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November 19, 2024

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California Coastal Commission Approves OSW Lease Plans

The California Coastal Commission took an important step last week to allow the West Coast’s first offshore wind lease auctions to proceed later this year, voting to back the federal Bureau of Ocean Energy Management’s assessment that lease activities off the coast of Central California are consistent with state and federal laws.

“I’m so excited we’ve finished this phase and will be moving forward,” commission Chair Donne Brownsey said after the unanimous vote Wednesday.

The commission had already approved leasing activities in April for the Humboldt Wind Energy Area (WEA) in Northern California. The latest vote concerned the Morro Bay Wind Energy Area — near the village of Cambria — the second of two WEAs that BOEM plans to auction this fall. Together the areas could generate 4.6 GW, a significant contribution to the state’s effort to rely on 100% clean energy by 2045.

While the lease areas in the Morro Bay area are 20 miles offshore in federal waters, the Coastal Commission has broad authority to govern activities within 3 miles of the coast and generally within about 1,000 yards of the high-tide mark on land. Following the auction, BOEM’s issuance of leases allows successful bidders to conduct studies in their lease areas, including installing buoys with data collection equipment and geophysical, biological, archaeological and ocean-use surveys. BOEM expects lessees to make up to 873 vessel trips to complete their surveys and site assessments over a three-year period.

“Lease activities have the potential to adversely affect marine resources through seafloor habitat disturbance and increasing turbidity, elevated levels of underwater sound during surveys, increased risk of ship strikes due to increased vessel traffic and incrementally increased entanglement risk due to the placement of buoys,” the Coastal Commission said in a staff report.

BOEM issued a proposed sale notice for the WEAs last month. (See BOEM Issues Proposed Sale Notice for Calif. Offshore Wind Areas.)

The Morro Bay leases will cover about 241,000 acres of ocean in an area home to whales, dolphins, deep-sea corals and sponges, among other species.

The leases do not permit the installation of wind turbines or other infrastructure. Development of the areas will fall under future proceedings by BOEM and the Coastal Commission, requiring approval by both. When development does occur, it will likely include some of the largest floating wind turbines ever built, capable of generating 15 MW each.

“A 15-MW turbine would be expected to have the following approximate dimensions: a hub height of 486 feet, a rotor diameter of 807 feet and a maximum height at the blade tip of 889 feet,” the staff report said. “If turbines of this size were installed in the Morro Bay WEA, they would likely have a distance between turbines of 0.917 to 1.22 miles.”

Mooring cables, undersea transmission lines and onshore port facilities would be part of the development plans.

“Approximately every 10 years, the entire system would need to be disconnected and towed to shore for repairs, followed by reinstallation,” the report said.

The Coastal Commission’s decision came with some conditions, including that the lessees’ surveys and site assessments minimize impacts to coastal resources, comply with marine wildlife protection measures and avoid contact with rocky outcroppings, seamounts, or deep-sea coral and sponge habitat. Another condition restricts vessel speeds to 10 knots, including during travel from harbors to the survey sites.

Public commenters at the hearing — which was surprisingly uncontentious, several of them noted — tended to support commission approval of the lease activities.

“Speaking on behalf of 45 companies, including offshore wind developers and technology firms, we are unified in our support of the Coastal Commission’s staff report and its conditions for federal leasing activities in the Morro Bay Wind Energy Area,” said Adam Stern, executive director of trade group Offshore Wind California. “Your endorsement of the staff report — similar to your unanimous action on the Humboldt Wind Energy Area in April — would reaffirm the commission’s historic commitment to protect California’s coastal resources and heritage, while also advancing the state’s clean energy and climate goals.”

The California Energy Commission is currently re-evaluating its goals for offshore wind development — 3 GW by 2030, and 10 to 15 GW by 2045 — after critics said they were too modest given the state’s clean energy needs and should be as high as 18 to 50 GW by 2045. (See CEC Postpones Vote on Offshore Wind Goals.)

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PG&E Vows to Reach Net Zero by 2040

Pacific Gas and Electric said Wednesday it plans to achieve carbon neutrality by 2040 and become “climate positive” by 2050, taking in as much carbon as it produces through carbon capture and other means while continuing to supply natural gas to customers.

“As recent events have made clear, California is not just on the front line for taking action on climate change, we’re also at the front line of its destructive effects,” CEO Patti Poppe said in a video announcement. “We cannot accept that. We can’t be content with simply adapting to those harms. We have to slow them down. We need to put that climate machine in reverse and begin undoing the damage.”

With its plan, PG&E joins the ranks of large investor-owned utilities that have made climate pledges, including Xcel Energy, which committed in December 2018 to provide its customers with 100% carbon-free energy by 2050, and Arizona Public Service, which did the same in January 2020.

