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July 22, 2024

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FERC Sets Dynegy’s MISO Market Manipulation Case for Hearing

Nearly a decade after the MISO capacity auction in which Dynegy was found to have manipulated clearing prices, FERC has directed hearing and settlement procedures in the case (EL15-70, et al.).

The commission’s June 6 order initiated a hearing to resolve the issue while denying Dynegy’s request for oral argument before FERC. The commission had been considering briefs from Dynegy and complainants Public Citizen and the Illinois Office of the Attorney General on whether Dynegy should refund $429 million to Illinois ratepayers.

Two years ago, FERC staff concluded that Dynegy knowingly manipulated the 2015/16 Planning Resource Auction to produce Southern Illinois’ Zone 4 clearing price of $150/MW-day. FERC’s arrival at that conclusion followed a twisty course, including an abruptly closed nonpublic investigation, an initial finding that cleared Dynegy with little explanation, a remand from the D.C. Circuit Court of Appeals and an announcement that the commission would revisit its decision. (See FERC Staff Finds Dynegy Manipulated 2015 MISO Capacity Auction.)

In its briefs, Dynegy maintained the process unfurled unjustly, saying FERC’s order on remand “reflects bad policy, is fundamentally unfair and is inconsistent with existing norms.” It said the commission improperly raised questions about the “finality” of its decision to close the investigation while “importing” nonpublic information gathered in an investigation under Federal Power Act Section 222 into a public proceeding under Section 206.

“According to Dynegy, this departure from policy, this departure from policy ‘threatens public confidence in the integrity of [FERC’s] enforcement process’ and ‘negatively affect[s] the perceived fairness of commission investigations,’” the commission said.

Dynegy also argued its due process was violated because the commission’s Office of Enforcement had to file a remand report outlining allegations in a Section 206 proceeding using evidence from its closed, nonpublic investigation. Because of the nonpublic nature of the investigation, Dynegy said it couldn’t participate in discovery or cross-examination.

It claimed the remand order exceeded FERC’s authority because, according to the commission itself, a Section 206 filing isn’t the “proper vehicle to prosecute claims of market manipulation.”

The Illinois AG and Public Citizen fired back that “Dynegy cannot now claim, at this late stage of the proceeding, and at the risk of further delay, that its procedural rights have been violated due to the absence of an evidentiary hearing that it never requested.”

FERC said its actions were “an appropriate response” to the D.C. Circuit’s findings, were consistent with its precedent and do not rise to violations of due process.

“We acknowledge that this case, and the issues that the commission must address on remand, present complicated questions regarding the interplay of the closed FPA Section 222 investigation and resolution of the still-pending FPA Section 206 complaints,” FERC said. It added that it takes seriously its decisions to disclose nonpublic information from its investigations and doesn’t foresee itself regularly releasing such information in the future.

“However, we continue to conclude that submission of the remand report and the opportunity for parties to submit initial and reply briefs was an appropriate response,” the commission said.

FERC also pointed out that it’s allowed to release nonpublic information from an investigation and that it’s common practice for it to initiate further briefings following a remand, “particularly where an appellate court rules that the commission failed to adequately explain its decision.”

Dynegy also argued that it wasn’t made aware via Enforcement staff that its behavior leading up to and during the 2015/16 auction could constitute market manipulation. It said it didn’t have a legal or regulatory requirement to sell capacity, nor was it “on notice” that FERC expected it to do so.

The commission didn’t buy the second argument from Dynegy and ruled the company had “adequate notice that its behavior could constitute market manipulation under relevant commission regulations and precedent.”

FERC pointed out that Enforcement staff said in their briefs that Dynegy took pains ahead of the auction to increase the chance an offer from it would set the clearing price in Zone 4. Staff said Dynegy “engaged in a scheme to amass and hoard megawatts that might otherwise have been offered into the 2015/16 auction at a zero price, thereby increasing the likelihood that a non-zero-priced Dynegy resource would be the marginal resource and set the Zone 4 clearing price.”

The division said evidence pointed to Dynegy expecting that the 2015/16 auction would clear below its lowest non-zero offer of $108/MW-day. Rather than submit all its supply at the cost-based $108 price, Dynegy engaged in pre-auction sales at approximately $66/MW-day until it offloaded enough supply to create a specific gap and therefore ensure its own resource would set the clearing price in the zone.

Staff said Dynegy then took steps to maintain the gap by increasing the price of the capacity component of its retail sales offers from $66/MW-day to $164/MW-day, resulting in 125.4 MW of unsold capacity, and refusing to offer a price to two customers for 385 MW of capacity.

“Dynegy also sought to increase the ‘gap’ by purchasing 50 MW of capacity for $61/MW-day — an act that made no economic sense given that it already held thousands of megawatts of unsold capacity,” Enforcement staff wrote.

The company claims its actions were “motivated by a legitimate intent to recover its costs,” not to commit fraud. It said after it lost money in the 2013/14 auction, it devised a strategy to recover its costs by offering capacity both prior to and in auctions. Dynegy said its attempts to receive price signals that could help it make decisions, including resource retirement, were “not only economically rational, but the only way for an independent power producer, reliant on market revenues, to stay in business.”

