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October 31, 2024

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Exelon, Constellation at Loggerheads over Data Center Co-location

The dispute between Exelon and Constellation Energy continues to play out in FERC, as the latter and others have protested a series of filings from the former’s utilities seeking to implement new rules for co-locating data centers at power plants in their territories (ER24-2894).

“Pepco supports the opportunity for end-use load customers to co-locate where it can be done without threatening reliability. Because the new loads are end-use customers, state law, rather than the [Federal Power Act], determines the retail rate treatment of these arrangements,” the Exelon subsidiary said in its proposal, submitted in August along with those of its five sister utilities.

Ahead of the deadline for comments on the proposals, Exelon petitioned FERC on Sept. 30 for an order declaring that PJM’s generator interconnection procedures under Order 2003 apply only to end-use generation, not load. (See related story, Exelon Asks FERC to Weigh in on Co-location Dispute with Constellation.)

Exelon’s utilities argue in their filings it’s important that co-located customers bear their fair share of the costs of transmission service they use and of the interconnection facilities. Even data centers on the generator side of the meter impose similar needs on PJM when it comes to ancillary services and RTO monitoring and administration, they said.

The changes would require any co-located data centers to pay their share of the cost of transmission services, ancillary services and other PJM charges. Exelon also initially said it would be required to meter the “gross load” of the end-use customer, but it removed that language after a protest from the Natural Resources Defense Council saying that could impact backup generation many customers use.

Constellation argues in its protest that any data centers that might connect to its nuclear plants in PJM — and in Exelon utility territories — would not take any service from the grid. They would be separated from the grid by redundant protective relays and other equipment that prevent them from ever taking energy off the grid or relying on other grid services.

“Exelon’s request should be rejected for what it is: another attempt by a monopoly utility to preserve and increase its market share at the expense of competition and economic development, including the critical and urgent national security need for artificial intelligence and data centers,” Constellation said.

Even with the clarification preserving netting arrangements, Constellation said Exelon’s rules are as “clear as mud.” The filings leave out details of the services the utilities would provide to “fully isolated co-located loads” and do not explain the rates it would charge them.

They would change the definition of network integration transmission service (NITS) in PJM and require every customer “synchronized” to the grid to become Exelon’s transmission customers, Constellation argued. “This would force office buildings, grocery stores and even homes across the Exelon footprint to become transmission customers under the PJM tariff.”

Exelon should have made the proposal under FPA Section 206 because only PJM itself can file changes to its rules under Section 205, Constellation said. Even if the changes were filed correctly, the lack of any description or justification of the rules means Exelon has failed to meet its burden of proof, it argued.

“Exelon wants to require its interconnection customers to be its transmission customers, but the commission has always recognized a distinction between the two services, and it should not allow Exelon to eliminate that distinction here through its control over interconnection services,” Constellation said. “Nor should the commission usurp a state’s authority to determine what is and is not a retail sale.”

Constellation filed affidavits with its protest from two experts: former PJM Vice President of Planning Steven Herling, and market design expert Roy Shanker.

Herling analyzed the engineering and equipment of co-located load and explained why the load is not relying on grid services.

“Protective relays prevent the load — be it data center, hydrogen electrolyzer or otherwise — from taking electricity off the grid,” he said. “Yet Exelon seeks to classify all fully isolated co-located load as network load. Basic engineering confirms that this load is not relying on the grid. Basic cost-causation principles dictate that this load should not pay for services it does not take.”

Herling said co-located loads have transformers to measure any flows between the grid, and the behind-the-fence customer can automatically trip circuit breakers if any such flows are detected. That can happen if the nuclear plant trips offline, or lower their output, unexpectedly and would “trip the load from the grid” in 0.05 seconds.

Exelon has protested an existing deal that Talen Energy wanted to expand with a data center at its Susquehanna Nuclear Plant. (See Talen Energy Deal with Data Center Leads to Cost Shifting Debate at FERC.)

The debate in the Talen proceeding led to FERC scheduling a technical conference on the issue for Nov. 1. The issues around data centers also are being taken up by state regulators, with the Virginia State Corporation Commission on Oct. 2 announcing a technical conference for December and the Maryland Public Service Commission recently holding a hearing. (See With Three Mile Island Restart, Debate Continues on Co-located Load in PJM.)

Data centers are particularly important to the modern economy, and their recent proliferation in Northern Virginia shows that only allowing them to connect through the grid can lead to significant delays, Constellation said.

While FERC has rules against generators withholding power, they can sell to any willing customer — including engaging in off-system bilateral sales.

“The commission cannot allow Exelon to exercise monopoly power or force all generators to live and die by RTO market prices,” Constellation said.

FERC has worked to correct “the excesses of transmission monopoly” through its 30 years of policies supporting open access, Constellation argued, while Exelon’s play is to quash a competitive alternative it believes threatens its bottom line. It is not just data centers; Constellation is using its LaSalle nuclear plant in Illinois to directly power hydrogen electrolyzers under the U.S. Department of Energy’s hydrogen hubs program.

The gross metering proposal would be a huge blow to that hydrogen effort, as well as to facilities such as batteries and pumped storage that withdraw more energy from the grid than they inject, Constellation said.

Other Parties Weigh in on the Issues

Exelon’s filing drew about a dozen responses from other stakeholders, with Advanced Energy United and the Solar Energy Industries Association urging the commission to either reject them or set them for hearing, so that the issues around co-location can be worked out in a general way.

“These new arrangements raise jurisdictional considerations that require a full analysis of implications based on the unique structure of the arrangement,” the organizations said. “The industry and the commission itself are still exploring the electrical, economic and legal implications of these arrangements.”

The lack of understanding around the issue could lead to unintended consequences if Exelon’s proposal were to go into effect before it is examined in a more general way such as at the technical conference next month, AEU and SEIA said.

Calpine also argued that the issue was too novel to be decided now and that Exelon’s proposal could impact industrial facilities and potentially even residential customers.

“The commission’s actions here will impact the nation’s ability to build vital data infrastructure that is critical for national security and economic development,” the company said. “This attempt to circumvent a policy discussion of national significance must be rejected.”

Old Dominion Electric Cooperative also wants to see FERC address the issues on a generic, or at least regional, basis — not ad hoc, transmission owner by transmission owner. The co-op uses behind-the-meter generation, including in Exelon’s territory, and it had urged the commission to reject the initial filing with its language about gross load because that could eliminate the longstanding netting of load it does for customers served by distributed generation.

“ODEC submits that such a piecemeal, TO-by-TO approach to these issues is inefficient and could lead to disparate treatment of co-located load and behind-the-meter generation throughout the PJM region,” the co-op said. “For [load-serving entities] like ODEC that have load in several PJM transmission zones, this disparate treatment can have real impacts on ODEC’s costs for transmission, ancillary service and PJM administrative charges, as well as ODEC’s ability to invest in generation resources and participate in demand response programs.”

