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November 2, 2024

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ISO-NE Market Monitor Reports Decreased Winter Energy Costs

ISO-NE wholesale market costs were down 23% for the winter of 2023 compared to 2022, said the RTO’s Internal Market Monitor (IMM) at the Markets Committee meeting on Tuesday. The decrease was driven by a 29% drop in energy costs, which was largely a result of the 37% decrease in natural gas prices compared to the previous winter.

While wholesale costs declined, capacity market costs increased by 18%, or nearly $100 million, due to the supplemental payments to the Mystic 8 and 9 generators — the main customers of the Everett LNG import terminal — which totaled $213.5 million.

ISO-NE entered into an agreement in 2022 with Constellation Mystic Power to keep the generators operating through May 2024. The RTO justified the agreement to bolster fuel security in the region, but the agreement has been subject to intense criticism from a range of stakeholders.

“The net costs passed through the agreement so far have been astronomical: more than $436 million over the first ten months of the two-year term,” per a May FERC filing on behalf of a group of New England consumer-owned utilities (ER18-1639). “Most of those costs have resulted from [Constellation] buying — and then selling at a loss, burning uneconomically, or otherwise disposing of — fuel that Mystic did not need.”

The IMM noted in its presentation that relatively high winter temperatures led to lower average and peak loads for 2023. The average load was down by about 4% compared to the winter of 2022.

The region did experience two major cold snaps Dec. 24-27 and Feb. 3-4. On Dec. 24, the region faced its first pay-for-performance (PfP) capacity scarcity conditions since 2018, due to a combination of factors including low temperatures, a reduction in net imports, and several gas and dual-fuel generation plants failing to supply power.

“Most resources that tripped were older generators that run infrequently,” said Kathryn Lynch of the IMM. Lynch said these resources totaled approximately 2,180 MW of capacity.

The IMM said PfP credits and charges totaled $35.9 million during the scarcity conditions, with most charges incurred by gas and dual-fuel generators, while most credits went to imports, nuclear and pumped storage.

Generation from oil spiked during the two periods of extreme cold weather, making up 20-26% of generation during these stretches. Overall, oil generation decreased relative to 2022 and made up a small fraction of overall generation.

Technical Difficulties

ISO-NE said it has paused discussions on its Resource Capacity Accreditation (RCA) project due to a software error related to how it models LNG inputs for gas generation plants.

“The software significantly restricted LNG available to the gas resources,” said Tongxin Zheng of ISO-NE.

The RTO is developing the RCA modeling to project the reliability and availability of energy resources, and it will use the modeling to determine the amount of capacity a resource could receive in the Forward Capacity Market.

“The preliminary evaluation after correcting the software effectively results in negligible reliability risk in the model for winter under FCA 16 assumptions,” Zheng said. “Further evaluation is needed to determine whether the winter risk level in the initial results containing the error [nearly complete elimination of LNG in the software] is reasonable.”

The RTO previously hoped to implement the RCA modeling for the 19th Forward Capacity Auction, which is scheduled for 2025 and will determine capacity obligations for 2028/2029. Zheng said the software will impact the project schedule.

“ISO is reviewing its options and plans to share further information with stakeholders ahead of the June NEPOOL Participants Committee meeting,” Zheng said.

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Nevada Lawmakers Pass Bills on Utility Market Risk, Clean Trucks

The Nevada Legislature wrapped up its 2023 regular session by passing bills related to integrated resource planning for electric and gas utilities, along with a bill creating a zero-emission truck incentive program.

Assembly Bill 524 passed on a 20-1 Senate floor vote just hours before the legislature adjourned at 11:59 p.m. on Monday.

Assemblyman Howard Watts (D) introduced the bill with the goal of reducing electric utilities’ reliance on the open energy market to acquire sufficient supply. That in turn might improve electric reliability and reduce consumer costs, he said.

The bill would require utilities to include in their integrated resource plans a scenario in which they acquire enough energy resources to close their open position. Although that scenario must be evaluated, it wouldn’t necessarily be the one chosen. (See Bill Would Require NV Energy to Examine Market Reliance.)

