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November 5, 2024

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FERC Accepts Results of New England Capacity Auction

FERC accepted the results of ISO-NE’s Forward Capacity Auction 18 on June 18, finding that the auction was run according to the RTO’s tariff and that protests submitted by climate activists were outside the scope of the proceeding (ER24-1290).  

FCA 18, which was held in February and relates to the 2027/28 capacity commitment period (CCP), saw an approximately 40% increase in the cost of capacity relative to the previous auction, along with a rise in renewable resources. (See Prices, Renewables Rise in New England Capacity Auction.) 

The auction likely marks the last auction held prior to the implementation of major changes to ISO-NE’s capacity market.  

The RTO is amid a multiyear process reworking how it calculates resource capacity values, and also is pursuing significant changes that would split the annual CCP into seasons and hold auctions much closer to each CCP. This year, FERC approved a three-year delay of the next capacity auction to give ISO-NE time to develop these changes with the goal of implementing them for FCA 19. (See FERC Approves Additional Delay of ISO-NE FCA 19.) 

ISO-NE’s filing of the results spurred opposition from climate activists, who argued the auction was biased in favor of fossil fuel resources. (See Climate Activists Urge FERC to Reject Results of ISO-NE FCA 18.) 

“These results are in violation of ISO-NE’s tariff and mandate to ‘protect the health of the region’s economy and the well-being of its people by ensuring the constant availability of competitively priced wholesale electricity — today and for future generations,’” the group No Coal No Gas wrote in comments signed by more than 4,000 individuals. The group also protested the results of the three prior FCAs.  

“FCA 18’s award of nearly $350 million in forward capacity payments to fossil fuel peaker plants is a clear violation of this mission,” the organization added. “Supporting fossil fuel generators that can only provide electricity by worsening climate change and exacerbating grid instability is dangerous, irresponsible grid management.” 

Echoing its response to the protests of previous FCAs, FERC sided with ISO-NE, ruling that the structural critiques of the auction are outside the scope of the proceeding. (See FERC Accepts Results of ISO-NE FCA 17.)

The commission wrote that the protests “do not bear on the sole question here — namely, whether ISO-NE conducted FCA 18 in accordance with the requirements set forth in its tariff.” 

“Instead, these protests largely challenge the FCM design and raise various challenges related to climate change, fossil fuels, the minimum offer price rule and the Merrimack Generating Station, which are issues that are beyond the scope of the instant proceeding,” FERC said. 

FERC added that the concerns about a conflict between ISO-NE’s mission statement and the capacity market design “are more appropriately raised in the stakeholder process.” 

ISO-NE applauded FERC’s ruling, writing in a statement that “the Forward Capacity Market is and has been open to all resources able to provide capacity to the region, and claims of bias are without merit.” 

“All the new resources clearing in this year’s auction were renewable energy, battery storage or demand-reducing resources,” wrote ISO-NE spokesperson Matt Kakley. “We look forward to continuing to work with stakeholders and the New England states on longer-term changes to the capacity market.” 

Meanwhile, climate activists expressed disappointment with the decision and took issue with the commission’s suggestion that they raise their concerns within the NEPOOL stakeholder process.  

Marla Marcum of No Coal No Gas emphasized that the NEPOOL process is closed to nonmembers and that member groups representing end users have minimal voting power within the organization. 

“Referring us to a body to which we are unlikely to gain access, and which explicitly limits public input and agency, is unfortunately typical of this system — a system designed to prevent meaningful participation,” Marcum said, adding that FERC’s ruling suggests ratepayers “should have no effective way to participate in decisions about the billions of dollars taken from their utility bills every year to manage the grid.” 

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Renewable Development Faces Regulatory Tangle

Two new reports have been published on the profusion of local and state regulations affecting renewable energy development — one attempting to summarize them, the other quantifying the growing number of restrictions they impose. 

“Laws in Order: An Inventory of State Renewable Energy Siting Policies” summarizes the renewable energy siting and permitting policies in the 50 states and Puerto Rico. One of its findings is that the approach to this type of regulation can be difficult to categorize because it varies widely from one state to the next. 

“Opposition to Renewable Energy Facilities in the United States: June 2024 Edition” is an update of similar reports in 2021, 2022 and 2023. This year’s report finds 29% more contested projects nationwide than last year’s, along with 73% more local restrictions and 111% more state-level restrictions. 

List of Laws

“Laws in Order” was prepared by the Regulatory Assistance Project and Clean Air Task Force with support from the Department of Energy, Lawrence Berkeley National Laboratory and Consensus Building Institute. 

The team created an inventory of the siting and permitting policies that pertain to large-scale solar and onshore wind projects and the often-complex, layered mesh of approvals needed before construction can start. 

The report provides a summary of the findings and draws a profile for each state and is accompanied by an interactive map. It also identifies the: 

    • entities within each state or territory that make siting and permitting decisions; 
    • level of government that has the authority to set standards for large-scale renewables siting and construction;  
    • requirements for public involvement;  
    • timelines that exist; and 
    • availability of permitting guides and model ordinances designed to support local decision-making. 

A display of state-level model ordinances available to guide solar and wind power development | Regulatory Assistance Project

Illustrating the highly varied nature of regulatory oversight, the report notes that 12 states give local governments principal jurisdiction, the governments in five states and Puerto Rico hold jurisdictional authority, local and state governments share authority in six states, and oversight can fall to either the state or the local government in 27. 

List of Obstacles

“Opposition to Renewable Energy Facilities” was produced by the Sabin Center for Climate Change Law at Columbia University. 