Voltus, a virtual power plant provider, said that Exelon’s filings appear to be an attempt to get around FERC’s more general look at the issue with the November conference.

“Exelon provides no quantification of the size or number of facilities that are set to be built with the current tariff in effect, nor the timing of their construction,” Voltus said. “Without these details, Voltus does not understand Exelon’s need to move so expeditiously.”

Public Service Enterprise Group filed a protest arguing that Exelon’s proposal threatens New Jersey’s solar goals, saying it would harm the 90,000 BTM generation customers in its territory by making their service more expensive, and the same could be said for any qualifying facilities.

“The Exelon companies attempt to carve out from ‘all load’ BTMG, QFs and retail net metering arrangements,” PSEG said. “However, they make no effort to explain or justify why it is just and reasonable and not unduly discriminatory for co-located load to be treated differently than BTMG.”

PSEG also made the argument that while the filings claim to only apply to six Exelon utilities, they would modify general terms and conditions of PJM’s tariff, and Exelon lacks that authority. BTMG arrangements have been part of PJM’s rules for two decades, and Exelon’s proposals would threaten that activity, with the RTO’s tariff saying the load of a network customer “does not include the load served by operating” BTMG, PSEG argued.

“The central characteristic of a BTMG configuration is that it provides for the delivery of power from the generator to the co-located load ‘without using the transmission system,’” PSEG said.

The typical rooftop solar customer on PSEG’s system gets an annual bill of $59 from its service charge, but the firm estimated that under Exelon’s proposal, that would balloon to $419/year — a 700% increase. PSEG also estimated that it would impact several university campuses with BTMG by raising their network transmission charges by millions of dollars.

Exelon’s late revisions would carve out traditional BTMGs, but PSEG said that only compounds the filings’ legal flaws.

“As amended, the Exelon filings are unduly discriminatory and preferential in proposing fundamentally different treatment for BTMG arrangements, QFs and retail net metering arrangements on the one hand and co-located load arrangements on the other hand,” PSEG said.

Exelon’s proposal did win outright support from PJM’s Independent Market Monitor, who said in a filing that current proposals for co-located load would provide for “discriminatory treatment” for such customers and impose costs on other consumers.

“Such arrangements between generation owners and co-located loads are not private bilateral arrangements that can ignore the applicable requirements of the PJM” tariff, Monitoring Analytics said. “The core result for co-located load proposals is avoiding the costs assigned to transmission and distribution customers under both state and federal regulation.”

The deals would allow large co-located customers to avoid paying transmission and distribution charges, as well as any regulation by state commissions.

“The core assertion underlying such co-located arrangements, that a co-located load at a power plant can be isolated from the grid, is an illusion,” the Monitor said. “It is not possible to be off the grid. Both the power plant at which the co-located load is sited and the co-located load itself depend on the grid and cannot exist or function without the grid. In addition, the co-located load will continue to rely on the grid for a range of ancillary services including frequency control, reactive, spinning reserves, reserves in general, black start and PJM administrative functions.”

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Brattle Study Likely to Fuel Debate over EDAM, Markets+

A new white paper by The Brattle Group offers a point-by-point comparison of CAISO’s Extended Day-Ahead Market and SPP’s Markets+ that leans in favor of EDAM but stops short of endorsing either market. 

The paper, published Oct. 1, likely will further fuel the ongoing and contentious debate between supporters of the two markets.  

It examines and compares seven design features in each market, including transmission optimization, fast-start pricing, real-time unit commitment (RTUC), procurement of imbalance and flexibility reserves, seams optimization, greenhouse gas pricing and congestion revenue allocation — all of which have been the subject of controversy between the two sides. 

“Many stakeholders in the [Western Interconnection] have suggested that certain market design elements, available in one market but not the other, will have material impacts on market outcomes and customer costs,” the paper says. “We aim to compare specific elements of the two market designs and, where possible, provide evidence that sheds light on where one market’s design is more likely to improve customer outcomes than the other.” 

Brattle produced the study on behalf of PacifiCorp, which in April became the first utility to sign an EDAM implementation agreement with CAISO. A separate Brattle study, released in September, found PacifiCorp could earn up to $359 million a year in net benefits from participating in the ISO’s day-ahead market, nearly double a previous estimate. (See Updated EDAM Study Shows Doubling of PacifiCorp Benefits.) 

“As we look at the future of the West and the next stage of market evolution, it’s clear that the logical next step is the EDAM,” Mike Wilding, vice president for energy supply management at PacifiCorp, said in a statement. “We have to strategically harness as much of the existing transmission and resource diversity of the West as we can, in order to benefit our customers, while maximizing the investments that will meet the evolving needs of the region into the future.” 

While resource diversity wasn’t a focus of the Oct. 1 analysis, the paper’s introduction emphasized Brattle’s finding from previous EDAM benefit studies performed for Western utilities: that the biggest driver of benefits in a day-ahead market will be creating the largest possible footprint containing the greatest diversity of load and resources — a point repeatedly argued by key EDAM supporters. 

“While some of the design differences between Markets+ and EDAM will impact market outcomes and overall market efficiency, they are unlikely to have a material effect on customer savings,” the paper says. “Various analyses of customer benefits from market participation indicate that the largest drivers of customer savings will be … the diversity of load and generation resources available in the markets, and the connectivity between participating members, which all lead to increased economic trading and lower curtailments in the market.” (See Brattle New Mexico Study Shows EDAM Benefits Outpacing Markets+ and NV Energy to Reap More from EDAM than Markets+, Report Shows.) 

Flow-based vs. Contract Path

The core of the paper starts with an examination of a market feature that a core group of Markets+ funders addressed in their most recent “issue alert” covering market seams: transmission optimization. (See Markets+ ‘Equitable’ Solution to Seams Issues, Backers Say.) 

In their Sept. 17 alert, the Markets+ backers contend that, unlike the SPP market, EDAM doesn’t rely on a “full” flow-based approach for optimizing transmission use. 

“As a result, EDAM transfers between [balancing authority areas] and between [transmission service providers] will continue to be subject to contract-path scheduling limits used under the [open access transmission tariff] framework (and currently employed in WEIM [the Western Energy Imbalance Market]),” the alert says. 

The Brattle paper attempts to deconstruct that contention, arguing that both markets will be required to recognize contract path limitations because of “the complex nature of transmission rights” in the West, where the operation of transmission systems largely is decentralized because of the absence of an RTO. 

“This is consistent with both markets’ tariff language filed with the Federal Energy Regulatory Commission, which indicate that both markets plan to recognize contract-path transmission constraints where appropriate,” Brattle says, noting that FERC likely would have directed either market operator to include contract path constraints in their market-clearing processes if they’d proposed “purely” flow-based optimization. 

