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August 10, 2024

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SPP Board Rejects Recommended Competitive Project

ST. PAUL, Minn. — SPP’s Board of Directors on Tuesday rejected an industry panel’s recommendation to award a competitive project in New Mexico, leaving staff unsure of the next steps.

“This is a first for us. We probably need a little bit of guidance,” SPP CEO Barbara Sugg said.

Pointing in General Counsel Paul Suskie’s direction, she asked her governance “guru” for guidance.

Suskie said SPP’s tariff does not “contemplate” remanding the project’s evaluation back to the five-person industry expert panel (IEP) responsible for awarding projects under the RTO’s competitive selection process. According to the tariff, the board could select either the recommended or alternate proposal, based primarily on the information provided by the panel, he said.

SPP’s Paul Suskie (left), Lanny Nickell confer on board’s vote and tariff implications. | © RTO Insider LLC

The IEP “put so much time and energy into this, I think it would be very difficult for them to come back with a different answer,” Sugg said.

“My advice to you, if you turn down our recommendation, is there’s only one other recommendation that could come up for your vote,” said Mike Jacobs, the panel’s chair and president of consulting firm Both Supply & Demand. He said if the board directed the IEP to run further projections and scenarios, “we’ll report back to you, but the analysis could lead to paralysis.”

The directors debated their options before deciding to take up the issue during their normal post-meeting debrief.

SPP said Wednesday that the board is working to determine “the best course of action to reach a timely outcome that preserves the integrity” of its FERC-approved Order 1000 process.

“SPP will communicate their plans to stakeholders in the coming days,” spokesperson Derek Wingfield said.

The IEP was seated last August to evaluate anonymous bids to build a 345-kV double-circuit line in eastern New Mexico from Crossroads through Hobbs to Roadrunner in two segments totaling 143 miles. The upgrade, estimated to cost $376.3 million, was proposed by Xcel Energy subsidiary Southwestern Public Service (SPS) as an alternative to a previously identified project in the 2021 Integrated Transmission Plan. (See SPP Board of Directors/Members Committee Briefs: July 26, 2022.)

The IEP’s scoring results for the three project proposals. | SPP

The panel received only three bids for the project, two of them from the same entity. Following the process, it unanimously recommended Proposal B, which accumulated the most points in the scoring system with 1,023.38 out of a possible 1,100. Proposal B also had the high scores in three of the five categories and placed second in another.

The IEP said the winning proposal presented “the best evidence that it can produce a successful project, built within budget; would operate as intended and in accordance with the requirements set out by SPP; and would be constructed in a safe manner.”

Proposal B also had the highest estimated construction cost at $291.6 million. Proposal C, which had a submitted cost of $220 million but finished third in the scoring, was selected as the alternate.

The proposal only gathered three “for” votes during the Members Committee’s advisory vote. Twelve members abstained, and seven voted against it. Ironically, one of those voting “no” was SPS, the incumbent transmission owner and widely believed to be one of the two bidders along with NextEra Energy. (The Florida-based transmission developer does not have a vote on the committee.)

“We do have an indication from the members that the motion shouldn’t pass. We didn’t get specific guidance on members about why they voted ‘no,’” Director John Cupparo said. “We’re in a bit of a conundrum. How do we extricate ourselves from this situation?”

Jacobs, who has participated on three of SPP’s five IEP panels and chaired two of them, was unable to satisfactorily answer Director Larry Altenbaumer’s questions attempting to understand why the more expensive option was recommended.

“I’m not sure the IEP’s recommendation is necessarily the wrong one,” Cupparo said. “What I’m really looking for is more supportive analysis that tells me the risk is too great for a lower-cost alternative. I don’t know if that’s the case or not, but the pieces seem to be there. I don’t know if that’s something that can be turned around quickly or evaluated, but that would certainly be helpful.”

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Members of Congress Debate Transmission Permitting

Congress has been talking about changing permitting laws this year, but it’s still unclear whether the two parties will be able to strike a deal, speakers said at an event Wednesday hosted by The Hill and Advanced Energy United at the National Press Club in D.C.

Sen. John Hickenlooper (D-Colo.) is working on the BIG WIRES Act, which would require minimum transfer capability between regions. That would benefit the entire country by making cheaper power supplies available and facilitating the shipping of more power to regions facing reliability crises, he said at the event.

“Certainly, it’s a steep hill these days, because both sides are worried about giving any advantage to the other side, rather than solving the problems,” Hickenlooper said. “I think the BIG WIRES is about trying to make sure that we can get the power to where it’s needed.”

