles, Ore., and Storey County and Henderson, in Nevada, with another under construction in Mesa, Ariz., near Phoenix.  

Colorado Public Utility Commission Chair Eric Blank, the panel moderator, asked why companies such as Google are locating data centers in an increasingly heat-stressed area like Arizona, which has seen two straight summers of recording-breaking averages for daytime and overnight temperatures. 

Sullivan said the decision largely comes down to the location of its growing segment of cloud-based computing customers. 

“Basically, you click the mouse on a laptop, [and] you see the impact of that right on your screen,” he said. “If that computer were 200 miles away from you, you would notice the difference and not like it. And cloud customers are the same, so that they have certain requirements for latency [in computing]. They want ‘compute’ to be close to where they are.” 

In working with electricity and water utility Salt River Project (SRP) to supply the Mesa data center, Sullivan said Google determined its draw on the local water supply would be unsustainable, so it instead chose to air-cool the facility, which caused “a bit of an energy penalty.” 

“But we have a mix of resources through SRP that gets us to a very high percentage of renewable energy around the clock now, on a 24/7 basis,” he said.  

Real or Hype?

A recurring question during the panel and among attendees who spoke with RTO Insider at the CREPC-WIRAB meeting was whether the extreme projections for data center load growth are “real” or a speculative overestimate stemming from either hype or the fact that data center companies could be shopping multiple utility service areas for the same proposed facility, causing double-counting across utility load forecasts. 

“We don’t know how much the demand is real,” Sullivan said. He explained that when Google developed its first data center in The Dalles, the company was growing at a time when it was “soaking up” excess energy capacity on the grid, just as overall economic growth in the U.S. was decoupling from its historical connection with parallel increases in electricity use. 

“But now, with the onshoring of manufacturing, electrification [and] with data center demand, capacity is now tight, and that creates a problem for the industrial site selectors, where the time it takes to energize a site is lengthening,” he said. “And there’s uncertainty about the ability to interconnect the site, and that’s led to a natural response of people essentially filing multiple requests” for the same data center plan. 

“Here’s my take on it: The load is real. It’s a question of what’s the actual volume,” said Brian Cole, vice president of resource management at Arizona Public Service (APS). “It’s hard to see where there’s overlap and where there’s not. That makes it difficult.”  

Cole said APS has created a new data center strategy team to deal with the issue. He said the utility “literally” is having daily conversations with data center companies. 

“We’re trying to learn from them, trying to understand what they need, trying to work with them, [and] trying to establish what is the best path forward,” he said. “Regardless of the path and how we do it, the reality is it’s going to require a lot of building, it’s going to be a lot of resources, and it’s going to be a lot of transmission.” 

Cole said the utility’s goal is to serve all customers while maintaining reliability and avoiding cost-shifts among those customers. 

Antoine Lucas, vice president of markets at SPP, said that, since the COVID-19 pandemic, his RTO has fielded 40 GW of customer interconnection requests, with about 15% of those resulting in load interconnection agreements. 

“Looking forward, though, we’ve seen quite a few projections that those numbers will increase,” Lucas said, partly driven by new demand, but also because SPP has integrated a large number of renewable resources. 

“That has been something that’s been attractive to a lot of these entities who are willing to bring data centers or other businesses into the footprint,” he said. 

Lucas also clarified that he thinks SPP’s 15% customer interconnection rate is like the section of prospectus for a mutual fund stating that “historical performance is not indicative of future returns.” 

“We know there will be an increase, but we know there are also factors that impact it as well — cost being one of those major considerations,” he said. “In my opinion, it’s not so much whether or not we’re going to see an increase, it’s just going to be where does it happen?” 

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Panels Debate PJM Capacity Market Design at OPSI Annual Meeting

COLUMBUS, Ohio — Uncertainty was the throughline across several panels on the state of PJM’s markets during the Organization of PJM States Inc. (OPSI) Annual Meeting, as state regulators, market participants and RTO officials discussed a possible delay in the 2026/27 Base Residual Auction (BRA) and debated the eightfold price spike in the prior auction.

PJM CEO Manu Asthana said that any time a change to auction rules or timelines is made, regardless of the merits, investor and consumer confidence in the outcomes can be damaged. Without certainty about price signals, he said the financing necessary to bring new resources to the markets can be impacted at a time when PJM projects resource adequacy shortfalls in the latter years of the decade. Balancing the need to deliver prices reasonable to consumers while sending price signals to invest could mean making hard decisions about what priorities the U.S. has in designing the future of the electric sector.

