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November 8, 2024

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NYPA Reports Successful Hydrogen Test at Natural Gas Power Plant

The New York Power Authority on Friday reported success in a hydrogen-natural gas hybrid demonstration project at a 45-MW power plant it operates on Long Island.

NYPA said the Brentwood Small Clean Power Plant maintained full operational status while decreasing carbon emissions during the test.

The project was a collaboration with EPRI, General Electric and Airgas, among others, and was the first utility-scale hydrogen-blending project in New York, NYPA said.

The plant’s GE LM-6000 turbine was tested with fuel mixtures of 5% to 44% hydrogen from the fall of 2021 through spring 2022.

At steady state conditions, the exhaust stack ammonia, carbon monoxide and nitrogen oxide slip levels showed that emissions could be maintained below the state Department of Environmental Conservation Title V Regulatory Permit limits using the existing post-combustion emissions reduction systems, NYPA said.

Carbon dioxide emissions decreased as the hydrogen percentage increased, the test found. At 35% hydrogen by volume, CO2 output was down by about 14%.

Carbon monoxide decreased by as much as 88% as the hydrogen mixture increased, apparently due to greater oxidation in the presence of hydroxyl radicals resulting from hydrogen combustion.

However, NOx increased by as much as 24% as the hydrogen content was increased, unless the water injection rate also was increased. This performance is specific to the technology of the LM-6000 and may not apply to dry-low emissions combustors, authors of a report on the test said.

Engine control was stable throughout the duration of the test. Combustion equipment was in good condition before, during and after the test; periodic borescope inspections found no apparent damage to the turbine due to hydrogen combustion.

Takeaway lessons from the tests included:

  • Maintain a stable hydrogen supply so the hydrogen system does not trip off; the manual hydrogen regulators at Brentwood required continuous monitoring and adjustment, which would not be practical in normal plant operations.
  • Ensure adequate natural gas supply pressure, which must increase as the hydrogen ratio increases. This proved to be a limiting factor on the percentage of hydrogen used in the test.
  • Allow sufficient time for concept review and permit exceptions. Hydrogen is not well-defined in National Fire Protection Association codes and standards, and securing permits needed to operate the Brentwood plant in an experimental mode took an extended time.
  • Adopt a collaborative design approach earlier on in the process. The large number of teams involved in the Brentwood project progressed with their work at different speeds, requiring rework to be done late in the process.

Many partners joined for the NYPA project:

  • GE assisted in building the hydrogen/natural gas blending system.
  • EPRI’s Low-Carbon Resources Initiative helped design the project and served as advisors on the technical evaluation.
  • Airgas supplied the renewable hydrogen for the testing.
  • Sargent & Lundy, the original architect engineer of the Brentwood plant, provided engineering expertise as well as safety reviews.
  • Fresh Meadow Power developed the piping system that delivered the hydrogen to the GE-designed mixing skid and into the turbine.

NYPA interim CEO Justin E. Driscoll said in a news release that this type of collaborative, multi-pronged approach is what is needed to advance the technology New York will rely on to meet its ambitious climate-protection goals: 70% renewable energy generation by 2030, 100% renewable by 2040 and an 85% reduction in greenhouse gas emissions in 2050 compared with 1990 levels.

Not all the technology needed to accomplish this exists in scalable or economically viable form. Green hydrogen — hydrogen generated through zero-emissions means — is just one of what will likely be many components of the strategy to reach the decarbonization goals set by New York and other governments.

“Today, NYPA is pleased to share the results of our hydrogen study with the industry and the public so that our key learnings can help illuminate future decarbonization efforts,” Driscoll said.

Eric Gray, CEO of GE Gas Power, said: “Efforts like the Green Hydrogen Demonstration Project are vital to validate the important role that hydrogen can play in lowering carbon emissions from power generation while also providing reliable and affordable power.”

The report on the demonstration project is offered for sale by EPRI here. The executive summary is available for free download here.

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Gas Plant Wins Temporary Injunction Against CEJA Emissions Rules

The owner of a large gas plant in Illinois has secured a temporary injunction against emissions-control provisions laid out in the state’s Climate and Equitable Jobs Act (CEJA).

J-Power USA’s 1,350-MW Elwood Power Plant is temporarily exempted from the Illinois Environmental Protection Agency’s (IEPA) enforcement of an annual emissions threshold under CEJA. In granting the mid-September injunction, Illinois’ 7th Judicial Circuit Court decided that enforcement of the pollutant cap predated the rules’ official implementation and J-Power didn’t have fair notice (2022-CH-50).