NV Energy opposed the bill, saying the legislature should go further by calling for utilities to quickly close their open positions.

AB 524, which previously passed unanimously in the Assembly, now goes to Gov. Joe Lombardo for a signature. In a March executive order, Lombardo called for the state’s “advancement of energy independence.”

The state’s legislature meets every other year in a 120-day session. Although the regular session has ended, Lombardo is expected to call a special session on unresolved budget issues.

The 2023 legislature also passed Senate Bill 281 by Sen. Rochelle Nguyen (D).

The bill would require natural gas utilities to file a plan every three years, similar to the IRPs filed by electric utilities. The bill aims to improve the transparency of gas utility planning. (See Nev. Bill Would Require Gas Company Efficiency, GHG Plans.)

The Senate and Assembly both unanimously passed the bill, which was backed by Southwest Gas.

Zero-emission Truck Incentive

Another bill introduced by Watts this year was AB 184, which directs the Nevada Division of Environmental Protection to work with the state Department of Transportation to establish a Clean Trucks and Buses Incentive Program.

The incentives would be funded through the federal Carbon Reduction Program, part of the Infrastructure Investment and Jobs Act.

Nevada will receive an estimated $57 million over five years through the federal program. Of that, 35% is flexible funding that could be applied to the incentive program, Watts said during a hearing this month before the Senate Natural Resources Committee. No state funding would go toward the incentives.

The incentives would be for the purchase of a zero-emission medium- or heavy-duty truck, including a battery electric or hydrogen fuel cell vehicle. Base incentive amounts would range from $20,000 for a Class 2b truck to $175,000 for a Class 8 truck.

Increases to the base incentive would also be available in some cases. For example, a small business could receive a 20% increase to the base incentive, and a disadvantaged small business, such as one owned by a minority, woman or veteran, would be eligible for a 5% increase. A truck buyer could combine up to two base incentive increases.

Independent truck operators would be eligible for a 33% increase to the base incentive amount, but they wouldn’t be able to add on the small business increase.

The incentives would be available to businesses, nonprofits, and state and local government agencies. Watts said the idea was to bring the cost of a zero-emission truck in line with that of its diesel counterpart.

Andrew MacKay, executive director of the Nevada Franchised Auto Dealers Association, said zero-emission trucks are cost-prohibitive for most independent truck operators and small operators.

“This bill’s transformative,” MacKay said during the committee hearing. “It’s going to put these people in a position … of being able to afford these vehicles.”

Another bill by Watts adds new requirements for state automobile fleets. AB 262 requires the state to give preference to vehicles that minimize emissions and give consideration to the lifetime cost of the vehicle when making purchasing decisions, “to the extent practicable.”

Lombardo signed the bill on Monday.

Ben Prochazka, executive director of the Electrification Coalition, said Tuesday that electric vehicles are typically less expensive to operate than those with internal combustion engines.

“AB 262 will save Nevada’s taxpayers money and signal that the state is demonstrating leadership as the U.S. rapidly accelerates toward transportation electrification,” Prochazka said in a statement.

Yucca Bill Fails

Bills that failed during the 2023 legislative session include Senate Joint Resolution 4, introduced by state Sen. James Ohrenschall (D). SJR 4 would have urged the federal government to use Yucca Mountain for the development and storage of renewable energy. The site, about 100 miles from Las Vegas, has been eyed as a disposal site for the nation’s high-level radioactive waste. (See Nevada Resolution Seeks to Bring Renewables to Yucca Mountain.)

But SJR 4 missed the deadline for passage from its first committee, Senate Natural Resources.

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Developer Seeks to Terminate SouthCoast Wind PPAs

SouthCoast Wind Energy is moving to end its offshore wind power purchase agreements with three Massachusetts electric distribution companies.

The company said it will continue developing the project in federal waters south of Martha’s Vineyard while the parties seek a solution, but that the terms of the PPAs they negotiated in 2020 and amended in 2022 are untenable, given rising costs.