Without making individual judgments on the hundreds of examples they cite, the authors conclude that as a whole, there is widening local opposition to renewable energy facilities that is a potentially significant barrier to achieving emission-reduction goals. 

The report looked only at restrictions so severe that they have either killed a specific project or could limit or ban development of renewables. It catalogs 395 such restrictions at the local level and 19 at the state level in 41 states. It also identifies 378 renewable projects in 47 states that have encountered significant opposition. 

Alaska was the outlier as the only state with no severe restrictions or significant controversies identified. 

Polices that bear indirectly on renewable energy facilities — such as net metering, renewable energy standards or subsidies — are not included if they do not bear directly on renewables. But the authors note local governments increasingly taking action to oppose the infrastructure needed to support renewable energy facilities, such as transmission and battery storage.

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FERC Order 1920 Sees Wide-ranging Rehearing Requests

FERC has received rehearing requests on Order 1920 ranging from stakeholders who just want to see a few tweaks, to those who prefer the commission trash the entire order and start over.

Many states filed for rehearing on the order, arguing for more authority and flexibility for their efforts to reform transmission planning and cost allocation rules that started before FERC issued its order. (See Order 1920 Rehearing Request from States Seek Bigger Role in Tx Planning.)

The only two RTOs that filed for rehearing also sought flexibility to keep going with the changes they have been working on with stakeholders. PJM seeks to continue with its Long-Term Regional Transmission Planning (LTRTP) process and SPP with its Consolidated Planning Process (CPP).

PJM’s changes would lead to a process where, working with states and other stakeholders, it could come up with scenarios based on evolving concerns such as the changing resource mix and new demand. It was designed to reflect the realities of the RTO’s region, which is “comprised of 14 jurisdictions that have public policy initiatives that are simultaneously overlapping and conflicting — while also taking into consideration the challenges the PJM region is facing as a result of the accelerating energy transition.”

The LTRTP process is meant to deal chiefly with reliability while considering states’ policy requirements in consultation with them. The rule prevents transmission providers from setting up cost allocation methods that separate out reliability, economic and public policies, but PJM said its disparate state membership means it should be exempted from that. The LTRTP process does not align with Order 1920’s requirements perfectly, and some details differ from FERC’s requirements, the RTO said.

“However, PJM believes that the PJM LTRTP process is directionally consistent with the commission’s long-term planning goals, and importantly, the process recognizes PJM’s unique needs and circumstances,” the RTO said.

SPP asked for clarification that it could move forward with a different set of rules around its CPP process.

“The CPP will include a comprehensive long-term assessment that projects supply and demand needs over a 20-year period, incorporating regional and subregional components,” the RTO said. “The CPP will allow for simultaneous planning of transmission, as opposed to the piecemeal approach SPP employs today.”

The new planning process uses a single, common base model for the entire region, it improves data collection, and SPP said it was working on a cost allocation method that would require flexibility from some of Order 1920’s requirements.

The Re-evaluation Requirement

One area transmission owners singled out for review was the requirement that transmission projects be re-evaluated after they’re picked in a regional plan under Order 1920.

It kicks in when projects are delayed long enough to impact reliability, if actual costs significantly exceed estimates, or if some underlying law or policy changes.

The Edison Electric Institute argued that section of the rule was poorly noticed, with FERC pointing to paragraph 248 in the Notice of Proposed Rulemaking. The utility trade group argued that paragraph lacked sufficient detail to count as appropriate notice under the Administrative Procedure Act.

“The onus is on the agency to inform stakeholders that it is considering a proposal put forth in comments; the onus is not on stakeholders to sift through thousands of pages of comments and respond to each one in case the agency should decide to use a particular proposal as the basis for its final rule,” EEI said.

Order 1920 largely takes MISO’s transmission planning process and sets it as the baseline for other regions to implement their own rules around, but a large group of MISO TOs argued that the re-evaluation requirement goes well beyond what they are used to in one key way: The RTO’s “variance analysis” does not require transmission lines to be re-evaluated using new benefits that have been updated since it initially was planned.

The benefit re-evaluation requirement conflicts directly “with the commission’s intended goal of shaping a regulatory environment that facilitates regional transmission development,” the MISO TOs said.

Using new benefits in the updated process creates massive uncertainty for transmission development and basically “requires re-planning every five years,” they added. That increases the risk that transmission will be removed from the plan based on entirely new inputs and assumptions, which can put at risk permits required by other regulators and could implicate projects already under construction.

“Such uncertainty also risks spooking investment in these crucially needed transmission facilities and may delay subsequent portfolios of long-term regional transmission facilities as the resources that would otherwise be used in their development will be used to re-evaluate past portfolios,” the TOs said.

The WIRES Group also told FERC it should reconsider the re-evaluation requirement because it could undermine, by delay or cancellation, the development and timely completion of long-term regional transmission facilities.

Rights of First Refusal

Both WIRES and EEI had the re-imposition of rights of first refusal as a major goal for the order, and FERC did that with projects “right-sized” from the local planning process into the regional planning process, but neither of them brought up the issue in their rehearing filings.

The right-sized ROFR did come under fire from the Electricity Transmission Competition Coalition, the Resale Power Group of Iowa and LS Power Grid.

“Competition in the transmission planning process for the right to develop and construct new transmission facilities reduces costs to consumers and drives efficiencies in project construction,” ETCC said. “The Competition Coalition supports competition and competitive prices to maintain just and reasonable transmission rates, consistent with Order No. 1000’s pro-competition directives.”

Giving incumbent owners a ROFR over transmission projects elevated out of the local planning process was meant to deal with what FERC said were infirmities in those processes. But the rule change is not based on any finding that the current regional planning processes are unjust and unreasonable.

