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July 9, 2024

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Stakeholders Propose Amendments to ISO-NE Order 2023 Compliance

Clean energy companies and trade groups proposed a series of amendments to ISO-NE’s proposed Order 2023 compliance at the NEPOOL Transmission Committee meeting Jan. 4, as the RTO and its stakeholders scramble to reach a consensus prior to the scheduled TC vote in February.

The compliance filing is set to bring sweeping interconnection changes as ISO-NE switches from a first-come, first-served queue to a process in which interconnection requests are studied simultaneously in large clusters.

ISO-NE discussed the initial details of its compliance over several TC meetings throughout the fall and presented the detailed tariff changes of its compliance proposal to the TC in December. (See ISO-NE Details Order 2023 Tariff Changes.)

The RTO has proposed several deviations from the specific approach detailed in FERC’s order, including a 270-day cluster study timeline, compared to FERC’s 150-day timeline. Advanced Energy United, a clean energy trade group, called for ISO-NE to stick to FERC’s timeline.

Alex Lawton of United said a significant extension of the study timeline could undermine the order’s goal of reducing interconnection delays and could cause future uncertainty if FERC ultimately rejects this request.

“Recognizing there are challenges and constraints in conducting cluster studies, we are concerned the filing will be rejected and interconnection study timelines will not be significantly improved without a 150 days requirement,” Lawton said. “Submitting the 270 days proposal therefore introduces significant regulatory risk.”

For the initial transitional cluster study process, the clean energy association RENEW Northeast proposed to add a customer engagement window within the existing time frame. While later clusters will have a customer engagement window at the beginning of the process for questions and feedback between interconnection customers and the RTO, ISO-NE’s current proposal does not include this opportunity in the initial cluster study.

“Without sufficient information about potential members of the transitional cluster or the ability to ask the ISO or interconnection transmission owners questions about a proposed interconnection, customers are asked to decide whether to enter the transitional cluster with incomplete information,” said Abby Krich on behalf of RENEW.

United, with the support of New Leaf Energy, also proposed to reduce the transitional cluster’s large generator commercial readiness deposits (CRDs) from $5 million to $2.25 million. CRDs are intended to prevent speculative projects from entering the cluster.

ISO-NE has smaller average project sizes compared to RTOs like PJM and MISO, Lawton said, adding that the $5 million deposit “disproportionately impacts commercially ready smaller projects that may be comparably mature.”

Lawton called the $5 million CRD “far less appropriate for ISO-NE, which has smaller projects and relatively less of a queue backlog.”

Meanwhile, Glenvale Solar advocated for reduced CRDs that are scaled to project size for the cluster studies that follow the initial transitional cluster.

“It is especially critical to manage costs for smaller generators (including smaller LGIRs) to ensure project development costs are as rational as possible” said Aidan Foley of Glenvale. “This will ensure the maximum number of generators reach the market.”

Foley said keeping deposits as low as possible “will maintain relative competitiveness with other RTOs where ICs parent companies are active. This will ensure that project sponsors find New England a compelling geography to direct investments to.”

Glenvale also proposed a reduction in deposits for projects that do not increase the generation capacity at a given site, such as repowering or adding batteries to a site.

Regarding withdrawal penalties in the transitional cluster, Glenvale is supporting New Leaf’s proposal to calculate the penalties based on costs incurred only during the transitional cluster, instead of based on a project’s total study costs since the project entered the queue.

Alex Chaplin of New Leaf said ISO-NE’s current proposal would unfairly increase withdrawal penalties for projects that already have included study costs associated with incomplete interconnection studies prior to the transitional cluster.

“This leads to similarly situated projects being subject to significantly different withdrawal penalties,” Chaplin said.

Meanwhile, RENEW proposed to exempt interconnection customers from withdrawal penalties if their decision to enter the cluster study was based on incorrect or misleading information provided at the beginning of the process.

“When this happens today, the interconnection customer must deal with the variety of consequences, but is not charged a withdrawal penalty,” RENEW wrote in a December memo. “With the introduction of a withdrawal penalty, it is appropriate to create an exception for this to protect everyone in the process.”

RENEW also proposed several amendments related to the distinctions between resources that request energy-only interconnection and resources that request both capacity and energy interconnection service. The trade group said interconnection customers should have the option to “downgrade” their request to energy-only interconnection based on study results.

Without this option, “the ISO proposal would prevent otherwise-viable energy-only projects from moving forward to commercial operation on a timely basis, result in additional withdrawals, reallocation of costs and further withdrawals,” Krich told the TC.