SouthCoast, formerly Mayflower Wind Energy, is a joint venture of Shell New Energies and Ocean Winds North America. It holds an offshore wind lease area with the potential for up to 2,400 MW of power generation and was to supply 1,200 MW to Eversource Energy, National Grid and Unitil.

In October, SouthCoast asked the Massachusetts Department of Public Utilities to suspend the PPA proceedings for a month so the parties could consider recent economic changes — including inflation, interest rates and material shortages — that made the PPAs financially untenable.

Around the same time, Avangrid made a similar request for the 1,200 MW of PPAs with the same three utilities for output from the Commonwealth Wind project it is developing.

The utilities declined to negotiate, and the DPU rejected the requests.

Avangrid dug in its heels and moved to terminate the PPAs, setting in motion a process that landed in Suffolk County Supreme Judicial Court four months ago. The company says it remains committed to Commonwealth and would like to rebid the project in Massachusetts’ next offshore wind solicitation.

SouthCoast backed down after the DPU rejection, at least publicly. It maintained that the financials were untenable but said it would work toward a solution. Apparently, it did not find one.

As of press time, there still were no official filings posted by the DPU, but SouthCoast CEO Francis Slingsby on Friday submitted testimony to the Rhode Island Energy Facility Siting Board, which is considering SouthCoast’s request to run one of the project’s export cables underwater and underground through Rhode Island on its way to Massachusetts. Slingsby argued that the board should not suspend its consideration of the transmission line application until new PPAs are in place because doing so would delay or jeopardize the project.

Even as it seeks better financial terms, SouthCoast has secured interconnection queue positions for the offshore wind farm and continues preparatory work, with more than 75 full-time employees on the job and a roughly $100 million development budget for 2023, Slingsby said. He expects the U.S. Bureau of Ocean Energy Management to issue a Record of Decision on the project in December.

But SouthCoast cannot attract financing with the existing PPAs, he said, because they are low-priced and have no indexation. The latest Massachusetts offshore wind solicitation addresses those concerns by allowing for inflation-indexed pricing, Slingsby said. SouthCoast plans to compete in that and/or other future rounds of bidding in New England, he said.

In a statement SouthCoast said it is open to solutions other than terminating the PPAs. But even after factoring in the cost of termination, any resulting penalties and lost tax incentives, terminating the PPAs is a better option than proceeding with them as written, it said.

Economic Headwinds

This latest development will not help Massachusetts reach its statutory goal: 5,600 MW of offshore wind online by 2027.

Gov. Maura Healey last month announced the draft of the state’s fourth offshore wind solicitation would seek proposals totaling up to 3,600 MW of generation capacity.

That — combined with the 800-MW Vineyard Wind 1 now under construction and SouthCoast — would reach the desired number of megawatts, if not the deadline.

Without SouthCoast or Commonwealth, Massachusetts falls short.

A spokesperson for Healey’s Executive Office of Energy and Environmental Affairs on Tuesday said, “We encourage all parties to find clarity on the next steps before the fourth offshore wind solicitation becomes active.”

The U.S. is late to the offshore wind sector: 32 years after the first commercial offshore wind farm went online in Denmark, U.S. waters host just 42 of the 63,200 MW of offshore generation installed worldwide.

As the public and private sectors try to create an industry almost from scratch, costs and logistics are proving to be challenges. The Northeast coast is the early focal point of development efforts, and the projects and proposals there are feeling the brunt of headwinds facing the industry.

Besides SouthCoast and Commonwealth, recent examples include:

      • Rhode Island’s latest offshore wind solicitation attracted just one proposal, and the wording of Rhode Island Energy’s public response indicated it might be expensive.
      • Avangrid has said it would ask Connecticut for a PPA adjustment on its Park City Wind project.
      • Ørsted has said it would take a $365 million cost impairment on its Sunrise Wind project in New York and has said returns on its Ocean Wind 1 project in New Jersey were not what it had hoped for.

On a brighter note, Avangrid has said Vineyard Wind 1 locked in supply contracts before the economic headwinds rose, averting a financial crunch.