Publicly owned utilities that have made similar commitments include the Sacramento Municipal Utility District, which promised to eliminate all greenhouse gas emissions from its electric generation by 2030. The Los Angeles Department of Water and Power is seeking to rely on 100% renewable power by 2045.

Under Senate Bill 100, California utilities must supply retail customers with 100% carbon-free resources by 2045. Other measures require the state to reduce its greenhouse gas emissions to 40% below 1990 levels by 2030 and 80% below 1990 levels by 2050.

PG&E’s ambitious plan is short on many details but lays out a broad strategy for meeting its goals.

By 2030, the company said, its generation mix will consist of 70% renewable resources such as wind and solar.

Promoting adoption of electric vehicles is a cornerstone of its carbon-reduction efforts.

“PG&E plans to be the industry’s global model by fueling at least 3 million electric vehicles in its service area by 2030 — leading to a cumulative reduction of at least 58 million metric tons of carbon emissions,” it said in a news release. The company also wants 2 million EVs to be able to send electricity back to the grid, “allowing EVs to be a cornerstone of energy reliability and resilience efforts.” It has begun vehicle-to-grid pilot programs with approval from the California Public Utilities Commission.

Another 48 MMTs of carbon reduction could come from building electrification and replacement of gas appliances, it said.

By 2030, PG&E expects renewable natural gas to make up 15% of its gas supply serving residential and commercial customers, and it said it is launching a pilot program to “maximize readiness for hydrogen blending.” Converting large industrial and commercial users to a cleaner natural gas supply will cut 2.5 MMT, it said.

“PG&E’s vision is to evolve the gas system to be an affordable, safe and reliable net zero energy delivery platform,” the utility’s news release said. “To make the transition, PG&E expects a diverse mix of resources to be available — from broad electrification to cleaner fuels such as renewable natural gas and hydrogen to nature-based solutions and carbon capture, storage and utilization.”

Direct-air carbon capture and underground sequestration will offset greenhouse gas emissions from thermal generation and other sources, PG&E said in its plan.

“With increasing electricity demand from buildings and transportation, California must also substantially invest in thermal generation with clean fuels and/or carbon capture and storage to maintain reliability,” it said.

The California Public Utilities Commission would have to approve the programs, including the ratepayer costs at a time of soaring utility bills. PG&E also has announced ambitious plans to bury 10,000 miles of power lines to avoid wildfire ignitions, the massive cost of which must still be determined.

PG&E is planning to close its Diablo Canyon nuclear power plant by 2025, but the utility said it expects to be able to meet its clean energy goals without the plant. The office of Gov. Gavin Newsom recently petitioned the Biden administration to make funds available to keep the plant open to maintain grid reliability while providing a large portion of the state’s carbon-free energy.

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OMS-MISO RA Survey Says Supply Deficits Could Top 10 GW by 2027

MISO and the Organization of MISO States’ 2022 resource adequacy survey again sounded the supply alarm that the RTO rang in early April when it published its 2022/23 capacity auction results.

The survey projects the footprint will have a 2.6-GW capacity deficit below the 2023 planning reserve margin requirement. The shortage would more than double up the 1.2-GW shortfall unearthed in the 2022/23 Planning Resource Auction. (See MISO’s 2022/23 Capacity Auction Lays Bare Shortfalls in Midwest.) As with the auction results, the survey foresees the shortfalls confined to MISO Midwest.

“Our efforts must be accelerated and reinforced to reliably manage the portfolio transition,” MISO Executive Director of Resource Planning Scott Wright said during a special teleconference Friday to discuss the results.

The five-year OMS-MISO survey foresees more bad news on the horizon, as well, with possible capacity deficits that are expected to deepen through 2027. The survey showed MISO could be short 4.4 GW in the 2024/25 planning year, 6.5 GW in 2025/26, 7.4 GW in 2026/27 and nearly 11 GW by 2027/28.

MISO’s Local Resource Zone 6, in Indiana and a portion of Kentucky, stands to have the widest capacity deficit in 2023. By the 2027/28 planning year, Zone 7 in Michigan’s Lower Peninsula and Zone 8 in Arkansas are the only zones that appear to have a comfortable padding of committed capacity.

However, MISO and OMS said much depends on how market resources respond to this year’s capacity auction results. If resources act, MISO Midwest could have a 2.4-GW capacity surplus in 2023, they said.

“We think there are a lot of things that could help mitigate the risk and even have a surplus in 2023,” Wright said.

2022 OMS-MISO Survey results (MISO and OMS) Content.jpg2022 OMS-MISO Survey results | MISO and OMS

 

The survey put MISO’s 2023 demand growth at 1 GW (a 0.8% increase year-over year) as the pandemic recovery finishes. It predicted “modest growth thereafter” at 0.2% per year through 2027. The survey didn’t contemplate MISO’s new seasonal capacity design and availability-based resource accreditation pending before FERC.

