Search
`
November 5, 2024

Posted on

Summit Examines What’s Needed to Build Hydrogen Economy

The hydrogen revolution energizing green hydrogen advocates and producers in the wake of the Biden administration’s renewables push won’t happen until key players from the fossil fuel and financial sectors buy into the transition, according to a key government official charged with helping to make it happen.

Jigar Shah, a former green entrepreneur and now director of U.S. Department of Energy’s loan program office, offered the prediction Tuesday during a focused conversation at the two-day Hydrogen Americas Summit in Washington, hosted by the DOE and the Sustainable Energy Council, a global business organization. More than 600 attended.

Shah said U.S. heavy industry, including oil refineries, now uses about 10 million tons of hydrogen annually. Nearly all of it is made from methane, a process that produces carbon dioxide. Convincing the refineries to switch to buying green hydrogen would be a promising first step for the cleaner fuel, Shah said. 

“The president has been very clear that we need to decarbonize the electricity sector by 2035. And the economy by 2050,” Shah said. “I don’t see a single refinery actually signing a long-term offtake agreement — not one. No one is suggesting that the refineries are going to go out of business next week. I mean, you’re talking about a hybrid system we’re going to live in for a very long time.”

Shah said he hoped the event — and others like it — will spur recognition of the need for long-term “anchor” customers for green hydrogen.

“And they’re not concerned about the volatility of the price of natural gas and hydrogen … because they’ve already picked hydrogen. Hydrogen is already being used [at the rate of] 10 million tons a year in the United States,” he said.

But he said refineries are not signing long-term offtake agreements with upstart green hydrogen producers, in part because the oil industry has been unprofitable in recent years and the long-term financial future of oil refining looks uncertain. Moreover, green hydrogen companies could look risky. 

That is a real problem for green hydrogen producers that need solidly committed customers to finance expansion, he explained. They have trouble attracting both private equity investment as well as traditional formal financing because established industries are not ready to buy from them.

Shannon Angielski, a principal with Van Ness Feldman LLP, moderated the panel discussion. She suggested that the difficulty in jumpstarting U.S. green hydrogen production may also be the result of a supply chain problem.

“We’re talking about a big market here, and starting either small or going big, even with the regional hubs, there is a lot of equipment, components and other things that are really needed for that market. There are not a lot of manufacturers today, or they’re very limited and that could limit some of these supplies,” Angielski said. 

“How do you look at that from a financing perspective, equity [financing] or otherwise? How do we accelerate that or send that . . . market signal?” she asked panel members. 

Shah suggested that building a recognized parts supply system is not as big a problem as the green hydrogen industry itself.

He said the burgeoning industry keeps creating new business models for the use of hydrogen.

“That confuses the crap out of the finance sector because the [models] are all different. The use cases are completely different. They are not actually related to each other,” Shah said. 

“Finance people think in terms of risk,” he explained. Their questions will include: “What do the standardized contracts look like? What [responsibility] does each party take on? Do I get protected if the electrolyzer manufacturer gives me a 10-year warranty? …

“Do I get protected … if the leak rates are much higher than expected, and the project is worse than what it was replacing? Is there moral harm? And if the project gets shut down and I don’t get paid back? …

“The last piece of it [investor concerns] are residual value and recovery rates,” he said. “What if the team ends up being completely incompetent, and the project itself is good, but the team can’t operate it. Is there a way to bring in a new team to actually realize that vision?” 

New Finance Models Needed

The DOE’s efforts to bring more certainty to the situation include $9.5 billion in funding for governments and industries that can create the concentrated production of hydrogen and its use in a relatively small region. The agency is accepting concept proposals for these hydrogen “hubs” until Nov. 7 and is seeking full applications by April 7, 2023.

Early conversations have been disturbing, Shah revealed. “We do think that [green hydrogen producers] should strive to get offtake agreements, but I do also think that some of what we’re seeing seems slightly fanciful. There are a lot of people getting European offtake agreements with almost nothing happening in the United States,” he said.

Nicole Faucher, CEO of BEAM Group, a large private equity fund focusing on carbon-negative investments, said the problems that green hydrogen companies face “boils down” to outdated financing models. 

“We can’t reinvent the future energy of how we’re going to power a better planet using yesterday’s financing models,” she said.

Faucher said current financing models will not work because the expansion of green hydrogen production requires a 20- to 40-year outlook. 

“The current market is really set up in terms of venture capital hedge funds for a much shorter timeframe. We need long-term, patient, strategic capital to really move the needle on the clean hydrogen economy,” she said.

Private equity is set up to typically offer 10 years of financing, with possibly two one-year extensions on top of that. “So, you’ve got 12 years of runway there, not really enough time,” Faucher said.

Some private equity groups are now using another investment tool called “continuation funds,” an arrangement in which a second fund buys the debt from the original investor after the first 10 or 12 years.

“One of our anchors is very excited about doing a continuation fund. At that point, you’ve got 20 years. That’s what you need to move the needle on the clean hydrogen economy,” she said. 

Posted on

SEEM Set for Nov. Commencement Date

The Southeast Energy Exchange Market (SEEM) is set to begin operations on Nov. 9 despite an ongoing legal challenge from environmental groups, the market’s membership board said in a filing to FERC last week (ER21-1111, et al.).

In their filing, the members noted that their agreement required the board to establish a commencement date after FERC issued orders accepting all relevant tariff filings by participating transmission providers.

The agreement automatically took effect almost exactly a year ago under Section 205 of the Federal Power Act after FERC — then evenly split between Republicans and Democrats after the departure of Commissioner Neil Chatterjee — was “divided two against two as to the lawfulness of the change.” (See SEEM to Move Ahead, Minus FERC Approval.)

