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November 5, 2024

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NYISO Stakeholders Debate Proposed Interconnection Queue Overhaul

ALBANY, N.Y. — NYISO stakeholders discussed the merits and pitfalls of the ISO’s proposed phased window approach to fundamentally rework its interconnection study processes after it was presented in greater detail during the Transmission Planning Advisory Subcommittee’s meeting April 19.

After studying how to expedite its interconnection queue, which has experienced project backlogs and delays since New York passed the Climate Leadership and Community Protection Act in 2019, NYISO recently settled on a three-stage approach that would stack a group of overlapping projects into a queue window. (See NYISO Previews Plan to Expedite Interconnection Queue.)

Stakeholders were mostly receptive but still had many concerns about the proposal, including about its timelines and scheduling; penalties for leaving the queue; and whether certain studies in one phase might be more appropriate elsewhere.

NYISO will take stakeholder feedback from last week’s meeting and address them at the subcommittee’s next meeting on May 5.

Application Review Period

Thinh Nguyen, NYISO senior manager of interconnection projects, summarized the proposal.

“The queue window leverages all the class year processes,” but instead of performing studies at the end, after developers have made significant financial commitments, “it puts all the analyses upfront to be done together so developers can make more informed decisions,” Nguyen said.

Therefore, the critical first step in the queue window would be the application review period. This “pre-act” review would serve as a “project filter,” said Nguyen, because during this time, developers would submit site-control requirements and application fees, undergo initial modeling demonstrations and create their base cases, which are the starting points for any interconnection study, showing much about a project’s feasibility.

Interconnection queue window (NYISO) Content.jpgProposed structure of the interconnection queue window approach (*boxes not at scale*) | NYISO

 

The idea is to enable developers to make important decisions about whether they want to enter or exit the queue without either facing withdrawal penalties or disrupting other potential projects in the queue window. Nguyen also said that the intention of this period is to validate a certain project application’s worthiness and if it can be considered in the interconnection study.

After submitting all required application materials and a nonrefundable application fee, developers would be able to submit a study deposit if they decide they want to proceed into the queue window.

Phase 1

“Phase 1 is similar to late-stage [Class Year] optional physical feasibility studies but is a more limited clustered study, rather than the individual studies as done today,” Nguyen said.

During this period, NYISO would review project design requirements provided by developers to determine a project’s feasibility, such as if existing infrastructure can physically accommodate the project or if it has environmental issues.

This would allow developers with projects identified by NYISO as having potential feasibility issues to decide whether they want to study this issue further or if it is enough to dissuade them from moving on.

Nguyen said Phase 1 “lets developers know if they may run into some problems,” so that they can decide to either exit the queue entirely or rejoin later in another window “without delaying other projects.”

Should a developer withdraw their project in Phase 1, NYISO would refund them 80% of the study deposit, though projects that move forward to Phase 2 and then decide to withdraw would forfeit the entire deposit.

At the end of this period, NYISO would publicly publish every developer’s decision so that others can understand how a given queue window or project could be affected.

Phase 2

Projects that pass Phase 1 feasibility requirements and posted relevant deposits would enter Phase 2, which is “almost like the system impact reliability study but with a twist,” said Nguyen.

Phase 2 would create binding cost estimates that are based on identified equipment and work upgrades necessary to interconnect a proposed project, which is unlike current processes that produce a nonbinding cost estimate.

Nguyen said Phase 2 is “tailored” to gives developers a “heads-up about some of their potential system upgrades that would be beyond the POI [point of interconnection].”

“This could be a step where we can streamline a lot of processes that we have today,” he said.

During Phase 2 the queue’s base cases would also be updated to reflect projects that were either rejected or withdrew during Phase 1 and the ISO performs limited analyses, such as short circuit, localized stability and screening deliverability analyses to generate useful information that reduces Phase 3 study times.

Developers who accept Phase 2’s results and project binding cost estimates would be required to post a project’s dollars-per-megawatt cash deposit before moving to Phase 3. Projects withdrawn during Phase 3 would see 25% of the cash deposit forfeited.

Like Phase 1, project decisions made in Phase 2 would be posted publicly by NYISO.

Phase 3

“Phase 3 is basically the final study for developers to know the certainty of their cost allocations,” Nguyen said.

During Phase 3, NYISO would update relevant base cases to reflect any projects that withdrew and perform any additional analyses needed to determine a project’s final cost allocation based on potential upgrades identified by the ISO.

Doreen Saia, an attorney with Greenberg Traurig, sought clarification, asking whether “Phase 3 is essentially becoming an additional deliverability study and additional SUF [system upgrade facility] study,” which Nguyen confirmed as correct.

Nguyen explained that the structure of NYISO’s proposal intentionally stacks projects together into a single queue window and staggers their study processes to “minimize the potential restudy or interaction between projects as much as possible.” This means, for example, a project might not commence Phase 3 studies until another project finishes its processes in the same window.

