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November 14, 2024

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Clean Energy in NY: Reveling in Opportunity, Realistic About Challenge

ALBANY, N.Y. — With the green energy agenda intact after Election Day and with billions in new funding secured for the energy transition, the fall 2022 conference of the Alliance for Clean Energy NY had a triumphal note.

Speakers at the Nov. 9-10 event celebrated New York voters’ approval of a $4.2 billion environmental bond act and the election of Gov. Kathy Hochul (D), who has continued pushing the ambitious clean energy transition begun by former governor Andrew Cuomo.

With tens of billions in funding expected from federal measures approved earlier this year, the stage is set for extensive progress under New York’s Climate Leadership and Community Protection Act (CLCPA), policymakers said.

Anne Reynolds 2022-11-10 (RTO Insider LLC) FI.jpgAnne Reynolds, Alliance for Clean Energy New York | © RTO Insider LLC

“Rather than looking forward to the transition in the future, we are in it right now,” ACE NY Executive Director Anne Reynolds said in welcoming attendees. The world needs an example of a sustained and successful transition to carbon-free energy, she said. “I do believe that with your help that New York can be that place that shows the world how to get it done.”

Leaders in the private sector, however, sounded a cautionary note about New York’s regulatory framework, calling it the most expensive and most time-consuming to navigate of any state in the nation.

The state’s top environmental regulator, Department of Environmental Conservation Commissioner Basil Seggos, acknowledged this and said work is underway to change it.

“That’s part of our effort under the CLCPA. We need to not just identify all these opportunities for growth and new programs but also, how do we streamline our processes and ultimately make New York more affordable for developers of clean energy and just New Yorkers in general?” he said.

Optimism and Excitement

Doreen Harris, CEO of the New York Energy Research and Development Authority, said New York is at an inflection point. The extensive groundwork the state has laid toward decarbonization is in line for a massive infusion of federal money from the Inflation Reduction Act (IRA) and other measures — as much as $70 billion, according to a NYSERDA analysis.

Doreen Harris 2022-11-10 (RTO Insider LLC) FI.jpgNYSERDA CEO Doreen Harris | © RTO Insider LLC

Also, New York voters Nov. 8 approved a bond act providing $4.2 billion for environmental projects, about a third of it for green energy and net zero initiatives. New Yorkers voted 2-1 in favor of the bond act, even as they gave a far narrower margin of victory to Hochul. (See Incumbents Successful in Most Contested Governors’ Races.)

“And so we have this moment of tailwind that we are building on here today,” Harris said. “It’s really quite an incredible time.”

Minelly De Coo, deputy director of infrastructure for Hochul, said even if Republicans regain control of the federal government, the transition may slow but it will not stop. “The boat has left the dock,” she said.

De Coo said the tens of billions of federal clean energy dollars coming to New York “is just a drop in the bucket for what is needed.”

But it will have an outsized impact, she added, “because of how far ahead New York state is in implementing and employing some of these programs.”

Harry Godfrey, managing director of Advanced Energy Economy, said manufacturing incentives are the most important part of the IRA. “The U.S. just became a much more attractive place to do business,” he said. “We’re talking about industrial policy we haven’t seen since the beginning of the space race.”

Obstacles on the Path

New York’s challenge is daunting: roughly tripling its generating capacity while simultaneously shifting from dirty-but-constant generation to clean-but-highly-variable power sources.

Some of the speakers tempered their optimism by acknowledging global and local challenges but said these are surmountable. Others centered their comments almost entirely on these challenges, and said they are particularly numerous in one of the most expensive and heavily regulated states in the nation.

Diane Sullivan 2022-11-10 (RTO Insider LLC) FI.jpgDiane Sullivan, Hecate Energy | © RTO Insider LLC

Diane Sullivan, a senior vice president at renewable developer Hecate Energy, told attendees she had worked as a consultant in all 50 states and that New York has the longest, most expensive siting and permitting process of any of them.

The top three “balance of plant” contractors are not interested in working in New York, and as a result, some other major contractors are hesitant, EDF Renewables Vice President Stephane Desdunes said. The contractors that are willing to work in the state have less experience with grid-scale projects of more than 100 MW, he said.

This reluctance is based on concerns ranging from the shorter northern construction season to New York’s Scaffold Law, which is unique among the 50 states in establishing absolute employer liability for injury in all gravity-related worksite accidents.

Michelle Piasecki of the Harris Beach law firm spoke of the risk of retroactive policymaking. Niagara County, for example, enacted a solar stewardship law that altered the timeline, complexity and financing of multiple projects already in the pipeline. Developers must draw up a recycling plan, pay a review fee, pay an annual fee and face fines of $100 per day per panel for non-compliance, she said.

Stephen Desdunes 2022-11-10 (RTO Insider LLC) FI.jpg

Stephane Desdunes, EDF Renewables | © RTO Insider LLC

This is a disincentive to development, Piasecki said, and there is a risk of it spreading to other counties across the state.

Sullivan said the permit issued for Hecate’s 500-MW Cider Solar project east of Buffalo had extensive checkoff lists and ran 78 pages — a red flag for contractors considering bidding on it.

“There seems to be a conflict between how NYSERDA screens projects vs. how the NYISO does,” Cypress Creek Renewables CEO Sarah Slusser said. “[They are] basically at odds with each other — one screens for concentration the other screens for lack of concentration of facilities. That kind of needs to align. That kind of coordination would greatly help.”

ACE NY’s Reynolds acknowledged the concern.

“I’ve never developed projects in other states but I’m talking to developers all the time, and you can get a permit and get an interconnection so much faster in other places,” she said.

Michelle Piasecki 2022-11-10 (RTO Insider LLC) FI.jpgMichelle Piasecki, Harris Beach law firm | © RTO Insider LLC

“I’m still optimistic but … you have so many moving parts. You have the interconnection process, you have transmission constraints, you have permitting, you have getting a NYSERDA contract and then you have to negotiate a tax agreement.”

The review and permitting processes pose the biggest challenge, speakers said. During a review that can take three to five years, key factors such as technology, landowner consent, local politics and interconnection capacity can change. A change of detail as minor as the manufacturer’s model name for a solar panel prompts a material modification review by NYISO.

George Pond of the law firm Barclay Damon said NYISO — which is currently advertising 38 job vacancies — does not have the capacity to catch up with the volume of projects coming to it for review.

George Pond 2022-11-10 (RTO Insider LLC) FI.jpgGeorge Pond, Barclay Damon law firm | © RTO Insider LLC

“I know that NYISO is struggling; I would say the biggest thing they need is more engineers,” he said. “In a sense I want to give a shout-out to them … they have a lot more projects in their class-year facilities study now than they did when the process was set up 20 years ago, and they’re managing to keep the timeline about where it’s been. So you shouldn’t overlook all the hard work they’ve done to get to that point.”

Another major challenge is the difficulty obtaining equipment and labor. The wait time for parts delivery has increased. Delivery of a substation inverter, for example, might take 18 to 24 months. In addition, contractors are submitting bids valid for as little as 30 days due to price volatility.

With the increasing number of renewable projects, there is intense competition for workers and much of the work requires union labor and minority- and women-owned business enterprise (MWBE) participation.

While New York needs thousands of new electricians and other skilled tradesmen, workforce development programs often require a multiyear commitment that potential students are unable or unwilling to make.

