BOSTON — As part of series of opening keynotes at the American Clean Power Association’s Offshore WINDPOWER 2021 conference, U.S. Secretary of the Interior Deb Haaland announced plans for the Bureau of Ocean Energy Management to potentially hold up to seven new OSW lease sales by 2025 in the Gulf of Maine, New York Bight, Central Atlantic and the Gulf of Mexico, in addition to the Carolinas, California and Oregon.
During a subsequent panel on permitting improvements, BOEM Renewable Energy Program Manager James Bennett said Haaland’s announcement represents “a path forward.”
“It does identify where we’re going and what we’re doing,” Bennett said. “This is not the first time we have attempted to put together and lay out a path forward, but it is the first time that we have been successful in being able to share with the public and specifically identify when lease sales are targeted for the near future.”
Massachusetts has targeted net-zero emissions by 2050, and at least 15 GW of OSW are needed, according to the state’s Decarbonization Roadmap. Energy and Environmental Affairs Secretary Kathleen Theoharides said that forward momentum on new lease areas “is a great, exciting announcement that probably should have received a lot more clapping from this audience.”
“It’s another piece of the puzzle to this whole question,” Theoharides said.
The Federal Permitting Improvement Steering Council (FIPSC) helps fit the puzzle pieces by overseeing interagency coordination and process improvements. With the Biden administration using a whole-of-government approach to deploy 30 GW of OSW by 2030, FIPSC Executive Director Christine Harada said from an efficiency perspective, “there’s a lot of work that we need to do within a very limited amount of time.”
Project uncertainty is challenging some of the agencies regarding how to permit something or how to evaluate the impacts under their statutory mandates, according to Scott Lundin, head of U.S. permitting and environmental affairs at Equinor. For example, Lundin said the Block Island Wind Farm began operations in 2016 with five 6-MW turbines, but General Electric announced that its turbines can now generate 14 MW of power.
“There’s a concern and a risk that alternatives get defined that are not technically, commercially, environmentally feasible,” Lundin said. “I think the opportunity for the developers to help inform and shape perspectives of these different agencies about the value and the need to bring these products to commercial operation is something that we’re very interested in facilitating whenever possible.”
Theoharides on Baker Announcement
After the permitting panel’s conclusion, Theoharides told RTO Insider that the announcement of legislation by Massachusetts Gov. Charlie Baker (R), which would create a $750 million clean energy investment fund and refine the current OSW procurement process, is “significant.”
“What it will open up for us here in Massachusetts is a chance to ensure that not only are we aggressively pursuing our net-zero targets, but we are leading the industry to design the solutions and then to retain those jobs right here in Massachusetts and in the Northeast,” Theoharides said.
The main change to the OSW procurement process would be the transfer of authority to select the winning bidder from state’s electric distribution companies like Eversource and National Grid to the Department of Energy Resources. However, EDCs would remain participants in the evaluation and provide technical advice to the department.
Theoharides said that taking the EDCs “out of the game” of choosing which company will win the bid makes procurements “more efficient” and “more objective process overall.”
Baker’s legislation comes on the heels of a plan by his administration to also direct $900 million in federal aid from the American Rescue Plan Act toward vital energy and environmental initiatives, including $100 million to invest in port infrastructure to support OSW. Theoharides said the $100 million would “kick off” port infrastructure work, and the state would look to leverage additional private investments.
Markey: Politics Hinder Renewable Energy Progress
U.S. Sen. Ed Markey (D-Mass.) said during an interview Thursday that the only thing stopping the progress on renewable energy sources like OSW is “politics and not technology.”
“If we didn’t have political opposition that was in place, the technology would have evolved much more quickly,” Markey said.
The target of 30 GW of OSW by 2030 set earlier this year is “modest,” according to Markey. However, he also thinks political opposition will be funded by the fossil fuel industry, especially at the ballot box.
“The fossil fuel industry is going to try to take the 2024 election, make it a referendum, bring back a gang that is tied to the fossil fuel generation strategy,” Markey said.
Markey introduced a bill in September that would create a 30% investment tax credit for U.S. manufacturers to produce qualified OSW components and dedicated vessels. “We’ve tailored the solutions to the exact needs of the industry to get the policies that fit to reduce the high capital costs that manufacturers face,” Markey said.
BOSTON — To meet the Biden administration’s 30-GW offshore wind goal by 2030, private investment coupled with government-backed financing is needed to spur construction of wind turbine installation vessels (WTIV), which carry a price tag of $500 million.
From the standpoint of the U.S. maritime industry, OSW is a “generational opportunity,” said Jennifer Carpenter, CEO of the American Waterways Operators, during the American Clean Power Association’s Offshore WINDPOWER 2021 conference on Thursday.
Multiple things can be done to “develop the supply of vessels” to serve the lifecycle of an OSW project, “from a survey, all the way on through construction development, eventual decommissioning,” she said.
“The first thing I would say is let’s not make it overly complicated to stimulate supply,” Carpenter said. “We have to focus on demand. It is not surprising that we do not have a fleet of vessels sitting on the proverbial shelf waiting to serve an industry that has not yet existed in this country because we’re doing something new.”
Because the Jones Act enjoys strong bipartisan support in Congress and from President Biden, Carpenter added, it “helps foster the certainty that we need to make investments” in WTIVs and other vessels. The Jones Act can be waived under tightly controlled circumstances, such as national defense, and there are no qualified U.S. vessels to meet that need, according to Carpenter.
Dominion Energy (NYSE: D) is currently constructing a Jones Act-compliant WTIV, which will be completed in 2023. However, U.S. developers will also have to rely on European-flagged jack-up vessels if any steel goes in the water in the near term. There are nine WTIVs available globally that can install turbines greater than 10 MW, and of those, only two of them can install turbines in the 12-MW-plus category. (See US Must Watch Europe’s OSW Supply Constraints, Analyst Says.)
Karl Humberson, director of construction projects for Dominion, said during the conference that he hopes construction of the WTIV provides the OSW industry “a level of certainty” that investments such as this are “going to help everybody else.”
Constructing a WTIV, he said, is not part of Dominion’s core business, but when the company looked at the puzzle pieces for OSW to determine “which ones are missing,” Dominion took “some risks.”
“We’re a little bit different. We are an owner-operator of a wind farm, so we have a little bit of certainty saying there’s a project here that we’re going after,” Humberson said. “That helped us make some decisions related to the WTIV. … We think it is the right way to build offshore wind, and that’s why we made these investments.”
While heavy lift vessels “get a lot of press” because of the significant investment, Troy Patton, COO for Ørsted Offshore North America, said he was struck by how many additional vessels are needed on an OSW project. Construction for a project off the coast Grimsby, England, he said, required upward of 50 vessels to deliver equipment and personnel to the wind farm.
