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November 13, 2024

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Floods Create Risk of ‘Climate Abandonment’ Across US

More than 110 million Americans live in places where flood risk is impacting housing choices, and millions have already left or chosen not to move to communities that climate research nonprofit First Street Foundation calls risky-growth and “climate abandonment” areas.  

Together, those areas are home to one-third of the population and 42% of all housing stock in the contiguous U.S., and additional areas are expected to reach a tipping point and see similar impacts over the next few decades.  

In a Dec. 19 webinar, the authors of the foundation’s Climate Abandonment Areas report published in Nature Communications said the areas experienced a loss of 3.2 million people between 2000 and 2020 that was directly attributable to flood risk. Risky-growth areas, on the other hand, still grew, but at a lower rate than if there were no flood risk.  

“More than 34% of the population in the contiguous U.S. live in [census] blocks which have already seen an impact from flood risk on population growth or decline,” said lead author of the study, Evelyn Shu, a senior research analyst at First Street Foundation. “This doesn’t mean that all of these populations declined because of flood risk or even that they will necessarily decline in the future, but a big proportion of the U.S. population is in blocks which may have seen slower growth than they would have otherwise.” 

“No matter where you are across the country, models are showing that areas that have high flood risk within a community are not growing as fast or are declining versus places that don’t have that flood risk,” Jeremy Porter, head of climate implications at First Street Foundation, said. The models control for amenities such as schools and medical care, socioeconomic characteristics such as age and income, and economic opportunities such as job availability. 

The study mapped high-resolution flood data against granular population changes. Population data was compared for the 11 million census blocks in the contiguous U.S., each with around 80 to 120 people — that is, areas as small as a building in a dense city or a block in a suburban neighborhood.  

“We use high-resolution data on historic and current flood exposure, which includes data from the First Street Foundation flood model, and the proportion of properties that are inundated in a given block across the 5-, 20-, 100- and 500-year return periods,” Shu said. 

Climate risk is a house-by-house issue, not a state-by-state issue. | First Street Foundation

Climate Disasters and Population Mobility

First Street Foundation tracks events resulting in at least $1 billion in damage, including wildfires, droughts, floods, hurricanes and winter storms, and while all states are affected, there are notable concentrations.  

“Of the $2.65 trillion in billion-dollar damages that we’ve seen since 1980, over half of it is accounted for by four U.S. states: California, Texas and Florida plus Louisiana. We can see this sort of hyper-concentration of damages and exposure in these areas,” Porter said.  

The study focused on flood risk; however, all climate-related risk factors are likely to impact migration within the U.S. The cross-state migration trend that has been going on for decades is dominated by moves “from the Rust Belt to the Sun Belt,” Porter said. “But we’re also seeing information that people are starting to take climate into account.”  

While there is interstate migration, they are vastly outweighed by moves within a state or county, and those local moves are where climate risk is layered with personal experience, Porter said.  

“You’re starting to take into account things like local knowledge and information about the community that you don’t have when you move across state lines. If I moved in my neighborhood, I know what streets flooded during a heavy rainfall, I know what areas to avoid during coastal flooding,” he said.  

34.5% of the population live in census blocks that have already been impacted. | First Street Foundation

Water’s Siren Song

People have a love-hate relationship with water: They are drawn to areas with beaches, rivers and lakes, but there comes a point where the increased flood risk drowns out their siren call. “We tend to see the densest areas, both within cities and across the country, close to water,” Porter said. “As you get more and more properties at risk of flooding within a community, we’re seeing this increase in population until you hit a certain tipping point and then we’re seeing a level-off or even decline.” 

While climate abandonment areas had net population declines, risky-growth areas “grew by about 17.4 million people from 2000 to 2020, relatively significant growth for those 2.1 million blocks, but the model showed that they would have grown to about 21.5 million people if it wasn’t for the flood risk,” Porter said. Those areas were so attractive based on amenities, job opportunities and other factors that they outweighed the flood risk for many, but not all, people choosing a community to live in.  

People leaving climate abandonment areas often move locally, leading to what some have called climate gentrification. A disproportionate amount of climate abandonment areas are in growing metropolitan areas such as San Antonio, El Paso, Fort Worth and Houston in Texas, and Tucson and Phoenix in Arizona.  

“People don’t want to live in those flood-risky neighborhoods, even if they would still want to live in the same area,” Shu said.  For example, someone who still wants to live in Miami-Dade County, which has a lot of flood risks, is likely to consider neighborhood differences and make trade-offs, resulting in a migration from the lower-lying areas to higher elevations. 

Flood risk isn’t the only thing leading to population loss in climate abandonment areas. Of the 9 million in total population loss in those areas from 2000 to 2020, about 3.2 million could be attributed to flood risk while the other 5.8 million were related to other socioeconomic characteristics of a community, such as lack of opportunity in rural areas. Those areas tend to spiral downwards, with declining housing prices and a loss of local businesses eroding the city tax base and cutting services. 

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FERC Rejects SPP WEIS Market Power Rule

FERC rejected SPP’s proposal to modify its market power test for the Western Energy Imbalance Service, faulting a provision granting the Market Monitoring Unit discretion in applying the rules (ER23-2183).

SPP proposed tariff changes to address a finding in the MMU’s August 2020 WEIS Market Power Study, which identified a high level of structural market power in the WEIS market.

SPP said its residual supply index (RSI) — the ratio of capacity not owned by a market participant to total market demand — failed to consider the total capacity from affiliated market participants together. That created an opportunity for an entity to split its fleet of resources into multiple market participant registrations to avoid failing the test, the MMU said.