The environmental justice and economic development component of New York’s clean energy transition is extensive and highly detailed. A 45-part scoring system will be used to determine if a community is economically disadvantaged, and it is being “continuously recalibrated,” according to Sameer Ranade of NYSERDA.

The Path Forward

In an interview, Seggos said the permitting concerns are valid, but they are being addressed by shifting responsibility from the DEC and the Department of Public Service to the state’s new Office of Renewable Energy Siting.

“Now you’re seeing projects move through there more quickly and hopefully get their permits,” Seggos said. “They need to be coming in with the right applications — we encourage pre-consultations so that a developer isn’t selecting a hundred acres of wetland, which happens, even still.”

Reynolds offered an optimistic take despite all the factors complicating New York’s transition.

Basil Seggos 2022-11-10 (RTO Insider LLC) FI.jpgN.Y. Department of Environmental Conservation Commissioner Basil Seggos | © RTO Insider LLC

“It’s definitely a lot; I don’t want to minimize it,” she said. “I’m hoping that it’s not unrealistic, and we do have 17 projects under construction this year, which is more than we’ve ever had before.

“I think the question you’re asking is, ‘If we keep hanging all these ornaments on the Christmas tree, will it eventually fall over?’ I’m still hopeful it won’t. It hasn’t happened yet; people are still coming to develop in New York, and there’s these projects under construction.

“But it’s also predicated on an even playing field. So, if all the solar companies have the same requirements … then it should work. And I think that’s what we’re counting on.”

Seggos said the technological challenges facing the engineers and scientists who will make the transition possible are exceeded by the societal challenge of carrying out such an enormous change.

Seggos compared it to simultaneously redesigning and building a plane while deciding where to go, navigating it to that location, and safely landing.

“What we’re trying to accomplish is to effectively undo a hundred years of how the state was built and regulated and adapt it to the current needs — without upsetting the apple cart along the way,” he said.

“It’s an extraordinary challenge.”

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Hydrogen-burning Locomotive Focus of New Federal Research

Research scientists and engineers from the Oak Ridge and Argonne national laboratories this week began a four-year research project with freight locomotive maker Wabtec Corp. aimed at substituting hydrogen for diesel fuel in diesel-electric train engines.

Pittsburgh-based Wabtec (NYSE:WAB) has already built a one-cylinder research diesel at Oak Ridge in Tennessee that will be the primary tool to investigate whether hydrogen can completely replace diesel or be burned in increasing percentages with the oily fossil fuel.

The company has previously investigated whether locomotive diesel engines could use a mixture of up to 80% natural gas and 20% conventional diesel in experiments to lower carbon emissions.

Wabtec has also built battery electric locomotives, which have tested both in switch yards and on a long-distance freight line. The company has a working agreement with the battery division of General Motors.

Battery weight is not a problem for a locomotive, but space to house the battery packs can be. And the cost to build the enormous battery packs is significant. Charging battery locomotives is another problem the company has investigated.

As for hydrogen, the current cost of hydrogen made with renewable energy is prohibitively high, but the Biden administration’s multi-faceted hydrogen programs, including billions in matching grants for the development of industrial hydrogen hubs along with significant tax credits for hydrogen production, are expected to lower to the price of clean hydrogen by the end of the decade.

Hyro-Loco Render (Oak Ridge Natinal Laboratory) Content.jpgArtist’s conception | Oak Ridge Natinal Laboratory

Under the terms of the agreement with the two federal laboratories, multi-disciplinary teams of company and federal engineers, working also with software developer Convergent Science of Madison, Wis., will now focus on what hardware modifications will be needed to the single cylinder research diesel, and to its electronic control systems and accompanying software to enable the engine to run on mixtures of hydrogen and diesel fuel and ultimately on hydrogen alone.

The project “aligns with the goals of DOE’s Vehicle Technologies Office to use low-carbon fuels in hard-to-electrify transportation sectors,” according to Argonne.

“Hydrogen has been used in light-duty combustion engines. However, hydrogen is a newer area of research in railway applications,” said Muhsin Ameen, a senior research scientist at Argonne.

If the team’s experimental objectives are successful and locomotives now in service can be modified accordingly, rail companies “will be able to greatly reduce carbon emissions while maintaining commonality within their current fleet of trains,” Wabtec Vice President James Gamble said.

There are approximately 25,000 freight locomotives operating in the U.S., emitting about 87.6 billion pounds of carbon dioxide annually. Locomotives typically last at least 30 years, and Wabtec has developed a business division that re-conditions older locomotives with modern systems, extending their working lifetime.

Freight trains are typically pulled by three or more locomotives, and Wabtec has run an electric locomotive in series with conventional diesel-electrics, using the battery-electric locomotives’ re-charging systems to increase the overall efficiency of a train.

The federally funded combustion research with Wabtec is unlikely to win the endorsement of environmental groups that have targeted diesel engines for extinction.

Because the purpose of a diesel engine in a diesel-electric locomotive is to spin an alternator to generate electricity for drive motors on the locomotive’s axles, the company has focused initially on cleaning up the fuel and has come to view hydrogen as “the fuel of the future.”

Replacing the diesel engine in a diesel-electric locomotive with a fuel cell — if fuel cells stacks are eventually made large enough and able to ramp up power output as quickly as a diesel-driven alternator — could work, according to previous company interviews.

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Stakeholders: NJ Storage Incentives Too Small, Slow

The New Jersey Board of Public Utilities’ (BPU) effort to limit the ratepayer costs of its incentive plan to stimulate the development of storage has run into concerns that its early stages are too slow and modest.

The limited size of the project capacity eligible for incentives in the first two years of the program will crimp storage development progress and push up expenses, developers told a stakeholder meeting held Friday into the grid-scale elements of the Storage Incentive Program (SIP).

The proposal uses a “declining block system” in which the first applicants are allocated incentives and capacity from the initial blocks, which pay the incentive at a rate that would cover about 30% of the project cost. Once that initial block is subscribed, the incentives for the next block then decline by a predetermined amount set by the BPU as more blocks are allocated. If a block is unsubscribed, the BPU can adjust the incentive to make it more attractive.

The system is designed to give the BPU the flexibility to adapt to market conditions and “ensure that the total cost to ratepayers decreases as the quantity of resources increases,” while also giving potential investors a “clear trajectory” of incentives, the straw proposal says.

But Scott Elias, director of Mid-Atlantic state affairs for the Solar Energy Industries Association, said the BPU’s proposed award of 30 MW of storage in the program’s first year is too small, and the agency should be planning for about 100 MW.

“It’s entirely conceivable that a single project would eat up the full capacity for the entire year,” he said. “And we think that would undermine the philosophy behind a block structure.”

Dennis Duffy, vice president at Energy Management Inc., an energy facility operator and developer, said the benefits of rapidly developing larger capacities of storage than is anticipated by the BPU are “known and measurable” and would create economies of scale.

“There’s no question, if you want to lower the costs, you’ve got to do these projects in scale,” he said. “And the way you do that is by larger volumes in the initial years of the program.”

Judy McElroy, CEO of Fractal Energy Storage Consultants, also urged the BPU to consider offering larger blocks of capacity.

“A 5-MW battery or storage system can be on the order of 20 to 25% higher on a per-unit basis than, say, a 50-MW or 100-MW storage system,” she said.

