Search
`
November 11, 2024

Posted on

Mass. DPU Moves to Streamline Municipal Aggregation

The Massachusetts DPU is looking for ways to streamline its review of municipal electric supply aggregation plans.

Tuesday’s Department of Public Utilities order (Docket 23-67) includes proposed guidelines and a draft template to help municipalities develop new aggregation plans. The DPU is proposing to expedite its review process for certain municipalities that use the template.

Many of the rules governing what must be included in a municipal aggregation plan have already been established through other DPU orders, but the guidelines proposed Tuesday would gather them in one place and provide a simplified explanation for them.

Municipal aggregation holds the promise of lower electric costs for ratepayers, as their city or town buys power for them in bulk. And some community choice aggregation packages have the added benefit of boosting the clean energy transition, if they specify use of renewable energy certificates.

A University of Massachusetts-Amherst report issued in February found that these plans saved money for residents of 79% of the municipalities that developed them. (See Community Choice Aggregation Benefits in Mass. Quantified.)

But the DPU has taken some criticism for the speed with which it approves them. The Boston Globe this year reported that Massachusetts’ two U.S. senators were urging DPU to “stop holding up communities’ attempts to cut utility bills and emissions.”

In the UMass-Amherst study, 26% of responding municipalities decried detrimental DPU delays.

The DPU addressed that in the order it issued Tuesday.

It said it has reviewed each aggregation request on a case-by-case basis, creating a continually evolving body of precedent that future applicants must continually monitor and adjust to.

“As a result, there is an unacceptable backlog of applications pending at the department that suggests a different approach is warranted,” the order reads.

“By providing this clear direction and otherwise streamlining the process for reviewing and approving municipal aggregation plans, the department intends to move expeditiously to address the backlog of applications currently pending before the department, as well as simplify the process going forward in the interests of reducing the administrative resources — on the part of both the municipalities and the department — devoted to this issue.”

The DPU is seeking public comment on the proposals through Sept. 18.

Massachusetts established municipal aggregation in 1997. The DPU has approved more than 175 programs since August 2000, and more than 1.2 million customers statewide are enrolled in an aggregation plan.

Posted on

The IRA at 1: Implementing at Speed and Scale Remains Key Challenge

As the Inflation Reduction Act begins its second year of implementation, one of the key measures of the law’s success is the wave of new clean technology manufacturing plants and investment dollars going to districts with Republican members in Congress, according to Jason Grumet, CEO of the American Clean Power Association (ACP).

“The vast majority of the benefits are going to states that tend to be governed by conservatives,” Grumet said during a Monday webinar reviewing the IRA’s first year. With ACP tracking more than $270 billion in private sector investments announced in the past year, about 80% of that money is going to districts with Republican lawmakers in Congress, while 60% of the manufacturing plants also are going into Republican-held districts, he said.

“And so, I think what we’re going to see is that the polarization that has been driving so much of the energy and climate debate is going to really start to settle out as it becomes clear that this is American energy and American resources and American communities and American jobs,” Grumet said.

Grumet and other industry leaders on the panel agreed that the investments and jobs flowing into red states make it increasingly unlikely Republicans in Congress will try to claw back any of the $370 billion in clean energy funds in the law.

“The reality is, at the ground level, [the IRA] was not an issue in the 2022 election,” said Gregory Wetstone, CEO of the American Council on Renewable Energy (ACORE), which sponsored the event. “The best way to make sure [repeal] doesn’t happen … is to see the law carried out.”

Republican lawmakers would be at pains to “turn back the clock and close down this new manufacturing facility in [their] district,” Wetstone said. “I don’t think it’s going to happen. … It would be extremely difficult politically.”

But the IRA has been a political flashpoint almost from the start. The law was passed in the House of Representatives and Senate on straight party-line votes (with Vice President Kamala Harris breaking the tie in the Senate), following intense, behind-closed-doors negotiations between the White House and Sen. Joe Manchin (D-W.Va.). The law was passed as a budget reconciliation measure, meaning it needed only a simple majority in both houses.

The incentives in the law range from the $7,500 tax credit for electric vehicles, to a 10-year extension of the 30% investment tax credit (ITC) for solar and other clean technologies, to $8.5 billion for consumer rebates for energy-efficient appliances and home upgrades.

A recent report from ACP counted 83 announcements for new cleantech manufacturing facilities across the country, expected to create an estimated 30,000 jobs. New clean energy projects totaling close to 185,000 MW also have been announced, the report said. (See American Clean Power Tallies Potential Impact of IRA at $270B.)

The ITC was a key provision for the solar industry, said Abigail Ross Hopper, CEO of the Solar Energy Industries Association.

Noting that the industry has had to contend with the uncertainty of previous one- and two-year extensions of the credit, Hopper said, “to have a 10-year runway has really been quite a revelation. This first year, there’s been a level of relief and optimism and long-term planning that at times felt a bit elusive.”

The tax credits also are structured to advance certain policy initiatives, such as bonus credits for projects with prevailing wage agreements and registered apprenticeship programs, or for using materials that meet domestic content requirements.