RENEW also proposed that ISO-NE differentiate between energy and capacity costs incurred in cluster studies. Grouping these costs together would burden energy-only interconnection customers with “a portion of the cost of identifying incremental upgrades required for the [capacity network resource interconnection service] requests, from which they do not benefit in any way,” RENEW wrote in the memo.

The TC will meet again Jan. 23 as it prepares for a vote on the compliance proposal in February.

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Federalist Society Examines the Changing Politics of Power Markets

Economic deregulation started out as a Republican policy, but GOP appointees to FERC have been questioning how it has been applied to the electric industry, a trend that was explored Jan. 5 at the 25th Annual Federalist Society Faculty Conference in D.C.

James Coleman, a professor at the Southern Methodist University Dedman School of Law, noted that former Commissioner Bernard McNamee has said marginal price auctions for energy are not ensuring reliability and that former Commissioner James Danly has said the markets are not a statutory requirement and that vertically integrated states have cheaper prices.

FERC Commissioner Mark Christie has not gone as far in his criticisms, but he has argued in the Energy Law Journal that it is time to examine whether the basic RTO market model is the best way forward, Coleman said. (See FERC’s Christie Calls for Reassessment of Single Clearing Price.)

“In some ways, it’s not so different from the traditional critique that we’ve seen from progressives of the use of electricity markets in providing electricity, which is they have been concerned that those electricity markets give short shrift to some of the important concerns other than price,” Coleman said.

Critiques from the left have focused on how the markets favor prices over environmental impacts, especially climate change, but the emerging criticism from the right is focused on how markets are impacted by a growing share of subsidized renewable power, Coleman said.

“In both the case of progressive critiques, and in the case of these increasing conservative critiques, the real concern is less about the use of markets, but more about what kinds of regulations we’re using to drive the kind of preferred energy sources,” he added.

One conservative critique is that the markets are focused on short-term costs and thus have no long-term vision, said Ari Peskoe, director of Harvard Law School’s Electricity Law Initiative. That led to the Trump administration trying to stem the shift from coal and nuclear to natural gas with a proposal that would have paid such baseload power plants outside of the ISO/RTO markets, effectively ending them.

“To maintain reliability, Scott Pruitt, who was then the head of EPA, went on TV and claimed that we needed to have 30% coal in our electricity mix, because, for the first time, coal was suddenly dropping below this marker,” Peskoe said. “And, so, he fabricated this number that was necessary to keep the system reliable.”

The so-called Grid Resiliency Pricing Rule, proposed by the Department of Energy, was rejected by FERC. Peskoe noted that the only utility to publicly support the rule was FirstEnergy, which was later found to be bribing Ohio officials for favorable treatment of its coal and nuclear plants in a massive corruption scandal.

Texas went further with restructuring than any other market, including on the retail side, and the devastating blackouts it experienced from Winter Storm Uri in February 2021 led to additional arguments against markets’ ability to maintain reliability.

“Texas is sort of vaunted as a purely competitive power market. It presents an interesting experiment, because there are actually a handful of remaining utility monopolies within the Texas ERCOT footprint that have no consumer choice, and which own their own fleet of power generation,” NRG Energy Vice President of Regulatory Affairs Travis Kavulla said. “And those power plants make their revenue by recourse to this captive base of ratepayers.”

Those traditionally regulated firms had poorer performance among their fossil fuel-fired power plants than did the competitive firms such as NRG, he added. The competitive market also was unable to pass along the huge costs from the storm, whereas Kavulla cited one gas utility in Oklahoma that is charging its customers $7/month for several decades to cover its costs from a week’s worth of natural gas.

The market felt major impacts from the storm, with Kavulla citing one NRG trader who had a retail deal exposed to wholesale prices and wound up spending $55 to boil a pot of water for tea that week. But instead of passing the costs along to customers for the next 20 years, NRG lost about $1 billion purchasing replacement power.

Uri also exposed issues with the side of the industry that has never seen any kind of deregulation — the distribution system — and how to implement rolling blackouts, Peskoe said. Utilities were not aware of vital natural gas infrastructure that needed power to keep operating, so when they cut off electricity to such sites, they only made the gas shortage worse, he added.

Winter Storm Elliott in late 2022 also showed that vertically integrated states can have some of the same issues, he said.

“It comes back to standards, sort of more traditional forms of regulation, because this is an essential good that people need,” Peskoe said. “And so, market or nonmarket is only sort of part of the debate; we have to have all this stuff happening to support the market or non-market and make sure that that all runs smoothly.”

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Citing California Law, FERC Rejects PG&E Request for RTO Adder

FERC on Dec. 29 rejected Pacific Gas and Electric’s request for an adder to its transmission rates based on its participation in CAISO, finding that California law precludes the utility from leaving the ISO without the state’s permission (ER24-96).

