Page 464 – RTO Insider

June 22, 2022November 8, 2023

California Study Takes Read on Heat Pump Views

Widespread adoption of heat pump water heaters in California has been stymied by a preference for tankless water heaters among homeowners, who may feel that a heat pump appliance is a “step backward,” a new report says.

The California Public Utilities Commission last week announced release of the report, which is a market study of electric heat pump appliances in the state.

“It feels like a step backward when you have a HPWH [heat pump water heater], because you have this giant tank that takes up space and then it’s losing heat,” said a builder who was interviewed as part of the study. “That’s going to be a hard move for consumers.”

In addition to taking up more space than a tankless unit, heat pump water heaters can be noisy and cost more upfront than alternatives. And contractors might not be familiar with HPWHs and prefer “business as usual, which has largely been gas tankless water heaters,” the report said.

The report recommended more homeowner education on the benefits of HPWHs, which include a chance to relieve stress on the grid if the appliance is tied in with a demand response program.

Meeting Climate Goals

The focus on heat pump appliances comes as California moves toward building electrification as one way to meet climate goals.

About 12% of California’s greenhouse gas emissions are direct emissions from residential and commercial buildings. And much of that is from space and water heating, CPUC said.

“Heat pump systems provide hot water, heating and cooling using energy from the electric grid, which is increasingly renewable,” the CPUC said in a release.

The goal of the new study was to provide insights that may guide strategies to accelerate adoption of heat pump appliances. The CPUC worked with consultant Opinion Dynamics on the study.

The study examines five electric heat pump technologies: air source heating and cooling heat pumps, heat pump water heaters, ground source heating and cooling heat pumps, heat pump clothes dryers, and heat pump pool heaters.

The report included analysis of past research on heat pump technologies and interviews with a range of stakeholders. The study looked at construction of market-rate and affordable housing, and single-family and multi-family buildings.

Heat Pump Surge Expected

Most of the construction trade representatives interviewed for the study said they expect heat pump installation in new homes to increase substantially over the next five years. That’s due, in part, to the growing number of cities that have banned natural gas in new construction or adopted reach codes encouraging the use of heat pump appliances. A reach code is a city building code that goes beyond minimum state standards.

The trend may be amplified when California’s 2022 Energy Code takes effect on Jan. 1, 2023. (See Calif. Energy Commission Adopts 2022 Building Code.) The code includes a provision requiring developers to install either an electric heat pump water or space heater in new single-family homes. For new multi-family housing, heat pump space heating will be the new standard.

The current market share for electric heat pumps for water and space heating in new homes in California is less than 6%, according to the California Energy Commission.

Another factor increasing demand for heat pump technology is the growing number of homeowners who don’t have air conditioning but now want it. Heat pumps can provide heating and cooling in a single piece of equipment and are “an attractive value proposition,” the report said.

“It’s hard to explain to them the value of heat pumps unless they really, really want the cooling,” said one single-family home architect who was interviewed during the study.

Opportunity Ahead

The report also notes an opportunity for heat pump space heating. Almost half of California homeowners whose main heating source is a natural gas or electric space heating appliance have units that are more than 14 years old, and therefore may need replacing within the next 10 years.

Study consultants also researched heat pump programs in states that are having some success in promoting the technology, including New York, Vermont, Washington, Oregon, Maine and an unidentified Southwestern state.

Staff with those programs said a key to success was developing a strong contractor network, starting initially with a few high-volume companies.

They also advised running marketing campaigns to explain to consumers the benefits of heat pumps and how to use them for the most savings.

Another recommendation was to offer a range of incentives to contractors, such as technical training, continuing education credits or free heat pump units so they can try out the technology in their own homes.

June 22, 2022

Jigar Shah: ‘Oil and Gas Sector Shouldn’t be Vilified’

WASHINGTON — The way Jigar Shah sees it, if the U.S. is to have any chance of decarbonizing the grid, building out transmission or standing up an energy storage supply chain, the clean energy industry has to stop vilifying the oil and gas industry and start answering some hard questions — like whether decarbonizing the grid by 2035 is even possible.

One of the industry’s most provocative thinkers, Shah is now director of the Department of Energy’s Loan Program Office (LPO), where he is making multimillion-dollar decisions about which clean energy startups and projects to invest the government’s dollars. That kind of money means clean energy is no longer the plucky, small disruptor that only has to advocate for itself, Shah said at the American Clean Power Association’s Energy Storage Policy Forum on Wednesday.

In the course of a 30-minute conversation with Jason Burwen, ACP’s vice president for energy storage, Shah set the industry a series of grown-up challenges.

“What responsibility do we have to actually answer … big tough questions, as opposed to saying, ‘I would like to not piss anybody off, so I’m not going to say anything,’ and I’m going to let people think that we can be at 90% renewable energy, and that it’s only an interconnection problem that’s holding us back, which is patently false,” he said.

“How much [do] you allow an uninformed part of your industry to vilify other parts of the industry? The oil and gas sector shouldn’t be vilified,” Shah said. “They actually have a lot of really valuable talents. We don’t know how to run refineries. If these people lose their jobs, and we can’t get them back, we’re screwed. All of us are screwed because you’re not all running electric vehicles yet for your installation crews.

“So, we all need to figure out how to coexist together as we make this transition occur, and that means a deep understanding of how all of these things interplay with each other,” he said.

“Where does LNG fit in the entire [energy] mix? What is the position of this audience? Do we want people to increase coal consumption by 25% over the next two years?” he said. “Because that’s what’s going to happen unless we figure out a way to give Asia the energy that they need to grow.”

20-year Payback

Shah was equally blunt about the industry’s failure to deal with core issues of transmission, equity and the manufacturing supply chain.

“The only thing harder to build than nuclear in this country is transmission, and so come on, we’re not going to [build] three to five times transmission in this country,” he said. “Who in this room actually thinks that’s going to happen by 2035? The lines that we’re building right now, we started 12 years ago.

“So, unless you know which lines you started 12 years ago that are going to solve the problem by 2035, what do you think is going to happen?”

Another example: “We are disrupting 300 communities across the country with coal plants that are getting retired. You’re telling me that all those communities want solar plus storage to go into that interconnection? No, they don’t, because they’re not getting jobs from solar plus storage, and that coal plant actually pays $2 million a year in property taxes. Which one of you is paying $2 million in property taxes? So, we need to figure that out.”