Sangamon County Judge Raylene Grischow ruled that if the IEPA were allowed to enforce emissions caps on Elwood beginning October 2021 as attempted, the plant would be forbidden from producing energy and J-Power would suffer irreparable harm. She said J-Power was unaware in 2021 that its operations would be monitored under a yet unreleased rule.

“The compliance rule is arbitrary and capricious because it demands compliance prior to IEPA’s announcement of how emissions caps were to be calculated. IEPA’s rule, issued in January 2022, declared that ‘any 12-month period’ meant a rolling, 12-month calculation, starting with the period October 2021 through September 2022. Prior to January 2022, energy producers did not have the necessary information to calculate their emissions caps or monitor their ongoing emissions for CEJA purposes,” Grischow wrote.

CEJA established emissions caps for investor-owned, gas-fired units with three years of operating history; those units must not annually exceed an average of their emissions from 2018 through 2020.

J-Power said that Elwood was “obligated to generate power at a higher-than-normal capacity” in the fall of 2021, before the IEPA issued the new emissions caps. The company claimed that by the time the agency announced a retroactive compliance period in January 2022, Elwood already used up more than 80% of its allotted run time for the year based on its emissions, with two of its nine units already maxed out.

After higher-than-normal deployments continued in the spring, J-Power predicted in early summer that Elwood would likely be vulnerable to noncompliance beginning in July. The plant stopped operating completely in September, and J-Power claims it has since lost millions of dollars.

The court said Illinois permitted a “significant implementation gap” and that the IEPA’s “retroactive application of its gap-filling rules” violates the due process clauses of both the U.S. and Illinois constitutions.

“Injunctive relief is necessary to safeguard the benefit Elwood provides to Illinois residents: the grid stability necessary to avoid and recover from blackouts and helping to control energy prices,” Grischow wrote. “If Elwood were to close due to a magnifying injury over the next few weeks, Elwood would no longer exist to operate when the grid needs it. Allowing Elwood to operate in the short term and provide electricity that the citizens of Illinois need is a reasonable and equitable measure.”

The temporary injunction isn’t a statement on the merits of CEJA’s emissions regulations, Grischow said, adding that it’s not the court’s function to answer that “ultimate question.” She also said the injunction is narrow and doesn’t stand to disrupt CEJA in the long run.

CEJA requires all fossil plants in Illinois to close by 2045.

The Illinois Clean Jobs Coalition said it wasn’t surprised that companies dealing in fossil fuel generation would challenge and try to “flout” the emissions limitations.

“The Climate and Equitable Jobs Act’s steady path to eliminating pollution from gas and coal plants is gradual, achievable, good for public health and essential to becoming a leader in the clean energy economy,” the group said in a statement. “We are confident the provisions will ultimately be upheld by the judicial system and thwart Elwood’s efforts to avoid compliance.”

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California PUC Proposes Aliso Canyon Endgame

The California Public Utilities Commission on Friday proposed replacing the state’s largest natural gas storage facility, Aliso Canyon, with a combination of non-gas-fired generation, building electrification, energy efficiency and storage.

The proposal accompanied a ruling in which the CPUC detailed its findings from the second phase of its investigation of Aliso Canyon, site of a massive methane leak in October 2015. The underground facility remains necessary for grid reliability and to serve gas customers in the Los Angeles Basin, the commission found.

“As California pursues its decarbonization goals, natural gas demand will decline over time,” it said. “Currently, however, millions of individuals and businesses continue to rely on natural gas for essential services. Given that flowing gas capacity alone is not sufficient to meet peak seasonal or hourly demand, natural gas storage at Aliso Canyon continues to be a key part of the state’s energy infrastructure.”

The commission’s ruling instructs the state’s major utilities, including Aliso Canyon owner Southern California Gas (NYSE:SRE), to provide input on how they would increase supply and reduce demand to allow the facility’s eventual closure. It poses a series of questions to the companies including, “What is the earliest reasonable time a portfolio can be adopted for reduction and elimination of California’s reliance on Aliso Canyon?”

The staff proposal said that to meet demand in 2027 without the facility, utilities would need to annually reduce peak gas demand by 214 MMcfd (about 4% of the peak total) or annually increase their non-gas generation by 1,084 MW of (2% of the state’s electric capacity) — or do a combination of both.

The facility’s fate has been controversial since a ruptured pipe at the SS-25 well poured more than 100,000 tons of natural gas into the air, leading to a blowout and sickening nearby residents. The leak was contained after four months in February 2016.

A few months later, Gov. Jerry Brown signed Senate Bill 380, which told the CPUC to determine “the feasibility of minimizing or eliminating the use of the Aliso Canyon natural gas storage facility … while still maintaining energy and reliability for the region.”

