The Texas Reliability Entity knocked another registered entity for violating NERC’s facility ratings standards last month, assessing a $105,000 penalty in a settlement with the Buffalo Gap Wind Farm (NP22-30).
FERC said Friday it would not further review the settlement, leaving the penalty intact.
NERC submitted the settlement to the commission in its monthly spreadsheet Notice of Penalty (NOP) on Aug. 31, the same day it submitted a separate NOP and spreadsheet NOP concerning violations of the Critical Infrastructure Protection (CIP) standards. Details of the utilities and regional entities involved in these violations were not disclosed, in accordance with NERC and FERC’s policy treating CIP infringements as critical energy/electric infrastructure information. (See FERC, NERC to End CIP Violation Disclosures.)
Buffalo Gap Wind Farm — located about 20 miles southwest of Abilene, Texas — was built in three phases between 2006 and 2008 and has a total capacity of 520 MW. During a compliance audit in 2020, Texas RE determined that the facility was in violation of reliability standard FAC-009-1 (Establish and communicate facility ratings) and its successor FAC-008-3 (Facility ratings). FAC-009-1 was in effect from 2009 to 2013, when it was replaced by FAC-008-3; FAC-008-3 was replaced by FAC-008-5 last year. (See “Standards Actions,” NERC Board of Trustees/MRC Briefs: Feb. 4, 2021.)
Requirement R1 of the original standard, and R6 of the second, requires transmission and generator owners to establish facility ratings that are “consistent with the associated facility ratings methodology [FRM].” However, Texas RE found that Buffalo Gap’s one-line diagram included elements that were not included in its FRM.
When confronted, the utility at first said that these elements were owned by another transmission owner, but the interconnection agreement confirmed that it was owned by Buffalo Gap. When the entity recalculated the FRM, it found that one of the elements, a switch, was the most limiting element in the facility. The miscalculation had been in effect ever since the utility made the original FRM in 2009 and ended when the facility ratings documents were updated on Aug. 26, 2021.
Texas RE determined the root cause of the error to be “a misunderstanding of the reliability standard” because “Buffalo Gap was not aware that the series elements should have been included in the facility ratings regardless of which entity owned them.” The regional entity assessed the violation as a “moderate” risk to the reliability of the bulk power system, noting that no harm is known to have occurred as a result.
To mitigate the violation, Buffalo Gap agreed to verify and revise its one-line diagram to “as-built conditions,” along with revising its facility ratings documentation and rewriting the FRM to describe rating sources and its process for deriving ratings. It also contracted a third part to undertake compliance verifications and mock audits to ensure the utility was in compliance with the appropriate standards.
Facility ratings issues are a frequent cause of penalties that come before FERC, as noted earlier this year in a report by SERC Reliability. (See SERC Urges Industry Effort on Facility Ratings.) Experts have warned that as utilities adopt new generation resources and the BPS comes under stress from climate change-induced severe weather, operators will need to get serious about building awareness of the limits of their own systems.
ATLANTIC CITY, N.J. — The state has formed a multi-stakeholder task force to plan how to accelerate the effort to reduce greenhouse gas emissions from buildings, its second largest source of emissions, through electrification, Gov. Phil Murphy told hundreds of attendees at a state-organized Clean Energy Conference on Monday.
The Clean Buildings Working Group — which will include union leaders, academics, experts in industry, environmental justice advocates, a builder, and private heating and energy companies — will focus on how best to implement the transition from fossil fuel heating, appliances and boilers to clean energy backed with energy efficiency strategies, state officials said.
The initiative will “help us ensure that we maximize the potential of every watt of green energy” as the state reaches for its goal of 100% clean energy by 2050, Murphy told the conference, at which more than 650 people registered to attend. The group will “focus on the job of making our current building stock more energy efficient and on ensuring that new buildings are arguably more so.”
“It will require a skilled workforce to employ new green building technologies,” Murphy said. “It will further require making needed health and safety repairs to low- and moderate-income housing to get them to the starting point for beneficial electrification. And it will require deploying deep federal investments in green building technologies equitably across should.”
Jesse Jenkins, an assistant professor of engineering at Princeton University, who gave a keynote speech on “The Economics of Decarbonization” at the start of the second day of the conference, told the audience that while there have been a variety of strategies tried and some adopted across the nation on how to increase the use of electric vehicles or install more electric chargers, the challenge of converting buildings to clean energy is largely untouched.
“I’ve not seen any state yet quite crack the code on what the building standard is, what the building policy is, that every state that is interested in leading [on clean energy issues] should be following,” said Jenkins, who leads the Princeton ZERO Lab. The federal government has also largely left it alone, aside from recent funding for building electrification, leaving the states to act, he said.
“The state that cracks the code will see that replicated,” he said.
Tackling Building Emissions
Murphy’s working group initiative comes after the state has taken some strides in addressing building emissions but not with the same vigor as it has put into some other clean energy sectors, such as offshore wind and stimulating the uptake of electric vehicles and installation of electric chargers.
The New Jersey Board of Public Utilities (BPU) on Sept. 7 approved a program that will require 30,000 buildings of more than 25,000 square feet to annually report their water, gas and electricity use in an effort to stimulate conservation and cut energy use. (See NJ BPU Backs Utility Benchmarking for 30,000 Buildings.)
In addition, the New Jersey Department of Environmental Protection (DEP) has posted new rules on the New Jersey Register that would prevent it from issuing permits for new fossil fuel-fired boilers of 1 to 5 MMBtu unless it is “technically infeasible” to use a non-fossil fuel boiler. The rules could be enacted Dec. 6 if no major changes are made.
The introduction of the rules showed the sensitivity of some stakeholders to building electrification, with a coalition of 24 New Jersey business and union interests — among them some of the state’s largest business groups — lobbying to halt the state plan. The group says 5,500 buildings around the state would come under the boiler rules. (See Business Groups Try to Head off NJ Building Electrification Rules.)
The governor formed the working group in part because of the complicated nature of the task of electrifying buildings that are old and need extensive renovation, said Jane Cohen, executive director of the governor’s Office of Climate Action and the Green Economy.