The LPO recently made a conditional commitment of a $107 million loan to Syrah Vidalia, a graphite manufacturer in Louisiana, to expand its plant to provide graphite for enough lithium-ion batteries to power 2.5 million EVs by 2040.

But Shah sees bigger challenges ahead for clean energy supply chains because “our country has not actually done this level of planning and forethought and what we would call industrial policy. That’s where industrial policy is defined by getting an outcome that’s slightly different than where the market would otherwise set,” he said. “We’ve always just said, ‘We want to get the lowest possible price, and if that’s importing it from other countries and not doing anything here, that will do.

“We haven’t manufactured stuff here in 40 years, and so a lot of the supply chain isn’t here — the training colleges, all that stuff that we need, it’s still atrophying. And so, we need to actually go the other way and strengthen it, and all of that gets tied into the Loan Program because we’re taking a 20-year [payback] on those loans, so they’re not going to pay back unless the ecosystem is supportive of that company for 20 years.”

VPPs and Net Metering

Pointing to growing penetrations of solar and wind on the grid, Shah pushed the energy storage industry to think beyond lithium-ion batteries.

“When you think about what storage really looks like in our country, it is all the natural gas that we store every single day in huge salt caverns across the country, and we store it all year for like, bursts of time, right? And so that’s what hydrogen storage is; that’s what pumped hydro is,” he said.

“And so, the question really becomes, as we move to this modern grid, can we also get away from real time: matching that electricity [supply and demand] in a way that is just stressful for everybody?”

Shah also had some insights on the impact of transport and building electrification and the need for virtual power plants (VPPs).

“When you think about utility-scale battery storage, which is where most people are thinking about things these days, we’re going to have to have 800 GWh of automotive battery manufacturing in this country by 2030 to meet the president’s goal” of 50% of all new cars sold being electric.

“There’s no way to integrate those vehicles into the grid without a VPP. You cannot let anyone just charge whatever they want, however, they want, as often as they want without some management of the distribution rate,” he said.

In addition, VPPs might offer a possible solution for state-level battles over net metering reform,” Shah said.

Instead of incremental reform — currently being debated in California — he said, “Why don’t we just immediately let in VPPs and say, ‘If you want to do solar on your roof, you’re only going to get paid 5 cents/kWh, and then you’ll get paid another 7 cents/kWh for the integration within the grid out of VPP. So, you get paid the full 12 cents that you wanted before, but you get paid only if you become a grid resource.’”

June 22, 2022November 1, 2023

Low PJM Capacity Prices No Bargain, Coal & Gas Generators Say

Groups representing gas- and coal-fired generators said Wednesday that the sharp price drop in PJM’s 2023/24 capacity auction is a continuation of trends that threaten the RTO’s long-term reliability.

PJM reported Tuesday that its capacity bill for the year will be $2.2 billion, down from about $4 billion for the 2022/23 delivery year. It was the second year in a row that capacity prices have fallen, with Rest of RTO clearing at $34.13/MW-day, the third-lowest in the history of the Base Residual Auction. PJM said the results were likely depressed by the effective elimination of the minimum offer price rule (MOPR), a tougher cap on generator prices and robust forward energy prices. (See related story, PJM Capacity Prices Crater.)

“While the auction’s low capacity clearing price represents a savings for customers in the short term, these results portend real concerns over adequate compensation for resources needed to support reliability in all conditions and looking forward,” the Electric Power Supply Association said in a statement. “What appears to be developing is a trend where the addition of new supply resources is far outpaced by the retirement of resources that can deliver reliable power in the PJM BRA. Oversimplifying the results of the auction by cheering the lower price for capacity fails to recognize that there is a cost to ensuring the delivery of reliable power, and the most cost-effective way to deliver it is through well functioning markets, not from picking winners and losers among the resources that participate.”

EPSA said PJM’s market rules are undermining capacity price signals, calling on the RTO to “avoid rule changes intended to accommodate specific preferred resources or technologies.”

“The desire by some to defer to the policy choices of 13 states and D.C. to dictate the regional resource mix may seem sound but, in reality, threatens the reliability framework to which consumers of all types have become accustomed and expect as a part of their daily lives,” EPSA said.

The PJM Power Providers (P3) Group, which represents more than a dozen merchant generators in the RTO, was similarly critical.

“The auction-clearing prices are among the lowest they’ve ever been, so the compensation that generators will receive to commit to serving PJM’s region next year is greatly reduced,” P3 President Glen Thomas said in a statement. “However, the requirements they will commit to are more rigorous than ever. Increased obligations for decreased compensation is an incentive to leave the market rather than retain existing resources or attract new ones that will help maintain reliability going forward.”

EPSA and P3 members hold large portfolios of natural gas-fired generation.

Nuclear in the Money

Nuclear plants were big winners in the auction, clearing 5,315 MW more than last year. Solar resources increased 25% to 1,868 MW, while wind resources dropped by 434 MW. Natural gas resources cleared an additional 1,685 MW, while cleared capacity of steam units (primarily coal) dropped by 7,186 MW to 27,682 MW, reflecting a decrease of 7,813 MW offered into the auction because of plant retirements.

Coal trade group America’s Power said the auction will likely cause more coal retirements.

“PJM’s coal fleet was already expected to decline by half (more than 24,000 MW of announced coal retirements by 2030) even before the auction,” CEO Michelle Bloodworth said in a statement. “In addition, EPA regulations are expected to cause even more coal retirements, especially during the 2026-2028 time frame.”

Bloodworth reiterated the group’s request that PJM study how its reliability would be affected if half or more of its coal fleet retires by 2030, saying more coal retirements could also cost ratepayers when gas prices spike.

“We continue to urge PJM and other grid operators to value the reliability, resilience and affordability attributes of coal,” Bloodworth said. “Doing so would help put coal on a more level playing field with other resources that are receiving federal and state subsidies.”

Impacts Debated

At a press conference announcing the results Tuesday, PJM Senior Vice President of Market Services Stu Bresler noted several rule and timing changes that may have impacted the results, including the effective elimination of the MOPR, the use of a lower unit-specific market seller offer cap (MSOC) to counter market power and a historical, rather than a forward-looking, energy and ancillary services revenue offset. Bresler cautioned that because the RTO had not done any modeling, “we don’t know the magnitude of any [price] impacts.”

The less restrictive MOPR was applied to only seven resources totaling 76 MW that had failed to file for exemptions in time, Bresler said.