That and other reforms are being debated, but the question is whether Congress can actually pass them — either on their own, or as part of some must-pass legislation, as happened with the first bite of the apple during the debt ceiling showdown. (See Debt Ceiling Bill Provides Mini-deal on Permitting.)

From left: Rep. John Curtis (R-Utah); Sen. John Hickenlooper (D-Colo.); and Bob Cusack, editor-in-chief of The Hill | The Hill

“I haven’t given up my hope for this Congress right now,” said Rep. John Curtis (R-Utah). “There are some great ideas out there.”

Any policies that do wind up getting past the Republican side at least will have to go through “regular order,” meaning the relevant committees will have to examine them and pass them, even if they go into some kind of must-pass budget deal, he added.

“There’s something therapeutic for a member, if he doesn’t understand an issue, that it’s gone through committee hearings, that his colleagues have had a chance to digest it; to read every line and study every line; and that they support it,” Curtis said.

A final rule from FERC on interconnection queue reform is expected at its open meeting Thursday, and rules on transmission planning and implementing its new backstop siting authority are still pending. While Hickenlooper noted the commission might be able to act faster than Congress, Curtis argued regulatory changes could prove transitory.

“If we don’t do it, legislatively, it’s not permanent,” Curtis said. “And it’s subject to change. … If we get a different administration, in two years, you’re starting over. And I think it’s harder to do it legislatively, but it’s more long-lasting if we can do it.”

Maria Robinson, DOE | The Hill

FERC is not the only agency working on the issue, with the Department of Energy’s Grid Deployment Office in charge of $26 billion in spending to help expand the transmission grid, said its director, Maria Robinson. With new factories and other sources of demand sprouting up around the country, along with major changes in power supply, new transmission needs to be built.

“Now part of this is, transmission is not cheap,” Robinson said. “I think that’s something that we can all agree on. And we want to make sure that we’re planning appropriately, whether it’s across different regions or across different state lines, to make sure that we’re doing it really efficiently and cost effectively for the American people so that no one is paying for lines that are duplicative or unnecessary.”

For too long, planning the grid has been too ad hoc and decentralized, with transmission plans focused on curing immediate reliability needs and not paying attention to the future, said Kyle Davis, director of U.S. federal policy for Enel North America.

“It’s good news that people are even uttering the word ‘transmission’ in the halls of Congress,” Davis said. “For those of us that have been working on this issue for over 10 years or so, it is refreshing. I think the hope is that we can get some real fundamental movement and sort of comprehensive transmission investment strategy for the United States.”

Permitting on Federal Land

Meanwhile, members of the Senate Energy and Natural Resources Committee debated permitting reform on federal lands. Much of the Wednesday was devoted to oil and gas permitting, but Chair Joe Manchin (D-W.Va.) made sure to include transmission in the discussions.

“Over the last year there has been an attempt to paint transmission permitting reform as just another subsidy for intermittent renewable energy,” Manchin said in his opening statement. “If that were the case, then that would be very hard for a lot of us to support. But this simply isn’t true, and we should not politicize infrastructure that has long enjoyed bipartisan support.”

Manchin argued the importance of transmission for reliability, “particularly during weather events that span hundreds of miles. Long-distance transmission and interconnectivity enables power to move to where it’s needed. And as we’ve seen in Texas and other parts of the country, the areas that need the power aren’t just blue states with aggressive climate targets that some of us may not agree with.”

Ranking Member John Barrasso (R-Wyo.) agreed, somewhat.

“The biggest threat to reliability is not the lack of transmission lines. It is the premature retirement of coal, natural gas and nuclear power plants,” Barrasso said in his opening statement. “Congress should not try to force electric customers in rural, inland states, such as Wyoming and West Virginia, to subsidize ill-conceived policies of coastal states, such as California and New Jersey. If California, New Jersey or New York want to rely on offshore wind, then their customers should pay for it.”

Manchin noted that while the debt ceiling deal limited environmental reviews under the National Environmental Policy Act, judicial proceedings over those reviews still can tie up projects long after they’ve been approved. Witnesses at the hearing generally agreed that it was necessary for Congress to set tighter deadlines for parties to file challenges, for courts to reach decisions and for agencies to fix the issues identified by the courts.

From left: former Maryland PSC Chair Jason Stanek; Antonio Smyth, AEP; and Chad Teply, Williams Companies | Senate ENR Committee

“I think a shot clock is important,” former Maryland Public Service Commission Chair Jason Stanek said. “Legal due process for the state who is out of favor is important … but that should not go on ad infinitum for potentially years at a time, so I think a statute of limitations is necessary.

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Senate Committee Looks into Climate Change’s Grid Impacts

Climate change already is causing billions of dollars in economic costs and damage to infrastructure, including the power grid, the Senate Budget Committee heard at a hearing Wednesday.