The rejection was part of a broader decision in which the commission partly accepted PG&E’s proposed revised formula rate and transmission recovery requirement (TRR), while also subjecting them to settlement judge procedures in light of protests from the utility’s transmission customers.

PG&E had proposed a base return on equity of 12.37%, which it said reflects its current financial situation and uncertainties and risks resulting from wildfires and California’s “inverse condemnation” law, which holds the state’s utilities responsible for damages caused by their equipment even in the absence of demonstrating negligence.

The utility said the base ROE fell within a “zone of reasonableness” ranging from 8.02 to 13.24% and contended that it deserved to be compensated at the higher end because of the risks it faces. On top of that, it also requested an adder of 50 basis points for participating in CAISO — for a total ROE of 12.87%.

Disputes around whether to allow California investor-owned utilities to recover an incentive for participating in the ISO have been ongoing. The commission in 2020 rejected the California Public Utilities Commission’s argument that PG&E was ineligible for the RTO adder — meant to incentivize utilities to join RTOs — because participation in CAISO was mandatory. FERC ruled that, based on California law, the utility’s participation in the ISO was voluntary and that it could unilaterally decide to leave. (See FERC Rejects RTO Incentive Adder Rehearing.)

But in September 2022, California amended its public utilities code to mandate that electric utilities join and remain members of CAISO, able to leave only with the CPUC’s approval.

The utility argued that because “California law expressly provides PG&E an opportunity to withdraw, subject to CPUC approval,” ISO participation is not strictly mandatory.

“We are not persuaded by PG&E’s arguments that there is a disputed factual issue about whether PG&E’s ongoing participation in CAISO is voluntary and that the commission should therefore set this matter for hearing and settlement judge procedures,” FERC said. “We find that, by virtue of the recently enacted California statute, PG&E is required to participate in CAISO and cannot unilaterally withdraw from CAISO. As such, PG&E’s participation in CAISO is no longer voluntary. Thus, we find that PG&E is no longer eligible for the RTO adder.”

FERC noted that the CPUC estimated the adder would have been worth $41.38 million annually.

Along with asking FERC to reject the RTO adder, several stakeholders also protested other aspects of PG&E’s proposed formula rate and TRR, contending the utility relied on an “inappropriately selected” proxy group for ROE comparatives, included an “expected earnings” analysis that is not part of FERC’s existing methodology and drew incorrect conclusions about its own risk position.

Among the complaints by protesters, two power agencies questioned PG&E’s accounting of its wildfire costs and the reasonableness of its proposed wildfire self-insurance program. Others contested the utility’s proposed 3.29% depreciation rate as being excessive, saying it was an unjustifiable increase from the presently authorized rate of 2.86%.

Having rejected the RTO adder, the commission said its preliminary analysis indicated that other aspects of PG&E’s requested formula rate and TRR might not meet FERC’s just-and-reasonable standard.

“We find that PG&E’s filing raises issues of material fact that, to the extent not summarily disposed of here, cannot be resolved based on the record before us and that are more appropriately addressed in the hearing and settlement judge procedures,” the commission wrote.

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Conditions Finally Reverted to (Somewhat) Normal for SPP in 2023

During SPP’s quarterly board meeting in October, CEO Barbara Sugg reflected on her tenure, which began shortly before the COVID-19 pandemic shut down the world in 2020.

“It is nice that after three and a half years as the CEO, we’re not talking about the pandemic anymore,” she told directors and stakeholders. “And we haven’t had a recent 100-year storm [in 2023].”

True. While the past year did not include a winter storm like those in February 2021 (Uri) and December 2022 (Elliott), it did include record-breaking heat during the summer that taxed the SPP system.

The grid operator broke the previous all-time peak several times before finally registering a record of 56.2 GW in August, a month during which it issued six conservative operations advisories for its footprint. Capacity dropped to ‑200 MW at one point during the summer, second only to the losses the RTO suffered during Winter Storm Uri. Imports from neighbors saved SPP both times.

“The summer was particularly challenging for us. It really tested our operators and your system operators as well,” Sugg told stakeholders. “The summer peak was 5% higher than the last summer, which was 5% higher than the summer before, which is incredible.”

Sugg said she is particularly concerned about the growth in demand and the variability of renewable resources. She pointed to a day in June when wind and solar resources produced only 111 MW at one point.

“That helps us really think about what we need to do to maintain reliability in the volatile climate,” she said. “The operating conditions certainly highlight the importance of maintaining the generation fleet and getting accreditation right for both conventional and renewable resources, and getting that to be as accurate as it can be.”

