Maine is building the framework for the offshore wind sector it hopes to develop, with legislation setting a goal of at least 3 GW by 2040 and setting parameters for reaching that goal.
The measure cleared the Legislature early Wednesday and heads now to Gov. Janet Mills (D), who in June vetoed similar legislation she herself had proposed. Pro-union provisions the Legislature inserted in the measure would put the state at a disadvantage in a competitive market, she said in her veto message.
But she urged negotiation and compromise, and that is what happened.
Democrat Mark Lawrence, chair of the Maine Senate’s Energy, Utilities and Technology Committee, introduced the original compromise legislation, LD 1895, an amended version of which was approved in the special legislative session.
“It’s a great step forward for the state of Maine,” he told NetZero Insider Wednesday. “It’s going to provide a great number of jobs.”
Most of the Gulf of Maine is too deep for the fixed-bottom turbines that now are being built by the dozens and planned by the hundreds farther south along the Atlantic Coast. Maine’s goal will rely heavily on floating wind technology that still is in development and has had minimal installation anywhere in the world.
But that’s not why Maine is setting the target for 2040, years later than nearby states.
“We actually expect it to happen faster than that, but you can’t predict a lot of these things,” Lawrence said.
The measure approved Wednesday sets policy guidelines now so the regulatory framework is in place when the technology is ready for large-scale buildout.
Maine also is taking steps to speed the development of that technology, with a research and development program underway at the state university and a request working through the federal regulatory process for a research-scale floating wind farm with up to 144 MW nameplate capacity.
The state hopes to be a leader in the floating wind industry. It issued a road map in February to guide the process.
Key provisions of the legislation include:
The Maine Offshore Wind Renewable Energy and Economic Development Program will be created.
The first request for proposals will be Jan. 15, 2026, or three months after the first federal lease is issued for commercial offshore wind in the Gulf of Maine, whichever is later.
Solicitations will specify a minimum of about 600 MW capacity but will not specify that floating wind technology is to be used; the Maine portion of solicitations coordinated with other states or entities can be less than 600 MW.
Bidder criteria must include provisions such as diversity, equity and inclusion in employment and contracting; a fishing communities investment plan; and fisheries research, monitoring and mitigation.
Developers will pay $5,000 per megawatt to the Offshore Wind Research Consortium Fund.
The Public Utilities Commission must select projects that are cost-effective for ratepayers but also consider other qualitative and quantitative benefits.
The PUC must prioritize projects that place infrastructure outside Lobster Management Area 1.
The PUC must seek to advance regional transmission solutions to interconnect offshore wind power.
Public work on offshore wind terminals must comply with a project labor agreement or community and workforce enhancement standards.
Offshore wind terminals must comply with a new visual impact standard, and the Department of Environmental Protection may approve no more than four terminals.
Advocates on Wednesday were happy with the compromise.
The Natural Resources Council of Maine said: “This new law will be a model for the rest of the nation for how people can come together across differences with common purpose to build a just clean energy economy that works for everyone.”
The Maine Labor Climate Council tweeted: “ICYMI: In a major win for workers and the climate in Maine, this offshore wind bill is on the governor’s desk. When labor leads on climate, we win!”
The Business Network for Offshore Wind said: “We would like to congratulate Maine’s elected officials for coming together to pass this historic advancement of offshore wind in Maine. Once signed into law, this bill will allow Maine and the broader U.S. to become leaders in floating offshore wind technology.”
Maine Audubon tweeted: “Today, Maine’s lawmakers took a serious and measurable step toward accelerating our clean energy transition and reducing our dependence on fossil fuels.”
Maine Conservation Voters tweeted: “Maine’s clean energy future and our clean energy economy secured a major victory today. When this bill is implemented, we’ll set a national example for how to responsibly develop a new, affordable energy source, grow good-paying jobs for our workers, and do so without compromising Maine values. We’re ready to get to work and launch this new industry!”
Eversource needs to provide more information regarding the climate and environmental justice effects and overall justification for a hotly contested gas pipeline project in Western Massachusetts, the state’s Executive Office of Energy and Environmental Affairs (EEA) ruled this month.
The state said the company’s Draft Environmental Impact Report (DEIR) for the proposed 5.3-mile-long pipeline running between Springfield and Longmeadow is inadequate. The state did not rule out a “No Build” alternative, saying Eversource did not justify the basic need for the project.
“The DEIR has not provided an adequate alternatives analysis, and has not fully justified dismissal of the ’No Build’ Alternative or other non-pipeline alternatives,” wrote EEA Secretary Rebecca Tepper.
Eversource has argued the pipeline is necessary to ensure reliability for gas customers in the area.
“More than 58,000 of our natural gas customers in the Greater Springfield area are currently served by a single 70-year-old natural gas pipeline system, and [the new pipeline] will provide a much-needed second supply source to enhance reliability for nearly 200,000 people and businesses in the area,” an Eversource spokesperson wrote in a statement to NetZero Insider.
The company said the pipeline project — which includes a new point-of-delivery facility in Longmeadow and upgrades to the Bliss Street Regulator Station in Springfield — is not an expansion project, and new customers in the area will be served by existing infrastructure.
Tepper acknowledged Eversource’s claims the pipeline is not meant to expand gas supply but wrote that this was due to a lack of approval for expansion from the state’s Department of Public Utilities (DPU) and that the proposed project appears to have the capability to increase supply in the future.
“The DEIR indicated that there will be no increase in gas because the DPU has not approved an increase, not because of any design or engineering capacity limitations of the project,” Tepper wrote.
Tepper pressed the company for more detail on the project justification and potential non-pipeline alternatives to meet reliability needs, while noting the context of the state’s emissions goals and desire to phase out natural gas.
“Beyond reiterating the ‘worst case’ scenario in which gas service is suspended to all 58,000 customers … the DEIR did not explain why this risk is deemed to be present in this particular location within the Proponent’s statewide territories, nor does it point to any studies or historical precedents that would require prioritizing the mitigation of risk at this location,” Tepper wrote. “The DEIR did not attempt to quantify the probability of risk, or present any reduced scenarios other than the worst-case outage scenario.”
Tepper added that Eversource “has not shown why a ‘hybrid’ scenario of combining shorter-term redundancy solutions (such as use of compressed natural gas (CNG) or liquified natural gas (LNG) to meet winter peak demand), combined with a longer-term transition to other fuel sources, may not be a feasible option.”