“Ignoring contract path rights in regional market clearing engines can result in commitment and dispatch decisions that create negative outcomes for neighboring entities,” Brattle writes. “For example, a market dispatch solution using a transmission asset beyond the contracted capacity can create congestion on the asset and impair the utilization of other parties’ transmission rights.” 

Brattle cited the controversy surrounding MISO’s integration of Entergy’s sprawling service territory (now MISO South) as a cautionary example of the consequences of ignoring contract path limitations in market dispatch. In that situation, MISO initially dispatched energy between its North and South regions without considering those limitations, which created parallel flows on neighboring systems and prompted SPP to “file a complaint with the FERC stating that ‘significant intentional, unscheduled incremental power flows are crossing SPP’s system without any corresponding reservation, service agreement or compensation.’” 

Western stakeholders concerned about the impact of contract path limitations would be best served by the entire region joining the same market, Brattle said. 

“This would bring all the physical transmission assets under the control of a single market operator, thereby reducing the need for contract path constraints. Moving towards a joint transmission tariff or a full regional transmission organization would further reduce, and possibly eliminate, the need for contract path constraints altogether,” the paper says. 

Fast-start Pricing

In another section, the Brattle paper plays down the importance of one market feature that Markets+ supporters have argued is an important benefit of the SPP market but notably absent from CAISO’s markets: fast-start pricing (FSP). 

“Some stakeholders have presented analyses suggesting that FSP has a substantial impact on market prices and revenues collected by generation resources that can come online quickly (‘fast-start resources’),” Brattle writes. “However, evidence from several U.S. markets, including SPP, indicates that FSP has a very minimal impact on market prices, impacts relatively few hours, and does not materially increase the market revenues of fast-start resources.” 

The paper points to discrete analyses performed by the market monitors for ISO-NE, MISO and SPP that showed “the overall frequency and magnitude of the price impacts of FSP [in each market] were very small.” 

For example, a MISO study covering 2016 showed FSP affected only 7.7% of real-time clearing intervals and increased real-time prices by just 1 cent/MWh, while an SPP study for 2022 found FSP increased fast-start resources’ day-ahead energy revenues by about 1.5% and real-time revenues by about 0.5%. 

Additionally, Brattle says, PJM’s Monitor “has also indicated that FSP potentially undermines the objective of reducing production cost, and its implementation in the PJM market has distorted efficiency.” 

Brattle also questioned the validity of a 2022 study conducted by consulting firm Energy GPS for Canada-based energy trader Powerex and the Portland, Ore.-based Public Power Council (both key Markets+ supporters). The study found that if CAISO markets had used FSP over 2017-2020, prices would have increased by $15 to $23/MWh and generators would have collected an additional $1.2 billion to $2 billion in market revenues. 

“The analysis informing [the Energy GPS] white paper calculated … fast-start units’ impacts on energy prices as the difference between the marginal cost of starting and running peaking units and the average energy price at regional pricing hubs (NP15 and SP15 in CAISO, plus the Southwest and Northwest regions),” Brattle said. “The study did not simulate a counterfactual market commitment and dispatch solution for the CAISO market to validate this impact, which falls short of the analytical rigor of the analysis conducted by the independent market monitors for the MISO, SPP and ISO-NE markets.” 

Jeff Spires, director of power at Powerex, said his “first impression” was that Brattle’s assessments of FSP was “flawed in multiple areas.” 

“Brattle mischaracterizes the methodology used by Energy GPS to assess the impact of fast-start pricing in the west and misrepresents the results of their analysis,” Spires told RTO Insider in an email, adding that the paper “selectively refers to certain historical data from eastern markets to support its conclusion, while failing to include other more recent metrics demonstrating a significant impact of fast-start pricing in eastern markets, including PJM and MISO.” 

Asked if he could supply those metrics, Spires said the Markets+ funders are compiling the information and will share it when it’s ready. 

Michael Linn, director of market analytics at the PPC, said the Brattle paper “misrepresents” the results of the Energy GPS study, and that the $15-$23/MWh range represented market prices “for the evening peak hours, typically the highest priced hours in the West when fast-start units are most often dispatched.” 

“The Brattle study takes these numbers and compares them to multi-month averages in other studies. The Energy GPS study included an apples-to-apples estimate of average fast-start price impacts that show prices increases by $2 to $4/MWh in Northern California, $4 to $9/MWh in Southern California over the study period, and lower impacts in the Pacific Northwest and Southwest,” Linn wrote. 

Linn said also that “while the Energy GPS study did not perform a counterfactual analysis, the study relied on publicly available data on actual historical fast-start unit dispatch and fuel costs, providing a useful and practical approach based on real-world data.” 

Linn criticized the Brattle report for “narrowly” focusing on “a few criticisms” of FSP and ignoring the “overwhelming evidence” of the benefits of the practice, “most recently echoed by the Western EIM Governing Body expert.” In May, that expert, Susan Pope, told the Western Energy Markets Governing Body that FSP could fix certain “price anomalies” in CAISO markets better than existing mechanisms for compensating fast-ramping resources. (See WEIM Expert Calls for Fast-start Pricing to Address ‘Anomalies’.) 

‘Look Ahead’

The Brattle paper commends CAISO’s markets for using a market-clearing engine that relies on a four-hour “look ahead” period “that enables it to optimize real-time unit commitment decisions for generation resources in the market that can cycle on and off in four hours across the entire market footprint.” 

In contrast, Brattle says, the market-clearing engine that SPP uses for its Western Energy Imbalance Service (WEIS) does not include a similar look ahead or perform RTUC, and the Markets+ tariff doesn’t indicate that practice will be adopted in the newer market. 

“These additional features of the WEIM optimization will allow it to find lower-cost and more operationally responsive solutions relative to the Markets+ real-time clearing that will not perform unit commitment and relies on manual real-time unit commitment decisions,” the paper says. 

Brattle notes the look ahead feature provides an advantage only real-time optimization, but does not affect day-ahead operations, “where both EDAM and Markets+ optimize unit commitment and day-ahead dispatch.” 

In an email to RTO Insider, SPP spokesperson Meghan Sever said the WEIS design is “not relevant to a comparison of Markets+ and EDAM.” 

“WEIS is a separate service provided under a different tariff than Markets+,” Sever wrote. “The study assumes Markets+ will not include real-time unit commitment, although it is clearly defined in the Markets+ tariff filing currently being reviewed by FERC.” 

“We do not say that there is no real-time unit commitment, but rather that the real-time market clearing engine does not perform that function,” John Tsoukalis, a principal with Brattle and the report’s lead author, said in an email. 

Tsoukalis said the section of the Markets+ tariff that lists the outcomes of the “Real-Time Balancing Market” does not include unit commitment, while another section describes unit commitment as being an outcome of the reliability unit commitment process.

Markets+ Wins on Seams

The Brattle study also takes a more favorable view of EDAM’s GHG pricing mechanism, which it says benefits from 10 years of operational experience in CAISO and the WEIM, and the ISO’s process for allocating congestion revenues in its markets. 