The Electric Power Research Institute told NetZero Insider the financial problems experienced by SouthCoast and other projects are not unique to them or to the offshore wind industry but are exacerbated by the newness of the sector in the U.S.

“Offtake agreements are negotiated when the project is in the relatively early stages of permitting, with a five- to seven-year lag before permits are approved and an eventual final investment decision is made,” Offshore R&D Lead Curtiss Fox said via email Tuesday. “With the continuous and dramatic cost declines for offshore wind over the past decade, it would be reasonable to assume those would continue with some limited risk. However, the implications of economy-wide inflation seen over the past two years have changed those underlying assumptions.”

Fox said last year’s Inflation Reduction Act will likely boost momentum in the U.S. offshore wind industry and expand its supply chain, but the rest of the world will be attempting to do the same thing at the same time.

“The global demand for offshore wind continues to expand dramatically, with Europe alone looking to expand capacity in the North Sea to 120 GW by 2030, up from nearly 28 GW today, and to reach 300 GW by 2050,” he said. “With the initial tranche of U.S. projects heavily leveraging EU supply chain capacity, the U.S. may not be able to rely on global excess capacity and will need to continue investments into offshore wind manufacturing, vessels and port infrastructure to achieve a sustainable offshore wind industry.”

[This story has been corrected. A previous version incorrectly identified the developer of the Commonwealth Wind project.]

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FERC Sends Elliott Complaints Against PJM to Settlement Judge

FERC on Monday authorized settlement judge procedures to resolve about a dozen complaints that generators filed against PJM’s assessment of penalties for underperformance during the December 2022 winter storm, also known as Elliott (EL23-53, et al.).

“Given PJM’s interest in finding a resolution to the issues raised in these proceedings — along with parties’ general collective willingness to engage in settlement procedures — we find that these procedures are a reasonable first step,” FERC said. “The commission has previously found that providing parties the opportunity to enter into a mutually acceptable settlement of highly contested and complex issues is superior to years of ongoing litigation which, as PJM notes, could be disruptive to the market.”

PJM requested settlement judge procedures in April, maintaining that it had properly followed its emergency procedures and that all penalties were valid. But the RTO also said there is value to seeking rapid resolution rather than engaging in years of litigation that could negatively impact market participants beyond the penalties themselves. (See PJM Seeks Settlement over Elliott Nonperformance Penalties.)

“The capacity market also is designed in large measure to signal the need for new capacity resource investment, and the expectations of the financial and investment community accordingly are an important backdrop to the operation of this market,” PJM said. “Timely, consensual resolution of these disputes thus could, potentially, help support the long-term health of the resource adequacy construct in the PJM region.”

By folding the protests under a global proceeding, PJM argued that it could promote consistency in settlement outcomes, if possible.

The RTO applauded the order Tuesday as providing a possible pathway for resolving the complaints.

“PJM appreciates the commission’s order establishing global settlement judge procedures to pursue a potential resolution of disputed nonperformance charges and the related complaints arising from Winter Storm Elliott,” PJM said.

Separately in May, PJM urged the commission to reject the complaints, arguing that its Capacity Performance rules were clear and that the RTO followed its tariff. (See PJM Urges FERC to Deny Winter Storm Complaints.)

FERC left the scope of the settlement proceedings open to all issues that have been raised in the complaints, which include arguments that PJM was not permitted to fulfill non-firm exports during performance assessment intervals, generators not dispatched or scheduled were penalized, and PJM’s forecast was incorrect and played a role in the cause of the emergency.

The order provides 10 days for the chief judge to appoint a settlement judge for the proceeding, with parties able to submit recommendations in that time. If the settlement judge reports that progress is not being made toward an agreement after 60 days, the chief judge may refer the complaints back to FERC; if a resolution appears possible, an extension of up to 30 days could be granted.