Eversource wrote in the project’s Environmental Notification Form that it “views the responsible and efficient use of natural gas as consistent with climate change policies and net-zero carbon objectives.”
Climate And Environmental Impacts
The state also called for more information on how the pipeline would affect carbon emissions and the health of nearby residents, many of whom live in state-designated environmental justice populations.
Tepper wrote that nearby environmental justice populations face above-state-average risks for a wide range of pollution indicators, including ozone, diesel particulate matter, air toxics respiratory hazard index, hazardous waste proximity and wastewater discharge.
The Asthma and Allergy Foundation ranked Springfield as the U.S. “Asthma Capital” in 2018 and 2019, citing the cumulative impacts of pollen and air pollution, while ranking the city as the most challenging place in New England to live with asthma in 2022.
Eversource wrote in the DEIR that “the project will not affect the health of those living in the environmental justice areas.”
To supplement the DEIR, Eversource must include information related to safety concerns, climate resiliency of the infrastructure and plans for air pollution monitoring, as well as how the proximity to vulnerable populations factored into the choice of location.
Concerning the project’s carbon emissions, Tepper said Eversource must quantify the increase in gas supply that could result from the project, along with associated carbon emissions. Tepper also directed Eversource to conduct at least one public meeting to discuss the pipeline, alternative options, and potential environmental and health effects various options would have on the community.
“We’re currently reviewing the specifics of MEPA’s decision and will respond accordingly as part of our everyday efforts to ensure safe, reliable service for all of our customers while maintaining environmental responsibility,” Eversource said in its statement to NetZero Insider.
Prior to the state’s response to the DEIR, a wide range of climate and environmental justice groups submitted public comments detailing extensive climate and health concerns.
“We envision a just and rapid transition away from gas to a future of clean heat powered by clean electricity,” they wrote in the petition, signed by more than 6,000 Massachusetts residents. “This is urgent for our planet, our health and for communities facing expansion projects right now like Springfield and Longmeadow. We urge Governor [Maura] Healey to put a halt to new gas system expansions until there is a concrete plan for a just transition to a clean and green energy future.”
The project is required to procure several other permits and approvals, including an approval to construct from the Energy Facilities Siting Board, a zoning exemption from the DPU and a highway access permit from the Massachusetts Department of Transportation.
New Jersey has no offshore wind turbines in operation yet, but the industry already is creating jobs — for lawyers.
The latest in a series of legal skirmishes came July 3, when developer Ørsted filed a lawsuit seeking to force Cape May County to grant permits that would allow the state’s first offshore wind project, Ocean Wind 1, to move ahead.
The suit by Ocean Wind LLC in New Jersey Superior Court claims the county illegally has withheld a road opening permit that would allow the company to do utility and environmental investigations. It follows a similar suit filed by the developer against Ocean City, which is in Cape May County, on May 4.
At issue in both suits is the developer’s plan to run cables through Ocean City, to bring power from the 1.1-GW Ocean Wind 1 to a substation in a closed coal-fired power plant in neighboring Upper Township.
The lawsuit says the failure to issue the road permits already has delayed the project and is “having a cascading and adverse effect on other permits and approvals needed for construction.”
“The county has not identified any ‘bona fide public safety reasons’ for their inaction,” according to the complaint. “Instead, the county is withholding the permit because it opposes the project.”
In a separate legal action, three opposition groups — Save Long Beach Island, Defend Brigantine Beach and Protect Our Coast NJ — filed an appeal in June in Superior Court challenging state permit approvals for Ocean Wind, claiming the project does not comply with state coastal management rules.
And Cape May on July 19 filed arguments for an appeal of the New Jersey Board of Public Utilities’ (BPU) approval of an easement that would allow Ocean Wind 1 to run cables across county land. The appeal is similar to one by Ocean City over the BPU’s approval of an easement in that municipality.
In both cases, the BPU acted under a law approved in 2021 that allows OSW projects to override local government agencies and give permitting and other approvals if they are “reasonably necessary” to the project. (See County Contests Tx Easement for NJ’s 1st OSW Project.) The county’s appeal, filed with the state Appellate Division, argues the BPU made “multiple erroneous legal findings” in granting the approval.
The county argues that although the new law enables the BPU to overrule local government bodies, the state constitutional right to “home rule” requires the agency to pay greater attention than it did to the “protection of the interests of municipalities and counties with regard to statutes that impact them.”
“BPU used the new statute to push aside the duly elected county commissioners” and took county property — the easement — for the benefit of “a private, foreign corporation,” the complaint argues. It adds that the BPU commissioners should have recused themselves from the case because the agency is a “driving force behind the installation of offshore wind facilities,” and so can’t make an impartial decision in the case.
One sign of that “bias,” the complaint argues, is that the board president and other agency staff “demonstratively wore and continue to wear lapel pins portraying the blades of offshore wind turbines.
“BPU set aside its obligation to be a fair, unbiased and impartial quasi-judicial panel,” the complaint states.
Fall Construction Target
How the courts respond to the litigation will play a key role deciding whether Ocean City 1 can meet its target of starting onshore construction in the fall. The appeals could bring the project to a halt.
Whatever happens to Ocean Wind 1 could have serious implications for later projects in the state’s OSW pipeline. The BPU approved Ocean Wind 1 in 2019, and two more projects in 2021: the 1,148-MW Ocean Wind 2 and 1,510-MW Atlantic Shores. In March, it launched a third solicitation, which could result in the award of capacity totaling 4 GW or more. (See NJ Opens Third OSW Solicitation Seeking 4 GW+.)
Opposition to the projects has risen steadily in recent months, in part over fears from the commercial fishing industry that turbines will limit their ability to fish, from tourist businesses concerned they will deter visitors and from shore property owners who fear the wind turbines will reduce the quality of life at the shore.
Opponents also have questioned whether a series of whales’ deaths are tied to preliminary undersea mapping projects that use sonar in preparation for turbine construction. State and federal researchers investigating the cases have said they see no such link.
The legal action soon may escalate, however. A July 12 release from the three groups that filed the appeal in June said they are “pursuing six lines of litigation and are preparing for at least three more major lawsuits later this year.”