“Nevertheless, in its declaration that [Federal Power Act] Section 206 allows it to act, Order No. 1920 seems to take the position” that it can modify any tariff provision regardless of whether it was found to be is just and reasonable, ETCC said. “There is no statutory or judicial support for such a broad reading of the requirement under the first prong of Section 206 of the Federal Power Act.”

Environmentalists Want Stronger Requirements

A joint filing from “public interest organizations” — including the Environmental Defense Fund, the Environmental Law & Policy Center, the Natural Resources Defense Council, the Sierra Club and the Sustainable FERC project — said they support the general direction of the order and FERC’s goal to efficiently expand the grid.

Order 1920’s changes “represent the lynchpin of the commission’s multi-proceeding reform effort,” and they “applaud the commission’s extensive stakeholder engagement and thoughtful consideration of the nearly 17,000 pages of comments from nearly 200 diverse parties,” the environmentalists said.

But the commission should issue firmer mandates to get around the “inherent economic incentives of transmission providers (and their generation owners)” that lead them to avoid building out transmission to preserve local market power, they argued. FERC should specifically require that transmission planners must plan around access to cheaper generation and cannot discount that benefit.

Clean Energy Trade Groups Request Tweaks

Advanced Energy United, the American Clean Power Association, American Council on Renewable Energy and Solar Energy Industries Association — filing as the “Clean Energy Associations” — supported most of the order, but they filed a request seeking a handful of changes.

The commission was wrong to include interconnection-related upgrades in the short-term process and the new 20-year LTRTP process envisioned in Order 1920, they said. The commission also should change the order by eliminating a requirement that those network upgrades meet minimum voltage thresholds, as its rationale was ambiguous on how transmission providers must determine network upgrades for inclusion in the regional plans, they argued.

The rationale for leaving network upgrades in the short-term plans that still will be run under the Order 1000 process is that they need to be built soon under generators’ interconnection timelines.

“However, the Clean Energy Associations respectfully submit that near-term progress and long-term progress in this area are not mutually exclusive and should be pursued in parallel,” they argued.

Harvard Electricity Law Initiative Backs State Cost Allocation Rights

FERC decided against requiring transmission providers to file state agreements on cost allocation because of the precedent set when Atlantic City Electric sued it over related issues.

But Harvard Law School’s Electricity Law Initiative argued that case applies only to utility filing rights under FPA Section 205. FERC still could make it a requirement under Section 206; not doing that effectively expands Atlantic City’s legal impact.

“Atlantic City does not prevent the commission from amending the pro forma OATT to include a process for filing all regional cost allocation methods approved by relevant state entities, regardless of the transmission provider’s approval,” the Harvard group said. “Imposing a process for filing relevant state entities’ cost allocation methods would not ‘deny [utilities] their right to unilaterally file rate and term changes.’”

The new process would supplement the existing cost allocation processes, whether held by TOs or RTOs. Giving states a guarantee that their work will be given at least a review by the commission would be a marked improvement over what the rule contemplates: states gathering to come up with ideas that the RTO or utilities can reject to use their own cost allocation method instead.

“State regulators might prefer to forgo this process entirely in order to avoid bargaining in the shadow of transmission providers’ veto authority,” the Harvard initiative said. “By placing transmission providers above state officials, the final rule grants utilities leverage over their regulators, potentially interfering with regulators’ duties under state law.”

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Vermont Heating Fuel Sales Decreasing in Recent Years

Vermonters are using less fossil fuel for heat in recent years, partly because winters have been trending warmer but also because more buildings are relying on electric heat pumps. 

The Energy Action Network lays out the data in a new report showing heating fuel sales lower than the previous year in four of the five years from 2019 through 2023. 

The total decrease from 2018 to 2023 was 12% as measured by Btu, and that came even as the state’s residential housing stock expanded by 2.7%. 

Meanwhile, annual heating degree days (HDD) were 8% lower in 2023 than in 2018.  

And the heat pump count climbed sharply each year during that period, from 12,834 in 2018 to 64,617 in 2023. 

Installation of heat pumps has been rising steadily in Vermont over the past six years. | Energy Action Network

The Energy Action Network, which unites more than 200 organizations working to achieve Vermont’s climate and energy goals, said the warmer winters are the largest factor in the declining use of heating fuel. The authors calculated the impact of weather at about 50% of the total reduction. 

Vermont has a longer and colder heating season than most states, and while its annual HDD total has ranged from fewer than 7,000 to more than 8,000 over the past 33 years, a warming trend has been observed. 

“Several other factors likely played a role, including increased adoption of electrification, efficiency and other pollution reduction measures,” the authors wrote in the May 2024 report. Largest among those would be high-efficiency heat pumps, which EAN estimates account for about 28% of the decrease in heating fuel sales. 

That decrease was not uniform. 

Fuel oil and kerosene sales were down 22.2% from 2018 to 2023, but fossil gas sales decreased only 9% and propane sales increased 4.3%. 

Some factors are hard to quantify — for example, the authors made no attempt to estimate how many people in the heavily forested state increased the amount of wood they burned or turned down their thermostats in attempts to economize as fossil fuel prices soared. But they saw no decrease in the quantity of fuel sold as prices rose and no decrease in sales as prices fell. 

They estimated smaller impacts on fossil heating fuel sales from installation of higher-efficiency residential fossil-burning equipment (7% of the total), residential weatherization (5%) and wider use of heat pump hot water heaters (3%). 

The report warns against Vermont relying on a continued warming trend to meet its climate goals. 

