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November 8, 2024

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Hydrogen: ‘Holy Grail’ or Rabbit Hole?

The gulf between the promise of hydrogen and the technology to make enough of it to help safely decarbonize power grids, industry and transportation in just a few decades is a challenge just now coming into public focus.

The outline of the potential dilemma emerged quickly during the Sept. 30 Future of Green Hydrogen webinar organized by the Environmental Business Council of New England

The virtual conference featured a policy and economic analyst, a hydrogen safety expert and a university researcher focusing on hydrogen as a potential pipeline fuel.

Speakers represented companies already investing in hydrogen technologies, including Toyota, (NYSE: TM), National Grid (NYSE: NGG) and Plug Power (NASDAQ: PLUG), who described their efforts to harness hydrogen’s potential.   

Paul Hibbard, principal at the Analysis Group, said green hydrogen has the potential to be “the Holy Grail of civilization,” as nations urgently work to reduce carbon emissions to net zero by 2050.

“It’s not going to be easy,” Hibbard stressed. “The transition timelines that we’re talking about are completely inconceivable relative to the pace of change that we’re used to in the sector. And the technological solutions for decarbonization are not readily apparent.” 

“Why are we focusing on hydrogen? In my view, being completely honest — and it’s not the sort of thing you want to say in public — it’s because it looks like a fossil fuel. When you think of all the potential decarbonization solutions that are being discussed, a lot of them don’t really look like the world we currently live in. Hydrogen absolutely does.”

Hibbard said a lot of the decarbonization will be based on electrifying automobiles and trucking, switching to heat pumps for heating and cooling in new construction, and moving toward a “potential trade-out of existing heating technologies” in existing homes and buildings.

“When you look at what the states are proposing and what’s in the pipeline from a decarbonization perspective in the electric sector … [you see] rapid increases in the demand for electricity on the one hand and changing the shape of electricity demand on the other as the sector acts as something of a sponge for greenhouse gases and transportation and building sectors,” he said. 

In other words, that decarbonization scenario relies heavily on the electric grid, and one based primarily on renewable generation.  And that’s the problem.

“That will significantly change the demand profile, and within 10 years the New York-New England region will become a winter peaking system, meaning power demand will peak when solar generation is out of the picture.” Offshore wind and imported Canadian hydropower and storage would be crucial in this scenario, he added.

The harder question to answer, Hillard said, will be whether the regional grid could meet the growing demand “without some form of thermal generation to back it up,” such as gas turbines burning hydrogen or fuel cells generating power by combining hydrogen with oxygen in ambient air. 

Safety First

Then there is the question of learning how to handle hydrogen safely.   

Nick Barilo, executive director of the Center for Hydrogen Safety at the American Institute of Chemical Engineers, said hydrogen as a general use fuel poses significant problems.

Citing accidents over the decades, including the Challenger space shuttle explosion in 1986, Barilo said the industry has developed strong safety protocols but that the public has no experience with hydrogen and plenty of misconceptions.

“Some of the things that we have run into so far are apathy, fear and the general misconception that it’s just like any other flammable gas,” he said.

But hydrogen has no color, is flammable at a wider range of temperatures and lower concentrations than methane and propane, and burns with a pale blue flame that is hard to detect, said Barilo.

Another problem that many may be unaware of, he said, is that the industry does not yet have a good “odorant” to add to hydrogen as it did to natural gas decades ago.

“The key for safety … [is] that it’s like any other flammable gas. You need to identify and eliminate those hazards and find mitigation measures,” Barilo said. “System integrity is critical. It’s a small molecule so that becomes even more important. Proper ventilation is a key to safety. And then managing discharges, detecting, and isolating leaks and not the least of which is training personnel. … There are a lot of things to think about.”

Devinder Mahajan, director of Stony Brook University’s Institute of Gas Innovation and Technology, said “there is a pretty solid foundation to move to hydrogen power … using methane in the mix.” 

Mixing green hydrogen with methane, presumably to feed gas turbines, “basically addresses the intermittency of power generation from renewables,” he said. 

The major challenge will be developing the technologies to lower the cost of producing hydrogen through electrolysis and then moving the gas to where it is needed.

Using the nation’s existing gas lines is one of the keys to an economical transition away from methane to hydrogen, said Mahajan. 

“Do we just abandon this $1 trillion infrastructure that is already in place by not using any gas or can we repurpose this infrastructure for hydrogen?  I think that is the question, and I think there is a fairly simple no-brainer answer. Why would you abandon a $1 trillion infrastructure that the public paid for, and just say let’s go on to something else that we don’t know anything about?”

As for hydrogen’s destructive impact on existing natural gas lines, Mahajan said federal labs and his institute have been working on detection technologies to enable utilities and pipeline companies to develop an early enough warning of such leaks to make a “business decision” about using an existing line.

No Silver Bullet

One company with some experience moving hydrogen is National Grid, which sees hydrogen as a “zero-carbon energy carrier” rather than a fuel.

“The decarbonization train is leaving the station, and hydrogen is definitely one of the engines,” said Christopher Cavanagh, and engineer with National Grid.

“We have a high degree of confidence that hydrogen can be safely blended with natural gas today. There may be changes, and we’re trying to figure out what exactly those are now. And we are not the only ones proposing this. 

“Our experience with hydrogen has been pretty substantial. We produced hydrogen as part of our synthetic natural gas production during the energy crunch in the ’70s and ’80s,” said Cavanagh. 

The most important question, he said, is how green hydrogen will be sourced.  “We’re going to produce hydrogen onsite in a distributed manner, from either onsite renewables or from purchased renewable power.

“New York state is supporting that, but it’s also supporting new centralized hydrogen production facilities,” he added.

Plug Power, a N.Y.-based fuel cell company that also builds hydrolysis equipment to make hydrogen, announced in February that it would build a plant in western New York to produced 45 metric tons of liquefied green hydrogen a day. 

Swarna Arza, vice president and operations general manager at Plug Power, said her company’s vision for the future is one “where we create the energy, we store the energy, and then when we have a downtime, we can use that same energy … and create the electricity that can substitute for any intermittent energy sources like wind.” She said Plug Power’s hydrolysis technology under development produces significantly more hydrogen than standard hydrolysis equipment. 

Plug Power is working with Toyota on a hydrogen project in California, Arza said. 

Refueling a hydrogen fuel cell car takes 5 minutes. | Toyota

Toyota, unlike major U.S. automakers, is already producing and selling fuel cell cars. In the U.S., Toyota’s Mirai fuel cell model is available in California, where 52 hydrogen refueling stations have been built.  Refueling time is five minutes.