FERC’s Dec. 19 order approved new tariff language specifying that the RTO would consider together “all on-line resource capacity from any affiliate of the market participant.”

But the commission rejected a second change that would have allowed the MMU to exclude from the RSI calculations capacity associated with an affiliate if the monitor was convinced the participant maintained “safeguards and corporate controls to prevent coordinated or collusive market activity,” such as maintaining electronic permissions and access controls and physically segregating the personnel who make daily bid/offer or strategic market decisions.

FERC said the second change would undermine the first and thus was not just and reasonable.

“Accordingly, we reject the entire proposal as filed, but we note that SPP may resubmit a proposal that addresses the concerns described above,” the commission said.

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FERC Approves Settlement Reducing PJM Penalties for Elliott Underperformance

FERC approved a settlement between PJM and 81 parties to reduce the $1.8 billion in non-performance charges assigned to generators that did not meet their capacity obligations during the December 2022 winter storm (ER23-2975, EL23-53).

The commission’s Dec. 19 order lowers the penalties to approximately $1.25 billion, a nearly 32% reduction, and resolves the bulk of the 15 complaints generators filed over the charges. In a separate order, the commission rejected a complaint from Energy Harbor disputing how PJM factored a maintenance outage into its calculation of the W.H. Sammis coal generator performance shortfall.

“PJM appreciates the cooperation of its members who participated in the FERC-supervised settlement proceedings and reached this consensus-based resolution, allowing the PJM stakeholder community to focus on improvements and solutions going forward,” PJM General Counsel Christopher O’Hara said in an Inside Lines post regarding the commission’s order.

The agreement caps off months of settlement judge procedures the commission initiated June 5 resulting in the agreement reached in September. All of the complainants supported the agreement, with the exception of the Old Dominion Electric Cooperative (ODEC), which joined as a non-opposing party. (See Settlement over PJM Elliott Penalties Receives Broad Support.)

Because the collection process for the penalties already is well underway, reduction of the penalties will involve recipients of overperformance bonus payments returning a portion of their allocations. Under the capacity performance structure, underperformance penalties are paid out to generators that exceeded their expected performance during emergency conditions.

During the Dec. 20 Markets and Reliability Committee meeting, PJM Executive Vice President of Market Services Stu Bresler said staff are drafting an FAQ detailing how the settlement will be implemented, the effects it will have overall and how companies can calculate the change to their penalties and overperformance bonuses.

PJM and supporters of the settlement argued it would reduce market disruption that could result from penalties of that magnitude and protracted litigation about their legitimacy.

Chief Keystone Power and Chief Conemaugh Power raised the only objections to the settlement, but were overruled by the commission, which found the companies had lost their chance to be party to the agreement by waiting until after it had been filed with FERC to seek intervenor status and file a protest.

“Allowing entities to intervene in the new docket generated by the filing of a settlement, when such entities did not participate in the underlying dockets and settlement discussions, would run contrary to cases where the commission has disallowed parties to intervene for the first time after the parties have agreed to a settlement,” the order says.

The settlement left two issues raised by Energy Harbor and the East Kentucky Power Cooperative (EKPC) open for the commission to decide: how to calculate the penalties the Sammis facility is responsible for, and an argument the cooperative made that the capacity performance penalty structure and annual stop loss are unjust and unreasonable without a connection to generators’ capacity market revenues.

In its complaint, Energy Harbor argued that PJM had effectively disregarded a 300-MW maintenance outage the Sammis facility was on at the time of Winter Storm Elliott by subtracting the outage from the resource’s installed capacity (ICAP) value. The company said that was the wrong figure to look at, since it includes both committed capacity and uncommitted capacity the resource is not obligated to make available during emergency procedures. Instead, it made the case that PJM should have netted it against the performance shortfall it experienced — the difference between its expected and actual output used to derive the penalties.

PJM stated that excused outages, such as for maintenance, can reduce only a capacity resource’s performance shortfall and associated penalties if it is the sole reason the generator did not meet its obligation. In this case, PJM said forced outages Sammis experienced Dec. 23 and 24 accounted for the full shortfall.

“Even taking into account the maintenance outage of 300 MW, Energy Harbor should have been able to meet its expected performance. It failed to do so, because of the forced outages of Units 5 and 7. Hence, the maintenance outage was not the sole cause of Energy Harbor’s inability to meet its expected performance as the tariff requires,” the commission’s order says.

The EKPC complaint argued that basing the penalty rate and annual stop loss on the net cost of new entry (CONE), rather than the Base Residual Auction (BRA) clearing price, results in the potential for penalties being higher than the revenues a resource can earn in the market. The commission has yet to issue an order on that filing.

In a filing at the conclusion of the critical issue fast path (CIFP) process, PJM proposed to revise the calculation of the annual stop-loss limit to be based on the BRA clearing price and retain the penalty rate derived from net CONE. (See “PJM Steams Ahead with CIFP Filing Timeline After FERC Deficiency Notices,” PJM MIC Briefs: Dec. 6, 2023.)

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Minnesota PUC Tolerates Xcel Energy Cutting Off 20% of Distribution System Capacity

Xcel Energy is free to continue to apply a blanket 80% limit on its distribution system — limiting the amounts of community solar that can interconnect — after the Minnesota Public Utilities Commission’s decision last week.  

Minnesota regulators voted 4-0 at a Dec. 14 meeting against opening an investigation into Xcel Energy’s controversial policy of limiting the total capacity of the utility’s entire distribution system to 80% of its rated capacity (C-23-424). Xcel’s rule has been in place since March 2022.  