The tariff approvals followed, beginning last November when the commission accepted revisions to the tariffs of four of SEEM’s founding utilities: Duke Energy, Southern Co., Dominion Energy, and LG&E and KU Energy. (See FERC Accepts Key Tariff Revisions to SEEM.) Utilities’ most recent revision came in January when FERC accepted changes to Duke’s tariff (ER21-1115).

SEEM’s founders proposed the market last year, promising to reduce trading friction while promoting the integration of renewable resources through the use of automated trading, elimination of transmission rate pancaking and allowing 15-minute energy transactions. The project has been controversial from the start; many opponents have questioned whether the proposed measures would outperform alternative structures like an RTO, while others warned that the market would allow transmission-owning utilities to exclude competitors from the market and favor their own electricity.

Although SEEM’s members are moving ahead with their operational schedule, the market is still the subject of a challenge in the D.C. Circuit Court of Appeals. A collection of environmental, clean energy and community groups including the Southern Environmental Law Center, the Sierra Club, the Southern Alliance for Clean Energy and the North Carolina Sustainable Energy Association filed an appeal in February of the commission’s decision to allow the market to move forward. (See Environmental Groups Appeal SEEM in DC Circuit.)

The opponents are asking for the court to overturn both the original effective date and FERC’s subsequent tariff approvals, as well as the commission’s rejection of the rehearing requests that the opponents have previously filed for these orders.

SEEM’s members promised in their filing to update FERC “should the commencement date occur after Nov. 9, 2022, for any reason.”

Posted on

West Virginia v. EPA Ruling: `Nuclear Bomb’ or `Speed Limit’?

WASHINGTON — The Supreme Court’s ruling barring use of “generation shifting” to reduce greenhouse gas emissions will discourage executive agencies from ambitious rulemakings but is not yet a “nuclear bomb” that will cripple regulation, attorneys told the Energy Bar Association’s Mid-Year Energy Forum Wednesday.

The court ruled June 30 that the EPA failed to provide “clear congressional authorization” for the Clean Power Plan, which would have compelled generation shifting to reduce carbon emissions from coal-fired power plants (West Va. v. EPA). The court cited the “major questions doctrine,” which it said was necessary to address “a particular and recurring problem: agencies asserting highly consequential power beyond what Congress could reasonably be understood to have granted.” (See Supreme Court Rejects EPA Generation Shifting.)

Proposed by the EPA under the Obama administration, the CPP was withdrawn by the Trump administration — replaced by the Affordable Clean Energy (ACE) rule, which was in turn withdrawn by the Biden administration.

Crippling?

Stinson partner Harvey Reiter, who moderated EBA’s morning general session Wednesday, has written that the ruling is “a potential nuclear bomb that can be aimed not merely at a particular rule, but at crippling an agency’s ability to regulate at all.”

Harvey Reiter 2022-10-12 (RTO Insider LLC) FI.jpgHarvey Reiter, Stinson | © RTO Insider LLC

Reiter’s fellow panelists had a less apocalyptic view.

Elizabeth “Ellie” Boucher Dawson, counsel with Crowell & Moring, said she didn’t agree with Reiter’s dire prediction.

“Not yet, anyway,” said Boucher Dawson, who wrote an amicus brief on the case for the Edison Electric Institute. “For me, it’s very significant that Justice [Neil] Gorsuch only wrote a concurrence and not the majority opinion.”

Gorsuch pushed for a more extreme interpretation of the major questions doctrine as a limit on congressional delegations of policymaking to agencies. But only Justice Samuel Alito joined his argument.

Aram Gavoor, a lecturer at George Washington University Law School, said the court’s decision “did not substantially change administrative law.

“I think it could, like Ellie described, eventually be something that’s quite serious. But the court will have to press the button again — a few more times — to really reinforce it.”

Matthew Leopold, a partner in Hunton Andrews Kurth, said the ruling set “a speed limit on the regulatory highway that agencies should not exceed without the risk of their rules getting struck down.

“I think it will hold the agencies back, but the regulatory administrative process is alive and well,” he said.

No Limits on ‘Major Questions’?

Although the court’s ruling said the major questions doctrine would only apply in “extraordinary circumstances,” Reiter noted that the court cited it in three rulings in its last term, involving the Food and Drug Administration, the Centers for Disease Control and Prevention and the Occupational Safety and Health Administration. He said the issue also was raised in more than 100 circuit court and district court challenges since 2020.

Matthew Leopold 2022-10-12 (RTO Insider LLC) FI.jpgMatthew Leopold, Hunton Andrews Kurth LLP | © RTO Insider LLC

Aram said the West Virginia ruling resulted in a “mushy” standard that will encourage many litigants to raise it. “Part of this might also be [that] for the court to have gotten the majority for West Virginia v. EPA, maybe it needed to be a little bit broad,” he said, adding that future rulings could result in “the metes and boundaries of what major questions really means.’”

“The nature of lawyers is to raise any argument that might get traction, so I think people will overuse it,” Leopold added. “… But I think that the extent to which it’s raised — and then more importantly, the extent to which courts really lean into it and start utilizing it — has a direct relationship to how much federal agencies … are overreaching their long-held authority or positions.”

Samuel Backfield, legal counsel to FERC Commissioner Mark Christie, said the agency expects to see the argument raised in the future.

“I think that what’s going to happen next is that there’s going to be a process of refinement of the doctrine. … Right now, what we have essentially are indicia; we don’t have a firm test,” he said. “It’s not meaningless that we have this indicia condition instead of a firm test. I mean, I’m sort of reminded of Edmund Burke’s comment that no man can draw a stroke between night and day, and yet darkness and light are reasonably distinguishable.”

Reiter suggested the ruling could prompt “forum shopping” because appeals of most agency decisions go first to one of the 94 district courts rather than a circuit court of appeals, as with FERC challenges.

