FERC on May 23 upheld the contract termination payment (CTP) rules for Tri-State Generation and Transmission Association it approved last year, though it modified some of its original order in response to requests for clarification (ER21-2818-002, et al.).
Tri-State is a wholesale generation and transmission cooperative that serves members in Colorado, Nebraska, New Mexico and Wyoming with long-term, full-requirement wholesale electric service contracts.
FERC’s preferred balanced approach was initially proposed by one of Tri-State’s members. The co-op argued for its preferred accounting methods on rehearing, but FERC declined to overhaul its December order.
“We continue to find that the adopted BSA is consistent with principles of cost causation and with the purpose of an exit fee,” FERC said. “The presiding judge correctly explained that the BSA appropriately aligns costs and benefits to Tri-State members by declining to assign generation-related debt to Tri-State’s members located in the Eastern Interconnection, whose loads are supplied entirely through power purchase agreements.”
FERC also continued to find the BSA’s treatment of PPAs is just and reasonable because it requires that members pay their pro rata share of those that are actually used to serve load.
Tri-State argued that assigning the costs of dozens of PPAs to departing members would be unworkable, which did not persuade FERC. The commission said the co-op does not need to provide members with their exact share of PPA costs before they make a final decision on departure.
FERC granted requests for clarification from Tri-State and Mountain Parks Electric on the amortization term for the transmission credit. It should be amortized over the remaining term for the depreciation rates in effect for the assets to which the debt payment relates, the commission said.
It also clarified that the amortization term for the credit is determined based on the average remaining life of depreciable transmission plant base as determined by Tri-State’s most recent Form No. 1 filing at the time a member withdraws.
The commission sustained the overall transmission crediting approach, finding the prepayment and back-crediting of transmission-related debt in the adopted BSA strikes a reasonable balance between ensuring the debt-related costs of Tri-State’s transmission assets are recovered through the CTP and ensuring the withdrawing member reaps the full benefit of these costs while minimizing cost shifts.
“The payment of transmission-related debt as part of the CTP is intended to compensate Tri-State for the transmission-related debt it incurred to serve withdrawing members,” FERC said. “To prevent shifting costs onto remaining members, the withdrawing member must compensate Tri-State for this debt whether it uses Tri-State’s system or not.”
VAIL, Colo. — “Uncertainty” was a recurring theme at the annual meeting of the Western Conference of Public Service Commissioners on May 19-22, where participants grappled with how to account for the growing number of unknowns in resource adequacy modeling in a future with less predictable weather patterns and unprecedented load growth.
Some speakers at the meeting said the issue requires the electricity sector to fundamentally change its approach to load forecasting.
“There’s a lot of climate and economic uncertainties,” Siva Gunda, vice chair at the California Energy Commission, said during a panel May 20. “Do we really understand the climate data, and are we incorporating it into the forecast? Most of our work has been historically given — historic insights, historic weather patterns; obviously that’s not true anymore.”
The theme of uncertainty dominated conversations about RA, as industry experts shared both a fear of how changing conditions will affect the grid and an inspiration to address the unknown.
“The operational conditions on the system have become a challenge, and the need to harness the collective integration, diversity and power of the grid has never been more true,” said Sarah Edmonds, CEO of Western Power Pool. “Several years ago, utilities … observed that we are, for lots of reasons, headed toward a real reliability pinch in the West.”
Load growth was essentially flat for over a decade compared with today’s “astronomical” load growth projections stemming from new data centers, widespread electrification, and other trends in technology, policy and economics, said FERC Commissioner Mark Christie.
These “macro drivers” should be considered in modeling and forecasting, rather than relying solely on historical data, according to Jeremy Hargreaves, principal at Evolved Energy Research. Other macro drivers include state emissions targets, decarbonization and electrification policies, artificial intelligence sector growth, and crypto markets.
“The question is how to proactively plan in the face of uncertainty. We want to be finding these no-regrets actions that we can take that are informed by these macro drivers, recognizing there’s a lot of uncertainty in how these will play out,” Hargreaves said. “We need more complex modeling approaches to try and estimate what kind of impacts they’ll have.”