The Title XI Federal Ship Financing Program will pay up to 87.5% of the cost for certain vessel classes and shipyards, according to David Gilmore, director of the Office of Marine Financing at the United States Maritime Administration. That payment can cover the construction of new vessels, reconfiguring vessels and modernization of shipyard facilities. Applicants for this program must meet financial requirements. There are also loan guarantee programs for onshore wind, which could be expanded to OSW projects and a capital construction fund with tax deferrals.
“There’s a lot of opportunity out there,” Humberson said.
The debate over a Western RTO has ramped up this month, with discussions focused on the feasibility of an organized market in the West, its pros and cons, and its potential makeup, including whether California’s participation is necessary for success.
Stakeholders and state regulators weighed those factors at a CAISOforum Wednesday and in an Oregon RTO Advisory Committee meeting Oct. 6. This week’s joint meeting of the Committee on Regional Electric Power Cooperation and the Western Interconnection Regional Advisory Body (CREPC-WIRAB) includes an afternoon of panels devoted to the topic, as well as other panels and presentations by FERC commissioners touching on it.
The growing sense of urgency is being driven by state decarbonization mandates, resource adequacy problems and state laws requiring utilities to join RTOs. (See Western Utilities to Explore Market Options.)
“There’s been a convergence of interest in these issues like there has never been before, and I think that’s a very, very good thing,” California Public Utilities Commissioner Clifford Rechtschaffen said during CAISO’s forum. “People are really focused on regional markets, the need for robust rules for resource adequacy and shared reliability efforts. How do we achieve clean energy mandates across the West now that more and more states have gone that way?”
Rechtschaffen called it an “opportune time” for regionalization efforts in the West.
The forum was primarily focused on the ISO’s proposal to expand its Western Energy Imbalance Market from an interstate real-time trading platform to an extended day-ahead market (EDAM), a potentially significant step for Western regionalization. But discussion of the EDAM and the Northwest Power Pool’s creation of the interstate Western Resource Adequacy Program (WRAP) led to talk of a Western RTO. (See CAISO Promotes EDAM Effort in Forum.)
“An RTO market is no panacea,” said Tony Braun, an attorney who represents the California Municipal Utilities Association. “For those that are in one, if you want to talk about funding of financial transmission rights by load and other things that are quite controversial, call me offline. We can talk about it. I think people underestimate the obstacles and, even within an RTO structure, the ongoing struggles of operating within that paradigm.”
EDAM, WRAP and the possibility of an RTO are all under consideration, and “I think we just need to tackle them all at the same time,” Braun said.
“I don’t them see as mutually exclusive, but I do see EDAM as low-hanging fruit. There’s so much work that has been put into EDAM … that it would not be prudent to abandon it just because there’s a myriad of other options. We have to walk and chew gum on this at the same time, maybe a couple different flavors of gum.”
State regulators and industry representatives weighed in on EDAM and Western markets. | CAISO
Spencer Gray, executive director of the Northwest & Intermountain Power Producers Coalition (NIPPC), called EDAM a worthwhile initiative but said “it can’t be the end goal of further regionalization.” EDAM and WRAP are incremental approaches that don’t adequately address the clean energy mandates of a growing number of Western states, or the laws that Colorado and Nevada enacted in June requiring transmission owning utilities join an RTO by 2030, he said.
“I don’t dispute that a staged approach to developing regional markets can help us move forward rather than just stalling out,” Gray said. “But I do want to emphasize that we have both statutory and market pressures across the West that hang over this initiative.”
California, New Mexico, Oregon and Washington have 100% clean energy mandates to meet by midcentury, he noted. Nevada established a 100% clean-energy goal it intends to reach by 2050.
“We also have large, sophisticated energy consumers across the West who are committed to going carbon-free, and many of them are convinced, based on actual experience procuring clean power in RTOs, that the model an RTO offers — of not having contract-based transmission anymore, not having pancaked rates, not having balkanized balancing authorities — [is] a better alternative.”
He said he worried the EDAM may be an “incremental step that holds at bay harder conversations about governance and balancing authority consolidation and transmission.”
SPP has been pitching its own RTO in the West. Gray called that a positive move that would allow entities to join an RTO without California having to give up control of CAISO, a state public benefit corporation created by the legislature, with board members appointed by the governor. Prior efforts to turn CAISO into an RTO have fizzled because California lawmakers were unwilling to cede any authority over it to out-of-state interests.
Joining SPP means utilities “can simply sidestep a brick wall of single-state governance that has bedeviled RTO conversations that have revolved around CAISO, so I think collectively we should take both the EDAM initiative seriously, take SPP’s work seriously and try to pick the best course. And we may pick different courses, which is OK. That’s been the experience along many seams in the East between the RTOs.”
Is California Necessary?
Gray’s comments and other discussions taking place in the West suggest industry stakeholders are weighing the need to create a workable RTO rather than an ideal one, forcing the region to consider the “art of the possible,” as Oregon Public Utility Commissioner Letha Tawney put it during a recent meeting of the state’s RTO Advisory Committee, which was charged with helping the state’s Department of Energy prepare a report on the benefits and risks of RTO membership. (See Oregon RTO Committee Ponders Paths to Regionalization.)
That could translate into an effort that sidelines California, the region’s most populous state, biggest load center and burgeoning center of cheap solar energy that can be exported to neighboring states during periods of surplus.
A recent state-led study produced by Energy Strategies found that all states in the Western Interconnection would realize the largest amount of savings — about $2 billion a year — from a single market that includes California, with the biggest beneficiaries being Washington, Oregon and California itself. (See Study Shows RTO Could Save West $2B Yearly by 2030.)
But integrating California into such a market is being seen as increasingly problematic as more states look to use RTO membership as one tool in meeting their decarbonization goals on ambitious schedules that will likely outpace the timeline for development.
Speaking during the Oct. 6 meeting of the RTO Advisory Committee, Tawney pointed to the well known governance issues that have hampered CAISO’s regionalization efforts in the past, with many in-state interests reluctant to allow the state to relinquish its direct authority over the appointment of members of the ISO’s Board of Governors. Resistance to changing that governance structure has made membership in an expanded CAISO a nonstarter for regulators in other parts of the West.
But just as problematic, Tawney noted, is California’s approach to resource adequacy, a process managed not by CAISO but by the state’s Energy Commission.
“It is unusual, but not unprecedented, to have your resource adequacy conversation happening in a different place than your RTO,” Tawney said. “CAISO does it that way. ERCOT sort of does it that way. But I think because of how resource adequacy is handled in California, it makes it very difficult to sort of take the California RA model and spread it across the West. And so then we have the rest of the West say, ‘How could we do RA for ourselves in a way that works for us?’”
Momentum toward a Western RTO could build after Colorado and Nevada passed bills requiring utilities in those states to join an RTO, Tawney said. She compared the potential outcome of that legislation to the expansion of the Western EIM, which eventually crowded out trading in the West’s bilateral markets.
“Where does that leave Oregon customers?” Tawney said.
She acknowledged the Energy Strategies study finding that showed that the biggest market footprint would produce the greatest volume of economic benefits for the West.