Constellation and Vistra had both filed protests to PJM’s request for the proceedings, arguing that the RTO’s filing was “premature and incomplete” and that each complaint should be decided on its own merits. If the commission granted PJM’s request, Vistra pushed for it to require that all interested parties be able to participate; specify that bonus payments remain due to generators that exceeded their obligations; and establish a legal framework regarding the filed-rate doctrine, PJM’s scheduling decisions, and the proper interpretations of PJM’s tariff and manuals.

“PJM’s motion for settlement judge procedures seeks to move resolution of the complaints in these proceedings behind closed doors and facilitate an opaque result that would most likely weaken the existing Capacity Performance framework. As noted, Vistra believes the best path forward is one that avoids settlement judge procedures altogether by the commission ruling on the merits of each complaint,” Vistra wrote.

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FERC Accepts SPP’s Planning Study Processes for TOs

FERC recently approved SPP’s tariff revisions to its transmission planning process that establish new study processes for transmission-owning members (ER23-567).

The commission in its May 26 order found the changes to be just and reasonable and not unduly discriminatory or preferential. It accepted them effective Feb. 6, as SPP requested. It said SPP’s proposal increases transparency into staff’s review of transmission owner (TO) projects and helps ensure those projects receive the “appropriate cost allocation.”

The grid operator’s revisions allow it to evaluate TO projects’ reliability impacts before their inclusion into the integrated transmission planning process and confirm that they are eligible for zonal cost allocation. Zonal reliability upgrades identified by a TO will only be eligible for zonal cost allocation if SPP can confirm they relieve a zonal planning criteria violation and conform to applicable facility design criteria.

If the projects don’t meet the criteria, they will be designated as sponsored upgrades and their costs directly assigned to the sponsoring TO.

Commissioners Allison Clements and Mark Christie jointly concurred with the decision, writing that SPP’s proposed revision is “consistent with existing precedent” and improves the status quo. However, they said the filing raised a much bigger concern about the need to ensure any future transmission development is cost effective, as expressed during a technical conference in October. (See FERC Tech Conference Highlights Regulatory Gaps on Transmission Oversight.)

“It is our hope that the commission addresses these issues in that proceeding, and we additionally encourage SPP to make further improvements to its process,” the commissioners said, noting that the RTO’s planning process “appears to have significant room for further improvement.”

Storage As Tx Assets

In a separate order issued May 26, FERC accepted SPP’s proposal to treat electric storage resources as transmission assets (ER22-2344).

The commission said the grid operator’s proposal to define storage as a transmission-only asset (SATOA) and add language addressing cost allocation and recovery, transmission planning, interconnection, market participation and market monitoring issues is just and reasonable and not unduly discriminatory or preferential.

SPP’s proposed framework results in the SATOAs’ selection only when they perform a transmission function. Under the RTO’s definition, the asset must be under SPP’s operational control and connected to the system as a transmission facility solely to support the system. It also must be identified or selected in planning processes as the preferred solution to resolve transmission issues.

SATOAs’ participation in the markets is limited to only charging from, and discharging to, the transmission system as necessary to provide the services for which it was issued a notification to construct. FERC said that under those circumstances, SATOAs are properly characterized as transmission assets and the costs of a SATOA are appropriately recoverable through transmission rates.  

“Because the operation of a SATOA would be limited to serving a transmission function, it is appropriate that a SATOA recover costs in the same manner as existing transmission facilities in the same transmission project category,” the commission wrote. “In addition, cost allocation for a SATOA is appropriately limited to the cost of the maximum capacity needed to address the identified transmission issue and is prorated on that basis if a SATOA of higher capacity is constructed.”

The American Clean Power Association and the Advanced Power Alliance led clean energy entities in requesting that FERC require SPP to add a restriction in its tariff on the use of SATOAs so they can be used only to address “non-routine” reliability transmission issues. They contended that the RTO’s proposed tariff language could permit SATOAs to be used for more routine transmission issues within each resource’s voltage parameters.

The commission declined clean energy’s request, noting that the proposal restricts a SATOA from resolving a transmission need for which a market solution exists. FERC said SPP will only evaluate a storage solution as a potential SATOA to address an identified transmission issue if it has unique characteristics or circumstances to meet transmission system performance requirements that are not available at comparable costs from other proposed solutions.

