Search
`
October 6, 2024

Posted on

Dominion’s Solar and Onshore Wind Plans Draw Heat

Dominion Energy’s proposal to develop new solar and energy storage resources faced harsh criticism in hearings before the Virginia State Corporation Commission (SCC) Monday and Tuesday.

Dominion is asking the SCC to approve its annual Renewable Portfolio Standard (RPS) Development Plan, which it filed Sept. 15 to comply with the Virginia Clean Economy Act (VCEA), which requires the utility to reach 100% clean electricity by 2045 (PUR-2021-00146).

Dominion is asking the SCC to approve:

      • its CE-2 plan to build and operate 13 utility-scale projects totaling 661 MW of solar and 70 MW of energy storage and related interconnection facilities;
      • two small solar projects totaling 4 MW;
      • 24 power purchase agreements (PPAs) for 32 resources totaling 253 MW of solar and 33 MW of energy storage; and
      • cost recovery for three utility-scale solar projects totaling 82 MW (CE-1), which the SCC approved in April at an estimated cost of $10.4 million (PUR-2020-00134). (See Virginia SCC Gives IOUs a Pass on RPS Plans — for Now.)

Dominion attorney Elaine Sanderlin Ryan of McGuireWoods said Monday that the company opposes an SCC staff suggestion to increase stakeholder input in the request-for-proposals process. “If it’s not broken, don’t fix it,” she said. She also opposed a request by environmental group Appalachian Voices to allow interested parties to submit additional models of future power production and consumption for the company to run.

“When left to its own devices, Dominion does not prepare or even attempt to prepare viable least-cost plans,” Will Cleveland, senior attorney with the Southern Environmental Law Center, said Monday on behalf of Appalachian Voices.

Energy Department also Calls for Stakeholder Group

The Virginia Department of Energy weighed in Tuesday, saying that while it supports approval of Dominion’s projects it “has concerns regarding the efficiency of planning and procurement for RPS compliant generation” and supports commission staff’s proposal to form a stakeholder group to help the company refine its request for proposal (RFP) procedures.

Virginia Energy Director John Warren said that the VCEA’s targets “require large-scale investments to occur within a near timeframe.”

“While the company’s current proposal represents an important step towards RPS and storage goals, there is a much greater volume of generation due to be proposed and built in the coming years, and it is essential that the company is operating a fair, transparent and efficient process for planning and procuring future projects,” he said in a filing.

Warren said the stakeholder group should “at a minimum, review general RFP development, including process transparency, scoring criteria and the value of employing an independent evaluator.”

The Solar Energy Industries Association also expressed concerns while supporting Dominion’s CE-2 projects. “We believe that this represents a diverse set of projects, and that these facilities will help the company comply with its mandatory obligations under the VCEA,” attorney William Reisinger said Monday on behalf of the group.

However, he said, the solar industry finds it “extremely concerning” that Dominion is saying it may not be able to meet the 1% RPS carveout for 2021 and may have to pay the $75/MWh deficiency payment for noncompliance. That should only be done as a “last resort,” and there are sufficient resources in Virginia for the company to meet the compliance goal, said Reisinger, who was also speaking for the Chesapeake Solar and Storage Association (CHESSA).

Walmart, which operates 94 stores and two distribution centers in Dominion’s territory, also expressed reservations about the utility’s RPS plans. “We see significant costs under VCEA that are not borne by the company or solar developers; they are borne by the customers,” Carrie Grundmann, attorney with Spilman, Thomas & Battle, said Monday. She urged the SCC to compel Dominion to adopt lower-cost power purchase agreements (PPAs) rather than build out its capacity at a higher cost.

On Tuesday, her cross-examination of Emil Avram, Dominion’s vice president of business development, led to a tense exchange. The subject was a clause of the VCEA that states that “35% of such [renewable] generating capacity procured shall be from the purchase of energy, capacity, and environmental attributes from solar or onshore wind facilities owned by persons other than the utility.”

“Is there anything in the code says that only 35% can come from PPAs?” Grundmann asked him. She had argued in her opening statement the day before that the company was treating this figure as a ceiling, which meant that Dominion had to build or acquire 65%, a method that she said would be more expensive for customers.

“It’s clear to us that the law says 35% must come from third parties,” Avram said. “It doesn’t say at least, it doesn’t say at most, it doesn’t say approximately. It says 35%.”

An attorney for the utility objected to Grundmann “badgering” Avram after they went back and forth on this point for several minutes.

As of Aug. 31, Dominion said, it had 1,958.1 MW of solar and onshore wind nameplate capacity, including operating facilities, those under construction and those that have been proposed, including the CE-2 projects it is now asking the SCC to approve. PPAs constituted 788.8 MW of that total, and another 52 MW qualify as distributed solar under the VCEA, because they are 3 MW or lower capacity projects.

Through 2020, Dominion says, 322.8 MW in solar and onshore wind generation facilities had reached the commercial operation stage, including PPAs, company-owned systems, and company-owned “ring-fenced” resources that are not under contract with a potentially eligible “accelerated renewable energy buyer.” The VCEA exempts such buyers from the costs of the RPS.

By the end of this year, Dominion expects to add another 240 MW to the total, followed by 492.5 MW next year, 1,063.1 MW in 2023 and 740 MW in 2024.

From 2025 to 2035, Dominion projects it will add approximately 14,865.1 MW more in capacity, which “will offset the 16,100 MW target for the development of solar and onshore wind” set by state law. As a result, the company expects its carbon dioxide output to decline from the 2021 total of more than 15 million metric tons per year to 5 million tons in 2035, although there will be a slight increase in this pollution in the next few years.

Cost

Dominion said the cost of the RPS program to residential customers who use an average of 1,000 kWh/month would rise from 37 cents/month this year, to $5.11 in 2022, and increase more than five-fold to $28 by 2035. Under a different “directed methodology,” the total added to monthly bills in 2035 would be $43.22, the company said.

Advocacy groups were not impressed with Dominion’s plans. “Once again, I believe Dominion has failed to conduct adequate long-term, least-cost implementation planning, and the commission should reject the plan proposed here,” consultant Karl Rabago said in written testimony submitted Nov. 16 on behalf of Appalachian Voices. “Given the company’s failure to submit least-cost VCEA compliant plans for the past two proceedings, I recommend that in future proceedings, the commission require the company to perform a set number of modeling runs and sensitivities as prescribed by other parties.” Additionally, he said, SCC staff, industrial and commercial customer groups, and environmental and consumer groups should be permitted to submit alternative plans.

In written testimony submitted Nov. 17, the Virginia Department of Environmental Quality and other state agencies focused on steps Dominion would have to take to protect the Chesapeake Bay, wetlands and other sensitive areas for its planned projects to go forward.

Posted on

New Jersey Lawmakers Back Municipal Bonds for EV Purchases

New Jersey lawmakers backed legislation Monday that would allow local governments to issue bonds to fund the purchase of electric vehicles, adding to the surge in legislation focused on promoting clean energy that lawmakers hope to approve before the session ends in mid-January.