“A lot of our housing and commercial buildings really need some significant health and safety and other types of repairs to get to the starting line to be able to partake in beneficial electrification,” said Catherine Klinger, a senior policy adviser to Murphy who will head the working group.
“Buildings are just more complicated than EVs and other types of green technology, because there are so many different types of buildings, so many different use cases,” she said. “There’s lots of legacy systems; you’re talking everything from delivered fuel and propane to old boilers and large multifamily and commercial buildings. So, there’s lots of different kinds of technologies that need to be employed, skillsets that you need in the workforce and strategies to decarbonize those different types of buildings.”
In addition, the state wants to ensure that low- to moderate-income residents and environmental justice communities get high priority in the allocation of resources for electrification, she said. The issue will be addressed in a similar way to the BPU’s recent Whole House pilot program, she said. The program, announced on Sept. 26, seeks to remediate health and safety hazards — such as electrical deficiencies and lead-based paint — in participant houses in coordination with the implementation of energy-efficiency measures.
Klinger said that through meetings and input from members, the group will be “looking at legislative levers, policy levers, funding incentives, and then out of those insights, our office will develop a roadmap to building decarbonization.”
Speaking after Murphy at the conference, FERC Commissioner Willie Phillips cited the Whole House program as one that other states can follow.
The program “is a beautiful combination of energy efficiency and equity,” he said, adding that “it recognizes that before any customer can take advantage of the clean energy transition, you have to make sure” that you take care of the fundamentals of their housing.
To embark on the clean energy transition, he said, “we have to acknowledge that equity must come first,” as New Jersey has done.
Phillips said that as a former president of the Mid-Atlantic Conference of Regulatory Utility Commissioners, he believes that “New Jersey has laid out a blueprint that many other states can follow” in a variety of issues, among them solar energy and offshore wind.
Phillips also took the opportunity to push for New Jersey and other states to take a long view of upgrading the grid. FERC in April proposed rules (RM21-17) that would direct transmission providers to revise their planning processes to, among many other things, identify infrastructure needs on a long-term, forward-looking basis and propose a list of benefits on which they would base their selections of proposed projects to meet those needs. (See FERC Issues 1st Proposal out of Transmission Proceeding.)
“If we don’t plan long-term, it’s going to hurt each and every one of you in your pocket because you are going to build out a dumb system for a smart future,” he said. Such a result would end up being expensive and is “going to hurt each and every person in this room.”
“It is no secret that our transmission needs have increased over the years,” he said, citing driving factors such as resource retirements, electrification of transportation and buildings and clean energy policies. “If we cannot do this affordably, we will not do it successfully,” he said, adding that further costs can be saved if “we squeeze as much capacity as we can out of the current system.”
“We are not requiring planners to elevate one particular policy over another. But what we are doing is saying, ‘This is the reality. This is what is happening. And it makes sense for us to consider these in our planning before they come up as a problem on our system,’” he said. “I am also proud to say that the proposed rule elevates the role of states regarding transmission buildout and cost allocation.”
Such a planning process would also help avoid “problems, and litigation and delays on the back end so that we can actually get some of this needed transmission built in an efficient manner.
Asked after the speech what are the biggest issues facing the grid, he cited “interconnection reform.”
“We have so many of our projects entering the interconnection queue, [and] we know that only 20% of those are going to be interconnected ultimately,” he said. “We have to figure out a way to undo that bottleneck to make sure that those projects can go ahead.”
He said the solution would be to go from a “serial, first-come, first-served process, to a clustered approach where it’s first-ready, first-served. The problem with the other 80% is they are caught in a situation that is “almost like a game,” he said.
“You know you are going to have to have for some projects very costly upgrades to the system. So, you see that those upgrades are needed and then you withdraw the project,” he said. “Then the person who finally gets lucky and gets in, they have to shoulder the cost of that upgrade and everybody else gets a free ride. That is what we are trying to solve.”
A California clean mobility program will open a $1 million funding round next month for nonprofits or public agencies to assess transportation needs in underserved communities.
Vouchers of up to $100,000 each will be awarded on a first-come, first-served basis. The application period opens on Nov. 2 at 9 a.m.
The vouchers are part of the Clean Mobility Options (CMO) program from the California Air Resources Board. CALSTART, a nonprofit group focused on clean transportation technologies, administers the program.
The vouchers will be available to tax-exempt nonprofits or public agencies. Examples of the latter include cities, counties, transit agencies or public school districts. Of the total funding, $200,000 has been set aside for tribal governments.
The proposals must cover areas that are disadvantaged, low-income or on tribal land.
Applicants may use their funding awards to identify transportation challenges in underserved communities and find ways to address them. The funds may be used to raise awareness of zero-emission mobility options such as car sharing or bike sharing.
Matching funds are not required.
Two Types of Awards
The CMO program is part of California Climate Investments, an initiative funded by cap-and-trade proceeds.
CMO includes two types of awards. Funding for community transportation needs assessments goes toward tasks such as information gathering, analysis and outreach. In the second type of award, CMO gives vouchers for specific mobility projects.
In its first funding window in 2020, CMO awarded $1.15 million for community transportation needs assessments to 24 applicants. Forty-one groups applied for the funds. The awards ranged from $18,750 to $50,000.
Also in its first funding window, CMO awarded $20 million to 21 applicants for zero-emission mobility projects in underserved communities.
The awards included $997,833 to the city of Chula Vista for an on-demand community shuttle serving seniors. The program, which launched in June 2022, will initially provide free rides in all-electric vehicles to passengers 55 and older in the northwest part of the city. Microtransit service Circuit operates the shuttle system.
Chula Vista plans to open the service to the general public in the second year, charging what it described as a small fare. The city received additional support for the project through a grant from the Community Congregational Development Corporation.
Another CMO award went to the Oakland Department of Transportation, which received $1 million for an e-bike “library.” The project will provide affordable medium- and long-term e-bike rentals in four disadvantaged Oakland neighborhoods, according to the city of Oakland.
About 500 e-bikes will be offered, including cargo bikes and adaptive bikes, which are designed for people with disabilities. The five-year project will be run by GRID Alternatives Bay Area in partnership with local bike shops.
Other types of projects that received CMO funding include electric vehicle car share programs, bike sharing and scooter sharing.
CMO expects to offer another round of mobility project vouchers next year.