Vistra, which acquired Dynegy in 2018, said it disagrees with FERC setting the case for hearing. In an email to RTO Insider, Vistra insisted that the matter has “been investigated several times and adjudicated in Dynegy’s favor,” and it continues to believe “Dynegy’s actions were completely appropriate.”

“When FERC cleared Dynegy in 2019, they found that no market manipulation occurred and that the MISO 2015/2016 capacity auction results were just and reasonable. No new facts, circumstances or evidence have come to light in the five years since that decision,” Vistra said, adding that it will participate in the FERC-directed settlement discussions.

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FERC Allows Berkshire Utilities to Earn Market-based Rates in WRAP

FERC on June 7 approved tariff revisions by Berkshire Hathaway Energy subsidiaries PacifiCorp, Nevada Power and Sierra Pacific Power that will enable the utilities to earn market-based rates when participating in the Western Resource Adequacy Program (WRAP). 

As noted in the commission’s order (ER24-851), the Western Power Pool’s (WPP) WRAP does not intend to be a centralized market for capacity or energy, but rather a voluntary planning and compliance framework for resource adequacy that facilitates the ability of participants to meet capacity shortfalls through bilateral transactions. 

“As proposed, transactions in the [WRAP’s] Operations Program (notably the energy deployment and its associated total settlement price) would be market-based rate transactions conducted under existing authorities and frameworks on a bilateral basis between participants,” the commission wrote. 

The WPP’s initial plan was to avoid requiring WRAP participants to file individual market-based rate filings and instead rely on a structure of indexed-based prices to settle the bilateral transactions, contending the system would prevent the exercise of market power among participants. 

Despite that measure, FERC was concerned some participants still would be transacting in balancing authority areas (BAAs) in which they had been found to exercise market power, and that existing market-based rate requirements imposed on individual participants still would apply. 

“With regard to the price index component of WRAP’s structure, the commission found that the Western Power Pool’s proposal was ‘not sufficient to demonstrate that a price index may be used by specific participants that lack market-based rate authority or are subject to market-based rate mitigation,’ as it failed to address whether the proposed index-based price was a just and reasonable rate for such participants,” FERC noted. 

But recognizing that existing restrictions on market-based rate authority (MBRA) could impede a participant’s ability to transact at WRAP tariff-specified rates, the commission said such a participant could submit a Federal Power Act Section 205 filing “to seek new market-based rate authorization with appropriate mitigation or propose to amend its current market-based rate tariff to include tailored mitigation for the commission to consider.” 

No Market Power

In their Section 205 filings, the utilities pointed out they lack MBRA in their own BAAs, as well as in some first-tier — or interconnected — BAAs. 

“They note, however, that the WRAP tariff obliges them to deliver physical power to a neighbor in need, which could be to a balancing authority area where their market-based rate authority is mitigated. They assert that complying with the WRAP tariff could cause them to exceed the authority in their market-based rate tariffs,” the commission wrote. 

The three utilities proposed to rely on the liquid hubs specified by the WRAP: Mid-C in Washington and Palo Verde in Arizona. The utilities contended they would not set the market price for any transactions in the WRAP and would be price takers, with all sales settled at the price index for each region. 

“Applicants argue that allowing them to amend their market-based rate tariffs to use index prices when selling to counter-parties under the WRAP tariff would be just and reasonable under Order No. 697, where the commission stated it would allow mitigated sellers to use an index or locational marginal price proxy ‘on a case-by-case basis based on their individual circumstances’ rather than defaulting to cost-based rates,” FERC wrote. 

The utilities also argued that Mid-C and Palo Verde meet the commission’s liquidity requirements for use in jurisdictional tariffs. 

“PacifiCorp states that it routinely makes sales at both the Mid-C and Palo Verde hubs and has engaged in sales of millions of megawatt-hours at both the Mid-C and Palo Verde hubs since 2019. Nevada Power and Sierra Pacific did not make any representations about their sales at either the Mid-C or Palo Verde hubs,” but they did note they trade more frequently at the Mead hub in Nevada, FERC said. 

PacifiCorp said it trades only lightly at Palo Verde and, while trading more heavily at Mid-C, it does not report its transactions at either hub to price indexers and therefore could not influence the WRAP settlement price at either hub. 

The commission clarified that its acceptance of the changes to the market-based rate tariffs for the utilities is limited to WRAP transactions and predicated on program provisions that restrict the potential for the exercise of market power. 

“As applicants note, under the WRAP design, when load-responsible entities choose to join WRAP, once committed under the Operations Program, they are obligated to comply with its requirements, including requirements to make non-discretionary sales, or face charges for noncompliance,” the commission wrote. As such, the applicants and other participants in WRAP will have no discretion as to: whether to make a sale; the quantity of any sale; or the price of any sale. For any such sale, the applicants will act as a price taker and, therefore, will not know the WRAP settlement price until after the markets close.” 