Gunda emphasized the importance of adequate forecasting to address uncertainty and maintain reliability.
“Forecasting has a direct implication on affordability; it has a direct implication on reliability; it has direct implications on economic and industrial processes. And so, what we’re doing right or wrong will directly affect the entire system,” Gunda said.
Forecasting should evolve to keep up with changing conditions and uncertainty, and Hargreaves and other industry analysts suggested supporting the grid with bottom-up forecasting and end-use forecasting, which looks at individual customer load geographically.
“My argument is that our historical approach to planning is not going to do,” said Ry Horsey, researcher and software engineer at National Renewable Energy Laboratory. “Forecasts should inform planning and decision-making.”
Evolved Energy Research has looked at a variety of different sectors and developed a load-growth taxonomy that reflects different loads and how they impact people over time, and Hargreaves suggested more widespread implementation of this model in forecasting.
Robert Kenney, president of Xcel Energy’s Colorado division, summed up both the fear of uncertainty and the actions being taken to address it.
“I don’t think there’s any disagreement that we’re retiring resources more quickly … we have load showing up in ways that we haven’t seen in 20 years,” Kenney said. “We should be freaked out, but only to the extent that it drives creativity and action.”
CARROLL, N.H. — Angst over looming load growth, cost increases and reliability headaches headlined the 76th annual New England Conference of Public Utilities Commissioners (NECPUC) Symposium, held May 20-21 at the Mount Washington Hotel.
“I think it is a laudable goal to want to get rid of any greenhouse gas-emitting source, but we’re going to have to do this at pace,” said Charles Dickerson, CEO of the Northeast Power Coordinating Council. He said that as policymakers push for “100% reliable, 100% renewable and 100% really cheap [power], I just don’t think those three [aspects] can exist in one space at one time.”
Dickerson called on regulators to work to encourage innovation and be “a little less rigid” around cost recovery for utilities experimenting with new solutions.
“If we take the same approach to regulation that we’ve taken over the past 100 years, it’s probably going to take us 100 years to solve this,” Dickerson said, adding that regulators should try to approach the looming challenges with “a little bit more risk tolerance and a lot more creativity.”
Vineyard Offshore CEO Alicia Barton pushed back with a more optimistic tone.
“Respectfully, I do disagree — actually pretty strongly — that we can’t do all three,” said Barton, former CEO of the New York State Energy Research and Development Authority. She emphasized that changes to the power purchase agreement model, including tweaks to contract lengths and inflation-adjustment mechanisms, could help bring costs down.
“You can actually get better costs if you leverage some of these choices,” Barton said.
Richard Levitan of Levitan & Associates recommended that public utility commissions “embrace principles of transparency, honesty and realism” when weighing competing priorities.
“I don’t think in the pursuit of clean, reliable and affordable [that] there are easy tradeoffs,” Levitan said. “There is no one unassailable answer; there’s no quick solution; but constructive debate with prominent stakeholders — possibly through the ISO, but at the state level too — should inspire awareness, and I think that’s a laudable goal.”
One way to limit costs would be to maximize the potential of high-performance conductors and grid-enhancing technologies (GETs) like dynamic line ratings, advanced-power flow control and topology optimization, said Rob Gramlich, president of Grid Strategies.
Gramlich noted that the deployment of GETs in the U.S. has lagged behind other countries.
“You just have to wonder whether the cost-of-service regulatory model — which rewards large capital investments — is a disincentive for getting senior management at utilities to really deploy these things,” Gramlich said. “I think we’re at the place nationally with GETs where there’s a need for some independent expert who has access to all the information to identify where the right technology could apply.”
Tiffany Menhorn, principal at the Menhorn Group, said GETs often can provide ancillary grid resilience benefits and give utilities “eyes on your line like never … before.”
Along with better real-time awareness, predictive analytics could provide significant insights into asset health and help to identify anomalies, Menhorn added.
Speakers also highlighted retail demand response as an area for improvement that could significantly reduce the overall costs associated with the clean energy transition.
ISO-NE CEO Gordon van Welie said activating DR at the retail level remains “a work in progress.”