“The flip of that is there’s more people you have to work with and figure out how to get along with and manage through,” Tawney said. “So, you have to find that sweet spot, from my perspective, between customer benefits and state policy.”
What About BPA?
The situation in the Northwest is further complicated by the presence of the Bonneville Power Administration, which operates about 70% of the region’s high-voltage transmission and manages its extensive network hydroelectric dams.
Speaking at the RTO Advisory Committee meeting, Northwest Energy Coalition policy analyst Fred Heutte noted that BPA’s “integrated system” relies on a contract-based — rather than flow-based — approach to transmission use.
“I think it’s easy to say [that], in an RTO, you can move to a flow-based approach and it’s all going to be great,” Heutte said. “But we have to look at Bonneville as a unique institution with a really important role, and trying to move from a contract-based approach to a flow-based approach, given Bonneville’s integrated approach, is going to be a big issue to have to unravel and kind of piece together how you do that transmission.
“It’s not just a matter of grandfathering rights and that sort of thing,” Heutte said. “The Bonneville system has some unique features that we have to consider in the transition to an RTO process.”
During the RTO Advisory Committee’s first meeting Sept. 21, BPA Manager Ravi Aggarwal encouraged the group to consider a “staged and incremental” approach to developing an RTO, saying the region’s transmission planning, RA and real-time market are already being served by Northern Grid, NWPP and the Western EIM, respectively.
Speaking at the Oct. 6 meeting, Aggarwal clarified that he was not advocating for the long-term persistence of those looser arrangements in lieu of an RTO but thinks they could provide a “pathway” to an organized market, whether West-wide or in a smaller footprint, such as that covered by the NWPP.
“I think we have to be careful about holding out a perfect RTO as a possibility — or maybe an Eastern-style RTO maybe is the way to put it — because we aren’t starting with a blank slate,” Tawney said.
Offshore wind developers are starting to make good on their job-creation promises, but that hasn’t ended opposition to their projects.
Danish wind power company Ørsted A/S on Friday announced a $70 million contract with a Maryland steel company to supply components that will be used in the wind turbine foundations for Ørsted’s Mid-Atlantic offshore projects, its second supply-chain announcement this month.
The contract with Crystal Steel Fabricators in Federalsburg, Md., will create jobs for up to 50 welders, fitters, machinists and others who will manufacture turbine foundation boat landings, ladders, platforms, railings, gratings and other items for least three Ørsted projects: the Skipjack Wind project off Ocean City, Md. and Ocean Wind 1 and 2 in New Jersey. Crystal Steel will begin construction of new facilities to accommodate the work this month.
On Oct. 6, Ørsted announced it will spend $20 million to build an operations and maintenance center in Worcester County, Md., which will house up to three zero-emission crew transfer vessels to service the Skipjack wind farm. The facility will provide 110 temporary and permanent full-time jobs, a fraction of the almost 1,400 jobs the company says its 120-MW Skipjack 1 project will create across the state.
Press releases announcing the two deals included congratulatory quotes from Maryland Gov. Larry Hogan (R) and U.S. Sens. Ben Cardin (D) and Chris Van Hollen (D), who like politicians up and down the East Coast have embraced offshore wind as an economic development engine.
Concerns over Fishing, Tourism
But the projects also have sparked opposition from the fishing industry and tourism-dependent businesses. The Maryland Public Service Commission (PSC) must decide by Dec. 18 whether to approve Ørsted’s Skipjack 2.1, which could be as large as 882 MW, and US Wind’s proposed Momentum Wind project, which will also be located east of Ocean City. (Case No. 9666)
The Clean Energy Jobs Act of 2019 directed the commission procure at least 1,200 MW of offshore wind projects in its second solicitation. In 2017, the PSC approved 368 MW in OSW by Skipjack and US Wind. (See Md. PSC OKs 368 MW in Offshore Wind Projects.)
Ocean City, a town of just under 7,000 residents that swells with beach visitors in the summer, is perched on a narrow barrier island known as Fenwick Island.
At PSC public hearings Sept. 28 and 30 on Skipjack 2.1 and Momentum Wind some speakers welcomed the projects, while others objected, with particular criticism of the planned location of US Wind’s site, which could come as close as 13 miles to Ocean City.
Resident Danny Robinson, who said he works in a local restaurant, said the projects would lead to the “complete looting of our local resources and tourism industry” to benefit the “big wind cartels.”
The 13-mile figure came in testimony filed at the PSC Aug. 25 by Matthew Filippelli, technical director of US Wind. He explained that the first of the turbines for the project will be built in the easternmost portion of the lease area, in federally owned waters approximately 22 miles offshore of Ocean City, extending westward to between 13 and 18 miles from shore, depending on the project size. Deborah Henry, project development director for Ørsted, testified her company’s turbines will be a minimum of 20 miles from shore.
Elected officials were also split on the projects. Evan Richards, representing the office of state Sen. Katherine Klausmeier (D), said she supports both wind farms, calling the development “one of her proudest legislative accomplishments.”
Jennifer Aiosa, chief sustainability officer for Baltimore County Executive Johnny Olszewski, also spoke forcefully in favor, saying, “How often are we offered the opportunity for large-scale economic development that actually improves the quality of our environment?”
But Maryland state Sen. Mary Beth Carozza, a Republican whose district encompasses the town, said “the Ocean City way of life for both residents and visitors may be no more with the latest proposals. Why would we put all this at risk? The turbines should be moved further offshore.”
Terry McGean, city engineer for Ocean City, warned of “a wall of turbines across the entire Ocean City beach horizon.”
Ocean City Mayor Richard Meehan also expressed concern. “We support offshore wind, but not at the expense of the future of the town of Ocean City. It was supposed to be more than 20 miles offshore — allowing it to be closer contradicts the commission’s own opinion.”
PSC Communications Director Tori Leonard said she was not certain what “opinion” Mayor Meehan was referring to.
The commission’s 2017 order awarding US Wind and Skipjack offshore wind renewable energy credits (ORECs) in its first OSW solicitation directed U.S. Wind to locate its project “in the eastern-most portion of the Maryland Wind Energy Area that can reasonably and practicably accommodate” it.
“Notwithstanding the legal permissibility of a proposed OSW project to locate as close as 10 miles off the coast of the state, we find that there is a strong public interest in ensuring that impacts to the viewshed as a result of an OSW project are minimized to the fullest extent possible,” the order said. (Case 9431)
In its 2020 order approving Skipjack’s request to increase the size of the turbines it planned to use, the commission noted that it had required Skipjack to “use best commercially-reasonable efforts to minimize visual impacts. Nowhere did the commission require that the project be invisible from the shore. For these reasons, the commission finds that it is not commercially reasonable to require the project to be moved beyond the visibility of Ocean City’s shore.” (Case 9629) (See Md. PSC Approves Larger OSW Turbines.)