“To be less dependent on the whims of weather — so that we are not counting on record-breaking warm winters to meet thermal sector emissions reduction targets — more concerted efforts to help customers install and properly operate heat pumps for both space and water heating and complete weatherization projects will be necessary to achieve more predictable and durable emissions reductions,” the authors write. 

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ERCOT Board Chair Foster Steps Down

Paul Foster, who chaired ERCOT’s first Board of Directors under rules established in the aftermath of 2021’s disastrous winter storm, announced June 18 that he is stepping down from the position. 

Vice Chair Bill Flores will replace Foster on an interim basis, effective June 20. 

Foster said he had been thinking about leaving when his term expired this year. However, he said a recent discussion with Texas Gov. Greg Abbott (R), who plays a role in selecting ERCOT’s board members, hastened his decision. 

“It became clear to me it’d be much more beneficial to the board and to ERCOT for this transition to happen sooner rather than later,” Foster told the board. “ERCOT has a tremendous amount of work to do in the last half of 2024 leading into a legislative session. … The board has a lot of work to do, shaping and supporting these efforts. Having a new board chair and a new board member in place as soon as possible and well in advance of the legislative session is what would be best for ERCOT.” 

The Texas Legislature meets biennially. Its 90th session begins next January, with legislators expected to probe ERCOT’s market changes and performance.  

Foster was appointed as chair in October 2021 as one of the revamped board’s first two independent directors. The previous board’s members, six of whom did not live in Texas, resigned under pressure after Winter Storm Uri brought the grid within minutes of a total collapse. (See Two New ERCOT Directors Named, Replacing Current Board.) 

Legislation passed after the storm now requires board members to be Texans and independent of the ERCOT market, and have executive-level experience in several disciplines. A three-person board-selection committee appointed by the governor and the state’s other two political leaders is responsible for picking board members. 

Foster is president of Franklin Mountain Investment and founder of Western Refining. An El Paso philanthropist, he has been renovating a third downtown building in his hometown. 

“When I took this job, I had only a very high-level understanding of the grid and the market,” Foster said. “What I’ve come to learn in my tenure as chair is that this is the most dynamic, innovative, adaptive and forward-looking electric grid and competitive market in the world. Texas and ERCOT are at the forefront in the global energy transfer transformation that is currently taking place … and frankly, I think we’re handling it better than just about anybody else.” 

Foster heaped praise on ERCOT’s staff and the Public Utility Commission, which oversees the grid operator. 

“As I leave this post, I truly believe that ERCOT is headed in the right direction with the right people in leadership and poised to lead the world through the energy transformation that we’re in the middle of,” he said.

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NYISO: Prepared for Heat Dome Scorching New York

NYISO says it is prepared to meet demand during an extreme kind of heat wave called a heat dome that is already spiking temperatures to near 100 degrees Fahrenheit in western New York and is expected to spread this week throughout the state, northern New England and New Jersey. 

“Based on current conditions, … NYISO forecasts that there will be adequate supply of electricity to meet demand through the coming period of hot weather,” Aaron Markham, vice president of operations, said in a press release June 18. 

A heat dome is a high-pressure system in the upper atmosphere that traps warm air in place. Heat domes are more likely to arise in dry summer conditions. 

According to the National Weather Service, Albany, Buffalo, Rochester, Syracuse and the Plattsburgh area will likely experience “extreme heat” with little to no overnight relief beginning June 19. The heat is expected to move east and south, hitting New York City on June 20. Dangerous heat levels could persist until June 23. 

NYISO forecasts peak demand to reach as high as 28.9 GW by June 20. That is well below its forecast peak load for the season of about 31.5 GW, according to its Summer Assessment. The ISO will have about 40.7 GW of capacity available before derates, and operators could dispatch up to 3,275 MW through emergency procedures. (See NYISO Reports Adequate Capacity for Summer, but Heat Waves a Concern.) 

Kevin Lanahan, vice president of external affairs and corporate communications, told RTO Insider that based on historical load data, weather conditions and modeling software, operations and planning personnel anticipate being able to meet demand. 

“It’s a technical process, and we’ve gotten pretty good at it,” Lanahan said. “We have a lot of confidence in our planners and forecasters. We do believe we have enough power to meet demand.” 

Last year’s peak demand of 30,206 MW was during the Labor Day heat wave. The all-time record peak of 33,956 MW occurred in July 2013.  

New York Gov. Kathy Hochul announced she had activated the state’s Emergency Operations Center. “New Yorkers should take every precaution to stay cool this week,” she said. “Stay hydrated, avoid excessive outdoor activity and, if needed, visit a cooling center near you.” 

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NJ Electrification Bill Stirs Opposition

A bill that would require New Jersey utilities to offer building electrification incentive programs sparked more than two hours of heated debate June 10 as supporters cast it as a way to give consumers the option to embrace electric appliances and opponents questioned whether it would really cut emissions. 

Sen. Bob Smith, chair of the Senate Environment and Energy Committee, opened the hearing by saying the bill, S249, would be discussed but not voted on to solicit input on additional changes. He sought to head off anticipated misrepresentation of the bill by some of the witnesses. 

“Let me tell you what it is not,” he said. “The bill is not a law that’s going to mandate that tomorrow you change your electric system. Because you’re going to hear that nonsense today. … It is important to note the bill does not mandate electrification in any way.” 

The bill would direct the New Jersey Board of Public Utilities to establish a program that requires utilities to prepare and implement multiyear “beneficial” electrification plans to assist ratepayers with the transition from non-electric water heating, space heating, industrial processes or transportation equipment. The program would provide assistance if the change “reduces cost from a societal perspective, reduces greenhouse gas emissions or promotes the increased use of the electric grid in off peak hours.” 