OSW Impact and Legacy
Hearings held by the Bureau of Ocean Energy Management into the agency’s Draft Environmental Impact Statement (Draft EIS) on June 21 and 28 offered a snapshot of opponents’ concerns. While the majority of the 30 or speakers favored the plans, several asked pointed questions at what they see as plan elements that will hurt the shore and its residents and businesses.
Peter Himchak, a marine fishery scientist who spoke for Lamonica Fine Foods, a Cape May-based seafood company, said the commercial fishing industry had for several years told federal and state officials their biggest concern was that clam vessels could not enter the turbine zone if the turbines were less than two miles apart. Without that separation, fishing vessels couldn’t safely fish in those areas, he said. But the preliminary EIS shows the plan was “considered and rejected,” Himchak said, calling the industry “collateral damage in the industrialization of the ocean.”
“Our worst fears have been realized that we will have to live now with likely 27 exclusion zones where we can no longer operate,” he said, referring to lease areas approved by the federal government.
Several speakers said the 45 days allocated by BOEM for public comment was too short a time for the public to digest and respond to a 900-page report.
Richard Jones urged BOEM to extend by six months the comment period because the “rush to approve multiple ocean wind industrial scale power factories in pristine areas is overwhelming the public’s time to respond properly.”
Turning to the whale deaths, Jones suggested that the real figure of deaths could be higher because the whale bodies wash ashore only when the current is in that direction. “Who knows how many drifted away offshore uncounted?” he asked.
Jones added that “intense noise generated by hydro hammers driving 4-million-pound, 30-foot diameter three-inch thick steel monopiles is harmful to marine life.” He said he had been told the piling process can’t be stopped once it starts even if a whale arrives in the area because it would damage the foundation.
In response, Greg Fulling, a marine biologist with BOEM, said whales are protected from piling noise by a process in which “protected species observers” (PSO) on the turbine platform scour the sea for whales for up to 60 minutes before piling. If none are seen, the work starts with about an hour of the piling hammer used at “reduced power with minimal strikes,” he said.
This is a “ramp up procedure … to essentially warn the animal of the loud noise,” he said. “If there is a whale detected within the shutdown zone, the PSO will call for a shutdown.”
Decommissioning Turbines
Stephanie Adams, a resident of Fair Haven, a shore town about 90 miles north of the areas most affected by the proposed turbines, said New Jersey should consider putting solar panels along the state highways, rather than turning to offshore wind, due to the harm likely to marine life.
“I understand it seems like a good idea,” she said of the OSW projects. “But the scope and the scale that we’re proposing is unprecedented,” she said, adding “there is very limited research” on how it will impact the ocean.
She asked who would be responsible for decommissioning the turbines after 30 years, at the end of their expected life.
“Presumably that will fall on taxpayers, and we’ll have a graveyard of broken turbines in our oceans,” she said.
William Waskes, project coordinator for BOEM, said under BOEM’s rules Atlantic Shores has to decommission the turbines within two years of the end of its 25-year lease. The developer has to submit an application stating what facilities will be removed, the schedule for the work and the plans for transportation and disposal of the facility, Waskes said.
“Decommissioning of an offshore wind facility is at the sole cost of the lessee,” he said. “They’re the ones paying for the decommissioning.”
In response to a question about why the turbines are so close to the shoreline, Waskes said New Jersey officials working with BOEM decided those distances between 2010 and 2012 in a public consultation process that sought to minimize conflicts with other ocean users in the area and protect ecologically sensitive areas.
“It was based on the technology limitations and trends at the time,” he said.
The Management Committee on Wednesday voted for NYISO to not conduct a new cost-of-service study to modify the Rate Schedule 1 cost allocations between units withdrawing and injecting.
The divided vote was previewed last month when NYISO announced stakeholders would have the opportunity to potentially change RS1 allocations, which have been set at 72% for withdrawals and 28% for injections since 2011. (See “Vote Set on Rate Schedule 1,” NYISO Management Committee Briefs: June 13, 2023.)
Some stakeholders opposed the motion and voted in favor of conducting the study, arguing that the allocations had not been updated in a long time and keeping things up to date was important because new technologies are entering the grid.
David Clarke, director of wholesale market policy at LIPA, argued in favor of conducting the study, saying, “we have put this off for a long time. … It is probably important to do this at least once a decade.”
On the other hand, Scott Leuthauser of Hydro-Quebec Energy Services argued against the study, saying, “it seems to me that nobody’s really opposed to the current values.”
“We have so many really high-priority projects that we’re not doing because resources are not available, so let’s just keep it for another year,” he added.
Howard Fromer, who represents Bayonne Energy Center, asked how distributed energy resources aggregations fit into these RS1 mechanisms.
Chris Russell, senior manager at NYISO, responded: “DER aggregations will be charged as a generator essentially,” adding, “these resources would be charged the injection rate similar to how we charge special resources cases today.”
Russell also said storage resources in an aggregation would be charged the prevailing injection rate whether it was injecting or withdrawing.
Erin Hogan of the state’s Utility Intervention Unit argued that these resource-related issues highlight the need to update the RS1 cost allocations.
The motion passed with 91.22% of the vote in favor of not conducting the RS1 study.
Board Selection Subcommittee
NYISO CEO Rich Dewey announced the ISO is forming a new board selection subcommittee to seek a replacement for Ave M. Bie, whose term ends in April.
Dewey said Julia Popova, chair of the MC and NRG Energy’s manager of regulatory affairs, will lead the subcommittee.
Bie is a former chair of the Wisconsin Public Service Commission and joined NYISO’s board in April 2009.
The Mountain Valley Pipeline’s Southgate extension asked FERC for a three-year extension to build the project after Congress passed a law pushing through the mainline of the project, which ran into protests in comments filed Monday.
The Southgate extension would run 75 miles from the end of the MVP Mainline in southern Virginia to central North Carolina, bringing natural gas from the Marcellus and Utica shale to Dominion Energy subsidiary’s Public Service North Carolina Energy’s distribution system. Equitrans Midstream Corporation owns 47% of the project, NextEra Energy 32.16% and AltaGas 10%.
Both pipelines were initially supposed to be done by now, but the Mainline has been tied up in litigation and that contributed to delays of the Southgate extension, which needs Mainline to be built so it can actually ship natural gas.
“The circumstances have changed,” the pipeline told FERC on June 15. “President Biden signed legislation that will expedite the completion of the Mainline System, which the United States Congress found and declared to be in the national interest.”