The facility reopened at a reduced capacity in July 2017, but last November the CPUC increased its storage limits by 7 Bcf amid concerns about winter gas supply.

“Our decision today helps ensure energy reliability for the Los Angeles Basin this winter in a safe and reliable manner,” former Commissioner Martha Guzman Aceves said at the time. “We continue to move forward on planning how to reduce or eliminate the use of Aliso Canyon, and to ultimately reduce our reliance entirely on such natural gas infrastructure as we transition to a clean energy economy.”

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IPP Gets Free Allowances Under Wash. Cap-and-trade Program

The non-utility owner of a Washington gas-fired power plant can receive an initial allocation of free cap-and-trade allowances from the state, a government board decided Tuesday.

Washington’s Energy Facility Site Evaluation Council (EFSEC) unanimously approved extending the allocation to the 620 MW Grays Harbor Energy Center, which is owned by independent power producer Invenergy. The council’s discussion was limited to tweaking the language of the approval document. 

The Grays Harbor plant is the only gas-fired facility in Washington that is not owned by a public utility, which means it did not receive the same no-cost carbon allowances granted to utility-owned power plants under the state’s new cap-and-trade program, which goes into effect on Jan. 1, 2023. Carbon emissions are calculated the same way for both utility- and non-utility-owned plants under the program.

The plant’s officials protested this discrepancy to the Washington Department of Ecology in June. “All the state’s power plants need to be on the same footing,” Grays Harbor Energy representative Torey Mielke said during a June 21 public hearing. (See Independent Power Producer Sees Risk from Wash. Cap-and-trade.)

Invenergy officials also expressed concern about their plant having to compete with out-of-state power producers that don’t have to spend money on the carbon-combating measures now required in Washington.

Under cap-and-trade, carbon emitters must acquire allowances for specific amounts of carbon dioxide pollution, which they can buy, sell or trade with other businesses. The maximum volume of statewide emissions would decrease over time.

The Ecology Department’s plan calls for an undetermined number of emissions allowances to be auctioned four times a year to smokestack industries. The first two auctions are scheduled for the first half of 2023, and the state will set the number of allowances 60 days prior to the auctions.

Companies would bid on the allowances in clusters of 1,000 individual allowances. The number of allowances will be decreased over time to meet 2035 and 2050 decarbonization goals. If Washington chooses to join the Western Climate Initiative, which includes California and Quebec, participants would expand their purchase and trading territory to those two areas.

For each auction, a specific number of allowances would be made available to bidders. All bids must be above a certain price level set in advance by the state. The highest bidder would get first crack at the limited number of allowances, while the second highest bidder would get the second crack, followed by additional iterations. The auction ends when the last of the designated number of allowances is bid upon. Then all the successful bidders pay the same clearing price set by the lowest successful bid.

Bidding companies are limited to acquiring 4-10% of the total number of allowances, depending on various criteria.

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FERC Revokes Tri-State’s Market-based Rate Authority in WACM

FERC last week revoked Tri-State Generation and Transmission Association’s market-based rate authority in the Western Area Power Administration’s Colorado-Missouri balancing authority area (WACM), but it found the cooperative may retain that authority in other BAAs (ER20-681, EL22-28).

The commission said information provided by Tri-State “failed to rebut the presumption of market power” in WACM. “As a result, we find that it is not just and reasonable for Tri-State to continue to have market-based rate authority in the WACM balancing authority area,” it said.

The data showed consistent screen failures across measurements, season/load periods and price sensitivities in the BAA, FERC said. It directed the cooperative to submit within 30 days a revised market-based rate tariff limiting sales at market-based rates to areas outside of WACM in which it retains MBRA.

The commission also ordered Tri-State to respond with a separate tariff to provide for the default cost-based rates in WACM or to make clear its intent to use its current cost-based tariff on file.

FERC opened an investigation into Tri-State under Federal Power Act Section 206 after it submitted its triennial updated market power analysis and a change-in-status notice last December.

The commission allows power sales at market-based rates if the seller and its affiliates do not have, or have adequately mitigated, horizontal and vertical market power. An applicant that fails one or more of the indicative screens is provided with several procedural options, including the right to challenge the market power presumption by submitting a delivered price test (DPT). However, the revised DPT indicated the consistent screen failures.

FERC did find that Tri-State passed the horizontal market power indicative screens for the Public Service Company of New Mexico and Public Service Company of Colorado BAAs and CAISO’s Western Energy Imbalance Market.