Jacquelyn Birdsall, a senior engineering manager with Toyota’s fuel cell integration group, said the company’s goal is to reduce the CO2 emissions of its fleet 90% by 2050 compared to 2010 levels and that fuel cells vehicles are part of the strategy to accomplish that.

“Toyota believes in what we call a portfolio of solutions. I think that you’ve heard this from other members [today] as well. There’s not really one silver bullet; there’s not one great solution. It takes a combination of all [technologies].  
 
 “For us, that means hybrid, plug in hybrid, battery electric and fuel cell electric, she said.

Toyota’s progress at moving from gasoline to electric vehicles might be seen as an example of the road ahead for the massive electrification goals of industrial nations around the world. It will be expensive and take time.

Birdsall pointed to the Prius hybrid as a starting point. Introduced in 1997, Prius sales were initially slow, taking 10 years for the first one million sales. Today, Toyota sells 1.5 million hybrids annually around the globe.

“We sell more electrified vehicles than the rest of the auto industry combined,” she said. Toyota and Kenworth built 10 heavy-duty fuel cell trucks for use in California ports. | Toyota

Sales of Toyota’s Mirai, first introduced in 2014 and updated this year, have been slow. And the company more recently built 10 fuel cell electric Class 8 heavy-duty semi-trucks with Kenworth, each equipped with a 560-horsepower electric motor, Birdsall said. The trucks can haul 80,000 pounds and have a 300-mile range between fill-ups. They are in operation around the ports in Los Angeles.  

“We use about 10 times the amount of hydrogen in a truck that we do in a light-duty vehicle. So that increase in the fuel demand is driving down the cost of the hydrogen,” Birdsall said.

“However, in order to get the cost of the trucks themselves down, we need the volume of the fuel cell stacks, which comes from the light-duty market. So, we need to sell the light-duty vehicles as well to build more hydrogen … fuel cell stacks to drive down the cost of the technology itself.”

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California Can Get By Without More Gas, Energy Commission Says

The California Energy Commission adopted a midterm reliability analysis Thursday that determined the state can meet its 2023-2026 capacity needs without adding more gas generation but warned that extreme weather and the state’s dependence on battery storage could prove problematic.

“The analysis concludes that, given the assumptions, it appears that sufficient capacity has been ordered for midterm reliability from 2023 through 2026,” Liz Gill, advisor to CEC Vice Chair Siva Gunda, told commissioners. “However, additional retirements [of aging natural gas plants] would increase the likelihood of system reliability challenges.”

The analysis did not “capture the frequency and dispersion of extreme climate events” or the higher demand from electrification of the transportation and building sectors, Gill said. The CEC is working to include those factors in future analyses, she said.

The second conclusion of the analysis was that “a portfolio of zero-emitting resources can provide the equivalent system reliability compared to fossil fuel resources,” but lithium-ion battery performance must be monitored as storage plays a larger role, she said.

The vote on the midterm reliability analysis followed two CEC workshops on Aug. 30 that examined the role of natural gas in the energy mix through 2026 as the state’s last nuclear plant retires, older gas plants close, and the grid relies more heavily on renewables and storage. (See CEC Looks at Gas for Midterm Reliability.)

The CEC’s demand forecasts inform procurement decisions by the California Public Utilities Commission.

In June, the CPUC ordered utilities to procure an additional 11.5 GW of capacity by mid-decade but intentionally left open the question of whether more gas generation is needed. (See CPUC Orders Additional 11.5 GW but No Gas.)

A proposed decision by a CPUC administrative law judge said the state needed up to 1,500 MW in additional gas capacity, but CPUC commissioners rejected that component amid a public outcry. (See CPUC Proposes Adding 11.5 GW of New Resources.)

“The revised [proposed decision] that we’re voting on today removes the requirement to procure any fossil resources, and instead our staff will work with the Energy Commission staff to conduct additional analysis over the next few months about the need for fossil resources for reliability purposes,” CPUC Commissioner Clifford Rechtschaffen said at the time. “The results of this analysis from our staff and the Energy Commission will help inform our next procurement decision, which we will debate about later this year.”

Thursday’s analysis found the CPUC’s 11.5 GW no-gas procurement order was sufficient to ensure reliability through 2026. Under the order, the state is expected to add 10 GW of four-hour battery storage, 8.3 GW of solar capacity, 2.5 GW of wind, 1.2 GW of geothermal power and 1 GW of long-duration storage.

Concerns have been raised that the international supply chain for battery production might not support the projected growth, Gill said. The analysis applied a one-year delay to 20% of new battery resources and found that it did not undermine reliability, she said.

Battery Performance

The analysis also raised the issue of battery performance, including charging and outages.

Battery outage rates need more analysis as the technology is deployed, Gill said.

A Sept. 4 outage at Vistra Energy’s Moss Landing Energy Storage Facility, the world’s largest battery array at 400 MW, pointed to one potential flaw in lithium-ion batteries: overheating. Initially the incident was blamed on high heat and fire, but Vistra said in a Sept. 30 statement that it has so far found no evidence of batteries exceeding acceptable temperature limits when its sprinklers went off, damaging a small percentage of units.

The CEC projects a 12,000 MW increase in battery storage from 2022 to 2026. | California Energy Commission

Limitations on imports, solar and hydropower could affect charging conditions, Gill said.

The analysis looked at scenarios in which imports were limited by up to 5,600 MW, hydropower was limited to average minimum generation during non-peak hours, and solar was reduced by 15% to 45% to reflect cloudy or smoky conditions.

The CEC analysts found there was sufficient capacity on the grid until both imports and hydropower were constrained and solar output dropped by 45%.

“Given the extreme nature of this scenario, staff has determined that it does not appear energy sufficiency will be a limiting factor to system reliability in the next five years,” Gill said.

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Slow Progress of NJ Community Solar Pilot Draws Fire

Solar developers are increasingly concerned that the New Jersey Board of Public Utilities (BPU) has yet to announce the winning applicants of the state’s second community solar pilot program, eight months after the submission deadline. But the BPU says it is simply coping with the “massive undertaking” of reviewing more than 400 complex applications.

Solar developers and representatives of the Coalition for Community Solar Access (CCSA) and Solar Energy Industries Association (SEIA), two national advocacy groups, told a public hearing on Sept. 28 that the BPU’s failure to announce the winners is putting submitted projects in jeopardy.