Last year’s survey anticipated the grid operator would have anywhere from 3.4 to 13.9 GW of extra unforced capacity beyond its summer peak planning reserve margin requirement. That supply estimate didn’t pan out in the 2022/23 auction, which left MISO Midwest short of its 101.2-GW requirement. The 2021 survey also predicted anywhere from a 3.3-GW shortage to a 13.3-GW surplus through 2025. (See 2021 OMS-MISO Resource Adequacy Survey Shows Less Cause for Concern.)

MISO predicted it will be increasingly reliant on emergency and non-firm imports going forward. The grid operator said that while those resources are not reflected in the survey, they “have historically been important and available to MISO.”

However, if new generation can interconnect, MISO could have a few gigawatts to spare in 2024-2027. MISO and OMS said the impending threat “can be meaningfully mitigated” depending on the tempo of new generation and retirements.

“We have a very active queue process,” Wright reminded stakeholders. “I feel like we’ve had a good track record of adding about 2.5 GW of [unforced capacity] every year.”

OMS President and Indiana Utility Regulatory Commissioner Sarah Freeman noted that there are “tons of generation in the queue” waiting to replace retiring resources.

Freeman also said the results are a “very static glimpse” in time, and that MISO’s and states’ planning processes are dynamic.

But Clean Grid Alliance’s Natalie McIntire pointed out that the new transmission capacity MISO is planning under its long-range transmission portfolio is still years away. She said the new lines are needed in order to interconnect new generation.

Freeman opened the floor to suggestions on how to improve next year’s survey structure.

“It’s only as accurate as the questions we have on it,” she said.

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DOE Initiative Aims to Make Interconnection ‘Simpler, Faster, Fairer’

The message from the Tuesday launch of the Department of Energy’s Interconnection Innovation eXchange (I2X) initiative was clear: To reach President Biden’s goal of a U.S. electricity system powered 100% by clean power by 2035, interconnecting solar, wind and other clean energy projects to the grid must be made simpler, faster and fairer.

The latest figures from the Lawrence Berkeley National Laboratory (LBNL) show that more than 1,400 GW of mostly zero-carbon generation and storage projects are sitting in transmission interconnection queues across the country, with solar making up about half the total.

“This is mind-blowing to me,” Energy Secretary Jennifer Granholm said in opening remarks at the virtual launch. “That 1,400 GW is about what we need to reach a critical milestone of 80% clean electricity by 2030. If we could get all that capacity online, imagine how much faster we could reach our climate goals.”

Granholm acknowledged the challenges ahead are complex, if not daunting. LBNL also found that interconnection wait times are trending up, while project completion rates are falling. From 2000 to 2016, completion rates sat at 20% for solar projects and 16% for wind projects. In 2021, wait times had climbed to 3.7 years, up from 2.1 years a decade earlier.

Further, according to Alejandro Moreno, DOE deputy assistant secretary for renewable power, the time and cost of interconnection processes “tend to favor incumbents who have the resources and know-how to add new generation to the grid. [But they] can disadvantage new generation, particularly community-scale generation,” he said.

“Because [these] projects tend to be smaller in scale, they’re more sensitive to cost and become quickly too expensive to build,” Moreno said.

Funded with $3 million from the Infrastructure Investment and Jobs Act, I2X hopes to untangle such issues by pulling in a broad range of stakeholders, setting up collaborative working groups, collecting and analyzing massive amounts of data and developing a five-year interconnection roadmap, Granholm said. The initiative will look at both transmission- and distribution-level interconnection.

About 200 companies and organizations have already signed up to participate, including CAISO, PJM, SPP and NERC, as well as major utilities such as National Grid, Xcel Energy and the Los Angeles Department of Water and Power.

With stakeholder engagement a core pillar of the initiative, Naomi Davis, founder and CEO of Chicago nonprofit Blacks in Green, said a commitment to ensuring communities are at the table will be essential. The need is real, she said, “but the practice requires a budget line item, and it requires metrics, concrete metrics for achieving equitable, meaningful engagement.”

Speaking on the first of two stakeholder panels at the launch, Davis pointed to weatherization as a “threshold issue” for communities of color. “We have many seniors, homeowners who are entitled … to have the comfort, the security, the reliability of the new renewable energy that everyone is so excited about but which too few of our homes in the Black and brown community are prepared to receive. The deferred maintenance issue must be addressed,” she said.

Danielle Sass Byrnett, director of the Center for Partnerships and Innovation at the National Association of Regulatory Utility Commissioners, spoke of the intensive stakeholder engagement processes now underway in several states as they roll out interconnection standards under IEEE 1547-2108. Implementing the standards for interconnecting distributed energy resources has taken multiple years of “learning about the standard, understanding the implications of different decision-making within the standard … and looking at the processes and speed of interconnection once you have the new standards in place,” Byrnett said.