Once the bill is enacted, the BPU would have a year to adopt program rules and regulations and set greenhouse gas emission-reductions targets. The rules would also “establish a cost recovery and performance incentive mechanism” and “develop and provide direct incentives for the installation of electric heat pumps.” 

Eric DeGesero, representing the Fuel Merchants Association of New Jersey and the New Jersey Propane Gas Association, said one problem with the bill is the phrase “beneficial electrification.” 

“Why isn’t the goal decarbonization?” he said. “Because if the goal is decarbonization, then renewable natural gas, hydrogen, renewable diesel — i.e., heating oil — [and] renewable propane would be included. They’re not. 

“It’s far more cost effective to use existing infrastructure than it is to have to retrofit. This bill doesn’t really put a thumb on the scale for electrification; it puts a whole hand on it.” 

Loose Definition

Nicholas Kikis, representing the New Jersey Apartment Association, also questioned the bill’s focus on electrification, “with this kind of very loose definition of what is beneficial, rather than focusing on those projects that would have the greatest impact, and therefore not negatively impact either housing affordability or, ultimately, our utility rates.” 

But a majority of the two-dozen speakers at the hearing backed the legislation. 

Anjuli Ramos-Busot, director of the Sierra Club’s state chapter, said that “fossil fuel equipment, such as boilers and gas furnaces inside New Jersey homes, [emits] a dangerous cocktail of harmful pollutants” and more carbon pollution than power plants in the state. The bill, by creating “effective building electrification programs, would provide a sure passage away from that,” she said. 

“It is clear that a transition from fossil fuels will save lives and protect residents’ health and wellbeing,” she said. “I’m just going to leave a very simple question to those opposed to this bill: What is so bad about more consumer choice?” 

Out-of-state Emissions

Building emissions are the second-largest source of greenhouse gases in New Jersey, after transportation, and Gov. Phil Murphy’s administration has developed a portfolio of measures to assist in the transition toward electrification. 

Murphy signed an executive order in 2023 calling for the electrification of 400,000 homes by December 2030, and more recently, the BPU on April 30 approved a package of new construction incentives worth up to $5.25 per square foot. (See NJ Enacts New Construction Electrification Incentives.) 

But the plans have faced vigorous opposition from business groups and fossil fuel representatives, who express concerns about the cost of the transition and urge the state to consider other alternative fuels, such as hydrogen and renewable natural gas, saying the existing natural gas infrastructure could be used. 

Bob Kettig, manager of corporate strategy at New Jersey Resources — which operates natural gas transportation and distribution infrastructure, as well as solar projects — said the bill focuses too narrowly on reducing “on-site emissions” and does not account for the fact that the electricity that powers the new appliances used will be generated out of state. 

The New Jersey Division of Rate Counsel urged the committee not to back S249, saying “electric utility ratepayers will shoulder the entire cost of the program.” 

“Electric distribution companies do not require any incentive to carry out electrification projects,” Director Brian Lipman wrote in a June 7 letter to the committee. “Electrification will necessarily increase electric load and therefore very likely increase revenue and profits for the EDCs.” 

Sen. Smith said he expects to amend the bill based on the points raised and will put it on the agenda for the committee’s June 20 meeting. 

Solar Recycling

The committee also considered, but eventually held, a bill, S3399, that would require end-of-life recycling of solar and photovoltaic energy generation facilities and structures. 

The legislation was one of two solar-focused bills addressed by the legislature June 10. The Senate Economic Growth Committee heard a bill, S2427, that would create a warranty program to protect solar panels erected on warehouses and other roofs. 

The recycling bill would require the owner of solar projects to remove and recycle the structure and any related equipment after its use. It would also require the New Jersey Department of Environmental Protection to set rules and standards for the program and allow fines of up to $1,000 if they were not adhered to. 

Glenn Laga, of Commercial Solar Panel Recycling, which has a solar recycling facility in California and is trying to set one up in New Jersey, said the company uses a simple recycling process. The panels are inspected and removed from the aluminum frame, and the electric boxes stripped off, before all the components go for recycling. 

Lyle Rawlings, president of the Mid-Atlantic Solar & Storage Industries Association, who said he served on the New Jersey Solar Panel Recycling Commission, said the bill should encourage operators to keep the panels for the full 35-year life. 

“We need regulations or incentives that will encourage people not to end their [facilities’] lives after 15 years or 20 years, when they still have plenty of life left,” he said, adding that the bill should also advocate for older panels to be repurposed and reused. 

Rawlings also expressed concern that when solar panels are crushed and ground down in the recycling process, they could release lead into the environment. 

Smith said he would incorporate the insights heard by the committee into the bill. 

Solar Roof Damage

The Economic Growth Committee voted 3-2 to approve S2427 over objections from two Republican senators and the Division of Rate Counsel. 

Smith, who sponsored the bill, said it addresses a “big hurdle” that is preventing more of the state’s numerous warehouse roofs from hosting solar panels: Because flat roofs are prone to leaking once a solar panel is mounted, the owners lose their insurance. 

“You lose your insurance the minute you put something on top of that roof,” he said. The bill would create a warranty program that would reimburse building owners if the property was damaged because of panels, he said. 

Sen. Joseph Pennacchio (R) questioned why the bill made the state responsible for the payments. 

“You’re talking about groups like Amazon. Why should we ask the ratepayers to foot the bill for something that, quite frankly, maybe they could do by themselves?” he said. 

Lipman said in a June letter to the committee that the bill “unfairly forces New Jersey’s ratepayers to pay for insurance that covers any mishaps in the work of solar contractors.” This “removes important incentives for those contractors to operate without causing damage,” he said. 

