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November 1, 2024

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ISO-NE Must Include Pumped Hydro in Inventoried Energy Program, FERC Rules

ISO-NE must include pumped storage resources in its Inventoried Energy Program (IEP), FERC ruled on Thursday, siding with Brookfield Renewable Trading and Marketing in the company’s complaint against the RTO (EL23-89).

The IEP is intended to compensate resources for storing extra fuel they otherwise would not procure during periods of winter reliability risk. (See FERC Approves Updates to ISO-NE Inventoried Energy Program.) The D.C. Circuit Court of Appeals ruled in 2022 the IEP cannot extend to nuclear, coal, biomass and hydroelectric resources because the program would not result in a change of their fuel storage behaviors.

Following the D.C. Circuit ruling, ISO-NE submitted — and FERC approved — a version of the IEP which excluded the specified resources, including pumped storage. Brookfield Renewable, which operates a 633-MW pumped hydro storage facility in western Massachusetts, filed a complaint over the exclusion of the resource type in August.

In FERC’s ruling on Thursday, the commission said the D.C. Circuit ruling does not preclude the inclusion of pumped storage because these facilities fall under the category of electric storage facilities, which are allowed to receive payments in the IEP.

“As the ISO-NE tariff currently permits battery storage electric storage facilities to be eligible to participate in the Inventoried Energy Program, it is unduly discriminatory to prohibit pumped storage electric storage facilities, which similarly store energy to later inject the energy into the system, from being eligible to participate in the Inventoried Energy Program and receive those payments,” the commission wrote.

FERC wrote that IEP payments likely would incentivize pumped storage facilities to alter their behavior and boost reliability in the region.

“Allowing pumped storage electric storage facilities to be eligible to participate in the Inventoried Energy Program, similar to other electric storage facilities, can alter their incentives and thus their behavior by providing an incremental financial incentive to store energy,” the commission wrote in the Sept. 21 ruling.

FirstLight Power and the New England Power Generators Association both submitted comments in August supporting Brookfield’s complaint, while a group of consumer-owned power companies opposed it.

The consumer-owned power companies argued the complaint was attempting to relitigate previous findings and that including pumped storage in the IEP would not result in more stored energy.

“Brookfield’s complaint fails to show that any system-wide incremental energy production would result from extending the IEP’s incentive compensation mechanism to pumped storage hydro facilities,” the group wrote.

In its complaint, Brookfield argued pumped storage operates in the same way as any other type of electric storage.

“The fact that one ESF [electric storage facility] may use pumped storage technology and another ESF may use a chemical battery is irrelevant because they both are able to provide the identical winter reliability service through the IEP,” Brookfield wrote. “Because all ESF technologies operate under the same economic principles, the same incentive exists for all ESFs to provide reliability service through the IEP.”

ISO-NE told FERC it did not oppose the inclusion of pumped storage in the IEP but said it believed the D.C. Circuit ruling prevented their inclusion in the program.

“The D.C. Circuit’s Belmont decision did not differentiate between pondage and pumped hydroelectric resources, but instead simply indicated that ‘hydroelectric’ resources must be excluded from the IEP,” ISO-NE wrote. “The Belmont court did not provide any exception for pumped hydroelectric resources to participate in the IEP as ESFs.”

ISO-NE had said it needed a FERC order by Sept. 22 to include pumped storage in the IEP for the upcoming winter.

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NJ’s Push Toward Clean Cars Rule Sparks Vigorous Debate

New Jersey’s planned adoption of California’s Advanced Clean Car II (ACC II) rules stirred a heated exchange Thursday as business groups argued the state is far from ready for a sudden surge in electric vehicle use and environmentalists argued climate change threats demand the rules be in place by 2024.

Groups representing car dealers, gas station convenience stores, the petroleum industry, businesses and other sectors at an online public hearing on the rules organized by the New Jersey Department of Environmental Protection said mandating EV sales would disenfranchise numerous low-income consumers who already struggle to buy a car.

The three-hour online hearing, the only one scheduled, drew more than 40 speakers. It came as ACC II supporters are urging the administration of Gov. Phil Murphy (D) to have the rules in place by the end of the year so they can impact the 2027 model year. The eight-week-long public comment period will end Oct. 20. (See NJ Sets Advanced Clean Cars II Proposal in Motion.)

ACC II calls for a steady increase in EV sales as a portion of all new light-duty vehicle sales, until they account for 100% in 2035. But, business groups argue, that mandate would push up the price of used cars as consumers looked for a cheaper alternative to the higher-priced clean energy-fueled vehicle, framing the rules as a big government intervention in what should be a decision by the market.

“New Jersey and all the other ACC II states will be a 100% EV sales market when consumers want to buy only EVs, not when government mandates it,” said Jim Appleton, president of the New Jersey Coalition of Automotive Retailers (NJCAR).  “Frankly, we believe this plan will frustrate and cause a consumer backlash that will slow our roll to an EV future, not accelerate.”

He argued that if consumers face a mandate for sales increases when they find the prices high, or access to the charging infrastructure unreliable, they will simply “hold on to their older cars longer or opt into the used car market which is not regulated by ACC II.”

Other opponents argued the state’s grid is not ready to provide the amount of electricity needed to serve hundreds of thousands — perhaps millions — of EVs. And they questioned the impact on carbon reduction, saying much of the electricity still might be generated with natural gas.

‘Shackles of Saudi Arabia’

Supporters of the rules — including EV manufacturers, health care professionals and some businesses — made up the majority of speakers at the hearing, however. They argued that recent extreme weather events — including the hottest summer on record — show the state needs to rapidly stoke EV adoption.