The switch from natural gas to hydrogen for heating and use in heavy industry won’t be as easy to accomplish as the passage of recent legislation providing hundreds of billions of dollars to make it happen.
“Hydrogen is not a universal solution to all of our energy problems,” Steven Hamburg, chief scientist for the Environmental Defense Fund, argued during a recent webinar produced by the D.C.-based Center for Strategic and International Studies.
Josephh Majkut, CSIS | CSIS
In a dialogue with National Grid Chief Strategy and External Affairs Officer Ben Wilson, moderated by CSIS policy expert Joseph Majkut, Hamburg argued that producing hydrogen either from electrolysis or by high-temperature reforming of natural gas will itself take energy that could be used for something else.
Wilson countered that a hurried electrification of home and commercial heating would put a significant load on the electrical grid and make existing challenges much more difficult.
But Hamburg predicted that hydrogen would leak from existing gas lines at whatever percentage added to natural gas because gas lines already leak methane, which is a much larger molecule. And he argued that hydrogen, while not a greenhouse gas, “causes reactions in the atmosphere that increase the impact of other greenhouse gases.”
Current leakage rates show just how difficult it will be to run a leak-free system, Hamburg said. Data on leakage of the gas distribution system in Boston, which includes a lot of plastic pipe, shows the scope of the problem, he said.
“Boston, on average, has 4-plus percent of methane emitted just from that distribution system. … At least half of that is coming from the houses and [other] users. When you put hydrogen in the system, that number will go up.”
Fractured Understanding
Four thousand miles away, in an unrelated webinar presented by Mission Hydrogen, GmbH, an independent German producer of hydrogen-focused weekly webinars, a University of Belgrade mechanical engineering professor said that hydrogen, even when mixed at a low percentage with natural gas, will embrittle and lead to cracks in cast iron as well as modern stainless steel pipelines, especially if there is pre-existing corrosion.
Milos Djukic, University of Belgrade | Mission Hydrogen
“There is a serious threat of hydrogen damage and catastrophic failure, particularly for old gas pipelines, and particularly after future long-term service and transportation of hydrogen in, for example, gas pipelines with pre-existing defects on the inner side,” Milos Djukic, an expert on stress fractures, said.
“We need to implement a structural integrity model for estimation of safety of such pipelines,” he said, adding that old pipelines carrying as little as 1% hydrogen and 99% natural gas have sustained serious degradation.
“The first research started in 1892,” he said of century-long efforts to understand the effect of hydrogen on metals. “We still do not have agreement about the true hydrogen-materials interaction at various scales,” he added, referring to the debate among metallurgists about the nature of hydrogen’s interaction with metals at the microscopic level and down to the size of atoms.
Djukic said there is much research underway, especially in the U.S., to figure out the rates of stress fractures caused by hydrogen and hydrogen-induced embrittlement in pipelines and associated parts.
David Wenger, Mission Hydrogen | Mission Hydrogen
“I’m a big advocate of hydrogen technology, and we must move in that direction,” Djukic told more than 2,500 viewers. “This presentation was just my effort to give some hints, but not to give a complete story of what should be done in order to bring a little bit more safety.”
European governments, especially Germany, are aiming to replace natural gas with hydrogen, leading to studies indicating that the region will soon see as many as 40,000 km of gas lines carrying hydrogen, once standards have been established, Mission Hydrogen founder David Wenger said.
“If you read such a study from the gas industry, what would you think? Is it realistic? Is more research needed? Is it safe? What’s your … [opinion] on thousands of kilometers of repurposed pipelines,” Wenger asked.
“That is the reason why in my slides I pointed out that such a comprehensive technical [and] scientific approach should be applied, and I gave some actual measures, what should be done, in order to provide safety,” Djukic replied.
A switch to hydrogen for heating is still just a discussion in the U.S., which is where EDF would like to keep it, arguing instead for conversion of home and commercial heating to air-source heat pumps.
Steven Hamburg, EDF | CSIS
“If we use electricity directly, we can decarbonize many times more of that infrastructure … than we can if we just use hydrogen,” Hamburg said in the CSIS discussion.
He also said there is a serious shortage of data about hydrogen — in this case, how much hydrogen would leak out of existing systems converted from pure gas to a mixture of gas and hydrogen, or even more uncertain, pure hydrogen.
“In the absence of data right now, we’re all speculating. And if we do have higher hydrogen emission rates, it could greatly undercut the net climate benefits. It could even cause more climate warming,” Hamburg argued.
Hybrid Strategy
Ben Wilson, National Grid | CSIS
Wilson said National Grid is developing a hybrid strategy to achieve decarbonization, in part because switching from gas to 100% electric heating in New York and New England, where the utility has electric customers, would strain the distribution and transmission systems and drive up prices.
“It’s got four elements,” he said of National Grid’s plan to decarbonize. “The first one is energy efficiency. We have incentive and grant programs available for our customers on that. The second one is that between now and 2050, we will progressively decarbonize 100% of the gas that we deliver through our networks, initially mostly with renewable natural gas, but then increasingly over time with green hydrogen.”
The company’s gas distribution system will see increasing volumes of renewable natural gas in this decade and, in the 2030s, increasing volumes of green hydrogen blended with the gas — up to 20% hydrogen by volume before hitting “the blend wall,” Wilson said. “Up to that level, the customer’s appliances can cope with that blend,” he said.
Higher hydrogen blends will require a change out of burner tips in home appliances, he said.
“Our strategy in the Northeast is a green hydrogen strategy, mainly because there’s no legacy gas production. There are no geologic storage facilities,” he said in reference to how utilities in other regions store gas.
“We forecast that by 2050, probably 75% of our customers will have an air-source heat pump, probably 50% of them will also still have gas heating, powered by decarbonized gas to top up because air-source heat pumps, particularly if you’ve got old legacy housing stock, will struggle when it’s really cold.”
He added that “having couple of delivery mechanisms rather than just one, we think is just a much more practical and faster and more affordable way to make the transition.”
Wilson said leakage rates, particularly in modern systems in which cast iron pipes have been replaced with plastic pipe, should be no more than 3% maximum.