To that end, SPP created the Resource and Energy Adequacy Leadership (REAL) Team to mitigate resource adequacy risks and develop policies on fuel assurance, demand response and accreditation. The team — a cooperative effort between the Board of Directors, state regulators and stakeholders — has already signed off on performance-based accreditation for conventional resources and effective load-carrying capability accreditation for wind, solar and storage resources.

The REAL Team is waiting on the biennial loss-of-load expectation study to be finalized this spring. The study will fuel the effort to deliver winter and summer planning reserve margins to the team and to the July governance meetings.

FERC added to the REAL Team’s workload in November when it rejected SPP’s proposed winter resource adequacy requirement. However, the commission said the RTO can address FERC’s concerns and resubmit the proposal (ER23-2781). (See ‘Therapy Session’: SPP REAL Team Reviews Draft LOLE Study.)

Coming on the heels of Winter Storm Elliott, SPP set as its first goal improving grid resilience to prepare for extreme weather events. Staff have included winter scenarios in its 2024 and 2025 transmission plans and completed numerous recommendations from its review of the recent winter storms.

Another major priority for SPP has been improving a generator interconnection queue that contains more than 500 projects and more than 100 GW of capacity. Sugg said the RTO is still on track to meet its stated goal of clearing the original GI backlog and the 2022 cluster by the end of this year, having processed 93 GI agreements last year. Staff processed 37 agreements in 2022.

“I’m actually extremely optimistic about how far we will get with the ’22 and ’23 clusters … which is a far cry from where we were years ago when you were looking at four or five years to get answers on your generator interconnection requests,” Sugg said.

SPP also celebrated a $464 million grant from the Department of Energy to help fund its joint targeted interconnection queue projects with MISO. The portfolio and its five high-voltage transmission lines, recently revised to cost $1.86 billion, were one of several grid resilience and improvement projects to be awarded DOE funding from the Infrastructure Investment and Jobs Act. (See DOE Announces $3.46B for Grid Resilience, Improvement Projects.)

But that’s just SPP’s Eastern Interconnection footprint. Out West, where the grid operator is involved in several reliability and market initiatives, it received commitments from nine utilities that want to join its RTO West when it goes live in 2026. They are now obligated to reimburse the RTO for development expenses if membership agreements are not executed in March 2026.

In November, SPP began operating the Western Resource Adequacy Program (WRAP) on behalf of the Western Power Pool. The WRAP’s operations program produces seasonal forecasts to help determine whether participants have sufficient resources, and it enables anyone with a deficit to secure additional resources.

Western stakeholders and staff are well into the first developmental phase of Markets+, an RTO-light bundle of day-ahead and real-time market services. As 2023 wound down, stakeholders endorsed, and the Markets+ leadership approved, the market’s governance plan, helping clear much of the road to filing a tariff at FERC in February. (See IMIP Approves SPP Markets+ Governance Tariff Language.)

SPP’s Western Energy Imbalance Service added three Colorado utilities in April, expanding the reliability coordination market from 4.5 GW to 13.5 GW. The real-time balancing market, operational since 2019, provided an estimated $31.7 million in net benefits to its 12 participating utilities in 2022 at a benefit-to-cost ratio of 7-to-1, according to SPP analysis. The RTO said this resulted in reduced wholesale electricity costs by an average of $1.35/MWh over the year.

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Western Transmission Initiatives Differ on Dealing with Cost Allocation

The backers of two separate initiatives to spur development of new transmission in the West are taking different approaches on when to deal with the issue of who should pay for projects.

The Western Transmission Expansion Coalition (WTEC), launched by the Western Power Pool (WPP) and backed largely by the power sector, wants discussions about cost allocation to be put on the back burner while industry stakeholders first figure out what should be built.

But the Western States Transmission Initiative (WSTI), established by state regulators, thinks cost allocation must be addressed before serious planning can begin. (See In West, Proposals for Tx Planning Proliferate Faster than New Lines.)

WPP CEO Sarah Edmonds said WTEC efforts “aren’t touching cost allocation”; the subject is outside the intended scope of the effort, which is designed to expand the geographical scope of transmission planning to include all the West. “We aren’t part of a cost allocation federal tariff,” she noted during a Dec. 11 meeting of the CAISO Western Energy Imbalance Market’s Regional Issues Forum (RIF).

“Cost allocation is kind of one of those things that has really chilled conversation in the West around transmission planning. If we took that off the table for the WTEC effort, what might we find in terms of creative ideas?” Edmonds said.

While acknowledging the conundrum around the matter, Matthew Tisdale — executive director of decarbonization nonprofit Gridworks, which is partnering with the Committee on Regional Electric Power Cooperation on the WSTI — sees a problem with that approach.