The Assembly Appropriations Committee voted 10-1 with no comment to advance the bill, A-2208, which would create an exception to an existing law that prohibits local and county governments from bonding projects that have a useful life of less than five years. The law also prevents governments from issuing bonds for the purchase of passenger vehicles and station wagons.

The bill approved Monday would amend that law to permit counties and municipalities to bond for passenger cars and station wagons that are “solely fueled by a battery or equivalent energy storage device charged from an electricity supply external to the vehicle or by a renewable power source.”

The committee’s support for the bill followed the advance last Thursday of several clean-energy related bills that lawmakers would like to send to the desk of Gov. Phil Murphy by the term ends. Bills that are not enacted by mid-January would have to be refiled to move forward.

Master Plan Triggers Competing Views

Among the most high profile and contentious of the bills that moved in recent days was A5720. The bill, advanced by the Assembly Science, Innovation and Technology Committee on a 4-2 vote, would codify into law the main elements of the 2019 Energy Master Plan crafted by Murphy. The vote follows support for the bill by the full Senate in June. (See Lawmakers Back Putting NJ’s Clean Energy Plan into Law.)

At the time of the Senate vote, the bill provided a way of ensuring that Murphy’s aggressive clean energy goals would stay in place even if he lost his re-election fight on Nov. 2. Murphy won re-election with a 2.9% margin against Republican Jack Ciattarelli.

The bill would codify key planks of the plan, including the goal of putting 330,000 light-duty vehicles on state roads by 2025. Other parts of the bill would require the state’s mass transit agency, New Jersey Transit, to have in development at least one battery-powered train by 2025 and that New Jersey generate 7.5 GW of offshore wind by 2035.

The bill, which now needs the support of the full General Assembly to land on Murphy’s desk, sparked a vigorous debate over the Master Plan’s merits, and whether the proposals are realistic enough to sustain the rigidity of codification into law.

Ray Cantor, vice president of government affairs for the New Jersey Business & Industry Association, one of the state’s largest business advocacy groups, argued that the plan failed to meet the most important criteria of being affordable and ensuring that the state’s energy system is reliable. He also expressed concern that the Murphy administration had never calculated the cost of meeting its requirements.

“The Energy Master Plan was meant to be a fluid document to be updated every three years based on new information, new technology [and] new policy directions,” he said. “This would lock it in place in 2021.

“This bill would set unattainable goals, unachievable goals,” he said. “And when that happens, regulators then make bad decisions. They tend to push the limits and make requirements that can’t be met. They waste money.”

Kate Gibbs, deputy director for the Engineers Labor-Employer Cooperative, which represents operating engineers and their employers, added that the plan is “not rooted in reality.”

“It’s more about virtue signaling and relies more on political science than the laws of physics,” she said. “Passing this legislation is setting our state up for a very expensive gambit, one that New Jersey residents and businesses cannot afford. And that will put an incredible strain on the potential for long-term economic development.”

The National Resources Defense Council, Environment New Jersey and Clean Water Action said that regardless of any deficiencies in the plan, the urgency of the need to combat climate change requires that legislators codify the main plan elements. That way there is a greater likelihood that the plan will be carried out, they argued, adding that the cost of not responding to climate change — through damage and destruction from extreme weather events — would be much higher.

Eric Miller, New Jersey energy policy director for NRDC, said the legislation would enable the state to keep its commitment to reducing carbon emission policies, such as the goal to produce 7.5 GW of offshore wind energy goals by 2035.

“Putting them into law is critical to prevent any potential for future backsliding on our climate commitments,” he said. “And it also provides a more stable regulatory environment. … We support codifying the 7.5-GW wind target, which currently just exists as an executive order, so that there’s certainty New Jersey will complete all of its planned offshore wind solicitations.”

Backing Microgrids, Low-carbon Concrete

Also Thursday, the Senate Economic Growth Committee voted 5-0 to back a bill, S3593, that would authorize the creation of a program to develop six electric microgrids around the state to provide power to charge medium- and heavy-duty EVs. The bill has yet to go before the full Assembly or Senate.

The program, to be created by the New Jersey Economic Development Authority in consultation with the Board of Public Utilities and Department of Environmental Protection, would require the authority to seek proposals for the creation one microgrid in each of the six utilities that serve the state.

The Senate Environment and Energy Committee backed two clean energy bills Thursday, including one, A2360, that would require electric utilities to charge “residential rates for service used by residential customers for electric vehicle charging at charging stations” in parking garages or other parking spaces tied to residential units.

While the New Jersey Chamber of Commerce, the South Jersey Chamber of Commerce and New Jersey Utilities Association opposed the bill, NRDC submitted comments in favor, as did the New Jersey Apartment Association. The Assembly passed the bill 68-4 in June.

The committee also backed a legislation, S3732, that would provide corporation business tax credits to concrete producers that provide more than 50 cubic yards of “low embodied carbon concrete” to a project built under contract with a state agency. Low-embodied means the concrete was made with a process that creates low carbon emissions. (See New Jersey Lawmakers Back Low-carbon Concrete.)

The producer could receive a credit valued up to 8% of the cost of the concrete, and the cumulative total of all the credits issued under the bill in the state could not exceed $10 million. The committee backed the bill 4-1.

Sen. Linda Greenstein (D), who sponsored the bill, said the aim is to encourage investment by New Jersey’s concrete manufacturers in the “latest low-embodied carbon concrete manufacturing techniques.” That would “increase supply and competition while building the infrastructure necessary for New Jersey to be at the forefront of this cutting-edge effort to reduce carbon emissions of construction materials,” she said.

Posted on

Wash. Senator Seeks Fee on Fossil Fuel Financers

A Washington state senator wants to create a “climate resiliency fee” on global financial institutions in the state that fund fossil fuel projects.

Sen. Reuven Carlyle (D), chairman of the Senate Environment, Energy and Technology Committee, announced his intention to introduce such a bill in a press release Monday. The bill has not yet been pre-filed for the Washington legislature’s 2022 session, which begins Jan. 10.

Carlyle’s press release said a state report estimates that Washington taxpayers spent more than $1.2 billion over the 2019-2021 biennium on climate resiliency costs “from forest fires to floods, ocean acidification to heat domes.”

Carlyle is calling for adding a surcharge to a financial institution’s business and occupation (B&O) tax, the state’s tax on a firm’s gross income. The press release did not address the size of the B&O surcharge, nor specify which global financial institutions operate in Washington.

The senator expects the surcharge to raise $80 million to $100 million annually for climate resiliency measures, such as creating public cooling centers, relocating infrastructure at risk from floods and sea level rise, and helping farmers and communities obtain critical water supplies during more frequent and severe droughts.

An analysis by Bloomberg Business of the world’s largest banks found that they invested more than $3.6 trillion combined into the fossil fuel industry in the five years immediately after the Paris Climate Agreement was signed, the press release said.

“One of the most profound lessons from the UN Climate Summit conference was that global banks have financed almost three times more fossil fuel than clean energy projects since the Paris Agreement in 2016. At the same time, these same banks have made commitments to design net zero portfolio investments by 2050. This bill is simply asking those funding climate change to pay a modest fee toward the cost that Washington taxpayers are currently spending on climate resiliency,” Carlyle said. 