Block Size vs. Cost Tradeoff

BPU officials said the block sizes were set in an effort to balance the size of incentives needed to get the storage sector up and running with the cost to ratepayers.

Abe Silverman, the BPU’s general counsel, said the fixed incentives in the grid-scale part of the storage proposal would cost ratepayers $2.08 million in the first year. He displayed a slide that showed the program would cost another $2.39 million for the blocks allocated in the second year, for a total of $4.472 million paid out in the second year. The program would award $1.8 million in the third year, for a total cost of $6.272 million.

The program over that period would allocate three capacity blocks each year for three years: 5, 10 and 15 MW in the first year; one 16-MW block and two 17-MW blocks in the second; and three 25-MW blocks in the third. The incentives would start at $20/kWh per year for the first block, declining to $4/kWh in the last block of the third year.

“We want to make sure we’re doing something that’s realistic from a budgets standpoint … but also get things moving,” said Paul Heitmann, program manager for the clean energy division of the BPU, who presented the proposal at the hearing. He said there was a clear tradeoff between block size and the cost; creating larger blocks would result in smaller incentives because of the BPU’s cost constraints.

But Ted Ko, a consultant to clean energy companies who said he had extensive experience putting together storage projects, told the hearing that the BPU needed to take a broader view of the program. The agency should consider the goal of reducing ratepayer costs in conjunction with a more expansive vision of reducing the “the overall cost of deploying the energy storage to meet the target.”

“The way to do that with incentive programs … is to get the market learning curve accelerated quickly enough to reduce the soft costs of energy storage deployment in your state, in your market … thereby reducing the overall cost of deploying to your targeted goal,” he said.

Long-duration Storage

The discussion came in the second of three online hearings into the SIP proposal, for which more than 300 people signed up to listen in and more than 20 people spoke.

The state is trying to remedy slow progress toward its ambitious goals for storage development. The state Energy Master Plan recognized storage as a key element and predicted that the state would eventually need 9 GW of capacity. The state’s Clean Energy Act of 2018 set a goal of having 2,000 MW in place by 2030. Yet the state at present has only about 500 MW of storage.

The SIP sets a target of building 1,000 MW of four-hour-plus storage by 2030. It anticipates a steady increase in the annual capacity of storage installed each year, with 40 MW of four-hour storage installed in 2023, rising to 330 MW in 2029.

The full incentives would be paid to a storage facility that is available for 95% of the hours in the day, the SIP suggests. And the proposal suggests that units should be available for at least 50% of the year.

Hong Zhang Durandal, senior manager for EDP Renewables, a global clean energy development company, said the BPU could attract more participants into the storage market and increase the sector’s flexibility by setting the availability percentage before 50%. That would increase the market and prevent storage users from having to rely on just a few players, he said.

“Say some unexpected event happened to battery X operator for some X reason,” he said. “Then you have another three battery providers that can actually fulfill” whatever the need is, he said.

The proposal also suggested that there could be incentives for long-duration storage, which provide power for more than 20 hours, rather than the four-hour duration that the BPU adopted as a standard in the proposal. The agency is soliciting input from stakeholders to flesh out the details of what it should look like and how to stimulate the development of long-duration storage.

Such a program could be expected to offer lower incentives because long-duration technologies can have lower costs and sometimes don’t cut carbon emissions as much as short-duration storage, the proposal says.

The proposal cites the example of Form Energy, which has agreements with both a Minnesota electric cooperative and a Georgia utility to deploy pilot versions of “a novel iron-air-exchange flow battery” that it claims “can offer up to 100 hours of electricity storage at a price of less than $20/kWh.” However, the battery “likely” has lower efficiency and loses more power in providing charge than does a lithium-ion battery, the straw proposal says.

Michael D’Ambrose, consulting engineer at TRC, a Connecticut-based consulting firm, said the BPU should be open to storage with durations even longer than 20 hours, such as “seasonal energy storage,” as well as alternative sources such as hydrogen.

Heitmann said the agency wants to be “technology agnostic” but also has to evaluate what mix of storage duration models is best for the state goals and what targets to prioritize. There are models for both thermal storage and mechanical storage emerging, and flywheel systems are a “proven technology,” he said.

“Long-duration storage tends to not have that high megawatts” generating capacity, which smaller-duration projects do, he said. “But it’s got the ability to do it for a long time. … Long-duration storage has a place, and it’s kind of one of those missing pieces of making this all work and helping us balance everything on our grid.”

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Road to Mass EV Adoption Still Unclear in Wash.

Washington needs to do a large amount of legwork to prepare for Gov. Jay Inslee’s mandate banning the sale of new gas-powered cars by 2035, according to interviews with various state officials.

Inslee announced the mandate in August, later California adopted its own Advanced Clean Cars II rules, which will bar the sale of gas-powered passenger vehicles in that state beginning in 2035. Washington is one of 17 states that follow California’s tougher vehicle emission standards, rather than the less-stringent federal ones. 

“This is a critical milestone in our climate fight. … We’re ready to adopt California’s regs by end of this year,” Inslee tweeted at the time.

The governor’s action builds on a 2008 state law that sets carbon emissions-reduction targets of 45% below 1990 levels by 2030, 70% by 2040 and 95% by 2050. A 2021 Washington Department of Ecology report put the state’s CO2 emissions at 99.57 million metric tons in 2018 and showed that from 2016 to 2018 the transportation sector was the largest contributor at nearly 45% of emissions.

“Electric vehicles are the key technology to decarbonize road transport, a sector that accounts for 16% of global emissions,” a September 2022 International Energy Agency report said. “Recent years have seen exponential growth in the sale of electric vehicles together with improved range, wider model availability and increased performance.”

In broad terms, the state of Washington has two targets regarding gas-powered cars. In its last session, Washington’s legislature set a target of 2030 to encourage residents to wean themselves from gas-powered vehicles. This is not a mandate, but a goal to strive for, Anna Lising, Inslee’s senior climate policy adviser, told NetZero Insider.

“If you don’t have a goal out there, you don’t have the sense of urgency that it needs,” said Rep. Jake Fey (D), chair of the state’s House Transportation Committee.

Sen. Curtis King, ranking Republican on the Senate Transportation Committee, said Inslee and the state government cannot precisely enough predict how the use of EVs will evolve through 2035 to intelligently apply a mandate. “I don’t think it’s reasonable. I don’t think it is necessarily rational. I don’t see how you can foresee all of the challenges of that sort of mandate,” King said in an interview. 

Uncertain Journey

For Washington, the road to 2035 has yet to be mapped out.

The state government does not know how many new charging stations and types of new chargers will be needed by 2035. Sources of electricity and building the extra capacity to deliver that power have to be addressed. Budget estimates have not been calculated. An electric vehicle council of 10 state agencies has been set up to do this sort of planning, but it is still in the organizational stages. 

“As often in public life, we’re building an airplane while we’re flying it,” said Sen. Marko Liias (D), chair of the Senate Transportation Committee.

A study to tackle those questions is in the works, but its findings won’t be delivered to the legislature until December 2023, according to Lising and Loren Othon, alternative fuels program manager at the Washington Department of Transportation.

At least three types of EV chargers must be considered in any plan, including those at drivers’ homes that can operate overnight, chargers at workplaces where employees can power up their vehicles over a workday, and charging stations for traveling vehicles along highways. The federal government is partly addressing charging stations along interstate highways through the National Electric Vehicle Infrastructure (NEVI) funding program. (See West Coast NEVI Plans to Charge up I-5 … and Beyond.) 