“I think there’s gonna be a substantial amount of it,” agreed Aram. “… It’s also going to cause a lot of struggling with the circuit courts as to what does this mean for Chevron deference” — which requires courts to defer to a federal agency’s interpretation of an ambiguous law that Congress assigned to the agency to administer.

Impact on Prior Rulemakings

Elizabeth Boucher Dawson 2022-10-12 (RTO Insider LLC) FI.jpgElizabeth Boucher Dawson, Crowell & Moring | © RTO Insider LLC

Boucher Dawson said she was relieved that the court did not “reach back in time” to undo its previous rulings, such as Massachusetts v. EPA, in which it ruled greenhouse gases were air pollutants and could be regulated by EPA under the Clean Air Act.

Reiter questioned whether FERC’s prior rulemakings could be in jeopardy as a result of the narrowing of the Chevron doctrine. He noted the commission cited the Federal Power Act as its authority for regulating demand response, “which wasn’t even a thing in 1935,” when the FPA was enacted. Some commenters raised the major questions doctrine in FERC’s current transmission planning Notice of Proposed Rulemaking (RM21-17), he added.

FERC’s Backfield said the challenges could result in unpredictable outcomes. “There are courts of appeals and panels that would rule differently, I think, on certain of the cases,” he said.

Backfield declined to opine on whether any of the commission’s major rulemakings would survive scrutiny under major questions. “But … other than demand response, they’ve mostly been around for quite a while. And there is at least a rationale that these do go to the fundamental central regulatory duty of the FERC, which is to ensure just and reasonable rates.”

“I don’t think that the Supreme Court — at least the majority of the justices — would coalesce around an opinion that picks on old scabs,” said Gavoor. “I think if we anachronistically applied West Virginia v. EPA to some of these older actions by the agency they’d be at risk. But I don’t think they’re at risk right now. I think recent actions and ones that are in the future are likely to be at risk.”

Impact on Future Regulations

Leopold noted that the Securities and Exchange Commission recently reopened comment on a portion of its proposed greenhouse gas rulemaking, a suggestion that it sees vulnerability to a major questions challenge.

“The SEC has been around since the Depression, and they’ve never really gotten in the environmental game. But they’re all of a sudden saying you have to disclose your climate risks. You have to disclose your greenhouse gas emissions — not just your direct emissions, but your scope one, two, and three [emissions] — including three, and no one even knows how to calculate that,” he said.

Aram Gavoor 2022-10-12 (RTO Insider LLC) FI.jpgAram Gavoor, George Washington University Law School | © RTO Insider LLC

Leopold said the ruling has resulted in a “burden shift.”

“If it’s a major question, the burden is now on the agency to say that they have the authority, rather on the petitioner who was challenging the agency rule to say … that that application of their authority was not a reasonable interpretation. So that’s a major change.”

He said the ruling also shifts the burden to Congress, which will be required to demonstrate “political will” to pass new legislation.

Aram said he expects “more incrementalist regulation so as not to cross this tripwire of major questions.

“So, I think it is going to require a change in tactics and strategy. I think it will result in some tension with the White House, because the White House absolutely loves to politicize any sort of policy. … It’s going to have to be much more strategic and cautious. And the [legislation] shops are going to have to be far more engaged.”

Leopold, a former Justice Department attorney, said if he were still advising federal agencies, “I would be telling them very specifically, do not characterize this in the press as ‘major, transformative, earth shattering, we’re going to save the planet’ unless you really do have clear authority to do so.

“Those types of grandiose statements [are] going to raise the hairs on the back of the neck of judges who care about [the] major questions [doctrine].”

What’s Possible in GHG Rules?

With new Clean Air Act amendments unlikely, it’s unclear what GHG regulations EPA could approve that would pass muster. The administration told the court in oral arguments in February that it planned to issue a replacement for the CPP by the end of this year.

Would carbon capture pass the court’s scrutiny, as Justice Kagan suggested in her dissent?

“I think that’s possible because that that would be a technology applied at the source, conceivably, if you had a way to sequester the carbon there or nearby,” said Leopold. “If you’re having to pipe it miles way to another reservoir, that could raise questions.”

Leopold said Kagan, however, ignored the Clean Air Act’s requirement that the “best system of emission reduction” also be “adequately demonstrated.”

“We know from attempts at the Kemper plant in Mississippi that carbon capture and sequestration for coal fired plants still has a lot of hurdles — financial hurdles, in particular.”

Posted on

NERC’s Cold Weather Work to Continue in 2023

ATLANTA — With NERC’s newest cold weather standards having passed their final ballot and ready for submission to the organization’s Board of Trustees, a member of the team that drafted the standards on Wednesday reminded stakeholders that the work of protecting North America’s grid from winter weather has only begun.

The new reliability standards EOP-012-1 (Extreme cold weather preparedness and operations) and EOP-011-3 (Emergency operations) were submitted to industry stakeholders for their final ballot Sept. 23 and passed Sept. 30, along with their implementation plan. Trustees are expected to approve them at the board’s upcoming meeting in New Orleans, after which they will await acceptance from FERC.

Speaking at the North American Generator Forum’s annual Compliance Conference at NERC’s headquarters, David Lemmons, co-founder of consulting firm Greybeard Compliance Services and head of NAGF’s Cold Weather Working Group,  jokingly observed that “it’s going to take a few days” for the standards to take effect. He was referring to the fact that EOP-011-3 will not be enforceable until 18 months after the commission grants its approval, while EOP-012-1 will not fully take effect for more than six years from that point.

Joining Lemmons was Occidental Power Services’ Venona Greaff, who outlined some of the changes that utilities can expect in EOP-012-1 and EOP-011-3. Greaff served on the standard drafting teams for both Project 2021-07, which drafted the new standards, and its predecessor Project 2019-06, which created three cold weather standards approved by FERC last year. (See FERC Approves Cold Weather Standards.)