Such provisions forge “a direct connection between policy outcomes and investment decisions,” Hopper said. “So, we’re seeing projects really driving toward particular geographies; particular materials; in particular communities. That sort of linking … means that there will be a much greater likelihood that the investments are going to be built and the money spent in areas that perhaps in the past have not seen the benefits of this kind of investment.”

Public Awareness vs. Results

But implementation of the IRA has not been smooth or easy. Manchin has broken with the White House over the Treasury Department’s guidance on domestic content requirements for certain tax credits that he says do not follow the letter of the law.

Treasury still is working its way through the guidelines it must issue for tax credits and other provisions in the law. A page on the Internal Revenue Service website, last updated on Monday, lists 27 notices the agency has issued to date on the various provisions of the law.

Public awareness of the law and its benefits for consumers is another ongoing challenge, with significant political implications for President Joe Biden heading into next year’s presidential election. A recent poll from George Mason University found that four out of 10 registered voters said they knew nothing about the IRA, while six in 10 said they knew “a little.”

But Heather O’Neill, CEO of Advanced Energy United, said knowing the name of the law may be less important than seeing and experiencing its results. “What we want are benefits,” she said. “We want steel in the ground. We want new projects, new products, new manufacturing, new economic development and new ability for consumers to purchase these products and goods and services.”

The bigger roadblocks for implementation are well known, Grumet said: transmission, permitting and workforce development and the politics surrounding those issues. But he views the challenge as a critical opportunity for the industry.

“The fact that we are now confronting these fundamental, big-term structural challenges to scaling clean energy is great news, right? Because we’re not going to have any version of a sustainable climate economy or national security picture if we don’t make a profound transition in our energy system, which I don’t think very many people have appreciated the scale of in terms of those challenges,” he said.

Wetstone agreed, saying the issues arising out of implementation of the IRA are “a result of trying to get something done really rapidly, which is the pace we need to go to address the climate crisis. So, I actually think it’s a very good thing that we’re being forced to come to grips with all this.”

He and the other panelists agreed that while a deal on permitting is possible this year, finding a spark to trigger bipartisan cooperation and action is less likely.

“There’s no committee that has the jurisdiction to put the pieces together that are necessary for a politically viable outcome,” Grumet said. “So, the only way we’re going to get a deal through this divided Congress is if there was … support for transmission, particularly interregional transmission.”

Making the profound changes ahead also will mean the clean energy industry has to rethink its role in the mainstream energy system, he said.

“If we’re going to be honest about what this transition looks like, we have to embrace where we are today, which means we have to be part of the energy sector; not the renewable power sector, not the clean power sector, [but] the energy sector. … We think we’ve got the best technologies. Give us fair competition based on economics and security and climate change, [and] clean power is going to win. We’re going to win on the merits, and we’re going to win in a collaborative environment.”

Posted on

SPP Awards NextEra 3rd Competitive Project

Three weeks after it was unable to agree on a recommended developer for a competitive upgrade in New Mexico, SPP’s Board of Directors regrouped Tuesday and endorsed an industry expert panel’s initial direction.

Following a brief virtual discussion, the board approved a notification to construct award to NextEra Energy Transmission (NEET) Southwest as the Crossroads-Hobbs-Roadrunner transmission project’s designated transmission owner.

Xcel Energy subsidiary Southwestern Public Service (SPS), the incumbent transmission provider, was selected as the upgrade’s alternative designated TO.

NEET Southwest’s bid came in at $291.6 million to build the proposed 90.5- and 44.5-mile, 345-kilovolt lines to connect the Crossroads, Hobbs and Roadrunner substations. SPS’ bid came in at $220 million.

NEET Southwest and SPS were the only entities to submit proposals. A third proposal that came in at $282.7 million is thought to be NEET Southwest’s; according to the IEP’s report, the two proposals were similar, but the SPS bid offered a construction schedule of one year, half as much as the other two.

“No explanation, method or means was provided in the proposal to support the indicated timeframe to construct,” the IEP said of the SPS bid.

The board failed to reach a decision during last month’s board meeting in St. Paul, Minn., when some of the directors were unable to get satisfactory answers from the IEP on the cost and timelines of the winning bid. The board rejected the panel’s recommendation after the Members Committee’s straw ballot gained only three votes in favor. (See SPP Board Rejects Recommended Competitive Project.)

The Members Committee’s straw vote passed in a 10-7 vote. The committee also approved SPS as the alternate DTO 10-2, with five abstentions.

SPP director Larry Altenbaumer | © RTO Insider LLC

Larry Altenbaumer, one of the more vocal directors during the July discussion, supported the IEP’s recommendation during the Tuesday call.

“As a board member, I don’t have the credentials or the analytic ability to independently develop my own recommendation, and I don’t think it is either the job of me as a board member or the IEP to try to resolve deficiencies in terms of proposals that are submitted,” he said.

“I remain a very strong supporter of the competitive process. but in the end, my conclusion is that the shortfalls we have in this particular process were largely shortfalls in terms of what had been submitted by proposals,” Altenbaumer said.