“The idea is that subsequent queue window projects will be able to consider upgrades identified in prior queue window projects,” which makes the queue “more manageable, because subsequent projects will know exactly who the group of projects prior to them are and what decisions they have to make,” he said.

Nguyen said that NYISO’s proposed “concept is much better than what we have today because when we studied projects individually, they had no idea what going on with other Class Year members … creating more uncertainty for those project developers.”

A developer who accepts their Phase 3 cost allocations would be required to post security for any system deliverability or facility upgrades necessary for interconnection to complete the queue window study process.

The Phase 3 decision-making period, like the end of the Class Year process, would be an iterative process that repeats until every queue window project member either accepts or rejects their cost allocations.

Stakeholder Comments

Stakeholders shared many concerns, both specific and general, about NYISO’s proposed revisions during last week’s meeting.

Several stakeholders commented that the proposed penalties incurred by developers withdrawing from the queue window may be overly burdensome, prohibitive and unequal, as bigger projects may be susceptible to higher fines than smaller ones. Some singled out the 20% for a Phase 1 departure as too high.

NYISO attorney Sara Keegan, however, said the amount is “consistent with other ISOs,” with SPP taking 20% from projects leaving at the end of its Phase 1 study. Nguyen said this is “a penalty that deters projects that are just not ready yet.”

Mark Reeder, representing the Alliance for Clean Energy New York, concurred, saying how he saw the 20% forfeiture “as the penalty for those starting and not being ready,” which to him seemed good because “we don’t want a lot of people jumping in and then out [of the queue] without a good reason.”

Vitaly Spitsa of Consolidated Edison asked what deliverables would come out of Phase 2 and whether, by this point in the process, developers would have access to sufficient information to make critical decisions about moving ahead in the queue.

Nguyen said that by the end of Phase 2, “developers will know exactly what the potential cost is of their binding POI” and about any necessary upgrades, which “definitely isn’t all the information but is sufficient information for a developer to make a decision about whether they want to move to the next phase.”

Anthony Abate, lead energy market adviser with the New York Power Authority, said NYISO’s illustrations of its queue window were “deceptively simple” and that “the devil’s in the details,” referencing how lengthy discussions during the meeting show that stakeholders need more information about the structure and timeline of the proposal.

Although much of the meeting was spent answering stakeholder questions or addressing comments of concern, some attendees expressed optimism about the ISO’s proposal.

Shane O’Brien, senior director with Aypa Power, said “from the developer’s side, this is a step in the right direction,” because NYISO’s proposal addresses “administrative inefficiencies” and “those downtime wait periods” where developers may be waiting for others before they can make their own decisions.

However, a remark by Saia seemed to best capture the sentiment among the stakeholders present at the meeting.

In reference to how NYISO’s proposal would remove much of the Class Year studies, such as the system impact reliability study or siting and permitting processes, Saia said, “We must make sure that whatever we do in this new process, [former] processes align, because if they don’t, then it’s great that you fixed this, but it’s going to create discordance somewhere else that causes the whole thing to die under its own weight.

“NYISO needs to indicate that you acknowledge and recognize [these concerns] because I don’t think you’re going to be able to get any real signoff on this without those assurances,” she said.

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EPA Reportedly Soon to Release Rule on Power Plant CO2 Limits

EPA is reportedly poised to propose rules that would require all coal and gas-fired power plants to reduce or capture nearly all of their carbon dioxide emissions by 2040.

The New York Times reported Saturday that EPA plans to release a rule that for the first time would set limits on carbon dioxide emissions from existing power plants.

The pollution limits would not be technology specific, allowing natural gas plants to either capture their carbon, or switch to “green” hydrogen that is produced without carbon emissions, according a report in the Times that was largely confirmed by The Washington Post.

While carbon capture has proven expensive on power plants, recent federal legislation, including the Infrastructure Investment and Jobs Act and the Inflation Reduction Act, have set up a comprehensive framework that should enable the wide-scale deployment of carbon capture by 2030, the Carbon Capture Coalition said Monday in releasing its 2023 Federal Policy Blueprint.

The IRA increased federal tax credits for electric utilities that capture their carbon dioxide from $30 to $50/ton of CO2 to $85 to $135.

At a press event announcing the blueprint Monday, the coalition’s Executive Director Jessie Stolark said its wide-ranging membership has not had a chance to coordinate a response to the reported regulations yet. The group has focused mainly on market-incentives to encourage carbon capture technology, she added.

“I really want to underscore that our members agree that deploying carbon capture technologies in the power sector is absolutely critical to reducing emissions, as well as providing a more affordable, reliable baseload power and a deeply decarbonized energy grid,” Stolark said.

Shannon Heyck-Williams, vice president of climate and energy for the National Wildlife Fund, who participated in the coalition event, said her group welcomed news of EPA’s plans.