The latest project was initiated in response to NERC and FERC’s joint inquiry into the winter storms of February 2021 that knocked thousands of megawatts of capacity offline in Texas and left households across the state without power for days. (See FERC, NERC Release Final Texas Storm Report.) Recommendations from the report include requiring generator owners (GOs) and operators (GOPs) to build or retrofit generating units to operate to specific ambient temperatures and weather, and to perform annual training on winterization plans.

The two standards passed last month comprise Phase 1 of the overall cold weather strategy and were developed under an accelerated schedule in hopes of getting them before FERC sooner. (See NERC Standards Committee Fast Tracks Cold Weather Project.) Now that their development is finished, the organization plans to move to Phase 2, which will address more recommendations from the report such as specifying the role of GOs and GOPs, as well as balancing authorities, in determining generator capacity, along with requirements protecting natural gas infrastructure from load shedding. NERC currently hopes to finish this stage by next year.

Although the SDT did not add these elements to its remit in order to avoid delaying completion, the members did take “some steps in Phase 1 to address some of the things that we’re going to have to address in Phase 2,” Greaff said. In particular, she noted the FERC-NERC report’s recommendation that GOs “identify cold-weather critical components and systems for each generating unit.” Greaff said the team decided to go ahead and create specific definitions of relevant terms so that “when we get to Phase 2, we [will] already have a foundation layer” to build on.

Posted on

NJ Bill Would Require Pension Divestment from Fossil Fuel Companies

New Jersey pension funds would be forced to divest from the largest 200 publicly traded fossil fuel companies under a controversial bill approved by the state Senate Environment and Energy Committee last week as the fall legislative session gathered pace.

The bill was one of five clean energy bills heard by the committee Thursday, including one that would stipulate how much time electric vehicle chargers installed with state incentives should be available for use, and one that would require utilities to plan for the growth in the use of distributed electric resources.

The committee voted 3-2 along party lines to move the disinvestment bill, S416, forward, sending it the Senate Budget and Appropriations Committee. The legislation, which has not moved in the General Assembly, would require the State Investment Council and the director of the Division of Investment to divest any stock, debt or other security investment from companies with large oil, gas or coal reserves within 12 months of the law’s enactment.

The Division of Investment manages seven public pensions that support the retirement plans of more than 800,000 members with a total, as of May, of $92.9 billion.

“What’s proposed here is sending a signal to the fossil fuel world and industry that we’ve got to find different ways to live and you, the companies that produce these fossil fuels, have to help us,” said committee Chair Bob Smith (D), who sponsored the legislation. He acknowledged that it is a “controversial bill.”

Sen. Edward Durr (R), who voted against the bill, said he feared that enacting the legislation would have “unintended consequences.”

“I think our voice is greater when we are invested into a company, and we have leverage,” he said. “Plus I believe it sends a signal of [the government] picking winners and losers, and I disagree with that.”

The bill’s advance comes nearly a year after the State Investment Council codified a strategy to pressure the companies it’s invested in to reduce their emissions, including an in-house assessment of emission-reduction efforts across its entire portfolio and participation in shareholder pressure tactics. (See NJ Pension Fund Backs Climate Strategy.)

Opponents of the bill include the American Petroleum Institute; the New Jersey Society for Economic, Environmental Development; and the New Jersey Chamber of Commerce. Supporting the bill are environmental groups Clean Water Action, Environment New Jersey and the League of Conservation Voters.

“We live in a capitalist society,” said Ed Potosnak, the league’s executive director. “And one of the ways that we shift what corporations do is by voting with our wallets.”

By disinvesting, the state would send a message to fossil fuel companies that “we want you to succeed … in a future that is ever increasingly ravaged by the effects of climate change” by adopting a “new operating model,” he said.

But Dennis Hart, executive director Chemistry Council of New Jersey, said the “short sighted” bill “removes New Jersey from influencing the direction of the fossil fuel industry.” He said the state’s corporations are already working hard to develop new technologies that will help mitigate climate change, and selling shares would take “the state away from the ability to influence these companies.”

“It’s similar to somebody saying, ‘I decided not to vote because I’m sending a personal message,’” he said. “I think that’s a bad policy.”

Raymond Cantor, a lobbyist for the New Jersey Business & Industry Association, noted that the pension fund is already underfunded, and now is the wrong moment to do “anything other than making sound investments.”

“From a fiduciary responsibility, the state should be making sure that its pension is invested in sound, legal investments, and should not be taking public policy and these types of concerns into the equation,” he said.

Barbara Powell, co-chair of Divest NJ, which was formed to push for the reduction in the pension fund’s investment in fossil companies, said the profits from the companies are a “negligible” part of fund returns.

“Staying invested in a sector whose days are numbered is not a fiduciarily responsible policy,” she said.

Meter Collar Adapters

The committee also unanimously approved a bill, S3092, that would require electric public utilities to authorize the installation and operation of meter collar adapters.

The small electronic device, which is installed between a residential electric meter and meter socket, facilitates the deployment and interconnection of an on-site electric generation source. That enables the customer to isolate their load and use backup power.

The bill would require an electric utility to approve or disapprove a meter collar adapter for installation in its service area within 60 days of a manufacturer submitting a request.

Zachary Kahn, senior policy adviser for Tesla, said that no utility at present allows the use of meter collar adapters, and he urged the committee to approve the use of a device that he said would simplify and speed up the process of installing residential storage and backup power.

“Meter collar adapters provide an immense opportunity to expedite the clean energy transition by allowing energy storage, solar and even EV chargers to be installed in a fraction of the time and at a fraction of the costs at residences,” he said.

The committee also unanimously backed legislation, S3102, that would direct the New Jersey Board of Public Utilities (BPU) to require that any electric service equipment installed with a state incentive should be operational 95% of the time. The BPU would have to develop and implement a process of monitoring incentive recipients to ensure that they are compliant.