But the commission also required the utilities to include in their triennial market power updates to details about their “transactions at or near the Palo Verde and Mid-C hubs, relative to the total volume of transactions at the Palo Verde and Mid-C hubs, respectively, to allow the commission to evaluate the applicants’ sales contribution to index formation.” 

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FERC Chair: States not Benefiting from Grid Projects Won’t Pay — Period

OXON HILL, Md. — FERC Chair Willie Phillips did not expect his audience at the Exelon Innovation Expo to have read every word of the commission’s 1,363-page Order 1920, which sets out to transform transmission planning in the U.S. 

But in his June 5 keynote at the daylong event, he did pick out a few key provisions of the order and made a promise.  

“State regulators must be and will be at the table when we decide what projects to select and how we will pay for them,” Phillips said, speaking to a packed room of about 1,000 attendees at the MGM National Harbor Hotel & Casino. “And I’ll tell you this right now: If you do not benefit from a project, you will not have to pay for it, period.” 

He also stressed the innovative elements of the order’s approach to long-term planning for regional transmission, with a focus on reliability, affordability and sustainability.  

“It makes sure that we look out over the long-term, 20-year horizon to make sure that we plan for the reality … on the horizon; that we consider a broad set of benefits when we do this planning, including grid-enhancing technologies,” he said.

Similarly, Phillips described Order 1977, issued with 1920 on May 13, as a “breakthrough when it comes to how we engage with landowners and environmental justice communities” as part of FERC’s backstop permitting authority for projects in federally designated National Interest Electric Transmission Corridors. (See FERC Issues Transmission Rule Without ROFR Changes, Christie’s Vote.) 

The order’s Landowner Bill of Rights and requirements for project developers to submit Tribal Resource and Environmental Justice Public Engagement plans are intended to “make sure that these vulnerable communities are a part of planning for the new infrastructure that will power the American economy.” 

Speaking on the event’s main theme ― the role of innovation in the U.S. energy transition ― both Phillips and former Energy Secretary Ernest Moniz covered by-now-predictable ground ― the exponential growth in U.S. energy demand driven by data centers and artificial intelligence ― and provided some individual and at times provocative insights. 

Former Energy Secretary Ernest Moniz | © RTO Insider LLC

Now CEO of the nonprofit Energy Futures Initiative, Moniz said current data center load growth signals “we’re just in the early stages of reindustrialization of the United States.”  

Phillips agreed, saying “the technology revolution is an energy revolution … pushing the way we consume, the way we produce and the way we distribute our energy across the country.” 

Chip, battery and EV factories, and heat pumps are all in the mix, Moniz said, “and then we have wild cards that we still don’t know how they’re going to play out fully.” For example, converting the country’s current hydrogen production from natural gas to green hydrogen produced with electrolyzers could require about one-eighth of total U.S. electricity production, he said.  

Moniz agrees with utilities calling for new natural gas generation to meet growing demand.  

“I believe that is a reality,” he said. “However, rather than treating this as a conflict, what I think we need to do is to take a more rational view of the clean energy transition. The word ‘transition’ there has meaning; it means we should not be looking at points in time, but a transition. 

“We have opportunities to design systems in which, if we have a little more carbon now to meet the load, we have to have a catch-up period during the transition in terms of the overall forcing of global warming. We can do that, but the discussion has to evolve around transition.” Moniz did not elaborate on the impacts of such an approach, such as whether building new gas plants in the near term would increase the likelihood of future stranded assets to be paid for by utility customers, and he was not made available to respond to questions.  

However, during his speech, he did say other options for reducing emissions, such as carbon capture and sequestration and advanced or small modular nuclear reactors, “are clearly at least 10 years on the horizon, and that means you don’t wait eight years to start planning it. That means you start last year to start planning it.” 

‘Utilities Didn’t Make the Cut’

Phillips also spoke about the connection between innovation and diversity. 

“Most successful companies value innovation, and for those companies that value innovation, they also value something else; that’s diversity; diversity of experience and diversity of thought,” he said. 

Phillips’ efforts to bring that kind of diverse thinking to FERC are rooted in his own experience, he said, growing up in a single-parent household in Alabama, where he watched his mother spread out bills on the kitchen table to decide which to pay. 

“Sometimes, utilities just didn’t make the cut,” he said. “So, it’s never far from my mind, as I do this work, what real, everyday people — ratepayers — what they’re thinking about; what they’re struggling with to make their ends meet,” he said.  

Phillips sees the coming spikes in energy demand from a similar perspective. While demand is growing, the fact that “70% of our grid was built in the 1950s and 1960s” translates into an aging system where some regions are facing potential power shortages in the near term, he said. “For regulators like us, [the] question is, what do people do when they don’t have the power they need? What do you do when the lights go out?” 

Orders 1920 and 1977 are at least part of the answers to those challenges, he said.  

Moniz called Order 1920 the “biggest step by FERC on transmission, probably in more than a decade.” Planning for the clean energy transition, energy security and social equity should be “one conversation in the policy world,” Moniz said. “It may be treated like three conversations, but it’s not. It’s one conversation, and that is the basis of long-term planning.” 