But Brattle gives Markets+ higher marks for seams optimization, noting that the SPP market will require all participants along a market seam to offer buy and sell bids for import and exports at the seam — the practice of “intertie trading” — while in EDAM, intertie trading will only be activated if market members choose to do so and at the CAISO balancing authority area border. 

“The automatic inclusion of intertie trading at the Markets+ seam is likely to deliver benefits to market participants, and similar broad availability of intertie trading would be an improvement to the EDAM design,” Brattle wrote. 

‘Independent Evaluation,’ or ‘Limited’

Asked why PacifiCorp commissioned the study, spokesperson Omar Granados said the utility was seeking “to offer an independent evaluation of the market design, including the design differences between EDAM and Markets+. This information will be useful for potential future market enhancements and will help inform decision-making if the Western Energy Imbalance Market participants split their participation between two day-ahead markets.” 

For its part, Brattle said it hoped the paper provides “helpful takeaways for stakeholders in both markets on where the respective designs can be improved in the future, and help the region focus its efforts on developing the markets to enhance the overall efficiency and outcomes for customers.” 

CAISO and SPP offered predictably different takes on the study. 

“We appreciate Brattle’s publication of the comparative design paper between Markets+ and EDAM,” CAISO spokesperson Anne Gonzales told RTO Insider. “The assessment aligns with our perspective that EDAM provides significant reliability and economic value to customers across the West as designed, with the largest seamless footprint possible providing for significant load and resources diversity as well as transmission connectivity, all key factors in enabling those benefits.” 

SPP’s Sever said the RTO hadn’t been invited to participate in the study and was still reviewing the results. 

“Beyond our assessment of the study’s conclusions, SPP also notes that its scope is limited and ignores a number of factors that stand to distinguish it from other options. Production cost studies don’t tell the entire story,” she said. “Apart from the unique Markets+ design elements that will benefit all Western entities, participants will benefit from an independent and transparent governance and robust stakeholder process that values all participants equally.” 

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Long Road Still Ahead for Aroostook Transmission Project

A proposed transmission project to relieve transmission constraints in Maine has received a major boost with the U.S. Department of Energy’s announcement of an up-to $425 million investment in the project.

The funding for Avangrid’s Aroostook Renewable Gateway stems from DOE’s Transmission Facilitation Program, which on Oct. 2 awarded up to $1.5 billion for four projects across the country. (See related story, DOE Funding 4 Large Tx Projects, Releases National Tx Planning Study.) The department would serve as an anchor off-taker for the transmission capacity of the projects, with the goal of de-risking development and increasing outside investment.

Northern Maine is not currently interconnected with ISO-NE, limiting the development of renewables in the area despite high wind speeds and a large amount of undeveloped land.

“Unlocking the enormous wind resource in Aroostook County will deliver economic benefits to this important region of the state and is a necessary step toward Maine becoming energy independent by freeing our residents from the stranglehold of expensive and unreliable oil and gas,” the Natural Resources Council of Maine said in response to the announcement.

“Transmission line development and the ability to connect clean, affordable energy to the New England power grid is one of the most effective tools available to combat climate change while also enabling a stronger, 21st century economy,” Avangrid CEO Pedro Azagra said.

Gov. Janet Mills (D) applauded the Biden administration for the “unprecedented investment” and called the announcement “an exciting step forward and a testament to the tremendous energy opportunity available in Northern Maine.”

Looming Challenges

To unlock renewable development in the northern part of the state, the Maine Public Utilities Commission is planning separate solicitations of transmission capacity and renewable generation. Avangrid’s project would need to be selected by the PUC to proceed with development. The company expects the commission to announce the winning bids in 2025.

Transmission development in New England has faced significant challenges in recent years, and DOE’s support of Avangrid’s project is no guarantee of success.

The PUC’s solicitations come after a previously selected project by LS Power was terminated in December by the commission after the company requested an unspecified price adjustment. LS Power said it could no longer proceed with the fixed price it bid into the solicitation because of delays associated with negotiating contracts with Massachusetts and pressures from inflation, interest rates and supply chain distributions (2021-00369).

LS Power’s project was selected in conjunction with a 1,000-MW wind project by Longroad Energy. According to a study commissioned by LS Power, the projects would have saved Maine ratepayers nearly $900 million over the life of the contracts through lower electricity prices.

Maine transmission system map | ISO-NE

Following the solicitation, the Massachusetts Department of Energy Resources found it would be beneficial for the state’s electric utilities to contract for up to 40% of the generation and renewable energy certificates from the wind project and up to 40% of the line’s transmission service.

The DOER’s authority to participate in the multistate solicitations for transmission expired at the end of 2022, but Massachusetts Gov. Maura Healey (D) included language in a recently introduced budget bill to extend this authority through 2027. (See Mass. Gov. Healey Includes Permitting Reform in Budget Proposal.)

“Our region needs to buy more clean power and retain our existing clean resources to ensure reliability and advance our clean energy transition,” DOER spokesperson Lauren Diggin said. “Massachusetts will continue to seek out opportunities to partner with other states for our collective benefit.”

A spokesperson for Longroad Energy said the company understands why Maine opted to rebid the transmission and generation solicitations, but they said its wind proposal “will be a pivotal investment in Northern Maine and the largest, cheapest source of new clean energy in New England.”

DOE previously agreed to be an off-taker for National Grid’s Twin States Clean Energy Link Project, a proposed bidirectional transmission line connecting New England and Quebec via Vermont and New Hampshire. But despite the federal support, National Grid backed out of the project in March. (See National Grid Backs out of Twin States Clean Energy Link Project.)

Avangrid’s New England Clean Energy Connect (NECEC) project, currently under construction in Eastern Maine, has dealt with significant delays and a roughly 50% cost increase following legal and political challenges, which were heavily funded by incumbent fossil generators. When in service, the NECEC line will allow for the import of Quebec hydropower procured by Massachusetts. (See Avangrid Details Progress on NECEC Tx Line.)

Beyond connecting Northern Maine to the rest of ISO-NE, additional work likely looms to ease transmission constraints between Maine and load centers in Southern New England. In its 2050 Transmission Study, ISO-NE found that the interface between Maine and New Hampshire is likely to face overloads starting in 2035.

Unlocking access to large-scale renewable generation in Northern Maine could put more pressure on these interfaces, while the locations of offshore wind interconnections will also be a major factor in the timing and intensity of potential overloads. (See ISO-NE Analysis Shows Benefits of Shifting OSW Interconnection Points.)

“While the total generation in northern New England is a factor in these overloads, the precise locations of particular generator interconnections in Maine do not affect the probability that the overloads will occur; most of the power generated in this subregion still ultimately flows down through the major lines leading into Massachusetts,” the study found.

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Regulators Worry Data Centers Consume Too Much Clean Energy

The growing trend of pairing power-hungry data centers with clean energy resources is sparking mixed feelings among some regulators. 