Commission Rejects SPP Tariff Revision, Reversing ALJ Decision

The commission on Thursday also rejected SPP’s proposed tariff revision to include an annual transmission revenue requirement (ATRR) for certain GridLiance High Plains facilities in Oklahoma’s Panhandle, affirming in part and reversing in part a decision by an administrative law judge in hearing and settlement procedures (ER18-2358).

FERC said that SPP’s 2018 filing to revise the tariff and allow recovery of the ATRR for GridLiance’s facilities was unable to prove the change was just and reasonable. It said that in protesting the filing, Xcel Energy Services (NASDAQ:XEL) was able to show “adequate evidence” that the facilities should be declassified as transmission under the commission’s seven-factor test.

GridLiance-Sub-in-Winfield-(GridLiance)-FI.jpgFERC rules GridLiance’s Oklahoma facilities do not qualify for rate recovery. | GridLiance

Xcel also said GridLiance’s inclusion of its Oklahoma Panhandle facilities in its ATRR would result in a cost-shift to its Southwestern Public Service subsidiary, which shares the same transmission pricing zone (Zone 11). (See GridLiance, Xcel Battle over Tx Qualifications.)

The commission reversed an ALJ decision last year that the transmission facilities were eligible for recovery in transmission rates under SPP’s tariff. FERC directed GridLiance and SPP to issue refunds within 45 days to customers in GridLiance’s ATRR in Zone 11.

“We find, among other things, that … SPP and GridLiance failed to meet their burden to prove by a preponderance of the evidence that the GridLiance facilities are transmission facilities eligible for recovery,” the commissioners wrote.

FERC said that because it resolved the case’s central issue, it did not reach the merits of the rate impact, cost causation, prudent decision-making, and other arguments raised by Xcel and other intervenors.

The commission also dismissed a pair of Xcel’s formal challenges to GridLiance’s 2021 and 2022 annual formula rate updates as moot, citing the 2021 order over Xcel’s previous informal contention that GridLiance’s inclusion of the Oklahoma assets’ costs in its updates was improper (ER21-1438, ER22-1353).

It said that given the decision in the earlier proceeding and GridLiance’s implementation of the Zone 11 ATRR in the 2021 and 2022 annual updates, Xcel’s formal challenges were moot.

Just Energy OK’d for MBRA

FERC also granted power marketer Just Energy’s authority to make wholesale sales of energy and capacity at market-based rates and found it met the criteria to be a Category 1 seller in all regions (ER22-2044, ER22-2044-001).

The commission determined that because Just Energy does not own or control generation or transmission facilities, it satisfies FERC’s requirements for market-based rates regarding horizontal and vertical market power.

The ruling allows Just Energy to supply retail power in competitive markets, as one affiliate already does in ERCOT. It will contract with third parties to procure supply for its other affiliates and to provide them scheduling, settlement and bid/offer submission services once it registers with grid operators.

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MISO Adding Availability-based Renewable Energy Accreditation

MISO continues to suss out a new availability-based capacity accreditation method for renewable generation, despite some stakeholders’ qualms with the early design.

The grid operator held a workshop Wednesday to dissect its proposed methodology for wind and solar resources. It will dole out capacity credit based on a unit’s availability during times of system need.

Jordan Bakke, MISO’s director of policy studies, said the goal is to fit renewable-resource accreditation into the “mold” of thermal units’ recently approved availability-based accreditation. He said MISO must make some assumption adjustments for a “different resource type with different characteristics.”

The RTO is creating “different swim lanes” between thermal, renewable and load-modifying resources, Bakke said.  

The grid operator will use a modified effective load carrying capability (ELCC) calculation for renewable resources, then adjust those values for availability based on what it calls “resource adequacy hours,” or historical hours over a year that contain tight supplies and reliability risks.

MISO introduced the concept of resource adequacy hours when it overhauled its ELCC for thermal resources. They represent the top 3%, or 65, riskiest hours per three-month season and include the hours spent in maximum generation events. (See FERC OKs MISO Seasonal Auction, Accreditation.)

“Our bias is to remain somewhat close to what we filed at FERC” for thermal units, MISO planning adviser Davey Lopez said.

Bakke said ELCC is a “comparable method” when compared to thermal generation’s unforced capacity calculation (UCAP).

Clean Grid Alliance’s Natalie McIntire said she didn’t see how the calculations are comparable because UCAP relies on units’ forced outage rates but ELCC doesn’t.

Bakke said the divergence is necessary because wind and solar performance contain a lot of “availability variability” during tight operating periods. On the other hand, thermal output is steadier.

“The performance is much more uniform over time,” he explained.