Developers that lined up rooftops and signed contracts to apply for the program are struggling to keep their partners on board, with little information from the BPU to calm partner concerns, the industry representatives said. That’s compounded by the fact that BPU has said nothing about whether the second phase will be succeeded by a third pilot phase, a new permanent community solar program, or something else, the representatives said.

The BPU announced in May that it had received 410 applications totaling 800.5 MW by the Feb. 5 deadline —  more than five times the 150 MW that the agency expects to allocate in the second phase.

The number of applications in the second phase is about 60% more than the 252 applications received in the first phase of the program, in which 45 applications were approved for a total of 78 MW. (See Billing Key to NJ Community Solar Growth.) The BPU announced the winners of the first phase in December, about three months after the submission deadline.

BPU spokesperson Peter Peretzman said the program remains on track despite the difficulty of handling the surge in applications.

“There is no delay in the program,” he said. “But rather the review process has taken a significant amount of time and resources due to the number, size and complexity” of the applications, he said.

“We understand the issues the industry brought up and appreciate the urgency. We will provide more information as soon as it’s available,” he said. “We appreciate the strong interest we have received from those who applied, and we expect the board to consider project approvals this fall.”

Expiring ‘Roof Rights’

Speaking at the BPU meeting, Leslie Elder, CCSA’s mid-Atlantic director, encouraged the BPU to announce the awards “as soon as possible” and said there is an “urgent need to bring clarity, predictability and focus to the community solar program.”

The delay has already resulted in some property owners, who had agreed to participate, informing the developer that “their roof rights have expired and that they’re going to be moving on,” she said.

“All contracts have strict timelines that have to be met between the developers and the landowners,” she said. “The uncertainty in awards and what’s next in the community solar program is making it extremely difficult for us to meet those needs.”

Elder said that the organization understands that “the community solar pilot program has experienced both programmatic and administrative delays, which tends to happen [with] a new initiative, let alone when there’s a global pandemic happening.” But she said, “there are growing concerns about the announcement of pilot year two awards.”

Kaitlin Hollinger, a policy manager of Boston-based developer BlueWave, echoed the need for clarity and encouraged the board to address the “urgent concerns within the community.”

Annika Colston, founder of AC Power, a New York City-based solar developer, suggested the BPU provide a timeline on how the program will proceed.

“A great deal of work is completed prior to submission of applications, including partnerships with various stakeholders, such as township governing bodies, local planning boards, community and workforce development partners, property owners, and ratepayers,” she said. “A great deal of goodwill is shared, and commitments are made in an effort to submit the strongest application possible.”

She said the lack of certainty “has reduced the credibility of the program” among her company’s partners.

‘Certainty’ on the Way

The industry’s frustration emerged at the latest of a series of quarterly meetings set up by the BPU— with no set agenda — that are designed to give members of the public and business community a chance to air their views on BPU issues and activities.

Board President Joseph L. Fiordaliso acknowledged the industry’s need for a predictable future and told those at the meeting that “certainty is coming down the line.”

“We are very, very conscious of the industry’s anxiousness regarding certain aspects” of the pilot, he said. With more than 400 applications, it “takes time to evaluate each one individually, diligently and prudently,” he said.

Fiordaliso said he couldn’t say when the awards would be announced but added that the BPU staff is “working extremely hard,” including on improving the “transparency” of the process.

Scott Elias, senior manager of state affairs for SEIA’s Mid-Atlantic region, said the uncertainty is already making it difficult for developers to plan.

“There’s ongoing questions and concerns amongst the industry as to whether a permanent program will be up and running in time to avoid the need for a third year of the pilot,” he said.

Joe Henri, vice president of policy for developer Dimension Renewable Energy, encouraged the board to avoid “putting your staff in a position where they become a bottleneck in a program.”

He said that “month after month” his stakeholders ask what is happening with the project, and “we have to keep telling them that it’s going to be a little bit longer.”

Fear of Interconnection Delays

Fred DeSanti, executive director of the New Jersey Solar Energy Coalition, which represents 27 companies involved in solar development, said the industry is also concerned about utilities’ ability to respond to increasing demand for solar. He urged the BPU to provide more flexibility to account for back-ups in the interconnection process.

With 15,000 projects totaling 1.2 GW ready to be built, DeSanti said he feared that the electric distribution companies (EDC) don’t have the staff to connect them all before the project permits expire.

“We are becoming very concerned that a significant mismatch of resources is beginning to take shape,” DeSanti said. He speculated that only a third of the projects in the state’s Transition Incentive Program will begin commercial operation unless EDC interconnection resources are dramatically increased.

The state stipulates that solar projects have 12 months from BPU approval to get connected to the grid.

He suggested that the BPU take steps to match the volume of projects waiting with the EDCs’ capability to handle them and automatically grant extensions if projects are delayed for reasons out of the developers’ control.

“This would add a great deal of stability and order to the process of providing EDCs with an appropriate planning tool and help relieve anxiety on the part of investors and developers to continue to fund project construction,” DeSanti said.

Francis G. Tedesco, a spokesperson for Atlantic City Electric, said the company continues to invest in and adopt “new grid modeling tools and grid automation technologies as they become available, which allow us to optimize the system and make us better able to accommodate increasing amounts of solar.” That’s enabled the company to increase interconnections, he said.

“However, even with more sophisticated technologies and tools, physical upgrades to increase the capacity of the local energy grid will be required to accommodate the significant growth of solar we expect to see in the coming years,” he added. The company is working with the BPU and other stakeholders to “identify the most efficient and fair path forward to expand capacity on the local energy grid to create new opportunities for solar.”

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RGGI Centers Environmental Justice in 3rd Program Review

Environmental justice is taking center stage in the latest Regional Greenhouse Gas Initiative (RGGI) program review now underway.

“[Participating RGGI] states recognize there are challenges related to environmental justice and equity and challenges faced by overburdened and underserved communities, and we commit to listening and better understanding how those issues can be addressed,” Valerie Gray, program administrator at the Delaware Department of Natural Resources, said on Tuesday.

Justice and equity considerations were among the topics that RGGI sought input on during a public engagement session for the program’s third review since its launch in 2009.

During the session, Phelps Turner, a senior attorney at Conservation Law Foundation Maine, called on RGGI to allocate at least 70% of program investments to overburdened communities and to conduct equity-specific analyses.

“The program should conduct equity analyses to show prior investments and demographics of beneficiaries of RGGI investments and to show what power plants have emissions increasing or decreasing and the demographics of impacted residents and workers,” Turner said.

While RGGI has delivered many benefits, such as clean air and energy savings, “the program falls short when it comes to ensuring that those benefits are equitably delivered,” Jordan Stutt, carbon programs director at Acadia Center, said during the session.