Project Doubled
Skipjack’s proposal to add up to 882 MW of turbines in Phase 2.1 more than doubles the 335 MW it planned for Phase 2 as of last December. Henry testified that the company had made the more modest plan before Congress extended the Investment Tax Credit to offshore wind. “The extension of the Investment Tax Credit allowed Skipjack to revisit its plans and submit a second, larger option that builds on economies of scale and provides even greater investment in, and benefits to, the state of Maryland,” she said.
Since the Maryland PSC approved Skipjack 1 in 2017, Ørsted says it has invested nearly $40 million in the state, including more than $13 million at Tradepoint Atlantic, a port in Baltimore County where it is creating an offshore wind staging center on the site of the former Sparrows Point steel mill. (See Former Steel Mill Eyes OSW Future.)
Ørsted, which said it expects to begin commercial operations at Skipjack 1 in the second half of 2026, did not respond to multiple requests for comment as to when construction will begin.
US Wind, majority-owned by Italian renewable energy developer Renexia SpA, filed three applications to Maryland for ORECs — for 411.6 MW, 808.5 MW and 1205.4 MW. It said it would begin construction in 2025 and start commercial operations on the 411.5 MW in 2026.
US Wind’s Filippelli testified that Momentum Wind “represents up to $10.7 billion in industry output, nearly 2,000 full time jobs, and approximately $575 million in state and local taxes from construction through the 25-year operating life.”
Filippelli added that “for larger OREC 2 awards US Wind may also consider a much larger service operations vessel, requiring use of Baltimore or another port in addition to the Ocean City area, which is both space and water depth constrained.”
Democrats’ proposed Clean Electricity Performance Program (CEPP) is dead or on life support, doomed by Sen. Joe Manchin’s (D-W.Va.) opposition, according to numerous news reports over the weekend.
The CEPP, which would reward utilities that exceed emission reductions of 4% annually and penalize laggards, has been widely described as the “linchpin” of President Biden’s climate plan. News of its demise, coming just two weeks before the U.N.’s COP26 climate talks in Glasgow, had some environmentalists in despair.
But others said the $150 billion program would be bad policy and insisted its loss would not necessarily doom the Biden administration’s pledge to reduce U.S. greenhouse gas emissions to 50% below 2005 levels by 2030. They said efforts to decarbonize the power sector will continue, thanks to federal tax credits and supportive state policies.
“The CEPP is overshadowing the real star proposal”: about $300 billion to extend existing tax credits for utilities, commercial businesses and homeowners that use or generate electricity from zero-carbon sources, The Economistwrote.
CEPP: One-third of Reductions?
An analysis this month by Energy Innovation: Policy and Technology, an energy and environmental policy firm, said the most powerful emission-reduction provisions in the bipartisan infrastructure bill and the broader legislation Democrats hope to pass on party-line votes (referred to as the “infrastructure bills”) “is the combination of clean energy tax credits and the Clean Electricity Performance Program, which drives the power sector to 70 to 85% clean energy.”
The group said its modeling “underscores how important the CEPP is to achieving deep power sector decarbonization. Without it, emissions are likely to be 250 to 700 MMT higher per year in 2030, which could eliminate more than a third of the total emissions reductions under the infrastructure bills.”
“This is absolutely the most important climate policy in the package,” Leah Stokes, a climate policy expert advising Senate Democrats, told The New York Times, which reported Friday that CEPP was dead.
David G. Victor, co-director of the Deep Decarbonization Initiative at the University of California, San Diego, said both carrots (tax incentives) and sticks (penalties) are needed to clean up electric generation. “You need not just to deploy new stuff, but a way to retire old stuff,” he toldThe Wall Street Journal. “The combination of the two is key.”
The news had some proposing Hail Mary passes to save the program. “Time to make a deal with [U.S. Sens. Susan] Collins [R-Maine] and [Lisa] Murkowski [R-Alaska] to carve out the CEPP to get to 50 votes,” suggestedauthor Herb Simmens.
Manchin was unapologetic.
“Sen. Manchin has clearly expressed his concerns about using taxpayer dollars to pay private companies to do things they’re already doing,” Manchin’s office said in a statement. “He continues to support efforts to combat climate change while protecting American energy independence and ensuring our energy reliability.”
West Virginia Coal, Gas Ties
Many of those weighing in about CEPP’s demise on Twitter took note of Manchin’s financial and political ties to the coal and natural gas industries. West Virginia ranks second in coal and seventh in natural gas production among the 50 states. Enersystems, a coal brokerage Manchin founded in 1988 and now run by his son, represents 30% of his net worth. He reported $491,949 in dividend income from the company in 2020, 71% of his total investment income.
But others said Manchin had valid policy concerns.
“The media narrative that [Manchin] is single handedly blocking the president’s agenda is absurd and unfair,” tweeted former FERC Chair Neil Chatterjee. “There are FIFTY other U.S. senators who strongly oppose this legislation.”
“CEPP was a lucrative giveaway for utilities to consolidate their monopoly power and generouslyyyyy incentivize already cost-effective generation,” tweeted Maggie Clark, director of government affairs for Pine Gate Renewables, a North Carolina-based company that does project development and strategic financing of utility-scale solar and storage projects.
“A clean energy standard as traditionally designed is one thing. Crafting that policy to fit under reconciliation parameters led to progressives rallying around a government giveaway as the magic solution to climate change. Come on,” she said. “Clean energy wins on price today. The barrier to widespread adoption is inadequate infrastructure. Take every dollar away from CEPP and put it towards grid upgrades and then we’re getting somewhere.”
Others noted that in addition to the clean energy tax credits, the Democratic bill also includes $32 billion in tax credits to encourage the purchase of electric vehicles, $13.5 billion for electric car charging stations, $9 billion to update the electric grid and $17.5 billion to reduce carbon dioxide emissions from federal buildings and vehicles.
“Clean energy tax credits are nothing to sneeze at,” tweeted Robin Dutta, who works on market development and policy in the federal affairs staff of rooftop solar company SunPower. “And might be more effective than whatever CEPP could do.”
“Despite the attention paid to it, CEPP is actually less potent as a greenhouse-gas slayer than those boring tax credits, which are less controversial because they do not overtly penalize coal or gas,” The Economist reported.
“Two energy veterans, one at a top renewables lobbying outfit and the other at a fossil-heavy utility, agree that the tax credits would sharply boost investment in low-carbon technologies,” it said. “That is because they improve the current setup by replacing stop-go uncertainty with a predictable long-term tax regime and make tax breaks ‘refundable’ rather than needing to be offset against tax liabilities, meaning even utilities that do not have such tax liabilities can enjoy them as freely as cash in the bank.”
In addition, more than half the states are implementing their own climate policies. Twenty-six states, representing 61% of the U.S. economy, have joined the U.S. Climate Alliance, which was created after former President Donald Trump announced the U.S. would withdraw from the Paris Agreement.
CEPP Vital Signs Waning
The Times reported that Manchin, chairman of the Senate Energy and Natural Resources Committee, was considering a clean electricity program that would reward utilities for switching from coal to natural gas. But last week, it said, Manchin told the White House he was completely opposed to a clean energy program.