The utility has said the restriction is essential because a daunting number of community solar gardens is inundating its system and worsening congestion. It said it created the planning limit to reserve some hosting capacity on the lines as a safeguard. Minnesota’s community solar program lets ratepayers sign up for a portion of output from developers’ small solar farms. Xcel issues a bill credit for subscribers’ share of energy that flows back onto the grid. Currently, Xcel has more than 860 MW of community solar gardens on its distribution system.  

The Minnesota Solar Energy Industries Association (MnSEIA) and a group of more than 20 developers, clean energy organizations and individuals filed a complaint against Xcel’s practice in September. They argued that Xcel broke the law in sequestering a portion of its capacity and that 20% is too much cushion and unnecessary for the sake of reliability.  

MnSEIA said the PUC’s dismissal of its complaint amounts to regulators allowing Xcel to continue “arbitrarily limiting capacity of its distribution system.”  

During the hearing, MnSEIA Director of Policy and Regulatory Affairs Curtis Zaun argued state law prohibits Xcel from implementing sweeping interconnection rules without explicit PUC approval.  

“Xcel is effectively unregulated when it comes to interconnection practices,” he said, adding that Xcel doesn’t have a detailed analysis to back up its decision to shelf grid capacity.  

Zaun said the matter was about more than Xcel’s distribution limits. He said it strikes at the commission’s “authority, ability and responsibility to regulate utilities and thus its role in Minnesota’s clean energy future.”  

Zaun said the 20% capacity that Xcel proposes to reserve on its system is equal to 2.6 GW of generation and essentially wastes ratepayers’ money.    

Misgivings from Schuerger

Minnesota Commissioner Matthew Schuerger said he had reservations with Xcel’s program as it stands today. He said he didn’t agree with the limit if it amounts to Xcel setting aside a chunk of the distribution system only to “warehouse” it.  

Matt Schuerger, Minnesota PUC | NARUC

He said when the commission didn’t stop Xcel from moving ahead with the grid management program in January 2022, it did so only because there wasn’t sufficient information in the record for the commission to approve or reject it.  At the time, the Minnesota PUC opted to leave the capacity program to the utility’s engineering judgment.  

Schuerger said his understanding of equipment ratings is “they aren’t actually hard-edge limits.”  

“I think the details really matter in how we look at equipment ratings. On the bulk power system, we’re looking at dynamic ratings on equipment. The best practices and the research is moving towards the idea of dynamic ratings on distribution systems as well,” he said. “I’m struggling a little bit with this idea … that your equipment ratings should be some static, hard limit for all of time going forward.”  

Xcel Energy DER Integration Manager Dean Schiro said there’s a difference in ratings on the distribution system and the more flexible ratings of the transmission system. He said Xcel is trying to be conservative in the planning realm — rather than in operations — realizing that the utility doesn’t know what’s going to connect to the distribution system upwards of five years into the future.  

Schuerger pointed out that Xcel’s own load growth forecast “seems 180 degrees out of sync” with its proposal to limit capacity on the distribution system. Xcel predicts its 8.5-GW peak aggregate load will become 20.5 GW by 2052.  

Schuerger also said the program seems like a “large safety margin” and out of step with Xcel’s efforts to have more visibility into and operational controls on its distribution system.  

Schiro said Xcel doesn’t yet have flexible resources on the distribution system. He reminded regulators that resources wishing to interconnect to the distribution system are still firm and non-dispatchable.  

Xcel Energy Assistant General Counsel Jim Denniston said MnSEIA’s allegation that Xcel flouted the commission’s earlier order by moving ahead with the 80% threshold is “serious” and “troubling.”   

Xcel maintains it needs a distribution capacity limit to preserve reliability and keep load and generation in balance.  

“No utility should be forced to run its system to the very brink,” Xcel told the PUC in response to the complaint.  

Minn. Department of Commerce Recommends Investigation

The Minnesota Department of Commerce recommended the PUC open an investigation into Xcel’s practice to flesh out the record and allow experts to weigh in on the engineering logic behind the decision.  

Commerce attorney Sara Payne said an investigation would be important in helping establish whether the utility’s program is in the public interest and to what degree the commission has oversight of a utility’s engineering decisions.  

“I think the hope would be that an investigation could help provide enough information that the commission could provide guidance on where that line is from a legal threshold,” Payne said. She added that at a minimum, the PUC could at least get some “visibility into the issue from the engineers.”  

Payne said requiring some clarity and transparency now would be helpful for the PUC to address dockets down the road as DER continues to grow.  

Prior to the hearing, the Minnesota Attorney General’s Office also told regulators they should investigate Xcel’s planning limit.  

Schuerger said he was hesitant to open an investigation that would “chisel” the 80% or another figure in stone considering the grid modernization efforts on the horizon.  

“If that 80% buffer doesn’t get reduced over time, something is seriously wrong in my view. It better move over time,” Schuerger said.  

MnSEIA Executive Director Logan O’Grady said the limit hinders Minnesota’s progress towards 100% carbon-free energy.  

“This decision goes beyond that concern alone; it raises deeper concerns that Minnesota’s regulated utilities are free to act without clear authorization from regulators and with little regard for the wishes of Minnesotans who are seeking cleaner energy options, but whose choices have been blocked by the policy decisions of powerful, self-interested monopoly utilities,” O’Grady said in a press release following the decision.  

Even though regulators declined to investigate Xcel’s rating policy, they required the utility to reach out to and hold meetings with stakeholders to explain the rationale behind the 80% threshold.  

The commission will release a final order on the complaint in the coming months.  

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FERC Accepts SPP Compliance Filing on Order 881

FERC on Dec. 19 found SPP mostly in compliance with the directives of Order 881 (Docket No. ER22-2339-001).