“WF is very excited to see this rule come out,” she said, saying CCS technology could have a role to play with some natural gas plants. “Obviously, we can’t adequately tackle climate change unless we’re really dramatically reducing power sector CO2 emissions. And, frankly, we could get to zero. That’s the goal.”

In response to EPA’s request last year for comments on how it should handle emissions from “electric generating units,” the Edison Electric Institute spelled out a way that it said could encourage cuts without mandating specific technologies.

EEI noted that for now the main way to cut emissions from power plants is to make them more efficient, with both hydrogen and carbon capture technologies not quite ready for mass deployment.

“Both hydrogen co-firing and CCS technology face a number of other challenges that will need to be overcome to enable commercial scale use throughout the industry,” EEI said. “Government and industry are investing in addressing these cost, technology, and infrastructure challenges. With that investment, there is reason to be optimistic that these challenges will be overcome in this decade.”

EEI argued that any new rules should be flexible, saying that hydrogen and carbon capture might work in some regions of the country but be infeasible in others. The agency should allow new power plants to retrofit those technologies when they become viable.

EEI also suggested that the agency would benefit from shifting to mass-based tonnage requirements for regulated units. Previous emissions rules have used a rate-based system.

“Since decreases in (or limits of) a unit’s capacity factor have a direct impact on its CO2 emissions profile, states, EPA, and units can employ a mass-based approach to leverage the emissions reductions benefits of a decrease in capacity factors, while preserving maximum operational flexibility to support overall system reliability by preserving the availability of units for resource adequacy, particularly during extreme weather events or other emergency conditions,” EEI said.

“We’ve got to go with a scale, we’ve got to go with the pace like never before,” U.S. Deputy Secretary of Energy David Turk said at the coalition’s webinar Monday. “My former colleagues at the [International Energy Agency] projected that by 2030, we’ll need to lock away roughly 30 times as much carbon as we’re currently managing, and nearly quintuple that by the middle of the century.”

DOE has made $10 billion available for a suite of carbon management applications, including the recent request for six demonstration projects at coal and natural gas plants, he added. DOE is also working with the Treasury Department to finalize the expanded 45 Q tax credit for carbon capture, said Turk.

EPA’s power plant rules would not be finalized until next year, following a public comment period. The Biden administration hopes to complete the regulations before Republicans could upend them by winning control of Congress in 2024. The Congressional Review Act allows a new Congress to reject regulations finalized within 60 days of the previous Congress.

The administration also is attempting to craft the rules to withstand certain court challenges.

The Supreme Court ruled last June that the Obama administration’s EPA failed to provide “clear congressional authorization” for its Clean Power Plan, which would have compelled generation shifting to reduce carbon emissions from coal-fired power plants. (See Supreme Court Rejects EPA Generation Shifting.)

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NYISO Study to Examine Future Winter Security Risks

An upcoming fuel and energy security study will examine the combined impacts of electricity generation trends and extended cold snaps on NYISO’s system reliability, the Analysis Group (AG) told the ISO’s Installed Capacity Working Group/Market Issues Working Group (ICAP/MIWG) on Friday.  

The main thrust of the study is to identify circumstances under which available resources will be insufficient to meet both load and required reserves before emergency actions as the New York grid transitions to a greater dependence on renewable resources.

For the near-term, the study will assume NYISO’s continued reliance on fossil fuel-fired generation, followed by increasing reliance on weather-dependent and variable resources over the long term. Within that context, it will examine 17-day cold periods in winter 2023/24 and two other future winters.

AG plans to use historical weather and load data, literature reviews of other RTOs, projected resource demand and supply forecasts, and assumed worst-case scenarios to assess the potential risks associated with NYISO’s transition and the impacts extreme weather events could have on the grid.

The assessment will use criteria such as net load and reserve needs, gas generation availability, interzonal transfers, and environmental constraints to identify hourly energy surplus and deficits in New York at a zonal level.

Paul Hibbard, a principal with AG, said the company conducted a similar study in 2019 that found “a continued reliance on fossil fuels was necessary in the near term,” and that NYISO could build more transmission to “address potential reliability risks associated with increasing variable generation.” (See “Fuel Security Study,” Analysis Group Presents NYISO Carbon Pricing Study Plan.)

Mark Younger, president of Hudson Energy Economics, asked whether the upcoming study will offer any noteworthy changes from the 2019 study.

Hibbard said the company is “kind of repeating what was done previously” given that the methodology and basic source material are similar, but the underlying risk scenarios determining the current study’s assumptions are different because of the passage of time.

Hibbard said the goal of the new study is to “identify circumstances under which resources may be insufficient to meet demand plus reserves without taking emergency actions.”

AG will return in May to give a more detailed presentation on the study’s assumptions, data and scenarios.

In early summer AG will share the study’s initial findings and recommendations, then present the final report later that season.