“And if it’s green hydrogen produced close to the customer . . . there’s no gas gathering system. There’s no transmission with venting; it should be a much more manageable problem,” he said.
“I completely agree [with Hamburg’s concerns]. We don’t want to go from one solution to a new solution and create significant atmospheric issues,” Wilson said.
FERC on Monday rejected the Coalition of MISO Transmission Customers’ (CMTC) proposal to allow some load to exit the MISO system penalty-free given the current Midwestern capacity shortfall.
The commission said CMTC failed to prove that MISO’s current tariff practices are unjust and unreasonable just because they don’t contemplate allowing load to bow out when the capacity auction fails to procure enough supply (EL22-60).
CMTC argued before FERC in May that MISO should allow its customers to decrement their load without being charged capacity payment obligations to lessen the possibility of summer blackouts. (See MISO Customers Ask for Penalty-free Load Reductions.)
The group said reductions in load would help following MISO’s 2022/23 Planning Resource Auction (PRA), which unveiled a 1.2-GW capacity shortage across MISO Midwest, triggering a $236.66/MW-day cost of new generation entry (CONE) clearing price for the entire subregion. (See MISO’s 2022/23 Capacity Auction Lays Bare Shortfalls in Midwest.)
CMTC contended that when a deficit occurs, MISO should allow some load to depart the system to avoid the steep capacity prices and bolster reliability by trimming demand. The group suggested that the RTO could allow load exits up to the 1.2-GW auction shortage and stop accepting any further load reductions once the supply and demand imbalance is resolved.
But FERC said that CONE clearing prices are an intentional feature of the auction — not a bug — beckoning new resources into the market.
“We are not convinced that the 2022/2023 auction results constitute a change in circumstances,” the commission wrote.
FERC said load-serving entities have ways of hedging against high auction prices, including entering bilateral supply contracts ahead of the auction, “supporting the development of new facilities” or selling demand response capabilities.
“The ability to hedge against high auction prices and the various off-ramps from the auction is further evidence that the existing tariff provides opportunities to avoid potentially high prices in the auction and is not unjust and unreasonable as complainants claim,” FERC said.
The commission also said it wasn’t convinced that CMTC’s proposed solution would be just and reasonable. It said giving auction participants the chance to “shed an otherwise binding commitment after an auction is conducted” would undermine the auction’s prices that signal for resource planning and investment.
In a separate concurring opinion, Commissioner James Danly repeated concerns about the flood of intermittent resources in MISO’s interconnection queue and its dwindling dispatchable generation. He called the RTO’s current market design “inadequate to the task of procuring sufficient capacity.”
However, he admitted that the 2022/23 PRA functioned as intentioned “regardless of poor decisions by market participants or the long-term consequences of systemic defects in MISO’s capacity construct.”
“Why observers of MISO would shriek and clutch their pearls when the price rises to CONE in the event of a capacity shortfall … is beyond me. Anyone who gets upset about prices rising in times of scarcity cannot truly be a proponent of competitive markets,” Danly said.
MISO itself argued that processing and then resettling “a multitude of load exit requests” would be burdensome and require compliance controls. It said it foresaw “complex computation” and “needless litigation” if FERC greenlit penalty-free departures.
The RTO said it would likely be forced to replicate the auction with new levels of load so it could establish updated demand forecasts, different systemwide and zonal reserve requirements, and adjusted zonal resource credits. It said CMTC was oversimplifying a solution.
MISO’s Independent Market Monitor said CMTC’s complaint was “fundamentally incompatible with MISO’s market design and tariff.”
The Coalition of Midwest Power Producers added that CMTC was essentially seeking retroactive ratemaking and said if FERC granted the complaint, it would have “eroded investor confidence in all regional transmission organization/independent system operator markets and would also represent a disruptive precedent that others could seek similar cost avoidance.”
Multiple stakeholders are seeking a FERC re-evaluation of MISO’s approved seasonal auction design, arguing that the plan’s capacity accreditation based on generators’ past performance is untested and unfair.
The Louisiana and Mississippi public service commissions said that while they don’t “in concept” oppose capacity accreditation rules “based upon some measure of historic generator performance,” MISO didn’t provide evidence to back up its availability-based accreditation.
They acknowledged that FERC defers to and gives grid operators latitude in designing their markets.
“But when the vast majority of utilities and many state regulators, with thousands of years of cumulative experience regulating utilities and serving retail customers, vociferously object to an expensive, untried, untested and unmodeled market experiment that is highly unlikely to address the resource adequacy concerns developing in MISO, FERC needs to listen,” the state commissions wrote.
FERC in late August gave MISO the go-ahead to establish four seasonal capacity auctions — with separate reserve margins by 2024 and apply a seasonal accreditation based on a generating unit’s past performance during tight system conditions. However, the commission disallowed MISO’s proposal to institute a minimum capacity obligation, in which a load-serving entity must demonstrate that it has secured at least 50% of the capacity required to meet their peak load in advance of the RTO’s voluntary capacity auctions (ER22-495 and ER22-496). (See FERC OKs MISO Seasonal Auction, Accreditation.)
Consumers Energy said the availability-based accreditation will breed “unreasonable volatility for market participants and increased costs to customers without demonstrated reliability benefit.” The company asked FERC to consider delaying implementation until the 2024/2025 planning year if it chooses to let the accreditation design stand.
DTE Energy and Alliant Energy seconded Consumers’ claims that the accreditation will aggravate volatility and raise costs. They called the design a “flawed and insufficiently supported approach that will handicap prudent planning practices by stakeholders.”
Entergy, Cleco Power and other MISO South electric cooperatives said the accreditation will yield “large and unreasonable fluctuations in accredited capacity from one season in one year to the same season in the next year.” They said LSEs stand to lose “significant capacity value” in one season based on performance during one or two days with small operating reserves.
The MISO South stakeholders also took issue with the RTO’s 31-day outage limit in a given season. They said the rule “places unreasonable limits and costs on a utility that wishes to engage in prudent maintenance practices at times when sufficient resources are expected to be available to maintain reliability.”
The Clean Energy Coalition — which includes Clean Grid Alliance, Sierra Club, Natural Resources Defense Council, Sustainable FERC Project, Fresh Energy, GridLab, American Clean Power Association and Solar Energy Industries Association — said MISO’s plan to apply different accreditation methods between thermal and non-thermal generating resources is unjustified and unlawfully discriminates based on resource type.