“I have a fear that without more explicitly choosing whether we’re going to actually relax some of our environmental goals; or if we’re going to relax our desire to win the AI race; or we’re going to be willing to pay higher prices; or we’re going to put all of our chips in to invent a new technology that comes up with this green and cheap power; that we will not actually have any of these things. We will not have a reliable grid; we will not have an affordable grid; and we may not be able to serve all of the data centers,” Asthana said.

In contrast to Asthana’s concerns about resource adequacy at the 2022 OPSI meeting, he said he’s more worried now about the confluence of permitting and supply chain challenges, accelerating load growth and increasing public policy pressure on generators. Developers considering building new gas-fired capacity in PJM have to weigh EPA regulations that require carbon capture and sequestration against the revenues that can be received through PJM’s markets.

“You’re seeing that in investment: If you look at what is coming through our queue, the picture is pretty dramatic. You saw gas plants, gas plants, gas plants; this year, almost no gas,” he said. “I’m not saying we only need gas; we need everything.”

To address resource adequacy concerns, Asthana said PJM seeks to make three key changes to how resources can come onto the grid: the process for transferring capacity interconnection rights (CIRs) from a deactivating generator to a new resource; surplus interconnection service (SIS) to allow new resources to be co-located at underutilized interconnections; and a reliability resource initiative (RRI) to create a one-time expedited application window for high capacity factor resources to be studied in Transitional Cycle 2.

The RRI concept has been met with criticism from many stakeholders who argue it would amount to preferential treatment for some resource classes at the expense of renewables that have been waiting years for interconnection studies to be completed. PJM has responded that new resources with a high reliability contribution are needed to ward off a potential capacity shortfall in the 2029/30 delivery year. (See Stakeholders Divided on PJM Proposal to Expedite High-capacity Generation.)

The Planning Committee endorsed a proposal from a coalition of stakeholders to create an expedited study process for resources receiving CIRs from deactivating generators during its Oct. 8 meeting. (See PJM Stakeholders Endorse Coalition Proposal on CIR Transfers.)

Elevate Renewables, the original sponsor of that package, told RTO Insider it is encouraged by PJM’s supportive statements during the OPSI meeting and the recognition that a process is needed to allow the efficient development of new resources in the place of retiring units.

“The replacement of existing resource should not be relegated to the back of a backlogged, multiyear-long interconnection queue process,” Elevate said in an email. “Instead, there are efficiencies gained by aligning the timing of the de-energizing of the deactivating resource with the energizing of the new replacement resource. However, the current state of the PJM queue creates a timing mismatch, which, as we’ve seen, has resulted in mass closures of generating facilities, affecting more than just reliability but employee and communities.”

Elevate said SIS presents PJM with an opportunity to optimize the capacity contribution of resources that are not fully using their maximum facility output. The RTO’s current rules prohibit any projects that would increase line flow or short circuit current from utilizing the SIS process to fast-track their interconnection.

“However, as currently deployed, the PJM [SIS] process creates significant roadblocks for battery storage and many other newer technologies and fuel types to utilize the process FERC directed all RTOs to adopt in Order 845,” Elevate said. “We are hopeful that as PJM makes statements that they plan to make tweaks to the surplus interconnection service process, that those tweaks would include changing the triggering criteria for project failure in the SIS process to be actual reliability criteria violations, e.g., line overload or breaker over duty as failing criteria.”

OPSI Speakers Discuss Future Auction Design

Speaking on a panel focused on the future of the capacity market, Executive Vice President of Market Services and Strategy Stu Bresler said PJM is working toward a Federal Power Act Section 205 filing in December to make several changes to the design of the BRA.

While the 2026/27 auction currently is scheduled to be conducted in December, PJM has asked FERC to delay its opening by six months (ER25-118).

The filing could include changes to how PJM models the output of generators operating on a reliability-must-run (RMR) contract, the topic of a complaint filed in September by the Sierra Club, Natural Resources Defense Council, Public Citizen, Sustainable FERC Project and the Union of Concerned Scientists that argues the expected output of RMR units should be included in the capacity market supply stack (EL24-148).