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PJM Stakeholders Complete 2nd Phase of CIFP

VALLEY FORGE, Pa. — PJM last week wrapped up the second phase of its Critical Issue Fast Path (CIFP) process to address resource adequacy concerns with two meetings about proposed changes to the RTO’s capacity market.

At May 30’s meeting, Constellation Energy proposed shifting to a prompt capacity auction held closer to the corresponding delivery year; the Consumer Advocates of the PJM States (CAPS) discussed states’ priorities and concerns around overhauling the Reliability Pricing Model (RPM); and American Municipal Power (AMP) presented changes to its conceptual design.

PJM also provided additional information about its contemplated switch to an expected unserved energy (EUE) model for measuring risk. (See PJM Presents Lessons Learned from Elliott, More CIFP Presentations.)

Thursday’s meeting saw presentations from the Natural Resources Defense Council on creating a seasonal capacity market; a former market design architect from ISO-NE providing information on a conceptual market design; Cornerstone Research’s Roy Shanker on his concerns about the current market structure; and Vistra on creating a credit market to value resource upgrades providing added reliability.

Stakeholders will begin developing formal packages during the third CIFP stage beginning June 14, when PJM will present its proposal.

Constellation Proposes Tighter Auction Schedule

Constellation’s Bill Berg said many of the inputs to the capacity auction could be more accurate and price signals could be improved if PJM holds capacity auctions six months to a year in advance of a delivery year. The status quo of holding auctions three years in advance makes it difficult to accurately forecast load and for generators to be sure whether they can procure firm fuel supply — a parameter PJM is considering having generators report prior to the auction.

Several stakeholders said the rationale for holding auctions three years in advance has been to allow the reference resource, currently a combined cycle generator, to be built between the auction clearing and the start of the delivery year to shore up capacity procurement shortfalls. Berg said investors monitor resource needs regardless of auction timing and are likely to make investments if they believe a region will be short on generation, regardless of auction timing.

Ryann Reagan, of the New Jersey Board of Public Utilities (BPU), questioned how a shortened time frame would interact with state retail auctions, noting that New Jersey has a three-year forward capacity product.

Berg responded that there’s a balance between price certainty and accuracy, which he believes is best weighed in favor of accuracy. Resources participating in state auctions with a longer lead time than a prompt auction would have to estimate PJM capacity prices when participating in state markets.

Constellation also suggested that compensating capacity resources at the end of the delivery year could improve performance incentives and lead to higher collections of any performance penalties the generator may accrue over the year.

While Berg said his company supports PJM’s proposal to set a minimum number of performance assessment intervals (PAIs) each year, market sellers must be able to reflect all risks and avoidable costs in their capacity offers.

CAPS Executive Director Greg Poulos said expanding the costs included in capacity market offers could run afoul of FERC’s 2021 order on PJM’s market seller offer cap (MSOC). (See Judges Skeptical of Capacity Sellers in PJM Offer Cap Dispute.)

“This seems like a dead-end to us because FERC already ruled on this,” Poulos said.

Berg also urged stakeholders to consider changes to the energy market, where he said PJM has put the onus of addressing reliability risks posed by forecast uncertainty and resource constraints, but it has had to resort to out-of-market actions to maintain operational reliability.

CAPS Outlines Advocate Concerns

As stakeholders discuss an overhaul of the capacity market, Poulos said state advocates are concerned about the Base Residual Auction (BRA) schedule, as well as how to ensure that market power is kept in check, performance incentivized and proper price signals are sent.

Advocates also lack firsthand insight into how the markets functioned during the December 2022 winter storm, also known as Elliott, making it difficult for them to evaluate proposals being discussed in the CIFP process, he said.

When considering changes to Capacity Performance (CP) penalties, Poulos said, it’s important to balance having penalties so high that generators risk bankruptcy after one event and having them so low that they don’t lead to better performance during future emergencies. Though performance was an issue during both the 2014 polar vortex and Elliott, he said CP likely did lead to increased readiness.