“Revisions demanded by FERC have virtually eliminated the MOPR, and it now fails in its purpose to prohibit subsidized resources from both suppressing the clearing price for resources who do not enjoy the benefit of a subsidy and preventing those otherwise economic resources from clearing,” P3 said.

The group said the elimination of the default MSOCs “promoted by proponents as necessary to protect against the potential to inappropriately influence prices, instead … forced suppliers to use unit-specific calculations of anticipated revenues from the energy and ancillary services markets to determine their necessary capacity market revenues while also prohibiting those calculations from accounting for the costs and risks of accepting a capacity obligation to operate when so directed by PJM.”

Jeff Dennis, managing director and general counsel of Advanced Energy Economy (AEE), offered a different take.

“There will be unfounded speculation that removal of the expanded MOPR caused the low prices; but past auctions run without an expanded MOPR produced even lower prices,” he tweeted. “PJM has been oversupplied for years; oversupplied markets produce low prices.”

He also expressed dismay at the increase in natural gas clearing the market, saying gas capacity is overvalued because of PJM’s use of an “outdated methodology” compared with the effective load-carrying capability (ELCC) used to value renewables.

P3, however, contended that the capacity capability provided by wind and solar is “overstated” even with ELCC.

“PJM’s proposed solution to rectify this issue is under dispute because it assumes utilization of extra room on the transmission system that should be available to all system users,” P3 said.

Constellation and Vistra Report on Auction Results

All of Constellation Energy’s (NASDAQ GS:CEG) nuclear-, natural gas- and oil-fired generation in PJM (18,775 MW) cleared in the auction, the company said in a filing with the U.S. Securities and Exchange Commission.

That included all 16,175 MW of its nuclear capacity, up from 9,900 MW last year, when the Byron, Dresden and Quad Cities plants in Illinois were left out of the money.

Exelon (NASDAQ:EXC) spun Constellation — including its generation and competitive energy operations — off as a standalone company in February to focus on its regulated utilities.

Vistra (NYSE:VST) reported it cleared 6,868 MW at a weighted average clearing price of $37.20/MW-day, a total of $94 million.

It said it also expects incremental revenue of $70 million to $75 million from existing retail and other third-party bilateral sales above the auction clearing price, for total estimated revenues of $164 million to $169 million.

Public Service Enterprise Group (NYSE:PEG), owner of the Salem and Hope Creek nuclear plants in New Jersey, and Energy Harbor, which operates nuclear plants formerly owned by FirstEnergy Solutions, did not respond to requests for comment. Talen Energy declined to comment on whether its Susquehanna nuclear plant cleared.

June 22, 2022June 14, 2023

Overheard at East Coast Renewables Conference: Spotlight on NY

The Business Council of New York State, The Hudson Renewable Energy Institute and Pace University on June 21-22 hosted the 8th Annual 2022 Renewable Energy Conference, which explored the challenges of managing a fundamental change in society’s energy supply and infrastructure under New York’s climate law.

The following are comments heard at the conference that featured state officials and regulators, business leaders, utility representatives and other stakeholders.

Society does not change according to a stipulated schedule, but it is an evolutionary process, Hudson Institute Chair Allan Page said.

“Leadership in the state needs to take into account the voluntary beneficial behavior of citizens of New York to get to net carbon zero on a societal glide path free of deleterious unintended consequences,” Page said. “Competitive markets come back to balance or equilibrium that allows choice between competing needs. Regarding the [New York Climate Action Council’s] draft scoping plan, a little more balance is needed.”

Implementing CLCPA

The Climate Leadership and Community Protection Act (CLCPA) requires New York to obtain 70% of its electricity from renewable sources by 2030 and to make the grid net-zero emissions by 2040.

The council in December unanimously approved a draft scoping plan that lays out the steps needed to achieve the emission limits set by the CLCPA.

NYSERDA CEO Doreen Harris | BCNYS

That plan provides several scenarios for meeting the state’s environmental directives and incorporates recommendations from the council’s seven sector-specific advisory panels, including from one on energy-intensive and trade-exposed industries, said Doreen Harris, president and CEO of the New York State Energy Research and Development Authority (NYSERDA) and council co-chair.

“When we look at the draft scoping plan in the broadest sense, it does show that the cost of inaction exceeds the cost of action by more than $90 billion, and ultimately the improvements in air quality, transportation and energy in low-income homes will generate health benefits ranging from approximately $165 billion to $170 billion,” Harris said.

In addition to hundreds of miles of transmission projects under construction, the Public Service Commission and NYISO have taken up utility investment plans needed to integrate renewables across the state, and the public policy transmission project, for example, advancing to provide better transfer capability from Long Island to New York City to allow the integration of more offshore wind energy into the city’s grid, she said.

“When we look at it in the longer term, that’s when the investments, that will be needed to realize that very reliable 2050 grid, are really topics that are to be determined through the work of NYISO, the Department of Public Service with NYSERDA, and of course with the federal investments that we are very excited to benefit from as they move forward,” Harris said.

Power Sector and DERs

Investing in and building new transmission in New York will be key to achieving the state’s public policy objectives, yet it is extraordinarily challenging, particularly on Long Island, where adding new infrastructure has always been difficult, said Scott Medla, managing partner at investment bank Ansonia Partners, who moderated a panel on distributed energy resources (DER).

“In my view, the bottom line is to find ways to use existing rights of way to build, not higher, not wider, not longer, be it underground or underwater, but to the extent possible to use leading technologies that are proven,” Medla said.

NYISO’s focus is on operating the grid to provide reliable service to customers, which requires having sufficient resources that can satisfy the CLCPA, while controlling their output, running for extended periods at specific output levels and being flexible, Nicole Bouchez, NYISO Principal Economist, said.

“The real puzzle now is that we don’t know what technology is going to step in and provide that service,” Bouchez said.

Maintaining affordability in the energy supply must be a part of the clean energy transition, said John Borchert, senior director of energy policy for Central Hudson Gas and Electric.

“One of the big steps that needs to be further explored is reducing emissions and energy use in the lowest cost way,” Borchert said. “Energy efficiency has always been the lowest-cost, most effective way to reduce emissions and save money,”

New York, he added, should continue to support and evaluate further expansion of energy efficiency.