That filing came into FERC a few weeks before the pipeline’s opponents got the Fourth Circuit Court of Appeals to issue a stay on construction of the project as the court considers challenges to that legislation. The pipeline has asked Supreme Court Chief Justice John Roberts to overturn that stay, asking for a ruling by July 26.
The projects continued legal woes came up repeatedly in comments on Southgate’s extension request, with North Carolina Gov. Roy Cooper (D) telling FERC that the argument that more time is warranted because Mainline will be completed quickly is “clearly erroneous.” North Carolina has a law requiring a 70% cut in carbon emissions from the power sector by 2030 and carbon neutrality by 2050.
“Proponents of MVP Southgate have argued that the pipeline is needed for new electricity generation units,” Cooper said. “However, due to the requirements of Session Law 2021-165, any newly constructed natural gas fueled electricity generation units will be forced to retire before the end of their useful lives, leading to sunk costs that will be charged to North Carolina’s ratepayers.”
Cooper also argued that the pipeline is not needed for heating after the federal Inflation Reduction Act gave incentives for customers to move away from natural gas.
A group of several dozen legislators from North Carolina also urged FERC to reject the application, saying that the pipeline is not needed.
“There is no need for the gas MVPS is proposing to transport,” the legislators said. “Years’ worth of evidence points to how the developers overstated the demand for gas, and upgrades to existing infrastructure show increased available capacity substantiates the lack of market need for the MVP.”
Dominion Energy’s PSNC asked FERC to grant the extension, saying that it has added 100,000 customers in the past decade without any new supply. It signed a contract with MVP Southgate for a 20-year term of 300,000 dekatherms per day and a related 250,000 dekatherms per day from the Mainline Project.
“The project will provide geographic diversity of supply through access to Marcellus and Utica shale gas and will alleviate price swings that PSNC has experienced in the past,” the utility said. “MVP Southgate will improve reliability and add resiliency to the interstate pipeline services that PSNC receives and enable PSNC to gain optionality in selecting best-cost supply sources,”
Duke Energy urged FERC to grant the extension request, given that the litigation around the MVP project has been outside of its backers’ control and the commission issued similar extensions for the Mainline Project. Duke said the pipeline would help it secure fuel for natural gas power plants.
“The companies have experienced significant growth in natural gas demand for power generation and expect that trend to continue as the company retires its coal units,” Duke said. “Today, the Carolinas and the companies face a potential fuel security challenge that will be difficult to improve without completion of Southgate, which would allow increased physical gas deliverability into the Carolinas.”
New natural gas will help balance new renewables and is the least cost replacement for aging coal fired power plants, but they will require more pipeline infrastructure because the main pipeline serving Duke’s territory, Transcontinental Pipeline, is fully subscribed and constrained during periods of high use, especially during the winter.
“Increased pipe infrastructure allowing Appalachian Gas to flow into the Carolinas can play a key role in enabling the companies’ generation transition while supporting the communities and businesses that rely upon us for their energy needs today and in the future,” Duke said.
The Natural Resources Defense Council noted that the federal debt deal might have eased the federal permitting process for MVP, but it failed to reckon with market conditions that have changed since the pipeline was first proposed.
“Given national, state and regional commitments to move away from natural gas as an energy source in the coming years, combined with continued uncertainty around the fate of the Mainline system, the commission must reject Mountain Valley’s plea and deny the extension request,” NRDC said. “Denying this extension provides the commission with a logical imperative opportunity to demonstrate its commitment to a sensible energy future by refusing to saddle the public with another stranded asset inconsistent with statewide, regional, and federal energy needs, and ultimately the public interest.”
The firm effectively has stopped trying to get permits for the Southgate project, waiting for the litigation around Mainline to play out. It has failed to resubmit for a water permit in North Carolina, an air permit in Virginia, and it has halted all eminent domain proceedings.
“Mountain Valley has sat on its hands during the certificate period–abandoning efforts to secure crucial permits for the project, time and time again,” NRDC said. “These pending litigation- and permitting-related delays are entirely within Mountain Valley’s control.”
FERC requires that developers continue to work on their projects when it grants extensions, but in this case that has amounted to focusing on the Mainline Project, NRDC said.
Utility regulators from Oregon and California discussed their proposal for a new independent RTO covering the entire West for the first time publicly during Tuesday’s summer meeting of the Committee on Regional Electric Power Cooperation (CREPC).
The proposal was first described in a July 14 letter signed by regulators from Arizona, California, New Mexico, Oregon and Washington and sent to the chairs of the Western Interstate Energy Board (WIEB) and CREPC, which has become a forum for discussing Western market development. (See Regulators Propose New Independent Western RTO.)
Mark Thompson, a member of the Oregon Public Utility Commission and a signer of the letter, told CREPC Tuesday that the proposal originated from a desire to pursue the benefits of a full Western market and not see the West “fractured” by competing market proposals by SPP, CAISO and possibly others.
SPP and CAISO have offered competing day-ahead market proposals, and SPP is developing a Western version of its Eastern RTO, called RTO West, to compete with CAISO, which lacks independent governance. (See Western Day-Ahead Markets Debated at CREPC-WIRAB.)
“The idea was that perhaps we can form an entity in the West that would have independent governance shared across all states, and that the entity could eventually become the delivery arm for some of the programs that we already have through the CAISO, including the [Western] Energy Imbalance Market, perhaps the EDAM as well,” Thompson said, referring to CAISO’s proposal for an extended day-ahead market for the WEIM.
“Ultimately, that entity could create an independently governed full market opportunity for the West that all states could join, including California,” he said. “The vision would be that rather than fracture the market, let’s stand up another entity to at least be a vessel that can deliver a full market opportunity and that can have independent governance that all Western states could join in.”
Alice Reynolds, president of the California Public Utilities Commission, also signed the letter and helped develop the proposal, which she called an initial “invitation for all states that are interested to discuss and consider this concept.”
“I really do share the view that the fundamental driver of this working group idea and consideration of the concept is the recognition that customers across the West will benefit significantly from a West-wide market,” Reynolds said at the CREPC meeting. “As regulators, this is a common goal that we share — affordable rates, and increased Western cooperation can help us advance that.”