Bakke said PJM and ISO-NE have made similar arguments to FERC when getting their renewable capacity accreditation designs approved. He said MISO could pursue a more complex calculation only to end up with a “comparable outcome” to the simpler ELCC method. He said MISO isn’t convinced that more labor-intensive number crunching would be worth the effort.

MISO plans on tweaking its current ELCC computation to apply to its ever-expanding renewable fleet.

Renewable energy accreditation will move from being derived using an individual, unit-level ELCC based on peak hour contribution to a resource portfolio-based standard ELCC that will be applied to a unit’s availability during pre-defined resource adequacy hours. Staff said they will create separate portfolio-level ELCCs for wind and solar generation and said they might adjust those based on whether units are located in MISO Midwest or MISO South.

Some stakeholders called the proposed ELCC method difficult to understand. Others said using a fleet-based average is too broad to apply to diverse wind units and will condemn renewable generators to lower capacity values.

Bakke said the portfolio-wide ELCC is “not a wholesale change” but necessary for MISO to have sustainable and consistent renewable accreditation moving forward.

Whether the ELCC should remain an average of unit performance across the portfolio or a become a marginal value, reflecting the capacity value of the most recent renewables additions, remains an open question.

MISO Independent Market Monitor David Patton advocated for a marginal value because he said renewable capacity contributions become less valuable from a reliability perspective as more are added.

“Every conceivable loss of load risk compounds when the wind isn’t blowing; therefore, building more wind at the margins is futile,” Patton explained. “You need more and more capacity for every megawatt you build of an already saturated technology.”

MISO hasn’t yet settled on a marginal versus average approach.

The renewable accreditation won’t cover battery storage or hybrid resources that pair a renewable energy resource with a storage facility. Bakke said MISO wanted to tackle the large amounts of wind, solar and load-modifying resources first before evaluating next year the accreditation of the “more emergent” resource types.

The grid operator has proposed using historical availability data collected from its existing demand-side resource interface to accredit LMRs. It said its control room operators “see a significant reduction in LMR availability when compared to what clears in the PRA.”

Stakeholders have asked MISO to compare the amount of LMRs’ load reduction that is weather dependent during the workday with weekend dependent.

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MISO Considers Resource Attributes as Thermal Output Falls

As its on-demand, dispatchable resources shrink, MISO held its first stakeholder discussion on how it can better value generators’ services to the grid.

Senior Vice President Todd Ramey said the RTO is experiencing firsthand the global push to cut greenhouse gas emissions.

“We’re seeing a very similar story, interest in decarbonization, which in the power sector is a very tall ask,” he said during the Wednesday workshop.

Ramey said MISO is changing the way it thinks about power system operations as it grapples with a more decarbonized fleet. He said units that can ramp up or down on MISO instructions are in short supply.

MISO is expecting a 40% renewable energy penetration by the end of the decade.

Ramey said planning reserve margins “have all but disappeared at this point.” He said this is occurring against a backdrop of increasingly severe and unstable weather and electrification’s growing demand.

“Reserve margins might be set daily on what our risk posture is,” Ramey said. “Planning to get through a worst week is really not something the electric industry has focused on until recently.”

During the workshop, MISO proposed a handful of essential reliability attributes for resources that included black start, rapid start up, ramp up and down capability, sustained high output, voltage stability, and fuel assurance.

Zakaria Joundi, director of resource adequacy coordination, said the grid operator is attempting to figure out how much of each attribute it should maintain in its resource portfolio. He invited stakeholders to suggest other essential attributes staff need to consider.

If an aggressive resource transition plays out in the footprint over the next 20 years, Joundi said MISO will need about 366 GW worth of installed capacity on hand to maintain a one-day-in-10-years reliability standard. More than 83 GW of that would have to be capable of providing output for several days in a row.

The RTO also thinks it will require 5 GW of resources capable of ramping up within 10 minutes and 28 GW that can ramp up within an hour.

“Based on public plans that are out there, we feel that we may fall short on these attributes,” Joundi said

Jordan Bakke, director of policy studies, said staff isn’t presupposing an answer on attributes. He said MISO is asking stakeholders what “signals, requirements and facilities” it might need to improve the short-term operational horizon and its long-term resource adequacy.

“First we need to understand what attributes of resources are becoming at risk of being scarce,” he said.

Michelle Bloodworth, CEO of coal lobbying group America’s Power, asked that MISO extend attribute incentives to its current portfolio so that more thermal units don’t retire prematurely. She said a focus on the fleet’s existing attributes will ensure the RTO “doesn’t throw out the old with the new.”