Ideally, stations of at least four chargers each should be located every 50 miles along the state’s highways, Othon said, a view that aligns with NEVI program requirements. She noted that Washington’s highways weave into remote corners of the state — through places like isolated small towns such as Twisp deep in the Cascade Mountains, Republic near the Canadian border, and Walla Walla alone in southeast Washington.

Rural Eastern Washington will find meeting the 2035 target especially challenging with its very small number of electric cars and charging stations.

Washington has roughly 2.8 million registered cars, the 11th highest number in the U.S. The state had about 109,000 EVs in mid-October, according to the Washington State Department of Licensing. That is the fourth highest number in the nation behind California, Texas and Florida, according to the U.S. Department of Energy. 

King County and Puget Sound are home to the bulk of Washington’s electric vehicles, according to figures from Washington’s Department of Transportation. King County had 56,252 electric vehicles, followed by Snohomish County at 11,972 and Pierce County at 8,357. Thurston, Kitsap and Whatcom counties had between 4,105 and 2,811 electric vehicles.

East of the Cascade Mountains, Spokane County had the most electric vehicles at 2,778, followed by Benton County at 1,347.

Othon noted that people are anxious about being caught in rural areas without chargers. The ranges of the 10 cheapest electric cars vary from 100 to 275 miles, according to reviews by “Car & Driver.” Meanwhile, businesses are reluctant to install charging stations in rural areas with few customers, Othon said. 

“We’re in a chicken and the egg situation, and we need more chickens and eggs,” she said.

Othon, Lising, Liias and Fey acknowledged that market developments will be also factor into whether Washington achieves its 2035 goal.

“We’ve seen the price of electric vehicles drop precipitously,” Lising said. Fey said those prices need to shrink to levels to where lower-income people can afford them.

“Passenger electric cars are surging in popularity,” the IEA report said. “The IEA estimates that 13% of new cars sold in 2022 will be electric. … However, electric vehicles are not yet a global phenomenon. … Electric car sales reached a record high in 2021, despite supply chain bottlenecks and the ongoing COVID-19 pandemic. Compared with 2020, sales nearly doubled to 6.6 million (a sales share of nearly 9%), bringing the total number of electric cars on the road to 16.5 million.”

Prices for EVs are still prohibitively high for many drivers. The “Car & Driver” reviews show that the second to 10th cheapest models of electric cars range from $30,750 to $42,525. The cheapest model — the Nissan Leaf — sells for $28,495 with a range of 149 miles between charges. Expanding the Leaf’s range to 226 miles costs an extra $5,000.

Grid Support

During last spring’s session, Washington lawmakers appropriated $69 million to build charging stations and other infrastructure in areas of obvious need. Although the full formal report on the state’s electric vehicle needs — and accompanying financial estimates — is not due until December 2023, legislative leaders expect bits and pieces of information be released during the 2023 session that begins in January. Liias and Fey said some preliminary groundwork around additional stations could be tackled next year while waiting for the full report. 

King says hybrid vehicles have been ignored by the legislature and thinks incentives for them should be addressed in the 2023 session.  He also worries that a push for new charging stations will take money away from maintenance of highways and bridges.

Liias and Fey don’t believe state taxes and fees will significantly increase to pay for new charging stations and grid infrastructure. They and Lising said revenues generated by the state’s cap-and-trade program, passed last year, will likely pay for much of the infrastructure costs. Fey speculated that funding for other state decarbonization programs might have to be sacrificed to pay for the charging stations.

Washington will also have to address whether it has enough electricity to power the vast number of new charging stations envisioned to be in place by 2035, Fey and King said. “We’ve got to make sure the grid is set up properly,” Fey said.

King added that the manufacture and disposal of electric cars’ batteries needs to be studied. The state needs to look at the carbon footprint of mining lithium for car batteries and of manufacturing, as well as identifying locations and protocols for burying old batteries, he said.

“Those are elements that no one wants to talk about,” King said.

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Proposed ERCOT Market Redesigns ‘Capacity-ish’ to Some

Texas regulators threw another curveball at ERCOT market participants last week, backing away from a market design they seemed to favor a year ago and moving toward a hybrid model recommended by commission staff.

Following an external consultants’ review of the Public Utility Commission’s proposed market redesign, staff urged the commissioners to pursue a performance credit mechanism (PCM) that requires load-serving entities to buy performance-based credits from generation resources. (54335).

Staff told the PUC during Thursday’s open meeting that the PCM design has elements similar to the load-serving entity reliability obligation (LSERO) that commission Chair Peter Lake has frequently pushed, but that it also introduces features “more consistent” with ERCOT market principles. Staff pointed to earned accreditation rather than an upfront administrative process as one example.

Staffer Ben Haguewood said PCM draws on “complementary elements” from other proposals in the commission’s blueprint, released last December. The blueprint recommended several design changes to “ensure sufficient dispatchable” generation is available in the ERCOT market to “meet reliability needs during a range of extreme weather conditions and net load variability scenarios.” (See PUC Forges Ahead with ERCOT Market Redesign.)

The PCM was one of six market designs that Energy and Environmental Economics (E3) and subcontractor Astrapé Consulting have been reviewing and modeling since the spring. It establishes a reliability standard and corresponding quantity of performance credits (PCs) that must be produced during the highest reliability risk hours to meet the standard.

LSEs can purchase PCs, awarded to resources through a retrospective settlement process based on availability during hours of highest risk, according to their load-ratio shares during those same periods. This allows generators and LSEs to trade PCs in a voluntary forward market, E3 said. Generators must participate in the forward market to qualify for the settlement process.

Alison-Silverstein-2022-11-01-(RTO-Insider-LLC)-FI.jpgAlison Silverstein, Silverstein Consulting | © RTO Insider LLC

“This study confirms that we can achieve even more dramatic improvements in reliability with minimal cost impact to consumers,” Lake said in a press release. “By combining the best elements of each design model into the [PCM], we create a system that ensures enough electricity when we need it most while incentivizing construction of new plants to deliver reliable power to Texas homes and businesses.”

Energy consultant Alison Silverstein told RTO Insider Friday that she was still working her way through the report but said she was concerned that neither the PCM nor the LSERO “give a clear, multi-year forward set of revenue” that would really spark investors’ interest.

“We don’t know what those critical hours are and the level of scarcity and what the price is going to be until afterwards. At the start of the year, the hours that you think might have been great might not be critical,” she said.

“We’ve already set up a scarcity price mechanism to pay more during hours of scarcity,” Silverstein said, referring to ERCOT’s operating reserve demand curve. “The PCM wants to pay for existing generators for the same hours, so it looks to me like it’s a double payment for performance during tight hours. That’s great for existing generators, but I’m not sure that it’s good for accepting an incremental increase over [the PUC’s first phase of market changes last year], which is like throwing money at existing generators.”

‘Detail Devils’

Beth Garza, a senior fellow with R Street Institute and ERCOT’s former market monitor, said there are rarely right or wrong answers when designing a market but “merely choices that will have consequences.”

“Ever the optimist, I think the PCM can be a workable mechanism,” she said. “The detail devils include one, capacity accreditation and two, the definition and number of ‘high-risk’ hours. I am also optimistic that PCM could provide another incentive for loads to consider their consumption during times of potential supply scarcity.”