Bresler said PJM also is looking at changing the reference resource for the 2026/27 auction, which would be the first to use a combined cycle rather than combustion turbine as the model unit on which several parameters are based. Because of the higher energy and ancillary service revenues for combined cycle generators, the net cost of new entry (CONE) value fell to $0, bringing the Capacity Performance (CP) penalty rate for units that fail to deliver during emergency conditions to zero as well.

The disparity between the net and gross CONE also resulted in a significantly sharper variable resource requirement (VRR) curve capped at $696/MW-day should 145,774 MW or less clear the auction, falling to $0 at 149,455 MW.

“I think the reason why we went to [the Reliability Pricing Model] and the sloped demand curve in the first place is because we thought that the sort of boom-bust cycle associated with a more vertical demand curve was not the best answer for long-term lowest reasonable cost to the customer,” Bresler said. “And so getting back to a VRR curve and a slope of a VRR curve that results in a more stable pricing outcome given the supply and demand conditions I think is important.”

Vitol’s Jason Barker said a vertical demand curve with a narrow band of prices can create whiplash that undermines the auction’s value as a data point for investors evaluating PJM’s markets.

American Municipal Power Vice President of Transmission and Regulatory Affairs Steve Lieberman noted that the Members Committee had endorsed an AMP-sponsored proposal to redefine the penalty rate to be based on the BRA clearing price, a change that was rejected by the PJM Board of Managers. Complaints subsequently were brought by the Independent Market Monitor and East Kentucky Power Cooperative, both of which were rejected by the commission in August. (See PJM Board Rejects Lowering Capacity Performance Penalties.)

Because the bonus payments for overperforming during a performance assessment interval (PAI) are paid out of the pool of penalties collected under the CP construct, Lieberman said the status quo net CONE would eliminate the incentive to perform during an emergency.

Monitor Joe Bowring said RMR units are being retained to provide reliability services and thus should be included in the capacity market supply stack, which is one component of a package of changes to PJM’s generation deactivation rules proposed by the Monitor at the Deactivation Enhancements Senior Task Force. The results of an online vote on four proposals before the task force are set to be presented during its Nov. 14 meeting. (See PJM Stakeholders Delay Vote on Generator Deactivation Rules.)

The need to enter into RMR agreements constitutes a deeper market failure, Bowring said, driven by market rules that do not recognize the full reliability contribution of generators.

PJM has defended not including RMR units in the supply stack by arguing that those resources have a stated desire to leave the market, so a price signal is needed to incentivize development to replace them. It also has pointed to differing obligations for capacity resources, which are held to CP rules that penalize underperformance, and RMR agreements that limit when units can be deployed. Going beyond counting them in the supply stack to require that RMR units offer into the capacity market also would subject those units to PAI penalty risks, creating a disincentive for voluntarily entering into an RMR agreement.

Bresler noted that in some cases RMR agreements allowed PJM to dispatch those units only to resolve specific transmission security needs, which is something PJM may be rethinking. He cautioned that a one-size-fits-all approach likely does not make sense for a construct created to address specific transmission needs.

“No. 1, when it comes to RMR resources, I don’t think we want to include them or treat them or model them as supply in the auctions unless the service they’re providing is comparable to that of a capacity resource,” Bresler said. “Otherwise they’re not interchangeable, so you wouldn’t want to change the supply-and-demand balance on the basis of that assumption unless that’s the comparable service that they are providing.”

Barker expressed a similar outlook, stating that RMR units have different performance obligations from capacity resources and including the former in the supply stack could be unduly discriminatory if they are treated comparably to capacity without being held to CP standards.

Susan Bruce, representing the PJM Industrial Customer Coalition, said that the compressed auction schedule has left little time for developers to respond to the high price signals prompted by a generator leaving the capacity market to operate on an RMR contract. At the same time that consumers are paying higher capacity prices, they are also paying for transmission upgrades necessary to resolve the violations necessitating the RMR agreement, she said.

Gregory Poulos, executive director of the Consumer Advocates of the PJM States, said the repeated auction delays have led to risk being shifted to consumers, pointing to a “miscalculation” in the reliability requirement for the DPL South zone in the 2024/25 auction that cost consumers about $100 million in higher capacity costs with no corresponding reliability benefit.

It also left little time for market participants to respond to changes in the guidelines for energy efficiency resources offering into the following auction, which caused a marked drop in supply, Poulos said. A PJM filing at FERC would eliminate the resource class outright from the capacity market. (See PJM Asks FERC to Eliminate Energy Efficiency from Capacity Market.)