Committee Chair Smith, a bill co-sponsor, said the bill stemmed from a media report that some chargers are “out of commission” 60% of the time.

“That’s unacceptable,” he said. “So this bill sets the standard for the uptime, meaning that it has to be working a certain percentage of the time to get any kind of government support.”

However, Nicholas Kikis, vice president of legislative and regulatory affairs for New Jersey Apartment Association, said that 95% is “too high.” The operators of chargers that do not reach that standard would get 18.5 days to reach the required uptime “or the incentive could be clawed back,” Kikis said. Such a penalty, he added, could dissuade people from seeking government support and so reduce the development of new chargers.

That issue is especially concerning given the state’s goal that by 2030 EV chargers be installed in 30% of all multifamily apartments, he said. “There’s right now insufficient incentives” to reach that goal, he said.

Preparing for Distributed Power Sources

Finally, the committee approved a bill, S2973, that would require electric utilities to submit integrated distribution plans (IDPs) to the BPU. Such a plan, developed by the utility, outlines the physical and operational changes to the transmission and distribution system needed to adapt to the use of DERs.

Introducing the bill before a unanimous vote, Smith said that the reason for creating an integrated distribution system is that it “makes for a stronger grid.” It would first require the BPU to develop criteria for the IDPs, and utilities would have to submit them within a year.

The bill, which Smith co-sponsored, has not moved in the Assembly. It is supported by Environment New Jersey and the Natural Resources Defense Council and opposed by the New Jersey Utilities Association.

Also opposing the bill, the New Jersey Division of Rate Counsel argued that the timeline for review of the IDPs is too short — 90 days — and includes a “lack of stakeholder involvement.”

In addition, the Rate Counsel said in an Oct. 5 letter to the committee, the bill should take the BPU process into account more.

“Rate Counsel would prefer sufficient time for thoughtful deliberation of the issues involved in the IDP approval process,” it said. It also “believes the board and stakeholders should be afforded no less than 180 days of review and approval of the submitted IDPs.”

The Rate Counsel also planned to oppose a second bill, S2978, that would revise the state’s renewable energy portfolio standards out of concern that it would be expensive for ratepayers. However, the bill — which has not advanced in either the Senate or Assembly — was pulled by Smith, the primary sponsor, who concluded after receiving stakeholder input that “it needs some adjustment.”

The bill would revise the RPS requirements for Class I renewable energy, starting in 2030. It also would require that after 2030, at least 50% of the renewable energy certificates used by an entity to satisfy the RPS requirement for Class I energy be generated in New Jersey. In addition, the bill would require that from 2045, 100% of energy sold at retail in the state would be from Class I renewable sources.

Posted on

MISO Rolls Up Sleeves on Capacity Auction Alterations

MISO told stakeholders Wednesday that it plans to add a sloped demand curve in its capacity auction and will make a FERC filing in the second quarter of 2023. 

The RTO’s Mike Robinson likened a sloped demand curve to his attempt to make an avocado-and-jalapeño-based gazpacho, but not having enough avocados to make the soup. He said when he went to the grocery store, he found surplus avocados priced at a quarter apiece and bought extra for the next night’s poke bowls.

That behavior showed that extra items beyond what is necessary still hold value. 

“We’re trying to recognize the value of that additional capacity beyond the planning requirement,” he said during a Resource Adequacy Subcommittee (RAS) meeting. “The additional 100 MW have reliability value beyond the reliability target, and we should reflect that in a cost-effective manner.”

Robinson said a sloped curve will make the auction more “sustainable” in the long run, sending price signals to plants to keep operating or reflecting the additional risk if capacity doesn’t cover their requirements. He said staff and stakeholders must figure out how to translate marginal reliability into dollar values. 

MISO says the incremental value of capacity might consider the avoided value of lost-load pricing and avoided high-priced emergency purchases.

Robinson said that over the last 10 years, the grid operator has been experiencing a “significant decrement” in its supply, which could have been helped with “some elasticity” in the demand curve. 

“If we’re going to do this auction, let’s do it right with prices that value capacity,” Robinson said. “We can do better than having a straight line, vertical demand curve.” 

Staff in July committed to a series of discussions with RAS over how the RTO might restructure its capacity auction with a sloped demand curve, among other changes. Some stakeholders said MISO needs to issue more detailed supply and demand data on a regular basis ahead of capacity auctions. (See MISO Promises Stakeholder Discussions on Capacity Auction Reform.) 

The RTO is holding auction-reform discussions as it begins organizing its first seasonal capacity auctions. In late August, FERC approved the grid operator’s plan to hold four simultaneous auctions for the 2023-24 planning year using an availability-based resource accreditation that relies on the presumptive riskiest hours in a season. (See FERC OKs MISO Seasonal Auction, Accreditation.)

MISO’s Durgesh Manjure said “some of the parts and plans are evolving” in implementing a seasonal auction and accreditation. Staff plans to publish draft accreditation values — based on a unit’s availability over the past three years and filtered by the RTO’s preselected, predicted risky hours — in November, with final numbers by mid-December. The grid operator has also scheduled office hours to answer questions about the new auction process.

At stakeholders’ request. MISO will allow mid-year capacity accreditation for new resources that will serve as replacement capacity.

CONE Goes Up

MISO has upped its cost-of-new-entry (CONE) for generators heading into the 2023-2024 planning year.

The highest CONE value is in eastern Missouri’s Zone 5 at a little more than $300/MW-day, the first time it has crossed that threshold. The lowest value can be found in East Texas and Louisiana’s Zone 9, at $257.75/MW-day.

MISO said CONE values swelled on “significant increases in base project capital costs and the weighted average cost of capital.” It said it used actual and expected inflation estimates to calculate the estimates.