ECBL Aggregation Manual Updates

NYISO also presented the Friday ICAP/MIWG with draft manual updates for sections covering the economic customer baseline load (ECBL) that adjust the calculations to a five-minute basis for distributed energy resources.

The ECBL, which was implemented into NYISO markets in 2018, provides an estimated energy baseline for the ISO to measure the amount of demand reduction supplied by a demand-side resource participating in a day-ahead demand response program.

This update was one of a series of aggregation manual updates, and NYISO will return to share additional manual revisions on April 27.

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FERC Denies Rehearing of Cold Weather Standard

FERC said last week that “by operation of law” it would not reconsider its approval of one of NERC’s new cold weather reliability standards earlier this year because of the expiration of the time limit for its response.

The Electric Power Supply Association (EPSA), the New England Power Generators Association and the PJM Power Providers Group had filed a request for rehearing in March of EOP-012-1 (Extreme cold weather preparedness and operations), which FERC approved alongside EOP-011-3 (Emergency operations) in February (RD23-1).

FERC ordered NERC to develop the standards as Phase 1 of a three-phase process to respond to the winter storm of February 2021 that nearly led to the collapse of the Texas Interconnection. (See FERC Orders New Reliability Standards in Response to Uri.)

In a filing Thursday, the commission said that because 30 days had passed without it taking action on the request, it should “be deemed to have been denied.”

Requirement R1 of EOP-012-1 mandates that generator owners (GOs) installing a new generation unit must implement freeze protection measures that allow the unit to operate for at least 12 hours at the extreme cold weather temperature for its location, defined as the lowest 0.2 percentile of the hourly temperatures measured in December, January and February of each year since 2000.

Requirement R2 requires owners of existing generating units to ensure they can operate for at least one hour at the extreme cold weather temperature, either by adding or modifying existing freeze protection measures.

EPSA and the other organizations objected to these requirements on the grounds that they would “require [GOs] to incur potentially significant costs that they lack a reasonable opportunity to recover through rates.” They urged FERC to either initiate a new proceeding regarding cost recovery or remand the standard to NERC for revisions.

However, the commission said these concerns were “outside the scope of the instant proceeding,” and while it did raise several concerns for NERC to address in the next version of the standard — including the timeline for completion of corrective action plans and the grace period for generators to implement those plans and freeze protection measures — it did not provide for any delay in implementation of the standard or for addressing the groups’ concerns.

The petitioners’ rehearing request claimed that FERC erred by saying cost recovery was not in the scope of the proceeding, arguing that the standard “cannot be just and reasonable” as the Federal Power Act requires that reliability standards provide “a regulated entity of a reasonable opportunity to recover its costs.” EPSA said EOP-012-1 also violates the FPA by imposing requirements on registered entities for the modification or construction of generation facilities.

FERC did not specifically refer to these complaints in its filing last week, but it promised that it would address the rehearing request in a future order. It also affirmed that it “may modify or set aside its … order … in such manner as it shall deem proper.”

EOP-012-1 is set to take effect Oct. 1, 2024. The effective date of EOP-011-3 has not been set; FERC said in its implementation order that it will not finalize the standard’s implementation date until NERC submits its proposed revisions to EOP-012-1.

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Upgrade to Ease NY Transmission Bottleneck 75% Complete

A $615 million project to ease one of the transmission bottlenecks in upstate New York is nearing completion.

State officials last week announced the Central East Energy Connect (CEEC) upgrade undertaken by LS Power Grid New York and the New York Power Authority is now 75% complete with energization of a new substation in Princetown, west of Schenectady.

The 345-kV CEEC runs 93 miles from the Utica area east to the Albany area. The upgrades are designed to not only increase the CEEC’s capacity but improve its reliability and resilience. Steel monopoles are replacing wooden H-frame towers that are more than 60 years old in some cases. Four existing substations along the route are being upgraded, and two new substations have been built and are now in service.

Completion is anticipated later in 2023 and will result in a nearly five-fold increase in capacity.

The CEEC upgrade arose from a December 2015 finding by the state Public Service Commission that a Public Policy Transmission Need existed for new 345-kV transmission facilities to move power from upstate to downstate. LS Power and NYPA submitted a joint proposal in August 2019, and the PSC adopted it in January 2021. Work began the next month.

As thousands of megawatts of wind and solar generation capacity are planned upstate to carry out New York’s clean energy transition, the need for such transmission lines will only grow.