The press release said global banks’ investments in fossil fuels increased between 2016 and 2021, despite those institutions’ commitment to meet carbon neutrality by 2050.

The bill would reduce the surcharge as the affected institution decrease its investment in fossil fuels — eventually reaching zero when a bank’s investments in fossil fuel projects reach 5% or less of its 2022 level.

Posted on

Overheard at gridCONNEXT 2021

WASHINGTON — About 200 attendees of GridWise Alliance’s gridCONNEXT conference Wednesday listened as John Rhodes — former New York Public Service Commission chair, now special assistant to President Biden for climate policy — hyped the administration’s ambitious climate agenda, optimistic that its many goals could be achieved.

Rhodes spoke of a “zero-carbon electricity system by 2035 that’s reliable; that’s resilient to the weather that we know is getting more extreme; that is affordable and cost-effective for all Americans, especially low-income Americans, while creating millions of jobs.”

“That sounds like it’s Goldilocks; everything’s great,” Rhodes said. “The amazing thing is it’s actually possible. We just need to work to get there.”

Attendees were on board, but not just because they agreed with Rhodes’ rhetoric. There was a general sense of enthusiasm and optimism in the room — a dedicated event space run by Convene blocks from the White House — as they listened to panelists and speakers opine on a high-tech future in which everything is electrified, digitized and clean if the administration’s goals are achieved.

And like WIRES’ Fall Conference in late October, it was the first in-person event for many since the COVID-19 pandemic caused cancellations and transitions to online. (See Transmission Industry Hoping for Landmark Order(s) out of FERC ANOPR.) All attendees were required to be vaccinated and wear masks when not seated or eating. Additionally, attendees attached colored stickers to their nametag to indicate how comfortable they were with physical interaction: green meant hugs were OK; yellow for elbow bumps only; and red for social distancing. (This reporter did not see anyone hugging but chose yellow just in case.)

It was a sharp contrast to last year’s online-only event, in which speakers were obviously fatigued by both the pandemic and federal inaction on energy policy. (See Industry Eager for New Leadership on Tx, Climate.)

This year’s conference billed grid infrastructure as “the platform for decarbonization,” but for much of the conference, transmission took a backseat to everything it would enable. Attendees received a sales pitch from a Ford Motor Co. executive on its upcoming lineup of electric vehicles; an official from the Electric Power Research Institute spoke about a future in which all home appliances are grid-connected and controlled by the utility; and Maud Texier, Google’s carbon-free energy (CFE) lead, talked about how the company is aiming to procure 100% CFE at all times of the day, rather than just on an annual basis, by 2030.

The last of those presentations came the same day Biden ordered the federal government to procure half of its electricity from clean resources 24/7 by 2030. (See Biden Calls for Federal Procurement of 100% Clean Energy by 2030.) One of the slides in Texier’s presentation proclaimed that “24/7 CFE is the New Net Zero.”

Reality Check

Many speakers noted there was much to be done in the next decade or so to achieve Biden administration and company targets. Eric Dresselhuys, CEO of energy storage company ESS, was more blunt in his assessment. On a panel discussing approaches to decarbonization, Dresselhuys said “there’s no billions of dollars of investment that gets us anywhere close to what John Rhodes threw out; to total decarbonization by 2035. Round it to 2045; it doesn’t matter. The amount of work that has to get done is of a different scale.”

Eric Dresselhuys 2021-12-08 (RTO Insider LLC) FI.jpgESS CEO Eric Dresselhuys | © RTO Insider LLC

He said conference panelists often say, “‘We’re trying to decarbonize the energy system,’ like that’s a static thing. … But we’re going to electrify everything: transportation, buildings, natural gas; we’re going to make everything electric. Then we’ve got about 100 million people around the planet who do not have access to electricity. … And then we have 2.3 billion people who don’t have access to clean cooking fuels, so we have to fix that problem. Oh, and by the way, the population is going to grow to about 9 billion people in the time frame we’re talking about.

“When you add that up, that is an electricity system that is two-and-a-half times the size of the global electricity system that it is today. And we’re going to do it all with no carbon. …

“We need smart people thinking about how the arc of this development is going to happen over the course of the next 20 [to] 50 years. I kind of feel like when someone says ‘we’re going to get to decarbonization by 2040, 2045, 2050’ — that triggers, because we’re human beings, ‘I’ve got time.’ … That’s just a natural way for our brains to think. I would tell you that we are massively behind. I think in the best-case scenario we are at a fraction — 20% would be generous — in the wave of change that we need to come anywhere close to come to the slow end [2050]. … I’m sorry folks, but 2035 is a pipe dream.”

Shah on the Hot Seat

Jigar Shah, director of the U.S. Department of Energy Loan Program Office, sat down with Lee Krevat, CEO of Krevat Energy Innovations, for a live edition of Krevat’s podcast “Climate Champions.”

Shah was co-founder and president of Generate Capital, which finances clean energy infrastructure projects. He was also a co-host of “The Energy Gang” podcast produced by Wood Mackenize, in which he could be contrarian and offer somewhat brash opinions.

Meanwhile, in addition to his energy consultancy work, Krevat performs improv and, judging by how he concluded the session, free-style raps.

Jigar Shah Lee Krevat 2021-12-08 (RTO Insider LLC) Alt FI.jpgDOE’s Jigar Shah (left) and Lee Krevat, Krevat Energy Innovations | © RTO Insider LLC

 

Together, they made for an entertaining duo as they ate hot-sauce covered biscuits, borrowing the premise of the YouTube series “Hot Ones,” in which celebrities are interviewed while eating buffalo wings that gradually increase in spiciness.

Krevat asked Shah what “transformational” technology he was most excited about. Shah talked at length about the ability of electric vehicles to provide backup power during an outage, especially as working from home continues to normalize. “People say, ‘Well is there going to be enough demand for electric vehicles?’ And I’m like, ‘Well is there enough demand for resiliency at home?’ … I think you will see long queues of people waiting for electric cars for no other reason than to back up their house.”

“Well I hope you’re right because…” Krevat began.

“Well I know I’m right!” Shah interjected.

Posted on

Rooftop Solar Supporters Pressure Legislator to Eliminate Cap

LANSING, Mich. — Environmental and community-action groups are stepping up pressure on the chair of Michigan’s House Energy Committee in hopes of getting action on a bill to expand rooftop solar by ending the state’s 1% cap on distributed energy.

The effort by the Michigan League of Conservation Voters and other groups is targeting constituents in Republican Rep. Joe Bellino’s home of Monroe County to call on him to take action on HB 4236. The campaign, which includes online ads, billboards and advertisements, prompted more than 1,800 people to sign a Sierra Club-sponsored online letter backing the bill, with hundreds more in Monroe County contacting Bellino.

Bob Allison, deputy director of the LCV, said the campaign to push Bellino on the bill extends an effort begun last spring to shore up Democratic support as utility worker unions opposed the legislation. The state’s largest utilities, CMS Energy (NYSE:CMS) and DTE Energy (NYSE:DTE), also oppose it.