But FERC directed SPP to clarify what entity is responsible for developing forecasts of ambient air temperatures. Those are used to calculate the ambient-adjusted ratings (AARs) and seasonal line ratings, but FERC said SPP’s proposed wording was ambiguous.

FERC rejected a request by SPP’s independent Market Monitoring Unit (MMU) to direct SPP to include language that places additional candor requirements on transmission owners. Order 881 did not impose such a requirement, FERC said, and a compliance filing is not an appropriate proceeding to address that issue for the first time.

FERC Order 881, issued Dec. 17, 2021, directed that transmission providers end the use of static line ratings in evaluating near-term transmission service, a move the commission said would improve accuracy and transparency and increase grid use.

Order 881 requires transmission providers to employ AARs for short-term transmission requests — 10 days or less — for all lines that are impacted by air temperature. It requires seasonal ratings for long-term service.

SPP submitted its first compliance filing July 12, 2022. In response, FERC issued its first compliance order May 18, 2023, finding several faults:

“SPP did not address whether or how its compliance filing requires SPP to use updated AARs as part of any market process associated with the day-ahead and real-time markets, including reliability unit commitment, as well as any look-ahead commitment processes or other such processes, as required by Order No. 881.”

Nor, FERC found, did the first filing address the requirement that RTOs and ISOs use AARs as the relevant transmission line rating for any seams-based transmission service offered.

FERC directed SPP to submit revisions as a second compliance filing by Aug. 1, 2023. SPP filed July 28.

The MMU filed its motion to intervene and protest Aug. 17. It said SPP’s proposal did not demonstrate how it would use AARs in its market processes and said such information should be included in the tariff.

The MMU also said the second compliance filing does not indicate which transmission line rating — AAR or seasonal — will be used for each of the integrated marketplace processes, and particularly the transmission congestion rights market.

The MMU argued that, given the frequent changes in temperature forecasts and line ratings, SPP must transparently set the time horizon for the ratings used in each market process.

SPP disagreed with the MMU, and for the most part, so did FERC.

In the Dec. 19 order, FERC said neither Order 881 nor the first compliance order directed SPP to use or to clarify specific line ratings in transmission congestion rights markets.

FERC also disagreed with the MMU’s assertion that the second compliance filing did not explain how SPP would use in its market processes a replacement line rating when it identifies an inaccuracy.

“Given that the tariff provides for use of seasonal line ratings as a default recourse rating when an AAR is unavailable,” FERC wrote, “which would include when there is an identified inaccuracy that cannot be resolved, we find that the tariff provides for replacement line ratings if an AAR inaccuracy is identified.”

The MMU further argued that the second compliance filing does not clearly delineate transmission owner and transmission provider roles and does not address transparency and accuracy of transmission line ratings and methodologies. But FERC said it had not imposed any such candor requirements on SPP.

FERC did not completely disagree with one of the MMU’s protests — the request for a transparent time horizon. That is not required, FERC said, but Order 881 does require transmission providers to explain their timelines for calculating or submitting AARs as part of their compliance filings.

SPP failed to do this in its first compliance filing, FERC said, so in its first compliance order, it directed SPP to submit by Nov. 12, 2024, a further compliance filing that explains those timelines.

In its order Dec. 19, FERC also accepted four tariff wording revisions SPP had proposed in its second compliance filing:

    • “[SPP] must establish and maintain systems and procedures necessary to allow Transmission Owners to electronically update Transmission Line Ratings at least hourly.”
    • “If an AAR for any interval is unavailable, Transmission Provider must use a recourse rating as the appropriate Transmission Line Rating.”
    • “In the event there is disagreement among entities on the calculated AAR of a tie line between neighboring Transmission Owners, the Transmission Provider must use the most limiting AAR in order to ensure reliability and that thermal limits are maintained.”
    • The term “available transfer capacity” will be changed to “available transfer capability” in the definition of Near-Term Transmission Service.

With FERC’s order, the second compliance filing becomes effective July 12, 2025, subject to the additional steps FERC directed regarding AARs.

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Christie Blasts FERC Transmission Incentives in PATH, Brandon Shores Orders

FERC Commissioner Mark Christie on Dec. 19 used orders on the canceled Potomac-Appalachian Transmission Highline (PATH) project and a $785 million reliability project in PJM to blast the commission’s “ridiculously generous” incentives for transmission developers. 

Christie wrote in a concurrence that FERC policy gave him no alternative but to approve an abandoned plant incentive for three Exelon subsidiaries assigned to build $785 million in transmission to address reliability problems expected from the scheduled closure of Talen Energy’s Brandon Shores coal-fired plant in Pasadena, Md. The incentive allows the utilities to recover all “prudently incurred” costs if the project is canceled for reasons outside of their control. 

But he used his concurring statement to renew his call for the commission to reevaluate that incentive as well as the construction work in progress (CWIP) incentive and the RTO participation adder (ER24-163). 

Christie also concurred with the commission’s approval of an uncontested settlement in the 15-year dispute over the abandoned PATH project, saying it cost ratepayers $250 million, although it was never approved by any of the three states in which it would have passed and “even though not a single ounce of steel was ever put in the ground” (ER12-2708, et al). 

Christie said the CWIP incentive “effectively makes consumers the bank for transmission developers,” while the abandoned plant incentive “effectively makes them the insurer of last resort.” 

“This incentive allows transmission developers to recover from consumers the costs of investments in projects that fail to materialize and thus do not benefit consumers,” he wrote. “Just as consumers receive no interest for the money they effectively loan transmission developers through CWIP, they receive no premiums for the insurance they provide through the abandoned plant incentive if the project is never built.” 