The CEEC is just one of several such transmission projects on the drawing board or in progress across upstate New York, and far from the largest:

  • The rebuild of NYPA’s 86-mile Moses-Adirondack Smart Path is nearing completion.
  • NYPA and National Grid began work in December on Smart Path Connect, which will add 45 miles on the north end of Smart Path and 55 miles on the south end, where it will connect to the CEEC.
  • New York Transco is progressing on the New York Energy Solution, a rebuild of 54 miles of north-south transmission lines in the Hudson Valley south of Albany; the 456th and final monopole was erected earlier this month.
  • Last year NextEra Energy Transmission New York completed the Empire State Line, which runs only 20 miles but includes a new 345-kV hub for western New York and links to the state’s largest electric producer, the Niagara Power Project.
  • Work recently began on the Champlain Hudson Power Express, a $6 billion project running 340 miles underground and underwater from Quebec to New York City.
  • NYPA, energyRE and Invenergy have teamed up on a 175-mile underground and underwater transmission line called Clean Path NY that would run southeast through the Catskills to New York City and is now in the permitting process. With associated wind and solar generation projects, the price tag is estimated at $11 billion.

The planning continues, as New York works toward an emissions-free grid by 2040, with concurrent increases in power demand and variability of power supply.

The PSC in February approved 62 transmission upgrades with a combined capacity of 3.5 GW and an estimated cost of $4.4 billion. Last week it approved an $810 million clean energy hub designed to increase transmission capacity in New York City amid the demand of electrification, with many more upgrades expected there in the decades to come.

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Former Chairs, Rep. Casten Call for Bolder FERC

LEESBURG, Va. — FERC has become too politicized and should use its independent authority to move the electricity industry forward, two former commission chairs said Tuesday at an event hosted by aggregation company Voltus in Northern Virginia.

Former Chair Neil Chatterjee, now a senior advisor with Hogan Lovells, said he has developed a relationship over the years with Voltus Chief Regulatory Officer Jon Wellinghoff, who chaired FERC under President Obama, because during his tenure at the agency he looked to build on his predecessor’s work through major orders.

Wellinghoff was the force behind Order 745 on demand response compensation, which became the subject of a U.S. Supreme Court case affirming FERC’s jurisdiction over demand side resources, and Chatterjee helped shepherd through several orders expanding its authority in that area.

“A lot of what ultimately culminated in [orders] 841 and 2222, and 845, was me building upon the work that he had already done,” said Chatterjee. “And that’s how FERC needs to be. It was an independent agency because you actually didn’t know the partisan affiliations of the different commissioners.”

Now articles regularly spell out the political affiliation of the commissioners. (For the record, Chatterjee was a Republican appointee, and Wellinghoff, a Democrat.) Chatterjee argued parties should not matter.

“When it comes to something like the proper functioning of markets, and the oversight and the reliability of the grid, these things should be independent and above politics,” he said.

While Chatterjee got the initial Order 2222 through, many compliance filings are still before FERC. Wellinghoff said he hoped the commission would move those through and ensure that market rules for distributed energy resources are in line with the order.

“I hope that FERC does step up under 2222 — that they do carry out the spirit and intent of what you started there and actually ensure that these distributed resources do have a full opportunity to play in this market,” Wellinghoff said. “Because if they do, the potential is huge.”

Some forecasts put 28 million electric vehicles on U.S. roads by 2030, a figure that could double based on EPA’s recent proposed emissions rules. (See: EPA Releases Emissions Rules Aimed at Boosting EVs.) But even the smaller number means the country’s behind-the-meter battery capacity will exceed its generating capacity, Wellinghoff said.

“It’s going to be available to be used, and we have to effectuate the ability to use that resource,” he said. “FERC is in the trenches on that right now.”

Reason to be Proud

U.S. Rep Sean Casten (D-Ill.), a major supporter of FERC on Capitol Hill, said the commission has plenty of authority to move the needle on energy policy on its own, although it sometimes needs a push from Congress to get going. He has introduced a bill — the REDUCE Act — that would remove the state opt-out for wholesale demand response programs, as well as other bills on transmission, and he wants FERC to set a price on carbon to give zero-carbon assets their proper value on a grid awash in resources that have no marginal costs.

“I think a strong case can be made that FERC has authority, but perhaps not the obligation,” Casten said. “And whether it’s the REDUCE Act or others, we find ourselves in Congress saying, ‘Well, let’s just give you the obligation.’”

Casten argued that FERC is the most important agency for climate policy and said its adoption of wholesale competition, which led to rapid growth in natural gas combined cycle plants and a surge in capacity uprates for existing nuclear plants, was the main reason the industry moved away from coal.

“FERC’s power comes from authority and independence,” Casten said. “And I think FERC is a little bit afraid of its own shadow.”

Casten said the fact that former FERC Chair Richard Glick was denied a renomination hearing after endorsing policies opposed by Senate Energy and Natural Resources Committee Chair Joe Manchin (D-W. Va.) — particularly around the climate impacts of natural gas pipelines — has also put a chill on the agency.

“My view is if you are appointed to a term running an agency as powerful as FERC, or a commissioner on an agency as powerful as FERC, you have five years to tell your grandchildren that ‘you have reason to be proud of me,’’’ Casten said.

Worrying about whether a policy will impact a renomination hearing or offend a particular senator is no way to go about the job, he said.