Posted on

A New Path to Net Zero: High-performance Computing

Boston Metal has figured out a way to turn iron into steel without using coal, thanks in part to the Department of Energy’s high-performance supercomputers, which helped the Massachusetts-based startup model the superhigh temperatures — 1,600 degrees Celsius — needed for the decarbonized process.

“There are the electric chemical elements; there is the material fluid dynamics element. You have liquid metal; you have liquid electrolyte; you have oxygen bubbling through all of that,” said Adam Rauwerdink, the company’s senior vice president for business development. “This thermal modeling is a key element that you want to ensure you have all of your liquid metal and your liquid electrolytes in a molten form, that you’re not getting solid corners or freezing of the surface layers.”

Rauwerdink was speaking at DOE’s High-Performance Computing for Energy Innovation (HPC4EI) online workshop on Friday, where the focus was on the potential for high-performance computers (HPCs), and the ultrafast processing and simulations they offer, to overcome the challenges of decarbonizing heavy industry in the U.S. by 2050.

“We use computer simulations to short-circuit the usual Edisonian approach” — engineer-speak for trial and error, said Aaron Fisher, the HPC4EI project manager at Lawrence Livermore National Laboratory.

In other words, researchers and technology developers can use the computers to simulate and test models of new equipment, new materials and new processes and iterate at warp speed through the trial-and-error phase of project development, without running up costs for repeated lab or field demonstrations.

U.S. manufacturing is in the midst of a technological revolution, Fisher said. “This revolution, instead of being powered by machinery, is being powered by the great expansion of our ability to [collect] data and process it and predict the outcomes, using that data. The data revolution is leading us to new ways of producing things … it’s allowing us to rethink how we develop manufacturing processes themselves.”

The HPC4EI program provides $300,000 awards to companies, allowing them to work with researchers at DOE’s national labs, which house a wide range of supercomputers. Oak Ridge National Laboratory’s Summit system, for example, has been ranked as one of the fastest computers on Earth, capable of processing 200,000 trillion calculations per second.

Since it was started eight years ago, HPC4EI has funded close to 150 projects, working with more than 80 companies of all sizes, from startups to major corporations, Fisher said. The companies benefit from smarter product designs and faster time to market, while also improving efficiency and saving money, he said.

Researchers at the labs also benefit “by cutting their teeth on a new class of problems that they may not have thought of before. This leads to new thinking and computational methods.”

Fisher cited a number of HPC4EI projects, such as working with ArcelorMittal to reduce the amount of natural gas needed to reheat steel slabs before they are rolled out into sheet metal. The program also paired up Raytheon and Oak Ridge National Lab for “microstructural phase field simulations” that resulted in the manufacture of lighter airplane parts, which could eventually help airlines save on fuel costs.

In the case of Boston Metals, DOE provided early funding and technical support for the company’s development of its molten oxide electrolysis process for making steel. As described on the company website, the process involves an electrolyte containing iron ore, which is electrified to 1,600 degrees Celsius, splitting off the oxygen from the ore to produce liquid metal.

The company is working toward its first commercial-scale plant in 2025, with investors that include Bill Gates’ Breakthrough Energy Ventures, utility-funded Energy Impact Partners and The Engine, a venture fund that, like Boston Metal, began as a spin-off from the Massachusetts Institute of Technology.

The impact could be significant. According to Rauwerdink, the 2 billion tons of steel produced with coal worldwide per year pumps 3.5 billion tons of CO2 into the atmosphere, or about 8% to 10% of all global CO2 emissions.

Scaling the technology on a global basis, which is part of Boston Metal’s long-term plan, will require even more sophisticated computer modeling, he said. “You just keep adding additional levels of complexity to your modeling.”

Scale up or Scale out?

DOE has recently intensified its focus on industrial decarbonization, for example, releasing an Industrial Decarbonization Roadmap last month, with plans and milestones laid out for the country’s five most carbon-intensive industrial sectors — iron and steel, chemicals, cement, food and beverage production and petroleum refining. 

These industries and other manufacturing and industrial sectors account for 33% of U.S. energy consumption and 30% of carbon emissions, the roadmap said, citing figures from the Energy Information Administration.

DOE’s Advanced Manufacturing Office (AMO) will also be split in two, with one office still focusing on advanced manufacturing and a second targeting industrial decarbonization, according to Robin Miles, HPC4EI director at the Livermore Lab.

“We now have a really unique time to be able to change the way we have been doing things for centuries or, in some cases, millennia, and really rethink what that means,” said Joe Cresko, AMO’s chief engineer. “We’re going to really need to do a lot of research and development, and expedite that, accelerate that, and have a deeper understanding about the options and impacts of making these changes.

“High-performance computing is a really important part of that,” Cresko said. Continuing business as usual could result in a 17% increase in U.S. carbon emissions by 2050, he said.

Supercomputers can analyze multiple paths and options for reaching net-zero — and the tradeoffs each may entail, he said. “We need to ensure reliable and electrified services, which means you need to be able to integrate into the grid intermittent energy sources. We need to consider the ability to use hybrid and dual-fuel sources [and] more efficient heat transfer at all scales.

“Modular approaches may be a way to really transform some of the operations that are done at very large economies of scale,” Cresko said. “Instead of scaling up, can we scale out? What [do] those processes look like as we begin to change?”

Next-gen CSP

Cresko and others at the workshop see HPC playing a central role in accelerating the scaling and commercialization of still emerging technologies — such as green hydrogen, carbon capture and sequestration, and concentrated solar power — that are increasingly seen as vital for achieving a net-zero economy in the U.S. by 2050.

While once considered a promising and possibly better technology than photovoltaic solar, concentrated solar power (CSP) lost momentum in the U.S. after a few large projects were completed in the Southwestern desert — most notably the 386 MW Ivanpah project near Las Vegas. PV was cheaper, easier to permit, simpler to operate and less environmentally disruptive.