The bill will now be heard by the Senate Budget and Appropriations Committee. 

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Decade of Strong Growth Forecast in Offshore Wind Sector

A new report charts sharp growth in the global offshore wind sector, with 2023 showing the second-highest year-over-year installed capacity jump ever.

The 2024 “Global Offshore Wind Report” by the Global Wind Energy Council (GWEC), an international trade association, indicates 75.2 GW of capacity had been installed worldwide by the end of 2023 and predicts 410 GW of additional capacity will be installed in the next 10 years — if present policy support continues and effective strategies are in place to support such growth.

Most of that growth is forecast for 2029 to 2032, GWEC said — 60 GW in 2032 alone — and much of it is expected to be driven by countries newly embracing offshore wind as a source of clean energy, such as Australia, Japan, Brazil and Poland.

The report also notes that installations are falling short of policy goals and indicates that permitting, financing, the supply chain and the grid are key to supporting or limiting factors in the growth of offshore wind.

The will to succeed is there, the report says, adding: “The priority now must be continued collaboration between industry and policymakers to overcome hurdles to rapidly scale up this crucial technology for the economic and environmental wellbeing of people and economies around the world.”

Announcing the annual report, GWEC CEO Ben Backwell said: “Installing almost 11 GW of offshore wind is the leading edge of a new wave of offshore wind growth. Policy progress — especially across the Asia-Pacific region and the Americas — has set us on course to regularly install record-breaking capacity annually and pass the 380-GW target set up by the Global Offshore Wind Alliance.”

In all, 10.8 GW of capacity was added in 2023, the report said, which was 23.7% more than was added in 2022. It was the second-highest increase ever from one year to the next, aside from the 208% increase in 2021 over 2020.

Problem Spots

The picture drawn by the report is not uniformly bright.

The U.S. wrapped up 2023 with just 42 MW of installed capacity, or 0.056% of the world total. With the completion of South Fork Wind and with continued progress on Vineyard Wind, U.S. installed capacity is much higher than at the end of 2023, but it is still less than one half of 1% of the world’s total.

A confluence of macroeconomic factors came together to slow U.S. offshore wind development in 2023, the report notes, with 7.7 GW of projects canceled outright or sidelined with canceled offtake contracts.

As a result, GWEC is now projecting 15 GW of offshore wind will be online in U.S. waters in 2030, a sharp decrease from the 25 GW it projected in last year’s edition of the report.

However, as of June 2024, “the situation is now steadily improving,” the report says, citing multiple policy changes announced by state and federal officials scrambling to get the nascent U.S. industry back on track.

Projects totaling 4.3 GW are now under construction in U.S. waters, and projects totaling 50 GW are in some stage of planning nationwide. State procurement targets announced so far total 84 GW over the next two decades.

The report identifies floating wind as another problematic area.

Floating turbines are expected to be an important part of the generation profile as hundreds of gigawatts of offshore electric generation are built because there is only so much water shallow enough for fixed-bottom turbines.

But floating wind is not evolving technologically as quickly as once expected. It is still more expensive than fixed-bottom offshore wind and the specialized equipment and infrastructure needed to build and install floating wind farms is limited or nonexistent.

Just 236 MW of floating wind was installed worldwide at the end of 2023, most of it in Norway and the U.K.

In the year since it published the 2023 report, GWEC has concluded that commercialization of floating wind is unlikely to occur until the end of this decade — three years later than it predicted in 2023 — and has reduced its 2030 projection of installed floating capacity by 22% to 8.5 GW.

The Path Forward

The report offers several suggestions for supporting the global growth of offshore wind in its 2024 report:

    • The financing of offshore wind construction must expand, including in the Global South, where investment in the emerging markets and developing economies lags far behind mature markets and the North.
    • Offshore wind can be a tool for decarbonizing industry, and the industrial sector can provide a non-government offtake mechanism for the electricity produced offshore.
    • The supply chain must be built, and then it must be supported with strong volumes and steady policies. Government rules such as local content requirements and trade barriers create additional hurdles. The offshore wind industry must do its part by embracing collaboration, standardization and sustainable innovation.
    • Permitting needs to proceed faster: Longer lead times raise project costs and exposure to risk.
    • Expanded offshore wind development creates an opportunity for governments to pursue economic and social regeneration along coasts, if well established policies are in place and the support of communities is secured.
    • The workforce needed for the campaign can be built by up-skilling and re-skilling; industry and local and federal governments should put holistic plans in place to accomplish this.
    • Modern and efficient grids are the foundation on which offshore wind and other renewables stand, and a common challenge is how to achieve them. Aligning grid infrastructure development with clear regulatory frameworks will foster a resilient energy system.
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Order 1920 Rehearing Requests from States Seek Bigger Role in Tx Planning

The states that filed for a rehearing of FERC Order 1920 on transmission planning and cost allocation either argue the federal regulator is overstepping its authority or want changes to the order to ensure it doesn’t upset ongoing regional planning efforts. 

Many states, or organizations that represent them, that commented earlier in the rulemaking process did not file for rehearing. But more than a dozen rehearing requests came into FERC from either states or organizations that represent multiple states, such as the National Association of Regulatory Utility Commissioners. 

NARUC told FERC it appreciated the outreach to states during the rulemaking process and through task force meetings on transmission policy. But the group filed for rehearing because the final rule rejected some key provisions from the Notice of Proposed Rulemaking and adopted others that could undermine the goal of efficiently expanding the power grid. 

“On rehearing, NARUC respectfully requests FERC address the necessary deference to and importance of the state agreement and consensus on planning and cost allocation issues outlined in the NOPR,” it said in a rehearing request filed last week. “The suggested changes will necessarily improve outcomes, reduce potential litigation and facilitate subsequent state siting proceedings associated with transmission projects.” 