Given the little direct insight consumer advocates have on market decisions, they often are reliant on PJM estimates of the potential impacts market changes could have on prices, Poulos said. He urged PJM to use the information at its disposal to do more proactive modeling and analysis, which he said would improve consumer confidence in future auction outcomes.

More analysis and modeling of potential market changes could give stakeholders more certainty on proposals they are asked to vote on and increase certainty in future auction outcomes, he said.

Maryland Public Service Commissioner Michael T. Richard, moderator of the panel, said high prices can disrupt the economies and lives of ratepayers in PJM states.

“Markets are created for the customer. The concern I think some of us have is that after we see a sudden 800% jump in the market, we just have to ask, is this really a stable and predictable environment for customers, for state economies?” Richard said. “This essential service needs to be available to everybody and needs to be something that’s affordable.”

Panelists Discuss Price Surge in 2025/26 Auction

Speaking on a panel focused on the results of the 2025/26 BRA, Bresler defended the eightfold increase in prices, stating that the increase properly reflected tightening supply and demand. He said the capacity market has seen years of low prices owing to a surplus of generation in the market, leading to deactivations that are putting pressure on supply.

LS Power Senior Vice President of Wholesale Market Policy Marji Philips said the original concept of the capacity market was for prices to increase when demand is tight and fall when it is low, averaging out to net CONE over the lifespan of the reference resource. While regular market interventions have been creating price volatility and uncertainty, she said the return of prices to net CONE levels signals that investments in new generation are needed.

Bowring disagreed that the auction accurately reflected supply and demand, stating that administrative changes to the definition of capacity, namely the use of marginal effective load-carrying capability for resource accreditation, actually inflated prices. He also argued that supply is being suppressed by PJM’s categorical exemption of intermittent and storage resources from the requirement that all resources holding CIRs offer into the BRA. Both points were raised in the first two sections of the Monitor’s report on the 2025/26 auction. (See PJM Market Monitor Releases Second Section of 2025/26 Capacity Auction Report.)

“The design of the market did not reveal what the actual supply and demand was,” he said.

Clara Summers, campaign manager of the Consumers for a Better Grid project at the Illinois Citizens Utility Board, said there were changes in supply and demand, but they were not significant enough to account for the scale of the price jump seen in the July auction. Moreover, she argued that the capacity market is incapable of sending price signals to build because of the backlogged interconnection queue, an issue she said also is present when considering if high capacity prices can incentivize replacement resources while transmission upgrades are built.

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Tx Supporters Check in on Order 1920 Compliance Efforts

With the Order 1920 compliance window already halfway closed and an order on rehearing expected in the next couple of months, Americans for a Clean Energy Grid (ACEG) hosted a webinar Oct. 28 examining progress on the measure so far. 

The group worked with Grid Strategies to release an update to its regional transmission report card, which showed all U.S. organized markets recently have been looking at changes to their planning practices. (See ACEG Report Checks in on Regional Planning After Order 1920.) 

The original report, which predated Order 1920, attempted to examine best practices in planning. With Order 1920 compliance efforts underway, it was time for an update, said Rob Gramlich, president of Grid Strategies and co-author of both reports. 

“There’s some signs of improvement,” Gramlich said. “CAISO and MISO continue to proceed with what they’re doing, which is, you know, largely close to Order 1920 and the best practices.” 

CAISO and MISO received the best grades in the initial report, and other markets have all made improvements, though the report said areas outside organized markets — the Southeast and most of the West — have done little in terms of region-wide transmission planning, he added. 

Compliance filings are due next summer, but some regions are starting to work on them. For example, several regions have launched their state engagement periods, which give six months for state regulators to craft a regional cost allocation methodology, said ACEG Executive Director Christina Hayes. 

SPP launched that process Oct. 28 and its Regional State Committee was poised to vote on whether it would be the venue for those cost allocation discussions, said Christy Walsh, a senior attorney at the Natural Resources Defense Council. Walsh watches the organized markets for NRDC and its Sustainable FERC Project, and she noted a similar attitude among many of them. 

“They say: ‘We know there’s need for regional transmission — it brings reliability and affordability benefits, but we’re doing it right,’” Walsh said. 

WIRES Executive Director Larry Gasteiger said he sees some of that messaging from the RTOs/ISOs, but contended they still have many issues to deal with. 