E3 and Astrapé compared each of the six market designs against ERCOT’s status quo energy-only construct. They said the current design results in a 1.25 loss-of-load expectation, above the industry standard of 0.1 days/year, and that it would retire 11.3 GW of thermal resources because of an assumed significant level of renewable and storage additions.

For its part, E3 recommended a forward reliability market (FRM) design that Stoic Energy principal Doug Lewin called a “straight-up forward capacity market.”

“Capacity-ish,” Silverstein said. “I don’t think they’ve found the magic solution.”

Market design alternatives (E3 Consulting) Content.jpgComparisons of the market design alternatives. | E3 Consulting

 

The FRM design establishes a reliability standard and identifies the reliability credits — assigned to resources using marginal effective load-carrying capability (ELCC) — needed to meet the standard. The forward market’s reliability credits would be centrally cleared by ERCOT based on a sloped demand curve, with costs allocated to LSEs based on pro-rata consumption during the highest reliability risk hours.

The PCM, LSERO and FRM constructs would add an incremental 5.6 GW of natural gas capacity, as compared to ERCOT’s current design, the study said. That would improve the LOLE to 0.1 at an incremental cost of $460 million over the energy-only construct’s total customer costs of $22.3 billion in 2026.

The study also looked at the backstop reliability service (BRS) and dispatchable energy credits (DECs), both proposed by the PUC last December, and a hybrid that merged both designs. The BRS would produce results similar to the forward-market designs at an incremental annual cost of $360 million; when combined with DECs, the costs rise to $920 million a year.

The DEC proposal’s eligibility criteria would reduce natural gas generation, according to the study, increasing the LOLE to 2.03.

Silverstein was among several analysts who noted the study looked at winter peak loads across 40 historical years (1980-2019) but did not include the 2021 winter storm that came within minutes of collapsing ERCOT’s grid. E3 said incorporating the extreme event as an “appropriate probability” was beyond the study’s scope.

She said the “strip of weather” E3 used also did not include this summer’s unending heat waves that led to dozens of new records for demand.

“They guarantee that they’re not going to get the conditions that are more challenging for reliability. And in so doing, they say, ‘Look, we have great reliability results,’” she said. “They’re doing that against a three-foot wet bar instead of a six-foot reservoir that is gradually, inexorably rising higher almost every year, in terms of the magnitude of extreme weather events. They’re not a valid test of whether these mechanisms will help us in what are the next set of heat waves.”

Silverstein was also critical of the study’s exclusion of battery storage, which is increasingly accounting for new requests in ERCOT’s generator interconnection queue. E3 included storage with wind and solar in netting out the resources from total demand in the models.

“Storage is a resource, not a bad thing, and it’s totally controllable. So why would you set it up?” she said. “We’re gonna have a crap ton of it. Storage is way too important a resource to play games with it.”

Silverstein, ERCOT’s Independent Market Monitor and other stakeholders will all have an opportunity to comment on the proposed market designs, which have largely been discussed and drafted this year behind closed doors. Staff drafted an initial set of questions that included:

  • Would the PCM, having not been implemented anywhere else, present a significant obstacle to operating the ERCOT market?
  • Would the PCM incent generation performance, retention and market entry?
  • Is the 1-in-10 loss-of-load expectation a reasonable standard?
  • Does ERCOT centrally clearing the market mitigate the risk of market power abuse?
  • Should a short-term “bridge” product or service to be used to maintain system reliability should a market design be adopted that needs several years to be implemented?

Commissioner Lori Cobos added a question to the list related to the PCM’s costs — but not without some pushback by PUC Chair Lake.

“So you’re not satisfied with the cost analysis provided by E3?” Lake asked during the commission’s discussion.

“I would like for the stakeholders and the public to evaluate that cost run and give us their thoughts on the cost impacts of the PCM,” Cobos responded. “I would like the public, that’s going to be incurring costs with respect to this market redesign, to let us know what they believe are the cost impacts because we can’t just take the E3 cost-impact analysis at face value. We need to hear from the stakeholders in the market that are going to be operating in this market design.”

“Nobody up here is taking anything from E3 at face value,” Lake said, pointing to the hours the commission spent with its consultants “poking, prodding, questioning all of the inputs, all of the assumptions.”

“I don’t want the public to think that, in any way, this is just slapped together with some duct tape. This is hours and hours, months of analysis, iteration, and feedback to get to the assumptions that go into this baseline model,” Lake said. “That being said, no model is perfect, and no model can guarantee future outcomes. It’s, at best, an approximation with the best information we have on what future scenarios may look like,” he said.

The commission is limiting public comments and feedback to the E3 study, the PUC’s blueprint for market design and the commission staff’s memo. Comments are due by noon Dec. 15.

The PUC said it will review and “consider” public comments and feedback in preparing its final design plan. That design will then be shared with the Texas Legislature, which begins its 2023 session Jan. 10.

The state Senate’s Business & Commerce Committee will get a first crack at the proposal when it holds a hearing Thursday on the ERCOT market.

PUC Sides with ERCOT Board

The commissioners also agreed on a statement of input in response to ERCOT’s proposed bylaw amendment that eliminates corporate members’ right to vote on future proposed amendments to the governing documents (52933).

ERCOT in September requested market participants’ feedback on a bylaw amendment proposed by the Board of Directors. The ISO received nine sets of comments, many of which “disagree with the board’s proposal,” General Counsel Chad Seely told the PUC. (See ERCOT Stakeholders Wait on Bylaw Amendment Changes.)

Noting that the state law requires that ERCOT bylaws reflect the commission’s input, the PUC said the board is empowered to amend its bylaws without obtaining its members’ affirmative vote and that the board has the sole authority to make bylaw changes, subject only to the commission’s approval.

Legislation passed in the wake of last year’s winter storm replaced ERCOT’s 16-member hybrid board that included directors from various market segments with an 11- member independent body without segment representatives. It also created a selection committee, comprised of representatives appointed by political leadership, to find and nominate the independent directors.

“The legislation from the last session made it absolutely, abundantly clear … that ERCOT ought to be governed by the independent board that is selected by the selection committee,” said Lake, who filed a memo in the docket. “The bottom line is while our market participants and corporate members play a critical role and offer a unique insight that no other source can provide, the legislature was clear that they need to continue to contribute to the ERCOT market process and be a part of those deliberations, but they can no longer control the market in which they generate profits.”

The commission agreed with a modification to the amendment clarifying that the stakeholder Technical Advisory Committee, which makes recommendations to the board, cannot be eliminated unless directed by the commission.

Commissioner Jimmy Glotfelty said he has seen RTOs become “extremely powerful and insulated” and organizations where “many projects go to die.”

“Not this [grid operator] … I believe it’s our responsibility in conjunction with [ERCOT] to make sure that they’re all doing what we see fit to ensure that we have a functioning reliable and economic marketplace and that the bylaws, that input from TAC, are part of that process,” Glotfelty said. “The professionals on the board that come from power and gas know that they don’t know everything, so having TAC, having industry input, will be critically important for them as we go forward.”

Entergy Plant Approved

The commission approved Entergy Texas’ (NYSE:ETI) application to build its 1.22-GW Orange County Advanced Power Station in MISO South’s Texas footprint Southeast Texas, siding with an administrative law judge’s decision to remove the plant’s hydrogen capabilities (52487).