Some participating states, he said, have “laudable” equity measures in place already, but the program should ensure that environmental justice policies are required for all its jurisdictions.

“In the same way that the model rule requires certain critical program elements to be implemented consistently across the region to ensure effective program operation, baseline measures to ensure equitable outcomes must also be required at the regional level,” he said.

The public input session will help RGGI develop an update to its model rule, which is the base of the legislation and regulations that each of the 11 program states developed to authorize their participation. RGGI states include Connecticut, Delaware, Maine, Maryland, Massachusetts, New Jersey, New Hampshire, New York, Rhode Island, Virginia and Vermont.

Pennsylvania and North Carolina are both in the process of becoming participating states.

Pennsylvania could begin participating sometime in 2022, according to Brian Woods, an environmental analyst with the Vermont Department of Environmental Conservation. North Carolina is farther behind Pennsylvania in the process to adopt RGGI regulations, so the state likely would not begin participating any sooner than 2023, Woods said.

Emissions Cap

RGGI completed its first program review in 2013 and its second in 2017, according to Lois New, a representative of the New York State Department of Environmental Conservation.

After the first review, she said, the states reduced the program’s regional emissions cap from 165 million tons in 2013 to 91 million tons in 2014 to better align with current emissions. Following the second review, the states committed to a continued emissions cap decline of 30% from 2020 to 2030. The cap bounced back up after New Jersey reentered the program and Virginia started participating at the beginning of this year.

The current emissions cap is now at 119.8 million tons, and that decreases by 3.7 million tons per year through 2030. Three RGGI auctions this year have resulted in $574 million in revenues for participating states, and the last auction of the year is scheduled for Dec. 1.

RGGI sought input during the public comment session on the trajectory of the cap before and after 2030.

Rapidly changing climate policies and scientific data on climate change point to a need to design the trajectory of the cap to reach zero emissions by 2035, Turner said.

Chris Phelps, state director of Environment Connecticut, agreed that the update should include a commitment to the cap declining to zero, but he did not support a specific target date.

That commitment, he said, would ensure that the emissions cap aligns with the ambitious climate mandates many states in the region have put into law.

Review Timeline

RGGI states are working now to develop assumptions for an integrated planning model that will inform a base case for the program review, according to Rupa Deshmukh, senior research scientist at the New Jersey Department of Environmental Protection. A public meeting in December will allow stakeholders to provide input on those model assumptions, she said during the session.

The base case, she added, will reflect the current RGGI cap and relevant state policies that are underway and will be available for public review next spring. Modeling for an additional policy case will analyze potential RGGI policy changes.

“These results will have projected allowance prices, emissions and other impacts related to the electricity sector and the RGGI carbon market,” Deshmukh said.

Separate economic modeling will begin next summer to examine the effects of RGGI implementation, with projections on employment and other economic growth indicators.

Together, all the modeling will help RGGI states consider potential changes to the program’s model rule, which they will release in draft form next fall. After considering the draft updated model rule with public input in December 2022, Deshmukh said, the states will conclude the program review and begin individual rulemaking processes to align their regulations with the update.

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CGEP Talks Repurposing Infrastructure for Low-carbon Energy

The world needs to transform tens of trillions of dollars in energy infrastructure by midcentury to decarbonize the global economy and move away from fossil fuels, and a good portion of the existing assets can be repurposed to carry or accommodate low-carbon energy.

“How do we reconcile any new capital investments in energy infrastructure that need to be aligned with net-zero [emissions] with the reality that today’s energy system is very far from that, as energy shortages across Europe and Asia are reminding us acutely?” Jason Bordoff, director of Columbia University’s Center on Global Energy Policy, asked during a webinar the center hosted Monday.

Even if all the necessary solar panels and wind turbines were installed tomorrow, it would still not be enough to achieve net zero because there are very significant parts of the economy that cannot be easily or affordably electrified with current or even short-term future technology, said Maarten Wetselaar, director for integrated gas, renewables and energy solutions at Royal Dutch Shell.

“Think about the production of steel and cement or petrochemicals where you need a molecule to start with, but also to be transported by planes and ships and heavy trucks,” Wetselaar said. “Certainly advanced biofuels and hydrogen will be playing a crucial role in those sectors in the future, but they’re not sufficiently available yet. It will take time to scale up their production to become a meaningful part of the energy mix.”

Clockwise from top left: Jason Bordoff, CGEP; Maarten Wetselaar, Royal Dutch Shell; Melanie Kenderdine, Energy Futures Initiative; Maria Elena Drew, T. Rowe Price; and Demetrios Papathanasiou, World Bank | CGEP

Bordoff asked him to respond to the skepticism — which he suspected some viewers had — that there’s some degree of “greenwashing going on when we hear people in the energy sector” talk about needing to keep investing in pipelines and to take time in transitioning away from fossil fuels.

If society in the coming decade puts all the money available to be invested into creating clean energy, there’s likely to be a deficit of energy required for consumption, Wetselaar said.

“We need to thread the needle of producing just enough of today’s energy so the world can continue to turn,” Wetselaar said. “You can’t stop investing in oil and gas, because it will decline 5% per year, and the world is not ready with alternatives because the size of the global energy system is just so large it will take more time than that.”

Natural gas is going to be a very important transition fuel, said Maria Elena Drew, director of research at T. Rowe Price. “If we think about a just transition, it’s pretty critical that we have natural gas; otherwise it’s going to be tough to keep the lights on; it’s going to be tough for politicians to stay in office and to put policies in place for the energy transition.”

Costly Coal

The developing world accounts for about 93% of the capital invested in coal-fired power generation, which risks being stranded. So, to eliminate all the emissions from today’s roughly 2,100 GW of coal units by 2040 requires closing one plant a day, said Demetrios Papathanasiou, director of the World Bank’s Energy and Extractives Global Practice.

“Of course, China and India are among the major countries where these figures are very important,” Papathanasiou said. The value of these stranded assets in terms of GDP ranges between 2 and 10% of GDP, “very high numbers” amid a global pandemic, he said.

“There’s still about $15 trillion in assets and bonds that are earning a negative return. … Even my home country Greece, which is notorious for its difficulties on the macro side, [managed] a few months back for short-term debt to get a negative interest rate,” Papathanasiou said. “That shows that we live in a very special time; we have enormous financial needs, and there are significant unprecedented events that are taking place in financial markets.”

For coal plants in India and China, the land that surrounds a plant has very significant value, Papathanasiou said. “There is even significant value in the scrap metal if you decide to take everything down and sell it off as scrap.”