But more work needs to be done. Moniz sees demand aggregation and risk sharing as a critical part of long-term planning, pointing to a recent agreement by Google, Microsoft and steel producer Nucor to aggregate their demand and fund clean energy projects that can provide carbon-free power.  

“Aggregating demand will again be part of the 20-year planning horizon and a way of sharing risk that the private sector can take on, and the public sector can work with the private sector on,” he said. “There’s no way we can accelerate the way we need to, I think, without all of that.” 

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NPCC Predicts Adequate Electricity Supply this Summer

The Northeast Power Coordinating Council’s 2024 Summer Reliability Assessment, released last week, shows the region “will have an adequate supply of electricity this summer” under most conditions, with a forecast peak demand about 200 MW lower than last summer. 

The regional entity’s predicted peak week begins Aug. 11, though this represents an overall high for the territory. Subregions have a range of peak-week starts ranging from June 2 for New England to Sept. 22 for the Maritimes. 

NPCC said coincident demand in its footprint — which includes the six New England states, New York, Québec, Ontario, New Brunswick and Nova Scotia — should peak at 105,014 MW in its 50/50 forecast, which represents a prediction with a 50% chance of being exceeded. This compares to the 105,200-MW peak in the RE’s summer assessment last year, for the week beginning Aug. 20. (See NPCC Warns of Tight Summer Margins in Ontario.) 

Under the 90/10 forecast — indicating a 10% chance of being exceeded — coincident demand would peak at 112,011 MW, while the RE’s extreme case predicts demand of 117,598 MW for a peak week beginning July 21. Total capacity for the 50/50 and 90/10 scenarios is 162,006 MW, dropping to 161,973 MW in the extreme forecast. Predicted net margins are 12,382 MW for 50/50 and 5,385 MW for 90/10, and a 5,923-MW deficit in the extreme, indicating that energy imports and operating procedures would be necessary to maintain reliability. 

According to the assessment, the “single most important variable” impacting demand in NPCC’s footprint — which is winter-peaking — is ambient weather conditions. This means subregions can experience widely different patterns of demand, reflected in the range of peak week dates and conditions predicted by each reliability coordinator.  

As a result, the RE suggested it is unlikely multiple subregions will experience tight margins at the same time, meaning neighbors will likely be able to help each other out when needed. Québec in particular should “be able to provide assistance to other areas if needed, up to the transfer capability available,” NPCC said. 

While expected demand is lower than last year, NPCC acknowledged that the predicted capacity has also declined slightly, from 163,338 MW in last year’s assessment. The RE noted several resource retirements, the largest of which is the Mystic Generating Station combined cycle Units 8 and 9, representing a total nameplate capacity of 1,515 MW, which went offline May 31. The Mystic retirement “accounts for nearly a 5% reduction in New England’s installed capacity compared to” the 2023 assessment, NPCC said. 

Hydro and tidal power continues to account for the majority of generation in peak weeks, although NPCC noted this figure is skewed by Québec, where this resource makes up 89% of generation. In other subregions, hydro and tidal make up no more than 23% of generation (Ontario), to as low as 11% (New England).  

Dual-fuel generation is projected to be the second most common in the region, though this total is also affected by New York, where dual-fuel makes up 50% of the generation mix, and New England, where it makes up 30%. It also makes up the biggest share of generation in both subregions. 

The Maritimes subregion has the greatest diversity of resource types in the assessment, with coal taking the largest share at 22%, and wind, oil and hydro each accounting for at least 10%. In Ontario, nuclear power leads all other resource types with 34% of generation capacity. 

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Market Footprint Critical for EDAM Decision, NV Energy Says

The growing footprint of CAISO’s Extended Day-Ahead Market (EDAM) was a critical factor in NV Energy’s recently announced decision to join it rather than the competing Markets+ offering from SPP, the utility said in a regulatory filing.

PacifiCorp, the Balancing Authority of Northern California, Los Angeles Department of Water and Power, and Portland General Electric, as well as CAISO, all are expected to participate in EDAM. In addition, Idaho Power has said it is leaning toward EDAM as its day-ahead market choice.

The expected EDAM lineup “provides a significant degree of interconnectivity and supports a diversity of resources,” said Ryan Atkins, NV Energy’s vice president of resource optimization and resource planning.

Atkins’ comments are from written testimony included in the company’s 2025/27 integrated resource plan, filed with the Public Utilities Commission of Nevada on May 31. The commission made the filings public June 5.

CAISO’s recent approval of the Southwest Intertie Project-North (SWIP-North) was another key factor in NV Energy’s decision, Atkins said. A joint project by NV Energy and LS Power, SWIP-North will be a 285-mile, 500-kV line to send Idaho wind energy to markets to the south. It will connect to the One Nevada (ON) Line at Robinson Summit, a site that eventually will be one corner of a transmission triangle across Nevada when NV Energy’s Greenlink North and Greenlink West lines are completed. (See CAISO Board Approves Nevada Transmission Line to Access Idaho Wind.)