The new focus on Bellino is an effort to get movement on the bill, which was initially proposed in 2016, he said. “We’re drawing a line in the sand.  We’re not going to be placated with a hearing and a pledge of later action.   We want to see action now.”

Allison said it was critical to see some action on the legislation no later than June 2022, before all lawmaking is hung up in the election season.  If the bill passes the House, Allison said he is fairly confident it would pass in the Republican-controlled Senate.

HB 4236 is a priority of energy and climate change activists, who have urged its passage to the House Energy Committee and the Michigan Council on Climate Solutions, which is now working on its final recommendations for Gov. Gretchen Whitmer (D).

Enacted in 2016, the current cap is based on 1% of the utility’s average peak load for the previous five years. Utilities can change that cap, and CMS has done so, lifting it to 2%.

Bellino could not be reached for comment. But in an interview recently with Gongwer News Service, Bellino said his committee has not killed the bill and he wants to see the cap increased to 6%.

The utilities have argued repeatedly that they are subsidizing distributed energy providers, mostly small solar systems, which they said have shifted costs for their use of the grid to other ratepayers.

CMS spokesperson Katie Carey said the utility supports raising the cap on distributed generation, but “only if it’s done in a way to address the subsidy.” Carey said CMS sees renewable energy as “an important part of Michigan’s clean energy future,” and the utility is “committed to developing solar” as part of its future plans.

A study for the Public Service Commission concluded there was no economic reason to maintain the limit. (See Mich. Enviros Use Report for New Push to Remove Solar Cap.) PSC Chair Dan Scripps and other commission officials have said there is no indication of any cost shift.

One organization joining LCV’s campaign, the Michigan Conservative Energy Forum (MICEF), has run an ad in one publication showing a tombstone and a headline: “The Solar Subsidy is Dead!”

“There is no solar subsidy,” the ad says. “Take action on residential & community solar legislation.”

HB 4236 is sponsored by a fellow Republican on the committee, Rep. Greg Markkanen from Michigan’s Upper Peninsula where rooftop solar installations are becoming more popular. He has complained Bellino has not acted on the bill largely because of utility influence.

Allison said Bellino has not put the bill up for a vote despite clear bipartisan support.  Allison blamed much of that on large campaign contributions Bellino and others have received from the utilities.  They have talked with the House Speaker, Rep. Jason Wentworth (R), in hopes he could persuade Bellino to act, but Wentworth prefers giving committee chairs deference.

“We’ve been working on this since 2016, and now we have a situation where a majority of committee members say they could pass it with bipartisan support,” Allison said.

“The only people standing in the way of this bill are DTE and Consumers,” Allison said. “Michiganders are tired of paying the highest rates, and they’re tired of DTE and Consumers buying and selling legislators.”

State politicians have come under fire in recent months for accepting utility campaign donations, particularly after massive summer storms led to utility blackouts for about 1 million customers in the Detroit area. In August, DTE sponsored a fundraiser for Whitmer that collected nearly $50,000.

To push for committee action, Allison said the campaign is focusing on the high cost of electricity in the state — Michigan has the highest average retail rate in the Midwest, said the Energy Information Administration — and ongoing issues with reliability. With climate change and years of little upgrading of utilities’ infrastructure, Allison said, it’s reasonable to expect massive storms and service disruptions will recur in the future.

LCV’s campaign is backed by the group Vote Solar, and the social engagement group Michigan United, which focuses mostly on equity and justice issues.

Allison said LCV and other supporters are happy to talk about a compromise solution to move the bill.   Bellino’s proposal to raise the cap to 6% could be a good starting point for those discussions, he said.

In 2022, all 148 of Michigan’s legislators are up for election, and under its term-limit system, most of the 38 senators will not be eligible for re-election. The House also could face changes as many members seek to move to the upper chamber.

Michigan’s primary takes place in August. “The bill has got to get some real serious consideration in the first couple of quarters” to have a chance to pass in this legislative session, Allison said.

Posted on

ERCOT Generators Near 100% Winter Readiness Compliance

All but one ERCOT system generating resources have submitted their winter readiness reports, part of the state’s new requirements, the grid operator’s staff said Friday in a filing with the Public Utility Commission.

ERCOT said it had received 828 of 847, or 97.8%, of the total readiness reports that were required to be submitted by a Dec. 1 deadline. Another 18 reports were received by close of business Thursday, leaving only Rippey Solar, an 81-MW facility in North Texas, unaccounted for.

Rippey Solar is owned by BT Cooke Solar, one of eight generation companies recently fined for failing to provide winter readiness reports by the Dec. 1 deadline. (See “PUC Docks 8 Generators,” Texas PUC Chair Lake: ‘The Lights Will Stay On’.)

ERCOT staff noted 244 resources asserted good cause of non-compliance as of Thursday but said that after reviewing about 70% of the exception requests, “ERCOT does not believe [the assertions] should be taken as an indication that 244 generating units are wholly unprepared for the winter peak period.”

Staff said the attestations include about 25 separate winterization elements, such as enclosing sensors. “Many good-cause assertions identify a failure to comply with only a small number of these elements, but otherwise suggest compliance with the rule.”

Many of the good-cause assertions reviewed by ERCOT “reasonably asserted” that some requirements do not apply to the resource while others proposed a quick timetable to reach compliance.

“For these reasons, ERCOT would caution against an inference that a significant number of generators should be considered unprepared for winter based solely on the number of good-cause assertions,” staff said.

Austin Energy, which filed exception requests for all 13 of its generating resources, told RTO Insider it is making additional improvements based on its experience during February’s winter storm, and it expects the majority of its measures to be completed by the end of the year.

“That work is ongoing because either a unit at the plant site is undergoing planned maintenance that precludes completion of the step until the maintenance outage concludes and/or a contractor scheduled to perform winterization work could not complete the work until after Dec. 1,” a spokesperson said.

The utility noted it was able to maintain operations during February’s cold snap because of its prior weatherization efforts.

“The reports and the requests for exception are having the desired effect of increasing accountability and giving regulators more visibility into weatherization efforts,” the PUC said in a statement.

The commission and ERCOT must both sign off on the exception requests.

The new rules are a result of legislation following the February winter storm, when about half of ERCOT’s thermal generation fleet was rendered unavailable by the freezing temperatures.

Generation owners must implement winter-weather readiness recommendations from a post-event analysis of a 2011 winter weather event and fix any “known, acute issues” from last winter (51840). The generation owners’ highest-ranking executives were required to file notarized attestations that the resource has met its required actions by Dec. 1. (See “Weatherization Rule Published,” PUC Workshop Takes First Stab at Market Changes.)

Dispatchable generators submitted 520 of 530 reports (98%) on time, while 308 of 317 (97%) intermittent resources met the Dec. 1 deadline.

Posted on

NE Stakeholders Propose Retirement, Financial Assurance Changes

The NEPOOL Markets Committee will vote in January on two proposals to modify ISO-NE’s generator retirement rules, which the proposals’ sponsor contends are “the most onerous and difficult … in the country.”