NYISO has been a leader in facilitating the complex integration of renewable resources onto the grid, said Luke Falk, senior vice president for development at EnergyRe, partner with Invenergy in developing the 1,300-MW Clean Path New York transmission project to bring upstate wind and solar energy into the city.

“We’re talking about 20-something, large-scale wind and solar development projects, all of which are advanced in parallel and in their own right, and a large, underground HVDC transmission line,” Falk said.

Developing those projects will be a complex process that requires precise orchestration, according to Falk, who says it’s reasonable to forecast a trend toward HVDC.

Regulatory Challenges

William Flynn, partner at law firm Harris Beach, moderated a discussion with two PSC commissioners to explore significant opportunities and challenges facing the state’s energy sector and business community regarding the energy sector transformation.

Environmental considerations have not always been a priority for the commission, particularly the impact of those pollutants on individuals, PSC Chair Rory Christian said.

“One of the first places I worked was at the Ravenswood power station Astoria Queens, and I was always surprised at how close it was to a very dense urban population center and significant [public] housing within walking distance,” Christian said.

Planners made decisions 50 or 60 years ago to site power plants in places that have had a deleterious effect on residents, according to Christian. Reducing those emissions allows the state to address those impacts and improve the health of affected communities.

“That’s probably one of the biggest priorities of the commission,” he said.

As the state leans into electrification, demand may far outpace reliable supply in meeting the growing electricity needs of New York, Commissioner Diane Burman said.

Clockwise from top left: William Flynn, partner at law firm Harris Beach; NYPSC Chair Rory Christian; and NYPSC Commissioner Diane Burman | BCNYS

The commission needs “to understand that we have a fiduciary responsibility to our ratepayers, and we need to look at it through the lens of us as economic regulators, which means that costs do matter, they impact on everyone, and to that end how do we do this in a way that achieves greenhouse gas reduction goals without going backwards,” Burman said.

As an example, Christian said New York has spent many decades building up the gas network and that it’s important to ensure continued use of it in the most efficient way possible toward meeting climate goals.

“In addition to that, we’ve also released the CLCPA order which in many ways is going to track all the various components and actions, specifically actions, that are taken by this commission towards meeting goals of the CLCPA, and that would be in addition to tracking the costs of those items moving towards meeting the goals,” Christian said.

While the state is on a good track, realistically it needs to address the challenge of transitioning away from natural gas without compromising reliability, Burman said.

“We need to look at how curtailing the use of natural gas can actually conflict with our state goals to reduce carbon emissions if the unavailability of gas leads to greater near-term reliance on other fossil fuels such as oil,” Burman said.

June 22, 2022January 20, 2024

37 States Fight Over California Tailpipe Standards

The first potentially decisive motions are due Monday in a case that pits 17 states and their allies against the U.S. Environmental Protection Agency over its waiver allowing California to enact stricter tailpipe emissions standards than the federal government.

California and 19 other states back the EPA’s decision, along with environmental groups, automakers and some utilities.

Ohio Attorney General Dave Yost filed the case, Ohio v. EPA, in the D.C. Circuit Court of Appeals in May, two months after the EPA rescinded a Trump administration decision that had revoked California’s decades-old Clean Air Act waiver. EPA also reinstated California’s requirement that all new passenger vehicles sold in-state must be emissions free by 2035. (See EPA Restores California Tailpipe Standards.)

Yost and the attorneys general of the 16 other states asked the court to decide if EPA’s action was unconstitutional, “arbitrary, capricious [and] an abuse of discretion” because the agency allowed stronger state regulations to supersede federal fuel economy standards.

They contended that the D.C. Circuit was the proper venue for the matter because the court, which normally hears cases on appeal, has primary authority to review decisions the EPA determines have “nationwide scope or effect.”

The petition for review was signed by Yost and the attorney generals of Alabama, Arkansas, Georgia, Indiana, Kansas, Kentucky, Louisiana, Mississippi, Missouri, Montana, Nebraska, Oklahoma, South Carolina, Texas, Utah, and West Virginia.

Asked to discuss the case with RTO Insider, Yost’s office declined to comment.

California Attorney General Rob Bonta quickly moved to intervene, joined by his counterparts in Colorado, Connecticut, Delaware, Hawaii, Illinois, Maine, Maryland, Massachusetts, Minnesota, Nevada, New Jersey, New Mexico, New York, North Carolina, Oregon, Pennsylvania, Rhode Island, Vermont and Washington. New York City, Los Angeles and Washington, D.C., also weighed in on the side of California and the EPA.

Congress has long allowed other states to adopt the more stringent vehicle emissions standards for which California was granted a Clean Air Act preemption waiver starting in the 1970s. (See NM Adopts Calif. Advanced Clean Cars Rules.)

“This regulatory regime has operated as Congress intended for more than half a century,” Bonta’s office wrote. “California has expanded its pioneering efforts to reduce new motor vehicle pollution, pursuant to preemption waivers granted by EPA. And EPA has continued to draw heavily on the California experience to fashion and to improve the national efforts at emissions control, thereby reducing vehicular air pollution nationwide.”

Environmental groups such as the Sierra Club, Natural Resources Defense Council and the Environmental Defense Fund asked the court for permission to intervene in support of the EPA and California. Automakers including Ford, Volkswagen and BMW also intervened.

“The automobile manufacturers … support the waiver decision and California’s ability to regulate greenhouse gas emissions from new light-duty motor vehicles,” their lawyers wrote. “Ford, Volkswagen, BMW Group, Honda, and Volvo Cars are committed to reducing greenhouse gas emissions in their own fleets.”

“Ford has committed to invest more than $50 billion by 2026 to put electric vehicles on the road across the world,” they said. “Similarly, the Volkswagen Group is in the midst of deploying a $40 billion electrification development plan to accelerate the timeline to introduce an increasingly broad range of electrified vehicles globally.”

Honda has said 100% of its vehicles worldwide will be electrified by 2040, with plans to launch more than 30 different electric vehicle models by 2030, the motion noted.

Advanced Energy Economy (AEE), Calpine Corp., National Grid USA, New York Power Authority and the Power Companies Climate Coalition filed a joint brief on June 14.

“California’s long-standing right to establish more stringent auto emissions standards is foundational to achieving the Clean Air Act’s goals of protecting public health and forcing the development of low and zero-emissions technologies like electric vehicles,” AEE General Counsel Jeff Dennis said in a news release. “AEE is intervening today to ensure that our business voice is heard in this case.”