A June 2021 study found an RTO covering the entire U.S. portion of the Western Interconnection could save the region $2 billion in annual electricity costs by 2030 and cut carbon dioxide emissions by 191 million metric tons. Utah Gov. Spencer Cox’s Office of Energy Development led the study along with energy offices in Colorado, Idaho and Montana. (See Study Shows RTO Could Save West $2B Yearly by 2030.)
The WEIM has produced nearly $4 billion in cumulative benefits for participants since its founding in 2014, she noted.
“The discussion of a new concept, a West-wide entity with independent governance, really gives us an opportunity to build on this and to ensure that customers are getting the benefit of the full range of possible services and benefits that can be achieved through West-wide cooperation,” she said.
Others who signed the letter included Washington Utilities and Transportation Commission members David Danner, Milt Doumit and Ann Rendahl; Oregon Public Utility Commissioner Letha Tawney; Arizona Corporation Commission member Kevin Thompson; Pat O’Connell, chair of the New Mexico Public Regulation Commission; and Siva Gunda, vice chair of the California Energy Commission.
“We have identified a common commitment in seeking the benefits shown in multiple studies that demonstrate the most favorable electricity market for consumers is one that includes a West-wide market footprint,” the letter said. “Such a market would avoid the issue of ‘seams’ from separate markets across major portions in the West and result in optimized use of resources to meet loads across the entire interconnection.”
The new entity could contract with CAISO as a regional transmission operator and assume control of the WEIM and EDAM, it said.
‘Larger Conversation’
CREPC allotted 20 minutes for the presentation by Reynolds and Thompson and a brief question-and-answer session.
One question was whether the Canadian provinces in the Western Interconnection could join the RTO.
“I don’t see any reason to limit it to states,” Reynolds said. “We need a collective term that’s broader” than a Western RTO.
Utah Public Service Commissioner John Harvey asked about the potential costs of establishing a new entity.
“I’m an economist by training, and I’m curious and worried about the idea that if a whole new entity is created, you’re adding a tremendous amount of transaction costs,” Harvey said. “Just looking at CAISO or SPP, there’s a huge infrastructure there to try and settle these markets and determine the pricing and settle the accounts. Duplicating that again could burn up a lot of those benefits.”
He also said states with lower energy costs might not want to join an RTO.
“They would tend to say that the EIM and the day-ahead market give them the opportunities they need, and they don’t really see much benefit to moving beyond that,” he said.
Reynolds replied, “I think that’s part of the conversation that we want to have around this concept. If states are feeling like, ‘Well, wait a minute, we’re good with EIM and EDAM,’ then that’s certainly relevant to next steps.”
To Harvey’s first question, she said, “the idea of this is not to add costs, but to take advantage of investments that have already been made and then build on those.”
There was not time to answer questions from other participants.
CREPC Co-Chair Megan Decker, who is also chair of the Oregon PUC, said the committee would convene a follow-up meeting.
“It seems to me this is something where CREPC could convene a larger conversation to answer some of the questions that we didn’t have time for in 20 minutes today,” Decker said.
New solar power surged to record heights in the U.S. in the first quarter of 2023, while energy storage slumped because of a major jump in the already-high number of megawatts sitting in interconnection queues across the country, according to recent reports from industry analyst Wood Mackenzie.
Solar had its best first quarter in the industry’s history, with installations of 6.1 GWdc, up 47% from a year ago, according to Wood Mackenzie’s latest Solar Market Insight report for the Solar Energy Industries Association. Further, solar accounted for 54% of all new generation on the grid in the first quarter.
Drivers for the year-over-year growth include a loosening of supply chain constraints, with a wave of formerly delayed projects being completed, and a rush of first-quarter residential installations in California ahead of the state’s new, lower solar compensation plan, called NEM 3.0, which went into effect April 15, the report says.
At the same time, the full impact of the solar tax credits in the Inflation Reduction Act has yet to really affect the market as installers continue to work through the Internal Revenue Service guidelines that have been issued to date. For example, project developers can get add-on credits for locating projects in “energy communities” — such as areas that have lost employment because of coal plant closures.
The IRS guidelines for the add-on credits are complex and still being issued, the report says.
Storage, on the other hand, added a modest 778 MW/2,145 MWh in the first quarter, down 26% from the fourth quarter of 2022, as reported in Wood Mackenzie’s Energy Storage Monitor for the American Clean Power Association.
The amount of storage sitting in interconnection queues soared 40% year over year in Q1, as installations fell 21%. | Wood Mackenzie
Year-over-year figures in the report are divided by sector, with grid-scale storage taking the biggest hit, declining 21% from Q1 2022, installing 554 MW this year versus 697 MW a year ago. The culprit here is the 40% increase in the new storage capacity added to interconnection queues, the report says, growing from 315 MW in Q1 2022 to 430 MW this year.
The report also notes that more than 1.8 GW of storage projects scheduled to come online in the first quarter have been delayed to later in the year.
Additions came from a 119% increase in the commercial and industrial sector, from 31.6 MW last year to 69.1 MW, and a smaller 7% gain in residential storage, from 145.1 MW to 155.4 MW.
The storage tax credits in the IRA are proving a mixed blessing, the report notes. While lithium-ion prices are down, to get the law’s full 30% tax credit, developers have to meet its requirements for prevailing wages and apprenticeship programs, which are raising labor and other costs.
Big Growth Ahead
Growth in solar and storage markets is seen as critical for President Joe Biden’s goal of decarbonizing the U.S. electric grid by 2035. While the uneven first-quarter results may cause some uncertainty, Wood Mackenzie still expects exponential growth for both sectors.
Solar capacity is expected to nearly triple over the next five years, from 142 MW to 378 MW. In addition, the IRA’s domestic content provisions — which link tax credits to panels with U.S.-made components — have spurred a growing list of announcements of new panel manufacturing in the U.S.
By the end of the first quarter, Wood Mackenzie was tracking 52 GW of new facilities that had been announced, with at least 16 GW under construction. The challenge for the sector is that even if assembled in the U.S., solar panels may not meet the IRA’s domestic content provisions, as manufacturing for other key components will likely lag, the report says.
“There is currently no silicon solar cell manufacturing located in the U.S., and these facilities take at least two to three years to build and ramp up production,” the report says. Only 20 GW of new cell manufacturing facilities have been announced since passage of the IRA, significantly less than the new solar panel capacity already announced, the report says.