MISO’s new capacity accreditation design applies only to thermal generation; the RTO is still working on a separate accreditation for its renewable and load-modifying resources.
MISO Submits Rehearing Request for Different Reason
Meanwhile, MISO is asking FERC review its decision to reject the minimum capacity obligation (MCO).
The grid operator said the commission’s denial “failed to recognize the proposal as a solution to encourage prudent planning by load-serving entities, utilities, suppliers and regulators to address immediate resource adequacy concerns and the widening gap between available capacity and rising demand.”
MISO said the MCO is not meant to incent generation construction, as FERC assumed.
“Instead, the MCO is a solution designed to serve as a guardrail for the region’s increased reliance on the PRA [Planning Resource Auction] for more than residual capacity needs,” the RTO said. It added that the rule would help avoid “last-minute capacity shortfalls in the PRA by requiring a minimum level of prudent, forward planning by LSEs.”
MISO said years of low capacity prices have led to expedited retirements and deferred investment in generating facilities, with some LSEs depending on its residual auction to stock all their capacity needs.
AUSTIN, Texas — With ERCOT’s Board of Directors having solidified itself as the new sheriff in town — and made up entirely of Texas residents — the grid operator’s stakeholders are settling themselves into a lesser role.
Technical Advisory Committee members discussed weighty issues such as ERCOT’s use of emergency response service (ERS) and how to handle priority revision requests from regulators, but they did not take any votes to resolve the issues.
Leading the meeting in Chair Clif Lange’s absence, TAC Vice Chair Bob Helton set the tone when he recapped the board’s August meeting, during which the directors overturned the committee’s reduction of counterparties’ unsecured credit limit to $30 million. Instead, the board eliminated unsecured credit limits, leaving ERCOT as the only U.S. grid operator without a cap.
“With that, I believe [the board] made it clear with the way the protocols are going to go is that we, as TAC and stakeholders, are an advisory function only, and not a control or authoritative function above the stakeholder process,” Helton said during the Sept. 28 meeting.
Referring to TAC as “the collective wisdom of the market,” Golden Spread Electric Cooperative’s Mike Wise said during the conversation over priority requests that the committee needs to point out the unintended consequences in any revision requests it considers.
“We have to highlight those unintended consequences and do it in a passionate way, potentially to get the attention of those who do have the ability to make decisions, those that are in authority,” he said. “We have in this case really no authority. Not limited, but no authority. And that means that this group right here has got to really engage and get to do so in an articulate way to get the attention of the decision-makers.”
Legislation passed in the wake of last year’s winter storm removed market participants from the ERCOT board. It also required the independent directors be Texas residents, eliminating potential candidates with deep market experience from across the country.
Reliant Energy’s Bill Barnes, wearing a bow tie “to reflect the occasion,” referred to Greer, known for his opposition to ERS and for being willing to let everyone know, as one of TAC’s “OGs” (original gangstas).
“Here at TAC, we honor those that have made extraordinary contributions to our process and to our market design,” Barnes said. “Our meetings will now be much more efficient and faster without Clayton’s participation.”
Several TAC members and their companies sponsored a BBQ spread after the meeting and a pair of cakes with the Drake meme, showing the rapper turning away from ERS but liking real-time co-optimization, a market mechanism still years away from implementation. A promised dunk tank “sponsored by a coalition of ERS providers” failed to arrive.
Greer, who participated in the meeting as an observer, couldn’t resist getting his own digs in. During a discussion on ERCOT’s ERS deployment practices, he said, “I just wanted to first thank you guys for having this today, because it certainly entertains me. I get that this is an antique program and we inherited it after a bad event in 2006, but it’s time to revamp it.”
Turning serious, Greer told members it was an honor to have served on TAC for two decades and offered support for the committee’s new dynamic with the board.
“Over the last 20 years working on TAC and working with some of the brightest people in the industry, the faces may change, but the mission never did,” he said. “It’s always to provide the best product, market design and reliability design, and I think we did that. If you ask any of the traders, they always want to trade ERCOT; it’s one of the most liquid markets out there. And I think that’s a testament to how well this body works.
“In the past, we’ve always had the stakeholders on the [ERCOT] board, so there was always that knowledge on the board,” Greer added. “I think the new board members are really eager to understand how the market works and why a lot of these decisions are made because sometimes, that’s opaque. Usually there’s an underlying reason why things are the way they are [and] why they’ve been the way they’ve been for the last 10 years, and helping those guys understand that, I think, it’s one of the goals to this body.”
Members honored Greer with a standing ovation before adjourning for lunch.
TAC Approves 10 Change Requests
The committee approved, separately and as part of the combination ballot, 10 revision requests and a list of the system’s 258 major transmission elements.
Luminant voted against a nodal protocol revision request (NPRR1084) that would allow ERCOT to publicly provide information about resources’ forced outages, forced derates and start-up loading failures in a more complete and timely manner. The generator said it had concerns it wouldn’t be able to comply with the change without an update to the outage scheduler. The NPRR passed by a 26-1 vote, with two abstentions.
Shell Energy abstained from NPRR1058, which passed 29-0. The NPRR would require quicker updates by qualified scheduling entities to the telemetered resource status, high sustained limit (HSL), and other relevant information, improving the physical responsive capability calculation’s validity and dispatch.
The combination ballot included four NPRRs, two revisions to the Nodal Operating Guide (NOGRRs) and two system change requests (SCRs), which if approved by the board would:
NPRR1118: clarify the outage schedule adjustment (OSA) process to improve the terminology and clarifies the process for issuing advanced action notices and OSAs, and to clarify offer submission and reliability unit commitment (RUC) procedures after an OSA is issued.
NPRR1127 and NOGRR241: clarify which entities are required to have hotline and 24/7 communications with ERCOT, and requires those entities answer each hotline call to proactively ensure situational awareness during emergency situations.
NPRR1139: replace the usage of the wind-powered generation resource and photovoltaic generation resource productions with the HSL of an intermittent renewable resource as reflected in the current operating plan.