On the one hand, the planned reopening of Three Mile Island Unit 1 will supply Microsoft with energy through a power purchase agreement. It’s also likely to supply some energy to the local grid, helping with decarbonization, according to Maryland Public Service Commissioner Michael Richard, who spoke during a WECC webinar on large loads Oct. 2. 

But Richard was more concerned about the Susquehanna nuclear power plant in neighboring Pennsylvania, where Talen Energy wants to amend the interconnection service agreement to send some output to a co-located Amazon Web Services data center rather than to PJM. (See With Three Mile Island Restart, Debate Continues on Co-located Load in PJM.) 

Richard also voiced concern about the possibility of data-center co-location at Calvert Cliffs nuclear plant, which he described as “one of those bedrock, in-state assets that we depend on.” Maryland imports about 40% of its electricity, he noted. 

“As we drive toward decarbonization and cleaner resources, if we lose what we have, and just end up … importing and enabling the continued operation of coal plants and other fossil plants, that really doesn’t advance some of our goals,” Richard said. 

Richard was more enthusiastic about co-location of data centers with potential wind facilities off the Maryland and Delaware coasts, where he said the centers could help make the economics of offshore wind work. 

Resource Shortage

The webinar was part of WECC’s “Reliability in the West” discussion series. The focus of the Oct. 2 session was “large load experiences.” 

Kris Raper, WECC’s vice president of external affairs, said the discussion had hit on a challenge that the West, and perhaps the entire nation, is facing. 

“We don’t have enough resources to meet what is already going on,” Raper said, pointing to electrification and efforts to bring clean resources to the grid. 

Webinar panelist Glenda Oskar, an economist in the Department of Energy’s Office of Policy, said DOE is looking at ways to help new data centers. One possible approach is siting data centers at retired coal plant locations, where existing infrastructure could be used. 

DOE also wants to aid in the commercialization of “clean, firm technologies” that could benefit data centers, Oskar said. Those include next-generation geothermal, advanced nuclear and long-duration storage. 

Webinar panelist Travis Metcalfe, energy projects manager at Amazon Web Services, said not all data centers are the same. 

At some centers, customers might simply be looking for a place to back up their data once a day without using much energy. 

“Then you have … AI and machine-learning models, which might be using enormous amounts of electricity,” Metcalfe said. 

Back-up Generation

Even though Northern Virginia, the world’s largest data center market, is just across the Potomac River from Maryland, Richard said he didn’t encounter data center issues at the Maryland PSC until recently. 

In 2023, a data center developer filed for an exemption from the PSC’s certificate of public convenience and necessity (CPCN) requirement for 168 backup diesel generators totaling 504 MW. 

Initially, the commission rejected the request. But recognizing the state goal of promoting data center development, the commission later approved a waiver for 25 generators totaling about 70 MW — enough for the first phase of the project, Richard said. 

The issue then ended up before the Maryland legislature. A bill requested by the governor (SB 474/HB 579) was introduced this year to remove the CPCN requirement for backup power at “critical facilities,” which include hospitals, health care facilities and data centers. 

The legislature passed the bill, which took effect July 1. 

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EEI Projects Need for 42.2M Charge Ports by 2035

The Edison Electric Institute has ratcheted up its projections of U.S. electric vehicle adoption, and with it the number of charging ports and grid upgrades that will be needed. 

EEI on Oct. 2 released “Electric Vehicles Sales and the Charging Infrastructure Required Through 2035,” an update of a 2018 report that looked as far ahead as 2030. 

The 2018 edition predicted that 18.7 million light-duty EVs would be on U.S. roads by 2030 and said they would need an array of 9.6 million charge ports to keep running. 

After six years of rapid EV sales growth, the updated report predicts 34.4 million light-duty EVs will be on the road in 2030 and 78.5 million in 2035. To support them, it calculates a 2035 need for 42.2 million charge ports. 

EEI based the new numbers on four independent forecasts analyzed by the National Renewable Energy Laboratory. In announcing the new report, EEI said significant infrastructure upgrades to support this change already are underway, but more are needed. 

EEI

The Edison Electric Institute in a new report projects there will be 78.5 million light-duty electric vehicles on U.S. roads by 2035. | EEI

EEI Senior Vice President of Customer Solutions Phil Dion said in the news release: “We are excited to continue working with our members around the country to evaluate grid capacity and other infrastructure needs due to the growing number of EVs in their service territories. Our members remain committed to supporting policies, especially those focused on proactively enhancing the energy grid, to ensure the transition to EVs is done in a cost-effective way that is also convenient, equitable and seamless for all drivers.” 

The report does not factor in the substantial need for additional public charging infrastructure that would be created by large-scale electrification of medium- and heavy-duty vehicles. 

The report indicates that electric companies are preparing for this demand in many ways, including developing make-ready infrastructure for site hosts that will procure the charging equipment, installing and owning the charging infrastructure themselves, offering rebates to defray the costs of buying and installing charging equipment, offering time-of-use rate structures, requiring demand response capability for charging equipment and educating EV drivers and charger site hosts.  

The report states that EV charging will not only create unprecedented growth in demand, but also may create localized pinch points, particularly along highway corridors, where large charging stations would be needed if there is a wholesale switch to EVs for long-distance travel. 

The authors cite recent studies by National Grid, Xcel Energy and other electric companies showing that grid upgrades and proactive planning should begin as soon as possible to meet future demand. (See Study Projects Power Demands of Highway EV Charging Network and DOE Funds Studies of Heavy-duty EV Charging Network Needs.) 

The authors noted that The Electric Power Research Institute has launched its EVs2Scale2030 initiative to start working toward the “unprecedented” coordination of diverse stakeholder groups that will be needed to enable a national transition to EV travel. 

Notwithstanding the recent fluctuations in the EV industry, most projections call for steadily increasing EV adoption. 

EEI said improvements in battery technology, decreases in vehicle costs and favorable federal/state policy decisions have caused the EV market to expand and caused the growth projections to increase. 

There are unknown variables, including the future popularity of plug-in hybrid vehicles (PHEVs), which combine an internal combustion engine with a battery smaller than those in battery electric vehicles (BEVs).  

PHEVs cannot use DCFCs, the fast-working chargers that cost substantially more to install and place much higher demand on the grid than L1 and L2 chargers. 

If enough American car buyers choose PHEVs over BEVs, fewer DCFC ports will be needed. The report indicates that 15% PHEV adoption could save several billion in capital costs for charging infrastructure compared with 10% adoption. 

The reported projects that 325,000 DCFC ports will be needed in 2035, each with a price tag potentially ranging into the six digits, and they will be critical to soothing the range anxiety that deters some car buyers from considering BEVs. 

But that is less than 1% of the projected total number of ports, the report says. The other 99% are L1 and L2 chargers — 85% at residences, 7% at workplaces or multifamily dwellings and 7% at public charging sites. 