The NOPR proposed a stronger role for states in cost allocation, but FERC backed off that and requires only that states in a given region have six months to come up with their preferred cost allocation. The relevant transmission provider could decide to ignore that and file its own proposal. 

The state agreement should be binding and subject only to FERC approval, NARUC argued. Transmission providers should have to detail their efforts on state outreach, and if FERC does not require its adoption, transmission providers should have to file details on any state agreement reached. 

“Order 1920 creates a process that integrates individual state energy policies and goals into transmission planning, creates extensive procedures for ‘consultation’ with states and acknowledges how state input will facilitate the planning process,” NARUC said. “But then the order establishes conditions that permit the transmission providers to completely ignore and not even report upon state input.” 

The majority on FERC pointed to a court precedent called Atlantic City in finding that transmission providers ultimately have the final say on whether to file cost allocation methods. The New England States Committee on Electricity argued that was not the case. 

“However, Atlantic City does not prohibit commission action under FPA Section 206, under which authority the commission has promulgated Order No. 1920,” NESCOE said. “Rather, Atlantic City simply affirms that transmission-owning utilities have filing rights under Section 205 that FERC may not revoke.” 

If FERC cannot grant rehearing on that, it should at least encourage transmission providers to voluntarily codify existing or new approaches that would put state alternatives before FERC, which would be consistent with the current practice in NYISO and SPP. 

“Including the state-agreed-upon cost allocation method in a transmission provider’s Section 205 filing is a lawful and rational means to effectuate in a concrete way the respect for the state role the commission articulates,” NESCOE said. “The more the commission is successful in encouraging transmission providers to include such voluntary commitments in their tariffs, the greater the likelihood … that states in the region will have comfort with moving forward on providing the approvals needed to actually get much-needed new transmission built.” 

The main thrust of NESCOE’s comments was that it did not want Order 1920 to mess with the implementation of recently enacted transmission planning rules where ISO New England has agreed with its state members on transmission plans that enact its members’ policies. FERC already has approved rules allowing the ISO to study scenarios developed with the states, but companion rules to competitively solicit actual transmission lines are pending. (See Stakeholders Support ISO-NE Long-term Tx Planning Filing, with Caveats.) 

“NESCOE shares a commitment to meaningful, long-term regional transmission planning reform and seeks to ensure that FERC-jurisdictional transmission rates remain just and reasonable and not unduly discriminatory or preferential,” it said. “In light of the progress in New England, NESCOE especially appreciates the commission’s acknowledgment that certain transmission planning regions already conduct regional transmission planning on a forward-looking, proactive basis and its intent not to undermine progress made in these transmission planning regions, and our goal is to set a floor, not a ceiling.” 

The Virginia State Corporation Commission and North Carolina Utilities Commission said they support the rule’s stated purpose and recognize the potential cost savings and reliability benefits that longer-term, comprehensive planning could provide to consumers. But they took issue with some aspects of the final rule, including its claim that states won’t subsidize others’ policies. 

“Because the same public policies included in planning scenarios, and ultimately embedded in selected transmission projects, are not required to be considered for purposes of cost allocation, it is far from clear how that bedrock principle of just and reasonable rates can be actualized under the final rule,” the two said. 

State policies like climate laws, which Virginia and North Carolina have enacted, are included in the long-term plan. But aiding their actual achievement is not among the benefits, so the state may pay too low a share for enacting its policy. The two suggested allowing transmission planners to do “baseline scenarios” that exclude state policies so it can be discerned how much the policies impact the other plans. 

North Carolina and Virginia regulators also were skeptical of the proposal requiring utility and corporate “goals” to be included in the long-term transmission plans because they are easily changed, or even abandoned. 

“This may ‘skew’ information submitted in the stakeholder process in favor of utility or corporate interests and result in planning scenarios that give too much weight to ‘goals’ that are unlikely to be achieved,” the SCC and NCUC said. 

Other rehearing requests from states were more strident in their opposition to FERC’s Order 1920, arguing the commission overstepped its authority in the Federal Power Act and violated the “major questions doctrine.” 

A group of Republican state attorneys general (from Texas, Alabama, Arkansas, Florida, Georgia, Idaho, Iowa, Kansas, Kentucky, Louisiana, Mississippi, Montana, Nebraska, North Dakota, Oklahoma, South Carolina, South Dakota, Tennessee and Utah) argued FERC is trying to use the planning and cost allocation rule to implement the Biden Administration’s green energy policies. 

“It shifts transmission costs for those remote renewables to consumers under the guise that those consumers will ‘benefit’ from those resources, without considering whether less remote resources of any type might be less expensive, more reliable and environmentally beneficial,” the attorneys general said. 

The filing was coordinated by the Texas Attorney General’s office, and it noted that the states aren’t opposed to renewable energy, with the Lone Star State leading the country in terms of megawatts of renewables installed.  

“The commission’s claim that the rule’s proposals are necessary to ensure just and reasonable rates stretches the FPA beyond its limits,” the attorneys general said. “Indeed, the proposals set forth in the rule will not — and are not designed to — ensure just and reasonable rates; they are blatantly preferential and would harm consumers by shifting costs to load, not protect them.” 

A group of state regulators used language similar to those attorney generals, with the Louisiana PSC, Mississippi PSC, Arkansas PSC and South Dakota PUC also arguing that while they are not against renewable energy, they are opposed to Order 1920’s usurpation of state authority. 