NPRR1140: permit generation resources to recover their fuel costs when instructed to start because of a RUC and operate above the resource’s low sustained limit.
NOGRR242: update references from point of interconnection to point of interconnection bus.
SCR820: build on the hotline communication process by developing a web-based platform supporting real-time, bidirectional, “send-review” messaging between ERCOT operators and transmission operators during emergency event coordination.
SCR823: request that ERCOT process (upload) a flat file received by ERCOT from each affected transmission/distribution service provider (TDSP) that contains all the TDSPs’ electric service identifier (ESI), besides retired ESIs. This flat file would allow all retail electric providers to have county names associated to all ESIs on the very first day following Texas SET V5.0 production go-live through the TDSPs’ ESI extract that is produced daily by ERCOT.
The Inflation Reduction Act (IRA) could provide New York with up to $70 billion in energy incentives and reduce the cost of meeting state emissions goals by almost the same amount, the state’s Climate Action Council (CAC) heard last week.
The CAC’s Sept. 29 meeting featured progress reports from two of its three subgroups and a presentation of an analysis on how the recently signed IRA will impact New York’s climate goals, embodied in the Climate Leadership and Community Protection Act (CLCPA).
Carl Mas, director of NYSERDA’s Energy and Environmental Analysis Department, shared results from an integration analysis that estimated that the IRA could provide New Yorkers with up to $70 billion in incentives, reduce the costs needed to meet CLCPA requirements by $43-$68 billion and increase the net benefit from climate mitigation by up to $50 billion.
The IRA, which was signed by President Joe Biden on Aug. 16, contains provisions that span the entire economy, driving the adoption of renewable energy and clean technologies while promoting energy efficiency and electrification. (See Biden Signs Inflation Reduction Act.)
The CAC requested an integration analysis of the IRA to better understand its overall impact on the state, examine sensitivities related to fuel prices and technology costs, and consider how implementation of the CLCPA might be affected.
The analysis explored two key aspects: estimates on how much money will be available to New York to offset CLCPA costs and what net benefits will be specifically provided to the state by those funds. Due to the breadth and size of the IRA, as well as remaining uncertainties about the legislation, the analysis was purposely conservative in its estimations.
The analysis estimated that $70 billion from the IRA will:
“tip the balance” toward more in-state wind energy;
lower procurement costs for innovative technologies, such as hydrogen;
reduce vehicle charging costs and encourage EV uptake;
reduce costs associated with transitioning buildings to more energy-efficient stocks; and
broaden the adoption of electrification across disadvantaged communities.
The net benefit analysis showed that $50 billion will flow toward “the execution of future solicitations” and increase the overall benefits provided by the CLCPA by “drawing co-funding from outside of New York State,” while raising New York’s “storyline” around climate action.
Mas also shared how the IRA will impact sensitivities around fuels prices and future clean technologies.
The analysis showed there will continue to be “upward pressures on fossil fuel prices” and that if costs for clean technologies unexpectedly rise, those costs will be passed to consumers who will then take longer to adopt them.
Mas noted that the findings underscore “the value of [New York’s] transition to renewable energy as a way to buffer New Yorkers against future uncertainties.”
He pointed out that the IRA will help insulate disadvantaged customers from these uncertainties by encouraging rapid adoption of clean energy because the law contains “explicit provisions dedicated towards low-income communities.”
Mas concluded by saying that evidence continues to show that the “net benefits from decarbonization” exceed the “net costs from inaction” and the IRA will be a key element in achieving New York’s climate and energy goals.
NYSERDA plans to appear before the CAC in October to share the IRA’s impact on the building sector and distribution system.
Gas Transition
Jessica Waldorf, director of policy implementation at the Department of Public Service, shared key considerations that Gas Transition subgroup members say should be included in the scoping plan to help guide New York’s gas system transition.
The subgroup recommended that plans be developed for how “individual gas utilities and local distribution companies will reduce their emissions by 2030 and 2050,” to both “mitigate impacts on remaining gas customers as other customers transition to alternative heating methods” and ensure that customers can continue relying on these assets without facing “undue burden or cost.”
Additionally, the subgroup wanted the development of a detailed timeline that aligns with the scoping plan to help consumers and generators better understand when transitions will occur and how they can leverage new technologies.
The subgroup also emphasized that significant consideration be given to communities that the CLCPA has identified as being “historically underinvested.”
Waldorf noted that disadvantaged communities should be “prioritized” and that the subgroup felt strongly about the development of clear frameworks that ensure emissions reductions, maintain existing gas infrastructure during the transition and give greater scrutiny to investments in those communities.
The subgroup also emphasized that the state should make plans to ensure a just transition of the gas industry labor workforce by helping to provide reemployment opportunities to displaced workers.
The Gas Transition and other two subgroups, Economy-Wide and Alternative Fuels, were formed to “tackle the challenging issues before the CAC, where there was considerable difference of views among the members,” according to NYSERDA CEO Doreen Harris.
Economy-Wide
Jared Snyder, deputy commissioner for air resources, climate change and energy at the Department of Environmental Conservation, shared findings from an Economy-Wide subgroup analysis that supports New York implementing a cap-and-invest program.
Proposed cap-and-invest design for New York. | New York State Climate Action Council
The subgroup evaluated three economy-wide strategies identified in the draft scoping plan: a carbon tax, a cap-and-invest scheme, and a sectoral clean energy supply standard.
The subgroup detailed how a carbon tax “places a price directly on emissions of greenhouse gases” while a cap-and-invest approach “places a cap on the emissions and then markets allocate the emissions reductions through the sale of those allowances in auctions.” A sector specific clean energy supply standard places limitations on fuel standards to regulate bulk emissions in specific industries.
Based on the subgroup’s analyses, most members concluded that a cap-and-invest policy was best suited for New York. The subgroup preferred the strategy because “it places a cap on the emissions that could be designed to meet emissions limits that were required to achieved CLCPA goals.”
The subgroup said cap-and-invested would be a “strong mechanism” because it “ensures all emissions in the state are contributing to the CLCPA goals,” and crucially showed interactions between allowance budget and non-allowance budget sectors. Furthermore, the policy would address climate justice by enabling price certainty through the creation of price floors and placing penalties on producers exceeding their cap levels.