An unidentified participant asked whether an aggressive carbon price would enable needed changes to infrastructure.

“One of the challenges we’ve seen as investors, and one of the easiest things for regulators to do, is to drive more sustainable finance,” Drew said. “Seeing more action from regulators would help because, if you think we’re moving to a net-zero world, we as investors are going to anticipate that in our investments, but if the regulation isn’t coming, we’re going to end up being wrong.”

The electrification of everything and its contribution to deep decarbonization depends on how you’re generating your electricity, said Melanie Kenderdine of Energy Futures Initiative. In the Pacific region of the U.S., the Energy Information Administration now considers hydropower as a non-dispatchable energy resource because of drought. “Electrification is a good policy if you’re not then running your home heating on coal,” she said.

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Vineyard Wind to Build Salem OSW Port if Massachusetts Approves Newest Bid

Vineyard Wind created a partnership with the City of Salem, Massachusetts, on Sept. 30, stating it would turn an area of Salem Harbor into the state’s second offshore wind port, if the developer wins a new procurement bid from the state.

The agreement is part of Vineyard Wind’s 800-MW and 1,200-MW Commonwealth Wind proposals, submitted under Massachusetts’ 83C iii competitive solicitation that opened in May.

Florida-based Crowley Maritime, through its New Energy subsidiary Crowley Wind Services, would purchase a 42-acre area surrounding Salem Harbor and serve as the long-term port operator.

“We see a tremendous opportunity in this new industry being based out of Salem,” Mayor Kim Driscoll told NetZero Insider. The turbines will be installed off Martha’s Vineyard, but “the vast majority of the activity is on the site shoreside,” she said.

Vineyard Wind will use the port at Salem Harbor for turbine assembly and staging, as well as for the storage of blades, nacelles and tower sections before offshore installation.

Salem Harbor is also a popular recreation site, and Driscoll said the city will work to fit reactional activities with the new offshore wind port expansion.

“We still want it to bring people to Winter Island Park, another popular recreation site,” which sits on a plot of land that juts out into the harbor, she said.

Crowley Maritime will offer OSW workforce training on how to install turbines, rendered here, to environmental justice communities surrounding Salem. | Crowley MaritimeSalem Harbor is adjacent to historic districts and neighborhoods in the downtown area of the city, so it will be important to work with residents and businesses to limit the impact of the construction and operations at the new port, Driscoll said.

Historic Salem’s preservation committee will be involved in the public review process and is “willing to meet with any developer to ensure historic resources are part of the consideration,” said Emily Udy, preservation manager at Historic Salem.

“Addressing questions of how new uses [of the harbor] impact the existing character are an important part of our mission to ensure that the historic resources of Salem are preserved for future generations and that new development complements the historic character of the city,” Udy said.

Salem Harbor is not a new industrial site. The city recently replaced its coal-fired power plant with a gas-fired plant at the Salem Harbor Power Station, a project worth $1 billion in investment and construction that came online in 2018. The city government learned a lot from that project in terms of how to keep the community appraised of activities and involved in the process, Driscoll said.

“Constant communication is really necessary,” she said.

“There will be traffic from construction, but there won’t be coal ash on trucks traveling through the area,” Driscoll said. “A dozen years ago, the waterfront was so different.”

Vineyard Wind predicts the project will create about 400 full-time equivalent job years (FTE) during construction at the port and another 500 FTEs over the first five years of operation. Construction and staging the wind projects, along with day-to-day port operations, will create an additional 900 FTEs.

“As OSW continues to expand, new purpose-built ports will be key to the success of this industry,” Lars Pedersen, CEO of Vineyard Wind, said in a statement. “With a new OSW port in Salem, the commonwealth can ensure that it is ready to face the demands of a rapidly growing industry.”

The first OSW port in Massachusetts will be built in New Bedford.

Massachusetts expects to announce the winners of OSW bids on Dec. 17, with the execution of long-term contracts planned for March 2022.

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Hawaii Incentives Aim to Replace Diesels with EVs

The Hawaii State Energy Office (HSEO) is partnering with the state’s Department of Health (HDOH) to give away $2.1 million in rebates to incentivize diesel vehicle owners to switch to electric equivalents.

The Diesel Replacement Rebate (DRR) program will offer a 45% rebate to both public and private organizations that replace medium- and heavy-duty vehicles with an electric equivalent.

“Ground transportation represents about one quarter of Hawaii’s oil consumption and energy sector greenhouse gas emissions,” HSEO Chief Energy Officer Scott Glenn said. The DRR will “support job creation and reduce exposure to pollution for people who rely on mass transit.”

Qualified vehicles would include buses for transit, schools, and shuttles, as well as medium- and heavy-duty trucks. These would be type A, B, C and D school buses; class 5+ medium- and heavy-duty buses; and class 5, 6, 7 and 8 medium- and heavy-duty trucks.

Applicants must have owned and operated the vehicle in Hawaii for at least two years prior to applying, the vehicle must be fully operational, and it must have an estimated remaining life of at least three years.

Eligible replacement vehicles must be fully electric and zero-emission, resemble the replaced vehicle “in form and function,” be the most recent model available, be of a similar weight and horsepower class, and cannot be a retrofitted vehicle.

The DRR program guide also emphasizes that the replacement vehicle must operate in Hawaii for at least five years upon deployment.

DRR applicants can also apply for a charging station to go with the new vehicle, which would be included in the 45% rebate total. The rebate will only go toward the charging station itself; equipment and services such as batteries, solar panels, additional wiring and maintenance are not included.

HSEO is also running the Hawaii Energy charger rebate, which can be combined with the DRR. The DRR program guide notes that the charger rebate “will be netted from the project cost and the Diesel Replacement Rebate will be applied to the remaining cost.”

The DRR allows the salvaging and selling of parts from the diesel vehicles, yet the program guide notes that “the income may be used to meet the cost-sharing or matching requirement of the award. Therefore, the rebate amount will remain the same.”

Applicants must match at least 55% of the cost and cannot use federal funding for cost matching. Applicants also cannot request more than $1.2 million.

“Reducing harmful emissions from diesel engines is important to protect human health and our island environment,” Kathleen Ho, HDOH deputy director for environmental health, said in a statement. “We are excited to partner with the Hawaii State Energy Office to reduce air pollution and improve air quality for the people of Hawaii.”

Applications for the DRR will open on Oct. 29, but the HSEO recommends prospective applicants attend a webinar on Oct. 21 for detailed information.