EEI is the industry association for U.S. investor-owned electric companies. 

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MISO: Lower Prices, Fewer Outages and Annual Peak in August

MISO reported relatively lower costs and outages in August while it served its annual peak late in the month.

MISO averaged 86 GW load over August, about 1 GW lower than August 2023’s average, according to MISO’s monthly operations report. MISO’s 122-GW annual peak arrived in the afternoon on Aug. 26 during a heat wave and a maximum generation warning. (See Late August Heat Wave Delivers 122-GW MISO Summer Peak.)

The summertime peak was lower than 2023’s 125-GW peak, which was set nearly a year to the date earlier during a separate heat wave and maximum generation warning.

Average daily generation outages were down year over year, at 30 GW, an 8 GW improvement over last August.

Real-time locational marginal prices also were down year over year, at $26/MWh from $33/MWh. However, natural gas and coal prices remained static from 2023 at $2/MMBtu. The pricing was a far cry from 2022, when August saw average real-time prices of $87/MWh and $8/MMBtu coal and natural gas prices.

Natural gas delivered the greatest share of terawatt hours this August, at 28 of the month’s total 62 TWh. Coal supplied 17 TWh, a stark contrast from the 26 TWh coal managed in August 2021.

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DOE Funding 4 Large Tx Projects, Releases National Tx Planning Study

The U.S. Department of Energy has announced two actions to support the expansion of the transmission grid: investing up to $1.5 billion in four specific projects around the country and releasing the final National Transmission Planning Study. 

The $1.5 billion investment from the Transmission Facilitation Program was authorized by the Infrastructure Investment and Jobs Act. DOE is giving the money upfront to four projects, which eventually can sell it to actual users, at which point the department will get its money back to use on future transmission projects, Deputy Energy Secretary David Turk said on a call with reporters Oct. 1.

“Like many things about the clean energy transition, building new transmission is extremely challenging, and it’s also extremely urgent,” Turk said. 

DOE announced the first three lines under the TFP last fall; all three have signed deals with the department, Turk said. In total, the TFP should help build more than 3,000 miles of new transmission by early next decade. (See DOE to Sign up as Off-taker for 3 Transmission Projects.) 

Avangrid Network’s Aroostook Renewable Gateway in Northern Maine will negotiate for DOE for funding of up to $425 million to build the 111-mile project that seeks to link up to 1,200 MW with ISO-NE. The region lacks direct connections with the rest of New England, and the line would help three mature wind projects connect to the market, with the potential for more wind and solar development. 

Invenergy’s Cimarron Link Transmission is negotiating for TFP funds of up to $306 million to build its 400-mile HVDC line running from Oklahoma’s panhandle to Tulsa in the east, opening 1,900 MW of transfer capacity that can deliver wind and solar to load centers.

Pattern Energy’s Southern Spirit Transmission project also is up for negotiations for $360 million to help get the 320-mile, 525-kV HVDC line that would connect ERCOT to the Southeast. The line can ship up to 3,000 MW of renewables from Texas to the Southeast and can ship power the other way if demand spikes in Texas. 

Southern Spirit could better help ERCOT make it through a cold snap, avoiding some of the devastation seen during Winter Storm Uri in 2021, White House National Climate Advisor Ali Zaidi said. 

“This buildout is really transformational in breaking down the barrier between ERCOT and the rest of the country, and it feeds into this broader insight that this administration has pushed, which is essentially [that] interregional transmission translates to lower costs for consumers and higher reliability across the system,” Zaidi said. 

Southern Spirit has been under development for years, with FERC finding in 2014 that it would not trigger federal regulation over ERCOT, according to a fact sheet from Pattern. 

Phase 2 of Grid United and Black Forest Partners’ joint Southline Transmission Project would add a 108-mile, 345-kV line capable of delivering 1,000 MW of capacity across New Mexico, helping to support electricity delivery in the Southwest. It is up for $352 million. Southline Phase 1 was in the first set of projects announced last year. 

“You need only to look at the recent devastation of Hurricane Helene to know how the climate crisis is already straining our existing grid infrastructure at the precise moment when we need that infrastructure to be larger, stronger and more reliable,” White House Senior Advisor John Podesta said.

National Transmission Planning Study

The National Transmission Planning Study features a set of long-term planning tools and analyses that examine potential scenarios through 2050, including various interregional transmission expansions. 

It shows the highest level of grid reliability can be maintained at the lowest cost by coordinating interregional transmission. The study was developed by the DOE Grid Deployment Office alongside the National Renewable Energy Laboratory and the Pacific Northwest National Laboratory, who said they want other planners to use it in their efforts. 

A substantial expansion of the transmission system throughout the entire contiguous U.S. delivers the largest benefits of up to $270 billion to $490 billion through 2050. Every dollar invested in transmission leads to returns of $1.60 to $1.80 in system costs saved, the study found. 

Being able to coordinate resource adequacy across better connected regions lowers systems costs by $170 billion to $380 billion, the study found. 

The use of HVDC transmission technologies with multiple terminals — meaning power can be sent bidirectionally and from multiple entry and exit points in regions — was shown to be the most cost-beneficial way to stitch together a macrogrid across the Lower 48. 

“When translating zonal scenarios to nodal network models, HVDC was found useful for transferring power over long distances and between interconnections, but AC network expansion will continue to be the best solution for a large portion of transmission additions,” the study said. “Large interregional HVDC network solutions will also require additional strengthening of the regional AC networks they interconnect.” 

DOE has been working on the NTP since 2022. Its goal was to identify pathways that maintain current levels of reliability and saving costs while meeting local, regional and national interests, Grid Deployment Office Director Maria Robinson said on a call with reporters. 

“This study goes down to the nodal level, instead of at the zonal/regional level, and that means that this is a tool that utilities can actually use to help them determine what kinds of investments that they might want to make,” Robinson said. 

So far, interregional transmission plans have been limited, with Robinson pointing to MISO and SPP’s Targeted Interconnection Queue Study as a rare example of it actually happening. 

“So, this is why we think it’s important to make sure that these tools are available, so that it is easier for those folks who are looking to do so, and also so that we’re able to use the best-in-class modeling available from the National Laboratories,” she added. 

DOE is not going to tell FERC how to do its job, she added. Chair Willie Phillips has said the commission could look at interregional planning in the future, noting that NERC’s interregional transfer capability is due at the end of the year. (See Webinar Examines How FERC Could Use Interregional Transmission Study.) 

The department has provided some technical assistance to NERC on its interregional transfer capability study and offered updates on what was being developed in the NTP, Robinson said. 

“Of course, while doing coordination, it doesn’t mean that the exact thing will happen in both places,” Robinson said. “So, we are really looking forward, as everyone else is, to seeing the ultimate results come out of that study. But a lot of the fundamentals are relatively similar, and it’s just nice to see this greater interest in interregional transfer capacity, understanding that it can be so important in times like right now in extreme weather events.” 