“What I really think is happening is they are saying we are working hard on trying to address these concerns. We think we’re meeting them in some respects,” he added. “I think there’s an acknowledgement that there can be some improvements, but I’m also hearing it against the background where they’re trying to get a heck of a lot of other things done at the same time.” 

MISO got good grades on its ACEG report card, but it has asked for a year delay in complying with Order 1920 to avoid disturbing its ongoing planning processes. (See MISO to Request Year Deferral on FERC Order 1920.) 

ISO-NE got a most-improved nod from Gramlich because of its recent work with member states around transmission planning, but it recently put a pause on Order 1920 compliance due to uncertainty around the rule’s fate. (ISO-NE Announces Pause of Order 1920 Compliance Discussions.) 

Rehearing Order Imminent

In general, major FERC orders have not undergone significant changes on rehearing, but that might not be the case with 1920, Gasteiger said. 

“There were some stark differences right from the get-go on this rule, and I don’t know with three new commissioners how that’s going to play out,” he said. “My guess is not huge changes, but I think the potential for more significant changes is greater here than in the past.” 

FERC is expected to issue a rehearing order in the next couple of months because it has asked the 4th U.S. Circuit Court of Appeals to hold off on its review of the order until January, Walsh said. Gramlich agreed a rehearing order likely will come soon. 

Another looming area of uncertainty is the elections, as a change in the White House would mean a change in FERC chairs and eventually a shift to a Republican majority on the commission.

“To the extent some regions are not racing [toward] compliance, I do think the industry will get some more clarity in the next couple of months about some things, and hopefully at that point they’ll be moving forward quickly,” Gramlich said. 

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Future of Power Markets Discussed at Aurora Energy Conference

NEW YORK — The Inflation Reduction Act and other policies have made the U.S. into one of the most attractive places to invest in clean energy, but completing the energy transition will require additional advances, panelists said Oct. 24 at the Aurora Energy Transition Forum.

Oliver Kerr, Aurora Energy Research’s managing director for North America, asked panelists whether they would pick the U.S. or Europe if they had $1 billion to invest.

“If I had a billion dollars, I would spend $100 million on the best development pipeline that required $2 billion of investment” in the U.S., RWE Clean Energy CEO Andrew Flanagan said. “And I’d invest that other $900 million into that portfolio, and then I’d claw back that additional billion, or $1.1 billion from our colleagues in Germany, or find some other equity source.”

Germany-based RWE is not alone, with Sandhya Ganapathy, CEO of EDP Renewables North America (a subsidiary of a Portuguese utility), saying the U.S. represents 45% of the parent firm’s investments, the largest share out of the 29 countries in which it is active.

“This is a great, great market to invest, and it’s also a great market where I truly believe that market fundamentals work really well,” Ganapathy said. “It’s not a lot of intervention; it’s really set by demand.”

There’s clearly still plenty of room to grow, as Europe is up to 35 to 40% renewable energy, while the U.S. is at just half of that. On top of federal policies spurring investments, 28 states have set some kind of mandate for renewables, and there is large and active demand from big corporate buyers, Ganapathy said.

Arguably the two leading states on the energy transition are California and Texas, which have deployed tens of thousands of megawatts using very different regulatory models.

“California, as we know, by state statute, has committed to decarbonizing the power sector by 2045,” CAISO CEO Elliot Mainzer said. “I think when you take the fifth-largest economy in the world and put it on that path, every major developer is going to want to have a piece of that, and so that’s why we have a 510-GW queue.”

Many developers come up against friction in the queue, but the issues around it can mask some realities like the fact that California has deployed 20,000 MW of new supply over the past four years, including 10,000 MW of batteries, he added.

California has a much more planning-based process with its various state agencies taking a bigger role in things than Texas, but part of the fix for that major backlog in the queue was borrowed from the Lone Star State. CAISO’s newest recently approved process involves studying which of those 510 GW actually are responding to demand and linking the transmission planning process to the queue, Mainzer said. (See FERC Approves CAISO Plan to Streamline Interconnection Process.)

CAISO borrowed “very shamelessly” Texas’ Competitive Renewable Energy Zone approach, which picked out the best areas for wind and built major transmission lines to connect them to cities, turning the state into the leader in wind capacity, Mainzer said.