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NCUC Debates Best Path for Duke Coal Retirements

The North Carolina Utilities Commission’s two-day technical conference on Duke Energy’s integrated resource plan (IRP), held Thursday and Friday, produced a flurry of industry jargon, the meaning of which varied depending on who was using it.

Duke’s “sequential peaker method” for determining when to retire specific coal plants in its 10,000 MW fleet was pitted against an “endogenous selection” approach recommended by clean energy advocates but labelled by Duke as being “single-source.”

Led by the Southern Alliance for Clean Energy (SACE) and the Carolinas Clean Energy Business Association (CCEBA), the advocates also pushed back on Duke’s plan to replace its coal-fired generation with significant new natural gas plants, calling instead for “all-source” procurements that could produce a portfolio of cheaper, cleaner alternatives. Duke argued that it already used competitive, “multisource procurements” based on the distinct system needs behind any one request for proposals (RFP) for new generation.

At the core of this war of words is Duke’s plan, as outlined in its September 2020 IRP, to keep 3,050 MW of its current coal fleet online at least through 2035 and add 9,600 MW of natural gas-fired generation. The technical conference was focused on the methodologies behind those figures and how they might be changed going forward.

Speaking for SACE, Rachel Wilson, principal associate for industry consultant Synapse Energy Economics, laid out the case for endogenous selection, in which the ordering and timing of coal retirements are determined by an advanced analytic platform, specifically the EnCompass modeling software.

“The first step in Duke’s methodology was to establish an order for unit retirements — rather than attempting to answer that key question … do the coal plants economically serve customer requirements — and then ranking them according to their value,” Wilson said. “Duke simply ordered the units according to capacity, with the smallest retiring first. So, the company’s economic analysis totally ignored the actual economics of these coal units.”

With endogenous selection, “the model’s decision is based on a calculation of unit profitability,” she said.

“For a unit that exists in an RTO like PJM, this is just the summation of its energy capacity and ancillary revenues minus its costs,” she said. “For Duke, which is operating in a vertically integrated area, this means a unit’s retirement is based on the cost of providing the next megawatt, whether that could be from an existing resource on the system, or it could be the cost to bring a new unit online.”

Duke executives at the technical conference defended the utility’s decarbonization strategy as balancing incremental emissions reductions with the need to maintain affordability and reliability. Downplaying energy storage as a not-yet-mature technology, they argued that Duke’s reliance on natural gas has allowed it to begin retiring coal while adding significant amounts of intermittent renewables, mostly solar. Since 2005, the utility has cut its carbon emissions per megawatt-hour of power generation from 1,025 pounds to 600 pounds today, according to figures in its IRP; it expects further reductions to 350 lbs/MWh by 2035.

Mike Quinto, lead engineer on Duke Energy Carolinas’ resource planning and analytics team, similarly defended Duke’s “sequential peaker” methodology for determining coal plant retirements as encompassing both capacity expansion and production cost modeling that provides a more granular and transparent analysis than endogenous selection.

Using the sequential peaker approach, Duke first set the order of plant closures — which essentially came out from smallest to largest — and then used production cost computer modeling to determine the most economical date for retiring each facility, Quinto said. This approach “acknowledges that the retirement of one unit impacts the operations of the remaining units in the fleet,” he said. “So, as we retire one unit, it may require the rest of the fleet to respond in a different way.

Endogenous selection looks at plants independently, he said, which “would inaccurately represent the incremental costs that each unit has to the system, and further blur the lines of the true value to the system.”

“It removes chronology … how the system operates from one hour to the next or one week from the next, which is important for how renewables and how batteries operate and how the system responds to these,” Quinto said. “We lose some of that detail with these models. And finally, we lose the ability to dynamically forecast the costs of the existing units when determining that appropriate retirement date.”

South Carolina Plan Revised

Duke’s IRP is essentially a consolidated plan covering both Duke Energy Carolinas, which serves portions of both North and South Carolina, and Duke Energy Progress, North Carolina’s largest utility. When first released, Duke framed it as an advance in its planning process, noting it had developed six different scenarios for coal retirements and emissions reductions. Advocates in both states, however, quickly criticized the plan’s recommended base case, which kept more than 3,000 MW of coal online through 2035, along with the 9,600 MW of new natural gas.

The South Carolina Public Service Commission sent Duke back to the drawing board in June, with specific instructions on recalculating certain elements of the plan. For example, Duke’s modified South Carolina IRP, submitted in August, included additional scenarios that incorporated solar projects with single-axis tracking, which increases project output.

Duke’s new preferred plan retires all coal by 2035, also adding in 600 MW of onshore wind and 1,250 MW from energy efficiency and demand response initiatives, neither of which had been included in the original plan. Company executives at the NCUC technical conference also reported the utility would be using EnCompass as its modeling platform for its 2022 IRP, along with improved stakeholder engagement.

The NCUC has already held a number of public hearings on the original plan and collected thousands of pages of arguments from both sides, said Commissioner Dan Clodfelter, who chaired the Thursday and Friday sessions. But under state law, the commission can make comments on the plan but cannot order revisions, which to a certain extent refocused the debate more on Duke’s upcoming 2022 IRP, rather than further changes to the 2020 plan. (See Outspoken Public Pushes for Duke to Lead on Climate.)

Representing CCEBA, Steve Levitas, senior vice president at Pine Gate Renewables, a North Carolina developer, specifically called for any new all-source procurement to be implemented with Duke’s next IRP, rather than delay any upcoming renewable procurements.

“Absent new legislative direction, the commission should require immediate large-scale procurement in renewable energy,” he said.

The Colorado Experience

John Wilson, director of research at Resource Insight, Inc., criticized Duke’s approach to procurement as “single-source,” waiting until a coal plant is uneconomic to issue an RFP to replace it. With a technology neutral, all-source procurement, “you can provide the economic basis for scheduling those retirements much more effectively,” he said.

He pointed to Colorado’s experience with all-source procurements, which in 2016 allowed Xcel Colorado to retire two coal plants and replace them via an RFP that produced 417 bids. The resulting portfolio included wind, solar, storage and existing natural gas. Prices ranged from just over $0.01/kWh for wind, $0.023/kWh for solar and $0.03/kWh for storage, according to a presentation Xcel made earlier this year to the Michigan Public Service Commission.

Jeremy Fisher of Synapse discussed another 2018 all-source procurement by Northern Indiana Public Service Company (NIPSCO), which found that replacing existing coal plants with renewables provided more value and lower costs for the utility’s customers. To accurately compare costs, the RFP was done in advance of setting the order and timing of plant retirements, Fisher said.