Pam Frank, CEO of ChargeEVC, a nonprofit coalition that promotes EV growth, said that with 123,000 EVs on the road in June, the state still is far from its goal of 330,000 EVs by 2025. A draft Strategic Climate Action Plan released by the DEP last week said the state would need 4.5 million light-duty EVs by 2035 to meet the state’s clean energy goals, accounting for 73% of all light-duty vehicles.

“Allowing the markets to set policy for the kinds of cars we drive will just not get us where we need to be as quickly as possible,” Frank said. “This is not a ban on [internal combustion] engine vehicles,” she said. She added most New Jerseyans buy used vehicles and that market would continue regardless of the new rules.

Supporters of ACC II argued EV prices already are declining and consumers would benefit because powering electric vehicles is cheaper than running on fossil fuel.

“Let me state emphatically that there’s nothing worse for New Jersey’s businesses than high oil prices,” said Sean Mohen, executive director of Tri-County Sustainability Alliance, which promotes sustainability in South Jersey. He argued that oil production cuts by Russia and Saudi Arabia had pushed up gas prices to their highest level this year, and demonstrated the need to focus more on electricity.

“It’s time for America and New Jersey to throw off the shackles of Saudi Arabia for both climate and business reasons,” he said.

Accounting for Health Costs

As adopted by California last August, ACC II requires car manufacturers to provide an increasing percentage of zero-emission vehicles (ZEVs) for sale each year. It defines zero-emission vehicles as battery-electric, hydrogen fuel cell or plug-in hybrid.

The regulation starts with a 35% ZEV sales requirement for model year 2026, increasing to 68% in 2030 and reaching 100% in 2035. ACC II also includes increasingly stringent standards to reduce tailpipe emissions of gasoline-powered cars and heavier passenger trucks.

State officials announced the process for adopting ACC II in February, setting off a vigorous campaign between supporters and opponents over the rules’ merits. A coalition of 100 businesses two weeks ago submitted a letter to state Senate President Nicholas Scutari and Assembly Speaker Craig Coughlin, both Democrats, urging them to reject the rules and instead take legislative action on the issue. (See NJ Businesses Demand Halt to EV Sales Promotion Rules.)

If New Jersey approves the rules, it would be the ninth state to do so. Maryland last week joined Massachusetts, New York, Oregon, Vermont, Virginia and Washington in adopting the California rules. (See Maryland Moves Ahead with Advanced Clean Car and Truck Rules.)

Richard Lawton, executive director of the New Jersey Sustainable Business Council, which represents companies seeking a sustainable economy, said the state should be clear about the motives of some opponents to ACC II.

“EV technology represents a competitive threat to industries and companies who have a vested interest in maintaining the monopoly power of fossil fuels, and [they] are using their economic and political power to raise as many barriers to entry as possible,” he said.

“This is perfectly rational for them, but not for the rest of us,” he said. “Top economists have called climate change the largest market failure in history. So relying on market forces alone to address this market failure would be self-defeating, and frankly, naive.”

Rural Difficulties

Several supporters focused on the health benefits of EVs, saying ACC II especially would improve the quality of life for minority communities that have long suffered the effects of vehicle pollution in urban areas and neighborhoods next to highways.

“Air pollution resulting from transportation in New Jersey is first and foremost a health issue, and discussions of costs that don’t include health costs is imbalanced,” said Dr. Elizabeth Cerceo, chair of health and public policy for the American College of Physicians New Jersey. “When this is factored in, the social and mortality cost of carbon, it outweighs the cost of EV transition. The supposition that the market should dictate the decision ignores the lives lost and the illness caused by fossil fuel pollution.”

But Mary Jo Foley, speaker for the Rural and Agriculture Council of America, argued that adopting ACC II would unfairly and excessively impact the nearly 850,000 residents of the state who live in rural areas.

“New Jersey’s rural and agricultural communities will be hardest hit by this proposal,” she said. “Internal combustion engine vehicles are a necessary part of everyday life for rural Americans, where it’s not an easy task to find an electric vehicle charging station.”

She added that “there will be massive increased demands in the New Jersey power grid, which also likely means higher prices for New Jersey electricity consumers who already pay some of the highest rates in the country.”

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‘Challenging’ Grid Conditions Led to CAISO’s Summer Emergency Alerts

CAISO’s issuance of energy emergency watches and alerts on three days in July came under conditions that mirrored those during California’s September 2022 heatwave, officials said.

Several “challenging evenings of grid operations” led the ISO to issue a Stage 1 energy emergency alert (EEA 1) on July 20, followed by EEA watches on July 25 and 26, CAISO CEO Elliot Mainzer told the Board of Governors on Thursday.

The period was marked by high demand from a record-setting heat wave in the Southwest, Mainzer said, while demand was “high but not excessive” in California and hydro conditions in the Pacific Northwest were below average.

In the Southwest, record-breaking temperatures included an average high in Phoenix of 114.7 degrees for the month of July, compared to the previous record of 109.8 degrees in July 2020.

“In many ways, conditions were the mirror image of what we saw last September when California was on the edge with a historic heat wave, and other regions were able to supply us with large quantities of power to help maintain reliability,” Mainzer said in a report to the board.

So far, the three alerts are the only times CAISO triggered the emergency alert system this year, Mainzer said. No Flex Alerts — in which consumers are asked to voluntarily conserve energy — have been issued in 2023.

In addition to Mainzer’s report to the board, CAISO also released last week a summer market performance report for July that goes into more detail on the EEA events. A Sept. 27 meeting has been scheduled to discuss the report.