Although the cap-and-invest would theoretically cover the entire economy, the subgroup carefully noted that in cases where certain “sectors cannot be easily reached, the state would retire allowances on their behalf and the remaining allowances would be auctioned or distributed according to legislation.”
CAC members expressed concern about some of the proposed language around these policies, but the subgroup countered that each policy raised “open questions” and that the remaining weeks will be used to address concerns.
Next Steps and Other Details
The CAC will reconvene on Oct. 13 to cover any remaining details related to the draft scoping plan and then plans to spend November discussing redlines of interest to the plan, which will likely be subject to a formal vote by the CAC at its Dec. 19 meeting.
The CAC also voted to approve a bylaw amendment that would allow for the adoption of videoconferencing attendance for CAC members in extraordinary circumstances, except for executive sessions.
ISO-NE violated its tariff in its handling of construction delays at a Boston-area generating plant, FERC said, slapping the RTO with a $500,000 fine.
In an orderissued on Friday, FERC agreed to a settlement requiring the grid operator to boost its compliance program for making capacity payments to the New Salem Harbor Generating Station before it had started operating or even finished construction (IN18-8).
ISO-NE has repeatedly denied wrongdoing and called itself the victim of fraud. But FERC made clear in its order that they believe the grid operator played a role in encouraging the Salem Harbor developers to present misleading information about when the project was expected to be finished.
The gas-fired combined cycle generation plant had a planned commercial operation date (COD) of May 31, 2016, when it cleared the RTO’s Forward Capacity Auction In 2013. It was awarded a capacity supply obligation of 674 MW for the delivery year beginning June 1, 2016. FERC noted that the plant, which went into operation in June 2018, was the first new merchant generating resource to clear in ISO-NE’s FCA.
ISO-NE’s Violations
The FERC settlement lays out a detailed paper trail showing that ISO-NE failed to meet its duties under its tariff as the project was in development.
As likely delays popped up, Salem Harbor Power Development repeatedly provided information to ISO-NE about changing milestone dates, which should have led the company and grid operator to put forward a new commercial operation date, FERC found.
Instead, ISO-NE staff encouraged the developer to maintain May 31, 2017, as the COD. ISO-NE’s former director of resource adequacy did so explicitly to avoid triggering the automatic submission of a demand bid in the reconfiguration auction (ARA3) and forcing the company to give away its full capacity supply obligation, FERC said.
ISO-NE also violated its tariff by failing to submit a demand bid and submitting an inaccurate qualified capacity value, FERC’s Office of Enforcement found.
ISO-NE employees had enough information to know that they should have qualified it for 0 MW, FERC said.
Instead, the facility was qualified at 674 MW, which helped it earn more than $100 million in fraudulent capacity payments.
And finally, FERC found that ISO-NE restricted the access of its own Internal Market Monitor to capacity market data, including the narratives filed by the project’s developer, as the situation was unfolding.
“Enforcement concluded that System Planning’s conduct not only violated the tariff, but also frustrated the IMM’s key market oversight role,” the order reads.
ISO-NE spokesperson Matt Kakley said that since the incident, the organization has “taken steps to ensure that no one staff person can take such an action.”
And he noted that the Monitor was still able to obtain the information needed even while access to the data was curtailed.
An Intentionally Light Fine
ISO-NE did not admit or deny the violations put forward by FERC, but it agreed to a $500,000 civil penalty and $350,000 worth of compliance improvements.
Those include expanding a portal for employees to anonymously report potential violations, a new training module on tariff compliance and the role of the Monitor, and compliance monitoring by FERC.
“We recognize that a larger civil penalty might otherwise be appropriate given the magnitude of the capacity payments that ISO-NE made to Footprint,” FERC wrote in its order. “However, such a penalty likely would be passed on to the fee-paying entities, potentially compounding the harm to those entities and undermining the deterrent value of a larger civil penalty.”
ISO-NE acknowledged the possible harm to ratepayers too, by saying that its executives will pay the fine.
“ISO New England’s senior management takes responsibility for the ISO’s role in this matter. Therefore, the financial penalty outlined in the settlement agreement will be paid through a reduction in executive compensation,” the grid operator said in a statement.
Kakley said that will come in the form of a pro rata reduction, and that it will be made public in the form of the RTO’s financial reporting.
ISO-NE Response
The grid operator maintained a defiant tone in its statement on the settlement, saying that the events were precipitated by “Salem Harbor Power Development’s failure to provide accurate and complete information to ISO staff.”
But ISO-NE also recognizes that the investigation “revealed inadequacies in the market rules and our internal controls, and areas where better judgments could have been made.”
It has since changed capacity market rules to include an automatic financial penalty for resources that are behind in their development, and worked to “foster increased information exchange among internal groups.”
The issue of project delays wreaking havoc on the capacity market has not gone away. The results of this year’s capacity auction were significantly delayed while ISO-NE waited for FERC and the D.C. Circuit Court of Appeals to settle litigation over Killingly Energy Center, which had its capacity supply obligation pulled by the grid operator because of its failure to meet milestones and stay on track for its COD. (See ISO-NE Announces Capacity Auction Results After Killingly Delay.)
The New Jersey county of Cape May asked the state Board of Public Utilities (BPU) on Thursday to slow the approval process for an easement to run power cables from the state’s first offshore wind project — Ocean Wind 1 — across county land until federal environmental studies are completed.
Michael J. Donahue, representing Cape May County | New Jersey Board of Public Utilities
Michael J. Donahue, a lawyer and former state superior court judge representing the county at two online BPU hearings, said the federal environmental impact study could provide information that is relevant to whether the cable route is feasible or not.
Donahue, who said he also represents 10 of the 16 communities in Cape May County, also urged the BPU to consider alternative routes more acceptable to area residents, many of whom oppose the project.
Danish developer Ørsted is seeking BPU approval for an easement to run cables bringing energy from its Ocean Wind project to a substation that would tie the project to the grid. The developer’s favored route runs through the Jersey shore community of Ocean City, which is in Cape May County.
The case is related to but separate from Ørsted’s petition for an easement running across public land in Ocean City, which the BPU approved on Wednesday. (See NJ BPU Approves Easement Plan for 1st OSW Project.)