On Ohio’s side, the American Fuel & Petrochemical Manufacturers, Domestic Energy Producers Alliance, Energy Marketers of America and the National Association of Convenience Stores argued in a court filing that the EPA’s action “financially harms [their] members … by reducing demand for products produced or sold by petitioners’ members.”

The court consolidated Ohio’s petition with related actions by parties representing ethanol producers such as the Clean Fuels Development Coalition, ethanol processor ICM Inc., and the Kansas Corn Growers Association.

The DC Circuit has set June 27 as the deadline for filing motions to dismiss the case or for summary judgement. None of the parties have said if they intend to file such motions, which are common but seldom successful in similar litigation.

John Funk contributed to this story.

June 22, 2022January 20, 2024

New Jersey Bill Would Offer Help to Delayed Solar Projects

A New Jersey bill designed to help solar developers who say that delays beyond their control are threatening the viability of some projects has raised concerns about the costs to ratepayers.

The bill, which the Senate Energy and Environment Committee backed 5-0 on June 9, would automatically extend the completion deadline for qualified projects. The extension would be available for projects that are in danger of failing to be completed by the designated deadline because of a “tolling” event and would continue as long as the event continues.

The definition of a “tolling event” includes: any action or inaction by PJM or an electric utility; a PJM or utility moratorium on new applications; any “new application process, study, report or analysis established” by the RTO or a utility; or an “undue” delay caused by local government planning board or other entity in supplying a required permit.

The bill, S2732, would cover 33 projects — mainly on landfills and brownfields — that together would total 500 MW, says Sen. Bob Smith (D), one of two bill sponsors and the committee chairman.

The bill touches an ongoing concern among solar developers that New Jersey projects can be derailed, and deadlines broken, by factors beyond their control, such as equipment delays stemming from supply chain issues, labor shortages, delays in getting municipal permits and difficulties getting projects connected to the grid.

“These problems have been devastating to the industry,” Lyle Rawlings, president of the Mid-Atlantic Solar & Storage Industries Association, told a hearing into the bill. “They’ve caused delays; they’ve caused tremendous price increases … it could be an existential threat to some businesses if they are not provided relief.”

The problem is complicated by a reshaping of the state’s solar incentive programs by the Board of Public Utilities (BPU) in recent years as it has sought to reduce the cost to ratepayers of solar subsidies, which has increased the consequences of a project missing a completion deadline. The BPU in May 2020 replaced the state’s long-time solar incentive program, the Solar Renewable Energy Certificate (SREC) program, which paid about $250/MWh, with the temporary Transition Renewable Energy Certificate (TREC) program, which granted incentives of $90 to $150/MWh. In July, the TREC program ended and was replaced by the Successor Solar Incentive (SuSi) program, which pays incentives of $70 to $100/MWh depending on the project.

The changes mean that a project with a TREC incentive that fails to meet its completion deadline could lose the incentive and have to apply for another under the less lucrative SuSi program. The only remedy would be to apply for a deadline extension to the BPU, which has been reluctant to grant extensions.

Evaluating such extension requests, the BPU has to consider, for example, whether the delay is genuinely because of circumstances beyond the developer’s control, or the applicant’s project was from the beginning unlikely to make the deadline and they are is seeking to remedy the problem with an extension.

During the hearing, Smith recounted that the BPU told him that about 75% of the 4,000 applications for TREC incentives were “bogus, meaning that it was just somebody putting in a slip to keep their name in line for a TREC, but not necessarily with any intention to build.”

The proposed legislation, however, would remove the need for a BPU deadline extension and instead grant qualified applicants an “automatic extension.”

Extension Questions

In a June 8 letter to the committee, the New Jersey Division of Rate Counsel opposed the bill, saying it “will inevitably result in increased rates for utility ratepayers.”

The bill would remove the BPU’s ability to deny extensions and prohibit it “from even investigating the factual accuracy of the certification” by a developer claiming that a tolling event had delayed its project, the Rate Counsel said. The legislation also would prevent the board from setting the length of an extension, if it concluded one was warranted, and replace its expertise in judging whether a project deserved the extension with an automatic extension award, the agency said.

That would enable projects to continue, and eventually receive incentives, that otherwise would fail because they otherwise would not meet the deadline, the counsel said.

“It would eliminate the board’s ability to enforce any deadlines and result in the payment of substantial excess incentives,” it said. “And since ratepayers ultimately fund these financial incentives, this bill will increase utility rates.”

Developers testifying before the committee, however, outlined the kind of scenarios that highlight the need for the legislation.

Melissa Sims, owner of Ecological Systems, a Manalapan-based solar development company, said she has two projects underway that will be finished within the deadline, except that each will be missing a small part. In one, she has waited several months for a circuit breaker that she was initially told would take 70 days to arrive.

Sims said she feared that because of the delay, she will fail to meet the deadline of the TREC grant awarded for the project.

“I cannot stress enough how serious and devastating it will be for anyone who has a solar project under construction who is experiencing these types of delays,” she said. “If I don’t have the breaker, I can’t call for my electrical inspection. And if I can’t call for my electrical inspection, I can’t get permission to operate from the utility. And if I can’t get permission to operate from the utility, I can’t get my TREC.”

Joshua Lewin, president of Helios Solar Energy, said he also has two projects in jeopardy because of similar problems, including a 1-MW project in Millville that could miss the completion deadline because he is still waiting for the arrival of the main distribution panel, which was ordered last July. He estimated that the customer would lose about $780,000 in revenue if the delay causes the project to miss its completion deadline.

“We’re constantly re-engineering some of the one-line diagrams and pieces of equipment to try to accommodate what might be available in the next couple of weeks or a couple of months,” he said. “But there are items that are just unavailable.”

Connection Obstacles

Business groups — among them the New Jersey Business and Industry Association and the South Jersey Chamber of Commerce — support the bill, as do environmentalists, including the New Jersey league of Conservation Voters.

Smith said the delays mean that New Jersey is “not keeping its promises” to provide a transition period between the SREC and the SuSi program, because developers find they can’t meet the deadlines of the temporary TREC program, which was meant to soften the transition.

“We said we would do lower [incentives] to have a transition, ultimately, to no subsidies,” he said. “But we were not performing.” Instead, he said, developers and their customers — through no fault of their own — face the loss of those incentives because of delays, and “we’re just saying, ‘Hey, tough, tough on you.’”