Wood Mackenzie is also anticipating a drop in the California residential solar market — with a knock-on effect on national growth — because of NEM 3.0, which slashes the amount of compensation rooftop solar owners will get for the excess power they put on the grid.
While a backlog of installations in California will keep figures up in 2023, Wood Mackenzie expects residential installations in the state will drop 38% in 2024, reducing the national residential market 4%. Boosted by IRA tax credits, solar across other states is expected to grow 12%.
For storage, Wood Mackenzie predicts 75 GW of new capacity will be installed by 2027, up from the current figure of just under 11 GW. More than 80% of the new capacity will be utility-scale storage, the report says.
The growth may start slowly, with supply chain and interconnection roadblocks affecting the market this year and next, but will accelerate to make up for such delays in the following years, the report says.
WASHINGTON — Leah Ellis is not worried about building demand for the low-carbon process she has developed for making cement. The CEO of Massachusetts-based Sublime Systems says she has a healthy pipeline of prospective customers waiting to buy the company’s product, made with an electrolyzer powered by wind and solar, rather than the traditional, high-heat, high-emission kiln.
“The demand for low-carbon cement is phenomenal,” Ellis said during an interview at Wednesday’s Clean Industrial Summit, sponsored by the Clean Air Task Force and ClearPath Foundation, both nonprofits focused on reducing greenhouse gas emissions. Sublime has a pilot plant up and running in Somerville, Mass., and potential customers are often more interested in how much of the company’s high-performance cement they can get than the price.
“They do ask about price, but I think it’s just not one of the first questions that people ask me,” she said. “Understand, you’re not just buying a ton of cement; you’re also buying the carbon avoidance.”
Ellis was just one of the startup executives at the summit, talking about the potentially game-changing technologies they are bringing to market, all aimed at upending conventional wisdom about heavy industry and its notoriously hard-to-abate greenhouse gas emissions.
Antora Energy, a California based startup, has developed a thermal storage technology that allows wind and solar energy to be stored at high temperatures — as high as 1,500 degrees Celsius — to provide heat for industrial processes. The company is targeting steel and cement as early markets, said CEO Andrew Ponec.
“This product has the potential to strike right in the heart of industrial emissions,” Ponec said. “It can serve almost every industry at any temperature range that’s used widely [and] any geography that has wind and solar at scale.”
The company’s investors include the Bill Gates-funded Breakthrough Energy Ventures, Lowercarbon Capital and Shell Ventures.
Historically dependent on carbon-intensive processes, heavy industry — including cement, iron and steel, and petrochemicals — accounts for 23% of U.S. greenhouse gas emissions, according to EPA. While transportation (28%) and electric power (25%) are the country’s top emitters today, industrial emissions are projected to jump into the No. 1 spot by 2035, according to the Rhodium Group.
The Department of Energy has made industrial decarbonization a priority, with a series of reports and funding opportunities, such as the Industrial Heat Shot, which is supporting research into new technologies that can cut industrial heat emissions by 85% by 2035.
Early research-and-development funds from DOE’s Advanced Research Projects Agency-Energy (ARPA-E) were essential for both Sublime and Antora, their CEOs said.
But, while promising, these new technologies may not be able to scale fast enough to meet the decarbonization goals of industrial giants such as Cemex, a multinational cement company with plants in seven states in the U.S., said Jerae Carlson, the company’s senior vice president for sustainability, communications and public affairs.
What’s technically feasible may not be economically feasible for “each and every one of our operations,” she said. And the new technologies like Sublime’s and Antora’s may take a long time to scale.
Many companies in the industrial sector have committed to cutting emissions and reaching net zero by 2050, but David Crane, DOE’s under secretary for infrastructure, says that’s not fast enough.
Crane said most of these businesses are approaching decarbonization with a four-step strategy. Efficiency and electrification are first and second, respectively, both over the next decade, followed by efforts to tackle industrial process heat in the mid-2030s and 2040s and some form of carbon sequestration for any residual emissions.
Crane is also focused on industrial process heat. “Our goal is to break that third step, which is where government can play a role because it’s the hardest step to change the mentality of both producers and buyers,” he said. “If you think you have to wait around till 2035, you won’t be a leader in your industry.
“The federal government is going to use every power at its disposal” to push industrial decarbonization forward, he said, from DOE programs, such as its $7 billion initiative to stand up regional green hydrogen hubs, to procurement.
“The government directly or indirectly pays for 50% of the cement used in the United States,” Crane said. “Now, how do you translate that into sending a market signal that we want green cement? That’s something we’re still working on.”
Melissa Carey, head of climate policy and government affairs for Holcim, a building materials multinational, acknowledged her company’s decarbonization strategy hews closely to Crane’s description.
“We do efficiency. We do carbon capture. We plant trees,” Carey said. “It’s unfortunate but true, in a sense, because we know what we need to do. We need to be able to do it faster.”
The key roadblocks to Holcim’s decarbonization plans are what Carey called “enabling conditions.” The company has ordered 200 of Ford’s F-150 Lightning electric pickup trucks but so far has received only one.
Reviewing plans for carbon capture at the company’s largest cement plant, Carey recalled asking, “How much does the timeline depends on funding and technology availability? And the answer was ‘completely.’
“If we can’t get more transmission built, then we can’t get more renewable energy,” she said. “We have 13 cement plants and zero pipelines right now to connect any captured CO2 to storage. … Where we’re really focused now is having later plans on trying to spur some of these enabling conditions so that we can do what we want to do as fast as possible.”
Cemex is looking to alternative fuels — such as bioenergy and renewable natural gas — to power its high-temperature kilns, Carlson said. With plants that operate 24/7 at high temperatures, the company would like to tap into waste streams as a source for bioenergy that can meet its need for tightly scheduled operation.
But, Carlson said, “the regulations around waste management here in the U.S. are not nearly as cohesive at a rural level, and then you also have to deal with state and local issues.”
While “focusing heavily” on carbon capture, Cemex’s “goals for 2050 … do not rely on known, proven, viable strategies right now,” she said. “We know we’re going to have to rely on innovations that we haven’t even conceived of yet.”
The steel industry has already cut its emissions, with a heavy reliance on the use of recycled steel as feedstock for steel production. “About 70% of the steel made in the United States is actually made through a recycling process,” said Kevin Dempsey, CEO of the American Iron and Steel Institute, an industry trade group.