“Our power grids are seeing record-breaking demand and reduced power efficiency, as well as added sea level rise risk where infrastructure — especially thermal power plants — is located along the coast,” said Committee Chair Sheldon Whitehouse (D-R.I.). “Extreme weather is responsible for 78% of the major disruptions to our power system. Since 2015, the frequency of major blackouts has doubled.”

During an average year, power outages can cost about $44 billion, but that can be doubled or more because of major climate impacts, he added.

Winter Storm Uri in February 2021 knocked out power to millions in Texas and surrounding states, leading to at least 246 deaths and damages ranging from $80 billion to $130 billion, said Analysis Group Senior Adviser Susan Tierney. In December, Winter Storm Elliott cut power to hundreds of thousands on the East Coast and knocked out a quarter of the generation in PJM (although the RTO kept the lights on in its territory). (See PJM Recounts Emergency Conditions, Actions in Elliott Report.)

“Before it could no longer do so, PJM had been exporting power to neighboring utilities in the Tennessee Valley Authority region and the Carolinas where rolling blackouts were underway,” Tierney said in written testimony.

Extreme heat and drought also have tested the energy systems, as have wildfires, hurricanes and other events.

“Due to the changing climate, the energy system is projected to be increasingly threatened by more frequent, longer-lasting power outages affecting critical energy infrastructure and creating fuel shortages,” she added.

Hurricane Katrina in 2005 showed what could happen when a major storm wreaks havoc on key energy infrastructure — cutting one-third of domestic oil production and one-sixth of natural gas production.

“U.S. oil and gas prices were double the national average for months and it raised the national cost of natural gas on the order of $50 billion in the 10 months after the storm,” said Tierney.

That hurricane led to a major policy change in Louisiana, its first “Comprehensive Master Plan for a Sustainable Coast.” The plan, which has been updated three times since then, already has produced benefits, said Gov. John Bel Edwards (D).

“The Coastal Master Plan is a $50 billion, 50-year roadmap that prioritizes our investment in coastal infrastructure,” Edwards said. “The plan reflects the best available science, accounting for changes on the ground and forecasting what is at risk in the future.”

If the plan is properly implemented, Louisiana could have less at risk from sea rise and related storm risks in 50 years than it does today, he said. Without action, the state would lose thousands of square miles of coastline and increase its vulnerability to storms, he added.

After Katrina, the levees and other protections around New Orleans got a $14.5 billion upgrade. It did not fail during several hurricanes since and thus has saved billions in damages, Edwards said.

Next month marks the 20th anniversary of another major energy disruption — the East Coast Blackout, which left 50 million without power for up to two days in what was the most widespread blackout in North American history, said ITC Holdings CEO Linda Apsey.

“It was a sobering reminder of how vulnerable our nation’s energy security can be when we fail to adequately invest in transmission infrastructure,” Apsey said. “This event served as the impetus for regulators and energy providers to put safeguards in place that have made our grid more reliable and resilient than it was before.”

Although the industry has improved since then, the country needs to update how transmission is built to better secure the grid, Apsey said.

“Building transmission can take up to a decade, if not more — a pace nowhere near fast enough to meet the [Biden] administration’s clean energy goals,” Apsey said. “It’s imperative that we examine changes to ensure that investment in transmission is predictable, timely and cost-effective in order to realize the benefits of a modern transmission grid.”

Making it easier to build transmission lines so they do not get delayed by years of litigation and permitting disputes is going to be a key part of that effort, she added.

MISO’s Cardinal-Hickory Creek Line, which is planned to run 102 miles from Iowa to Wisconsin, was part of the original Multi-Value Projects (MVP) in 2011, but it has yet to be built due to permitting concerns over the 1.3 miles that crosses federal land, said Apsey. The courts recently cleared the way for federal permitting authorities to approve the project and ITC is ready to start work when they do.

“Over 100 renewable energy projects are awaiting completion of the Cardinal-Hickory project in order to interconnect to the grid, resulting in hundreds of millions of dollars in lost energy savings to customers,” Apsey said.

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Maine Legislature Approves Compromise OSW Measure

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!”

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More Environmental Information Required for Western Mass. Gas Pipeline

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.

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Lawsuits Mount over NJ OSW Projects as Opposition Digs in

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.

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NYISO Management Committee Briefs: July 26, 2023

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.

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MVP Southgate Extension Request Gets Mixed Reception at FERC

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.

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Proposed New Western RTO Discussed at CREPC

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.

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WoodMac: New Solar Hits 54% of New Generation in US in Q1

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.