The Brandon Shores coal-fired power plant is scheduled to retire in June 2025, triggering $785 million in transmission upgrades. | Talen Energy

The RTO participation adder, which increases the transmission owner’s return on equity (ROE) above the market cost of capital, “is an involuntary gift from consumers,” Christie added. “There is something really wrong with this picture.” 

Looking ahead to 2024, Christie wrote, “as this commission considers other potential reforms related to regional transmission planning and development, it is imperative that incentives like the CWIP incentive, abandoned plant incentive and RTO participation adder are all revisited to ensure that all the costs and risks associated with transmission construction are not unfairly inflicted on consumers while transmission developers and owners stand to gain all the financial reward.” 

Exelon’s Baltimore Gas and Electric, PECO Energy and Potomac Electric Power Co. (Pepco) requested the abandoned plant incentive to build the transmission upgrades that PJM said are needed to address thermal and voltage violations that would result from Talen’s plan to close Units 1 and 2 of Brandon Shores on June 1, 2025. 

The utilities sought assurances they would be made whole if Talen withdraws its deactivation notice and either continues to operate the units or sell its injection rights to another developer. They also said the project could be undermined by transmission planned to deliver New Jersey and Maryland offshore wind generation. 

Exelon also cited the risk of opposition from landowners, noting the project will require the acquisition of about 50 acres of land in Pennsylvania for new and expanded substations, 1.25 miles of expanded rights of way in York County, Pa., and new facilities within existing rights of way in Maryland, requiring approvals from regulators in both states. 

Christie urged the commission to act on proposals to limit the RTO participation adder to the three years following a utility’s initial membership in an RTO (from its 2021 supplemental Notice of Proposed Rulemaking) and to eliminate the CWIP incentive (in its April 2022 transmission planning and cost allocation NOPR). 

“It is clear to me that the commission’s procedures and criteria for awarding the abandoned plant incentive should also be reconsidered,” Christie wrote. “In short, revisiting all these incentives is imperative at a time of rapidly rising customer power bills.” 

PATH Settlement

Christie also concurred on the PATH settlement, which the developers said “will facilitate the final wind-down and termination of the PATH companies.” (The commission directed PATH to notify it within 60 days whether they were withdrawing petitions for declaratory orders in dockets EL18-186 and EL18-187 that are not resolved by the settlement.) 

Christie said the settlement was significant because of the “major lessons — and warnings — it holds for long-term regional transmission planning driven by policy goals, the substantial costs that go with such projects and how FERC’s policies inflate those costs to consumers.” 

He said the commission’s formula rate structure, which gives developers a presumption of prudence when they file for cost recovery, “facilitated this assault on consumers, as it does regularly.” 

He also said PATH illustrates “the inherent dangers in approving for regional cost allocation long-distance projects based on a prediction (i.e., a guess) of what the generation mix will be in 20 years or more,” noting that PATH was originally part of “Project Mountaineer,” a plan to deliver mostly coal power over three high-voltage lines from West Virginia to East Coast load centers. 

“The lesson here is clear: For policy-driven long-distance, regional transmission projects affecting consumers in multiple states, it is absolutely essential that state regulators have the authority to approve — or disapprove — the construction of these lines and how they are selected for regional cost allocation and what that cost allocation formula is, if their consumers are going to be hit with the costs,” Christie wrote. 

The settlement, which was supported by FERC staff, calls for PATH to continue to use its current 8.11% ROE until its formula rate is terminated and payment of $9.5 million in refunds to customers. (See DC Circuit Reverses FERC on PATH Refunds.) 

Also approving the two orders were Chair Willie Phillips and Commissioner Allison Clements. James Danly, who attended his final meeting as a commissioner Dec. 19 and is presumed to be job hunting, did not participate. (See Secretary Bose and Commissioner Danly Honored at Their Final FERC Meeting.) 

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FERC Black Start Report Pushes Gas-electric Coordination

A study released Dec. 19 by FERC, NERC and the Texas Reliability Entity on black-start resource availability in Texas raises concerns about ERCOT’s dependence on natural gas to kick-start the grid during an emergency (AD24-5).

The study was launched in November 2022, following a recommendation by the commission and NERC’s joint inquiry into the winter storm that caused mass outages across Texas and the South Central U.S. in February 2021. (See FERC, NERC Release Final Texas Storm Report.) Staff focused on the availability of black-start and next-start resources and ERCOT’s procurement of black-start resources for its system restoration plan, while also assessing registered entities’ black-start resource testing, fuel-switching tests, fuel delivery infrastructure and other activities.

A black-start resource is a generating unit and its associated equipment that can be started without external support from the electric grid, or that is designed to remain energized without connection to the broader system. The first generator in a cranking path to be energized using power from the black-start unit is called a next-start unit.

Chanel Chasanov, FERC | FERC

The report indicated that ERCOT has well-defined processes for securing enough black-start resources to meet the needs of its restoration plan. However, ERCOT’s heavy reliance on natural gas for black-start and next-start generation could create problems. Presenting the report at the commission’s open meeting Dec. 19, Chanel Chasanov, of FERC’s Office of the General Counsel, said the study highlighted the “shared responsibility and need for the electric and natural gas industries to work together to plan for a blackout.”

Nine entities participated in the study, according to the report. The team aimed to identify participants that:

    • were subject to NERC reliability standard EOP-005-3 (System restoration from blackstart resources);
    • were located within ERCOT and possess different types of black-start resources;
    • had significant responsibilities during black-start restoration;
    • produced, processed and transported natural gas to black-start and next-start resources;
    • have experienced natural gas curtailments; and
    • have performed black-start resource testing under actual or anticipated conditions.