“I think that planning and cost allocation are sort of a chicken and an egg here,” Tisdale said at the RIF meeting. “It’s hard to do the planning without understanding what is going to be the approach to cost allocation, and it’s difficult to do the cost allocation without knowing what you’re planning for.”

Both initiatives have set the stage for conversations about who will incur the costs and reap the benefits of much needed transmission projects in the West.

A key goal of WSTI is to form a Transmission Working Group that would, among several tasks, advance the discussion on transmission cost allocation. The states, Tisdale said, will be leading the conversation and coordination around how the cost of interregional transmission could be allocated across state lines.

‘Taking the Bull by the Horns’

While Tisdale, Edmonds and CAISO officials at the meeting agreed that states should be the entities to determine cost allocation for transmission projects, some stakeholders expressed concern about the challenges of that approach for allocating costs across state lines.

Matt Lecar, principal at Pacific Gas and Electric, highlighted complexities surrounding different regulatory requirements; for example, California could agree on a cost allocation framework not matched by entities elsewhere in the region.

“I get that having the states buy in on a cost allocation framework brings down the risk barrier, but what’s going to convince me that the billion dollars or more that I spend on constructing and bringing online a project is going to lead to a successful cost recovery via a mix of jurisdictions that may or may not see eye-to-eye on whether those costs were prudently incurred?” Lecar said.

“Discussions around ratepayer recovery of transmission facilities have been challenging under [FERC] Order 1000, and we need to have the cost allocation conversation,” said Danielle Osborn Mills, director of market policy development at CAISO. “In the meantime, we’re trying to think creatively around how we can have bilateral arrangements that lead to shared benefits across the region and also appropriately shared costs.”

Michele Beck, director of the Utah Office of Consumer Services, emphasized the need for greater coordination among consumer advocates, regulators and transmission planners. She expressed concern that while the WSTI interviewed more than 40 stakeholders, consumer advocates were not included.

Beck also noted that while the WSTI has signaled it will include public interest organizations in a Western transmission conference it intends to host, consumer advocates were again left out.

“We’re very cautious about an emphasis on cost allocation and moving forward on that, especially when we may or may not be at the table,” Beck said. “In our view, sometimes that can be a euphemism for finding a way to get more people to pay for projects … that might be desired only by a subset of the folks involved.”

While there was some disagreement on how costs should be allocated, energy officials seemed to agree upon the struggle to find a better option.

“The states leading on cost allocation is probably the worst forum for developing cost allocation — except for all the other ones, because all the other ones haven’t worked for 20 years either, and so we want to see some leadership in the region,” Tisdale said. “We want to see somebody taking the bull by the horns and raising hard questions.”

A public webinar regarding the WTEC project is scheduled for Jan. 29.

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DOE Lays out Plans for Designating Transmission Corridors

The Department of Energy plans to release a list of potential National Interest Electric Transmission Corridors (NIETCs) this spring.

DOE has already released a transmission needs study looking at where new projects could be beneficial around the country, and it released a related guidance document last month. (See DOE to Sign Up as Off-taker for 3 Transmission Projects.)

“This guidance improves upon previous NIETC designation processes in response to both court decisions and updates to our authority in recent legislation,” Grid Deployment Office (GDO) Director Maria Robinson said during a webinar Jan. 3. “Specifically, I’ll note that the proposed process would designate narrow geographic areas as NIETCs, rather than large swaths of land.”

The department is taking public comment on that guidance, which is due Feb. 2, and it plans to release a list of NIETCs that it will continue to study 60 days after that.

“This list will provide the preliminary geographic boundaries of potential NIETCs, which we expect to be sort of a rough approximation,” said Gretchen Kershaw, GDO senior adviser for transmission.

The lists will also include preliminary assessment of transmission needs within the relevant area and any harms to consumers, essentially explaining the threshold need determination made in phase 1, she added.

The transmission needs study identified a need for interregional transfer capacity around the country, but Kershaw said DOE’s process would favor lines with multiple benefits in addition to increasing the ability to ship power between regions.

The list will provide high-level explanations of why potential NIETCs moved to phase 2 of the designation process, and any that did not will continue to be eligible in future designations. Stakeholders will have an additional 45 days to provide comment on those in phase 2. DOE will look to refine the NIETCs’ geographic scope and start to consider environmental assessments.

DOE will further narrow down the list and then formally propose the NIETCs in phases 3 and 4. The department is unsure of the timeline for that because of how long environmental reviews can take, Kershaw said. A standard environmental impact statement takes the department about two years to produce, she added.

The department does not plan to propose massive corridors, as it did the last time it designated a pair of NIETCs in 2007, Kershaw said. In a process that was ultimately stymied by the courts, the department picked one route that covered Southern California and parts of Arizona and another that covered much of the mid-Atlantic into New York City — both designed to ship cheap power into the two biggest cities in the U.S.