The PUC, citing rising labor costs and other inflationary pressures, removed a cost cap imposed during an administrative law judge’s approval of the project in September, saying it will revisit cost increases in a future rate case. The project’s costs have already risen from $1.19 billion to $1.58 billion in a year. (See “Entergy Power Plant not Considered,” Texas PUC Briefs: Nov. 3, 2022.)

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Judges Skeptical of Capacity Sellers in PJM Offer Cap Dispute

An attorney for Vistra (NYSE:VST) and other capacity sellers faced skeptical questioning from the D.C. Circuit Court of Appeals last week in a bid to overturn FERC’s September 2021 ruling changing PJM’s offer cap rules.

Vistra and attorneys for FERC, PJM and its Independent Market Monitor presented arguments to Judges Judith W. Rogers, Patricia Millett and J. Michelle Childs during a 70-minute hearing Nov. 8 (21-1214).  

In March 2021, the commission ordered PJM to revise its market seller offer cap (MSOC) in response to a complaint by the Monitor, which said the original cap was too high because it erroneously assumed the RTO would annually experience 30 performance assessment hours — emergency hours when capacity sellers face penalties for underperforming. (See FERC Backs PJM IMM on Market Power Claim.)

Six months later, the commission replaced PJM’s single default offer cap with several default caps applicable to different generation technologies (EL19-47). PJM and capacity sellers sought rehearing, with the RTO arguing that the commission’s decision could lead to over-mitigation of the market. (See PJM Requests Rehearing of MSOC Change.)

Vistra said the prior rules allowed sellers to include opportunity costs in their offers, even if the offer is above the seller’s avoidable costs.

In its brief to the D.C. Circuit, Vistra said that FERC could have corrected the MSOC by changing the assumed emergency hours to 20 hours or less.

“Instead of fixing the miscalibrated assumption … FERC abandoned an opportunity cost-based offer cap altogether, without explanation or even acknowledgment, in favor of an offer cap based solely on a flawed calculation of projected operating costs,” it said.

Under the new rules, Vistra said, the commission gave “precedence to the Market Monitor’s alternative version of the supplier’s offer and requires the supplier to make a filing with FERC to challenge the Market Monitor’s version of the supplier’s offer.” Vistra said that violates capacity sellers’ rights under Federal Power Act Section 205 to file rates and terms for services rendered.

Rogers challenged Vistra attorney Paul Hughes’ argument that the commission failed to adequately explain its ruling.

“I think some of the statements in your brief are a little misleading,” she said. “I mean, it’s fine if you don’t agree [with FERC’s conclusion] if you give us reasons. But that’s different from saying FERC never responded, or never addressed the alternatives, when clearly — when you read its order and order on rehearing — it did.”

PJM attorney Paul M. Flynn argued that FERC’s ruling upset the balance between consumers and market sellers.

“We want to make sure that there is no exercise of market power, but where there is a real legitimate cost a supplier has, we want to make sure they have reasonable opportunity to include that in their capacity price,” he said. “FERC overshot. It went dramatically away from the Capacity Performance construct.”

FERC attorney Matthew Estes said Vistra was erroneously contending “the commission has given the Market Monitor the ability to set the offer cap.”

“That’s not correct. The tariff gives the suppliers the ability in the first place to propose an offer cap based on the formula. The Market Monitor simply reviews that offer to see if it complies with the tariff. And ultimately, if the supplier disagrees with what the Market Monitor determines, it can go to the commission and ask the commission to decide what cap complies with the tariff.”

In such a dispute, said Jeffrey W. Mayes, general counsel for IMM Monitoring Analytics, “we would bear the burden of proof to show that the offer was unjust and unreasonable — that it was not competitive.”

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California PUC Revisits Net Metering Plan

The California Public Utilities Commission released a new net metering plan Thursday after months of controversy over its prior efforts to cut payments to rooftop solar owners for exported electricity and to charge them grid-connection fees.

The latest proposal tries to strike a balance between the competing demands of the solar industry and an alliance of investor-owned utilities and ratepayer advocates. The solar industry argues that reducing the state’s generous incentives will undermine solar adoption, while the utilities and ratepayer advocates say the state’s current net-metering scheme shifts billions of dollars in costs from those who can afford rooftop solar to those who cannot.

The CPUC is working under a legislative mandate to revise the state’s net energy metering (NEM) tariff by next year.

Under the latest plan, the existing “net energy metering tariff and its sub-tariffs are revised to balance the multiple requirements of the Public Utilities Code and the needs of the electric grid, the environment, participating ratepayers, as well as all other ratepayers,” the Nov. 10 proposed decision says.

The new plan would not change the credits paid to current rooftop solar owners for excess electricity they export to the grid. Utilities compensate those homeowners at full retail electricity rates, which are much higher than the costs of utility-scale solar.

The subsidies are credited with making California the nation’s leader in rooftop solar over the past 25 years.

“Since 1997, California has supported the rooftop solar market through its NEM tariffs, which have enabled 1.5 million customers to install more than 12,000 megawatts of renewable generation,” the CPUC said in a news release.

The CPUC’s prior net metering reform proposal, issued in December 2021, would have slashed NEM bill credits by more than half and possibly up to 80%. (See California PUC Proposes New Net Metering Plan.)

Under the new proposal, future rooftop solar owners would be compensated differently from existing customers.

“In the successor tariff, the structure of the [current NEM] tariff is revised to be an improved version of net billing, with a retail export compensation rate aligned with the value that behind-the-meter energy generation systems provide to the grid and retail import rates that encourage electrification and adoption of solar systems paired with storage,” the proposed decision says.

“The successor tariff applies electrification retail import rates, with high differentials between winter off-peak and summer on-peak rates, to new residential solar and storage customers instead of the time-of-use rates in the current tariff,” it says. “The successor tariff also replaces retail rate compensation for exported energy with Avoided Cost Calculator values that vary according to grid needs.”

A fact sheet accompanying the proposed decision says the new rate structure would encourage customers to install battery storage so they can store solar electricity generated in the daytime and sell it to the grid on hot summer evenings, when prices are higher, and the state needs it most for reliability.

Strained grid conditions in the past three summers occurred during heat waves when solar ramped down in the evening but demand remained high from air conditioning use.

The state legislature approved $900 million in funding this year to spur adoption of rooftop solar and battery storage, including $630 million for lower-income households. Those who install solar or solar coupled with storage in the next five years will receive extra payments.

“Customers lock in these extra bill credits for nine years,” the CPUC said in the fact sheet.

The solar industry would benefit by selling more storage along with solar arrays, it said.

The new plan removes a controversial provision contained in the December proposal to impose an $8/kWh grid charge on solar customers’ bills, averaging about $48 per month for residential customers.

The CPUC estimated that under the new plan, residential customers installing solar will save an average of $100 a month on their electricity bills, and those installing solar and batteries will save $136 a month or more.

“With these savings … customers will fully pay off their solar systems in just nine years or less,” the CPUC said in the fact sheet.

Neither Side Happy

Both the solar industry and investor-owned utilities expressed dissatisfaction with the plan last week.

The California Solar and Storage Association said in a news release that “based on an initial analysis the [Nov. 10 proposal] would cut the average export rate [for rooftop solar] in California from $0.30 per kilowatt to $0.08 per kilowatt and make those cuts effective in April 2023, resulting in a 75% reduction in value of exports.”