Lengthy delays connecting new projects to PJM are also common. The RTO said in February that it had 220 GW of capacity in the queue, of which renewables made up 95%. (See PJM Files Interconnection Proposal with FERC.)

“This is not an issue with New Jersey; this is an issue with PJM,” Doug O’Malley, director of Environment New Jersey, told the Senate Energy and Environment Committee as he offered support for the bill on June 9. “PJM is essentially throwing up the red stop sign and saying ‘do not proceed with solar,’ and that’s creating massive problems for the projects that have been teed up.”

The difficulty of connecting solar projects in the state to the grid is also well known. In May developers, testifying in support of a bill that would levy a fee that would raise funds to modernize the grid, said the grid is so old and its capacity so limited that new projects can’t be connected in some areas of the state. (See Solar Developers: NJ’s Aging Grid Can’t Accept New Projects.)

Awaiting Permission

A recent case before the BPU at its June 8 meeting, the latest in a series of deadline extension requests, highlighted the difficulties.

Project developer ESNJ-Key-Gibbstown, seeking to finish a 1.38-MW carport solar project located in Gibbstown, in South Jersey, had received three extensions since the project was approved for TREC incentives in June 2020. It then sought an additional extension to move the deadline to Dec. 31 because of the inability to connect the project to the grid through Atlantic City Electric (ACE).

The developer, according to the BPU order on the case, had “completed construction,” had a conditional permit to operate and was “capable of being fully energized and connected to the grid.” However, the order said, the developer could not get ACE to deliver the project’s full capacity to the grid because “ACE has not yet completed offsite upgrades necessary to allow interconnection for the full capacity of the project.” As a result, the project could only operate generating 50 kW.

The order said that BPU staff have “traditionally been reluctant to recommend that the board provide extensions for solar projects that miss their expiration dates because of supply chain issues, general interconnection processing delays and other factors that, while regrettable, do not rise to the level of warranting an extension.” Yet the staff recommended a deadline extension, and the board approved it.

“This does not appear to be a case of a project coming into the [TREC] program with an underdeveloped project development plan,” staff concluded, noting that the developer had done “everything in its power to complete its project” by the April deadline.

BPU President Joseph Fiordaliso said the board’s decision “struck the necessary balance of fairness to applicants whose projects are otherwise complete with a strong interest of the ratepayer who should always receive what they pay for, no more and no less.”

Still, he said, the case highlights the difficulties facing the state.

“When we’re talking to executives from utility companies, we are constantly talking about interconnection,” he said. “If anything keeps me awake at night, it is the fact that we’re going to have wind turbines out there; we have solar programs out there, and there’s no place to plug them in.”

June 22, 2022

SPP Issues Resource Advisory for the Week

[EDITOR’S NOTE: This story has been updated to reflect SPP’s conservative operations declaration Wednesday, June 22.]

SPP issued a resource advisory for its entire 14-state Eastern Interconnection footprint Monday because of higher-than-normal temperatures. The advisory is effective 4 p.m. CT on Tuesday and is expected to end at 8 p.m. Friday.

On Wednesday, the RTO upped the advisory in calling for conservative operations from 10 a.m. to 10 p.m. Wednesday. It said the advisory was declared because of high loads and wind generation’s availability.

Temperatures are forecasted to hit triple digits in Kansas, where heat stress has been blamed for the recent deaths of thousands of cattle.

The advisory does not require the public to conserve energy but does allow the RTO’s balancing authority to use greater unit commitment notification timeframes. That includes making commitments prior to day-ahead market and/or committing resources in reliability status.

SPP issues resource advisories when extreme weather, significant outages, and wind-forecast or load-forecast uncertainty is expected in its reliability coordination service territory. Generation and transmission operators have already been provided instructions on applicable procedures that include reporting any limitations, fuel shortages or concerns.

Conservative operations advisories are issued when weather, environmental, operational, terrorist, cyber or other events require the RTO to operate its system conservatively.

June 22, 2022June 14, 2023

Carbon Capture Navigating Path into Clean Energy Mainstream

Energy Secretary Jennifer Granholm came to the Global CCS Institute Forum in D.C. on Thursday to tell a roomful of executives, engineers, financiers and other advocates that the Biden administration is all in on carbon capture and storage (CCS) as a critical technology in the fight against climate change.

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Energy Secretary Jennifer Granholm | © RTO Insider LLC

“The climate science on this is unequivocal,” Granholm said. “Yes, we need to accelerate clean generation, and yes, we need to decarbonize because the goal of getting to 1.5 degrees Centigrade to meet the Paris Agreement, it just can’t happen without carbon removal. It can’t happen without carbon capture.”

While acknowledging public skepticism about the expense and feasibility of CCS, Granholm argued that “carbon-management technologies offer us tools, and these tools can be helpful or hurtful depending on how carefully or responsibly you can use them.”

Granholm’s use of the term “carbon management” reflects the repositioning of CCS that is underway both within traditional fossil fuel companies and CCS startups bringing their technologies to market, as the industry continues to negotiate a path into the clean energy mainstream. The underlying message at the conference was not if CCS will be effective, functional and affordable, but when that level of development will occur and what’s needed to accelerate the process.

Figures from the International Energy Agency (IEA) show that the existing 27 CCS facilities worldwide have the capacity to take about 40 million tons of CO₂ per year out of the air. The industry saw a record growth spurt in 2021 with 97 new projects announced and 66 more in advanced stages of development. But even if all these projects were to come online, the IEA says, they would not provide the 1.7 billion tons of CCS capacity that will be needed by 2030 as a foundation for a global net-zero economy by 2050.

In her keynote at the forum, Granholm focused on the environmental and economic imperatives for CCS. It will decarbonize the “things we cannot live without and yet whose carbon emissions we cannot live with,” such as steel, cement and chemicals, she said.

It will also be a job creator, Granholm said, providing new opportunities for fossil fuel workers and communities that “have powered this nation for over 100 years … and should empower us into the future.”

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But scaling CCS will require both government and industry to step up, said Jarad Daniels, CEO of the Global CCS Institute. Federal programs and incentives are vital “during those first-of-a-kind [projects],” he said. “But it’s really industry and the private sector that are going to get this deployed at commercial scale.”

The Biden administration’s support for CCS includes $12.1 billion in funding for demonstration projects and other research and development activities in the Infrastructure Investment and Jobs Act. Expanding tax credits for CCS — specifically, the 45Q tax credit — is also part of the clean energy incentives the administration and the industry still hope to get through Congress before the upcoming midterm elections.