SWIP-North “will only enhance the transfer capability of the existing ON Line transmission line in Nevada, bringing even greater benefits to all EDAM participants,” Atkins said.

Atkins also noted the “significant economic, reliability and environmental benefits” that NV Energy has gained through participation in CAISO’s Western Energy Imbalance Market (WEIM). Since joining the WEIM in December 2015, the utility has reaped $488 million in benefits.

Although NV Energy stated in its IRP that it plans to join EDAM, the utility will file a separate, formal proposal later this year seeking PUC approval to join the day-ahead market.

In a June 6 release, CAISO called NV Energy’s intent to join EDAM “a substantial milestone in advancing the efficient coordination of the electric needs for growing loads and a changing resource mix across the West.”

‘Least-cost, Least-regrets’ Decision

NV Energy’s announcement of its EDAM choice may be a central piece in the day-ahead market puzzle in the West.

As competition for day-ahead market participants has been heating up between CAISO and SPP, many potential participants have indicated they are waiting to see who will join each market before making their own decision.

Entities that have shown the most interest in joining Markets+ include the Bonneville Power Administration and Puget Sound Energy in the Northwest, and Arizona Public Service, Salt River Project and Tucson Electric Power in the Desert Southwest. NV Energy’s balancing authority area sits between those two areas.

The comments in the IRP are the latest confirmation of NV Energy’s intent to join EDAM.

David Rubin, NV Energy’s federal energy policy director, confirmed the utility’s decision May 31 during a meeting of the Launch Committee for the West-Wide Governance Pathways Initiative. (See NV Energy Confirms Intent to Join CAISO’s EDAM.)

Before that, NV Energy had disclosed its decision to join EDAM during private meetings, multiple sources previously told RTO Insider.

In his testimony, Atkins also addressed the question of how NV Energy plans to meet a Nevada requirement to join an RTO by 2030.

“Events in the West are still too fluid, and the requirement dates still far enough out, to make any judgments about [NV Energy’s] ability to meet the Jan. 1, 2030, requirement,” he said.

Atkins described the decision to join EDAM as an incremental step to capture “substantial customer benefits on a least-cost, least-regrets basis.”

Last year, the PUC opened a docket to explore ways to evaluate a utility’s request to join a regional market or RTO. (See Nevada RTO Proceeding Examines EDAM, Markets+ Design.)

In a May 20 procedural order, Commissioner Tammy Cordova laid out 18 topics that NV Energy should address in an application to join a day-ahead market.

Those include governance, cost of participation, greenhouse gas tracking, impacts on non-jurisdictional transmission customers and pathways to joining an RTO.

Another topic for consideration is any investment in generation and transmission that would be needed to participate in the market or maximize its benefits.

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BOEM Clears Way for Central Atlantic Wind Lease Auction

The Bureau of Ocean Energy Management has determined its planned lease of Central Atlantic wind energy areas would have no significant impact on the ocean, the creatures that live there or the people who use it for other purposes. 

The final environmental assessment, announced June 6 sets the stage for the BOEM to auction lease areas along the Delaware, Maryland and Virginia coasts this year. The target date is Aug. 14. 

The analysis does not examine the impacts of construction and operation of wind turbines and the associated infrastructure. It analyzes only the research that would determine the area’s suitability for future wind farms and underwater transmission. 

This research includes site assessment and site characterization efforts such as placement of meteorological buoys and oceanographic devices, as well as geophysical, geotechnical, archaeological and biological surveys. 

The three wind energy areas — designated A-2, B-1 and C-1 — total 356,545 acres and stand as little as 19 nautical miles from shore. BOEM expects the four lease areas would average 80,000 acres each. 

B-1 will not be offered in this year’s auction because of the potential conflicts there between offshore wind turbines and nearby military and space flight activities. BOEM concluded the scope of constraints and cost of mitigation measures needed for construction were too great.  

However, B-1 was included in the environmental assessment because it may be included in a later lease sale after NASA and the Department of Defense complete an in-depth review of what activities could co-exist there, and under what conditions. 

Site assessment and site characterization were projected to have a negligible or negligible-to-minor impact on each of the resources evaluated, which ranged from air quality to fishing to military operations to sea turtles. 

BOEM’s Central Atlantic region stretches from Delaware Bay to Cape Hatteras.  

The world’s largest naval base, multiple fighter wings, a bombing and gunnery range and a space launch facility all are sited close to water’s edge, and the Department of Defense has raised concerns about incompatibility with wind turbines. (See Potential Military/NASA Conflict with OSW Seen in Wind Energy Area.) 

Some interagency friction was reported as BOEM attempted to prepare the region for offshore wind development, but by the time Central Atlantic wind energy auction plans were announced in late 2023, the Department of Defense and NASA offered supportive statements. (See BOEM to Auction Wind Energy Areas in Central Atlantic.) 

The concerns about building wind turbines in area B-1 apparently do not extend to doing research work there, or in A-2 or C-1.  