To help utilities and DER developers navigate the new rules, some states are experimenting with “interconnection ombudsmen or adjudicators,” she said.

Models Don’t Match Reality

Beyond simpler, faster and fairer, I2X has some ambitious goals, according to Tom McDermott, solar subsector manager at the Pacific Northwest National Laboratory, one of three National Laboratories working on the initiative with DOE. The other two are LBNL and the National Renewable Energy Laboratory.

By the end of the year, I2X will have defined and simulated interconnection process improvements, McDermott said. The first draft of the roadmap and an accompanying interconnection studies guide geared toward engineers are due March 31, 2023.

“We also need to define achievable metrics for improvement over the five-year horizon, for example to reduce the cost and time of interconnection by 50%,” he said. “The right number may vary by state, region or operating entity.”

The roadmap will include separate sections for the bulk power and distribution systems and for large- and small-scale generation, McDermott said. “There may be different approaches for regulated and unregulated jurisdictions … and finally the roadmap will suggest mitigations for any costs, delays or uncertainties encountered in the transition from existing practice to a better set of practices.”

Drilling into key interconnection issues on the second stakeholder panel, Ryan Quint, a senior manager at NERC, argued for I2X to have a strong focus on reliability.

“The current interconnection requirements and interconnection study processes are not equipped to handle the new resource base” of renewable energy, Quint said. “Some of the issues include component modifications and rework throughout the process, which adds complexity and slows down the process.”

“We end up with models that are used in reliability studies … and these models don’t match reality” and can ultimately create “a huge liability risk,” he said.

“We need to recognize that reliability and speed of interconnection don’t have to be conflicting objectives here,” Quint said. “We need to develop measures of success that assess the root cause issues we face, not the symptoms.”

For example, instead of measuring project dropout rates, Quint said, researchers should be looking at the number of studies “that are necessary because equipment changes were made at the last minute” or the disparities between interconnection requirements and processes.

Automation is Coming

Charlie Smith, executive director of Energy Systems Integration Group, boiled the metrics down to three main benchmarks. For faster interconnection, he wants the time from application to interconnection agreement cut to “two years or even months.” To measure fairness, he said, the question will be, “[Are] our developers being saddled with unreasonable network upgrade costs, yes or no?”

To make the process simpler, he called for “a publicly transparent generator connection study process that allows developers to do their own analysis and have a sense of cost before submitting their project in order to reduce speculative projects.”

Smith also pointed to “connect and manage”  interconnection practices in Ireland, the U.K. and Germany. In these countries, he said, generation projects may be allowed to connect to a transmission system before completion of a wider set of system upgrades.

Brian Fitzsimons, CEO of GridUnity, sees interconnection as “a large, integrated data capture, data sharing and analysis problem that needs to be brought into the real-time, information-sharing world.” He talked up his company’s cloud platform for aggregating and validating data and automating engineering analysis.

“Automation of engineering analysis will reduce study times and can be applied to reduce the number of stages in the process and the number of complex decision points,” he said. “As study cost and time come down, there won’t be as much need for multiple go-no-go points in the interconnection process.”

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ERCOT Issues Low-level Alert as Heat Builds

ERCOT on Wednesday issued its third operating condition notice (OCN) since April, warning of extreme heat in several of its weather zones this weekend.

The Texas gird operator distributed the OCN, its lowest-level communication of a possible emergency condition, because it expects forecasted temperatures to exceed 103 degrees Fahrenheit in its North Central and South Central weather zones from Friday through Monday. Emergency conditions are issued when staff determine the system’s safety or reliability is compromised or threatened.

The first OCN was issued on May 3 and extended several times through May 20. A second OCN was issued for May 28-30.

AccuWeather said Wednesday Texans can expect the sweltering heat that has hung over the state since early June will stick around into next week. The weather pattern has been stuck in place for more than a week, the weather service said, allowing heat to build across the south-central U.S.

Daily temperatures have been 5-15 degrees above normal in many cities, with San Antonio setting records with consecutive 104-degree days Monday and Tuesday. Temperatures in the Dallas area are expected to reach triple digits Friday for the first time this year; the average date for Dallas’ first 100-degree day is July 1, according to an AccuWeather meteorologist.

ERCOT this week expected to break its all-time peak demand record of 74.8 GW, set in August 2019. (See ERCOT Expecting Record Demand this Week.) Demand fell short of that mark but did set June highs of 72.4 GW and 72.8 GW Monday and Tuesday, respectively. Demand Tuesday stayed above 72 GW for the three intervals ending 4-6 p.m.

The day-ahead forecast for Thursday projects a demand peak of 75.6 GW.