Companies also are shifting from coal to natural gas to produce the high heat needed for purifying iron ore, a key step in making steel, and looking forward to possibly moving to clean hydrogen, when it becomes available, he said.
At the same time, Dempsey cautioned, “there’s not going to be a single way to get to [net] zero. All our companies are significantly committed to get to zero … but they’re pursuing a variety of paths, because our industry is very competitive.
The upside is that customer demand has become a major spur for innovation. “Frankly, demonstrating you can produce a clean product that can meet your customers’ needs is really one of the most significant driving forces in the steel market today,” he said.
‘Turn off the Tap’
As with steel, the quest for carbon-free cement is also drawing multiple innovators and new technologies. The industry has long been seen as one of the hardest sectors to decarbonize, with its reliance on a raw material, limestone and a high-heat process. Worldwide cement accounts for about 8% of all CO2 emissions.
At California-based Brimstone, CEO Cody Finke and his team have developed a chemical process for making cement from calcium silicate rock, a carbon-free rock that, Finke said, is 100 times more abundant than the limestone used to make most cement. The process also produces magnesium, which can passively absorb CO2, making Brimstone’s cement potentially carbon negative.
The company’s goal is to manufacture Portland cement, a building industry standard, that is both cost-competitive and carbon-free. Brimstone’s cement was recently certified to meet a key industry standard for Portland cement, ASTM C150.
To earn industry acceptance and scale quickly, “you need to use the [industry] structure that exists out there, existing trade unions and builders who know how to deal with the material,” Finke said. “If I have the option to build that building with the material we trust, the same material that we’ve always been building buildings out of … it’s hard to take the risk to build with a new material, even if the new material may be as good.”
Finke also said Brimstone’s process can be used “across a broad range of energy scenarios” and can be completely electrified. All of the cement the company has produced to date has been powered by electricity, he said.
Sublime is going another route, also using calcium silicate rock but producing cement that meets another ASTM standard, C1157, which is performance-based, CEO Ellis said. The standard is just as rigorous as C150 and has increasing acceptance across the industry, she argued.
When mixed with water, Sublime’s cement “sets and hardens to make the same concrete we’ve be using for millennia, but it’s not made in a kiln,” she said.
The company’s pilot plant has recently expanded its capacity from 100 tons of cement per year to 250, Ellis said. The first shipments of cement are being sent to customers for field testing.
Responding to Carlson’s comments on scalability, Ellis said the next steps will be to “optimize” the demo plant and then scale, to produce tens of thousands of tons of low-carbon cement per year as soon as 2025 and up to 1 million tons by 2027 or early 2028.
The cement’s strongest selling point will be its carbon-avoidance, as opposed to the carbon capture used by Brimstone and the multinationals, she said.
“We have to do everything as fast as possible to bend the curve of CO2 emissions,” she said. “I think of CO2 emissions as a leak from a tap, and you have water spilling out onto the floor. And in my opinion, the first thing you do is turn off the tap … avoiding the source of the emissions.”
As Antora CEO Ponec says, tackling industrial process heat lies at the heart of industrial decarbonization, and multiple solutions will likely be needed. But he and others emphasized that new technologies should not be forced on the market.
Nuclear developer X-energy decided to go small with its 80-MW small modular reactor (SMR), the Xe-100. Benjamin Reinke, director of global business development, said the design provides a flexible solution with both electricity and super high temperatures for process heat.
The company is one of two being funded through DOE’s Advanced Reactor Demonstration Program, with $1.1 billion to stand up its first reactors this decade; the other is the Bill Gates-founded TerraPower.
X-energy had originally partnered with Energy Northwest, a public power provider in Washington state, for its first deployment, but it announced in March it would instead be working with Dow Chemical, providing process heat and electricity to one of the company’s plants on the Texas Gulf Coast.
The Xe-100 is a high-temperature, gas-cooled reactor, which uses small “pebbles” of graphite-covered nuclear fuel and can produce steam for high-heat industrial processes, with temperatures of 750 C, or close to 1,400 degrees Fahrenheit.
Reinke said the Xe-100 can turn its power level up or down, like a natural gas peaker plant, and can be expanded as needed. For Dow, the company is planning to install four of its SMRs. It is also still working with Energy Northwest and recently signed a joint agreement to develop up to 12 reactors for a site near the utility’s Columbia nuclear reactor in central Washington. (See X-energy, Energy Northwest to Develop up to 12 SMR Nukes.)
“Two years ago, we thought for sure that the largest utilities in America would be the first to adopt advanced nuclear at [scale] because they had the most experience operating nuclear reactors,” Reinke said. “Today, what we’re seeing is that investors’ [environmental, social and governance] goals and requirements at various companies and their customers are driving a lot of heavy industry to decarbonize faster than many utilities have in their own projections. …
“We’re opening up a new market,” he said. “It changes the total addressable market for us and for many of our competitors … but we’re also leveraging that for additional learning and the ability to de-risk new technology coming to market.”
Ponec said Antora’s process has also been market driven.
“We were really looking for what would have the biggest impact,” Ponec said. Looking at industrial heat, he said, combining “that need to decarbonize with the incredibly low cost of variable renewable energy is so tantalizing. It was clear that renewables could do the job, if not for the variability.”
Finding a solution to that problem led to the development of the company’s carbon-based thermal storage technology, he said. “The way our system works is you take electricity from wind and solar when it’s available; you run that through resistive heating elements, just like a twister coil, to heat up carbon blocks to a very high temperatures, white hot, about 1,500 degrees; and then you continuously extract that … heat as steam.”
Further, he said, the materials in the storage unit are inexpensive and domestically sourced. “There aren’t a lot of barriers to scaling this up to the massive scale we need for rapid decarbonization,” he said.
The company has completed construction of a pilot plant and hopes to have its first systems online by 2025, he said.
While not naming names, Ponec said potential customers are looking at Antora’s combination of cheap renewables and thermal storage as a lower-cost source of industrial heat than natural gas by 2030. “At the point that you can start saying … you can beat the cost of … natural gas over a 10-year contract, that opens a market that is extraordinarily large,” he said.
ISO-NE projects an approximate 47% decline in gas generation for the year 2032 compared to current levels but expects coal and oil generation to increase by 45% to meet winter peak loads, the RTO told its Planning Advisory Committee on Tuesday.