FERC, NERC and Texas RE staff reviewed documents provided by each participant and conducted on-site and virtual discussions to gain more information. After identifying best practices and opportunities for improvement among the entities, they produced several recommendations for addressing potential shortcomings.

The first set of recommendations applies to entities responsible for developing and implementing black-start restoration plans. Members of the study team advised entities to examine each black-start resource’s limits, including potential fuel issues and single points of failure.

Where possible, utilities should identify a wide range of options to incorporate into their plans, “beyond a reliance on traditional black-start resources,” the study says. Alternate options could include electric bypasses, HVDC ties and nonfuel energy resources, such as inverter-based resources and batteries.

To mitigate the risk of natural gas pipeline failures during outage events, the team suggested that entities add off-site gas storage options to their restoration plans. Report authors also recommended that owners of dual-fuel-capable resources be required to test alternate fuel options to verify they can perform when the primary fuel is unavailable.

Another group of recommendations was aimed at state regulators and other authorities with the ability to “facilitate and moderate engagement among the entities” involved in restoration. These stakeholders were advised to examine the potential impact of a blackout on the gas supply chain, which Texas RE Chief Engineer Mark Henry explained “could help the electric and natural gas industries better understand what action is required in a blackout and which electric and … gas entities are vital for black-start system restoration.”

The team also suggested that state and other authorities consider raising the priority of gas supply and transportation to black-start and next-start resources, as part of a coordinated restoration plan “that incorporates the needs of both the electric and natural gas industries.”

FERC Chair Willie Phillips thanked the team for their work and urged stakeholders to read the report.

“These recommendations are important. It really gets to the heart of what we’ve been talking about all year, which is reliability and resilience, and I cannot underscore how important it is that everyone pay close attention to the work that you’ve done,” Phillips said.

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ISO-NE Details Proposal for Regional Energy Shortfall Threshold

ISO-NE kicked off work to determine an acceptable level of energy shortfall risk for New England at the NEPOOL Reliability Committee’s meeting Dec. 18. 

The project is an offshoot from ISO-NE’s Operational Impact of Extreme Weather Events study, a collaboration with the Electric Power Research Institute to use historical extreme weather scenarios and the expected future resource mix to quantify energy shortfall risks for 2027 and 2032. (See ISO-NE Study Highlights the Importance of OSW, Nuclear, Stored Fuel.) 

The study also led to the development of the Probabilistic Energy Adequacy Tool (PEAT), which the RTO plans to use in future resource adequacy studies. The Regional Energy Shortfall Threshold (REST) would apply to the risk quantified in PEAT studies. 

“Establishment of the REST is intended to define the level of energy shortfall risk beyond which a set of additional, future solutions may be required,” said Stephen George, ISO-NE director of operational performance, training and integration. 

While the first phase of the project is not intended to outline solutions for when shortfall risks are deemed too high, ISO-NE is planning to pivot to solutions once the REST is established. 

“Possible solutions to reducing energy shortfall risk to within REST tolerances could range from market designs, to infrastructure investments, to dynamic retail pricing and responsiveness by end-use consumers,” George said. 

He added that ISO-NE will also use the project to consider the frequency and timescale of PEAT studies, and whether they should be conducted on an annual, seasonal or in-season basis. He noted that the PEAT framework could be used to better understand both long-term and short-term resource adequacy risks. 

ISO-NE is planning to collaborate with the states and stakeholders to establish the risk threshold, George said. The RTO intends to present an initial proposal in May, with some opportunity for stakeholder input prior to the proposal. 

“ISO envisions a multimonth process spanning several RC meetings to allow for proposals, feedback, counterproposals and finalization of the REST toward the end of 2024,” George said. 

Resource Adequacy Assessments

ISO-NE Technical Manager Fei Zeng presented to the RC proposed changes to the Resource Adequacy Assessment (RAA) modeling as part of the ongoing resource capacity accreditation (RCA) project.  

The changes would affect the capacity values of different resource types in the Forward Capacity Market and are intended to more accurately capture resources’ reliability attributes. 

“RAA is used to establish capacity requirements and demand curves and, under RCA, resource accreditation,” Zeng said. “Improvements to the RAA will better identify when loss-of-load events occur and their duration and will improve how individual resource performance is reflected during these events.” 

Zeng said the main motivations for the RAA changes are to more accurately model system conditions; improve the assessment of resource performance and interactions between resources; increase the modeling consistency between resource types; and “better reflect the correlation between resources’ performance and system loading conditions and weather.” 

Capacity Accreditation of Seasonal Tie Benefits

Zeng also presented changes to the evaluation of tie benefits in the RCA project, aimed at better capturing seasonal differences in values. 

Tie benefits quantify the reliability contributions of grid connections between New England and neighboring regions. While current values are based on summer peak load conditions, the RCA project requires a more accurate assessment of winter tie benefit values, Zeng said. 

Zeng said the tie benefits provided by New York are similar during winter and summer because the state has a similar load profile to New England’s. He noted that the benefits “are mainly the result of resource random outages and diversity.” 

Because Quebec and the Maritime Provinces are winter-peaking systems, the regions’ tie benefits to New England are likely lower in the winter than in the summer, when the regions have more surplus capacity available, Zeng said. 

For the RCA process, which is not intended to change the underlying tie benefit calculation methodology, ISO-NE is planning on using an approximation approach to quantifying winter tie benefits. This approach would approximate the winter tie benefits from New York, Quebec and the Maritimes based on the simulated summer tie benefits from New York. 