The ISO’s conservative operations posture had as much as 84 GW of committed capacity available Wednesday, when demand was expected to barely reach 70 GW. ERCOT apparently reduced demand by 649 MW after an explosion shut down an LNG plant near Houston.

In a blast email response to a Dallas television station that was sent to ERCOT’s media distribution list Wednesday, the grid operator said it “projects sufficient generation to meet forecasted demand.”

ERCOT expects peak demand to hit a record 77.3 GW this summer, it said in its seasonal assessment of resource adequacy released last month.

TAC Briefed on Recent Frequency Event

Staff gave ERCOT’s Technical Advisory Committee an early update on a frequency event last weekend in West Texas that momentarily knocked 2.5 GW of capacity offline.

Woody Rickerson, the ISO’s vice president of system planning and weatherization, told the committee during a Tuesday webinar that a lightning arrestor on a 345-kV line near Odessa faulted. Voltage briefly fell to 59.706 Hz before being restored to 60 Hz within two minutes.

The outage took 1.7 GW from 14 solar sites offline. Eight of the 14 solar sites also tripped offline last year in what is now called the “Odessa disturbance.” More than 1.1 GW of solar PV resources, up to 200 miles away, were affected.

Rickerson said staff has only just begun to collect data on the event as part of a full analysis required by NERC. He said preliminary results indicate a possible problem with the solar facilities’ inverter settings. Rickerson ­will discuss the event Friday with a task force addressing the growing dominance of inverter-based resources and also plans to bring a more detailed report to TAC’s June 27 meeting.

The committee also discussed its final comments to ERCOT’s proposed methodology for approving and denying planned generation maintenance outages in advance of the Board of Directors’ June 21 meeting. TAC Chair Clif Lange said he will share with directors the committee’s the “full range” of concerns with the methodology and why they exist.

Members and staff shared their respective comments on the maximum daily resource planned outage capacity calculation, the key feature in ERCOT’s plan to evaluate outage requests. TAC believes the calculation limits outages when compared to history and that a 10% growth rate for renewable resources is too low. Staff have said they want as much capacity and flexibility as possible for planned outages while maintaining reliability.

The board in April granted staff’s appeal of a revised nodal protocol revision request (NPRR1108) that gives the grid operator the authority to review, coordinate and approve or deny all planned generation maintenance outages. Stakeholders earlier rejected staff’s version of the measure, unanimously approving an NPRR as amended by several joint commenters. (See ERCOT Board of Directors Briefs: April 28, 2022.)

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NERC RSTC Briefs: June 8-9, 2022

Committee to Meet Face-to-face in September

NERC’s Reliability and Security Technical Committee (RSTC) plans to hold its next meeting in person in Atlanta, though the venue has not been chosen yet, committee leaders told attendees at its June meeting held via conference call on Wednesday and Thursday.

RSTC members have not met face-to-face since the committee’s first meeting, a short gathering in Atlanta in March 2020 at which attendees mainly discussed how to take over the business of the now defunct Planning, Operating and Critical Infrastructure Protection committees. (See RSTC Tackles Organization Issues in First Meeting.) The committee had planned to hold its first meeting of 2022 in person, but it was converted to a virtual gathering before the December conference call.

In that meeting, Secretary Stephen Crutchfield did not mention the change specifically but said the September gathering was “the only one [for which] we had a hotel booked currently.” On Thursday, Crutchfield said the meeting has changed from that location, the Grand Hyatt Atlanta in Buckhead, for unspecified reasons; however, he said NERC staff are “working on getting a new location” and that the committee does not intend to convert it to a conference call again.

December’s meeting is still being envisioned as virtual, but on Thursday, Edison Elizeh of the Bonneville Power Administration suggested that this gathering be held in person too, in light of the decision to cancel the physical meeting in April. Crutchfield said the RSTC executive committee plans to consider this at its upcoming meeting next Tuesday; NERC staff asked that attendees advise as to their ability to travel that month in light of “end-of-year responsibilities and the holiday.”

SARs Move to Standards Committee

Committee members endorsed two standard authorization requests (SARs) authored by NERC’s Energy Reliability Assessment Task Force on Wednesday. The goal of the project is to update NERC’s reliability standards (either by creating new standards or modifying existing ones) to require registered entities to perform energy reliability assessments in order to evaluate energy assurance and to develop corrective action plans to address any identified risks. The SARs will now be submitted to NERC’s Standards Committee for approval.

However, another SAR — proposed by the Inverter-based Resource Performance Working Group (IRPWG) to modify standard EOP-004-4 (Event reporting) to address a flaw identified in a report on the July 2020 San Fernando Disturbance — was rejected by the committee.