In February, NECPUC launched a yearlong working group to look at how retail DR can help address peak load and resource adequacy challenges.
“What I hope for is a standardized approach to doing demand response in the region,” van Welie said, adding that deploying automation, sending the right price signals and incorporating retail DR into the wholesale markets will be essential. As winter risks increase, longer-duration DR that can extend over multiday periods will become increasingly valuable. “That’s a much more complicated type of demand response, and I think it’s an opportunity for us to innovate as a region.”
The Role of Natural Gas
Several of the speakers presented significantly different visions for the role natural gas and gas pipelines will play in the coming decades.
“I hope that states don’t get away from … everything that we’re doing to ensure the safety and reliability of that infrastructure,” said Georgia Public Service Commissioner Tricia Pridemore, who is also first vice president of the National Association of Regulatory Utility Commissioners.
“I’m a pro-gas commissioner,” Pridemore said. She noted a report by the National Petroleum Council that found that “the pipeline infrastructure is going to be with us for a long time,” arguing that alternative fuels like hydrogen and renewable natural gas (RNG) will rely on the gas system as states decarbonize.
Marc Brown of the Consumer Energy Alliance, an advocacy group whose members include a wide range of industrial end users and fossil fuel companies, called natural gas “part of the solution” and argued that the most significant decarbonization gains over the past two decades have come from the proliferation of natural gas.
He said environmental progress and decarbonization “is going to take people accepting the fact that natural gas is going to continue to play an important role in affordability, reliability and emissions reductions in the near- and midterm future.”
In contrast, Emily Green, senior attorney at the Conservation Law Foundation, said states should engage in long-term planning efforts to transition off fossil fuels, including natural gas. She highlighted the significant warming effects of methane leaks from the gas system, which are typically underestimated by state and national greenhouse gas inventories.
“We’re going to be paying for today’s investments in gas for decades to come, both in terms of emissions and ratepayer impacts,” Green said. “It’s low-income consumers that are going to be left holding the bag.”
Green also called on regulators “to be very wary of utilities looking to maintain or even upgrade pipelines on the future promise of biomethane or hydrogen.”
In the Massachusetts Department of Public Utilities’ final rule on its multiyear “Future of Gas” investigation, it found that efforts to blend hydrogen and RNG into the gas network should not be funded through the general rate base (20-80-B).
“The department is uncertain about the viability of hybrid heating and hydrogen technologies and their potential as economical long-term solutions for ratepayers,” the DPU wrote, adding that “RNG and the use of hydrogen as a fuel are emerging technologies that have not yet been proven to lead to a net reduction in GHG emissions.”
FERC has denied a rehearing request and partly adopted a clarification request by Constellation Energy related to a challenge to the fixed costs associated with the Mystic cost-of-service agreement (COSA) (ER18-1639-028).
Initially signed in 2018, Mystic’s COSA between Constellation and ISO-NE delayed the retirement of the Mystic Generating Station by two years to help provide fuel security to the region. The agreement is set to expire — and Mystic to retire — at the end of May.
As part of the COSA, Constellation is required to submit annual informational filings related to the costs of the agreement. Relevant stakeholders are allowed to request more information and ultimately challenge the filings with FERC.
The May 23 FERC ruling stems from an October 2022 series of challenges by a group of municipal utilities to an informational filing submitted that year.
In December 2023, FERC granted several of the municipal utilities’ challenges, determining “that the challenges raised issues of material fact that could not be resolved on the record before the commission, and thus established hearing and settlement judge procedures.”
In January 2024, Constellation requested rehearing on three of the order’s rulings and clarification on two rulings — while also requesting rehearing on the latter two rulings if not granted the clarifications.
“The relief sought herein is aimed at avoiding unnecessary litigation in a case that has seen too much already,” the company wrote.
In its ruling May 23, FERC dismissed the rehearing requests on the basis that the challenge order was not a final decision and therefore not subject to rehearing.
FERC did grant Constellation’s clarification request regarding projected 2023 capital expenditures at the Everett LNG import facility, which also is owned by Constellation and provides the fuel for Mystic via a fuel supply agreement.