The environmental assessment predicts 201 to 377 round trips from port by an array of research vessels, and states that is not a large number when spread across the anticipated five- to seven-year research window or when compared with the heavy marine traffic already seen in the area. 

Potential conflicts with the military would be averted through effective coordination with military commanders and the U.S. Coast Guard, the report concludes, although site-specific stipulations may be needed. 

In a June 6 news release, BOEM Director Elizabeth Klein said development would move forward collaboratively: “We will continue to work closely with Tribes, our other government partners, ocean users, and the public to ensure that any development in the region is done in a way that avoids, reduces or mitigates potential impacts to ocean users and the marine environment.” 

BOEM also plans offshore wind energy auctions in 2024 in the Gulf of Maine, the Gulf of Mexico and Oregon. 

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Chicago Law Prof Takes ISO-NE to Task at Consumer Liaison Group

HOLYOKE, Mass. — Governance structures and market rules at ISO-NE that favor incumbent interests have contributed to pushing the region into costly and carbon-intensive reliability solutions, University of Chicago Law School professor Joshua Macey told the RTO’s Consumer Liaison Group (CLG) on June 4. 

Speaking to NEPOOL members, ISO-NE officials and members of the public at Holyoke Community College, Macey said the voting power of incumbents within NEPOOL has led to a bias toward capital-intensive solutions to reliability concerns. 

“Reliability regulations are increasingly coming into tensions with clean energy policies,” Macey said, pointing to the reliability-must-run agreement for the Mystic Generating station and ISO-NE’s inventoried energy program, which compensates resources for keeping stored fuel on hand in the winter. The program is set to expire at the end of February. 

“This is the type of intervention that essentially renders any type of clean energy policy irrelevant,” he said, arguing that out-of-market fuel security interventions constitute an admission that the capacity market is not adequately serving its reliability function. 

He argued that ISO-NE’s capacity market has had small penalties for generators that can’t run when called upon. In 2014, “a resource could have met none of its obligations and still made a profit in the capacity market,” he said.  

Although penalties have increased in recent years, that must be coupled with “some way to guarantee that the generator can pay,” Macey said. 

ISO-NE is in the middle of a multiyear process of revising its capacity market rules to better align procurements with tangible reliability benefits. The RTO also has an ongoing project “to reduce collateral shortfalls for Pay-for-Performance penalties that generators are assessed if they fail to operate or underperform during long-duration capacity-scarcity conditions.” 

Regarding transmission, Macey argued that a lack of oversight over line upgrades has led to high-cost projects that do not address the looming needs associated with the clean energy transition. 

Asset-condition project costs have increased dramatically over the past 10 years, prompting states to push for changes. In response, transmission owners have rolled out some changes to the asset-condition review process, including a new database, process guide and opportunities for stakeholders to provide comment on projects in the planning stages. (See “Asset Condition Project Updates,” ISO-NE PAC Briefs: Dec. 20, 2023.) 

However, asset-condition costs have continued to accumulate. In mid-May, National Grid proposed an approximately $500 million project to replace degrading wooden structures with steel poles on a line that was previously refurbished in 2008. (See ISO-NE Planning Advisory Committee Briefs: May 15, 2024.) 

Since the financial risk of these transmission investments falls on ratepayers, TOs face minimal consequences for ineffective or poorly planned upgrades, Macey said. 

One NEPOOL officer took exception to Macey’s characterizations of market and governance bias. 

“When you look at NEPOOL, all the voting is transparent,” said Dave Cavanaugh, vice chair of the organization’s Participants Committee, whose meetings are closed to the press and public. NEPOOL’s primary role as a purely advisory body limits the power of individual companies or sectors, he argued. 

Regarding Macey’s criticism of the capacity market, Cavanaugh said ISO-NE is working to address some of the issues the professor talked about, including increasing penalties. “There’s a message in the marketplace that you need to perform.” 

Demand Response

Henry Yoshimura, director of demand resource strategy at ISO-NE, outlined the role of demand response in the clean energy transition. 

As intermittent renewable resources increase, the grid will face “big periods of under-generation and big periods of over-generation,” Yoshimura said. These swings will lead to energy prices that increasingly “bounce around.” 

This variability of supply, combined with rapidly increasing peak loads, will make DR a key resource in the coming years, Yoshimura said. 

“I do think that retail rate reform is needed in order to encourage demand flexibility,” Yoshimura said, adding that time-of-use rates could incentivize end users to better align their consumption with wholesale prices. 

Yoshimura noted that the proposed shift to a prompt and seasonal capacity auction could boost DR resources, which can be relatively quick to develop and could be used to fill capacity deficiencies on a shorter notice than many traditional transmission or generation solutions. 

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WECC Flags Hydro in BC, SW Heat as Potential Summer Concerns

Extreme heat in the Desert Southwest and low hydro conditions the Northwest could pose reliability problems for the Western Interconnection this summer, although the region isn’t at an alarming risk for grid emergencies, WECC officials said during a June 5 call. 