The incident involved a widespread reduction of active power from solar facilities across a large geographic area; the report’s authors said that EOP-004-4’s event-reporting requirements are intended for large synchronous generating resources and don’t address scenarios in which generation losses at a number of small facilities add up to a large loss.

Presenting the SAR to the committee, the IRPWG’s Julia Matevosyan said the goal is to “ensure that future events that are similar to already-experienced [solar] events … would be captured by this [new] generation loss criteria.”

Attendees expressed discomfort at the SAR’s proposal to make reliability coordinators responsible for reporting the relevant generation loss data. The SAR justified this suggestion on the grounds that RCs “are best suited for identifying widespread events … involving solar PV and wind resources [and] are also able to coordinate with [neighbors] to identify if the loss of resources spans across multiple footprints.” But Duke Energy’s Greg Stone, in comments that were echoed by other speakers, said this idea would put the burden on the wrong stakeholders.

“The RCs … are reliability coordinators, not reporting coordinators,” Stone said. “Given the commentary that we got in [Matevosyan’s] presentation that the collection and submission of this data is already problematic, we don’t need to be putting the RCs in the middle of that and especially create a compliance burden for the RCs to go hunt this down after the fact. … Put the burden of reporting the data on the people who have the data, and don’t put another function in the middle of that.”

While 17 of the 30 RSTC members in attendance voted to endorse the SAR, with 11 voting against it, the committee’s rules require a two-thirds majority for an item to be considered approved. As a result, the proposal failed. Receiving the RSTC’s endorsement is not technically required to proceed with a standards development project, but Matevosyan agreed to take the SAR back to the IRPWG and modify it based on committee members’ feedback.

Procedural Confusion on EMT SAR

The RSTC’s rules created some confusion around another SAR intended to ensure that transmission planners and planning coordinators “have accurate models necessary to adequately conduct reliability assessments under increasing levels of inverter-based resources” by requiring TPs and PCs to conduct electromagnetic transient (EMT) studies during the interconnection study process and annual planning assessments.

The vote on endorsement initially appeared to fail to meet the two-thirds threshold, with 19 votes in support out of 30 recorded. But committee staff pointed out that under RSTC rules, abstentions are not counted as votes cast — therefore, the three abstentions should be left out of the total. After this subtraction, the eight votes against endorsement were not sufficient to carry the field.

This decision led to several minutes of discussion over the procedural implications of the rule; while no members disputed the result of the vote, several said that the existence of an “abstain” option in Slido, the voting software used by the committee, was at least an implication that votes other than yes or no were possible. Staff agreed to change the options in Slido, renaming “abstain” to “present,” in hopes of preventing further misunderstandings.

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Conn. Climate Council Gears Up for New Work Session

Connecticut Department of Energy and Environmental Protection Commissioner Katie Dykes kicked off a new phase of work Wednesday for the Governor’s Council on Climate Change.

“We want to be flexible and encourage working groups to reconvene, refresh their membership … and have the chance for dialogue to see what flows out of that,” Dykes said during the council’s first meeting of the year.

The state has made significant progress on recommendations in the council’s phase one report released in January 2021, but the council has “a lot more to do,” she said.

During the meeting, Dykes highlighted recent legislative successes that stem from the council’s report, including passage in May of an act establishing a goal of 100% zero-carbon electricity by 2040 and an act that expands programs for distributed energy resources.

Gov. Ned Lamont signed an executive order in December that extended the council’s responsibilities to include reporting by the end of the year on mitigation and adaptation and resilience progress.

Six working groups, aligned under a mitigation subcommittee and an adaptation and resilience subcommittee, will convene with a focus on cross-cutting themes that the council identified during the phase-one report development. Those themes include environmental justice and leveraging Infrastructure Investment and Jobs Act funding.

The council will select subcommittee and working group members this month, and the groups will meet twice before October. Those groups will present the results of their meetings to the full council in December, and the council will make a final progress report to the governor in January, according to Rebecca French, director of the Office of Climate Planning at DEEP.

“This is not a one year and done process,” French said, adding that the groups will continue discussions “in 2023 and beyond.”

The “spirit” of the council’s work this year is to reinvigorate the relationships that members built while developing the phase one report, Dykes said. Working groups will have an opportunity to take an in-depth look at what is happening in their focus areas and “give people a sense of where to plug in and get involved,” she said. They also will look at next steps for policies that can support objectives in the phase one report.

“We’re eager to see what comes out of this activity over the next couple months,” Dykes said.

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DOE Conference Details Massive R&D Effort on Clean Hydrogen

The Biden administration’s efforts to develop a hydrogen market — from the generation of clean hydrogen to its use as a universal fuel across the economy — has expanded as if on a war footing, focusing the firepower of the National Labs alongside that of multiple industries and universities.

That was made clear this week at the U.S. Department of Energy’s three-day virtual symposium, which attracted thousands of engineers, scientists and curious members of the public, and covered every aspect of what has become a rush to move the nation from fossil fuel to hydrogen energy.