July 20: EEA 1

Energy emergency alerts range from EEA 1, which includes calls for conservation measures and demand response, to EEA 3, in which rotating blackouts may be ordered. An EEA watch is a preliminary step before CAISO declares an alert.

When an energy emergency alert or watch is issued, CAISO has access to additional resources, such as the emergency load reduction program (ELRP), in which electricity customers are paid to voluntarily reduce their demand, and the state’s Strategic Reliability Reserve.

CAISO issued an EEA 1 at 7:30 p.m. on July 20 in response to “rapidly evolving grid conditions observed during real-time operations,” according to the monthly performance report. The July 20 conditions came up relatively unexpectedly, in contrast to grid events in 2020 and 2022 that were projected far in advance, the report said.

One and two days ahead, the market seemed able to meet the projected demand for July 20, although with thinning capacity margins.

But as the system approached net load peak on July 20, “the anticipated supply did not fully materialize,” the report said.

CAISO said reasons for the decreased supply included resource outages and derates; fewer imports due to potential fire impacts; and resources not dispatched due to congestion.

At the same time, demand was high from the desert Southwest, which experienced record-breaking high temperatures this summer. As a result, net imports were reduced during the net load peak.

Another issue was that a display of resource availability overestimated the amount of resource dispatch capability available — mostly due to storage resources that were providing multiple services, CAISO said.

As a result of the EEA 1, CAISO deployed resources from the ELRP. Normal operations resumed around 8:30 p.m.

July 25 and 26: EEA Watch

Factors similar to those that occurred on July 20 led CAISO to issue an EEA watch on July 25, effective at 7:30 p.m.

The ISO said it was seeing high external demand, wildfire threats to transmission, and the loss of about 2,000 MW of California resources “due to outages between the day-ahead and real-time markets.”

During peak hours, congestion on the Path 26 transmission lines made it difficult to send supply from the northern part of the system to Southern California, where it was still hot.

Another EEA watch was issued for July 26, from 6 to 10 p.m.

The report also discussed the flexible ramping product used by the real-time market. The EEA 1 on July 20 was sparked by a ramping shortfall as solar resources went offline in the evening hours.

The ramping product doesn’t procure capacity in response to unexpected outages or loss of imports, and so it had limited success addressing emerging uncertainty issues during the July events, CAISO said.

September 2022 Heat Wave

This year’s highest peak demand so far was 43,545 MW on July 25 at 6:27 p.m., well below the record peak of 52,061 MW on Sept. 6, 2022, during last year’s California heat wave. CAISO declared an EEA 3 that day but rotating blackouts were avoided after the governor’s Office of Emergency Services sent out a text alert at 5:45 p.m. urging consumers to conserve electricity.

Within 20 minutes, demand plunged by 2,385 MW and blackouts were averted. (See CAISO Reports on Summer Heat Wave Performance.)

Overall, operational conditions this summer have been “significantly less strained” compared to last year, CAISO said.

The state has been better positioned in terms of resource adequacy because of a record snowpack and strong hydro production, along with the addition of significant amounts of generating and storage resources.

Mainzer said August was another month with “a set of interesting conditions West-wide.” CAISO expects to release a market performance report for August next month.

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FERC Approves PJM Cost Recovery for NERC Penalty

FERC ruled last week that PJM can go to its customers to recover a $140,000 penalty leveled against the RTO this year by ReliabilityFirst, with Commissioner James Danly “reluctantly” concurring but calling for an investigation into PJM’s reliability violations and “manifest failures” to ensure reasonable electricity rates (ER23-2327).

PJM agreed to the penalty as part of a settlement with RF approved by FERC in April over several violations of NERC reliability standards — some at the Quad Cities and Dresden nuclear plants in Illinois, and others stemming from coordination issues at transmission facilities owned by FirstEnergy Utilities (NP23-13). (See PJM Hit With $140K Penalty for NERC Violations.)

According to a guidance order issued by FERC in 2008, RTOs and ISOs may “request recovery of penalty costs by spreading those costs among their members and/or consumers on a case-by-case basis.” Such requests must meet several criteria to be eligible for commission approval, including:

    • Whether the RTO or ISO involved had a compliance program in place.
    • Whether the violations were due to intent or gross neglect.
    • Whether management was involved in the violations.
    • The ability of the organization to pay the penalty.
    • The fairness of the RTO’s or ISO’s proposed assessment mechanism.

On June 30, PJM requested that FERC approve the recovery of the $140,000 RF penalty from its customers. The RTO explained that while it previously would have paid penalties from its administrative cost recovery rates, a change to its tariff in January 2022 meant the rates would no longer be “sufficient to absorb penalty costs.”

PJM claimed its proposed recovery was consistent with the criteria in FERC’s 2008 guidance order, noting that it possesses “a robust internal compliance program,” that all the violations were inadvertent and no harm to the grid resulted, and that management was not involved in the violations. The RTO said its proposal would allow “a broad allocation of the costs,” with a low impact on individual consumers; according to PJM, if recovered in a single month, the resulting additional cost to consumers would be around a fifth of a cent per MWh.

Public Citizen objected to PJM’s request, stating that putting the cost of the penalty on consumers would be “unjust and unreasonable. Instead of recovering the cost from consumers, the consumer advocacy group suggested that “PJM executives and PJM’s Board of Managers should be financially responsible for the penalties.”

This approach would be consistent with a FERC ruling last year against ISO-NE over construction delays at a Boston-area generating plant, Public Citizen said. In that case, ISO-NE agreed to a $500,000 civil penalty that was paid for through a reduction in executive compensation. (See FERC Investigation Faults ISO-NE in Capacity Market Fraud.)