A 2022 settlement agreement among Constellation, the New England states and ISO-NE “resulted in the Mystic Agreement no longer providing recovery for any Everett 2023 [reliability-must-run capital expenditures],” FERC wrote.
“Accordingly, we grant Mystic’s requested clarification and determine that there is nothing further to litigate” regarding this aspect of the informational filing, FERC ruled.
Meanwhile, FERC affirmed its 2023 ruling to “set for hearing and settlement judge procedures” the three other formal challenges to the informational filings, which relate to the calculations of Mystic and Everett’s rate bases prior to the agreement.
PJM on May 20 announced that it had completed the first phase of studies for 306 generation interconnection requests sorted into the first cycle in the transition to its new interconnection process, a cluster-based study approach intended to reduce how long it takes the RTO to bring generators online.
“This is another critical milestone for PJM’s widely supported interconnection process reform,” said Aftab Khan, executive vice president of operations, planning and security. “New service requests for generation resources are moving through our process as designed and promised, with more than 200,000 MW of projects to be studied over the next two years to help states advance their energy policy goals.”
Developers with projects in Transition Cycle 1 (TC1) will have 30 days to review the system impact studies and decide whether to move forward with their projects to the facility study phase. PJM said those that complete the process will be ready for construction by mid-2025. (See PJM Initiates Transitional Interconnection Queue.)
Another 306 projects expected to require minimal network upgrades are being studied through an Expedited Process “fast lane” that is expected to yield final interconnection service agreements (ISAs) throughout this year. PJM also plans to initiate Transition Cycle 2 on June 20, with a likely application deadline by Dec. 16.
PJM said about 72 GW are expected to clear the queue by mid-2025 and 230 GW over the next three years, more than 90% of which is renewable energy or storage.
The cluster-based approach groups projects together on a first-ready, first-served approach to identify any grid upgrades and assign costs. It also includes increasingly large readiness deposits to be made throughout the study process, with the aim of discouraging speculative or uncertain projects from taking focus away from others. PJM said 118 projects have dropped out of the queue or failed to post deposits, out of 734 eligible. (See FERC Approves PJM Plan to Speed Interconnection Queue.)
Environmental organizations said the milestone is a welcome first step but that more change is needed.
“PJM worries there’s not enough new power coming online, but it’s still only approving projects proposed four to six years ago,” said Tom Rutigliano, of the Natural Resources Defense Council. “This is a step forward, but PJM’s current process is not enough to get these new clean energy projects connected to the grid as quickly as they’re needed.”
Christine Powell, deputy managing attorney at Earthjustice, said the amount of time it has taken for PJM to get to this stage has already resulted in projects stalling or withdrawing from the queue. “While PJM’s shift to a cluster study process is a positive development for the hundreds of clean energy projects waiting to interconnect to the power grid, PJM continues to lag behind other RTOs,” she said.
Katie Siegner of RMI pointed to a study released in February that found that incorporating grid-enhancing technologies (GETs) into how PJM conducts transmission planning could optimize the use of existing infrastructure to reduce upgrades needed for new projects and speed interconnection studies. The study estimated that about $1 billion in annual production costs could be avoided through 2033 by expanding use of GETs. (See RMI Report: GETs Could Speed Renewable Development, Save Consumers Billions.)
PJM’s “clearest opportunity for improvement is bringing its interconnection process into compliance with Order 2023, particularly through serious consideration of alternative transmission technologies that could provide faster and cheaper network upgrade alternatives,” Siegner said. “The fact that no grid-enhancing technologies have been identified or used as network upgrades to date suggests PJM has more work to do in incorporating these fast, flexible transmission tools into its study methodologies.”
PJM spokesperson Jeff Shields told RTO Insider the RTO allows and welcomes GETs as components of proposals for its Regional Transmission Expansion Plan and laid out how it will fully comply with Order 2023’s requirements around their facilitation in its May 16 compliance filing (ER24-2045).