Those officials delved into the regional entity’s findings that became part of NERC’s 2024 Summer Reliability Assessment, which showed British Columbia, the Southwest and Baja California at an “elevated” — but not “high” — risk this summer, which indicates a “potential for insufficient operating reserves in extreme conditions.” (See NERC Summer Assessment Sees Some Risk in Extreme Heat Waves.)

Despite that assessment, Kris Raper, WECC vice president of strategic engagement and external affairs, cautioned call listeners about how quickly conditions could deteriorate, noting industry participants know the West has “had some really tight summers recently.”  

“Until we can get more resources and more transmission online to be able to get the energy from where it’s generated to load and have a broader perspective and purview of where that energy can come from, then we have to know what it is that we’re looking at and what the risks may be,” Raper said. “And right now, the risks are greater than they’ve ever been.”  

A trend of rising temperatures and an increased rate of load growth has fueled steady increases in summer peak demand in the West in recent years, and this year is expected to be no different, WECC officials said.  

Data from the National Center for Environmental Information indicates a 61% chance that 2024 will be the hottest year on record and a 100% chance it will be in the top five, said Matt Zapotocky, senior reliability assessments engineer at WECC.  

Investing in additional capacity is crucial to accommodating the increasing frequency of heat waves, Zapotocky said. Inverter-based resources (IBRs), which include renewables and battery storage, make up the bulk of capacity additions in the Western Interconnection, with the latter increasing “exponentially” between 2019 and 2023, from 230 MW to almost 10 GW. Solar resources nearly doubled from 19 GW to 35 GW over that time, and wind resources increased from 25 GW to 37 GW.  

An additional 32 GW of proposed capacity is projected in 2024, with about 80% of that being IBRs. WECC also expects 1.6 GW of mostly thermal resources to be retired.  

While no Western regions are projected to experience a loss-of-load event this summer, according to WECC’s assessment, some regions, such as British Columbia, are at a greater risk than others.   

While hydroelectric resources and reservoir levels — particularly in California — are in a better position than they’ve been in the recent past, conditions have not returned to historical norms, said Bryon Domgaard, a senior analyst at WECC. Drought remains in British Columbia, where hydro resources make up 90% of the resource portfolio. Additionally, the province is undergoing rapid electrification in the industrial, commercial and residential sectors, but there are no planned capacity additions for the summer ahead, he noted.  

“That reduction in hydro availability is really what is concerning for British Columbia. In addition, the transfer capacity has been diminishing over the past couple years as we see more load growth in the Pacific Northwest taking out some of the transfers that used to make it to British Columbia,” Zapotocky said. “These concerns, coupled with the increase in demand in British Columbia from electrification, placed it in that elevated risk category.”  

The Desert Southwest also sees elevated risk because of heat-related extreme weather. The potential for high temperatures to cause derates for natural gas-fired generators coupled with escalating demand could lead to loss of load, Zapotocky said.  

In California and Mexico, supply chain issues for obtaining grid equipment are of greater concern.  

“Not being able to complete their projects on time could result in escalating the small amount of loss-of-load hours that we’re seeing in that region,” Zapotocky said. “Which reliability risk is most pertinent depends on which region we’re discussing.” 

While increased coordination continues to be crucial for mitigating risk, interconnectivity in the system also adds new complexities.  

Solar proliferation in California and Mexico has boosted south-to-north transfers into the Northwest, causing concerns about hitting system operating limits on paths between the two regions, Zapotocky said. And despite seeing more transfers from California to the Northwest, fewer of the transfers are making it to Canada. As British Columbia is forced to serve more of its own load, the system in other regions, such as Alberta, can experience reduced transfer capability.  

“When it’s near islanding conditions — when IBR outputs are high and demand is low — there’s actually difficulty maintaining frequency response in that region, and this can potentially result in additional under-frequency load shedding. So really, everything is kind of interrelated here,” Zapotocky said.  

With the influx of IBRs, areas in the Desert Southwest also are experiencing increased frequency issues. 

Working Together

Demand response programs have been “instrumental” in reducing peak demand during stressed grid conditions, Domgaard said. But they face limits because of decreased customer participation in the face of increased DR events, and they should be reserved for emergencies.   

Working together remains the priority in ensuring reliability across the Western Interconnection, said Katie Rogers, WECC manager of reliability systems.  

“If there are wildfires going on in California, if there’s a drought that’s affecting hydro availability up in the north, how can the subregions and [balancing authorities] in the whole of the Western Interconnection work together so that someone isn’t stranded?”  

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FERC Nominees Set for a Quick Floor Vote as Schumer Files Cloture

President Joe Biden’s three nominees to FERC are set for a floor vote as soon as next week with Senate Majority Leader Chuck Schumer (D-N.Y.) filing cloture on them June 5. 

Energy expert Judy Chang, FERC staffer David Rosner and West Virginia Solicitor General Lindsay See all comfortably cleared the Energy and Natural Resources Committee on June 4, with leaders urging swift confirmation to maintain a quorum on the commission. (See related story, Senate Energy Committee Advances Biden’s FERC Nominees.) 