PJM in turn pushed back on this suggestion, pointing out that the 2008 order on cost recovery was not applicable to the ISO-NE violation, which did not concern recovery of a NERC penalty. Furthermore, PJM said, FERC did not require ISO-NE to pay its penalty from executive compensation; the ISO made that decision on its own. The RTO reiterated that its proposed recovery mechanism is valid under the 2008 order and suggested Public Citizen has a problem with the order itself, not with PJM’s use of it.

FERC sided with PJM on the applicability of its 2008 order and said commissioners were “not persuaded” by the arguments of Public Citizen. The commission said that because PJM had “adequately addressed the factors identified by the guidance order,” it would grant the RTO’s request for cost recovery, effective Aug. 30.

But commissioners’ reactions to the decision were mixed, as Danly’s concurrence demonstrated. While the commissioner agreed PJM had “met its relatively light burden” of proof regarding its ability to recover costs, he argued in his filing that not only does the RTO have a history of “undercutting or dismantling core market design principles essential for just and reasonable rates,” the case makes clear that “PJM also is not very good at reliability.”

“I would treat PJM like the public utility that it is and … investigate PJM’s manifest failures to ensure or at least advocate for just and reasonable rates — and now to also investigate whether PJM is complying with existing reliability rules,” Danly said. “The commission should not hesitate to enquire whether a public utility serving as [an RTO] should continue in this critical role when rates and reliability failures suggest it is not doing very well.”

Danly suggested that the commission has authority to conduct such an investigation under Section 206 of the Federal Power Act. Although FERC has not taken this action on its own, Danly pointed out that “any entity with standing” could file a case, and wondered if this would “have more of an effect … than a $140,000 penalty that we pass through to ratepayers.”

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MISO Charting Course on Stimulating Generating Attributes

MISO last week said it continues research to gauge the quantity of generating attributes it might prescribe for its fleet.

MISO has defined six system reliability attributes as necessary, including availability, rapid start times, the ability to deliver long-duration energy at a high output and providing voltage stability, ramp-up capability and fuel supply certainty. (See MISO Considers Resource Attributes as Thermal Output Falls.) The RTO is studying what role it can play in maintaining those increasingly scarce reliability attributes from generation in the long term.

The RTO will share what changes it thinks might be necessary in an action plan it plans to publish at the end of the year.

“A growing body of experiences in MISO and across the industry has led MISO to focus on ensuring reliability system attributes are understood and maintained,” Director of Policy Studies Jordan Bakke said during a Sept. 21 stakeholder workshop.

Bakke said MISO can learn and borrow solutions from smaller countries and how they’ve approached ensuring attributes. He said EirGrid in Ireland has similar challenges with its transitioning resource mix.

MISO’s Patrick Dalton said the strength of MISO’s system can be thought of as a trampoline that’s slowly losing spring because intermittent resources aren’t replacing the characteristics of baseload generation.

Bakke said less predictable weather paired with less predictable generation means MISO must focus on supplying energy for the worst week in every season instead of just the worst peak load in the summer.

Michael Milligan, a consultant to GridLab, asked how MISO will calculate the quantity of attributes necessary while tracking the rate that MISO is losing them.

“That is our intent, and that’s inherently difficult to do as we’ve learned over the last several months,” Bakke said. However, he said landing on specific amounts of attributes is “core” to what MISO is trying to accomplish.

Minnesota Public Utilities Commission staff member Hwikwon Ham said states need in-depth information as early as possible on how MISO plans to measure needed attributes so commissions can integrate them in state-level resource planning.

WEC Energy Group’s Chris Plante pointed out that MISO already has incorporated and is planning major resource adequacy changes, including capacity accreditation, a seasonal capacity auction design and sloped demand curve in the auction. He said those changes are driving a “fundamental change” in how resource planners approach generation planning. He said planners have reverted to an older style of resource planning, where they ensure they own energy adequacy and rely less on the MISO markets.

“I think it’s important that we keep that in mind that the shift is already occurring,” he said.

Plante also said new planning might mean MISO’s middle-of-the-road transmission planning future, which it’s using to analyze attributes, might be outdated in light of the new, more independent style of resource planning.

IMM Skeptical

MISO Independent Market Monitor David Patton repeated his reservations with MISO’s accreditation work at a Gulf Coast Power Association virtual forum Sept. 15.

“I don’t oppose the work in general, but I do oppose the notion of singling out specific attributes and identifying a megawatt quantity that’s needed because it points to the wrong solution, which is we should create products related to these attributes,” Patton said.

Instead, MISO should put more emphasis on applying marginal capacity accreditation with sound modeling behind it, Patton said. He said MISO will naturally entice units with reliability attributes if it portions out capacity credit based on how nimble and stable generators are.

“Units with good attributes will get high accreditation, and units with attributes that don’t help you much from a reliability standpoint will get low accreditation levels,” Patton said.

MISO has planned another attributes discussion during a dedicated Oct. 31 workshop, then again at the Nov. 8 Resource Adequacy Subcommittee.

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MISO Relaxes Proposal on Stricter Queue Ruleset

MISO convened a special meeting last week on its plan to downsize the number of projects allowed in its generator interconnection queue.

Since last month, the RTO has pared down proposed fees for projects to enter the queue and penalties assessed upon dropping out.

MISO intends to place an annual megawatt limit on project proposals, collect higher entry fees, enact escalating penalty charges and require developers to verify they have obtained land. RTO planners have said the plan will ensure that only the most prepared projects will have a spot in the queue and reduce speculative projects that drop out and gum up network upgrade studies. (See MISO Sticks with MW Caps, Higher Fees to Pare Down Queue Requests; MISO Aims for Manageable Interconnection Queue.)