Even before President Biden unveiled the administration’s goals in a series of speeches during the first weeks of his term, DOE had in late 2020 published an updated hydrogen plan that predicted the federal push to combat climate change by moving the nation to hydrogen. That plan was an update on previous, but much less ambitious, plans dating back to 2002.

The accelerated efforts under this administration have even surprised Sunita Satyapal, director of the Hydrogen and Fuel Cell Technologies Office within DOE’s Office of Energy Efficiency and Renewable Energy (EERE). She was moderator of the initial plenary session on Monday that took a quick look at the hydrogen effort, from basic science to deployment.

“Keeping track of all the information out there because things are moving so quickly” has become difficult, Satyapal said. “There are so many offices, so much happening in the space.

“Please do keep track of the websites and newsletters,” she advised viewers and listeners before introducing Todd Shrader, head of one of DOE’s newest operations, the Office of Clean Energy Demonstrations. “What are the priorities that stakeholders out there should pay attention to from your perspective?” she asked.

Shrader’s response: “What’s it going to take to launch the new hydrogen economy itself?” he replied. “We can build hydrogen hubs 1 through 4, or 1 through 5 with government support,” he said in a reference to the department’s offer of up to $2 billion in matching grants to regions capable of cooperating to build regional developments producing clean hydrogen for use by nearby industries.

“But what’s it going to take to build plants 6 to 100? What’s it going to take to move to these [administration] goals by 2035 and 2050?” he said in a reference to the administration’s goal of building a carbon-pollution free U.S. power grid by 2035 and a net-zero carbon economy by 2050.

But producing hydrogen, whether by electrolysis with renewable energy or by splitting it from methane and capturing the resulting carbon dioxide, is a complex process.

Ned Stetson, a veteran hydrogen technologies researcher and now program manager at DOE, made that clear when explaining the efforts of his research team at EERE to develop electrolyzer and related technologies to produce hydrogen at a price comparable to steam reforming and ultimately even lower.

Steam reforming today produces about 99% of the hydrogen used by industry, and one reason is that electrolyzer technology, from efficiency to durability, cannot compete. Helping industry develop more efficient and more durable electrolysis technology is near the top of Stetson’s list. But it’s not alone.

“We cover everything from reducing the hydrogen molecule; to all the infrastructure needed to condition it, move it, store it and dispense it; to all these various end-use applications for power generation, industrial applications and so forth,” he said.

“We are also involved with blending hydrogen with the natural gas infrastructure, and in terms of transportation, we’re also developing the onboard storage technologies. So it’s a very large activity covering a lot of distance.

“We are really focused in our office on using the clean and sustainable energy resources and feed stocks to produce clean hydrogen. We look at several key pathways producing hydrogen, including direct solar water splitting, biological processes and, of course, electrolysis. And then once you produce the molecule, we work on the conditioning, liquefying it … purifying it, moving it, storing it and then finally dispensing it to the new application,” he said.

The Infrastructure Investment and Jobs Act has provided $1 billion in research and development funds for electrolysis, he said. The ultimate goal is reduce the price of hydrogen produced through electrolysis to $1/kg by 2031.

“The goal of the electrolysis program is reducing the cost of hydrogen produced with electrolyzers to less than $2/kg by 2026. That’s right in line with getting to $1 by 2031,” he said.

After asking for input in February from industry and other researchers about how these goals might be accomplished, the division received comments from 120 companies and individuals, he said.

“We asked about the key attributes for storage and infrastructure, the ancillary technologies, what would be some of the barriers for scale up. What are the needs for national test facilities for electrolyzers? We asked about recommendations to incorporate … diversity and equity. We got a lot of input from … manufacturers and developers including universities and a lot of end users and stakeholders,” he said. “We’re still digesting all the information.”

An example of DOE working with industry is its contract with Shell in October 2021 to develop very large liquid hydrogen storage tanks. Such tanks will be important for domestic storage and at export terminals.

“Shell is looking at designing … an extremely large liquid hydrogen storage vessel, 20,000 to 100,000-cubic-meter storage vessels. To put that in perspective, currently the largest liquid hydrogen storage vessel, just constructed at the Kennedy Space Center, and is about 4,700 cubic meters,” Stetson said.

Dimitrios Papageorgopoulos, program manager at DOE’s Fuel Cell Technologies, provided some perspective on the depth of the agency’s involvement in efforts to help industry develop fuel cell power systems capable of competing in, for example, heavy trucking, power generation or infallible standby generation.

“The goal is to develop fuel cells that are competitive with incumbent and emerging technologies across all these applications. The goal is to develop these fuel cells to meet market needs, and this is very important because we’re not looking to develop a technology for the sake of technology,” he said.