FERC has been impacted by politics long before Manchin denied Glick a hearing, with Wellinghoff lamenting the fact that “Standard Market Design” for RTOs never got off the launching pad under Chairman Pat Wood during President George W. Bush’s first term.

“It used to drive me nuts at FERC when an order came in from an RTO and the words were different for the same thing,” said Wellinghoff. “It’s like we’re in Europe, you know — PJM speaks Italian and MISO speaks German.”

Wood tried to push through a reform that would have the same market design all around the country, but he was ultimately “run out of town” by powerful utility interests who were opposed to having independent markets, Wellinghoff said.

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How Green is that Green Hydrogen?

The term “green hydrogen” may be a misnomer under rules the U.S. Treasury Department is designing to determine the size of the federal production tax credit that a producer can claim using electrolysis.

It will come down to the amount of carbon dioxide and other greenhouse gases emitted to generate the electricity most companies will use to produce the hydrogen and whether they tried to net out those emissions with the purchase of renewable power. Even with the greenest method of production, that amount will depend on how green was the electricity used to power the technology.

The argument is more than academic because the Treasury and the Department of Energy are expected to use the calculated level of GHG emissions across regional grids to determine the PTC. Billions of dollars are at stake.

A company will be able claim up to $3/kg of hydrogen produced with renewable or nuclear power, or as low as 60 cents/kg for hydrogen produced by steam reformation of methane, and then only if the resulting carbon dioxide is either sequestered or sold as an industrial gas.

Allison Nyholm (E3-ACORE) FI.jpgAllison Nyholm, ACORE | E3/ACORE

One of complicating factors is whether to account for those new carbon emissions annually or on an hourly basis. Underlying assumptions are that clean grid power varies by region, by season and time of day. Electrolyzers will create a new, heavy load, likely causing power companies to run dirtier generation during times of peak demand.

In a report published last week, the American Council on Renewable Energy (ACORE) and energy consulting firm Energy and Environmental Economics (E3) argue that calculating emissions on an annual basis would likely lead to lower overall net carbon emissions and higher annual hydrogen production rates than calculating by the hour.

“An annual matching requirement, in which hydrogen producers would need to procure specified clean energy production to match their consumption on an annual basis, would allow electrolyzers to more cost-effectively operate at a higher capacity factor, reducing the cost of hydrogen production,” the report concludes.

The study found that calculating an electrolyzer company’s carbon emissions and efforts to offset them on an hourly basis could force electrolysis operations to shut down during times when the grid reaches peak demand, potentially driving up hydrogen prices.

Earlier studies by other organizations reached the opposite conclusion: that hourly accounting would lead to net-zero carbon in the atmosphere while still cutting the cost of hydrogen. The Treasury has not announced how it will address the issue. In addition to commissioning the study, ACORE has submitted comments to the department.

Arne Olson (E3-ACORE) Content.jpgArne Olson, E3 | E3/ACORE

“We began with three basic assumptions … that lowering the cost of hydrogen production is a fundamental goal to the tax incentives and should be considered in any analysis,” Allison Nyholm, vice president of policy and public affairs at ACORE, said at the start of a webinar last Wednesday to explain the findings of the report.

“Building out [hydrogen production] to scale requires considering the capital as well as energy costs for hydrogen production, and that … new clean energy development created through the Inflation Reduction Act … will result in lower greenhouse gas emissions, both independently and when combined with hydrogen production at scale,” she said. “Our assumption is that we’re looking at 500-MW electrolyzers that operates at 90% utilization rates. We account for capital costs.”

Noting that electrolyzers remain expensive, Nyholm said one of the objectives of the study was to provide an accurate picture of the cost of hydrogen production across regions and as well as clean energy use.

Arne Olson, senior partner at E3, said one of the underlying assumptions of the study is that “the relationship between supply and demand is purely contractual” across the grid, meaning the sources of power energizing the grid are indistinguishable.

Greg Gangelhoff (E3-ACORE) Content.jpgGreg Gangelhoff, E3 | E3/ACORE

“Any new electric load, including hydrogen [production], is served with power from the grid, and all else [being] equal, that’s going to increase carbon emissions, because carbon-emitting sources will need to increase their production to supply that load,” he said.

The only exception would be an electrolyzer and a renewable power supplier both operating completely off-grid, he added.

Companies wishing to use clean power account for the carbon content of grid power they are using by contracting with a clean power producer to “inject” that power into the grid, he said. In other words, the relationship between the supplier and company using it is purely contractual, he added.

Figuring out how the electrolyzer industry would affect the grid over different parts of the nation involved modeling 40 markets on an hourly and seasonal basis.