“All of the enumerated [GETs] already are considered and studied as necessary, if merit exists in the use of such technologies, in the course of interconnection studies in the PJM region,” Shields said. “This incorporation of new and emerging technology is consistent with the objectives of the final rule, which requires transmission providers to evaluate certain GETs in each and every one of its interconnection studies.”
Shields said PJM agrees there is more progress to be made in improving generator interconnection and development, both at the RTO and removing external obstacles. “We are working with stakeholders within the PJM stakeholder process, as well as entities outside of the PJM membership, to accomplish this.”
Responding to a rehearing request by Advanced Energy United over FERC’s partial acceptance of ISO-NE’s third Order 2222 compliance filing, FERC has directed ISO-NE to submit an additional filing to specify its metering and telemetry practices for distributed energy resource aggregations (DERAs) (ER22-983-006).
Order 2222, which requires RTOs to update their tariffs to enable DERAs to participate in wholesale markets, has led to a long series of compliance filings and rehearing requests related to ISO-NE’s compliance.
On May 23, FERC issued an order on rehearing responding to Advanced Energy United’s challenge of ISO-NE’s third compliance filing, which FERC accepted Nov. 2, 2023. (See FERC Accepts ISO-NE Order 2222 Compliance Filing.)
“We sustain three of the four findings AEU [Advanced Energy United] challenges,” FERC ruled.
Responding to the trade association’s argument that ISO-NE’s three metering options for DERAs — “retail delivery point metering, submetering with reconstitution and parallel metering” — are unnecessarily prohibitive, FERC affirmed its finding that these options “do not pose an unnecessary or undue barrier to individual DERs joining an aggregation.”
FERC upheld its acceptance of ISO-NE’s proposal to apply the requirements of the “binary storage facility” and “continuous storage facility” participation models for DERAs to provide withdrawal service. FERC also continued to find that the ISO-NE properly explained the steps it took to “avoid imposing unnecessarily burdensome costs on DER aggregators and individual resources in DERAs.”
However, FERC set aside its prior ruling that ISO-NE adequately described its metering requirements for DERAs.
“Specifically, we set aside our finding that, for those DERAs containing behind-the-meter DERs, ISO-NE’s tariff includes a basic description of the metering practices for DERAs with references to specific documents that contain further technical details for metering and telemetry practices,” FERC wrote.
“ISO-NE’s basic description of its metering practices for DERAs is incomplete because its tariff does not include submetering requirements for DERAs participating as submetered Alternative Technology Regulation Resources,” FERC added.
FERC directed ISO-NE to submit an additional compliance filing to specify these submetering requirements. FERC also set aside its ruling that ISO-NE’s proposal to extend “existing requirements for Alternative Technology Regulation Resources to DERAs” is just and reasonable, writing that it will reassess these requirements after the RTO submits its additional compliance filing.
Caitlin Marquis of Advanced Energy United said FERC’s directive “sends ISO back to the table to resolve one metering barrier for DERs seeking to provide regulation service, which is welcome and important.”
“However, as New England and the rest of the country face rising demand, rising electricity prices and reliability threats, much work remains to ensure the region is taking full advantage of DERs,” Marquis added.
Commissioner Mark Christie concurred with the parts of the order that accepted ISO-NE’s filing and dissented “to the rest.”
Christie decried Order 2222’s “seemingly never-ending and avoidable rounds of compliance filings” and called the compliance saga a waste of time and money.
FERC on May 23 found SPP’s tariff revisions laying out how it determines its planning reserve margin (PRM) methodology only partly met the commission’s order on rehearing and directed an additional compliance filing within 30 days (ER24-1221).
The commission said SPP complied with its directive to include a timeline for making changes to the PRM before a planning year in its tariff. But it also said the RTO failed to include further information on how it uses its loss-of-load expectation studies to determine the PRM.
FERC accepted SPP’s tariff revisions effective April 10, subject to further compliance.
The commission rejected protests from the grid operator’s members that SPP provide three years’ notice before increasing the PRM and that it be prohibited from adopting near-term increases without demonstrating that the market has capacity surplus available for purchase. The commission found both arguments to be outside the compliance proceeding’s scope, saying its directive only required the timeline for making PRM changes.