He said he still was unsatisfied with the panel’s response to one of 10 questions the directors asked the industry experts. Asked to explain who the panel would have recommended had the scores been the same, the IEP acknowledged the scores were very close.

“Therefore, the essence of this question was discussed in the selection of the proposals,” the panel wrote. “The IEP concluded that based on the review of factual information in the proposals as described in the IEP report, the IEP made and stands by its recommendation as stated in the IEP report.”

Altenbaumer said he planned to suggest additional considerations “that I think can further strengthen what is already a very high-quality and comprehensive competitive bid process.”

SPP will review its competitive transmission owner selection process, required under FERC Order 1000, for potential improvements. The grid operator has done the same thing after the four previous IEP panels.

NEET Southwest has been awarded SPP’s last three competitive projects, including Wolf Creek-Blackberry in Kansas and Missouri and Minco-Draper in Oklahoma. (See “Expert Panel Awards Competitive Project to NextEra Energy Transmission,” SPP Board of Directors/Members Committee Briefs: Oct. 26, 2021. See SPP Board of Directors/Markets Committee Briefs: April 26, 2022.)

The IEP was seated last August to evaluate anonymous bids for the project. The upgrade, initially estimated to cost $376.3 million, was proposed by SPS as an alternative to a previously identified project in the 2021 Integrated Transmission Plan. (See SPP Board of Directors/Members Committee Briefs: July 26, 2022.)

Posted on

NYPSC Seeks FERC Rehearing on NYISO’s 17-Year Amortization

The New York Public Service Commission on Monday asked FERC to rehear its order approving NYISO’s proposal to use a 17-year amortization period in the ISO’s capacity auction demand curves (ER21-502).

The PSC said its rehearing request is supported by points it made last month in a petition urging the D.C. Circuit Court of Appeals to review FERC’s decision to allow the ISO to reduce the 20-year amortization period — the assumed time that a hypothetical gas-fired peaking plant will remain operational — to 17 years. (See DC Circuit Asked Again to Rule on NYISO’s 17-Year Amortization.)

NYISO proposed the changes in response to legislation that set strict net-zero standards for fossil fuel plants, reducing their operational lives, but the PSC said the move will hurt consumers and “cause an increase in over $100 million in unhedged capacity costs for the state.”

The PSC noted that FERC’s letter order accepting the amortization proposal departed from precedent because the commission accepted the NYISO plan without explanation after having rejected it twice previously.

The FERC-approved demand curves became effective in July, prompting the PSC to seek a quick ruling because the use of the new amortization period in auctions “will wrongfully increase by hundreds of millions of dollars per year the wholesale electricity rates paid by New York ratepayers between July 2023 and March 2025.”

The PSC also contended that NYISO’s proposal is speculative, basing current demand curves on technologies that are either not yet in development or may never exist, highlighting how previous rulings wrote that state legislation “does not require that all existing fossil fuel generators retire by no later than 2040 to satisfy the 2040 zero-emission requirement.”

NYISO implemented the 17-year amortization period as part of its demand curve reset to adjust market demand assumptions for upcoming capability years.

Posted on

VP Harris Leads Seattle Anniversary Celebration for IRA

SEATTLE — Vice President Kamala Harris on Tuesday headlined a political cheerleading session at a Seattle-based building products and services company to celebrate the first anniversary of the passage of the Inflation Reduction Act (IRA).

“While there is still more to do, the president and I have shown how much we can accomplish together,” Harris told about 250 people at the headquarters of McKinstry, which specializes in designing, building and modifying large facilities to make them energy-efficient.

Harris praised the IRA, for which she cast the deciding vote in a divided U.S. Senate last summer. Funding from the bill has created 175,000 clean tech jobs, she said. 

Harris also spoke about the prospect of solar and wind farms springing up around the nation, especially in rural areas, leading to the installation of thousands of miles of power lines — with the accompanying jobs — to transmit that electricity to cities. 

“The energy not only will be a lot cleaner, but cheaper,” she said, adding that alternative energy sources are becoming more reliable.

Harris IRA

Energy Secretary Jennifer Granholm | © RTO Insider LLC

Secretary of Energy Jennifer Granholm talked about how U.S. states and other nations saw the federal government as a passive player in combating climate change until passage of the IRA.

“Other governments saw us as bringing a knife to a gunfight,” Granholm said.

Now the U.S. is the world leader in clean energy investments, she said.

“We’re back in the game, baby,” she shouted.

U.S. Sen. Maria Cantwell (D-Wash.) said McKinstry has grown and could double or triple its 1,000 union jobs. “Washington, we are leading the acceleration to clean energy,” she said.

Washington Gov. Jay Inslee (D) said the world has been dealing with increasing floods, melting ice caps and the massive wildfire in Maui. “This isn’t your grandma’s climate change anymore. It is a new beast,” he said.

Posted on

BOEM IDs Oregon Wind Energy Areas

The U.S. Bureau of Ocean Energy Management on Tuesday selected two draft wind energy areas (WEAs) off the coast of southern and central Oregon, opening a 60-day review-and-comment period.