CNN reported that it will “likely be dropped,” and Bloomberg reported it had confirmed the Times’ report.
“Per a person familiar, while a final decision hasn’t been made, without Manchin’s support there isn’t a path forward for the climate program,” Bloomberg’s Ari Natter tweeted.
The Journalreported the program was “is in danger of falling out” of the Democrats’ bill.
The Washington Postreported: “White House officials have not decided to completely jettison the CEPP but are instead looking at how to make changes that would ensure Manchin’s support for the broader economic package.”
“It’s not dead yet, per people familiar, but it’s struggling to stay in the talks given Manchin’s opposition,” tweeted POLITICO’s Zack Colman, who reported Wednesday that Democrats and the White House were discussing ways to amend the CEPP to allow natural gas and coal power plants with carbon capture to participate. “The changes I reported Wednesday are part of what’s being explored to bring Manchin to the table, but this latest reporting suggests the needle hasn’t moved.”
Manchin has recently expressed doubts about the viability of carbon capture. “It’s so darn expensive that it makes it almost impossible,” he said last month.
Legislative Scramble as COP26 Approaches
Progressive Caucus Chair Pramila Jayapal told MSNBC on Saturday that “there’s no decisions that have been made. The negotiations are continuing.
“We understand that we have to get 50 senators on board and that Sen. Manchin obviously has a very big role to play on this,” she said. “We’re open to that negotiation as long as we have strong climate protections that bring down carbon emissions. That’s the discussion that’s under way right now.”
The Postreported Saturday that White House officials are “still looking at whether they can preserve the clean energy program by providing a way for coal and natural gas plants to keep operating for longer.” It said another idea being considered was a voluntary emissions trading system among aluminum, steel, concrete and chemicals manufacturers that would provide federal funding to help them reduce emissions.
Earlier last week, Special Presidential Envoy for Climate John Kerry suggested Biden’s position at the COP26 talks beginning Oct. 31 would be weakened by the lack of a climate deal with Congress. Failure to pass such legislation “would be like President Trump pulling out of the Paris Agreement again,” he told the Associated Press.
On Friday night, Biden called Kerry’s comments “a little hyperbole.”
“It’d be good to have agreement on the climate piece, but we’re going to get the climate piece,” he said.
Car manufacturers selling vehicles in states that follow California’s zero-emission vehicle regulations would be able to transfer ZEV credits among states under a new proposal from the California Air Resources Board (CARB).
The proposal is part of the Advanced Clean Cars II regulation, which CARB is developing as an update to Advanced Clean Cars rules now in effect. CARB staff discussed the proposal during a workshop on Wednesday.
Under the proposal, transfers between states would be allowed for ZEV credits generated in model years 2026 through 2030.
An automaker would be able to transfer credits earned in one state to another state after the credit requirement in the initial state is met. For model year 2026, transferred credits could be used to satisfy up to 15% of a state’s ZEV requirement. The percentage allowed would decrease each year, dropping to 10% in model year 2030.
Credits from model years 2025 and earlier would not be eligible for transfer, nor would credits from a newly proposed environmental justice ZEV credit.
CARB said the idea behind the credit transfer allowance is to provide “flexibility to address varying needs and circumstances” of the different states “by giving automakers flexibility in the early years while ensuring sales ramp up to levels needed to achieve the states’ climate and air quality goals.”
The ZEV program is one part of Advanced Clean Cars; the regulation also includes a low-emission vehicle program that sets standards for vehicle emissions.
The ZEV program requires car manufacturers to earn a certain number of credits each year by providing zero-emission vehicles, such as battery-electric vehicles or fuel-cell electric vehicles, for sale in the state. Sales of plug-in hybrid electric vehicles also earn credit.
The goal is to increase the availability of ZEVs to car buyers. Twelve states so far have adopted California’s ZEV program, and several other states may soon follow suit.
Durability Standards
Advanced Clean Cars II will also include durability requirements for ZEVs.
CARB has proposed a requirement for battery-electric vehicles and fuel-cell electric vehicles to be designed to maintain 80% of their range for 10 years or 150,000 miles. That’s a change from an earlier proposal for maintaining 80% range at 15 years or 150,000 miles.
To check compliance, CARB would have authority to procure and test in-use vehicles that haven’t had an “excessive” amount of fast-charging or vehicle-to-grid operation.
Another proposed requirement would set a minimum warranty period of eight years or 100,000 miles for batteries, with warranty failure occurring when the battery falls below 80% of “state of health.”
CARB staff acknowledged that more stringent durability requirements could lead to higher costs for ZEVs.
In addition, a number of factors outside a manufacturer’s control may contribute to range degradation, CARB staff noted. Those include a vehicle owner’s charging and driving behavior, average ambient temperature and battery age.
EJ Credits Modified
CARB staff is also fine-tuning a proposal for environmental justice (EJ) credits in the ZEV program. The agency introduced the concept of EJ credits during a workshop in August. (See CARB Plan Aims to Broaden Access to ZEVs.)
The proposal would provide EJ credits to automakers that sell electric vehicles at a discount to community programs offering services such as ZEV car sharing. As proposed in August, the level of discount required to receive a credit would be based on the manufacturer’s suggested retail price for the vehicle, maxing out at 25%.
CARB’s latest proposal simplifies the discount requirement, setting it to a minimum of 25% for any vehicle sold to a community program. The program must serve low-income or disadvantaged communities.
Another way a car maker could earn an EJ credit would be by keeping ZEVs in California after their lease expires, thereby increasing the state’s supply of used ZEVs. As proposed in August, the credit would be available only to zero-emission vehicles; CARB’s latest proposal now includes ZEVs and plug-in hybrid electric vehicles.
The new proposal also adds a requirement that the used car be registered to a qualifying low-income household in California.
An automaker could use the optional EJ credits to increase the number of ZEV credits they receive for a particular vehicle. EJ credits for a single vehicle would range from 0.2 to 0.5.
The EJ credits would be available for model years 2026 through 2031. An automaker could use EJ credits to meet up to 5% of their ZEV credit requirement in a year.
CARB is still collecting feedback on its Advanced Clean Cars II proposals. The agency expects to present a rulemaking package to the CARB board in June 2022.
The regulations are expected to take effect starting with model year 2026.
Participants at the final session of FERC’s technical conference on energy and ancillary services (E&AS) Tuesday agreed overall that market participation rules need to be revised to ease the entry of new and emerging resource types into the wholesale electricity markets (AD21-10).
“The panelists informed us of a lot about this incredibly complicated, challenging problem” of incenting new resources while maintaining grid reliability, concluded Emma Nicholson, an economist at FERC who helped moderate the day’s sessions. “We at staff are heartened by how many bright, smart people are analyzing this problem from different points of view so we can crowdsource some really good solutions here.”
The commission held the first session of the conference last month and now will likely issue a call for comments, she said. (See Flexible Ramping Grows as Ancillary Service.)