The RTO said it will perform an LOLE study at least biennially to determine whether a PRM change is needed and post the results. Staff will then provide a recommendation for any changes, with the Board of Directors and state regulators approving the change. The tariff revisions place additional restrictions on any approved PRM that exceeds the current value or the value identified in the final LOLE results by 1% or more; any PRM increase would be implemented for the planning year, beginning at least one year after approval.
SPP’s board in 2022 approved changing the PRM to 15% from 12% over opposition from stakeholders advocating a three-year phase-in. Load-responsible entities unable to meet the requirement can incur financial penalties from the RTO. (See SPP Board, Regulators Side with Staff over Reserve Margin.)
FERC last year rejected a complaint by SPP members seeking to overturn the decision. In a 3-1 vote, the commission ruled that American Electric Power, Oklahoma Gas and Electric, and Xcel Energy failed to show SPP’s PRM process was unjust, unreasonable or unduly discriminatory because the figure itself was not included in its tariff. (See FERC Rejects Protest of SPP PRM Increase.)
AEP, OG&E and Xcel filed a rehearing request with FERC, but the commission took no action on it. They then filed a petition for review with the 8th U.S. Circuit Court of Appeals in July 2023; that proceeding has been held in abeyance pending SPP’s compliance filing following a successful FERC motion (23-2734).
FERC found in September 2023 that SPP’s proposal failed to “adequately” explain how it would account for the LOLE study’s results or any additional considerations when determining the PRM, and that the tariff did not adequately explain the timeline for the RTO’s PRM reviews (EL23-40-001). FERC ordered a compliance filing within 60 days, but SPP and the protesting companies jointly requested an extension to February, which the commission granted.
[EDITOR’S NOTE: This story has been updated to reflect ERCOT’s new unofficial peak demand record for the month of May, set May 27. The previously reported mark for the day was 73.75 GW.]
ERCOT’s latest capacity, demand and reserves (CDR) report projects summer peak demand will increase to more than 97 GW by 2034, assuming normal weather conditions.
However, the weather has been anything but normal recently in Texas. ERCOT is coming off the second-hottest summer in state history, and it just set an unofficial peak demand record for May (77.13 GW) that exceeds the grid operator’s all-time peak from 2018 (73.47 GW).
One Austin resident’s weather projection for the summer. | Emily Eby French via X
The heat index hit 113 degrees Fahrenheit in Austin on May 25 and has already hit triple digits in Houston, where the low temperature dropped to only 80 degrees on May 21. That is about a month and a half ahead of normal, according to a local forecaster.
The National Oceanic and Atmospheric Administration (NOAA) has predicted an “above-average” hurricane season this year, with between 17 and 25 named storms. It says “extraordinarily high, record-warm water temperatures” in the Atlantic Ocean, linked to climate change, are energizing the waters and fueling storm development.
NOAA said another factor influencing this year’s hurricane season is La Niña, a climate pattern that cools surface ocean temperatures and lessens wind speeds, allowing more storms to develop.
The CDR report forecasts peak demand of 83.29 GW this summer, assuming normal weather conditions. Demand is expected to exceed 84 GW in 2026, 86 GW in 2028 and 90 GW in 2030, according to the report.
Energy consultant and Stoic Energy principal Doug Lewin doesn’t think that is enough. He says ERCOT still doesn’t factor climate change into its projections, and he noted the ISO’s current record for peak demand is 85.46 GW, registered last August.
“They only expected 73 GW this month and we’ve already passed that. Had this heat hit outside a holiday weekend, we’d likely be around 80 GW,” he said on X, the social media platform formerly known as Twitter.
ERCOT says its load forecasts are based on normal weather conditions and determined by the methodologies posted to its website. Staff forecasts scenarios through 2033 using a model with historical weather years.
The CDR report is designed to provide forecasted planning reserve margins (PRMs) for ERCOT’s summer (June-September) and winter (December-February) peak-load seasons. The ISO says it is not intended to characterize the risk of scarcity conditions from a real-time operations perspective. It defines the PRM as the percentage of capacity above firm demand that is available to cover uncertainty in future demand, generator availability and new resource supply.