Now, the grid operator has cut back its first milestone fee paid to enter the queue from a proposed $10,000/MW to $8,000/MW. The fee currently stands at $4,000/MW; MISO first proposed to increase the fee to $12,000/MW in summer.

“We don’t plan to lower it any more. We think 8K is on the low end,” MISO’s Andy Witmeier told stakeholders.

Witmeier also said MISO has lowered its automatic penalty schedule so it can hold onto 10% instead of 25% of the first milestone fee at the queue’s first decision point and 35% instead of 50% by the second decision point.

The remainder of MISO’s automatic penalty structure proposal remains unchanged for the final two penalty points. A developer will still risk 75% by the time their project reaches the third and final phase of the queue and, finally, 100% if they drop out during the negotiation stage of the generator interconnection agreement.

Witmeier said MISO supports interconnection customers deciding to withdraw their projects as soon as they know they’re infeasible rather than lingering in the queue.

“I think we’re honing in on a really good proposal that we can bring to FERC in October,” Witmeier said.

MISO’s interconnection queue now stands at more than 240 GW across more than 1,400 projects.

MISO has a goal to file before the end of October, so its proposal is registered with FERC before the commission’s Order 2023 takes effect Nov. 5. Although MISO considers its proposal separate from Order 2023, the grid operator isn’t certain how the final rule will interact with the tightening of the MISO queue.

However, MISO still is working out how it will calculate its yearly megawatt cap on interconnection requests.

“We all agree we have a math problem here” in terms of how many projects MISO can realistically study, Witmeier said.

He added that MISO’s cap will include a “safety valve” feature that will allow developers to exceed the cap when projects are intended for load serving obligations, have a power purchase agreement, are an approved generator replacement facility or when projects simply are requesting to convert their unguaranteed level of interconnection service to firm service.

Consulting firm Charles Rivers Associates (CRA) reached similar solutions to help control MISO’s queue stampede.

MISO enlisted the help of CRA to review independently how MISO can best cut down on both its queue size and rate of withdrawals.

CRA concluded MISO should raise its first milestone fee from $4,000/MW to anywhere from $10,000 to $14,000/MW, install queue entry caps and enact an escalating fixed penalty schedule and a minimum penalty at every stage for withdrawing projects.

“After years of remaining relatively stable, the MISO queue has inflated to unmanageable levels in recent years,” CRA’s Margarita Patria said.

Patria said CRA’s recommendations strive to incentivize customers entering the MISO queue only after “really careful consideration.”

Patria said there “should be some consequences” for withdrawing projects because it’s a reality that withdrawing projects negatively impact other projects, even though the dollar amount is difficult to quantify.

Witmeier said MISO agrees its “pre-queue activity” needs to improve, as stakeholders have suggested. He said MISO plans to improve its existing point of interconnection tool to consider active interconnection requests and give developers a better idea of the feasibility of their projects.

He also said MISO plans to hold more informative scoping discussions with developers, use advanced analytics to share data on projects progressing in and exiting the queue alike and is considering using interactive AI chat bots to answer developers’ questions about MISO’s queue rules.

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NERC Standards Committee Briefs: Sept. 20, 2023

Leadership Elections

The NERC Standards Committee on Wednesday elected Todd Bennett of Associated Electric Cooperative Inc. and Troy Brumfield of American Transmission Co. as its new chair and vice chair, respectively.

Bennett, managing director of reliability compliance and audit services at AECI, will replace current Chair Amy Casuscelli, of Xcel Energy, beginning next year. When she steps down, Casuscelli will have served as chair for two consecutive two-year terms.

Casuscelli said she would give Bennett a “long, elaborate speech” for her last committee meeting in December, but she did tell him that “the committee is going to be in really good hands under your leadership, so congratulations.”

The committee chose Bennett over Charles Yeung, executive director of interregional affairs for SPP; the vote count was not revealed. Prior to the vote, Yeung said he was not running to oppose Bennett, saying that “Todd would be as good as chair with his experience as I could be. However, I think I would bring to the team a lot of insight from” his experience leading the Project Management and Oversight Subcommittee (PMOS).

Comments about the number of ongoing standards projects and how to prioritize them were sprinkled throughout the committee’s discussions. “I think the primary struggle of standards today is the projects,” Yeung said. “As we heard today, a lot of the concerns are about scheduling and priorities, so that will be a primary driver of leadership of the Standards Committee in the future.”

After Bennett’s election, WECC’s Steve Rueckert nominated Yeung for vice chair to run against Brumfield, manager of reliability standards compliance for ATC, who was running unopposed. Rueckert hedged his nomination on the condition that Yeung wanted to serve in the position, which made Casuscelli laugh, and Yeung say he had “never heard a nomination like that” before accepting.

Committee members also were briefed on their own upcoming elections. The committee is made up of 20 members, comprising two from each sector serving staggered two-year terms; thus, 10 members are up for re-election this year.

Nominations will be accepted from Oct. 3-13, and the election will be held over Nov. 1-13. The results will be announced Nov. 16.

Proposed Update to Supply Chain CIP Standard Deferred

After an hourlong discussion, the committee voted 9-7, with three abstentions, to delay consideration of a NERC-proposed standard authorization request (SAR) to update CIP-013-2 (Cyber Security — Supply Chain Risk Management) pending consultation with the Reliability and Security Technical Committee (RSTC).

Committee members expressed reluctance to approve another standard development project that did not seem urgent and seemed to prescribe one-size-fits-all solutions.