“I think some utilities are making decisions based on political and environmental pressure rather than reliability and logic,” MidAmerican Energy’s Dennis Kimm said. He said utilities’ planning processes don’t include voltage stability and regulation, and they might benefit from MISO telling them which attributes to focus on.

Joundi said the attributes discussion will be “one of many” MISO plans to hold.

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SERC Board of Directors Briefs: Sept. 22, 2022

Blake Praises SERC Entities’ Summer Performance

Jason Blake 2022-09-22 (RTO Insider LLC) FI.jpgJason Blake, president and CEO of SERC | © RTO Insider LLC

CHARLOTTE, N.C. — At Thursday’s meeting of SERC Reliability’s Board of Directors, CEO Jason Blake — reflecting on the fact that it was the first day of fall — reminded attendees “to celebrate our successes” in maintaining grid reliability during a challenging summer.

“I think sometimes within this industry we’re really good at focusing on where we fall short and wanting to take lessons learned,” Blake said. “But if you look at this summer, it was a hard one. We had seasonal peaks coming in earlier than ever, and occurring more frequently: extreme heat, extreme weather generally, whether it be extreme flooding [or] tornadoes. … And the thing I’d really like to take note of is the way the operators in our footprint generally have performed throughout the season. I think it’s been very laudable what they [have] achieved.”

Blake also reminded board members — and those attending virtually — that the challenges facing the grid from the growing adoption of renewable energy, the effects of climate change, electrification of transport and other trends “are not lessening.” He said that SERC and the rest of the ERO Enterprise have an important role to play in educating regulators and policymakers on the relevant issues.

NERC CEO Jim Robb has been instrumental in helping organization the leadership of the regional entities to advance these goals, Blake said, citing a “truly unprecedented” amount of “information and dialogue in this space” over the last year through the ERO Executive Committee, a gathering of the CEOs from each RE to discuss high-level reliability issues. Blake told attendees how SERC has worked to expand this engagement by hosting more meetings for lower-level staff from other REs to discuss the problems they face every day.

“The key point to take away there is that there’s alignment; there’s an understanding. We understand the broader picture, and we’ve had a strong voice,” Blake said. “I can tell you with great appreciation that the SERC team has been actively engaged in these discussions and really coming up with some awesome ideas to help advance the broader ERO Enterprise. So that alignment is key to our success — we need a strong NERC, just like NERC needs a very strong SERC to be successful.”

More Independent Directors a Possibility

SERC’s Nominating and Governance Committee is preparing to begin the process that could lead to a search for new independent directors, Chair Tim Lyons told directors on Thursday. The three independent directors currently serving on the board — Shirley Bloomfield, Lonni Dieck and Deborah Wheeler — are SERC’s first, having joined in 2021 after the RE implemented new bylaws in 2020 that required at least three, and no more than five, independent directors. (See SERC Appoints 1st Independent Board Members.)

Lyons said the committee is currently considering “whether … we are lacking skillsets on the board” that a fresh director could add. Areas of expertise that could be sought by the committee include the natural gas system, battery technology and human resources, along with “various other topics.”

The committee will first develop surveys — one for “stakeholder directors,” one for the current independent directors, and one for SERC’s leadership team — to determine the organization’s views on what skills might be needed. Lyons said the surveys should be sent out within the next six weeks, which would ensure enough time for respondents to return them and for results to be available by the next board meeting in December.

Board Chair Todd Hillman called for a “robust discussion” during the selection process for new directors, which Lyons said would likely take more than a year.

“As you all know, we [won] the lottery with our first set of independent directors,” Hillman said. “We want to continue to have the level of quality, insight and experience, and so we want to go into that conversation knowing full well that that quality is going to stay high.”

Strategic Plan Approved

The sole approval item at Thursday’s meeting was SERC’s long-term strategic plan, which the organization created to outline its contribution to fulfilling the goals of the ERO Enterprise Long-term Strategy. Members voted unanimously to approve the document.

The plan identified three key focus areas, according to which SERC should strive to be a:

  • credible and trusted expert organization;
  • leader in reliability and security across the industry; and
  • highly desirable place to work for all.

Jeni Belew, a senior program manager for strategic development at SERC who introduced the strategic plan, explained that to support the first area, the RE will “provide growth and development opportunities so that our talent is equipped to tackle the challenges facing the evolving electric grid,” along with “gold standard training opportunities [including] continuing education hours” and other credits that can encourage industry stakeholders to see SERC as a valuable source of expertise.