“It concentrates stakeholder attention on where new transmission is most likely to be built within a NIETC by having that narrower scope,” Kershaw said. “The narrower geographic areas also lead to more efficient preparation by DOE of environmental documents again focused on a narrower area, and also more useful environmental documents for permitting agencies including FERC.”

The Infrastructure Investment and Jobs Act granted FERC the authority to approve new transmission in the corridors when states either lack authority to site a project (if they cannot consider regional benefits, for example), have not acted on an application after a year or have denied an application for a line.

FERC is reviewing its own authority under the NIETC process with a Notice of Proposed Rulemaking (RM22-7). (See FERC Backstop Siting Proposal Runs into Opposition from States.)

Some projects will use that authority from FERC under Federal Power Act Section 216b, but for those that do not, DOE can help coordinate all federal authorizations and environmental reviews under Section 216h of the law, Kershaw said.

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Delaware Lays out Potential OSW Strategy

Delaware’s environmental agency has proposed an offshore wind procurement strategy for one of the few East Coast states without a stated goal for developing wind energy from the ocean.

The Department of Natural Resources and Environmental Control (DNREC) State Energy Office announced Jan. 3 that it had delivered the report to the governor and legislators.

It lays out the many moving pieces in an industry that holds great promise for producing clean energy but is experiencing severe growing pains in the United States.

Delaware, which has the shortest ocean coastline of any state with coastline except New Hampshire, currently has no plans for offshore wind procurement. The official state webpage for offshore wind leads off with a noncommittal summary: “Delaware continues to explore opportunities and challenges presented by the growing offshore wind industry.”

But the state has set a target for 40% renewable energy by 2035. And its Renewable Energy and Clean Technologies Workgroup recently recommended the state develop a procurement mechanism for at least 800 MW of offshore wind capacity.

This compares with goals of 8.5 GW in Maryland and 11 GW in New Jersey.

The strategy proposed by DNREC analyzes the cost, benefits and impact of a hypothetical 800-MW wind farm on the Outer Continental Shelf.

The report flags an inherent challenge: There are few options other than offshore wind for delivering renewable energy in the quantities needed by Delaware, but offshore wind is an industry where economy of scale is especially important, and it is hard for such a small state to achieve economy of scale on its own.

The strategy recommends looking at partnerships with neighboring states to achieve that economy.

It also reviews the uncertain and changing factors affecting the U.S. offshore wind industry, predicts developments in 2024 that will affect planning and offers recommendations on structuring a procurement.

The U.S. Bureau of Ocean Energy Management has designated wind energy areas in the vicinity of Delaware, but projects proposed to date would feed into Maryland. Delaware’s only role would be as a landing site for export cables.

Nearby, Ørsted has canceled both phases of a proposed wind farm that would feed into New Jersey. Ørsted has not canceled the proposed Skipjack Wind — a Maryland project off the Delaware coast — but it has scaled investments back to a minimum.

The report was produced by DNREC’s Division of Climate, Coastal and Energy with Synapse Energy Economics and Zooid Energy.

“This report provides the background, current economic conditions and options for the governor and state legislators to consider as Delaware charts its path forward in the development of a comprehensive offshore wind program,” DNREC Secretary Shawn M. Garvin said in announcing the proposed strategy.

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NJ Ready for Clean Energy Advance in 2024 After OSW Meltdown

New Jersey is looking to strengthen its clean energy commitment in 2024 with new wind projects, an enhanced community solar program and legislation to aggressively improve the grid after a year in which the state’s much-touted offshore wind program (OSW) suffered a major setback.

The New Jersey Board of Public Utilities (BPU) expects by March to pick the winners from the four projects submitted for the state’s third OSW solicitation, which could add capacity of 4 GW, and perhaps more, in line with solicitation guidelines.

A successful and sizable allocation of projects could help quell doubts that have swirled over the state’s OSW program since Danish developer Ørsted abandoned its two projects planned for the New Jersey coast — the 1,100-MW Ocean Wind 1 and 1,148-MW Ocean Wind 2. Ocean Wind 1, approved in 2019, was the state’s first and most advanced project.

Ørsted’s comments that the two projects were no longer economically viable raised questions about the wisdom of the state’s aggressive gambit on the OSW projects, which included the New Jersey Wind Port, to which the state has committed about $1 billion.

The projects’ demise marred a year that otherwise contained significant advances for clean energy policy. The state in November adopted California’s Advanced Clean Cars II (ACCII) rules, which require a growing proportion of new car sales to be zero-emission vehicles until all new sales must meet that criterion in 2035.