The trade group’s executive director, Bernadette Del Chiaro, said in the statement that the “CPUC’s new proposed decision would really hurt. It needs more work, or it will replace the solar tax with a steep solar decline. An immediate 75% reduction of net energy metering credits does not support a growing solar market in California.

“If passed as is, the CPUC’s proposal would protect utility monopolies and boost their profits, while making solar less affordable and delaying the goal of 100% clean energy,” she said

Affordable Clean Energy for All, an advocacy group that includes the state’s three large investor-owned utilities, said the plan does not go far enough.

“The CPUC’s new proposed decision released today fails to make the meaningful reform necessary to ensure that all electricity customers, those with rooftop solar and those without, pay their fair share of the costs for electric grid reliability, wildfire mitigation and other state mandated programs that benefit all Californians,” the group said in a news release.

“It is extremely disappointing that under this proposal, low-income families and all customers without solar will continue to pay a hidden tax on their electricity bills to subsidize rooftop solar for mostly wealthier Californians,” the group’s spokesperson Kathy Fairbanks said in the news release.

Parties have 20 days to comment on the proposal. The CPUC plans to take it up for the first time at its Dec. 15 voting meeting.

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Biden at COP27: Nations Must Step up, Double-down on Climate Action

Under new U.S. policies, federal contractors will have to disclose their greenhouse gas emissions and climate risks, and natural gas producers will have to respond quickly to reports of large methane leaks, President Biden announced at the U.N.’s 27th Conference of the Parties (COP27) in Sharm el-Sheikh, Egypt, on Friday.

“As the world’s largest customer, with more than [$630 billion] in spending last year, the United States government is putting our money where our mouth is to strengthen accountability for climate risk and resilience,” Biden said of the administration’s new guidelines for federal suppliers.

In a speech that highlighted his administration’s commitments to climate action at home and abroad, the president called on all countries to both raise their targets for emissions reductions and accelerate their progress toward achieving them.

“To permanently bend the emissions curve, every nation has to step up,” Biden said. “The United States is acting. Everyone has to act. That’s the duty and responsibility of global leadership.”

Current economic and political challenges — inflation, food and energy insecurity, and Russia’s invasion of Ukraine — make it “more urgent than ever that we double-down on our climate commitments,” Biden said. “True energy security means that every nation … is benefiting from a clean, diversified energy future” in which no country can “use energy as a weapon and hold the global economy hostage.”

He told a full conference hall, “with confidence,” that the U.S. would meet its commitment to reduce its emissions 50 to 52% below 2005 levels by 2030, the goal he set shortly after taking office in 2021. The U.S.’ flagship climate law, the Inflation Reduction Act, is expected to cut emissions 40%, according to estimates from the U.S. Department of Energy.

He also pointed to the U.S.’ recent ratification of the Kigali Amendment, which commits the country to cutting its use of hydrofluorocarbons — a potent greenhouse gas commonly used in air conditioning and refrigeration — by 45% by 2024 and 85% by 2036.

With the passage of the IRA, “we are proving that good climate policy is good economic policy,” Biden said. “It’s a strong foundation for durable, resilient, inclusive economic growth. It’s driving progress in the private sector. It’s driving progress around the world.”

Focusing on U.S. support for Africa, Biden announced a $500 million package, financed by the U.S., the EU and Germany, “that will enable Egypt to deploy 10 GW of renewable energy by 2030, while bringing offline 5 GW of inefficient gas-powered facilities.” The initiative will cut Egypt’s emission’s 10% and allow the country to increase its climate commitments, Biden said.

“If countries can finance coal in developing countries, there is no reason why we can’t finance clean energy in developing [countries],” he said.

He also pointed to “a partnership between American firms and the government of Angola to invest $2 billion to build new solar projects” in the country.

Biden’s announcements were primarily targeted at climate adaptation and mitigation, as opposed to the more sensitive issue of “loss and damage,” a key theme during the conference.

The issue turns on developing countries’ argument that while they produce only a small portion of the world’s greenhouse gases, they are more vulnerable to the impacts of climate change. Developed countries, who produce the majority of the world’s greenhouse gases, should therefore pay developing nations restitution for the loss and damage they have experienced from extreme weather events fueled by climate change.

While not mentioned in the president’s speech, Special Climate Envoy John Kerry earlier in the week included loss and damage in a list of climate initiatives the U.S. hoped to push forward at the conference.

Other funding the president announced included a doubling of U.S. contributions to support climate adaptation in developing countries from the $50 million pledged last year at COP26. The U.S. will also provide an additional $150 million for a range of adaptation initiatives across Africa, under the President’s Emergency Plan for Adaptation and Resilience (PREPARE), Biden said.

The funds will be used, in part, for an early warning system to alert countries to potential extreme weather events and other climate-related disasters, and to bolster adaptation programs aimed at increasing food security.

Federal Supplier Rules

The administration rolled out a range of climate-related initiatives in the week leading up to the president’s address in Sharm el-Sheikh, including the new proposed Federal Supplier Climate Risks and Resilience rule and more aggressive regulations for cutting methane emissions.

According to information from the White House Council on Environmental Quality (CEQ), the proposed emission reporting requirements for federal suppliers would depend on the amount of business they do with the government. Suppliers with contracts in excess of $50 million would be required to report on their Scope 1, Scope 2 and “relevant categories” of their Scope 3 greenhouse gas emissions, as well as on their climate-related financial risks, and set “science-based emission reduction targets.”

Scope 1 emissions are direct emissions from a company’s operations and owned assets, including emissions from a business’s vehicle fleet. Scope 2 covers emissions from the energy a company purchases, including electricity; while Scope 3 are the indirect emissions generated up and down a company’s value chain and not under the company’s direct control.

Federal suppliers with contracts between $7.5 million and $50 million would only have to report their Scope 1 and 2 emissions, and smaller suppliers, with contracts under $7.5 million, would be exempt from the requirements.

The CEQ’s announcement said that, like other sectors of the economy, the federal government has been affected by supply chain disruptions over the past year. The proposed rules “would strengthen the resilience of vulnerable federal supply chains, resulting in greater efficiencies and reduced climate risk.”

According to the White House, since the federal government adopted its own climate goals, energy use from buildings and vehicles has dropped 32%, with savings estimated at $11.8 billion per year.

A 60-day comment period on the proposed rules will close on Jan. 13, 2023, the CEQ said.

Super-emitter Program

The new proposed rules for cutting methane emissions from the oil and gas industry are part of an updated plan for increasing U.S. methane emissions reductions under the Global Methane Pledge launched last year at COP26.

Led by the U.S. and European Commission, the pledge is aimed at cutting methane emissions worldwide 30% below 2020 levels by 2030. At present, more than 130 countries have joined the pledge. A major driver of climate change, methane is 80 times more potent at trapping heat than carbon dioxide for the first 20 years it is in the atmosphere.

The new proposed regulations, released by EPA, would ensure regular monitoring of all well sites for leaks, while also providing “industry flexibility to use innovative and cost-effective methane detection technologies, and a streamlined process for approving new detection methods as they become available.”

In addition, a super-emitter response program would leverage “remote methane detection technology to quickly identify … large-scale emissions for prompt control.”

Backing up the proposed rules, EPA will also use $1.55 billion from the IRA to provide financial and technical assistance for emissions monitoring and reduction, including $700 million for conventional wells with only marginal production.