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CAISO Launches Phase 2 of Pricing Issues Initiative

CAISO on Sept. 30 launched Phase 2 of its Price Formation Enhancements Initiative, aimed at addressing issues specific to market power mitigation, scarcity pricing and fast-start pricing in its markets — including the Western Energy Imbalance Market and Extended Day-Ahead Market.

“These enhancements aim to improve the accuracy of our market clearing prices, provide better market price signals, and enhance incentives for resources to perform,” James Friedrich, CAISO lead policy developer, said during a meeting to launch the effort. “It is the general view of the [Price Formation Enhancements] working group that enhancements in these areas could help the market become a more effective steward of reliable outcomes.”

Phase 1 of the initiative hosted 18 working group meetings and resulted in a FERC-approved tariff change that allows hydroelectric and energy storage resources to bid above the ISO’s $1,000/MWh soft offer cap. (See FERC Approves CAISO Request to Lift Soft Offer Cap for Hydro, Storage.)

Scarcity Pricing

Scarcity pricing, a mechanism to determine market prices when supply falls short of demand, came into focus for CAISO following grid emergencies during the summers of 2020, 2022 and 2023, Friedrich said.

The increased risk that comes with declining reserves and a rising loss-of-load expectation should translate into the market’s willingness to pay more for additional reserves to maintain reliability. And while the ISO already relies on a number of different scarcity pricing mechanisms — including the scarcity reserve demand curve, the flexible ramping product and bidding above the soft offer cap — ISO staff and stakeholders saw a need to improve on those mechanisms to ensure more efficient market outcomes and maintain grid reliability.

“It’s important to note that while these mechanisms provide a good foundation for scarcity pricing in our markets, this initiative considers potential enhancements to ensure that they accurately reflect scarcity conditions across the entire market footprint and across all market intervals,” Friedrich said.

Staff and stakeholders have identified four key issues around scarcity pricing.

First, the market is inconsistent in how it procures ancillary services, a function not applicable to the WEIM or EDAM. The real-time market only procures incremental ancillary services for the CAISO balancing authority area (BAA), rather than fully re-optimizing them, Friedrich said. The market also doesn’t re-optimize in the five-minute market, leading to less efficient scarcity pricing outcomes and procurement.

Second, prior working groups also identified potentially outdated penalty prices, which currently are tied to the market bid cap and may not accurately reflect the true reliability value of a resource during scarcity events, Friedrich explained. Stakeholders also expressed concern the prices may be too low to provide effective incentives.

The third issue relates to potential disconnects between market prices and grid conditions during emergencies. The current market design may not adequately reflect the severity of emergency conditions in market prices, Friedrich said, leading to situations in which prices don’t align with the actual scarcity level indicated by emergency operator actions.

The last problem centers around insufficient scarcity signals. The scarcity reserve demand curve and power balance constraint violations in the market only get triggered during actual shortages, Friedrich said, which can result in price spikes that are “volatile and unpredictable.”

“Collectively, these issues point to the need for reform of our scarcity pricing mechanism, and by addressing these problems we aim to improve market efficiency, enhance reliability and provide more accurate price signals that reflect real-time grid conditions,” Friedrich said.

Elaborating on the initiative’s main objectives, Friedrich highlighted three main goals:

    • to improve market signals during tight supply conditions so that prices accurately reflect the true state of the grid;
    • to incentivize resource performance and demand reduction; and
    • to align prices with real-time grid conditions across the WEIM.

But two significant hurdles stand in the way of achieving these goals, Friedrich said. The first is the need to address discrepancies in how scarcity pricing applies across different balancing authorities in the market, while the second is the need to identify a “consensus-driven method to scale and anchor penalty prices.”

Market Power Mitigation

Friedrich said CAISO also must change rules around market power mitigation, which prevents the exercise of structural market power when a BAA is price-separated from CAISO.

Three main problems were identified in prior working groups: structural market power may be overestimated in individual BAAs; the CAISO BAA is excluded from the market power mitigation test; and the frequent mitigation during off-peak hours with low prices raises questions about current triggers.

The top priority is to ensure competitive pricing while refining mitigation mechanisms for WEIM and Extended-Day Ahead Market (EDAM) BAAs.

Fast-start Pricing

Friedrich also gave an overview of fast-start pricing, which integrates commitment costs of fast-start resources into market prices.

“Fast-start pricing recognizes that fast-start resources may serve as the marginal resource used to meet the next increment of energy or operating reserves demand,” Friedrich’s presentation said. “However, they often have output levels that prevent them from being fully dispatchable and thus are often ineligible to set the LMP.”

Phase 1 included a stakeholder-requested analysis to determine the potential market impact of fast-start pricing and whether it should be implemented. The analysis demonstrated a “generally moderate” impact, and some stakeholders saw value in continuing to prioritize the topic in discussion, while others didn’t. While members of the working group haven’t reached consensus, they mostly supported a deeper analysis of fast-start pricing.

Supporters of SPP’s Markets+ have pointed to the absence of fast-start pricing as a shortcoming of the EDAM.

The working group’s next Phase 2 meeting is tentatively scheduled for Oct. 23, and the target date for a straw proposal is May 25, 2025.

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FERC Rejects Mabee’s 2021 Supply Chain Complaint

FERC on Oct. 1 rejected a three-year-old complaint by security gadfly Michael Mabee requesting the commission order an audit of the electric grid looking for potentially harmful equipment manufactured in China and reliability standards requiring any new Chinese equipment to be tested for harmful capabilities (EL21-99). 

Mabee filed his complaint in August 2021, citing contemporary reports from media outlets and government officials that China had conducted “a campaign of cyberattacks” against critical U.S. infrastructure, including the energy sector. Specifically, he warned that U.S. electric utilities bought equipment made in China and installed it on the grid. 

This “could facilitate a cyberattack” by the Chinese government, Mabee asserted, particularly because — as he said — there were no requirements by the U.S. government or in NERC’s standards that entities inspect Chinese equipment for cyber risks and vulnerabilities either before or after installation. 

To address these supposed risks, Mabee requested the commission direct NERC to: 

    • survey all registered entities in the electric grid to find out “what Chinese equipment or systems” are in use; 
    • submit a proposed reliability standard for “testing and security of Chinese equipment or systems” that are in use on the bulk power system or purchased in the future; and 
    • work with state regulators to encourage adoption of the proposed standard or a state equivalent on the parts of the grid under state jurisdiction. 

NERC responded to Mabee’s complaint in 2021, arguing that FERC should deny his request on the grounds that several existing Critical Infrastructure Protection (CIP) standards already required entities to assess risks to the grid when acquiring applicable electronic systems. The ERO said that if the CIP standards identified a specific foreign nation by name, as Mabee requested, it might be harder to apply them to “other nation-states that may pose a threat.” (See “NERC Argues to Dismiss Supply Chain Complaint,” NERC Seeks FERC Approval to Fund Office Move.) 