The state also created a permanent Community Solar program, based on the experience of two (heavily oversubscribed) pilot programs that confirmed developer interest. The program started accepting applications in November. And the state made aggressive moves to cut emissions from buildings, its second-highest source of greenhouse gases after transportation.

“Clean energy policy is a game of inches, and certainly the ball was moved down the field this year on a number of significant fronts,” said Doug O’Malley, director of Environment New Jersey. “Obviously, there’s always going to be bumps along the way.”

He called Ørsted’s withdrawal a “sucker punch,” but noted that offshore wind projects continue to advance in other East Coast states, and cited New Jersey’s third solicitation as evidence that the sector marches on.

“There are multiple projects in the queue that will allow New Jersey to benefit from offshore wind in the future,” he said.

Decarbonizing Buildings

Gov. Phil Murphy (D) set the tone on building decarbonization, signing executive orders in February designed to “advance the electrification of commercial and residential buildings.” He also set a goal of electrifying 400,000 additional dwelling units and 20,000 additional commercial spaces or public facilities by December 2030.

The same day, Murphy signed an executive order that required the BPU to look at how to mitigate the impact on the gas industry and its workforce as the state switched to using electric hot water and heating appliances in pursuit of a 50% reduction in greenhouse gas emissions below 2006 levels by 2030.

In line with that intent, the New Jersey Economic Development Authority (EDA) in December launched a $15 million grant program to help commercial building owners retrofit heating or cooling systems.

The prospective shift has stoked vigorous opposition among business groups, unions and fossil fuel companies. In November, they backed a bill, A577, that would enable the use of renewable natural gas in the state’s gas infrastructure. But environmentalists, who say it is an unproven technology, fear that allowing renewable natural gas would weaken the state’s commitment to electrification. (See NJ Advances Multifaceted Building Decarbonization Strategy.)

New Master Plan

Murphy, and the BPU, remain committed to the wind sector. The governor’s vision of the state’s energy future likely will be laid out in the release of a new energy master plan some time this year. The last version of the plan, “Pathway to 2050,” released in 2019, has been a cornerstone of the state’s drive toward a zero-emissions energy policy. Business groups and Republicans have expressed concerns about the cost of the initiatives, which the governor has yet to fully outline.

Businesses are concerned they don’t know enough about the cost of the state’s proposed initiatives, especially the shift from fossil fuel use in buildings to electricity, said Michael Egenton, a lobbyist for the New Jersey Chamber of Commerce. He said he’d like to see more transparency this year and to see the Legislature more involved in clean energy decision-making, not just the BPU.

“I’m not saying that things should not be pursued, but it has to be done practically, logically, timely,” he said, expressing skepticism that the state can meet Murphy’s targets, such as the ACCII rule to have all new vehicles sold be electric vehicles by 2035.

“We need more information, we need to know what this is going to cost, and who’s going to be responsible for those costs,” he said.

Murphy’s task likely was made more challenging by the death Sept. 7.  of Joseph L. Fiordaliso, the well-regarded BPU board president and a BPU commissioner since 2005, who led Murphy’s efforts to transform the state. Murphy immediately appointed Christine Guhl-Sadovy, a clean energy advocate and Fiordaliso’s former chief of staff, as the board’s leader. (See NJ BPU President Fiordaliso Dies.)

Yet the board enters this year short of the depth of experience Fiordaliso possessed, with three remaining members who joined the board in the past two years. The Senate approved a fourth member, Michael Bange, a manager for New Jersey American Water, on Dec. 21.

Legislative Push

The Legislature also has pushed a vigorous clean energy agenda. Some Democrats and environmentalists saw the results of the November 2023 legislative elections — in which Democrats held their majority in the Senate and added five seats in the Assembly — as evidence the public backs clean energy initiatives. The GOP in some races sought to depict such initiatives as excessive and expensive.

Sen. Bob Smith (D), chairman of the influential Senate Environment and Energy Committee, which shapes many of the Legislature’s clean energy bills, sees two bills as key elements of the 2024 session. Legislators debated but did not act on either bill in the current legislative session, which ends Jan. 8. They will be heard in the next session, which starts Jan. 9.

One of the bills, S2978 in the current session, would put into law a Murphy executive order that set a state goal of reaching 100% clean energy by 2035. A second bill, S3992, would allocate $500 million in state and federal money to invest in upgrades to the state grid to prepare it for the expected surge in clean energy use, Smith said.

“Our grid is made up of bobby pins and chewing gum — the grid’s in terrible shape,” Smith said. “You can’t connect [a project] to the grid, because the utility, the [electric distribution company], will say, ‘Well, we have to do a study, and you’re gonna have to pay for improvements to the grid’” that are needed to handle the proposed project, he said.