Based on this approach, the winter tie benefits from Quebec and New York would be equal to the latter’s simulated summer tie benefits, while the Maritimes’ winter tie benefits would be set at half of this value. 

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DOE Issues Final Guidelines for National Transmission Corridors

The Department of Energy has released its final guidelines for the designation of National Interest Electric Transmission Corridors (NIETCs), which are narrowly defined areas where transmission is urgently needed to ensure power reliability and affordability and to advance “important national interests.”

DOE was authorized to designate such corridors in a “nonbinding process” through the Infrastructure Investment and Jobs Act, according to the guidelines issued Dec. 19.

As defined in the guidelines, a NIETC is “a geographic area where … DOE has identified present or expected transmission capacity constraints or congestion that adversely affects consumers. … One or more transmission projects could be located within that geographic area to alleviate such constraints or congestion.”

NIETC designation “unlocks” federal money and permitting tools to accelerate transmission construction, such as programs that allow DOE to sign on as an anchor off-taker for transmission projects, and direct loans made available by the Inflation Reduction Act.

DOE announced its first proposed off-taker agreements in October, with up to $1.7 billion invested in three interstate transmission projects. (See DOE to Sign up as Off-taker for 3 Transmission Projects.)

The IIJA also authorized FERC to issue permits for transmission projects within a NIETC if a state lacks authority to issue a permit, has delayed action on a permit application for more than a year or has denied the application.

The guidelines lay out a four-step process for NIETC designation: information collection on potential NIETCs; the publication of a preliminary list of proposed NIETCs; completion of environmental or other reviews, “robust public engagement” and the release of draft NIETC designation reports; and one or more final NIETC designation reports with related environmental documents.

“Improving and expanding national transmission infrastructure is essential to not only meeting President Biden’s clean energy goals, but also to ensuring that people across the country have access to resilient, affordable power,” Maria Robinson, director of DOE’s Grid Deployment Office, said in a DOE press release.

“Consumers are frequently harmed from a lack of transmission infrastructure, which can directly contribute to higher electricity prices, more frequent power outages from extreme weather and longer outages as the grid struggles to come back online,” according to the press release. “While these needs are urgent, building and expanding transmission often requires several years of permitting, siting and regulatory processes, especially if the line extends through multiple states and regions.”

‘Any Interested Party’

DOE was first authorized to designate transmission corridors in the Federal Power Act of 2005, according to a report from the department’s Electricity Advisory Committee. The law also allowed FERC “backstop” permitting authority — that is, allowing the commission to issue a permit even if a state was opposed to a project. Those provisions were ruled unconstitutional because they did not provide clear enough definitions of what conditions would trigger the backstop authority.

The IIJA amended the 2005 law to provide more clarity on DOE’s ability to designate the renamed NIETCs and FERC’s ability to permit interstate or interregional transmission.

The final guidelines incorporate feedback DOE received in the 112 comments it received following the Notice of Intent and Request for Information on the NIETC designation process, which it issued in May. For example, state officials, RTOs and advocacy groups were concerned that transmission developers might have too much influence in the NIETC designation process. (See States, RTOs Caution DOE on Transmission Corridors.)

The guidelines acknowledge this feedback and open eligibility to provide information and suggest corridors to “any interested party.”

“DOE does not prioritize NIETC designation based on which interested party submits information and recommendations. … As commenters suggest, opening eligibility may spur collaborative transmission development among traditional developers, load-serving entities (including public power entities and Indian tribes), states and local governments, and others.”

Robinson similarly stressed that DOE has pursued “meaningful, collaborative and widespread stakeholder engagement into our NIETC designation process to make sure we can clearly identify the areas that are the nation’s highest priorities for transmission and bring critical infrastructure there first.”

The release of the 66-page guidelines will kick off a comment period that will run through Feb. 2. DOE is targeting spring 2024 for a preliminary list of potential NIETCs.

NIETC vs. Transmission Planning

In evaluating potential NIETCs, the guidelines state that DOE’s National Transmission Needs Study, also released in October, will be a primary, but not the only, source of information for corridor designation.

The triennial report provided a breakdown of regional and interregional transmission needs, pointing to the higher electricity prices and reliability concerns grid congestion and constraints can have on consumers. From 2019 to 2020, the guidelines say, “congestion on interfaces across all [Western non-RTO/ISO] markets (day-ahead, 15-minute and 5-minute) increased by 74% from $152 million in 2019 to $263 million in 2020, primarily due to increased congestion.”

Looking ahead, the guidelines predict the effects of inadequate transmission will intensify. Massive growth in interregional transfer capacity may be needed, such as a 255% increase between New England and New York.

The guidelines’ summary of Needs Study suggests all regions may benefit from NIETCs. But, again noting stakeholder input, the guidelines stress the NIETC process isn’t intended to disrupt or supplant, but to complement existing transmission planning.

“In particular, DOE can use the NIETC designation process to identify valuable areas for transmission development that these existing transmission planning processes may not be identifying,” the guidelines say. “Existing transmission planning processes are largely constrained by their focus on regional or local needs, whereas the NIETC designation process can examine interregional needs.”

DOE also will use a “threshold need determination” to help identify possible NIETCs, based on the current status and future expectations of congestion or lack of capacity that may affect consumers, the guidelines say. Only areas that pass that screening will continue in the designation process.

Advocates and industry analysts are still reviewing the guidelines, but they shared initial reactions with RTO Insider.

Rob Gramlich, president of Grid Strategies, a research and consulting firm, said he’s glad to see DOE moving ahead with the process, but cautioned “it is better for all parties involved for the process to focus on actual routes which the … process allows. If they are not using that, they will need to find another way to focus on meaningful, narrow corridors.”