“The reason for selecting these markets was ultimately to see the impact of electrolyzer operations in a widespread of market contexts,” said Greg Gangelhoff, an E3 analyst. “The benefit of … an annual matching approach, the electrolyzer can ramp down to avoid those highest-priced hours. And by avoiding those highest-priced hours, you are also avoiding some of the highest hourly marginal emission rates … giving you a kind of a double bang for your buck in terms of efficiency and reducing cost.”

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FERC Rejects Pump Storage Bid for ISO-NE Inventoried Energy Program

FERC on Tuesday rejected a request to include pump storage facilities in ISO-NE’s Inventoried Energy Program saying it was outside the scope of the RTO’s recent compliance filing prompted by an appellate remand (ER19-1428-006).

Last June, the D.C. Circuit Court of Appeals 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). The program pays generators for maintaining up to three days’ worth of potential energy (e.g., fuel) on-site that can be converted into electricity at ISO-NE’s direction.

The court said FERC had failed to consider protestors’ argument that including those resources was improper because they were unlikely to change their behavior in response to the program’s incentives.

“Acceptance of compensation incentives — for a distinct category of generators that are unlikely to respond to those incentives — was arbitrary and capricious,” the court said. (See Court Strikes a Blow to ISO-NE Winter Plan.)

FERC in September issued an order on remand implementing the D.C. Circuit ruling and ordering the RTO to revise its tariff to eliminate those resources from the program. (See FERC Seeking Solutions for New England Winter Reliability.)

The RTO filed the requested tariff revisions in November. But it also noted that stakeholders — supported by Brookfield Energy Marketing, the National Hydropower Association and RENEW Northeast — had filed an amendment to the changes carving out pump storage projects from other hydropower and allowing it to participate in the program.

They said that because pumped hydro resources participate in the markets as binary storage facilities, a subcategory of electric storage facilities (which are permitted to participate in the Inventoried Energy Program), pumped hydro should be allowed to participate regardless of the D.C. Circuit’s ruling that hydroelectric resources are not permitted.

ISO-NE said it did not view the amendment as consistent with the D.C. Circuit’s order but would not oppose including pumped hydro in the program if FERC determined that the amendment met the compliance mandates.

In approving the RTO’s tariff revisions, the commission rejected the amendment as beyond the scope of the compliance filing. “The only question before the commission in this proceeding is whether ISO-NE’s filing complies with the directives of the September 2022 order. Protesters are effectively arguing that the September 2022 order should be modified to exclude a subset of hydroelectric resources from the compliance directive. These protests are essentially late-filed requests for rehearing of the September 2022 order.”

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Developer Abandons Plans for Pa. Gas Generator

A developer has scrapped its plans to build a 1,240-MW gas-fired generator in central Pennsylvania after environmental groups challenged the plant’s permits.

“Renovo Energy Center [REC] LLC will discontinue development of the proposed combined-cycle plant in Renovo, Pa.,” the developer said in a statement. “After more than 8 years, we do not see a path to a reasonable conclusion of the project’s air permit appeal, and have made the difficult decision to discontinue development.”

REC submitted its air quality application in December 2019, detailing plans for a combined cycle generator fueled by natural gas or ultra-low sulfur diesel. The Clean Air Council, Citizens for Pennsylvania’s Future and Center for Biological Diversity filed a series of appeals to the state Environmental Hearing Board, arguing that the Pennsylvania Department of Environmental Protection (DEP) had awarded several permits that would allow emissions higher than standards in state law.

The hearing board granted the environmental groups two appeals in August 2022, resulting in a partial summary judgment finding that the sulfur dioxide and volatile organic compound limits were too high in the DEP permits. The company dropped its development plans a week after a third appeal was set to move to hearings, following a filing stating that the parties could not reach a settlement.

“Our lawsuit was about protecting Pennsylvania and this environmental justice community from the additional pollution burdens that this plant would have imposed,” Jessica O’Neill, senior attorney at PennFuture, said in a statement following the project cancellation.

“It is a win for Renovo and for all Pennsylvanians when we realize that the fracked gas industry doesn’t make sense — from an economic, energy or environmental health perspective,” she said. “We will continue to push back against facilities and industries that threaten the health of our communities, our workers and the sustainable energy future that Pennsylvanians want and that our children deserve.”

The appeal argued that the DEP approval contained incorrect emissions limits for volatile organic compounds, carbon monoxide and particulate matter; uses outdated global warming potential factors to calculate emissions; misapplied the cost-benefit analysis required by the state; and stated that emission reduction credits sources from outside the state would be accepted without demonstrating that the credits would meet state requirements.

Clean Air Council Legal Director Alex Bomstein said the DEP has a track record of allowing air permits that exceed limits by relying on a developer’s projected emissions for a generator without conducting adequate analysis to verify the figures. The environmental groups hired an expert for their appeals who found that the plant’s emissions would have caused billions of dollars in public health costs for surrounding neighborhoods, which have been designated an environmental justice community.

The group has also been involved in appealing air permits awarded to Invenergy’s proposed gas-fired Allegheny Energy Center in Pennsylvania, with hearings expected in July.