Brian Thumm Jeni Belew 2022-09-22 (RTO Insider LLC) Alt FI.jpgSERC’s Brian Thumm and Jeni Belew presenting the organization’s strategic plan. | © RTO Insider LLC

 

Belew explained that the second area requires building out SERC’s communications ability so that, as policymakers, regulators and other stakeholders learn of its expertise, it can deliver the information they need. To become a desirable place to work, the organization will “continue focusing on our culture and environment … to prioritize diversity, equity, inclusion and allyship … so that everyone finds purpose and value in the work that they do.”

SERC’s next board meeting is scheduled for Dec. 14 in Charlotte.

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FERC Seeking Solutions for New England Winter Reliability

WASHINGTON — FERC’s members opened their monthly meeting Thursday by soliciting feedback on their forum with New England stakeholders on the region’s winter fuel security problems, once again highlighting the philosophical divide along party lines among the commissioners.

All agreed that the situation in New England is urgent, and any extreme weather this winter could result in a loss in electric reliability.

But Republican Commissioners James Danly and Mark Christie were more pessimistic, going so far as to suggest that the role of RTOs in general in ensuring resource adequacy should come to an end.

FERC had the previous day issued a notice in the forum’s docket seeking comment on the issues discussed (AD22-9). Comments are due Nov. 7. (See FERC Comes to Vermont and Leaves with a New England-sized Headache.)

Each of the commissioners urged stakeholders to submit suggestions in the docket on what the commission should do about New England.

Chairman Richard Glick noted that the region is “still heavily reliant on LNG imports, and that’s just not sustainable. In the short term it might be necessary to continue that reliance, but in the long term, it’s just not sustainable.” He noted other “opportunities” to maintain resource adequacy, including more transmission and the coming offshore wind farms.

He also said ISO-NE needs to consider market changes, such as a seasonal capacity construct “to incentivize generators to make arrangements to provide more assurance that there’s going to be fuel supply when it’s needed on the coldest days of the year.”

But Danly reiterated his view, expressed at the forum, that “the situation is bad enough, both in terms of the actual fact of reliability challenges on the one hand and, second, the fact that there is no conceivable way to me that a capacity market can have rates that are J&R [just and reasonable] if the capacity market doesn’t actually deliver the promise of the resources that are to be drawn upon when necessary down the road.”

FERC Protest Sign 2022-09-22 (RTO Insider LLC) Alt FI.jpgThis sign greeted those visiting FERC for the open meeting Sept. 22, the day after Sen. Joe Manchin unveiled the text of legislation that would, among other things, approve the Mountain Valley natural gas pipeline. The meeting itself was interrupted by four protesters, including one who began singing “More Waters Rising” by Saro Lynch-Thomason. | © RTO Insider LLC

 

He recalled that ISO-NE CEO Gordon van Welie had pushed back on his suggestion that FERC should institute a proceeding under Federal Power Act Section 206 to remove their responsibility over resource adequacy and return it to the states. He said he understood that the RTO would not want “a free-wheeling 206 in which we say, ‘You have a problem; go fix it.’”

But “I think we have an unjust and unreasonable market, probably; obviously that would be what the 206 hearing would be for.”

Danly also lamented a recent ruling by the D.C. Circuit Court of Appeals that found ISO-NE’s Inventoried Energy Program, to go into effect for winter 2023, to be unjust because it would unfairly pay nuclear, coal, biomass and hydroelectric resources for fuel storage (ER19-1428-005). (See Court Strikes a Blow to ISO-NE Winter Plan.) The court left the rest of the IEP in place, allowing the RTO to compensate oil, natural gas and refuse generators.

FERC on Thursday issued an order on remand implementing the D.C. Circuit ruling. (The order had not been published as of press time.) “I’m concurring because the court has spoken, and we will do what the court says,” Danly said. “But that got rid of, effectively, one of the possible solutions to the fuel security problem this winter, and I am quite sorry that we’re in a position where … the strategy to get through this winter is to cross our fingers and hope for mild weather. That is not a good plan. …

“If anybody can come up with a short-term fix that would help with fuel assurance this winter, I for one would solicit a 206 filing,” Danly said.

Speaking about a different ruling involving NYISO, Danly also argued that “when you consider how this experiment in markets began, that we were going to use the markets to deliver the least-cost energy generation for the region in which they operate … it’s becoming harder and harder to believe in the premise upon which these markets were originally developed as we have greater and greater price suppression through state subsidies.

“It is getting to the point where I believe that these markets are so manifestly not J&R, given the price warpings, that it is difficult for me not to consider abandoning the entire experiment as long as it’s being conducted this poorly.”