“The first question they asked is, what’s the fundamental value of each of these [coal] units in 2023 and then, is there a better combination of retirements that happen in 2023 or 2028, and [offer] various opportunities to avoid impending capital requirements that would come through environmental obligations,” he said.

As a result, the utility targeted 2023 for retiring most of its coal fleet, keeping one plant online until 2028 and later moving up the retirement of two plants to 2021, Fisher said.

Commissioner Clodfelter also pressed the Duke executives on the issue. “As I hear it, you are defining need in a more discreet, ‘componentized’ way and looking at procurements relative to components or elements in that need,” he said. “And what I hear the other party’s advocating for is that we should define what they call total system need, and then you should seek procurement of a portfolio of resources that in the aggregate will satisfy that total system need.”

Asked about a 2018 RFP to replace peaking capacity, Jim Northrup, Duke’s director of economic analysis, said the 33 bids included natural gas, both combustion turbines and combined cycle, and hydropower.  At the same time, under a state-mandated competitive procurement program for renewable energy, the utility has offered contracts for hundreds of megawatts of new solar in recent years, some of them to third-party developers.

Glen Snider, Duke’s head of long-term planning, said that fossil fuel retirements, new procurement and planning must take into account the evolution of technology and the grid.

“The system didn’t evolve overnight, and it’s not going to retire all of it overnight,” Snider said. “So, when you think about room for hydrogen or offshore wind, we really need to think beyond just retiring coal assets. By the time I get to the 2030s. I’m going to have a bunch of natural gas generators that went in in the late ‘90s and early 2000s that will be 35 years old. They are going to be approaching the end of their useful lives, and that will create additional need and room for new technologies to fill a future need that we’re really not talking about today.”

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Texas PUC Finances Market Debt over Lt. Gov.’s Objections

Texas regulators last week ignored political pressure in approving a pair of ERCOT requests for debt-obligation orders that will allow the grid operator to securitize $2.9 billion in market debt as a result of high charges incurred during the February winter storm.

The Public Utility Commission on Thursday tweaked and accepted a settlement reached between 46 parties and participants over ERCOT’s proposal for a $2.1 billion market uplift to cover short pays to the market, despite letters sent to each commissioner by Lt. Gov. Dan Patrick (R) in opposition to the agreement (52322).

Patrick said he supported the prioritization and securitization of retail electric providers (REPs) unaffiliated with generation companies. “However,” he said, “any portion of the proposed settlement agreement that does not calculate cost exposure on a net basis … is unacceptable.”

The state’s second most powerful politician said that the intent of legislation authorizing the securitization process (House Bill 4492) was to “calculate cost exposure on a net basis” by taking into account the profits of affiliated generators — such as Luminant and NRG Energy, affiliated with REPs TXU Energy and Reliant, respectively.

“The Texas Senate would not have passed a bill that gave money to companies that profited during the winter storm,” said Patrick, who as lieutenant governor is president of the Senate.

Commissioner Will McAdams, leading the PUC’s open meeting after Chairman Peter Lake recused himself, responded to the letter before the commission took up the docket. He said it was “well taken” and its assertion of legal intent “is always valuable to agencies” as they try to “execute the intent of the legislature and the letter of law.”

“With the submission of the unopposed settlement, we have a path forward and the mechanics of accomplishing securitization in an order,” McAdams said. “This is a complicated proceeding, with many intervenors. If we breach the unopposed settlement agreement, there’s a very good chance we would prevent staff from being able to move forward in a timely way to [meet] the deadline for issuing the order.”

The PUC faces a statutory deadline of Oct. 14 for issuing orders in the two proceedings. ERCOT’s other debt-obligation requests involves financing $800 million owed to the market by cooperatives and municipalities (52321). (See Texas PUC Hearings Begin on $2.9B ERCOT Securitization.)

“This settlement is that tool to provide badly needed liquidity into a market that has been significantly disrupted by” the storm, McAdams said. “Many actors are limping along, waiting on state-backed relief. If we restart this process, I fear that it may result in bankruptcies on the part of our most at-risk market participants.”

Patrick responded by issuing a statement after the meeting, calling the PUC’s decision “bad public policy and a bad decision for Texas taxpayers.” He also took shots at the commissioners, who replaced those seated during the winter storm, and HB4492’s author, Rep. Chris Paddie (R).

“After the winter storm, I called for the resignation of members of the PUC. They all resigned,” Patrick said. “I can assure you that the new commissioners’ Senate confirmation hearings would not have gone as smoothly if senators knew they intended to disregard the will of the Senate.”

He said Paddie, who recently said he was stepping down after eight years in the legislature, has been “disingenuous” during the legislative process and that he may be “seeking a highly compensated position in the same electric industry that stands to benefit from his position of no netting and no transparency.”

House Speaker Dade Phelan stood up for Paddie, chair of the powerful House State Affairs Committee, posting on Twitter that he was grateful for his “steady leadership, his character and his integrity.” Saying that implementing legislation related to ERCOT’s market “merits a deliberative, factual hearing,” Phelan said he has asked Paddie to convene a hearing to gather a progress report on the grid.”

“Shot … chaser,” tweeted energy consultant Doug Lewin, contrasting the Patrick and Phelan statements.

Lewin added that the political tit-for-tat is a fight about “who gets how much” of the $2.1 billion bailout, which is likely to be ultimately paid by ratepayers. “This is not a fight about how to give assistance to ratepayers or prevent another outage.”

State Senate Grills Gas Regulator

Texas senators took out their ire on the Texas Railroad Commission (RRC), which regulates the state’s oil and gas industry, when it became apparent that legislation they wrote earlier this year included a loophole that allows natural gas companies to opt out of weatherization requirements if they don’t voluntarily declare themselves to be “critical infrastructure.”

The opt-out fee is only $150. Should the facilities declare themselves “critical infrastructure,” they would be forced to spend significantly more money on weatherizing their facilities.

A timetable that requires a committee to map the state’s critical energy infrastructure by next September, and then gives the RRC 180 days to issue its weatherization rules, also raised the legislators’ hackles.

“Our weatherization rule will not be adopted for this winter because we have to put the map together,” RRC Executive Director Wei Wang said during the Senate Business and Commerce Committee’s Sept. 28 hearing on the energy industry’s winter preparations.

Texas RRC Executive Director Wei Wang (2nd from left) explains the commission’s weatherization plans during a Senate hearing. Also seated: Texas Energy Reliability Council Chair W. Nim Kidd, Interim ERCOT CEO Brad Jones, and PUC Chair Peter Lake. | Texas Senate

“Wait a minute … you haven’t done it yet?” Sen. Robert Nichols (R) asked.