EPA said the proposed rules are based on extensive input from industry stakeholders and close to half a million public comments. A new public comment period on the rules will run through Feb. 13.

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Pa. PUC Opens Proceeding on EV Rate Design

Pennsylvania regulators Thursday opened a rate design proceeding to encourage electric vehicle charging during off-peak hours.

Responding to a petition by a coalition of EV stakeholders and environmental groups, the Public Utility Commission voted unanimously to create a working group to provide the commission with recommendations by March 31, 2023 (P-2022-3030743). The commission’s directive calls for the issuance of an order responding to the recommendations by June 1, 2023.

The coalition, ChargEVC-PA, called for the proceeding in a petition filed Feb. 4, saying EV charging “will dramatically increase peak demand on the distribution system unless charging is directed to off-peak periods.”

“The significant increase in consumption due to EV charging has the potential to reduce system costs and rates for all customers because the fixed costs of the distribution system will be collected over a much larger number of kilowatt-hours,” said the group, whose members include the Electrification Coalition, Keystone Energy Alliance, Natural Resources Defense Council, Plug In America, Sierra Club and Gettysburg-based Adams Electric Cooperative.

Obstacle

The petition cited the state Department of Environmental Protection’s Electric Vehicle Roadmap, which identified as an obstacle the lack of utility rates designed to encourage EV adoption.

“Only two Pennsylvania companies offer time-varying (such as time-of-use, or TOU) rates for the supply portion of the bill (Duquesne [Light Co.] and, more recently, PECO [Energy]), and none of the electric distribution companies in Pennsylvania offers TOU rates for the delivery portion of the bill,” the group said. “Moreover, the TOU rates that Duquesne and PECO offer are for ‘whole house’ use. The roadmap recommends a strategy to advance EV deployment, where ‘each utility and electricity supplier could be encouraged to analyze and propose rate designs based on their own peak periods, timelines for introducing advanced meters, and other considerations and constraints.’”

Only 29,000 of the more than 12 million registered vehicles in Pennsylvania are electric, a penetration rate of less than 1%. But the group cited data showing global EV sales increased 41% in 2020 and projections that EVs will represent 25 to 30% of total sales by 2030 and 45 to 50% by 2035 as falling battery prices bring EVs to purchase price parity with internal combustion engine vehicles.

Pa EV Sales by Year (Pa Department of Environmental Protection) Content.jpgPennsylvania electric vehicle sales by year | Pennsylvania Electric Vehicle Roadmap, 2021 Update, Pa. Department of Environmental Protection

 

Pennsylvania expects to receive $171 million over five years from the Infrastructure Investment and Jobs Act to help build out an EV charging network.

The five PUC commissioners approved a joint motion by Chair Gladys Brown Dutrieuille and Vice Chair Stephen DeFrank, with Commissioner Ralph Yanora issuing a supporting statement saying the resulting rates should be “cost-based” and “not include subsidies.”

Commissioner Kathryn Zerfuss also issued a statement, saying that “affordability and equity should be paramount” in any resulting rates. “Our commonwealth should be a leader — proceeding without delay — to demonstrate to the federal government that our actions are deliberate and meaningful, so that we can maximize all potential federal funding available to Pennsylvania for EV infrastructure,” she said.

Other States’ Actions

The petition by ChargEVC-PA included descriptions to rate design initiatives by regulators in Arizona, Maryland and Minnesota.

Baltimore Gas and Electric, PEPCO, and Delmarva Power and Light told Maryland regulators last year that participants in their EV rate design pilot projects had responded to TOU rates by reducing and shifting consumption, with savings of 5.3 to 9.7% in the first year and 2.3 to 7.5% in the second year. The pilots also reduced peak demand in the summer season by 9.3 to 13.7% and by 4.9 to 5.4% for the non-summer season, the utilities reported.

In January, the Maryland Public Service Commission approved changes to the state’s pilot programs (Case No. 9478; Order No. 90036). “With two years remaining in the pilot, the commission recognizes the need to pivot toward deployment strategies that lean into charging gaps in order to engage a more diverse customer base to better understand different charging patterns,” it said. “The decision today reflects a measured approach, where the commission considered the proposals’ objectives along with potential impacts on the competitive market and cost implications for ratepayers.”

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Appellate Judge Presses FERC on End-of-life Transmission Planning

PJM stakeholders asked a federal appellate court Wednesday to require the RTO to exercise more oversight over transmission owners’ end-of-life (EOL) projects, saying some of the replacements should be subject to regional planning and competition.

The D.C. Circuit Court of Appeals heard 80 minutes of oral arguments in a challenge to commission rulings that EOL projects are the exclusive province of the transmission owners (20-1449).

In August 2020, the commission accepted a TO-initiated filing adding EOL projects to the planning procedures of tariff Attachment M-3 (ER20-2046). Four months later, the commission rejected proposed tariff changes supported by stakeholders including American Municipal Power, LS Power and consumer advocates that would have moved such projects under the RTO’s planning authority. The commission upheld its rulings last August. (See FERC Rejects Challenges to Decision on EOL Projects in PJM.)

“When the need arises because a facility has been retired, we want PJM to be involved in deciding: Is that a need that gives rise to a plan or a project with regional benefits, in which case it should be regionally planned?” Erin Murphy, an attorney for appellants, told the D.C. Circuit panel, which comprised Judges Neomi Rao, J. Michelle Childs and David Tatel. “Or maybe it is a project that’s local and can be locally planned. What we don’t want is a world in which transmission owners get to make that decision for themselves and decide to locally plan projects, even when as here it’s clear that they actually have projects with regional benefits.”

The appellants said FERC’s rulings result in balkanized planning for EOL projects. In 2018, they noted in a brief, “there were $8.5 billion worth of transmission projects planned, with the largest driver being the need to address end-of-life conditions.”

Speaking on behalf of the TOs, attorney John Longstreth said PJM already has authority to override local EOL projects when there’s an overlap between the local project and a regional project. “PJM gets to plan that project. … We can’t stop that,” he said. “So that protects this regional planning authority.”

In rejecting rehearing, FERC concluded that the Consolidated Transmission Owners Agreement (CTOA) with PJM was “ambiguous” as to planning EOL projects. But the commission sided with the TOs, noting that they had continued to plan EOL projects after the agreement was signed, “with PJM’s acquiescence.”

Rao pressed FERC attorney Susanna Chu on why the commission did not consider the justness and reasonableness of the local planning of EOL projects. Locally planned projects are allocated only to a TO’s zone rather than regionally.

“FERC’s position here seems to me very peculiar,” Rao said. “By choosing the transmission owner proposal, you are choosing one particular allocation of cost. And then why isn’t it incumbent on FERC to determine whether that cost allocation is just and reasonable?”

Chu responded that the rulings did not involve complaints over cost allocation. “The commission accepted it as just and reasonable, but on the basis that it didn’t change the status quo — the existing cost allocation remained the same,” Chu responded.

“Actually, on FERC’s view, it did change the status quo,” Rao shot back. “So at least, at a minimum, FERC’s internal reasoning is unreasonable, maybe, or arbitrary and capricious.”

The TOs intervened to challenge FERC’s description of the CTOA as ambiguous, saying it “interferes with and adds uncertainty to” the transmission planning process. FERC said the TOs’ claim should be dismissed because they failed “to demonstrate that they have suffered any concrete injury.”