Sigma Consultants’ William Fowler told the committee Thursday that his proposals would address New England’s large generation surplus. Fowler says the RTO’s plans to eliminate the minimum offer price rule (MOPR) is likely to cause an influx of new state-sponsored resources, which could exacerbate the surplus without rules to enable efficient exit. (See Monitor, Merchants Challenge ISO-NE Plan to Eliminate MOPR.)

Under current rules, retirement bids are due in March, 11 months before the annual Forward Capacity Auction, and cannot be updated to reflect changes that occur between then and the FCA. “This adds significant, unnecessary risk to the process,” Fowler said in a presentation.

He proposed allowing bids to be updated prior to the auction in mid-October, as is permitted for static delist bids.

Offer prices could be no more than 25% below the initial submission. Upward adjustments would not be permitted.

Fowler said he will seek an MC vote on his proposal at its Jan. 11-12 meeting, immediately after it votes on the MOPR elimination. He said the bid flexibility rules would be contingent on FERC eliminating the test price for Competitive Auctions with Sponsored Policy Resources along with the MOPR or a transition package.

Fowler said he hopes the new rules will be filed with FERC prior to the March bid submission deadline for FCA 16, allowing a commission order before the June auction election deadlines. He also plans to seek an MC vote at the same meeting on a second proposal intended to create a “meaningful” mothball option.

Bid Reductions (Sigma) Content.jpgExamples of how bid modification would work. | Sigma

Current rules require generation owners seeking to temporarily take a unit out of the capacity market to “string together a series of one-year delists,” Fowler said. “But that has many limitations. Also, once retirement is accepted, [there is] no meaningful way to return to service if there are major regional changes.”

He proposed modifying the “repowering rule,” which requires that the generation owner make a minimum financial investment in the plant to re-enter the market. He also suggested a three-year waiting period — including two consecutive FCAs after the one in which it retired — calling it a “reasonable balance.”

“Three years is [the] longest waiting period that can allow for changed circumstances before risking permanent actions that may frustrate [the unit’s] return,” he said. A shorter waiting period could allow generators to “toggle” into and out of the market, “fishing” for a reliability-must-run designation entitling it to cost-of-service compensation.

Fowler has withdrawn a proposal to eliminate a rule that requires resources that submit retirement bids and fail to clear in that FCA to continue submitting retirement bids until they do clear. He also has withdrawn a proposal to relax Internal Market Monitor reviews in certain situations.

Increased Penalties for Failed Capacity Resources

Competitive Power Ventures will early next year put forward its proposal to increase financial penalties for capacity resources that fail to reach milestones prior to their delivery year and commercial operation.

CPV will be seeking votes at the next Budget and Finance Subcommittee meeting Jan. 26 and at the succeeding MC in February, said Joel Gordon, CPV’s vice president of external and regulatory affairs.

Gordon said existing financial assurance (FA) requirements, designed to keep barriers to entry low, are insufficient to ensure that resources that win capacity supply obligations (CSOs) actually deliver.

Current rules do not distinguish between a project meeting all its milestone commitments, a delayed project and a totally failed project because there are no financial penalties until after the resource has failed to meet its commercial operating date (COD).

He cited ISO-NE’s Nov. 4 filing asking FERC to terminate Killingly Energy Center’s CSO for FCA 16, after the developer failed to advance its project despite participating in three consecutive auctions, FCAs 13 to 15. (See ISO-NE Seeks to Terminate CSO for Conn. Power Plant.)

Failed capacity projects impact other capacity sellers by artificially increasing apparent “supply,” reducing clearing prices and increasing performance risks, he said. He said Killingly’s failure reduced clearing prices by a total of $380 million over three auctions, an average of 31 cents/kW-month.

Currently, the RTO collects a “base” FA — equivalent to one month of net cost of new entry (CONE) — prior to the primary FCA and before the first and second subsequent auctions.

Following a failed project in FCA 10, the RTO also added a “trading” FA that collects any positive trading revenue from resources that engage in “cover” transactions for their CSOs.

CPV proposes to add a “milestone” FA for projects that don’t meet pre-COD obligations and a “delay” FA for projects that fail to meet their obligations at their commitment date:

  • Resources that have not achieved their financing milestone or their demand reduction value before the first subsequent FCA would be required to post an additional one month of FA.
  • Resources that have not achieved substantial site construction or achieved their demand reduction value before the second subsequent FCA would be required to post an incremental two months of FA (three months total).
  • Resources that have not achieved substantial site construction or achieved its demand reduction value before the third subsequent FCA would be required to post an additional three months of FA (six months total).

All milestone FA would be released upon catchup to active construction; projects that meet their commitments would face no increase in FA requirements.

Forfeited FA payments from the new requirements would be distributed pro rata to other CSO holders. Forfeited base and trading FA would continue to be allocated to load, as under current rules.

IMM Reports Summer Energy Costs up 48%

A large increase in natural gas prices and slightly higher loads pushed New England wholesale energy costs up by 48% last summer compared to the same period a year ago, according to the ISO-NE Internal Market Monitor’s quarterly markets performance report.

Wholesale market costs totaled $2.19 billion, up $710 million from summer 2020, according to the report presented by Donal O’Sullivan, IMM supervisor of surveillance and analysis.

The year-over-year increase was large because summer 2020 saw historically low natural gas prices as a result of warmer weather and reduced consumption from the pandemic-driven economic shutdown.

Average day-ahead and real-time hub LMPs were $41.29/MWh (+84%) and $40.22/MWh (+79%), respectively. The average natural gas price was $3.39/MMBtu, more than double the summer 2020 price of $1.62/MMBtu.

The average hourly load of 15,298 MW was up by 0.3% (320 MW), driven by increased humidity and less behind-the-meter solar generation. Capacity market costs totaled nearly $530 million, down by $73 million (-12%).

Summer 2021 was the first quarter of the FCA 12 commitment period, with clearing prices of $4.63/kW-month for Rest of System, compared to an FCA 11 price of $5.30/kW-month.

Gross real-time reserve payments more than doubled to $9 million.

Ten-minute non-spinning reserve (TMNSR) and 30-minute operating reserve payments increased by $1.9 million and $432,000, respectively.

Non-zero TMNSR pricing occurred in 386 hours in summer 2021, down from 506 hours. However, the average non-zero spinning reserve price increased from $9.81 to $14.27/MWh.

Total regulation payments were $7.6 million, up 19%.

The higher average real-time hub LMPs led to a $1 million increase in regulation capacity payments.

Net commitment period compensation (NCPC) costs totaled $10 million, up $3.1 million (+44%). But as in summer 2020, NCPC costs represented less than 1% of total energy costs. Economic payments made up 77% ($7.7 million) of the total, up by $2.1 million from the same period a year ago.

Economic out-of-merit payments increased by 34% to $4.98 million. Local reliability payments were $1.6 million, up 72%.