Ørsted’s second petition also seeks BPU consent for the developer to obtain several environmental and other permits needed to get project approval from the New Jersey Department of Environmental Protection (DEP).
The case is the second test of a controversial law (S3926) enacted in July 2021 that allows offshore wind developers to site power cables and equipment on public land regardless of local or state government opposition. If the BPU backs the easement and consents, the developer would not need approval from the county or Ocean City, which also opposes the project.
“The county is not trying to delay or obstruct,” Donahue told the hearing. “But we think it’s important that many of the issues that concern the people of Cape May County be given an opportunity to be heard.”
Donahue said the county had had “discussions over a long period of time” with Ørsted about the project, including an attempt to “modify the impacts, especially in terms of cluttering the horizon.” But the two sides failed to reach an agreement, he said.
“We urge the board, as Ocean City has, to wait for those federal environmental processes to be completed so we don’t have the prospect of having to do all this all over again,” Donahue said. The proposed route could jeopardize sensitive marshes and impact area historical sites, he argued, and it could “conflict with many utilities that already exist” in the area, including sewer, gas and water main lines.
Negative Impact
The 1,100-MW Ocean Wind project, which the BPU approved in 2019, was the first of three offshore wind farms approved by the state to date. The BPU expects to follow the approval of the 1,148-MW Ocean Wind 2 and the 1,510-MW Atlantic Shores in 2021 with a third solicitation for 1,200 MW in the first quarter of 2023. (See NJ Seeks Stakeholder Input for 3rd OSW Solicitation.)
The projects are part of Gov. Phil Murphy’s goal, signed on Sept. 21, that the state have in place 11 GW of offshore wind capacity by 2040. That goal replaced Murphy’s earlier goal of 7.5 GW by 2035.
The Bureau of Ocean Energy Management issued a draft environmental impact statement (EIS) on Ocean Wind 1 on June 22, with comments due by Aug. 23. The draft found that the project would not have major impacts on most of the 19 environmental and related categories scrutinized.
But the 1,408-page report did find that the construction and installation, operations and maintenance, and eventual decommissioning of the project would have major impacts on marine navigation and vessel traffic, as well as commercial and recreational fishing. (See BOEM Draft EIS Finds Potential Major Impacts from 1st NJ OSW Project.)
BOEM held three public hearings on the draft in July. The agency said that after it “addresses the comments provided,” it will issue a final EIS that will “inform” its decision to “approve, approve with modifications or disapprove the project.”
But federal approval is only one hurdle for Ocean Wind 1. Ørsted is seeking a 30-foot-wide easement running about eight miles along the length of Ocean City, a popular tourism and vacation area on the Jersey shore. The 275-kV line will connect the project’s turbines, about 15 miles offshore, to the PJM grid at a substation sited on a now closed coal-fired power plant in neighboring Upper Township.
At issue in the Cape May case is the project’s need for a temporary 18-month easement and a 30-foot-wide permanent easement across county land, both in Ocean City, the developer’s May 20 petition says.
The BPU’s approval of the Ocean City easement on Wednesday was a big step forward for Ocean Wind 1, allowing project cables to pass across land in Ocean City created with funds from the state Green Acres program, which pays to improve parkland and open space.
The case, which involves the same cable route as the Cape May County case, was the first test of the law granting the BPU power to override local officials on issues involving offshore wind projects. The law allows the BPU to do so — and grant approvals on projects — if the agency concludes that they are “reasonably necessary” to the project.
Madeline Urbish, Ørsted’s head of government affairs | New Jersey Board of Public Utilities
As in the earlier case, Ørsted argued that they are. Madeline Urbish, the company’s head of government affairs, told the hearing that the project needed the BPU’s approval to move ahead and meet New Jersey’s clean energy goals, after the developer had held fruitless discussions with Cape May County since 2019.
“Time is of the essence if the project is going to meet its commitment to New Jersey” and reach commercial operation in 2024, Urbish said.
“Cape May County has not been willing to reach the necessary agreements to allow the project to proceed,” she said. The county’s approval and permit consents are required for the project to secure approval from the DEP, whose blessing is needed in turn for the environmental review conducted by the federal Bureau of Ocean Energy Management.
Alternative Route
Donahue countered that in order to limit disruption and negative impacts from the transmission lines, the BPU should consider cable routes for two other offshore wind projects approved by the agency — Ocean Wind 2 and Atlantic Shores — at the same time as the route and easements for Ocean Wind 1.
Instead of running the cables through Ocean City, Ørsted could send them along an abandoned railroad or part of the Garden State Parkway, the main highway along the Jersey shore, he said.
More than a dozen speakers at the two hearings on Thursday opposed either the granting of the easement or the project in general. Many said they are Ocean City residents, and some were clearly upset by the BPU’s intervention in what they considered a decision that should be taken by local officials.
Ocean City’s business administrator, George Savastano | New Jersey Board of Public Utilities
George Savastano, Ocean City’s business administrator, questioned the legitimacy of the law and the “authority” of the BPU to make decisions on the easement issue. “It remains to be seen whether it will survive judicial scrutiny,” he said of the law, citing a section of the state constitution that, he said, states “any law concerning municipal corporations formed for local government or concerning county shall be liberally construed in their favor.”
Savastano also argued that Ørsted’s designation of several alternative routes for the cable means that the chosen route through Ocean City is not “reasonably necessary.” That question is enough reason for the issue to be heard by an administrative law court, rather than the BPU, he said, and urged the agency to send the case to the court.
At a hearing on the first easement case in June, Ocean City called on Ørsted to choose a route that would avoid the municipality and instead send the cable through Great Egg Harbor Bay, coming on shore close to the substation in Upper Township and avoiding Ocean City altogether. Cape May County also supports that route.
Savastano said that the route through Ocean City is shorter, and so likely cheaper for the developer, who should, as a result, be required to divulge the cost of pursuing each of the available routes.
“Until and unless Ocean Wind discloses the cost of each of the alternate routes, the board cannot find that the easements and consents which Ocean Wind claims to need are reasonably necessary,” he said.
The BPU has said in the past that the cost of any of the routes is irrelevant to the discussion because it will be paid for by Ørsted and won’t be an expenditure of public money.