The WEAs comprise about 220,000 acres in the Coos Bay and Brookings call areas that BOEM outlined in February 2022. The bureau has yet to identify a WEA in the third call area off the coast of Bandon, Ore.

Together, the three large call areas could support up to 17 GW of generating capacity, but BOEM said last year it intends to consider 3 GW for near-term commercial development.

The draft WEAs further the Biden administration’s goal of deploying 15 GW of floating offshore wind in deep waters by 2035, BOEM said.

“As BOEM works to identify potential areas for offshore wind development, we continue to prioritize a robust and transparent process, including ongoing engagement with tribal governments, agency partners, the fishing community and other ocean users,” BOEM Director Elizabeth Klein said in a statement Tuesday.

“At the request of Oregon’s governor and other state officials, there will be a 60-day public comment period on the draft WEAs, and BOEM will hold an intergovernmental task force meeting in addition to public meetings during the comment period,” Klein said. “We look forward to working with the state to help us finalize offshore areas that have strong resource potential and the fewest environmental and user conflicts.”

The Oregon WEAs are the latest developments in the emerging market for West Coast offshore wind.

BOEM held the first West Coast wind auction on Dec. 7, 2022, when five lease areas off the California coast, with 4.5 GW of total capacity, brought more than $757 million in winning bids. (See First West Coast Offshore Wind Auction Fetches $757M.) Three of the lease areas are in Morro Bay off the coast of Central California, and two are in Humboldt Bay off Northern California.

The auctions were held after a multiyear process like that now playing out in Oregon. In California, BOEM identified large call areas, then selected WEAs within the call areas and eventually auctioned parcels to developers.

Oregon’s Brookings Call Area sits about 60 miles north of the Humboldt WEA, raising the possibility of collaboration between West Coast states on developing port infrastructure and a supply chain that takes advantage of economies of scale.

BOEM has yet to identify any call areas off the coast of Washington state.

Posted on

NJ Seeks Stakeholder Input on Pending Storage Program

New Jersey is asking for more stakeholder input to help shape its much-awaited plan to boost its storage capacity as it strives to reach 2,000 MW by 2030.

In a request for information issued Aug. 9, the New Jersey Board of Public Utilities seeks comments on four areas of its New Jersey Energy Storage Incentive Program (SIP) that will be key to the final proposal. Among them are:

    • what role electric utility companies should have;
    • how big and in what form incentives should be granted; and
    • how quickly and over what timeline storage approvals should be granted.

The BPU also wants input on the form of the incentives designed to help overburdened communities (OBCs) and a variety of smaller issues.

The request follows considerable earlier public input on the SIP proposal, with three BPU hearings in October and November that raised a number of contentious issues the board now wants stakeholders to help further clarify.

One of them is how to adjust, if necessary, the board’s initial proposal to prohibit utilities from owning storage projects, a measure designed to better stimulate private investment and ownership in the sector. After resistance to the proposal from utilities and their supporters, and backing from some interest groups, the BPU seeks comment on the advantages and disadvantages of “utility control verses non-utilities control” of energy storage systems. (See Utilities Oppose NJ BPU Plan Limiting EDC Storage Ownership.)

Critical Resource

New Jersey has for years prioritized storage development, believing it will help provide energy when intermittent sources such as wind and solar do not. Yet the state is only about a quarter of the way toward its 2,000-by-2030 goal. (See NJ Lagging in Energy Storage Progress.)

“Energy storage resources are critical to increasing the resilience of New Jersey’s electric grid, reducing carbon emissions and enabling New Jersey’s transition to 100% clean energy,” the BPU said in the order outlining the RFI. The program “will build a critical foundation for a long-term energy storage effort in the state.”

Hoping to jump-start the process, the board in October outlined the SIP, which aims to stimulate private investment in storage by awarding fixed annual incentives to both utility-scale and distributed projects and “pay for performance” incentives in certain situations. The program’s goal is to implement 1,000 MW of four-hour-plus storage by 2030. (See NJ Offers Plan to Boost Lagging Storage Capacity.)

The RFI poses a series of detailed questions about the two-tiered incentive plan. One question, for example, asks for stakeholder input on what would be the “fully installed cost” (in dollars per kilowatt-hour) for storage systems and how they would vary in New Jersey from other places. The RFI also asks how the BPU should structure its performance-based incentives, including a Peak Demand Reduction program, and whether it would work in New Jersey.

Another question asks whether modifications to the SIP are needed to maximize the ability of energy storage developers to access federal investment tax credits or other incentives. That issue could be important because the Inflation Reduction Act, signed a year ago, includes tax credits for battery storage systems.

The solicitation also asks, “How can BPU assure that the incentive structure chosen will in fact provide benefits to OBCs?”

Contentious Issues

The public hearings solicited numerous live comments and 61 written comments, the BPU said (QO22080540). While many people supported the plan, according to the solicitation document, “many commenters argued that the size of the overall program and individual capacity blocks” under which incentives would be awarded were too small, especially for distributed storage.

Two main points of contention emerged, the RFI said: “While many commenters agreed with staff’s proposal to not provide incentives for utility-owned energy storage, numerous others argued that utility-owned energy storage systems should qualify for incentives.”