The energy sector as a whole is also beginning to shift, Daniels said, toward “providing diverse energy services, and it should be [technology] agnostic … as long as it moves toward sustainability” and reducing greenhouse gas emissions.

Traditional oil and gas companies can and should take a leadership role to accelerate the transition “to move away from just the energy sector being based on hydrocarbons to being based on this broader suite of technologies that all have lower carbon footprints,” Daniels said. “They have the infrastructure; they have the balance sheet to allow all of us to work together at scale.”

Occidental Petroleum (NYSE:OXY) CEO Vicki Hollub reminded CCS skeptics that “technology can be improved over time, as we’ve seen in the case for solar and wind. … You can’t make it better until you build the first one and improve it over time,” she said.

With market disruptions from the war in Ukraine, Hollub sees a more pressing question for the industry: how to accelerate the energy transition to meet the 2050 goals of the Paris Agreement, “but also ensure that we’re not putting any countries or regions at risk from a security standpoint and that we’re not leaving … developing countries behind.”

The Last Barrel of Oil

For Hollub the answer is Occidental’s commitment to enhanced oil recovery (EOR): injecting CO₂ into existing wells to increase their output, while decreasing the fuel’s carbon footprint.

Traditional extraction methods leave 50 to 60% of oil in the ground, Hollub said. But once injected, CO₂ expands into porous rock where oil is trapped, pushing it out and then filling the empty space, which sequesters it “forever,” she said.

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“It takes more CO₂ injected into a reservoir than what the incremental oil that that CO₂ generates will emit with use,” Hollub said. “So, you can actually generate net-negative or net-neutral carbon oil from an enhanced oil recovery project.”

Occidental currently has three EOR projects online in the Permian Basin in Texas and is also looking to expand into direct air capture to have enough CO₂ for widespread adoption of enhanced recovery. Hollub sees a global market for the technology, especially in developing countries that “have all these resources to develop, so they can achieve the same quality of life we have here in the United States,” she said. “We need to allow them to be able to develop, but in a carbon-neutral way.”

Hollub also anticipates a huge corporate market for EOR. “There are more than 5,000 corporations in the world that have committed to be net zero by 2050,” she said. “And what that means is there are not enough natural ways to sequester CO₂, so, we’re going to need carbon capture and sequestration.”

The goal, she said, is to reduce the carbon footprint of future oil development and production. “The last barrel of oil produced in the world should come from a CO₂ enhanced oil recovery reservoir,” she said.

Valuing Carbon

Getting to that last barrel is a matter of both technology and finance, said Jonathan Pershing, environment program director at the William and Flora Hewlett Foundation. Prices must come down, scale must go up, and “somehow, you’ve got to value the carbon,” he said in an afternoon keynote.

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“We have to figure out how to bridge the gap between the economic return [on CCS], which is a pretty small share of the total, and the price, which is a much larger number,” Pershing said. At present, he sees prices of $50/ton for industrial CCS and $200/ton for direct air capture as good targets.

Current 45Q tax credits are either below or just equal to those benchmarks — with no direct-pay option — with credits for EOR projects receiving credits starting at $10/metric ton, increasing over time to $35/MT, while the credit for carbon sequestered in salt caverns or other underground formations ranges from $20 to $50.

The incentives proposed in the original Build Back Better Act would have increased tax credits for carbon stored in geological formations to $85/MT, and the credits for direct air capture projects would have jumped to $130 to $180. (See No Net Zero Without Carbon Capture.)

An earlier panel on project finance zeroed in on direct-pay incentives as a key solution to bridging the gap. “Tax credits don’t incentivize because basically no corporations pay taxes … and if they do, they have excess tax credits,” said Jeff Brown, managing director of the Energy Futures Financing Forum. Furthermore, tax credits are not cash, so they cannot be used to pay off debt, he said. (See 3 Keys to Fixing the Cash-flow Dilemma in CO2 Capture.)

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But Mike Belenkie, CEO of Canadian startup Entropy Inc., sees a more fundamental problem. However generous, government subsidies and private philanthropy generally result in pilot projects, but climate change is a massive problem requiring more ambitious goals.

“It doesn’t get solved by showing you can do it,” he said. “It gets solved by actually putting a market together, understanding the cost of doing it and doing it.”

Belenkie was one of three startup executives speaking on a panel on the CCS technologies and business models now moving the industry forward. Entropy’s strategy, he said, is to “come up with a full business [model that] can be emulated over and over again around the world and develop a lot of market.”

Putting carbon in the ground “with the lowest possible cost is always going to be the best solution,” Belenkie said. “Avoid pipelines; we do not need a network of pipelines around North America or around the world to store carbon.”

With an investment of $300 million from Brookfield Renewable, the company is about to bring its first commercial-scale project online in Alberta, sequestering 47,000 metric tons of CO₂ per year at a cost of $50/ton.

June 21, 2022December 5, 2023

Utilities Could Double US Nuclear Capacity by 2050, NEI Chief Says

A recent poll of chief nuclear officers at the Nuclear Energy Institute’s (NEI) member utilities found that they plan to add 90 GW of nuclear generation to the U.S. grid, with the “bulk” of that capacity coming online by 2050, CEO Maria Korsnick said Tuesday.

That level of generation would double U.S. nuclear output and does not include “the growing list of utilities who are new to nuclear and demonstrating interest in advanced technologies,” she said in a State of the Industry address at NEI’s Nuclear Energy Assembly in D.C.

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Maria Korsnick, President and CEO of the Nuclear Energy Institute | Nuclear Energy Institute

Korsnick expects the new U.S. nuclear fleet to include “some” small modular reactors (SMRs). Supporters of the SMR approach, which limits traditionally large generating capacities to under 300 MW, say it offers the possibility of nimble nuclear deployment.

She also sees those new smaller plants that are based on advanced technologies, together with an expansion of existing nuclear technology, as an important part of addressing climate change.

“Nuclear is the key to unlocking a zero-carbon future,” she said, adding that she has observed a “sea change in the perception of nuclear energy … as an indispensable tool for driving down emissions.”

A growing vision for SMRs moves nuclear beyond ensuring grid reliability to helping decarbonize hard-to-abate industries, such as oil and gas chemical manufacturing, steelmaking and production of synthetic materials.