The first version of the standard went into effect in 2020. It requires entities to implement security controls in their supply chains addressing software integrity and authenticity; vendors’ remote access; information system planning; and vendor risk management. An update that went into effect last year extended the requirements to electronic access control or monitoring systems, physical access control systems and protected cyber assets. (See FERC OKs Updated Supply Chain Standards.)

A NERC survey on CIP-013, along with two others addressing cybersecurity that were approved alongside it, in March 2022 showed that although they were helpful, about 40% of respondents were unclear as to what would constitute a violation of the standards’ requirements. (See NERC Reports Mixed Data on Supply Chain Progress.)

“Industry implementation is wide ranging and variable across the ERO Enterprise,” according to the proposed SAR. “The implemented industry supply chain risk processes are ambiguous and generally lack rigor for validating the completeness and accuracy of the data, assessing the risks, considering the vendor’s mitigation activities and documenting and tracking residual risks. … The lack of specificity for correctly identifying and assessing supply chain security risks may lead to incomplete or inaccurate risk evaluations.”

“The threat has changed,” Jamie Calderon, NERC manager of standards development, told the committee. “New attacks have been documented. … How entities are complying with CIP-013 introduces too much room for residual risk.”

But Marty Hostler, reliability compliance manager for Northern California Power Agency, said the SAR seemed to be more about “course-correcting, [so] this seems like a lower priority then. We’ve got well over 30 projects already, and NERC just issued some guidance … on what we should be doing, [which means] it’s already correcting the course.”

“We did not state that it was a high priority,” answered Latrice Harkness, NERC director of standards development. “However, this is something that we need to address for security purposes.”

Hostler was not fully convinced, saying, “It would seem like we need a little … more guidance on what the real issue is, because we’ve got this guidance out there, and I think that’s appropriate.”

Brumfield noted the many instances in which the SAR said the standard “lacks specificity.”

“It’s telling us to drill down and be more prescriptive,” he said.

“I’m a little [conflicted] on whether this should go forward or not,” Yeung said. “On one hand, there’s gaps” in the standard. “The concern I have is, will this SAR be successful? Because from a PMOS perspective, we’ve got so many [projects] already. … So I want to make sure this SAR is amenable to industry to move forward.”

Hostler moved that the committee send it to the appropriate RSTC subcommittee for technical review, which ultimately was approved.

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Federal Budgets, Procurements to Include Social Cost of GHGs

President Joe Biden has directed all federal agencies to incorporate the social cost of greenhouse gases (SC-GHG) into a range of key processes, from developing and implementing their budget and procurement processes to environmental reviews required under the National Environmental Policy Act (NEPA).

“The Office of Management and Budget recently estimated that climate-related disasters could increase annual federal spending by over $100 billion and decrease annual federal revenue by up to $2 trillion by the end of the century,” according to a White House fact sheet on the announcement, released Thursday.

“By calculating the costs of climate change impacts on sectors like agriculture, public health, labor productivity and more, the SC-GHG allows better comparisons to other costs and benefits of agency decisions that may also be presented in dollar figures,” the fact sheet said. “And because the SC-GHG estimates the societal cost of the effects of various greenhouse gas pollutants emitted at distinct points in time, its use facilitates the comparison of alternative policies with different emissions profiles.”

The SC-GHG could be used to put a dollar amount on both the damages caused by GHG emissions and the benefits of measures to reduce them, the fact sheet says.

The president’s action represents “the first time this ‘whole of government approach’ is [being] used to evaluate the climate consequences of government actions,” Richard Revesz, director of the White House Office of Information and Regulatory Affairs, told The New York Times on Thursday.

The impact of the directive could be significant, as the fact sheet notes the U.S. government is the largest single purchaser of goods and services in the world, “spending over $630 billion per year … [with] the ability to move markets, invest in new ideas and act as a model contracting partner.”

“By integrating the SC-GHG into procurement … the federal government can reduce emissions while saving taxpayer dollars, both in the short term through reduced energy consumption and in the long term by helping to reduce the most catastrophic effects of the climate crisis.”

A recent analysis from the National Oceanic and Atmospheric Administration reported that so far this year, the U.S. has weathered 23 weather and climate disasters that caused more than $1 billion in damages.

The SC-GHG can be used to calculate emission reductions of proposed federal programs or actions compared to baseline GHG emissions of existing programs or projects. Agencies then can incorporate these calculations into “other considerations that inform and justify their budget proposals,” the fact sheet said.

Federal agencies also could use the procurement of “large, durable, energy-consuming products and systems” as pilots for incorporating the SC-GHG into their purchases, as was done by the U.S. Postal Service in its decision to increase its order of electric delivery vans from 40 to 75% of new purchases.

The social cost of carbon (SCC)  already has been incorporated in NEPA evaluations under guidelines the White House Council on Environmental Quality issued this year.

How Much is The SC-GHG?

The fact sheet does not specify any figures that federal agencies might use as they incorporate the SC-GHG into their processes and evaluations. The figure has fluctuated from around $51/ton of carbon emissions, set during the Obama administration, to $7/ton under former President Donald Trump, according to the EPA. The Biden administration returned the figure to $51, and EPA has proposed, but not finalized, a new figure of $190/ton.

Shortly after his inauguration, Biden also established an Interagency Working Group on the Social Cost of Greenhouse Gases, which in 2021 released a report with a wider range of values for the social costs of different greenhouse gases. For example, the SCC ran from $14 to $152/ton, depending on diverse variables. The low end of the social cost of methane was $670/ton, versus a high of $3,900/ton.