In addition, “many commenters contended that energy storage developers and/or private owners should be able to retain control over their energy storage systems while earning performance incentives, while others argued such systems should be under utility control.”

In the second area of disagreement, some commenters felt the program should start slowly and scale up, while others said it should “start larger and scale back over time,” the solicitation said.

In a December letter to the board, the Center for Sustainable Energy (CSE) argued that the BPU’s incentive structure will “likely fail to efficiently unlock the benefits of energy storage.” Instead of paying the incentive over several years, the BPU should pay it as a lump sum “after the project has met all program requirements,“ the center argued.

“In CSE’s experience, requiring performance‐based incentives involves an elaborate and costly administrative structure where a simple one‐time payment easily can be made instead,” the CSE wrote.

AES Clean Energy, an Arlington, Va.-based clean energy project operator, said in a Dec. 12 comment that the company could not evaluate whether the BPU proposal to pay a fixed-incentive rate of $20/kWh is “adequate” without knowing the level of the second part of the subsidy, the “performance-based incentive.”

The letter suggested that the incentives be indexed to the price of lithium.

“Lithium costs are driving the cancelation of storage projects across the country that developers can no longer afford to build,’ the company said. “In order to keep within the bounds of the cost cap, the indexed incentive could include a ceiling.”

EV Dealers’ Storage Needs

In a Dec. 9 letter, the New Jersey Coalition of Automotive Retailers (NJCAR) urged the BPU to recognize the needs of car retailers and specifically include in the SIP language that “encourages investment in energy storage facilities that support dealership operations needed to sell and service the growing number of EVs being sold in New Jersey.”

The organization said the state’s auto dealers expect to spend $140 million on electric vehicle charging infrastructure in the coming years to service the EVs they sell and service. The submission, by NJCAR President Jim Appleton, said dealers likely will be forced to rely on “battery storage and battery-buffered solutions” to make up for the failure of grid-supplied electricity.

“New Jersey dealers have been advised in many instances that New Jersey’s utility companies are not positioned to meet the demands associated with that investment,” he said. “A bottleneck of EV charging infrastructure planning exists at the utility level that may prevent the dealers’ investment from being fully operational, since the utilities cannot supply sufficient power to the dealers’ sites.”

Utilities and their supporters argued in written comments against the BPU-proposed prohibition on utilities owning or operating storage, saying they have the experience and in-house knowledge to help the state meet its storage goals.

“Market hurdles (e.g., cost, supply chain, siting and permitting, immature revenue markets) and the exclusive reliance on third-party development may result in insufficient deployment of energy storage assets to meet the state’s goals,” the New Jersey Utilities Association argued. “If EDC [electric distribution company] ownership is not permitted/encouraged as part of the SIP, the board will miss an opportunity to leverage a critical business model to spur market development of energy storage.”

Public Service Electric and Gas, the state’s largest utility, made a similar argument but also suggested the BPU consider authorizing utilities to set up a pilot program to test the agency’s behind-the-meter program. The plan sets out a system in which a central operator reaches out to distributed storage resources in moments of high electricity demand so the resources can respond automatically and provide electricity.

“The cornerstone to a distributed storage program is an effective communication and call mechanism that is also cost-efficient, coordinated and standardized among the EDCs,” the utility said. It suggested the quickest route for the BPU to get there would be for utilities to test the system with their own distributed storage devices.

Such a pilot, the utility said, could “test the efficiency of its call mechanisms and the impacts that distributed storage deployment would have on the grid.”

Posted on

NRC Eases Emergency Preparedness Rules for SMRs

The U.S. Nuclear Regulatory Commission has moved to ease some of the crisis requirements for small modular reactors, potentially eliminating the emergency preparedness zones currently required near most nuclear reactors.

The long-running process (Docket NRC-2015-0225) was approved Monday by the four sitting commissioners.

The final rule — “Emergency Preparedness for Small Modular Reactors and Other New Technologies” — next goes to the Office of Management and Budget for review and subsequent publication in the Federal Register.

It will take effect 30 days after publication, which NRC staff estimates will be somewhere between mid-November and mid-January.

NRC will simultaneously issue “Performance-Based Emergency Preparedness for Small Modular Reactors, Non-Light-Water Reactors and Non-Power Production or Utilization Facilities.”

NRC said in a news release that the rule’s framework is based on technology and consequences.

Specifically, the technology in the new generation of SMRs is expected to be improved from the older reactors in use across the nation. And the consequences of an accident with a small reactor are potentially less severe than with a large reactor.

The rule gives applicants a scalable method to determine the size of the emergency planning zone surrounding their proposed facility — or to not even create such a zone — and develop a performance-based emergency preparedness program rather than the off-site radiological emergency planning requirements now in effect.

The new rule excludes fuel cycle facilities; currently operating research and test reactors; and large light-water reactors —those licensed to produce greater than 1 GW of thermal power.

Advanced SMRs are viewed as a potentially significant part of the clean energy transition, providing the emissions-free benefits of wind and solar generation with a much more stable power output, not reliant on variable wind or sunshine.