Total global capacity for CSP currently stands at about 7 GW, according to Avi Shultz, DOE program manager for CSP. The technology uses large mirrors, called heliostats, to reflect and concentrate sunlight onto a tank at the top of tower, Fluid in the tank is heated to very high temperatures, 500 degrees or more, to produce steam that can then run a turbine or be stored for later use.

While no major CSP plants are under construction in the U.S., China is in the process of building 30 CSP projects, as a form of storage for larger installations combining PV and wind energy. Renewed interest in the technology has also surfaced in Australia.

DOE’s efforts to rebuild U.S. innovation and competitiveness in the technology, specifically as a potential source for process heat for heavy industry, could breathe new life into the U.S. market. The department recently released a roadmap for next-generation heliostat production and awarded $24 million in funding for a range of projects, such as developing CSP technologies to be used to decarbonize the production of cement and limestone.

Decarbonizing heavy industry could require CSP projects that can produce heat at 700 degrees Celsius, Shultz said. DOE also wants to cut the levelized cost of CSP, with 12 hours of storage, from its 2020 rate of 9.5 cents/kWh to 5 cents/kWh by 2030.

A team at NREL is “trying to model the field-level wind forces in the heliostat field, which … [can] become extremely complex and nonlinear,” Shultz said “This really calls out for computational analysis. The number of power metrics and variables in ways you can optimize these systems becomes very, very quickly unmanageable. So really clever computational approaches to solving and optimizing heliostat fields both at the component level and at the overall field and operational level really are necessary to hit our targets for cost and performance.”

Posted on

ISO-NE Proposes Tweaks to Inventoried Energy Program

ISO-NE is proposing changes to its winter fuel security plan, the Inventoried Energy Program, to answer a court order and, more significantly, account for the swirling global natural gas markets.

The IEP is set to be in place for the 2023-2025 winter seasons and will compensate resources for the inventoried energy they hold on winter days that hit a certain low-temperature threshold.

Coal, biomass, hydropower and nuclear generators will no longer be eligible for the program, after the D.C. Circuit Court of Appeals found that they would get $40 million in windfall payments for storing energy they would have kept anyway. (See Court Strikes a Blow to ISO-NE Winter Plan.)

In a presentation to the NEPOOL Markets Committee on Wednesday, ISO-NE Regulatory Counsel Kathryn Boucher laid out the grid operator’s relatively simple response to the court ruling and subsequent FERC order, which clarifies that those asset types can’t be included in the program.

ISO-NE is planning to put forward a compliance filing in mid-November.

Tweaking the Program to Address Market Changes

On a separate track, the grid operator is looking to make longer-term changes to the IEP to try to attract more market participants to use the program and help increase the region’s reliability.

“Increased global competition for oil and LNG has changed these markets relative to when the IEP was first designed,” ISO-NE’s Craig Martin said in a presentation to the MC.

The grid operator is proposing to change how the IEP payments are calculated and how gas contract eligibility works under it. It is working with Analysis Group to recalculate forward and spot rates for the 2023/2024 winter, using updated energy market pricing and LNG contract structures.

It’s also calling for a change in the terms of the program that state that “no limitations” can exist on when gas can be called.

And ISO-NE is proposing modifying the price eligibility threshold, which was included to “prevent contracts with very high incremental costs to buying gas from being eligible.” The shift from a Henry Hub/Algonquin Citygate metric to a Dutch Title Transfer Facility metric will “reduce the risk of gas contracts unintentionally being rejected due to potential price deviations between the cost of procuring LNG and domestic gas markets,” Martin said.

ISO-NE is also looking at potentially changing the duration of inventoried energy required from 72 to 120 hours and increasing the temperature point that triggers the program.

“ISO believes these updates will increase the quantities of inventoried energy attracted to the region for winters 2023/24 and 2024/25,” Martin said.

The grid operator is looking to get to a final NEPOOL vote on the changes in January 2023.

Posted on

NYC Proposes Rules to Implement Building Emissions Law

The New York City Department of Buildings (DOB) last week proposed new rules to carry out a 2019 local law aimed at reducing carbon emissions from the city’s largest buildings.

The agency also identified the 27,000 buildings that will be covered by Local Law 97 (LL97) and subjected to the first compliance deadline scheduled for 2025.

Enacted by the New York City Council three years ago as part of the NYC Accelerator program, LL97 established greenhouse gas emissions standards for most city buildings that exceed 25,000 square feet by requiring improved energy efficiency. The law also imposed stricter emissions reporting requirements on the covered buildings.

The rules proposed last week are intended to clarify and strengthen LL97 by setting building emission factors until 2050, simplifying administrative reporting processes, detailing formula for calculating a building’s annual emissions or energy usage, and setting up rules governing renewable energy credits (RECs) that property owners can buy to help meet targets.

The buildings subject to the rules range from government and military installations to religious centers, grocery stores and business offices, with the largest structures requiring initial compliance by 2024 followed by stronger limits in 2030.

LL97 was designed to cut emissions from the city’s largest buildings by 40% by 2030 and 80% by 2050. RECs, which were written into the law, could be bought by proprietors to help meet their emissions targets and would be used to help fund other renewable efforts or projects.

REC Rules ‘Far Too Weak’

Under the rules, the RECs can be generated by state renewable projects and are intended as economic tools to help building owners offset the emissions generated from electricity supplied by natural gas and avoid hefty non-compliance costs as they begin to bring their stocks into LL97 compliance.