Elise Caplan, vice president of regulatory affairs at the American Council on Renewable Energy (ACORE), said her organization “supports DOE’s preliminary finding that the greatest value for NIETC designation will be in geographic areas where DOE has found a need for increased interregional transfer capacity.”

“DOE also properly critiques the shortfalls in transmission planning and the absence of planning for larger-scale, regional and interregional transmission ‘that may address multiple transmission needs in a wider area more cost effectively than the piecemeal transmission expansion that dominates today,’” Caplan said. “ACORE supports the use of the NIETC designation process as one of many tools to address this shortcoming.”

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New Jersey EV Charger Bill Sparks Scrutiny of Demand Charges

A bill before a key New Jersey Senate committee that seeks to accelerate the installation of direct current fast chargers (DCFCs) by giving commercial charger operators a break on rates sparked a battery of concerns over who should pick up the tab.  

Developers, electric vehicle advocates and environmentalists expressed concerns about the bill, S3914, in a hearing Dec. 18 of the Senate Environment and Energy Committee. The bill would require electric public utilities to submit new tariffs on commercial charging station operators for approval to the Board of Public Utilities (BPU). It would require the tariffs to be an alternative to “traditional demand-based rate structures.” 

The tariffs also would be designed to “establish cost equity between commercial electric vehicle tariffs and residential tariffs” so the entire burden does not fall on the charging station operator. The bill is designed to create an investment environment that would promote third-party investment in electric vehicle (EV) charging technology. 

Demand charges are triggered by an unusually high peak in power consumption, at which point the customer is billed an extra rate because the provider must invest more to meet the higher-than-normal power demand. That contrasts with energy charges that determine customer payments based on the amount of power used over a sustained period. 

Critics of demand charges in the EV charging environment say charging station operators could end up paying high electricity charges even though the overall use of the charging point is low, a scenario more likely when there are relatively few EVs on the road. That would occur, for example, if three EVs charged at the same station at once, pushing up momentary demand and triggering a relatively high demand charge, even though the site gets little use most of the month. 

The committee heard discussion on the bill, but did not vote, in line with the directive in advance of the meeting by Chairman Sen. Bob Smith (D), the bill’s sole sponsor, who sought only to collect public input. The committee is one of the most prominent voices on clean energy in the legislature, which will conclude its business Jan. 8.  

Smith, who expects to offer the bill in the next legislative session, said he heard compelling testimony that day that “the places where the high-volume charging equipment is succeeding, and it’s being built in, are areas where there’s a volumetric charge rather than a charge based on the maximum utilization during three minutes of the year.” 

Encouraging Charger Investment

Speakers at the hearing took differing positions on how to balance the need to stimulate charging site development with a sense of fairness in deciding who benefits from the installation, and so should help pick up the cost. 

The bill requires the new tariffs be shaped to avoid demand charges for commercial customers who own or operate electric vehicle charging systems. 

“Rates for electric distribution in the tariff shall be designed to encourage investment in faster, higher-powered electric vehicle charging facilities and shall include comparable costs per megawatt-hour for both higher-power and lower-powered direct current fast charging facilities,” the bill states. 

Jigar Shah, head of energy services at Electrify America, a charger development company, welcomed the requirement. He said demand charges are an “additional levy” that effectively mean commercial customers are treated differently than residential customers.  

Demand charges originally were designed to set rates on manufacturers who would have high, sustained peaks, rather than the short-term peak of a DCFC charger, Shah said. He said his company’s experience installing chargers has shown that a single charging point with four to six chargers at a New Jersey location could trigger demand charges of more than $350,000 a year. 

“The financial risk posed by this is cost-prohibitive to investment in further charging stations in New Jersey,” he said. 

Who Benefits From EV Use?

Other speakers expressed concern about the need for equity in who would pick up the tab if demand charges were not used. 

Doug O’Malley, director for Environment New Jersey, said the bill fails to clarify how costs will be distributed between customers and ratepayers. 

“We do believe that all customers benefit from electrification, not just those that are charging,” he said, in part by reducing electricity rates and curbing emissions. 

Because charging benefits the grid overall, he said, costs as a should be borne by the entire rate base. He urged the committee to take time shaping the bill, in part because “usage and consumption patterns for public fast charging is changing pretty significantly.” 

The state Division of Rate Counsel, in a Dec. 15 letter to the committee, also expressed concerns about where the cost burden might land. Brian O. Lipman, the division’s director, wrote that the bill “could unfairly shift costs from private businesses responsible for the costs of electricity to all other ratepayer customer classes through higher rates.” 

Demand charges are an important part of an electric utility’s rate design, intended to ensure it builds and maintains a “distribution system that is ready to serve the customer’s load at all times,” Lipman wrote.  

 “If demand charges are waived for certain customers who are putting the greatest demands on the grid, other customers, who use far less electricity, will ultimately pay for them through rate increases.” 

Lipman noted that the BPU, recognizing that demand charges play an “important role … in forming just and reasonable rates,” has taken steps to address the issue in connection with EV charger operation. Utilities offer “demand charge rebates” to some customers, and the BPU on Nov. 17 approved a package for Basic Generation Service that allows utilities to implement similar benefits to DCFC customers, he said. 

Kassandra Damblu of ChargeEVC New Jersey, an EV advocacy group, said the bill contains no consideration of “who pays for this discounted market structure.” In addition, she said, the rates should be flexible enough to reflect the usage patterns of the equipment over time. 

“As chargers get more use, the need for these types of rates decreases, so they should not be considered as a permanent solution, which is the case in this legislation,” she added.