But to achieve widespread adoption, SMR technology will need to be perfected and be economical.

To achieve widespread acceptance, SMRs will need to win over people concerned that commercial nuclear fission carries health and safety risks.

Along these lines, the Union of Concerned Scientists criticized the NRC vote later Monday.

“Past natural and human-made disasters have taught us that having a robust and workable emergency plan in place is the key to minimizing human suffering and loss of life if the unthinkable happens. The NRC’s reckless decision today flies in the face of that experience,” said Edwin Lyman, director of nuclear power safety at the organization.

Stakeholders, the public and other government agencies submitted numerous comments in favor of and against the proposed rule as it was being finalized, and some NRC commissioners echoed some of the concerns in their own comments leading up to Monday’s vote. All four voted to approve, though Bradley Crowell registered disapproval of some aspects.

He commented: “We should recognize the collective lack of operating experience with these new technologies” and strike a better balance between easing their commercialization and adequately preparing for emergencies that involve them.

Commenters including the Federal Emergency Management Agency raised the same concern, Crowell said, adding: “I do not believe the draft final rule adequately reflects the concerns from these key stakeholders.”

He also said the frequency of emergency preparedness drills should be specified, given that the jurisdictions hosting SMRs may have no experiences with radiological emergencies.

Jeffrey Baran’s term on the commission recently ended, but not before he submitted comments.

Like Crowell, he raised concerns about emergency planning zones not extending beyond the gates of a reactor facility:

“Unlike a 5-mile or even 2-mile EPZ, a site boundary EPZ would not require dedicated offsite radiological emergency planning, and FEMA would have no role in evaluating the adequacy of a site’s emergency plans. With a site boundary EPZ, emergency responders would be left with all-hazards planning. While the NRC staff believes that all-hazards planning would be sufficient, FEMA and state emergency response agencies are not convinced.”

NRC Chair Christopher Hanson wrote that proposed rules do not preclude the emergency preparedness measures some commenters sought.

But it makes sense to have a flexible approach to SMR safety regulations, he said, because while SMRs are likely to be greatly variable in design and risk factor, they will have smaller reactor core, lower radionuclide inventories and smaller/slower fission product releases in the event of an accident — all of which would reduce risk to surrounding areas.

Hanson said NRC must be careful not to overstep its regulatory powers, but state and local entities can choose to implement safety plans of their own, and other federal agencies can support them.

Commissioner David Wright wrote: “Even if a determination is made that a formal offsite EP program is not required, the rule still requires that licensees maintain emergency plans that establish contacts, arrangements and procedures for coordination with offsite response organizations.”

Commissioner Annie Caputo said the rule is in line with congressional direction in the Nuclear Energy Innovation and Modernization Act, and will ensure decisions are objective, unbiased, scientific and protective of public health and safety.

Posted on

Report: Fuel Cells Key to NJ’s Clean Energy Future

Fuel cell technology could play a “critical role” in New Jersey’s drive to reach 100% clean energy, according to a state report released Aug. 8 that cited the energy source’s potential use in transportation, supplementing the state’s growing wind and solar sectors and acting as an emergency backup energy source.

The report by the New Jersey Fuel Cell Task Force, which Gov. Phil Murphy (D) created, outlines 21 recommendations on how the state should position itself to reap the benefits. It adds that the state is well positioned for such a move because of its high concentration of engineers and scientists, the network of research universities present and the “numerous industrial and chemical plants that could be used to generate hydrogen.”

Fuel cells have “the potential to reduce greenhouse gas emissions and harmful air pollutants and expand the state’s diverse clean energy portfolio,” the report says, echoing Murphy.

Fuel cells use hydrogen or other fuels to generate electricity, producing only water and heat as byproducts and emitting no greenhouse gases. In April, New Jersey and seven other states submitted a proposal seeking $1.25 billion from the U.S. Department of Energy to create a Northeast Regional Hydrogen Hub. (See Maine, RI Join Multistate Hydrogen Agreement.)

fuel cells

Schematic drawings of a how a fuel cell works (left) and a hydrogen fuel cell stack. | EIA/Fuel Cell Store

President Joe Biden authorized the hydrogen hub grants in the $1.2 trillion Infrastructure Investment and Jobs Act signed into law in November 2021. It provides $8 billion for four regional hydrogen hubs, $1 billion for research to bring down the cost of hydrogen electrolysis and $500 million to support equipment manufacturing.

Hub Proposal

Murphy created the task force to promote the use of cells in the state, and the body’s recommendations, according to the report, are designed to “create momentum in advancing fuel cells and hydrogen within the state and strengthen New Jersey’s hub proposal.”

Fuel cell electric vehicles (FCEVs) could be a key use of the technology, especially for medium- and heavy-duty vehicles, for which the battery weight, limited range and relatively long recharge time make battery power less viable, the report says. For similar reasons, technology could be extremely useful for buses, rail, marine vessels and material-handling equipment, the report says. (See Will Hydrogen Fuel Cell Vehicles Beat out Battery Electric?)