A group of Republican states, led by Louisiana, has been fighting the administration’s use of the SCC in federal processes but was turned back by federal appeals court decisions in 2022 and again in April 2023. The U.S. Supreme Court has refused to hear the case.

Initial reactions from the environmental community were positive.

David Doniger, a senior attorney at the Natural Resources Defense Council, called the administration’s action a “common-sense decision to assess how the federal government’s spending and investments will affect the climate crisis. Given the impacts from heat, storms and flooding that the nation has experienced this year, it’s clear that it’s long past time to consider the full impact of the federal government’s actions on the climate. This is an important step to do that.”

Responses on Capitol Hill split predictably along party lines.

Sen. Shelley Moore Capito (R-W.Va.), ranking member of the Senate Committee on the Environment and Public Works, criticized the Biden administration for using “unproven figures to attempt to justify its environmental policies that drive up costs for families, hamstring American employers and delay job-creating infrastructure projects from ever moving forward. Today’s announcement is more of the same devastating, top-down government mandates intended to kill energy jobs and make the United States more reliant on foreign countries.”

“This is a very big deal,” countered Sen. Sheldon Whitehouse (D-R.I.), chair of the Senate Budget Committee. “The Biden administration’s decision will put the full weight of federal government decisions into fighting climate change. … [The U.S.] will begin factoring the true costs of carbon pollution into a wide array of government actions, cutting back on taxpayers’ bills for climate-related disasters over the long term.”

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Déjà Vu as FERC, NERC Issue Recommendations over Holiday Outages

FERC and NERC staff presented their initial recommendations from their joint inquiry into the widespread electric outages last Christmas, which include completing development of winterization standards and improving reliability of natural gas infrastructure.

The report includes 11 recommendations to prevent similar events, such as Winter Storm Uri in 2021, when much of Texas was without power for days and hundreds died.

“This is the fifth time in 11 years that we’ve had a winter-related weather event where we had significant generator losses,” FERC Chairman Willie Phillips said. “But this time it was unprecedented: Nearly 90,000 megawatts and nearly 80% of the generating units failed to perform at temperatures above the unit’s own documented minimum operating temperature.”

As in previous winter events, the natural gas system also suffered, with production from the Marcellus and Utica shale regions falling by as much as 54%, which led to low pipeline pressures that nearly spelled disaster for New York City at the height of winter.

“We’re talking about — if pressure does not return — going house to house to house, apartment to apartment, to relight pilots; just the act of doing this would take months,” Phillips said at his post-meeting press conference. “And this event happened in December. A little bit of winter comes through in New York in January and February. It would have been catastrophic. Everyone should be concerned enough to act on this report, and the recommendations when they come out, immediately.”

NERC CEO Jim Robb was at the press conference, and he echoed Phillip’s concerns about how much a near miss Winter Storm Elliot proved to be.

“We were fortunate in that this was a relatively short-lived cold weather event,” Robb said. “And it warmed up on Christmas Day. Had it not, ConEd certainly would have been in the soup. It was also a storm that was centered in [the] western third of the Eastern Interconnection. And if it had been a couple hundred miles further east, New England would have had real catastrophic events.”

Robb noted that it took the 2003 Blackout in the Eastern Interconnection to get Congress to approve a mandatory reliability regime. He said he hoped the prospect of millions of New Yorkers being without heat at the height of winter will produce some action on natural gas reliability.

The report calls on Congress and states to enact legislation setting up reliability rules for the natural gas systems from the wellhead through the pipeline requiring cold weather preparedness plans, freeze protection plans and operating measures for extreme cold. That legislation should set up regional natural gas communications coordinators like the reliability coordinators for the power system, and it would need to designate critical natural gas infrastructure to be protected from any load shedding that grid operators use in emergencies.

Asked to comment on its near miss, Consolidated Edison pointed to a press release it issued at 6:30 p.m. on Christmas Eve calling for emergency conservation because of problems at pipelines serving New York that it did not own.

“We asked customers to conserve; switched our electric/steam generation plants to alternative fuels and relied on LNG and CNG,” said spokesman Allan Drury. “On Christmas morning, our region’s temperatures were a bit higher than expected and gas supplies were adequate.”

The company did not respond to a request for comment on the call for gas reliability rules.

The natural gas trade groups did not want to discuss the report, which is preliminary; FERC and NERC plan to release a final report later this fall. But the Interstate Natural Gas Association of America, which represents pipelines, did throw some cold water on the idea of a mandatory reliability regime for the industry.

“A reliability organization for interstate natural gas pipelines is the wrong approach to addressing the reliability problems identified during the discussion at today’s FERC meeting,” said INGAA CEO Amy Andryszak. “FERC exercises strict oversight of interstate natural gas pipelines and has promulgated regulations governing everything from construction to reporting of operational information to rates. As a result, interstate natural gas pipelines have a strong record of delivering on their firm commitments, even in extreme weather. There is no pervasive reliability problem across interstate natural gas pipelines like the electric reliability problems that led to the creation of NERC.”

Commissioner James Danly said a big part of the problem was the lack of infrastructure — and that FERC was largely to blame. While electricity is fundamental to the economy, it is not the only customer for natural gas, and customers need to pay for service, he said.

“There seems to be this assumption that it is entirely for the purpose of driving the electric reliability that the gas system should reorganize itself,” Danly said. “And I think that even if that were the right way to go about things and the best public policy to implement, they get to have a say in how their own systems are used because we still have private property in this country, even in a regulatory regime.”