Despite the expected winter increase in coal and oil generation, ISO-NE anticipates emissions declining across all months by 2032, with the largest emissions reductions coming in the spring, summer and fall. ISO-NE projects annual emissions being nearly half of 2021 levels, declining from about 30 million tons of carbon per year to 16 million tons.
These findings are part of the RTO’s ongoing Economic Planning for the Clean Energy Transition pilot study. The study takes into account the increase in peak load due to electrification projected by ISO-NE’s 2023 Capacity, Energy, Loads and Transmission report. (See ISO-NE Increases Peak Load Forecasts.)
“Additional PV and wind resources beyond what is already in the model may help alleviate demand for dispatchable generation, but the needed volume of energy is significant,” said Benjamin Wilson of ISO-NE. “Some additional energy storage will likely be needed to shift the energy from when it is produced to when it will be needed.”
Wilson said the results indicate overall lower production costs and locational marginal prices due to the influx of zero-marginal-cost energy resources replacing gas generation.
“The system may experience an increase in reliance on stored fuels (LNG, oil, and coal) in the winter despite the new wind, solar and energy storage resources,” Wilson added.
The results contain limits: The study did not model generator outages and includes generators that did not receive capacity supply obligations in the latest Forward Capacity Auction and may retire prior to 2032. This includes the Merrimack Station, the last coal-fired generator in New England. The study also assumes continued operations of the Everett LNG import terminal for 2032.
Monthly emissions in 2021 compared to 2032 min and max scenarios. | ISO-NE
“A reduced LNG capacity would lead to an increased demand on other stored fuel resources,” Wilson said.
Transmission Planning
Also at the PAC, Dan Schwarting, manager of transmission planning at ISO-NE, presented initial high-level takeaways from the RTO’s 2050 Transmission Study, looking at meeting the transmission needs of the region for 2035, 2040 and 2050. ISO-NE expects a draft of the study to be ready to present to the PAC in November.
Schwarting told the committee early results indicate relatively small reductions in the projected 2050 winter peak load are associated with outsized reductions in transmission costs.
A 10% reduction of ISO-NE’s initial 57-GW winter peak “snapshot” for 2050—which represents the electrification of nearly all the region’s heating using existing technology—would be associated with a roughly one-half to one-third reduction in transmission costs, Schwarting said.
Despite uncertainty in predicting future load concentrations and generator locations, Schwarting said some high-likelihood upgrades could be pursued in the near term, including increasing capability for north-south transfer and Boston imports.
“Investment in addressing these concerns may be prudent regardless of exact generator locations and load distribution,” Schwarting said.
To meet the future needs for north-south transfers and Boston imports, Schwarting laid out four potential pathways: prioritizing rebuilds of existing lines, building new 345-kV overhead transmission, building new HVDC transmission lines or building an offshore grid that would enable power transfer between states and regions.
“In many parts of New England, addressing concerns by rebuilding existing lines for higher capacity is clearly more cost-effective and feasible,” he said, adding that using this approach to address all regional needs could end up being more expensive than the alternatives, and this path could not scale up to meet a 57-GW peak demand.
Schwarting highlighted some potential benefits of an offshore grid, including the ability to move power between interconnection points when capacity is not taken up by wind power.
“For example: In summer daytime peak snapshots, wind is assumed to be at 5% output. The remaining 95% of cable capacity is available to transfer power from one point of interconnection to another,” Schwarting said. “Beyond what is modeled in the 2050 Transmission Study, these grids could be expanded to include wind farms connecting to New York, PJM or other neighboring areas.”
Schwarting emphasized that providing a full cost/benefit analysis of an offshore grid is beyond the scope of the study, which will look only at approximate costs and a limited set of benefits.
“While significant research and development towards offshore transmission has been performed in Europe, meshed offshore HVDC systems are not yet in use commercially,” Schwarting added, noting the National Renewable Energy Laboratory is conducting a two-year study into Atlantic offshore wind transmission that will consider the potential for an offshore grid.
Asset Condition Projects
Eversource, National Grid, and Avangrid presented on several asset condition projects totaling over $100 million:
Eversource expects to spend about $31 million on structure replacements and optical ground wire installations on one 115-kV line and two 345-kV lines in Connecticut, citing age-related issues including woodpecker damage, cracking and splitting, and damaged insulators and deteriorated steel hardware. The expected in-service dates for the projects range from late 2024 to early 2025.
National Grid proposed spending about $6 million to replace five 69-kV and six 115-kV Oil Circuit Breakers at the Northboro Road Substation in Northboro, Mass.
Avangrid increased its cost estimate for its 115-kV Derby Junction to Ansonia Line Rebuild Project, proposing to spend $71 million to rebuild the line, nearly doubling the cost compared to its 2021 estimate of the rebuild. The company said the rebuild would extend the life of the line by at least 50 years.
The U.S. Department of Energy is proposing efficiency standards it says will save Americans billions a year on the operation of their water heaters and eliminate millions of tons of carbon dioxide emissions.
The proposal announced Friday would mandate heat pump technology in the most common-sized electric water heaters and mandate improved condensing and other technology in fossil fuel-burning units.
The department is mandated by Congress to make periodic updates in efficiency requirements; this is the 18th it has issued so far in 2023. The last update of water heater standards was in 2010.
The agency said it followed recommendations from two major water heater manufacturers, the Consumer Federation of America and a variety of stakeholders as it put together this new proposal. If adopted on the timeline DOE proposes, it would take effect in 2029.
Warming up water for household purposes accounts for about 13% of annual residential energy use.
The actual consumer benefit of the new standard would depend on the cost of fuel or electricity and on the speed of replacement of old technology with new. But DOE estimates that over the course of 30 years, the proposed standards could save Americans $200 billion and reduce CO2 emissions by 500 million metric tons.
That breaks down to a savings of $1,868 over the lifespan of an electric heat pump water heater compared with a traditional electric resistance unit, the department said. Further savings accrue with credits, rebates and other incentives offered through the Inflation Reduction Act.
The rule also would boost minimum efficiency ratings for tankless and storage water heaters that burn oil or gas, again by relying on technology improvements.
In total, DOE estimates the proposed rule would reduce energy used by water heaters by 21% and provide a $2.8 billion-a-year health benefit.