Revising RTO/ISO Market Models
Investors in new technologies such as storage resources, hybrid and co-located resources, aggregated distributed energy resources, and standalone variable energy resources want to be sure that the new assets will be able to offer their full operational capability in the market.
Emma Nicholson, FERC | FERC
On the other hand, RTOs and ISOs wrestle with the difficulty of adapting their market software and rules to accommodate such resources — an uncertainty factor — while fulfilling what many consider to be their primary responsibility of maintaining reliability.
There are two sides to the challenge of incorporating uncertainty into market software because providing electricity “is really preserving ramp capability from one interval to the next so that [it] can be available and deliverable in the next market run where uncertainty potentially materializes,” said George Angelidis, principal for power systems and market technology at CAISO.
The second aspect is coming up with a reasonable methodology for calculating the uncertainty requirement without tremendous effort because you have to do it constantly as the market runs to update the requirements, Angelidis said.
George Angelidis, CAISO | FERC
For Jinye Zhao, principal analyst for advanced technology solutions at ISO-NE, the first question is how to reduce the magnitude of uncertainties; in other words, how to reduce the problem size.
“Given that there are always uncertainties in the system, what solution strategies can we use to manage uncertainties?” Zhao said.
Erik Ela, program manager for the Electric Power Research Institute, gave his perspective on ERCOT, which is not under FERC’s jurisdiction. Day-ahead forecasts for load, wind and solar used by the Texas grid operator are currently only used in the reliability unit commitment (RUC) process. This is run after the day-ahead market, with a primary focus of committing sufficient resources that require a day-ahead notification time while minimizing commitment costs, so resources committed in the day-ahead market are not de-committed, he said.
Jinye Zhao, ISO-NE | FERC
“If for example the renewable forecast is higher than the renewable bids, it is often the case that the incremental energy costs are ignored or largely discounted so that only the commitment costs are of concern,” Ela said.
The value of improved forecasts depends on both the amount of renewables and thermal units in the system, said Bethany Frew, senior engineer at the National Renewable Energy Laboratory.
“We’ve seen consistently across different studies almost a transition zone where as you start to increase the amount of renewables on your system, specifically variable renewable resources like wind and solar, and you start to reduce the amount of thermal units in the system, there’s this transition beyond which commitment-related impacts can be diminished,” Frew said.
Erik Ela, EPRI | FERC
Specifically, start-up costs are one of the areas where NREL researchers see a lot of value in improved forecasts, but as thermal units are removed or they get retired in future scenarios, the value of those forecasts declines, she said.
“There’s really this interesting kind of interplay between what’s happening in the rest of the system and the forecast quality,” Frew said.
Arne Olson, senior partner at Energy and Environmental Economics, had multiple recommendations. First, market operators must develop scientific methods for determining the quantity of ancillary services needed based on continually changing grid conditions. The upward and downward reserve product should also be specified and procured separately. Wind and solar projects have asymmetric cost functions, which are only partly ameliorated when the services dispatch upward in real time, Olson said.
Bethany Frew, NREL | FERC
“Finally, and most ambitiously, we should look to market software to optimize the use of energy storage,” Olson said. “This is the most flexible resource available in the market, but its costs are entirely defined by market opportunities to buy low and sell high. As substantial quantities of storage are added, it will be increasingly important for market software to optimize its use.”
Ultimately, the ideal state at MISO would be to design and modify markets to remove barriers and create incentives for emergency-only resources such as load-modifying resources, said Laura Rauch, director of settlements for the RTO. “In particular, that long-lead emergency resources be committed and dispatched to market operations is a paradigm that enhances market efficiency for greater transparency.”
Arne Olson, E3 | FERC
SPP deploys an uncertainty response team that talks on a daily basis and looks at the amount of uncertainty that the grid operator projects it will have to deal with, “and then the bulk responsibility of this team is to recommend some amount of capacity of generation that needs to be online,” said Yasser Bahbaz, manager of reliability coordination for the RTO. “And these are all recommendations that are made out-of-market because we don’t have a product that specifically deals with density and uncertainty.”
NYISO has been doing a good job for 20 years reducing out-of-market commitments, said Liam Baker, vice president of regulatory affairs for Eastern Generation. “Because of all the market power rules in New York City, I have to offer most of my products at cost or at zero. So as an investor … I want to see accurate price formation,” Baker said.
System Flexibility
One panel discussed whether energy and ancillary service market participation rules need to be changed to ensure that resources have incentives to offer operational flexibility to the RTO and ISO markets.
Yasser Bahbaz, SPP | FERC
The panelists stressed the importance of system flexibility in the markets.
Nicole Bouchez, principal economist in NYISO’s market design department, said New York is focused on the wholesale energy products that are needed for reliability “in the face of an evolving resource mix.” At the same time, Bouchez said, NYISO is also attempting to ensure the “broadest set of resources possible” can participate in the markets.
Bouchez said NYISO’s structure of market rules are designed to increase the financial returns for resources that perform flexibly and reliably in the real-time markets and reduce compensation for inflexible resources. Co-optimization in the energy and ancillary service markets and not in the day-ahead and real-time markets, Bouchez said, causes the prices to “reflect the cost of systems” that provide ancillary services and provide compensation when a unit “would otherwise be providing energy.”
“This opportunity to sell different products also has the potential to encourage resources to make investments or modify operating practices to participate in those markets,” Bouchez said. “These investments can, however, be costly, which is why the focus on reliability and the products needed to maintain reliability is so important.”
Nicole Bouchez, NYISO | FERC
Joseph Daniel, manager of electricity markets and the climate and energy program for the Union of Concerned Scientists, stressed why he believes flexibility to be important. Daniel said flexibility boils down to “reliability and affordability” with a more flexible grid lowering costs for consumers and bringing reliability through new technologies.
Daniel said sometimes he finds it difficult to “disaggregate” some of the flexibility issues with what he calls “uneconomic behavior in the markets.” He said when he looks at the current rules governing the energy and ancillary services markets, he’s concluded that “most of today’s rules were written for yesterday’s resources” and all someone has to do to see the future is look at the generation queues of RTOs and ISOs to see the changing resource mix.
Joseph Daniel, UCS | FERC
Daniel said he’s encouraged by FERC orders 841 and 2222 that demonstrate the commission is “working to find ways to accommodate that inevitable wave of lower cost, more flexible resources.” But he said rules governing the commitment and scheduling of resources “tend to bias towards inflexible, long lead-time resources” and work against newer, flexible technologies.
“FERC should pursue market fixes to promote competitive resources and to offer in the full range of possibility,” Daniel said. “As we make these steps towards creating market rules that will promote flexibility, we should recognize the limitations to that and try to find ways to make sure the market rules objectives actually achieve what we’re solving for.”
Michael McLaughlin, director of FERC’s Division of Economic and Technical Analysis, asked, “Do any existing RTO/ISO energy and ancillary service market rules, requirements or procedures actually encourage resources to offer into the market inflexibly, and if so, what changes should be made?”