The power industry has seen a major shift since the 1990s, when just 10% of generation was natural gas and that was for peaking, said Commissioner Mark Christie. Now 50% is natural gas and the bulk of that operates as baseload, he noted.

“Recommendation number seven says study whether we need more infrastructure,” Christie said. “I think this frivolous. Of course, we do. Of course, we do. You can’t turn your whole system from gas as a discrete peaker use and then make gas combined cycles your main baseload generation and not need more infrastructure.”

Commissioner Allison Clements noted that some natural gas utilities were unable to heat customers’ homes for up to eight days, but she questioned the need to build out more pipelines in response.

“We could come in and say we need more infrastructure, but the infrastructure that was there didn’t work,” Clements said. “From the production head through generation, we saw failures. We need to focus on the part we have jurisdiction over now, and industry needs to lean in, whichever part of the industry you’re in, to cut through some of these problems.”

Both Phillips and Robb said they have been arguing in favor of a new reliability regime for natural gas, and improved coordination between the two industries, for years.

“I think the issue we have in this country is that our recognition of the relationship between the natural gas system and the electric system hasn’t caught up to the realities of how those two systems are intertwined,” Robb said.

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Enbridge Announces Project to Increase Northeast Pipeline Capacity

Enbridge is soliciting requests for service as part of a natural gas pipeline expansion project that would significantly increase capacity to the Northeast, the company said in an open season notice issued this month.

The company said the project would expand capacity on the Algonquin gas system by up to 500,000 Dth/d at the Ramapo, N.Y., receipt point at the western end of the pipeline and 250,000 Dth/d at the Salem, Mass., receipt point at the eastern end. The total current capacity of the Algonquin system is just over 3 million Dth/d.

“Project Maple will provide much-needed supply reliability during peak daily demand, while stabilizing energy prices in the region and supporting New England’s continued journey to Net Zero,” Enbridge wrote in the open season notice.

The company said natural gas demand in New England has continued to grow, and it anticipates demand from local distribution companies increasing by 6.5% over the next five years, based on an analysis prepared for ISO-NE by ICF.

“Project scope will be comprised of a combination of replacing existing smaller diameter pipe with larger diameter pipe, extending pipeline loops in parallel to existing pipeline facilities, and adding compression at existing compressor stations, depending on subscribed volumes,” Enbridge wrote.

The open season process is a required step to demonstrate project demand to FERC. The process “seeks to identify parties desiring to obtain firm transportation service” and is open through Nov. 17. Enbridge’s target in-service date for the project is “as early as November 2029.”

Enbridge map of Project Maple and the Algonquin gas system. | Enbridge

“Through Project Maple, we’re seeking to increase capacity on our system to meet growing demand in the region from gas utilities, as well as for power generation,” said Max Bergeron, manager of stakeholder relations at Enbridge. “FERC has held technical conferences which have highlighted the power grid reliability concerns the region continues to face, and Project Maple is one solution which seeks to meet the need for reliable access to fuel for power generation, in addition to supporting growing demand from gas utilities.”

The proposal comes as many Northeast states are studying how to rapidly reduce the emissions resulting from the gas network and gas combustion. Natural gas primarily is made up of methane, a potent greenhouse gas, and is responsible for a large portion of the heating, electricity and industrial emissions in the region.

“Continuing the infrastructure and supply of methane is counter to our states’ climate goals; introduces hazards both from the inevitable leaks and the contributions to our enormous greenhouse gas load; and leaves rate payers, who cannot afford a clean energy transition, holding the ever-increasing bills,” said Judith Black, a climate organizer who lives in a neighboring town to Salem. “’Bad idea’ doesn’t begin to describe the Maple Project.”

In Weymouth, Mass., local community groups still are fighting to shut down a controversial Enbridge compressor station, which came online in 2021, because of climate, health and safety concerns.

“We do not anticipate adding any additional compression at the Weymouth Compressor Station as part of this project,” Bergeron said, adding the additional gas at the Salem receipt point would enter via the Maritimes & Northeast Pipeline at the western end of the system.

Alice Arena, director of Fore River Residents Against the Compressor Station, expressed dismay at the expansion plan, and called upon Massachusetts Gov. Maura Healey’s administration to block the project.

“If Maura Healey and her administration want to claim to be climate champions, this is where you stake that claim,” Arena said, adding that the proposal is incompatible with the need to rapidly reduce emissions.

“People cannot wrap their minds around where we are at in terms of climate,” Arena said. “It’s too hard to think about your children starving to death. It’s too hard to think about older people dying of the heat. It’s too hard to think about half of Boston being underwater.”

Enbridge may face a more difficult regulatory landscape than it did during the construction of the Weymouth Compressor. The state’s 2021 “Next Generation Roadmap” climate act enshrined protections for environmental justice populations into law, requiring enhanced public participation and environmental impact analyses for projects that affect state-designated environmental justice communities.

Over the past decade, Enbridge has successfully pushed through two pipeline expansion projects in the region — the Atlantic Bridge and Algonquin Incremental Market projects — but the proposed Access Northeast Project stalled because of lack of funding.

Joe LaRusso, a senior advocate at the Acadia Center, told RTO Insider the Maple Project likely will need to rely on firm contracts with the region’s local distribution companies to demonstrate demand for the project. Enbridge’s announcement noted that New England gas generators have firm contracts for only a small percentage of the gas needed to operate at full capacity, a dynamic the company called an “untenable disconnect” that raises energy prices and hurts grid reliability.

“Will the Project Maple AGTP expansion project succeed? Impossible to say,” LaRusso wrote on social media site Mastodon. “One thing IS certain: When it comes to fossil gas pipelines in New England, everything that’s old is new again.”