ERCOT’s operational capacity exceeds 100 GW next year but increases to only 101.50 GW by 2033. However, the CDR report indicates the grid operator expects 30 GW of planned capacity by that same time, with solar resources accounting for 28 GW.
The Bureau of Ocean Energy Management released its final environmental impact statement (FEIS) May 23 that concludes that New Jersey’s foremost offshore wind project, Atlantic Shores, would have a “major” impact on commercial and for-hire recreational fishing, the view from the shore and on-ship traffic.
The 560-page study found that the 200-turbine, 1,510-MW project would impact the commercial and recreational fishing sector through a range of activities, including anchoring, cable emplacement, noise, port use and structure presence. At about 10 miles from the shore, Atlantic Shores is the closest OSW project in development to the land in New Jersey.
But the FEIS also concludes the area would suffer a major impact even if the project were not constructed. Those impacts would stem from factors including fishery management measures taken to ensure that the volume of fish caught is sustainable; the impact of climate change from ocean warming, sea level rise and ocean acidification; and non-OSW construction on land.
Likewise, the study found that although the project would have a major scenic impact on the area — on the open ocean, seascape, and landscape character and views — the coast would suffer a strong scenic impact regardless because of onshore development and construction activities, offshore vessel traffic and the effects of other OSW projects.
And the agency found that the impact of the project on most of the other 19 categories studied — including recreation and tourism, land use and costal infrastructure, water and air quality, and a variety of animal species — would be moderate or minor.
BOEM compiles EIS reports to assess the potential impacts from an OSW project on physical, biological, socioeconomic and cultural resources. The final report informs BOEM’s decision on whether to approve, approve with modifications or disapprove the project’s Construction and Operations Plan (COP), and the FEIS may also be used by other agencies in evaluating the project.
The FEIS evaluates the impact on the area if the project does not go ahead and if the project goes ahead as planned. The agency also looks at the impact if the project were reshaped or adjusted to try to mitigate any effects, such as by reducing the number of turbines or their position in the lease area. But any such adjustments did not generally reduce the impacts of Atlantic Shores that BOEM assessed as “major.”
In response to the release of the FEIS, Atlantic Shores said it “remains dedicated to responsible development [and] environmental stewardship.”
“We are encouraged to see forward progress and getting another step closer to delivering New Jersey’s first offshore wind projects,” said CEO Joris Veldhoven. “We appreciate BOEM’s thorough environmental evaluation and recognize the significance of this milestone.”
Tourism, Whale Impact
Atlantic Shores, a 50/50 joint venture between EDF-RE Offshore Development and Shell New Energies US, was one of two projects — along with Danish developer Ørsted’s Ocean Wind 2 — that the New Jersey Board of Public Utilities approved in its second solicitation in 2021. That followed the agency’s approval in 2019 of Ørsted’s Ocean Wind 1 project. (See NJ Awards Two Offshore Wind Projects.)
Ørsted has abandoned its two projects, saying they were no longer feasible.
New Jersey approved two more projects in its third solicitation, and the combined total of those two and Atlantic Shores would, if completed, account for slightly less than half the state goal of 11 GW of OSW capacity by 2040. The state in April opened a fourth solicitation. (See New Jersey Opens 4th Offshore Wind Solicitation.)
Critics of the projects are concerned about the impact on the commercial fishing and tourism sectors and on the quality of life to local homeowners, especially from an impaired view of the sea.
The study also found the project would have only a minor impact on the tourism industry.
Navigation and vessel traffic in the area would suffer only a moderate impact if Atlantic Shores were not built, but a major impact if it were because of “increased vessel traffic in and near the project area and on the approach to ports used,” according to the report. Traffic would especially increase during the construction period, and the impacts would include “changes to navigational patterns and to the effectiveness of marine radar and other navigation tools” that could result in “delays within or approaching ports, increased navigational complexity [and] detours to offshore travel or port approaches,” the study says.