Posted on

Maine Explores Post-2024 OSW Procurement Options

Maine officials are looking at beginning a phased offshore wind procurement process following an anticipated 2024 Gulf of Maine federal lease sale, Celina Cunningham, deputy director of the Governor’s Energy Office, said Monday.

“What we are seeing from the energy needs for the region and the state is that, over the long term, OSW will be an important part of our energy mix to meet our clean energy and emission-reduction requirements,” Cunningham said during a Maine Offshore Wind Roadmap Advisory Committee meeting.

Cunningham presented the Energy Markets and Strategies Working Group’s initial roadmap recommendations to the full committee, saying an OSW target should accompany the procurement.

The U.S. Bureau of Ocean Energy Management (BOEM) announced plans in October for seven potential new OSW lease sales by 2025, including one in the Gulf of Maine. BOEM said it could designate a gulf wind area by mid-2023 and hold a lease sale in the third quarter of 2024.

The working group expects to finalize an energy needs analysis before identifying what it believes Maine’s OSW target should be, according to Cunningham, who added that pursuing a cost-effective energy strategy for the state is a priority.

Based on water depths, OSW development in federal waters of the gulf will require floating wind turbine technologies. The current floating wind market, however, is small, totaling 79 MW of installed capacity, according to the U.S. Department of Energy’s 2021 Offshore Wind Market Report.

By 2050, DNV estimates the U.S. will have 279 GW of OSW, and 47 GW of that total would be floating, Principal Consultant Ari Michelson told the committee. DNV has been supporting the working group with analyses on OSW potential for Maine.

Floating OSW development likely will not kick off significantly in the gulf until 2040, and it could more than triple in size by 2050, according to Michelson. DNV is currently finalizing its estimates for floating wind capacity in 2040 and 2050 for the roadmap.

In addition, he said the global levelized cost of energy (LCOE) for floating wind should drop rapidly through 2030, potentially hitting $39/MWh for the gulf in 2050. Globally, the average LCOE of fixed-bottom OSW installations is $95/MWh, according to the DOE report. Mayflower Wind has one of the lowest-priced OSW projects in the world at $71/MWh.

The committee heard initial recommendations from three of its working groups Monday, with additional recommendations still to come from the Fisheries Working Group in January. After taking feedback from stakeholders early next year, the working groups will present refined recommendations to the committee in July. The final roadmap is due in December 2022.

Supply Chain and Workforce

Maine should be connecting with the international OSW market as the state builds out its assets in the coming years, Steve Von Vogt, executive director of the Maine Composites Alliance, told the committee.

“We would like to see advocacy on the part of the state through its policies and economic outreach for Maine’s firms and industry, ports, workforce and excellent R&D related to offshore wind,” Von Vogt said in a presentation for the Supply Chain, Workforce Development, Ports and Marine Transportation Working Group.

The group’s initial recommendations included establishing a “commissioner-level industry advocate.”

The state needs a “consistent and high-level strategic effort to align Maine’s assets across industry, R&D, education and workforce development, to market opportunities,” Von Vogt said.

To accomplish that, the group suggested that the state “formally establish clear state policy supportive of OSW” and “announce an OSW goal or mandate.”

Developing Maine’s OSW workforce may require the state to ensure that students are engaged early in understanding the long-term opportunities for the industry, said Jonathan Poole, large business development manager at the Maine Department of Economic and Community Development.

To do that, Maine can expand STEM education for K-12 and continuing education students, Poole said in a presentation to the committee. The state, he said, also could increase OSW opportunities in post-secondary education by replicating its successful efforts to generate talent in the pulp and paper industry.

In addition to promoting the University of Maine’s long-term work on floating wind technologies, the state also could leverage its existing maritime sector programs, according to Poole.

“Improving the professional certifications in the maritime sector is what is going to be required by a lot of OSW developers and operators coming into the gulf,” he said.

Wildlife

Among the Environment and Wildlife Working Group’s top priorities for the roadmap is a drive to ensure that the state is prepared to communicate its needs to the federal government in the OSW citing process for the gulf.

There is a lack of data for the gulf; the existing data are old; and the gulf’s environment is in flux because of climate change, said Wing Goodale, science director at the Biodiversity Research Institute.

With that in mind, the group’s initial recommendations include using existing data to begin identifying areas of greatest conflict and the data gaps that need filling to inform OSW leasing, Goodale said. With input from science and fishery experts, the maps can be updated over time.

The group also wants to investigate Maine’s authority under the Coastal Zone Management Act (CZMA) to review federal activities that could affect the state’s coastal areas. The CZMA may provide the state with opportunities to address “issues of concern” regarding OSW development in federal waters, and the investigation could lead to potential changes in state laws, Goodale said.

Posted on

IPPs See Danger in Swift Move from Gas and Coal

Independent power producers warned Monday that policymakers are risking reliability by attempting to transition too quickly from gas and coal — and they said the consequences could be felt in New England this winter.

“We really shouldn’t just … pave the ground with solar panels and then deal with the consequences after you’ve shut down all of your gas projects, like we saw in California,” Gary Lambert, CEO of Competitive Power Ventures, said during a panel discussion at the New England Power Generators Association’s (NEPGA) New England Energy Summit in Boston. “We have to … have a market that compensates us appropriately to keep the reliability resources around.”

Sarah Wright, founder and managing partner of Hull Street Energy, a mid-market private equity firm, said it is “premature” to focus on retiring thermal generation. “You see it in California — the effects of this fictitious narrative that says, ‘All we need to do is install solar panels and batteries and we’ll be fine.’ That is a nice political story, but it’s not actually true,” she said.

Himanshu Saxena, CEO of Starwood Energy Group, noted that renewables only comprise about 20% of the 1,000 GW of installed capacity in the U.S., with coal and gas representing about 600 GW.

“In the best of times, this country installed 20 GW of renewables on an annual basis. So if the best of times continued, it will take 30 years to replace [thermal generation], and this is not even [considering the lower] capacity factor” of renewables, he said. “Everybody has to be realistic about how fast this change is going to happen.”

When Curt Morgan became CEO of Vistra (NYSE:VST) in 2016, he said the company’s generation was more than 70% coal. “And investors that we had were pretty comfortable with it,” he said.

After studying the subject, Morgan said, he and the board of directors concluded that climate change was real and they needed to change the company’s trajectory. It has pledged to reduce its carbon emissions by 60% from 2010 levels by 2030.

“Maybe that sounds simple to everybody in this room. But that was a huge thing for our board to accept and understand with over 70% coal [generation]. And so that put us on a path of not denying, but actually participating” in the transition away from fossil fuels.

“We’re the kind of company that policymakers should want, because we’re doing the responsible thing. We’re helping  the three pillars: reliability, affordability … and [reducing] emissions,” Morgan said. “But it’s going to take us some time to do this transition. And we can’t sacrifice one of those three pillars to get there. And so I tell policymakers this all the time: ‘We’re not the guys that you ought to be throwing darts at. We’re the ones that you ought to be supporting, because we are going to be the ones that will help this transition.”

Cash Flow, Financing Challenges

Saxena said cash flows for gas and coal assets have become less predictable because of volatility in capacity prices,  making it harder to raise debt or equity to fund the plants.