Wang responded that the commission is just following Senate Bill 3’s language. The comprehensive bill was the legislature’s primary response to February’s devastating winter storm. (See Abbott Signs Texas Grid Legislation into Law.)

“Your rulemaking proposal sucks, and we need a different direction,” Sen. John Whitmire (D) told Wang.

“Appreciate your guidance on that particular issue, and if we need to change the language, we will,” Wang replied.

The committee directed Wang to ask the RRC’s legal counsel as to whether lawmakers can revise the legislation during the current special session that ends Oct. 19.

“This gives the Texas Railroad Commission a great opportunity to prove up its worth,” Sen. Donna Campbell (R) said. “If you don’t, it can just be moved the PUC. It’s going to be looked at. You better prove up your worth.”

The FERC–NERC joint inquiry into February’s generation outages in Texas and the Midwest during the storm have fingered the lack of gas infrastructure weatherization as the primary culprit. Other reports and studies have come to the same conclusion. (See FERC, NERC Share Findings on February Winter Storm.)

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PJM Stakeholders Endorse Initial Margining Proposal

After nearly two hours of debate at Wednesday’s Markets and Reliability Committee meeting, PJM stakeholders endorsed tariff revisions on rules related to initial margining and closed out the work of the Financial Risk Mitigation Senior Task Force (FRMSTF).

The joint proposal by Duke Energy (NYSE:DUK) and Perast Capital Management won endorsement with a sector-weighted vote of 3.42 (68.4%), passing the 3.33 threshold for adoption. The proposal was initially endorsed at the Aug. 4 FRMSTF meeting with 69% support and was presented for a first read at the August MRC. (See “Initial Margining Solution,” PJM MRC Briefs: Aug. 25, 2021.)

Members also unanimously voted to sunset the FRMSTF, created in 2019 in the wake of the GreenHat Energy default. (See PJM Stakeholders OK Risk Management Task Force.)

Duke’s Matthew Holstein said that before GreenHat, FTR collateral was based upon the difference in bid/purchase price and the FTR’s historical performance, allowing GreenHat to select “free” paths whose cost was less than historical congestion

Holstein said the Duke/Perast proposal would make collateral requirements based upon volatility, which more closely relates to actual risk. It would also institute a minimum credit requirement, which would prevent a portfolio the size of GreenHat from ever existing again without a posting of collateral.

The proposal’s initial margining based on historical simulations methodology (IM-H) includes a 95% confidence interval, which represents the range of values likely to include a population value. PJM conducted analyses at confidence levels of 99%, 97% and 95% when evaluating the IM-H calculation.

Perast’s James Ramsey said they suggested 95% because the failure rate was reduced to 1.21% from the status quo of 8%. Ramsey said the 97% interval proposed in PJM’s proposal would cost an extra $140 million to achieve a failure rate improvement of 0.3%.

The PJM proposal only received 37% stakeholder support at the August FRMSTF meeting.

“You can summarize the two packages as the quality insurance plan versus the Rolls Royce insurance plan,” Ramsey said. “We believe the 95 is a vast improvement over where we are today and is the right cost-benefit.”

Tariff Language Debate

Several stakeholders, however, were concerned with the tariff language changes implementing the proposal and managed to get PJM to include a key calculation in them.

Troiano said that after the first read at the August MRC and reviewing stakeholder feedback, the RTO realized there was an “opportunity for confusion” in the previous redlines of the tariff language and some “unintended consequences.” PJM started over and redid the redline language, making sure it was “more concise” and “simpler” and contained fewer changes, she said.

Adrien Ford of Old Dominion Electric Cooperative noted that one section of the tariff revisions “seems to be missing” the exact weighting parameters that determine how the initial margin values for FTR obligations would be calculated, as detailed in the proposal.

“We’re totally willing to provide transparency to members, but there are other elements of the modeling assumption and simulations we believe must be held confidential,” Bloczynski said.

Ford said she “maintains the assertion” that the tariff language didn’t reflect the package before the committee and requested the parameters be included.

“We need integrity in this process, and that includes documenting the will of the committee,” Ford said.

David Anders, PJM’s director of stakeholder affairs, said he believed that “integrity’s maintained” in the redline language. Anders said there are portions of proposals for almost all issues that get documented in the governing document language like the tariff and the Operating Agreement, while other portions are contained in the implementing documents.

Ford said she “wasn’t satisfied” with that response and that she felt like she was “being discounted.” She said the main differences between PJM’s proposal and Duke/Perast’s was the confidence interval and the weighting. While Duke/Perast’s 95% confidence interval is reflected in the redlines, the weighting was left out. “The lack of documenting that here when it’s a key differential in the packages is a concern for me.”

“PJM is choosing which revisions it wants to include, which makes it convenient for PJM,” Hicks said. “While I understand why you want to do that, I can’t fathom this being acceptable.”

Bloczynski reiterated that PJM didn’t believe the weighting figures needed to be documented in the tariff and that it could be documented in the attachment. “I believe that most members trust us to run the market, make decisions and independently monitor risk management efficiently and effectively,” she said.

“To suggest that we can keep these numbers out when it is part of the filed rate is a dangerous precedent to set and runs contrary to everything regarding transparency, reflecting the will of the stakeholders and FERC precedent,” Sotkiewicz said.

PJM General Counsel Chris O’Hara said the RTO had “concerns” about the Duke/Perast proposal but was “trying to respect the stakeholders” by putting the endorsed proposal forward and including the weighting in the supplement document, where there could be an “easier path” toward changing the values if stakeholders decide they need to be changed in the future.

Sotkiewicz said by not adding the weighting, PJM was “setting this up for a really bad battle at FERC” over something that could be resolved by adding the numbers to the redlines.

Greg Poulos, executive director of the Consumer Advocates of the PJM States, said his group continued to support PJM’s proposal, citing findings in an independent consultant’s 2019 report of the GreenHat default. Poulos said the endorsed proposal “looks so much like deja vu” to actions taken by stakeholders after the $52 million credit default by Tower Research Capital’s Power Edge hedge fund in 2007. (See PJM Credit Adder Fails upon Heightened Review.)

Poulos said the report talks about how PJM brought recommendations to stakeholders after the 2007 default, but the membership decided to go in a different direction with reforms. The report said in italics that “PJM should be more assertive in pushing for action needed regarding any critical changes to credit policies, emergency discretion and the like.”

“I think PJM needs to take a stronger position even if certain stakeholders have a stronger voice and go a different way with this,” Poulos said.