“The way that society is moving, we’re not going to have many more of the large fossil fuel plants. … The market is favoring renewable energy,” Bomstein said, adding that his group is focusing on trying to combat legislation that would impede development of clean energy.

Local environmental groups cited the impact on residents’ health as the basis for their opposition.

“As a great-grandparent, I’m grateful that this power plant didn’t come to fruition because we are now able to protect what is most important — the health of our children,” Sue Cannon, co-founder of Renovo Residents for a Healthy Environment, said in the statement. “I opposed the power plant because I was thinking about the children in this community, especially my great-grandchild, and what the pollution would do to their health.”

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California Rolls Toward Zero-emission Locomotives

The California Air Resources Board plans to vote Thursday on a regulation requiring new passenger and short-distance switch locomotives to be zero-emission starting in 2030 and new freight locomotives to be zero-emission starting in 2035.

The proposal is meant to reduce emissions. Diesel-powered locomotives emit greenhouse gases, oxides of nitrogen (NOx) and fine particulate matter, with train tracks running through many densely populated areas of the state.

“Exposure to toxic and harmful diesel emissions is known to lead to cancer and increases in asthma, cardiopulmonary illness, hospitalizations and premature mortality,” CARB says on its website. “Communities near rail operations bear a disproportionate health burden due to their proximity to harmful emissions.”

Trains have generally been regarded as a cleaner form of transportation than big rigs, producing fewer emissions per ton of cargo carried. But a CARB analysis shows that as trucks decarbonize, trains will become the bigger polluters.

California’s current emissions limits will make trucks the cleaner mode of freight transportation starting as soon as this year, CARB says. Regulations to be implemented beginning in 2024 will gradually increase the differences between truck and train emissions until trucks are 100% zero-emitting and trains are not, CARB says.

“Results show that as California’s current truck regulations are implemented through 2023, trucks are producing less particulate matter (PM2.5) and [NOx] emissions,” the board’s website says. “By 2023, trucks will be the cleaner mode to transport freight. Beyond 2023, future CARB regulations will further reduce truck emissions, eventually bringing them to zero.”

The state’s Advanced Clean Trucks regulation, adopted by CARB in June 2020, will require truck manufacturers to sell an increasing percentage of zero-emission medium- and heavy-duty trucks in the state from 2024 through 2035.

The U.S. Environmental Protection Agency approved a Clean Air Act waiver for the rules on March 31, clearing the way for the state to launch the zero-emission program starting with model year 2024. (See Groundbreaking California Clean Truck Rules Win EPA Waiver.)

CARB adopted its Advanced Clean Cars II regulation in August, requiring all new cars sold in the state to be zero-emission or plug-in hybrid by 2035. (The EPA restored California’s long-held waiver for passenger vehicles in March 2022, after the Trump Administration revoked it in 2019.) So far, 17 states have adopted California’s clean car rules.

In-use Locomotive Regulation

CARB is tackling locomotive emissions by proposing similar rules. Its “in-use locomotive” regulation would phase out diesel trains and replace them with zero-emitting locomotives over time.

The regulation would require locomotive operators to begin funding their own trust accounts based on emissions starting in 2024.

“The dirtier the locomotive, the more funds must be set aside,” CARB’s website says.

The funds could be used to buy or rent the cleanest “tier” of diesel locomotives through 2030. They could also be used to purchase or lease zero-emissions (ZE) locomotives, to fund ZE locomotive pilot and demonstration projects, and to pay for ZE locomotive infrastructure.

Hydrogen powered switching locomotive (Ballard Power Systems Inc) Content.jpgSierra Northern Railway received a $4 million grant from the California Energy Commission for a hydrogen powered switching locomotive.

Under the proposed regulation, locomotives older than 23 years would be prohibited from operating in-state starting in 2030. “Switchers,” short-haul locomotives used to move train cars, and passenger locomotives with original build dates of 2030 and beyond would be required to “operate in a ZE configuration,” CARB says. More powerful “line-haul” locomotives would have to be zero-emitting if built after 2034.

Where the locomotives will come from remains in question. Only a handful of hydrogen fuel-cell and battery-powered trains are in experimental or development phases in the U.S. and Canada.

Canadian Pacific Railway made test runs of North America’s first hydrogen-powered locomotive last year and is seeking to have two more on the tracks by the end of 2023. (The railroad’s name changed to CPKC on April 14, when it merged with Kansas City Southern.)

The railroad intends to produce its own hydrogen at two railyards in Calgary and Edmonton, including using solar panels to power an electrolysis plant in Calgary that makes hydrogen from water.

In March 2021, the California Energy Commission awarded Sierra Northern Railway $4 million to develop a hydrogen fuel-cell switcher locomotive for use in West Sacramento, California, where it now operates an older high-polluting diesel engine. That project remains in development.