Gradually, Then Suddenly

“I didn’t hear the perspective that markets cannot work, but I certainly share the perspective that at this moment, the markets may not be delivering just and reasonable rates,” Commissioner Allison Clements said. “To me, exerting commission leadership to move this ball forward does not suggest that we know better than the New England states, or that we have the right to override the states’ perspectives. Nor does it suggest that the entire solution set rests in the commission’s jurisdiction.”

She noted that ISO-NE had proposed undertaking a comprehensive study of the problem and potential solutions, with a number of state officials at the forum concurring.

“I, though, did not come away with a level of specificity around what this study should actually look like,” she said. “We know that the root of New England’s winter electric system reliability challenge is the significant dependence on natural gas in these extreme conditions, along with gas supply constraints. Shoring up or adding more natural gas supply capability is one way to address these constraints, [but] it is only one way. The region can also diversify away from reliance on natural gas for electric generation and can reduce both electric and gas demand.”

“When it comes to RTO markets … whether they’re still providing reliability and, more importantly, whether they’re providing it at just and reasonable rates, I think is a serious question,” Commissioner Christie said.

He quoted “The Sun Also Rises” by Ernest Hemingway, in which a character asks another how he went bankrupt. He answers “gradually, and then suddenly.”

“I think [RTOs are] moving from the ‘gradually’ phase to the ‘suddenly’ phase, and I think we’re going to have to grapple with that as we look at the future.”

“I want to hear from people [about] what more can FERC do, both under our FPA authority” and its ability to facilitate discussions, Commissioner Willie Phillips said. “Will additional meetings help? Could we establish a task force? Is there another forum that FERC could use to help bring people to the table? I’m very interested in that.”

On the other side of the extreme weather spectrum, Chairman Glick also complimented CAISO for getting through a weeklong, record-breaking heat wave earlier this month. (See California Runs on Fumes but Avoids Blackouts.)

“California ISO had a number of challenges and did an amazing job of getting through it without having to engage in rolling blackouts.” He reported that, based on a conversation with the ISO last week, the state’s energy storage resources performed very well and were key to maintaining reliability. He also highlighted demand response and California’s ability to import power.

But Commissioner Danly responded: “It is true that various resources played a part, especially on the margins, in keeping the system operating, but a clear-eyed, accurate assessment — if we actually look at where the power came from, natural gas is the reason those lights stayed on. That is the simple fact of the matter.”

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DOE Opens Solicitation for $7B in Hydrogen Hubs Funding

The Department of Energy Thursday announced the opening of applications for $7 billion in funding for six to 10 clean hydrogen hubs.

“These hubs are going to be located in different regions all across the country,” Energy Secretary Jennifer Granholm said in announcing the solicitation at the Global Clean Energy Action Forum in Pittsburgh. “They’re going to use a variety of feedstocks — abated fossil fuel, renewables, nuclear — and they’ll focus on different end uses, for example, electricity generation, industrial production, residential, commercial heating [and] transportation.”

Funded by the Infrastructure Investment and Jobs Act, the “H2Hubs” will be one of the largest investments in DOE’s history, the agency said. It will be managed by DOE’s Office of Clean Energy Demonstrations with support from the Office of Energy Efficiency and Renewable Energy.

Concept papers are due by Nov. 7, with the deadline for full applications set for April 7, 2023.

Funded projects must include a “community benefits plan” to support disadvantaged communities, workforce development and diversity goals.

Demands for hydrogen (DOE) Content.jpgCurrent and emerging demands for hydrogen | DOE

Along with the solicitation, DOE also released its National Clean Hydrogen Strategy and Roadmap for public comment.

The report is the next step in the Hydrogen Energy Earthshot announced in June 2021, which set a goal of reducing the cost of clean hydrogen by 80% to $1/kilogram within a decade.

Granholm said the document projects “that by 2030, that our country’s clean hydrogen market might be twice as large as we projected originally: 10 million metric tons [MMT] by 2030, 20 million by 2040 and 50 million metric tons by 2050.”

The U.S. currently produces about 10 MMT of hydrogen per year — mostly for the petroleum refining, ammonia and chemicals — but that production generates greenhouse gases.

The report says clean hydrogen could reduce U.S. emissions by 10% by 2050 relative to 2005 levels, “based on achieving cost competitiveness to enable demand in specific sectors and where there are fewer alternatives, such as direct electrification or the use of biofuels.”

“Specific markets include the industrial sector, heavy-duty transportation and long-duration energy storage to enable a clean grid,” the road map says. “Long-term opportunities include the potential for exporting clean hydrogen or hydrogen carriers and enabling energy security for our allies.”