“The commission is attempting to do indirectly what it is prohibited from doing directly: usurp the states’ exclusive authority over generation choices by instituting planning rules designed to benefit remote generation, and that generation’s developers, over local generation and to shift billions or trillions of dollars in transmission costs from those developers onto electric consumers,” they said. 

The Arizona Corporation Commission said the order violates the major questions doctrine and would preempt its authority, while “unmistakably promoting a ‘net zero’ policy agenda.” 

“The final rule seeks to recast FERC as a national integrated resource planner with extraordinary powers to oversee and dictate to all public utility transmission providers in the country, in RTO and non-RTO regions, detailed instructions on planning transmission that fulfills the current presidential administration’s stated preferred policies,” the ACC said. 

The West Virginia PSC was more moderate in its criticism, noting that it supported the NOPR, but FERC’s decision to pare back state regulators’ input over cost allocation made the longer-term planning horizon and new mandatory benefits no longer just and reasonable. 

“That substitute, the engagement period and de minimis requirements placed on transmission providers, is so far removed from state cost allocation involvement that was noticed that the cost allocation and state agreement requirements in the final new rules must be re-noticed to give the public an opportunity to comment,” the PSC said. 

West Virginia is a member of the Organization of PJM States Inc., which filed its own rehearing request, also arguing states should have more of a guaranteed say over cost allocation. 

“If states, through the process envisioned and required by the commission, exert the effort and resources to successfully reach agreement on a cost allocation method or methods and transmission providers are not required to file or even acknowledge the relevant state entities’ efforts, state engagement in the development of cost allocation methods for long-term regional transmission facilities and any expected development of more efficient or cost-effective facilities may never materialize,” OPSI told FERC. 

In other words, giving states more authority would make them more likely to actually get steel in the ground.  

OPSI was one of several organizations that argued the six months to come up with a state agreement could easily prove too short, given state regulators’ other responsibilities. FERC should allow for an extension to 12 months total if states unanimously agree that would help them come up with cost-allocation rules. 

The PUC of Ohio’s Federal Energy Advocate filed comments noting that while the state has found RTO membership beneficial so far, Order 1920 could change that. RTO membership was based on assuring reliable transmission systems at the least cost. 

Order 1920 “puts these principles in the rear-view mirror,” the Ohio regulator said. “Instead, it attempts to look 20 years into the future to launch a massive program today, not focused on achieving reliability at just and reasonable rates, but rather on building transmission projects to satisfy the ambitions, goals and policies of corporations, developers and governments that are not connected to reliability. Nothing could be further from the principles of Order No. 1000 and the requirement under the FPA for the commission to ensure just and reasonable rates.” 

The Ohio commission supports the use of the existing State Agreement Approach, which so far has been used only by New Jersey, where PJM planners helped it save money on interconnecting the wind farms called for by its policies. But the rehearing request argued that would no longer be feasible under Order 1920 because the SAA is focused on state policies alone and ignores other benefits the lines produce — limiting cost allocation to the states that agree to it. 

The Ohio regulator noted that New Jersey has decided to pause on moving forward with another use of the SAA as the Garden State weighs the implications of Order 1920. 

“FERC must not let RTO membership devolve into an instrument by which states are pitted against one another in a zero-sum game of cross subsidies amongst competing policy interests,” the Ohio commission said. “Such a development would undermine the value proposition of RTO membership for states who do not wish to subsidize the policy preferences of others, directly contradicting FERC’s goal of encouraging RTO participation as envisioned by FERC Order No. 2000.” 

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EIA: Dispatch of Coal Generation Falls in PJM

Analysis from the U.S. Energy Information Administration finds that the average runtime for PJM coal-fired generators has declined sharply over the past decade because of increasing fuel and start-up costs.

The agency’s June 17 “Today in Energy” report said the RTO’s coal-fired power plants ran at an average of 34% of their maximum output in 2023, down from 56% in 2013.

That resource class made up 14% of generation available to PJM and 18% of capacity last year, compared with 44% and 38% a year earlier. About 34 GW of coal generation retired over that period, and an additional 2 GW was shifted to other fuel sources. EIA attributed much of the change to competition from the growth of efficient combined cycle gas generation.

The strain of repeat starts and stops can increase maintenance costs for thermal generators designed to operate at a constant rate, meaning that when PJM is selecting the lowest-cost resources for dispatch in the energy market, it’s often uneconomic to start an offline coal plant.

“Coal-fired generating units are generally designed for steady-state operation, and they operate with the fewest problems when they run all the time,” EIA wrote. “Restarts can be costly because large thermal plants can experience problems caused by repeated start-ups and shutdowns, increasing maintenance costs. The restart cost can be a key factor in determining plant operating strategy. … Because those restart costs increase their market offer, coal plants, when competing against other sources, may not be selected to operate.”

The changing economics hit independent power producers particularly hard, with 24 GW of IPP-owned coal generation deactivating over the past decade, leaving 17.6 GW on the grid. IPPs lack the cost recovery mechanisms that allow regulated utilities to mitigate financial risk for their generators, EIA said.

In an email to RTO Insider, PJM’s Dan Lockwood said the findings appear to be in line with a white paper the RTO published last year, which found that retirements of thermal generators could outpace the development of new resources through 2030. (See PJM Chief: Retirements Need to Slow Down.)

“As PJM pointed out in its ‘Energy Transition in PJM: Resource Retirements, Replacements & Risks’ study issued early last year, a confluence of conditions — including state and federal policy requirements; industry and corporate goals requiring clean energy; reduced costs and/or subsidies for clean resources; stringent environmental standards; age-related maintenance costs; and diminished energy revenues — are leading to an overall decline in the use of thermal resources, including an increase in coal unit retirements,” Lockwood wrote.