Other commenters were more sympathetic to Mabee, FERC noted in its order. The Secure the Grid Coalition — a security-focused think tank to whose website Mabee has contributed several articles — suggested FERC conduct a technical conference, possibly in conjunction with a special task force, to “determine the potential threat posed [to the grid] by Chinese transformers and other grid control and monitoring systems.” 

The Foundation for Resilient Societies — a nonprofit aimed at “boosting critical infrastructure resilience and recoverability” — also requested that FERC, NERC and other agencies conduct an investigation into the threat posed by Chinese equipment. In addition, several individuals filed comments expressing support for Mabee’s position and urging the commission to take the threat of Chinese infiltration into the power grid seriously. 

Mabee himself has followed up his original complaint with multiple subsequent filings prodding FERC to take action. His most recent filing was this February, when he submitted data from the Census Bureau purportedly showing the U.S. imported 449 transformers of more than 10,000 kVA from China between 2006 and 2023. 

FERC Sides with NERC

FERC agreed with NERC that “the relief sought [by Mabee] is duplicative of existing reliability standards, as well as past and ongoing efforts by the commission and other federal agencies.” 

In addressing Mabee’s request for an audit of electric utilities for Chinese equipment, FERC observed that NERC can “assess the risks associated with foreign owned suppliers” through existing means such as NERC Alerts. It cited two such alerts, issued in 2019 and 2020, requesting information from registered entities on exposure to cyber risks from equipment manufactured in China, Russia and other foreign adversaries. 

FERC also sided with NERC in its defense of the CIP standards, and noted its own activities, along with other federal agencies, to address the risks posed by equipment manufactured overseas. Since Mabee’s complaint, FERC has held two technical conferences in 2021 and 2022 covering cyber risk management in the power sector and supply chain security challenges in the power grid. 

Concerns over China’s cyber prowess in recent years have focused more on its capabilities in software than in hardware. Last year Volt Typhoon, a cyber actor connected to China by the Cybersecurity and Infrastructure Security Agency and other security organizations, was accused of infiltrating U.S. critical infrastructure organizations disguised as legitimate users. 

In a congressional hearing this year, FBI Director Christopher Wray called China’s cyber posture “the defining threat of our generation” and warned that the country’s hackers were preparing “to wreak havoc and cause real-world harm to American citizens and communities.” (See China Preparing to ‘Wreak Havoc’ on US, Cyber Officials Warn.) 

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OSW Industry, Advocates See Hope in NE Multistate Procurement

Even as the offshore wind industry continues to struggle, stakeholders’ hopes have been buoyed by the recent multistate procurement in New England, they said during a webinar held by the Northeast Energy and Commerce Association on Oct. 1. 

Massachusetts selected up to 2,678 MW of offshore wind capacity in early September, while Rhode Island selected 200 MW. (See Multistate Offshore Wind Solicitation Lands 2,878 MW for Mass., RI.) 

“I think Massachusetts was pretty bold in doing procurements of this size, and I think that’s going to help get offshore wind back on track,” said Ken Kimmell, chief development officer at Avangrid Renewables. 

Kimmell said he is “starting to see the ship righting itself” in the wake of the price shocks that caused a wave of project cancellations in 2023. 

Massachusetts and Connecticut are in talks for Connecticut to purchase the remaining 400 MW of the Vineyard Wind 2 project in exchange for Massachusetts purchasing some power from the Millstone nuclear plant, which currently is propped up by a contract with Connecticut. 

The rapidly increasing costs of offshore wind have caused some trepidation from New England lawmakers; the 2,678 MW selected in the multistate procurement fell significantly short of the 6,000 MW initially sought by the three states. 

While the prices for the procurement will not be announced until the contracts are filed with state utility regulators, the cost of offshore wind per megawatt-hour has roughly doubled in just a few years. 

“The last couple years have been hard for the offshore wind industry … but I think the future is bright,” said Moira Cyphers, director of Atlantic offshore and eastern state affairs at the American Clean Power Association. “This is a resource that we absolutely have to have. The climate goals and the reliability goals don’t happen without offshore wind.” 

Despite the current cost pressures, Cyphers said procuring projects at scale “is really what’s going to bring down costs over time.” 

Cyphers added that the first line of projects will shoulder costs associated with building up the domestic supply infrastructure, ports and shipping capabilities, which “future projects will then build on.” 

Kimmell echoed the need to improve the domestic supply chain and added that increasing global demand for offshore wind has exacerbated the recent cost increases. 

“Supply and demand are out of whack,” Kimmell said. “We are at a real disadvantage relying so much on European suppliers.” 

Kimmell also voiced his support for longer contracts for offshore wind resources. 

“It [would] reduce prices to ratepayers if Massachusetts were to extend the length of contracts,” Kimmell said, noting that the current generation of turbines will last “quite a bit longer than 20 years.” 

Cyphers said more flexibility regarding economic adjustment mechanisms could help improve future solicitations. 

“I think flexibility is going to become a lot more important at this stage in development,” Cyphers said, noting that Connecticut, Massachusetts and Rhode Island each took slightly different approaches to the inflation indexation options they gave to developers. Ultimately, no indexed project bids were selected. 

“I think to the extent that we can work to identify other ways to introduce flexibility, and make sure these procurements become more standardized, we’ll see more success in the future,” Cyphers said. 

Ben D’Antonio, manager of transmission strategy and economic analysis for Eversource Energy, stressed the need to develop transmission solutions to add “certainty and clarity” to the process of interconnecting offshore wind projects. 

He expressed hope that state-level efforts to reform permitting and siting procedures, coupled with FERC’s new interconnection requirements, eventually will help to speed up development timelines, which currently take about a decade for offshore wind projects. 

While developers have limited insight on where the best places to interconnect are, D’Antonio advocated for a more proactive transmission development approach. He floated the idea of charging a fixed fee for projects to interconnect so developers could “know ahead of time what it’s going to cost to interconnect.” 

“We want to try out this ‘build it and they will come’ approach,” D’Antonio added. “There’s no transition without transmission.” 

This year, FERC approved a proposal from ISO-NE and the New England states that would enable the states to make transmission investments to meet long-term needs, including needs associated with new offshore wind generation. (See FERC Approves New Pathway for New England Transmission Projects.) The six New England states also recently won a $389 million Department of Energy grant that largely will be dedicated to building substations to connect offshore wind to the grid. (See DOE Announces $2.2B in Grid Resilience, Innovation Awards.) 

Kimmell echoed D’Antonio’s comments about the need for proactive transmission planning, saying a line-by-line approach to transmission solutions makes sense for the initial projects coming online, but not for the next wave. 

“We certainly embrace the idea of shared transmission and planned transmission,” Kimmell said, advocating for the socialization of some of the costs associated with building transmission for offshore wind.