Catherine Tyler, Monitoring Analytics | FERC
Catherine Tyler, deputy market monitor for Monitoring Analytics, the Independent Market Monitor for PJM, said the way McLaughlin’s question was framed is “not quite the right” one. Tyler said stakeholders shouldn’t be worried whether resources offer flexibly but instead focus on the “need” for resources to perform flexibly.
Tyler said PJM rules require offering flexible parameters, including must-offer requirements in energy and reserve markets. She said there’s “plenty of flexibility on paper,” but there’s a “general lack of accountability” when it comes to performing flexibly in the markets. For example, there are no repercussions in the outage or uplift rules for failing to meet must-offer requirements. A potential solution would be penalties based on capacity market prices, which are paid for meeting certain performance standards.
“The market needs to account for the performance of the resources,” Tyler said. “Customers pay a premium for capacity that is meant to meet performance standards.”
Emerging Resources
Panelists discussed some of the issues keeping new technologies from entering and flourishing in markets.
Jason Burwen, ESA | FERC
Jason Burwen, interim CEO of the Energy Storage Association, said one of the early lessons with the development of energy storage technology is that flexible storage is running into market processes that are not providing “commensurate operator control” and weren’t written with that technological capability in mind. It’s important for the commission to take a “wide view” on the paths forward on potential market rules to “continue to ensure policy keeps up with technology” and not allow technology limitations “constrain our future.”
“The grid of the future will need more flexible, fast-starting resources, and we need to make sure that we reflect the cost of a lack of performance meeting that,” Burwen said.
Aaron Siskind, an economist with FERC, asked whether existing RTO/ISO energy and ancillary services market rules, practices or procedures prevent or otherwise obstruct relatively new and emerging resource types, such as variable, hybrid and storage, from fully participating in RTO/ISO markets and offering the operational flexibility they are capable of providing from a technical standpoint.
Walter Graf, PJM | FERC
Michael DeSocio, director of market design for NYISO, said the current market structure is “built to reward those that can move quickly, follow dispatch instructions closely and be responsive to emerging grid needs.” To be prepared for the continuing energy transition and the grid of the future, stakeholders need to “think more broadly” on solutions for market structures to ensure resources continue to respond to grid needs and operator instructions. He said there is also “a need to provide additional information more frequently” by resources submitting more data to the RTOs and ISOs for more efficient operations.
“This promotes improved efficiency and better price formation,” DeSocio said. “All of these pieces and parts are important.”
Walter Graf, senior director of economics for PJM, said the objective should not be to maximize operational flexibility but to “incentivize the efficient level of operational flexibility across all resources.” PJM is behind other areas in the country in respect to the penetration of emerging and intermittent technologies, giving it the “benefit” of having more time to address market design deficiencies “before they become problems.”
Graf said PJM “continues to believe in the ability of the competitive market to signal value through prices” and the ability of market participants to best make decisions. Graf said incentivizing flexibility and ensuring that sufficient flexibility is available when needed is the role of the energy and ancillary service markets.
“PJM believes that operational needs should guide the design of needed services and should not be compromised to accommodate resources that are unable to comply,” Graf said. “That said, there are cases where value can be unlocked or enabled without compromising operational requirements.”
The New York State Climate Action Council met Thursday to discuss an integration analysis toward shaping its final scoping plan by year-end to help reach the environmental goals outlined in the state’s Climate Leadership and Community Protection Act (CLCPA).
NYSERDA CEO Doreen Harris | NYDPS
“While we will see results based on a few key scenarios … these scenarios have been designed to bound the analysis and certainly not to set up an either-or situation where we pick our favorite scenario,” said Doreen Harris, CEO of the New York Energy Research and Development Authority (NYSERDA) and Council Co-chair.
The analysis provided by state agencies and consultancy Energy and Environmental Economics (E3) “is essentially yet another input and will provide an important point of reference as we head into 2022, and I fully expect that over the next year, once the draft scoping plan is issued, we will continue to discuss and debate the various strategies, challenges and tradeoffs that advance us to our goals,” Harris said.
The 22-member council aims to hold public meetings throughout 2022 before releasing a final plan in 2023.
Low-carbon Focus
The scenarios discussion focused on the strategic use of low-carbon fuels and an accelerated transition away from combustion.
Carl Mas, NYSERDA | NYDPS
“The strategic use of low-carbon fuels will achieve a system predominantly based on a grid that is wind, water and sunshine,” said Carl Mas, director of energy and environmental analysis at NYSERDA.
New York will have a heavily electrified system that includes strategic use of bioenergy, mostly derived from biogenic waste and agricultural residues, forest residues, and a limited amount of purpose-grown bioenergy as well as green hydrogen juxtaposed against that, Mas said.
The state is looking to limit and, in some cases, have no combustion, so no bioenergy combustion and no hydrogen switching to fuel cells where hydrogen might be used for long duration storage and the flow of new technologies that may come, he said.
“As a response we’ve had to accelerate our electrification and energy efficiency, so we’ll see how those play out both in terms of different health impacts and different cost structures,” Mas said. “We set the bar of trying to more comprehensively look at health than anyone has in the past, and I think we have succeeded.”
Bob Howarth, Cornell University | NYDPS
The building sector is now getting closer to the 40% reduction in greenhouse gas emissions from 1990 levels that the CLCPA calls for by 2030, but transportation is still at around 27%, said Bob Howarth, professor of ecology and environmental biology at Cornell University. He asked what more the state can do to push that sector even harder.
Transportation takes more time partly because of where the sector is today, which is an actual increase since 1990 that’s unmatched in any other sector, Mas said.
“Our grid has gotten much cleaner since 1990,” Mas said. “Our buildings have actually gotten better over time, and transportation has gotten more efficient, but we’ve just been driving more, and we’ve been driving bigger, so there’s a higher mountain to climb for transportation.”
Building Stock Turnover
There could be a lot of things that need to change, and consumers need to have incentives to change, said Gavin Donohue, president and CEO of the Independent Power Producers of New York.
IPPNY CEO Gavin Donohue | NYDPS
Does the state believe that the models being put in place “are going to be adequate to make those consumer changes, or are we going to need a whole new suite of additional regulations and laws to make that change workable?” Donohue asked.
Mas turned the question back to the Council: “That’s what this deliberative body needs to discuss and debate. How are we going to do this and what structures do we have in place, and can we expand those existing structures?”
For electrifying the building sector, the state has a very gradual ramp-up and then a more accelerated path after 2025. That pathway represents about 5% per year of New York’s building stock of around 8 million households, but that is not the key statistic, Mas said.
New construction is really a small percent of the turnover of the “huge built environment,” he said, adding that retrofitting existing buildings is very important, and that usually happens when a building changes hands.
The model includes an assumption of the opportunity space and the opportunity timing, according to Mas.
The New York State Climate Action Council met virtually October 14, 2021 to discuss integration analysis scenarios. | NYDPS
“What you see predominantly happening for the first couple years is that any existing turnover of gas systems [for residential heating] is to a more efficient system, but pretty quickly by 2024-2025 we’re starting to see the bending of the gas curve as well,” Mas said.