“Advanced reactors are the solution that they’ve been searching for,” Korsnick said. “They can provide the reliable, cost-effective carbon-free generation needed to decarbonize their supply chains, and they enable manufacturers to sell to companies like Ford, GM, Tesla and others who are committed to a lower-carbon future.”

In addition, she said that manufacturing and transportation sectors could decarbonize with hydrogen generated from the off-peak capacity of nuclear reactors.

Credit for ESG

To realize a role for nuclear in a decarbonizing the economy, the industry must navigate a future where investors are increasingly screening for environmental, social and governance (ESG) factors.

“Nuclear should be getting credit for ESG,” Korsnick said. “I’d like to tell you that it’s that simple, but it’s not, and there are some financial institutions that look at nuclear and look at ESG, and they struggle to say that nuclear actually supports that.”

As an example of the challenge, Korsnick pointed to the current controversy over inclusion of nuclear in the EU’s sustainable finance strategy (or “green taxonomy”). ESG investors are watching the EU’s strategy as an important standard for defining what makes a green investment.

The EU issued rules in April 2021 for activities that can be defined as “green,” but it chose to wait on its decision about whether to include nuclear and natural gas on the list. A final decision for the two resources is due in early July.

“It’s really important that we all stand up for nuclear … because one of the things we need to unlock is financial investment,” Korsnick said.

The U.N.’s 27th Climate Change Conference of the Parties (COP) in Egypt this fall is an opportunity for industry members to represent nuclear’s potential for decarbonizing the economy, according to Korsnick.

“At COP 27 … and every other forum where official critical decisions are being made about our climate and our energy future, we need to be crystal clear,” she said. “If we don’t commit to the next generation of nuclear now, our hesitation will cost our electric grid, our economy and our environment.”

June 21, 2022December 10, 2023

PJM Capacity Prices Crater

Capacity prices dropped by one-third to almost one-half in PJM’s Base Residual Auction for 2023/24, likely depressed by the effective elimination of the minimum offer price rule (MOPR), a tougher cap on generator prices and robust forward energy prices, which reduced revenue pressures on generators.

BRA clearing prices ($/MW-day)

Prices in most of the MAAC region (Atlantic City Electric, Jersey Central Power & Light, Met-Ed, PECO Energy, Penelec, Pepco, PPL, Public Service Electric and Gas, PPL, Rockland Electric and Delmarva Power’s northern territory) dropped to $49.49/MW-day, a nearly 50% drop, while those in rest-of-RTO fell to $34.13, a nearly one-third reduction.

Two transmission zones within MAAC, Baltimore Gas and Electric and Delmarva Power’s south separated at prices of $69.95, which PJM attributed to transmission limitations.

PJM procured 144,871 MW of resources for the year beginning June 1, 2023. Including the fixed resource requirement (FRR) obligation of 31,346 MW, the RTO will have a 20.3% reserve margin, well above its 14.8% requirement.

PJM’s total capacity bill for the year is $2.2 billion, down from about $4 billion for the 2022/23 delivery year. It was the second year in a row that capacity prices have fallen, following last year’s sharp drop. (See Capacity Prices Drop Sharply in PJM Auction.)

“I did not see anything in this auction that was, ‘Wow. I didn’t expect that to happen!’” PJM Senior Vice President of Market Services Stu Bresler said at press conference to announce the results Tuesday. “I think the prevailing wisdom out there was that we were going to see lower clearing prices in this auction than we had in the last auction … given some of the rule changes; given some of the external things that have occurred in various states in PJM. I just don’t think any of us were really surprised by many of the results.”

Nuclear Resurgence, New Gas and Solar

Nuclear plants were big winners in the auction, clearing an additional 5,315 MW than last year.

Solar resources increased 25% to 1,868 MW, while wind resources cleared only 1,294 MW, a reduction of 434 MW, as fewer resources participated.

New capacity offered by year

Natural gas resources cleared an additional 1,685 MW, with more efficient combined cycle units boosting their share by 3,627 MW and less efficient combustion turbines falling 1,012 MW. Combined cycle units cleared a total of 48,030 MW in the auction, and CT units cleared 19,080 MW.

Cleared capacity of steam units (primarily coal) dropped by 7,186 MW to 27,682 MW, reflecting a decrease of 7,813 MW offered into the auction because of plant retirements.

Energy efficiency resources jumped 660 MW to 5,471 MW, while demand response dropped 716 MW to 8,096 MW.

Hydro dropped from 4,157 MW to 3,677 MW.

New Variables

Bresler noted several rule and timing changes that may have impacted the results.

It was the first auction using the less restrictive MOPR, which was applied to only seven resources totaling 76 MW that had failed to file for exemptions in time.

The auction also used a lower unit-specific market seller offer cap to counter market power and a historical, rather than a forward-looking, energy and ancillary services revenue offset.

“I think the prevailing wisdom is that the impact of this implementation of the very narrow, less restrictive minimum offer price rule could have had a downward impact on prices in this auction,” Bresler said.

The replacement of the net cost of new entry-based offer cap with a unit-specific cap based on net avoidable costs “could have served to reduce the offer prices that some resources would have offered into this auction,” he added. “However, in both of these cases … it’s extremely difficult, if not impossible, for PJM to say what resources would have offered if they hadn’t offered what they did. It would be purely speculative. So we don’t know the magnitude of any impacts.”

Also new was the application of the effective load-carrying capability method for determining the capacity value of wind, solar and storage resources.

“It could result in a lower capacity value for certain resources,” he said, suggesting it might have impacted the reduction in wind generation offerings.

Futures Prices

Bresler said spark spreads and dark spreads — respectively, the difference between the wholesale market price of electricity and its cost of production using natural gas and coal — have increased, especially in the forward markets. “You would expect, if market sellers are anticipating higher net revenues in the energy market, that they will be able to offer less into the capacity market,” he said.

Timing

Bresler said the reduction in demand response could have been a result of the shortened auction timeline.

The 2023/24 auction was originally scheduled for May 2020 but was delayed while FERC considered approval of new market rules, leaving only a one-year lead time to the delivery year instead of the usual three.

“Most of the time we’re [three] years in advance; even the last auction was more than a year in advance of the delivery year, which gives curtailment service providers the opportunity to offer planned demand response that they can then … go out and sort of sell to customers.”

The next BRA, for the 2024/25 delivery year, will be held in December to return to a three-year-forward basis.