“You take something to market … if you have any green halo on it, you’re trading at 20 to 40 times EBITDA [earnings before interest, taxes, depreciation and amortization],” he said. “But the capital market community hates coal. So getting everything from insurance for that asset to getting refinancing done is really, really hard.”

Lambert said the influx of zero-cost resources could make it increasingly difficult to keep thermal plants operating. “So then you’ll see a bunch of shutdowns. And we’ll go back to RMRs [reliability-must-run contracts], and that’s the world that we don’t want to go back to, 2003-2005; everything was being run on cost-based RMRs.”

Morgan said his normal optimism is being tested. “I am always a positive person, but I am very concerned that in the next 10 years, it’s going to be a bumpy ride, because we’re relying more and more on government intervention to get our rents.

“PJM did a study that said that, with 50% penetration of renewables, they need a 70% reserve margin. Yet we’ve got people wanting to … literally drive assets out of the market. When I talk to regulators, reliability doesn’t even come out of their mouth. I have to raise it. It’s all about emissions.

“When you allow those things to come out of balance — reliability, affordability and emissions — you’re going to have California, which was driven by a lack of reliability, and Texas, which was driven by too much emphasis on affordability and a lack of focus on the fact that … intermittent resources” create new reliability challenges.

Morgan said the U.S. may need to adopt Australia’s solution of two markets: one for new renewables, and a residual market for dispatchable fossil fuel generators. “I’d hate to see us go there. But I don’t know how [else] we get there,” he said. “The markets are just not functional right now. … The ISOs have knuckled under to political pressure. And they’re not speaking what they believe. I think they’re saying what the politicians want to hear. And that’s dangerous, because … they’re the ones that are going to make sure whether this thing works or not. So we need them to speak up about their grids. And I’m concerned that they are not doing that.”

Increasing Gas Prices, Availability Concerns

In the short term, the speakers said, the increasing price of natural gas and its limited availability are a threat to New England’s energy security.

“So far, it has been a warm winter, and we may skirt through, but prices are certainly projected to be very high in the region,” Lambert said. New England would benefit from a new pipeline that could bring in cheaper gas from outside the region, “but that’s very, very difficult, if not impossible, to get done.”

The increasing globalization of natural gas prices through LNG also is a concern, Wright said. “Algonquin [Gas Transmission Pipeline] prices are high right now because we think it’s going to be cold in China,” she said. “That’s mind-blowing after decades of focusing on gas as a very local matter.”

Saxena said that although his company has firm gas transport agreements for many of its New England assets, “it’s not 100%. And [additional] firm transport is just not available. … There is no price at which you can buy firm gas in this market.”

ERCOT failed during the February winter storm “not because the generation wasn’t there; it failed because gas wasn’t there,” he said. “New England is going to have the same issue.”

Constraints in gas supply in the region will become more challenging as New England states push more renewable resources onto the grid, Morgan said.

“I think New England is the next region to be at risk [of a major blackout] with a lot of focus on offshore wind and a bitter hatred toward gas,” he said. “I know that we’ve got some challenged gas assets that really are going to be needed for reliability reasons, given the intermittency of all the offshore wind coming.”

Posted on

Roundtable Looks at Storage, Hydrogen to Decarbonize Northeast

The New England Electricity Restructuring Roundtable on Friday discussed storage and hydrogen as possible pathways to fully decarbonize the Northeast, including using both technologies in electric power production, transportation and buildings.

The keynote speakers presented views from neighboring New York and Canada, with Jonatan Julien, Québec Minister of Energy and Natural Resources, appearing in a pre-taped video to share the province’s new strategies to produce green hydrogen with hydropower and to develop batteries from indigenous lithium, aluminum and hydro resources.

Regional Approach

“Québec has the potential to be a world leader in renewable energy production and a team leader in decarbonizing the Northeast,” Julien said. “We share the same ambitions for a greener and a more sustainable energy future because we know that climate change knows no borders.”

As proof of the province’s role, Julien referred to New York in November having finalized a contract with Hydro-Quebec Energy Services for the Champlain Hudson Power Express to carry Canadian hydropower all the way to New York City. (See Two Transmission Projects Selected to Bring Low-carbon Power to NYC.)

Dominique Deschenes, Québec Deputy Minister of Energy and Natural Resources, appeared live and clarified that the province will not be manufacturing batteries but wants to invest in in a complementary sector for the manufacture of specialty electric vehicles such as emergency vehicles or fire trucks, and to develop the province’s role in a battery recycling logistics chain.

Raab Roundtable Panel 2 (Raab Associates) Content.jpgClockwise from top left: NYSERDA CEO Doreen Harris; Jonathan Raab of Raab Associates; and Dominique Deschenes, Québec Deputy Minister of Energy and Natural Resources | Raab Associates

 

On the role of green hydrogen in her province, Deschenes said, “Hydrogen is for us to use where we cannot use direct electricity.”

The Quebecois see green hydrogen being used for heating buildings, but especially for transportation and industry because of sectors like mining that cannot easily use electricity, she said.

“Hydrogen also goes with bioenergy [and] for 2030 we have a target of 37.5% GHG emissions reduction and we think that almost 15% of this reduction will be done with bioenergy and green hydrogen,” Deschenes said.

New York is ahead of schedule on its solar and energy storage targets and is also participating in several national and global groups focused on hydrogen, said joint keynote speaker Doreen Harris, CEO of the New York State Energy Research and Development Authority (NYSERDA).

For example, New York is collaborating with the National Renewable Energy Laboratory on a hydrogen strategy study to compile baseline information and data that will help to determine the role green hydrogen could play in the state’s decarbonization plans, Harris said.

In July, NYSERDA made $12.5 million in funding available for developing long-duration energy storage solutions that are six-plus hours in duration.

The state also is working with the Center for Hydrogen Safety, a global community of more than 75 government, industry and national lab participants promoting and learning about hydrogen safety and best practices across industrial and consumer applications, she said.

“We have also joined the HyBlend collaborative research partnership, which is comprised of six national labs and 15 university and industry partners co-led by NREL and Stony Brook University,” Harris said. “This national partnership will generate a database that allows New York to access the use of existing infrastructure and to develop general principles of operation of blended hydrogen and natural gas delivery systems.”

NYSERDA is looking to leverage the state’s regional clean energy hubs with funding focused on carbon capture and clean hydrogen, which is part of the Infrastructure Investment and Jobs Act, she said.

“This federal context is a very critical one for us as a state,” Harris said. “We see great alignment in the broader policies, but also a huge opportunity to capture those federal investments as we make New York the hub … for this burgeoning industry.”

In addition, the state target of 9 GW of offshore wind by 2035 is “only the beginning,” and will likely double, with plenty of opportunity at low load times to use that relatively low-cost power to produce green hydrogen, Harris said.

Strategy and Policy

Decarbonizing the Northeast can be thought of as a battle between how much and how fast renewable generation can be developed and how that can offset GHG from fossil fuel resources, said Paul Hibbard, principal of Analysis Group.