It will be an efficient electrification process, Mas said. “So when you’re working with a customer, you’re not just necessarily only switching out a furnace, but taking that opportunity to also look at upgrades.”
The operator of Hawaii’s only geothermal plant is working to bring the facility back to full capacity after it was shut down by a volcanic eruption three years ago.
Ormat Technologies subsidiary Puna Geothermal Venture (PGV) discussed its efforts to ramp up its geothermal plant on the Big Island during a public meeting Wednesday.
When running at its full 38 MW of capacity, the PGV plant accounts for about 30% of the Big Island’s renewable energy.
The plant was shut down in 2018 when an eruption from the Kīlauea volcano caused a lava flow that destroyed access roads and several sections of the plant. The company repaired enough of the facility to bring it back online last November, but at limited capacity.
“Currently the plant is producing 25 to 26 MW,” Zachery Adachi, PGV operations supervisor, said during the meeting. “We have nine of 11 [Ormat energy convertors] online right now. Out of the two that are down we have one that is down for annual maintenance,” while the other unit is “still under recovery from the whole lava event.”
Adachi noted the company is “just waiting on parts” for the energy converter still under recovery and expects it to be operational “in a month.”
Responding to a question from a community member, Ormat Senior Director of Hawaii Affairs Michael Kaleikini said that PGV has no construction plans for the next few months but will be performing maintenance on its KS5 production well that is still covered by lava.
Kaleikini explained that one reinjection well had also been covered by lava. “We checked the mechanical integrity, received all the proper approvals to use it again, and it’s back in operation. So we’re crossing our fingers that KS5 will be available for use in the near future.”
Kaleikini also pointed to the value of geothermal energy relative to solar energy, saying, “The solar farms with battery storage do contribute to the state’s mandate, but their technology is not available 24/7 like geothermal.”
Other community questions centered on the safety of the plant and if damage caused by the eruption will cause any unwanted emissions of hydrogen sulfide, a toxic volcanic gas. Kaleikini said that PGV is a closed-loop facility, meaning it does not have “continuous emissions of hydrogen sulfide” and thus should not pose a threat. He also explained that PGV is responsible for notifying the state of any dangers.
PGV and Hawaiian Electric Light Co., a subsidiary of Hawaiian Electric Co., are currently negotiating an amended power purchase agreement to increase the facility’s capacity from 38 MW to 46 MW. According to an Oct. 8 letter from PGV to the state’s Office of Planning, the amended PPA will also allow PGV to “enhance its operational efficiency” so that it can “displace annually approximately 10 million gallons of fossil fuel.”
Those efficiency gains would consist of replacing the plant’s 12 existing generating units with three newer, more efficient units that will “use the same amount of geothermal resource as is currently used.”
Below is a summary of the issues scheduled to be brought to a vote at the PJM Markets and Reliability Committee and Members Committee meetings on Wednesday. Each item is listed by agenda number, description and projected time of discussion, followed by a summary of the issue and links to prior coverage in RTO Insider.
RTO Insider will be covering the discussions and votes. See next Tuesday’s newsletter for a full report.
Markets and Reliability Committee
Consent Agenda (9:05-9:10)
B. Stakeholders will be asked to endorse the 2021 reserve requirement study (RRS) results for the installed reserve margin (IRM) and the forecast pool requirement (FPR). The study was unanimously endorsed at the Oct. 5 Planning Committee meeting. (See “Reserve Requirement Study Endorsed,” PJM PC/TEAC Briefs: Oct. 5, 2021.)
D. Members will be asked to endorse proposed revisions to Manual 15: Cost Development Guidelines, the Operating Agreement and the tariff to address incremental and no-load energy offers. The Cost Development Subcommittee proposed revising the no-load cost and incremental energy offer definitions to clearly define what costs can be included, including operating costs, tax credits and emissions allowances. (See “Manual 15 Revisions Endorsed,” PJM MIC Briefs: Sept. 9, 2021.)
E. Stakeholders will be asked to endorse the proposed solution and manual revisions to address the calculation of the energy efficiency add-back in Reliability Pricing Model auctions. The proposal, which called for modified language to section 2.4.5 of Manual 18 to reflect revisions to the EE add-back method, was endorsed at the Oct. 6 MIC meeting. (See “Energy Efficiency Add-back Endorsed,” PJM MIC Briefs: Oct. 6, 2021.)
Endorsements (9:10-10:55)
1. Resource Adequacy Senior Task Force Charter (9:10-9:35)
The committee will be asked to approve the proposed charter to create a new senior task force to discuss topics related to resource adequacy listed in an April 6 letter from the Board of Managers and to recommend possible changes to the capacity market. (See “Resource Adequacy Charter,” PJM MRC Briefs: Sept. 29, 2021.)
3. Undefined Regulation Mileage Ratio Calculation (9:35-10)
Members will be asked to endorse PJM’s proposal to change the undefined regulation mileage ratio calculation in Manual 28 and the tariff. The proposal will also be voted on at the MC meeting on the same day. If the proposals fails, stakeholders will be asked to vote on a separate proposal from the Independent Market Monitor. (See “Regulation Mileage Ratio Calculation Endorsed,” PJM MIC Briefs: Sept. 9, 2021.)
4. ARR/FTR Market Task Force Update (10-10:35)
Stakeholders will be asked to endorse a joint PJM-stakeholder proposal with corresponding manual and tariff revisions to address the RTO’s auction revenue rights and financial transmission rights. The proposal was endorsed at the October MIC meeting. (See “ARR/FTR Market Task Force Proposal,” PJM MIC Briefs: Oct. 6, 2021.)
5. Max Emergency Revisions (10:35-10:55)
The committee will be asked to endorse proposed revisions to Manual 13: Emergency Operations addressing the maximum emergency category. Stakeholders are being asked to endorse the revisions upon first read.
Members Committee
Endorsements (1:45-2:55)
1. Initial Margining Solution (1:45-2:15)
Stakeholders will be asked to endorse proposed tariff revisions on rules related to initial margining that close out the work of the Financial Risk Mitigation Senior Task Force (FRMSTF). A joint proposal from Perast Capital and Duke Energy was endorsed at the September MRC meeting after hours of debate. (See PJM Stakeholders Endorse Initial Margining Proposal.)
3. Manual 34 Revisions (2:35-2:55)
The committee will be asked to approve proposed revisions to Manual 34: PJM Stakeholder Process addressing the inclusion of forums as a stakeholder body. The revisions were originally discussed at the Stakeholder Process Forum and presented for a first read at the September MC meeting. (See “Manual 34 Revisions,” PJM MRC/MC Briefs: Sept. 29, 2021.)
Massachusetts Energy and Environmental Affairs Secretary Kathleen Theoharides (center) speaks on a panel with Kevin Ewing of Bracewell (left) and Scott Lundin of Equinor during the American Clean Power Association’s Offshore WINDPOWER 2021 conference last week in Boston. | © RTO Insider LLC