The faster fueling time of fuel cells, in particular, is a benefit, the report says. An FCEV can be filled up in about the same time as it takes to refuel a diesel engine, offering a timelier option than an electric battery, which can take hours to refuel depending on the strength of the charger, the report says.

“The state is also home to many large warehouses where fuel cell-powered material-handling equipment offers significant advantages over diesel or battery power in terms of emissions, productivity and lifecycle costs,” the report says.

The report’s other suggestions on how the state should strengthen its ability to take advantage of fuel cell technology include:

    • Explore ways to incentivize technology to improve local air quality;
    • Explore fuel cells as a non-combustion option for demand response programs, which provide alternate energy sources when high demand stretches the available electricity supply;
    • Consider options for state tax credits on investments or production of low-carbon hydrogen;
    • Encourage revisions in PJM’s tariff to include green hydrogen production;
    • Consider requiring electric distribution companies to propose state electricity resilience tariffs to help fund system strengthening measures;
    • Focus the Board of Public Utilities’ grid modernization program on valuing desired environmental attributes for distributed energy resources;
    • Spur FCEV adoption through incentives, bills, programs and tax credits;
    • Engage private sector industry partners to develop fuel cell and hydrogen-related pilot projects in New Jersey; and
    • Engage a broad hydrogen and fuel cell technology education, training and workforce development program.

Dispatchable Electric Supply

The report also sees the ability of fuel cells to turn on and off as a potentially useful source of dispatchable electric supply. That would help, for example, with “peak shaving,” offering a secondary energy supply to help handle peak demand periods and providing a supplement to intermittent sources, such as wind and solar, according to the report.

“The revenue that fuel cells receive for their value to the grid could be used as an incentive to promote their use as a replacement for diesel-powered emergency generators,” the report says. In addition, “less efficient peak load serving units create what is known as locational marginal emissions during peak load events; fuel cells directly offset these marginal emissions.”

Fuel cells also could be a source of backup power to the state, providing reliability and resilience, especially in situations in which natural disasters knock out power from the grid and can complement or provide a substitute to battery-based storage, the report says.

“Examples of fuel cells and hydrogen for backup power include small scale backup power (less than 100 kW), long-duration energy storage, microgrids and utilities,” the report says.

Posted on

DOE Launches Responsible Carbon Management Initiative

The Department of Energy on Friday made a series of announcements signaling that the Biden administration is doubling down on its commitment to develop and commercialize carbon management technologies as a critical element of its climate agenda.

The selection of two projects as the nation’s first regional direct air capture (DAC) hubs — one each in Louisiana and Texas — grabbed the headlines, but the two notices of intent (NOIs) released on the same day also show DOE digging in for the long haul, both on research and development and “responsible” implementation of its programs. (See DOE to Fund Direct Air Capture Hubs in Texas, Louisiana.)

Published in the Federal Register, the first NOI unveils DOE’s plans for a Responsible Carbon Management Initiative that will “encourage project developers and others in [the] industry to pursue the highest levels of safety, environmental stewardship, accountability, community engagement and societal benefits in carbon management projects.”

The NOI contains the agency’s Principles for Responsible Carbon Management, which cover community engagement and tribal consultation, environmental justice, transparency, long-term environmental stewardship, and regulatory and health and safety standards.

Since the passage of the Infrastructure Investment and Jobs Act, more than 100 carbon removal projects have been announced in the U.S., according to Brad Crabtree, assistant secretary of DOE’s Office of Fossil Energy and Carbon Management (FECM).

“That’s why this Responsible Carbon Management Initiative is so important,” he said in Friday’s announcement. “It will provide a framework for encouraging and recognizing best practices in the development of carbon management projects and for fostering transparency and learning through greater data and information sharing among industry, governments, communities and other stakeholders.”

The second NOI sets out DOE’s road map for new and ongoing research grants and prizes to advance its Carbon Negative Shot (CNS), one of the agency’s Energy Earthshot initiatives, which set high aspirational goals for improving the efficiency and cutting the costs of emerging technologies.

CNS is targeting “gigaton-scale deployment” for carbon dioxide removal technologies within the next decade, at a price of less than $100/metric ton of carbon dioxide captured, including the cost of monitoring, reporting, verification (MRV) and “durable storage.”

A gigaton of CO2 would equal 1 billion tons, or about one-fifth of total U.S. CO2 emissions in 2022, according to DOE.

Current prices for carbon removal technologies vary widely, from “low hundreds a ton and low thousands a ton,” said Noah Deich, FECM deputy assistant secretary, in an interview with NetZero Insider.

The agency defines carbon dioxide removal (CDR) as any form of carbon capture from ambient air or water, as opposed to capturing emissions from a power plant or industrial facility. The funding opportunities ahead will include pilots in small biomass carbon removal and storage, enhanced mineralization projects and marine projects, including direct capture from the ocean.