Two of the nominees would fill two open seats, and Chang would replace outgoing Commissioner Allison Clements, who congratulated them on their swift movement through the confirmation process in a post on X. 

“As my term is ending, I intend for the June open meeting to be my last,” Clements posted, along with a screenshot of the Senate Cloakroom’s X feed showing Schumer’s cloture motions. “More to say then, but for now — it has been my highest privilege and honor to serve.” 

Clements’ term ends June 30. A quick confirmation would maintain FERC’s quorum after Clements leaves, meaning it will be able to continue its normal business and vote out orders. 

In addition to the leadership of the ENR Committee, several groups had also called on the Senate to move quickly to confirm the three nominees. 

“It is vital that FERC [have] a full suite of commissioners as it goes through the rehearing process on Order 1920 and moves towards implementation,” Electricity Transmission Competition Coalition Chair Paul Cicio said in a statement. 

The Interstate Natural Gas Association of America, which represents the pipelines regulated by FERC, also called for swift approval of the nominees. 

“With a pending vacancy in a couple of weeks, the agency could lose quorum, which would eliminate the commission’s ability to approve construction of critical energy infrastructure projects, including natural gas pipelines and storage facilities,” INGAA CEO Amy Andryszak said in a statement. “INGAA urges the Senate to act swiftly to avoid this loss of quorum by scheduling votes to confirm the nominations of Rosner, See and Chang with bipartisan support.”

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USEA Event Looks into Addressing Growing Data Center Demand

Data center expansion is a major part of the power industry’s return to demand growth around the country, and the United States Energy Association hosted a webinar June 5 with industry leaders on how the sector’s growth will play out. 

NERC for years forecast flat growth nationally, but that changed last year in part because of data center expansion to meet new computing needs from artificial intelligence. CEO Jim Robb said he expects growth will be even higher in the next long-term assessment. (See NERC: Growing Demand, Shifting Supply Mix Add to Reliability Risks.) 

Growing demand makes ensuring resource adequacy more of an issue, but the scope of specific data centers can lead to challenges for the grid. 

“We’ve seen and heard reports of interconnection requests on the order of 1 to 1.5 GW,” Robb said. “And to put that in perspective, a gigawatt is about the entire load of the city of San Francisco. So, these are very, very large loads that are seeking to interconnect, and they’re not diverse, right? So as load is either on or off, that has potential to create stability issues for the grid.” 

AI uses much more energy than a normal Google search, but over time, the difference should shrink because Nvidia, which manufactures much of the hardware for AI, is expecting its next generation of chips to use less power, Robb said. 

“Algorithms will also get better over time,” Robb said. “We saw this with the internet when the internet was first coming into broad scale adoption in the ’90s and early 2000s. We had similar concerns around electricity demand that largely didn’t actually occur because the chips got better. The algorithms got better. We will see something similar happen with the AI chips as well.” 

Data centers are very important to modern civilization, and while they do consumer a lot of power, they provide major benefits, said Christopher Wellise of Equinix, which builds data centers around the world. 

“They do operate … 24/7/365, supporting a whole wide range of essential services, from the life-saving work in hospitals, to first responders, to powering global financial markets, managing food and pharmaceutical production, and so on,” Wellise said. “Not to mention, of course, entertainment, communication and all the other things … that folks rely upon.” 

Some in the data center industry are putting multiple facilities at one site, and those can get up to 4 or 5 GW of demand, said Daniel Brooks, vice president of integrated grid and energy systems at the Electric Power Research Institute. (See EPRI: Clean Energy, Efficiency Can Meet AI, Data Center Power Demand.) 

“That’s a significant requirement in terms of additional supply and delivery capacity that has to be planned and permitted and constructed,” Brooks said. “And the timelines for the development of the data centers themselves are on the order of … one to two, maybe three years.” 

It takes longer than that to actually get new supply and new power lines sited, permitted and built: three to five years for a new gas turbine. Transmission can take even longer, he added. 

Natural gas is going to be part of the grid for the near term; whether that is defined as five to 10 years or 15 to 20 is anyone’s guess, said Dan Brouillette, president of the Edison Electric Institute. 

“I don’t suggest to you that that’s what utilities want,” Brouillette said. “That’s just what is required by the physics of the problems that we’re facing today. There’s no way to stabilize the grid today without the use of some firm baseload power, and that includes natural gas. So, I think that you know, as I see it here, fully decarbonizing the grid, fully decarbonizing electricity production in the United States, it’s probably not going to happen by 2030.” 

Even getting it done by 2035 is ambitious, but Brouillette said utilities would continue to “make every effort.” 

While demand from data centers is a growing issue, the industry has dealt with huge spikes from specific facilities in the past, especially at the start of the Cold War, when nuclear weapons production was ramping up, Brouillette added. Those manufacturing facilities consumed 10% of the electricity in the country. 

The issue “boils down to a question of political will” and whether the facilities can be permitted, he added.