The study found the project would have only a moderate impact on most mammals but would have a major impact on the North Atlantic right whale, which is an endangered species. That assessment stemmed from the fact that “impacts on individual NARWs could have severe population-level effects and compromise the viability of the species due to their low population numbers and continued state of decline,” the report said.
Opponents of OSW projects regularly cite a series of whale deaths on the Jersey Shore as potentially caused by preliminary OSW activities. But construction has yet to begin on any project in the state, and federal and state investigators have found no link between the deaths and OSW activities, saying they are most likely caused by vessels hitting the whales.
A CenterPoint Energy senior executive told Texas regulators May 23 that slightly more than 27,000 of its customers remain without power a week after a derecho devastated the Houston area with winds exceeding 100 mph.
Jason Ryan, CenterPoint’s executive vice president of regulatory services and government affairs, said during the Public Utility Commission’s open meeting that the utility remains in emergency operations.
“We understand that it’s been a long seven days, that it’s been in excess of 100 degrees in terms of the feels-like temperature and that we still have a lot of work to do,” Ryan said. “We will work day and night until we finish the mission. We appreciate all of our customers and for sticking with us through this unprecedented event.”
He said CenterPoint had only about 15 minutes to prepare for the derecho, which national meteorologists define as a continuous or intermittent path of severe wind from a squall line of thunderstorms. Derechos can extend at least 400 miles and at least 60 miles wide and generate hurricane-force winds.
About 922,000 CenterPoint customers were without power in the storm’s aftermath. That number was down to fewer than 18,000 following the PUC meeting, according to CenterPoint’s performance tracker.
Ryan thanked the more than 5,000 mutual assistance crews from other states that augmented CenterPoint’s 2,000 crew members, noting they have not suffered any serious injuries or deaths.
“That’s probably the proudest accomplishment that I can stress with you,” he told the commissioners. “I look forward to sending these crews home just as safe as they arrived to help our communities.”
The restoration crews replaced more than 800 miles of wires, more than 700 transformers and about 2,000 distribution poles. CenterPoint said in a statement it has also deployed 13 mobile generators to critical facilities, cooling centers, health care facilities, first responder locations, senior centers and schools.
“Everyone I’ve talked to has said you all have done an amazing job responding to an event that you couldn’t really prepare for,” PUC Chair Thomas Gleeson told Ryan. “I’ve heard nothing but good things.”
Wearing a logoed polo shirt instead of his normal suit and several days’ worth of stubble, Ryan said he was returning to CenterPoint’s emergency operations center after his presentation. He said the company’s headquarters in downtown Houston lost more than 500 windows; officials say it could be months before the business district’s windows are repaired.
“While we don’t know when we’ll have access to our building again, it hasn’t impaired our restoration efforts,” Ryan said.
Loan Program Attracts Interest
PUC staff said they have received 10 completed commitments to apply for disbursements from the $5 billion Texas Energy Fund (TEF), which is designed to incent more dispatchable energy to the ERCOT grid. The proposed projects could add more than 4.9 GW of capacity (56455).
Applicants face a May 31 deadline to file notifications that they intend to apply for the funds. Formal applications can be submitted on or after June 1. The loans will be issued by Dec. 31, 2025.
The commission established the TEF in March because of state legislation passed last year. Qualifying projects must add at least 100 MW of dispatchable capacity to the grid. The PUC says the program can support up to 10 GW of new or upgraded generation capacity in ERCOT. (See Texas PUC Establishes $5B Energy Fund.)
NRG Energy accounts for three of the applications. The company said this year that it plans to use TEF loans to help finance construction of two new natural gas-fired plants that would be available in 2026.
Corona Named Executive Director
The commission announced it has promoted interim Executive Director Connie Corona to the official role. She fills the position vacated by Gleeson when he was appointed Texas PUC chair in January. (See Abbott Names PUC Executive Director as Chair.)
“I don’t think it could be any question you’re the right person for this job,” Gleeson told Corona.
Corona has spent 12 years at the commission, sandwiched around a 14-year stint in NRG’s regulatory affairs department.
The PUC also promoted Chief Program Officer Barksdale English to deputy executive director. English joined the commission in 2018 after six years at Austin Energy.