“The way the ERCOT market has evolved, it has been very open and made it very easy for both supply and for load to come to the system,” CEO Pablo Vegas said. “We’ve got a light regulatory touch on virtually all facets of the interconnection process, and we’re very flexible in the way we manage those interconnection queues. And it’s been a benefit that has, I think, gotten us to where we are today, but the old adage of ‘what got you to where you are today won’t get you where you’re going to go’ applies very accurately in Texas, as we look forward.”

Projections for load growth in ERCOT call for as much as 150 GW to come online; it set its peak record of 85,508 MW in August 2023. It is far from clear that demand will grow that much, but like in other parts of the country, Texas is seeing demand growth on a scale that has not been witnessed since the years following World War II, Vegas said.

“In order to meet that challenge, we are going to have to think differently,” Vegas said. “In Texas, we have not historically planned where load or where supply gets sited. And when you’re trying to build transmission, which is going to become the linchpin to the success of this whole strategy, transmission has to know where load and supply is going to be. And so, we’re starting to take similar constructs and approaches to what Elliot just described.”

ERCOT is doing that less formally, making assumptions as to where demand is likely to show up on the grid based on where resources are and linking the two with transmission. None of that activity is required by rules, but the hope is that the market will follow suit and plan accordingly.

“It’ll be the fastest way to get there, and it will be the most efficient way to build the transmission infrastructure, but the market will respond to that,” Vegas said.

ISO-NE CEO Gordon van Welie said the transition involves four pillars, but one of them is much less discussed: ensuring the system has enough stored energy in fuel tanks or other long-term options to make it through times when renewable supply is low and demand is high, especially during winter.

“We’ve assumed that problem away,” van Welie said. “Actually, if you go back 25 years ago when we started the market construct, we just assumed that everyone was going to have a reliable fuel supply.”

The clean energy supply in New England is being driven by state mandates, while the issues around resource adequacy and reliability services is driven by the wholesale market. The states have said they do not want to take back authority for resource adequacy, van Welie said.

“They want the kudos from signing the contracts with the green stuff, and they want to leave the problem of how you pay for all that fossil stuff to the ISO and FERC, right?” he added. “So that’s the sort of political dynamic that’s going on there. But in this regard, I agree with [FERC] Commissioner [Mark] Christie, which is the states can’t just walk away from resource adequacy.”

The states have to get behind a market that can support resource adequacy over the long term, because otherwise it will be chaos, with the markets having to be redesigned every three or four years, van Welie said.

One of New England’s longstanding issues is ensuring reliability at the end of the pipeline network during harsh winter weather, which has bedeviled the market at the opposite end of many of those pipelines: Texas. Unlike the Northeast, Texas has plenty of natural gas supply, but it has had its worst reliability issues during the winters, Hunt Energy Network CEO Pat Wood said.

“Gas has two mistresses in the middle of a cold day, and it’s gas customers who keep their homes warm through natural gas and now 62% of Texans who keep their home warm through electric heat,” Wood said. “And that very tight period of time is where you’ve got the problem.”

Texas cannot count on its growing solar resources before the sun rises on a cold winter morning and when wind also is not producing at those times, and the market is not sending a strong price signal that resource adequacy is required in such times, Wood said. After Winter Storm Uri, the price cap was cut back from $9,000/MWh to $5,000/MWh.

The dispatchable reliability reserve service (DRRS), a proposal from the Texas Industrial Energy Consumers working its way through ERCOT’s processes, could help send the right kind of price signals to get needed generation built, Wood said.

While Texas and New England both face winter reliability issues, Calpine CEO Thad Hill, whose firm is active in both markets, noted they have very different causes.

“In the east, we’ve got a fundamental capacity shortage,” Hill said. “In ERCOT, we had a breakdown of preparation.”

Part of that breakdown ahead of Winter Storm Uri came from new oil and gas production capacity that had come online in the Permian Basin since ERCOT’s previous winter reliability problems in 2011, he added. Oil and gas production older than that performed better, while the new Permian capacity often was supplied by the grid and stopped producing when it lost power, exacerbating shortages in both gas and electricity.

While PJM had its hiccups in winters past, historically it has had very healthy reserve margins. But its recent capacity auction saw prices shoot up as those narrowed, which has sparked controversy. (See PJM Capacity Prices Spike 10-fold in 2025/2026 Auction.)

Hill noted that in the past when capacity prices have spiked, his firm and other suppliers have responded with new supply, and he expects that to happen again.