Specifically, credits could be used to fund Tier 4 projects, such as the Clean Path New York and Champlain Hudson Power Express, which have seen recent implementation delays. (See NYSERDA Seeks 1-Year Delay for Tier 4 RECs)

In an email to NetZero Insider, DOB Press Secretary Andrew Rudansky said “this first batch of proposed rules” clarifies that building owners can only apply RECs to offset emissions from electricity use, preventing them from using RECs to offset other types of emissions associated with their buildings.

“The department will be releasing additional rules on how the use of RECs is limited in the future. Our rulemaking process will continue to be informed by careful study by the department’s Bureau of Sustainability along with close collaboration with our partner agencies, the Climate Advisory Board, the Local Law 97 Working Groups and also with state government officials,” Rudansky said.

Additionally, Rudansky said the DOB is “currently working with stakeholder partners to study RECs” and noted that credits have “always been part of the Local Law 97 equation,” pointing to language in the original law as evidence.

That language stipulates that a “deduction from the reported annual building emissions shall be authorized equal to the number of renewable energy credits purchased by or on behalf of a building owner.” It also requires that the resources generating eligible RECs be located in or directly deliverable to the New York grid operator’s New York City load zone; that the RECs be solely owned or retired on behalf of the building owner; and that they be generated in the same period as the reporting year.

“Covered buildings claiming deductions for renewable energy credits under this section must provide the department with the geographic location of the renewable energy resource that created the renewable energy credits. The [DOB], in consultation with the mayor’s office of long-term planning and sustainability, shall promulgate rules to implement this deduction,” the law states.

Despite the clarification, some environmental groups were still unsatisfied with the RECs provision.

In an online statement, a coalition of local organizations protested the new rules saying that although “Mayor [Eric] Adams is taking positive steps,” the current rules around RECs are “far too weak” and that moving forward the administration should “tightly limit RECs so they cover only up to 10% of a building’s total pollution.”

The DOB will be hosting an online public hearing on the proposed rules on Nov. 14. Public comments can be submitted to DOBRules@buildings.nyc.gov, while stakeholders can learn more about how to meet emissions targets through the NYC Accelerator program.

Posted on

Study: NYISO Dynamic Reserves Could Lower Congestion, Costs

NYISO’s proposed dynamic reserve requirements could result in significant changes in transmission flows and reduced costs, according to the findings that FTI Consulting presented to the NYISO Installed Capacity Working Group (ICAPWG) last week.

FTI’s Scott Harvey described how each element of the dynamic reserve design, first published in a white paper in December 2021, could result in reduced costs of meeting load, while maintaining reliability and meeting reserve targets.  

The ISO’s project was conducted to see if dynamically scheduling reserve requirements or procurements for generators could support New York’s Climate Leadership and Community Protection Act (CLCPA) by allowing more economic clean energy to be imported into the state, which would better align market outcomes with system operations. (See NYISO Exploring Dynamic Reserves.)

New Dynamic Reserve Project (FTI Consulting) Content.jpgSummary of FTI Consulting examination of new dynamic reserve project | FTI Consulting

 

NYISO’s existing operating reserve requirements are static; the white paper argued that a dynamic approach would “allow for appropriate reserves to be procured to cover the largest contingency,” while also allowing “for more reserves to be scheduled in cost-effective areas to meet the reliability needs,” which has become increasingly important as more intermittent generators are installed.

FTI’s study highlighted how dynamic reserve requirements can save money by replacing imported megawatts during periods of constraint with those directly from generators in load pockets.

Mark Younger, president of Hudson Energy Economics, commented how the proposal “is a pretty significant change from how things are currently done,” as it would “make contingency based on the actual loading of the unit rather than its capacity,” which he believes the ISO should make “very clear to stakeholders.”

FTI plans to return later in the year to share more examples of how dynamic reserve requirements will impact the system, including instances where intermittent resources are in load pockets.

Tariff Revisions on CRIS

NYISO also continues to work on proposed tariff revisions that would modify its rules for deactivated facilities with unexpired capacity resource interconnection service (CRIS).

The ISO’s Juan Sanchez told the ICAPWG that stakeholder feedback received on the tariff revisions discussed at previous meetings were mostly requesting additional “clarification around the rules.” The project is investigating ways to tighten the rules for CRIS retention where it is not fully utilized, while also increasing capacity deliverability headroom and potentially lowering the cost of market entry for future facilities. (See NYISO Proposes Changes to CRIS.)

Tariff Revisions for CRIS (NYISO) Content.jpgSummary of proposed tariff revisions for the CRIS expiration evaluation project | NYISO

 

NYISO wants to modify the rules and processes for deactivated facilities with unexpired CRIS by allowing them to voluntarily relinquish their full CRIS at any point in time simply by notifying the ISO. It would develop a standardized notification form, which, once received, would prompt it to stop including the facilities in future deliverability studies.

The revisions would also expire partial CRIS rights for transmission facilities limited from using their full CRIS because of physical limitations in neighboring control area systems. This provision would apply to transmission facilities that are not meeting ISO procedures because their net megawatt output is not reaching full capability, reducing their CRIS to the maximum monthly amount of energy demonstrated during a consecutive three-year period starting from initial synchronization.

They would also allow for same-location CRIS transfers to have the same flexibility as those between different locations. Units in the process of shutting down, or mothballing, would be allowed to transfer part or all their CRIS to a same-location facility even while the unit is deactivating.

Doreen Saia of Greenberg Traurig raised the point that the revisions need to take physical withholding rules into account because there will be facilities “not necessarily retiring until some future point” but are remaining on the grid for the near future and requesting CRIS transfers.

Saia argued that a challenge will emerge when the ISO “puts their marker in the sand to do a physical withholding assessment” and there will be units whose reliability status is unclear but are requesting an “ex ante determination,” making forecasts unclear for stakeholders.

NYISO will return to a future working group meeting to share any additional feedback it receives from stakeholders concerning the new tariff language. It asks that all comments be emailed to Sanchez (jsanchez@nyiso.com).