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NYISO 2022 Power Trends Report: Reliable Clean Energy Needed Quickly

NYISO continues to adapt its wholesale electricity markets and grid planning processes to accommodate a wave of widely distributed renewable resources more dependent on weather than traditional generation, according to the ISO’s annual Power Trends report issued Wednesday.

“The introduction of a lot of new resources and the planned exit of some high-emitting resources that we’ve relied on for quite some time has resulted in an increasingly dynamic, decentralized grid, which means it’s much more complicated to be able to manage and predict how the core functions are going to be satisfied,” CEO Rich Dewey said in a press briefing. “A lot of our focus is making sure that we’ve got the tools and capabilities to maintain the necessary level of reliability as we move through that transition.”

Reliability margins are shrinking as generators needed for reliability are planning to retire, and electrification of space heating will likely flip the peak load from summer to winter in the mid-2030s, according to the report, subtitled “The Path to a Reliable, Greener Grid for New York.” Meanwhile, delays in building new supply and transmission, higher-than-expected demand, and extreme weather could threaten reliability and resilience in the future, the report said.

Forecast Load Shapes (NYISO) Content.jpg2021 New York Control Area (NYCA) Bulk Electric System 2021 Actual and 2042 Forecasted Winter/Summer Load Shapes | NYISO

 

A successful transition of the electric system requires replacing the reliability attributes of existing fossil fuel generation with clean resources with similar capabilities, the report said. New transmission is being built, but more investment is necessary to support the delivery of offshore wind energy and to connect new resources upstate to downstate load centers where demand is greatest.

“We at NYISO have been firm advocates for the need for new transmission for several years now, and we’re happy to report that that New York state, not only the New York ISO, but also some of our state partners — the Public Service Commission and the New York Power Authority — are making meaningful progress in the development of new transmission that will be critically important to help move power from the upstate region,” Dewey said.

New York’s Climate Leadership and Community Protection Act (CLCPA) requires that 70% of the state’s energy come from renewable resources by 2030 and that its grid be 100% net-zero emissions by 2040.

FERC in May approved three changes to NYISO’s capacity market that were spurred by the CLCPA, such as excluding new policy-driven resources from its buyer-side market power mitigation (BSM) rules, which will eliminate offer floors for wind, solar, storage, hydroelectric, geothermal, fuel cells that do not use fossil fuel, demand response and other qualifying resources under the law. (See FERC OKs NYISO Capacity Market Changes Stemming from NY Climate Law.)

Hourly load profiles are also changing because of the growing impacts of behind-the-meter solar, EV charging, climate change and post-COVID-19 shifts in the occupancy rates of homes and businesses, the report said.

The ISO’s announcement for the report also includes a datasheet of key takeaways.

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ISO-NE Starts its Capacity Accreditation Journey

ISO-NE this week launched its effort to revamp its resource capacity accreditation process, a key fix to the capacity market that has been tied in with discussions around the contentious minimum offer price rule.

In a presentation to NEPOOL Markets Committee on Tuesday, ISO-NE’s Steven Otto laid out the beginnings of the RTO’s thinking and offered some early hints as to where it’s leaning as it prepares a more detailed proposal in the coming months.

The goals of the project are to boost reliability and maintain cost effectiveness as New England moves toward a decarbonized grid. The RTO’s current accreditation process is a mishmash of approaches that the grid operator has acknowledged doesn’t do a good enough job reflecting different energy sources’ contributions toward resource adequacy and reliability.

One of the key decisions that ISO-NE is thinking through, Otto said, is whether to employ an average or marginal approach to capacity accreditation.

Capacity accreditation (ISO-NE) Content.jpgThe pros and cons of marginal and average approaches to capacity accreditation | ISO-NE

 

Marginal approaches “set a resource’s accredited capacity based on the marginal reliability impact of an incremental change in size,” he said. Average approaches, on the other hand, set the accredited capacity based on the average reliability impact of a resource’s class.

The RTO is currently leaning toward a marginal approach, Otto said, sometimes also called a Marginal Reliability Impact value.

The advantages of a marginal approach, according to ISO-NE, are that it sends accurate entry and exit signals to market participants, can incorporate interactions between resource types, and provides the same compensation to resources that provide the same service.

It’s far from a settled conversation though: The grid operator is planning a roughly yearlong stakeholder process to hash out the details and decide on a proposal to send to FERC.

The first phase, involving conceptual design and education, is planned to go through October of this year. The RTO will start presenting a detailed design in November and move to finalize that design and produce tariff language by next spring. Stakeholder committee votes are planned for May and June of 2023.

Feedback on capacity accreditation will come both through the stakeholder process and outside of it: The Massachusetts Attorney General’s Office, for example, is planning to produce a report with recommendations in the coming weeks.