Prior to the close of the current legislative session, there are several bills on Murphy’s desk that Smith hopes could produce important clean energy policy, provided he signs them. If he doesn’t, the sponsors would have to start the process again in the next session.

Bill S3723, the Electric and Hybrid Vehicle Battery Management Act, would prohibit the disposal of vehicle batteries in the solid waste stream and create a framework for the proper disposal and recycling of the batteries. Smith believes it is the first legislation of its kind in the nation.

A second bill, S3490, would adjust the rules for make-ready charging stations to make it easier to install EV chargers in certain situations, especially in multi-dwelling units.

O’Malley said the need to accelerate the installation of EV chargers is an example of an issue the state, for all its clean energy efforts, needs to address more aggressively this year.

“New Jersey is way behind other states on the national electric vehicle infrastructure implementation,” he said. “We need to expand our charging network everywhere, not just the Turnpike and Parkway. It should be as easy to find an electric vehicle charging station as it is to find a 7-Eleven or a Wawa.”

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FERC Approves ISO-NE’s One-Year Delay of FCA 19

FERC has approved ISO-NE’s proposal to delay Forward Capacity Auction (FCA) 19 by one year, pushing the auction to February 2026 (ER24-339). The auction is for the capacity commitment period (CCP) that runs from June 2028 through May 2029.

Further changes could be on the horizon for FCA 19. ISO-NE has initiated the delay to update how it accredits the capacity value of different resources, as well as to consider structural changes to the capacity auction’s timing.

The RTO and its stakeholders are contemplating whether to change the capacity market from a forward-annual auction format to a prompt-seasonal format. While the current forward auction is held more than three years before the CCP, a prompt auction would be held just months prior to the CCP. A seasonal format would break up the yearlong CCP into distinct seasons with separately procured capacity.

In December, Analysis Group recommended that ISO-NE move to a prompt and seasonal auction for FCA 19, saying it would help the region cope with the rapidly changing influx of clean energy resources. (See Analysis Group Recommends Prompt, Seasonal Capacity Market for ISO-NE.) If ISO-NE ultimately moves to a prompt market for FCA 19, this could delay the auction to early 2028.

FERC found ISO-NE’s proposal of a one-year delay to be just and reasonable, noting that “the requested delay will allow ISO-NE the time necessary to develop a revised capacity accreditation methodology, in addition to further potential changes to the [forward capacity market] design.”

The filing was not opposed by any stakeholder groups, and was supported by the New England Power Generators Association, FirstLight Power and a coalition of public power entities.

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FERC Approves Dairyland Incentives for Minn.-Wis. Transmission Line

FERC on Dec. 29 approved Dairyland Power Cooperative’s request for transmission rate incentives for its investment in the Wilmarth-North Rochester-Tremval project, a 169-mile line spanning Minnesota and Wisconsin that is part of MISO’s 2021 Transmission Expansion Plan (MTEP 21) (ER24-260).

The Wisconsin-based cooperative received authorization for the construction work in progress (CWIP) and abandoned plant incentives for the 345-kV span, which will connect the Wilmarth substation near Mankato, Minn., to the Tremval substation near Blair, Wis. The project involves building a new 161/69-kV substation near Kellogg, Minn., north of Rochester, and upgrading existing 161-kV facilities.

FERC also granted Dairyland a hypothetical capital structure of 50% equity and 50% debt for the life of the financing of the project. The line is expected to be in service by June 2028 and cost about $689 million.

“Dairyland expects to invest an estimated $207.5 million in the project, or 44% of its projected 2023 net transmission plant in rate base,” the commission said. “The project’s multiple owners and complexity present significant risk, and the record shows that this investment could put downward pressure on Dairyland’s financial metrics. We find that the hypothetical capital structure and CWIP incentives will provide upfront certainty, bolster Dairyland’s financial metrics to help ensure maintenance of its current credit rating and facilitate its participation in the project.”

Xcel Energy, Southern Minnesota Municipal Power Agency and Rochester Public Utilities are co-owners of the project.

In a concurrence, Commissioner Mark Christie continued to urge the commission to reconsider its policies on incentives, although he acknowledged that Dairyland met the standards the commission laid out in Order 679.

“Just as the CWIP incentive effectively makes consumers the bank for transmission developers, the abandoned plant incentive effectively makes them the insurer of last resort as well,” he wrote. “As this commission considers other potential reforms related to regional transmission planning and development, it is imperative that incentives like the CWIP incentive, abandoned plant incentive and RTO participation adder are all revisited to ensure that all the costs and risks associated with transmission construction are not unfairly inflicted on consumers while transmission developers and owners stand to gain all the financial reward.”

Commissioner James Danly, who left the commission at the end of the year, recused himself.