The concern is that no matter how many thousands of gigawatts are generated from wind and solar there will be times when those technologies are unable to generate enough power to meet demand. And as electrification of the economy grows, such as with adoption of electric vehicles and electric heat pumps, those shortfalls could become big problems.

And that’s why current hydrogen R&D projects are “incredibly important,” said Hibbard. The energy density and phase flexibility of hydrogen make it easily transportable and potentially able to take advantage of existing pipeline and fuel storage infrastructure, he said.

Utilities and wind developers could “overbuild” wind and solar projects and produce hydrogen, which could then be stored and used as a “ramping resource,” whether burned in a combustion turbine or used in fuel cells to help stabilize the grid, Hibbard said.

The major question is whether green hydrogen will be cheap enough to be economic, Hibbard said.

Notwithstanding that question, National Grid, which delivers gas and electricity to 20 million customers across the Northeast, intends to distribute renewable (bio) natural gas and green hydrogen as part of a master plan to get to net zero carbon emissions.

“In some ways our gas network is the largest storage system we have, and through clean, net-zero fuel we see that as a way to provide value to our customers,” said Judith Judson, head of U.S. strategy at National Grid.

Hydrogen will interconnect large scale renewables with a modernized grid, she said.

“The magnitude of growth in clean electric generation needed to get to net zero across New England and New York will require hydropower, 25 gigawatts of onshore wind, 40 gigawatts of offshore wind and over 50 gigawatts of solar,” Judson said.

Energy storage, whether batteries or stored hydrogen, will be the “glue” that holds the system together, she said.

“We’re excited about storage as a transmission asset. It [provides] the opportunity to increase both the capacity of our existing infrastructure and improve the resiliency of the network by acting as a backup to the network,” Judson said.

Hydrogen may face competitive hurdles as a grid storage system, said Audrey Zibelman, vice president of of Tapestry, X’s moonshot for the electricity grid.

Zibelman stepped down as chair of the New York Public Service Commission in 2017 to serve as CEO of grid operator Australian Energy Market Operator, before returning early this year to the Google venture, X.

As for hydrogen as a method of long-term storage, the Australian grid operator decided pumped hydro was more cost effective than hydrogen storage, at least initially because of the cost of green hydrogen, she said.

Green hydrogen’s role in long-duration storage depends on reducing the cost, including the cost of electrolysis equipment used to make hydrogen from water.

“If we are talking about a 1-in-10-year event, where we need long duration storage, for days as opposed to just hours it’s going to become a very difficult market,” Zibelman said.

The answer might be something in the form of a storage reserve, like an oil reserve, but how would someone invest in something that might only be used once in four or five years, she said.

“We have probably not exhausted the DER side in terms of resources to make the grid itself much more efficient,” she said.

Probably the easiest market for hydrogen would be where gray hydrogen is now used, in heavy industry and refineries, Zibelman said.

Case Study Storage

The final panel featured storage and green hydrogen case studies in the power, transportation and building sectors.

Form Energy developed a sophisticated suite of analytics, which allowed it to run very complex technology-neutral investment and operational models for power grids.

Iron is cheap and abundant, two features that enable the company to project it will hit very aggressive cost targets, said Form Energy CEO Mateo Jaramillo.

“We are delivering our first material commercial project in a few years, so by the end of 2023 we will turn on our first pilot project, a roughly 1-MW, 150-MWh battery storage, hundreds of hours of duration for a transmission distribution co-op in Minnesota called Great River Energy,” Jaramillo said.

Form Energy developed a sophisticated suite of analytics that allow it to run complex cooperation problems. The company is today running integrated resource plans alongside the utilities that it’s talking to, so that when those utilities examine their future system needs and asset mix, “we’re able to inject the different types of technologies that may show up and compare them in a financial model,” Jaramillo said.

Mike Hill at FERC asked about the market barriers to deploying long-duration storage.

“The simplest response is that we need to price reliability,” Jaramillo said.

Case Study Transit

Toyota’s various hydrogen fuel cell initiatives are geared toward everything from light- to heavy-duty vehicles, buses, boats and stationary generators, and particularly to eventually power heavy-duty trucks, said Douglas Moore, the automaker’s general manager in the U.S. for fuel cell solutions.

Meanwhile, the world’s largest carmaker is making progress on relieving consumer range anxiety with fuel cell technology.

“Just a couple of months ago we had a hyper-miler run our second generation Mirai in Southern California, and he achieved a Guinness record of longest distance traveled by a fuel cell vehicle.  So he was able to go 845 miles on a single fill-up,” Moore said.

Toyota started fuel cell infrastructure development in California and has partnered with a number of station providers, including including First Element, Air Liquide, Shell and Iwatani, to supply fuel and Shell for distribution.  There are 49 stations open and more than 120 under development, mainly in the Bay Area, Los Angeles and San Diego, and in the Lake Tahoe area, he said.

Toyota is working to expand fuel cell markets across the country, with areas of promise being Colorado, Texas, the Pacific Northwest and the Northeast.

“On developing the light-duty vehicle refueling infrastructure, what would be the main factors in Toyota’s determination of which if any of these other markets to enter … and how much would the availability of green hydrogen from offshore wind or hydro in the Northeast influence such a decision?” said Roundtable organizer Jonathan Raab.

Moore said that California has obviously been a favorable state from a policy perspective, and developing fuel cell refueling infrastructure has its own challenges. “By sprinkling it around you’re creating a lot of little hotspots that could potentially have failure without backup,” he said.

Toyota concentrated in California on solving the whole equation, from supply to distribution to station provider — driven by supportive public policy.  In the Northeast, “culturally I think there’s a huge alignment as well … a strong desire to have green hydrogen and carbon neutralization here,” Moore said.

Case Study Power

Vicinity Energy plans to decarbonize its district energy system, which serves more than 65 million square feet of buildings and facilities in Boston and Cambridge, through a combination of renewable fuels, hydrogen, large scale heat pumps and storage.

District energy is a force multiplier, a way to get inside a building and alter that building’s carbon profile without having to make significant changes or any changes in the building at all, said Kevin Hagerty, chief technology officer of Vicinity Energy.

The company owns about 26 miles of steam piping underneath Boston and Cambridge, and three central facilities situated on the backbone power grid, all serving the equivalent of 55 Prudential Towers.

“If we make a change on just one of our facilities, if we make a small fuel change or small changes to our producing that steam, it alters the carbon profile of all the buildings connected to the district energy system,” Hagerty said.

The company is achieving electrification by installing electric boilers, industrial heat pumps, and thermal batteries, and hopes to take “a big bite out of the Boston and Cambridge carbon emissions” and decarbonize upwards of 800,000 metric tons per year by 2035, Hagerty said.

Industrial heat pumps will leverage heat from the adjacent Charles River, and thermal batteries will help the company improve district energy’s existing good alignment with peak generation from the offshore wind that’s soon coming onto the New England grid, he said. Offshore wind, like heating, peaks in the winter, and its daily production peak from 8 p.m. to 4 a.m. would offer Vicinity low-cost power for its load peak, which is precisely opposite the OSW production peak hours.