Biomass carbon renewal refers to technologies that use plants or algae to remove CO2 from the atmosphere, which in some cases may include combustion and carbon capture. Enhanced mineralization uses “alkaline materials such as calcium- or magnesium-rich crushed rocks spread over the ground,” according to a DOE fact sheet,

Other planned funding includes prizes for commercial-scale DAC pilots, smaller than the hubs, and funding for projects “developing and commercializing protocols, technologies and methods to improve MRV” of different carbon removal technologies.

Building the Market

Both the United Nations International Panel on Climate Change and the International Energy Agency (IEA) have framed carbon removal and storage technologies as essential to limiting climate change to 1.5 degrees or 2 degrees Celsius by 2050 or later.

In a 2022 analysis, the IEA said CDR should be part of a comprehensive strategy for reaching global net-zero emissions, but “not an alternative to cutting emissions or an excuse for delaying action.” The agency sees a more modest role for DAC, projecting that it would account for about 85 metric tons (MT) of CO2 removal worldwide in 2030 and 980 MT in 2050.

President Joe Biden and Energy Secretary Jennifer Granholm also have promoted carbon management technologies as central to the U.S. commitment to cut the nation’s greenhouse gas emissions 50-52% by 2030.

But to date, carbon capture and storage technologies have been used in the U.S. primarily for enhanced oil recovery (EOR) — that is, injecting CO2 into low-producing oil wells, first pushing out more oil from crevasses where the CO2 then can be permanently stored.

Both the Infrastructure Investment and Jobs Act (IIJA) and the Inflation Reduction Act (IRA) provide major new funding to develop a range of carbon management technologies at commercial scale. The IIJA provides $3.5 billion for the development of four DAC hubs, which will include CO2 capture, processing and sequestration, at commercial scale.

As the first two hubs, Occidental Petroleum’s South Texas DAC hub and Battelle’s Project Cypress hub on the Louisiana Gulf Coast are slated to receive up to $1.2 billion of the IIJA funds. The projects also will be eligible to receive the IRA’s DAC tax credits of $180/ton for up to 10 years.

Occidental uses EOR extensively at its wells in Texas, according to the company website. However, during a Thursday press call, Kelly Cummins, deputy director of DOE’s Office of Clean Energy Demonstrations, said none of the carbon captured at the Texas or Louisiana hub will be used for EOR.

Rather, the CNS NOI positions the regional hubs as part of DOE’s efforts to build out a carbon management ecosystem. The NOI lists a dozen projects and prizes already announced and underway. Still, DOE notes, “The gap between the goals of CNS and the current commercial viability of some CDR technologies is substantial.”

The NOI “provides a strategy to coordinate funding opportunities that involve a variety of CDR pathways, technology readiness levels, and DOE offices and programs.”

To help build the market, DOE will use $35 million from the IIJA to underwrite carbon removal purchasing agreements, aimed in part at standardizing the credits produced by CDR. Microsoft and Climeworks recently signed a 10-year agreement for the DAC startup to capture and permanently sequester 10,000 tons of CO2 on behalf of the computer software giant.

Deich said the CDR purchase initiative is intended to “show how this tool can be scaled in the future and how it can drive innovation in the carbon removal space.”

The relatively small amount allocated to the program means it would have minimal impact on U.S. emissions, he said.

But standards are needed “in terms of what counts as carbon removal credits, how to actually go about measuring and verifying the carbon removal that … actually was delivered and stays delivered,” Deich said. “So, our aim in this program is to really help demonstrate what we think is best in class and hopefully crowd in a lot more private sector purchases in the near term.”

‘When Deployed Responsibly’

The Responsible Carbon Management Initiative is another effort to develop standards for DOE’s projects and the industry at large, and perhaps quell concerns and skepticism among some environmental groups, which continue to see carbon capture as a lifeline for the fossil fuel sector.

The Environmental Protection Agency’s proposed rule to use carbon capture and storage as a “best system for emission reduction” at fossil fuel power plants also received a mixed reception in comments from a range of industry stakeholders. (See EPA Power Plant Proposal Gets Mixed Reception in Comments.)

Echoing IEA, the NOI on the initiative states, “When deployed responsibly, [carbon management technologies] are complementary [to], and not a replacement for parallel efforts to reduce emissions.”

DOE sees the initiative as a two-phase program, first developing the Responsible Carbon Management Principles and getting companies to commit to them. In the second phase, “FECM would provide resources to support project developers seeking to meet the principles or other aspects of this effort … [and] focus on evaluation of principle implementation, accountability and leadership.”

The principles outlined in the NOI focus broadly on different aspects of community engagement, equity and transparency. For example, developers are called on to consider the cumulative impacts a carbon management project might have on the community where it is located. Developers also should evaluate and mitigate environmental impacts and “publish environmental impact analyses and project monitoring data in a way that is timely and easy for the public to access.”

If the initiative is successful, FECM could develop “a robust recognition program” to raise the public profile of industry leaders and promote responsible carbon management, the NOI says.

The NOI also includes a request for information asking industry stakeholders for feedback on both the initiative and principles. Questions include whether the principles “would be likely to meaningfully advance carbon management,” whether stakeholders would either commit to or endorse them and what changes should be made to improve chances of industry acceptance. The deadline for comments is Sept. 11.