“The goal is not to bankrupt people — that is not helpful — but if you can’t perform, I don’t know what your value in this mix is,” Poulos said.

AMP Presents Revised Proposal

AMP revised the proposal it has been building throughout the CIFP process, which would replace the CP construct with a process for testing generators and penalizing them if they are not able to meet the amount of capacity they cleared. The changes aired May 30 would marry that concept with the proposed reworking of the performance penalty structure endorsed by the Members Committee last month but rejected by the PJM Board of Managers.

The revisions would shift the penalty rate and annual stop loss from being based on the net cost of new entry (CONE) to the BRA clearing price. AMP championed the language in the MC as a way of aligning market sellers’ capacity revenues with any penalties they’re assessed, while retaining an incentive to perform throughout the year.

Opponents of the language when it was before the MC argued that it would pose a reliability risk by cutting the penalty rate and stop loss by 90% without adding to requirements like winterization requirements.

PJM Presents Risk Modeling Analysis

PJM presented preliminary results of its analysis on the impact of switching to a reliability requirement based on an EUE model, which measures the amount of load that would go unmet during outages. The RTO currently uses a loss-of-load expectation (LOLE) model, which is a count of the number of outages expected. (See PJM, Stakeholders Present Initial Capacity Market Proposals to RASTF.)

In past CIFP discussions, PJM has proposed shifting the metric as part of its effort to improve risk modeling.

PJM’s analysis found that the EUE equivalent to the current one-day-in-10 reliability threshold would be around 1,800 MWh of lost load, with 96% of the outage risk concentrated in winter. Under the LOLE model, PJM estimates that 78% of the risk is in the winter, with the remainder being in summer.

PJM’s Patricio Rocha Garrido said winter outages tend to last longer and lead to more lost load, which he said is captured as increased winter risk through the EUE model.

The largest summer supply loss represented in the data was about 15 GW in July 2012, Rocha Garrido said, while 46 GW of generation was lost during Elliott.

James Wilson, a consultant to state consumer advocates, argued that the change would exaggerate risk and said that if being conservative in resource adequacy is a goal, that should be done through policy rather than modeling. He noted the analysis shown May 30 doesn’t account for climate change, which he said is likely to reduce the amount of risk in winter relative to summer by leading to warmer temperatures in both winter and summer.

Bruno-Patrick-2019-01-09-RTO-Insider-FI.jpgPatrick Bruno, PJM | © RTO Insider LLC

 

PJM’s Pat Bruno said the RTO plans to continue improving the modeling, including by incorporating climate change into the data. He added that PJM had run sensitivities that found that climate change was unlikely to move the needle much for the type of modeling under discussion. Future analysis is also likely to include the impact on the installed reserve margin (IRM) and resource accreditation.

Bruno said the planning and market structures are currently based on an assumption that risk is concentrated in the summer, but the analysis suggests that a rethinking of those rules may be needed to maintain future reliability.

Vistra Presents Credit Market for Reliability Upgrades

During Thursday’s CIFP meeting, Vistra presented a proposal to create tradable credits to be awarded to generators that make investments to increase their performance, which would also raise their capacity accreditation.

Erik Heinle, Vistra’s director of PJM market policy, said that such investments may not lead to more capacity clearing in the BRA; however, it will increase a generator’s performance obligation, making it more likely to be subject to penalties and less likely to receive bonus payments.

The credits would be tradable in a PJM market and could be used by a buyer to excuse a performance shortfall equal to the increased capacity accreditation. PJM would create weekly risk assessments based on factors such as load and intermittent forecast variation, outages and fuel supply surveys, which buyers and sellers could use to determine their estimates of being subject to penalties.

Credits would only be awarded for facility upgrades on a list PJM would create during each quadrennial review.

Heinle said the proposal would add a financial product to allow generators to mitigate their non-performance risk, while still retaining an incentive to invest in upgrades.

Vitol’s Jason Barker said similar transactions exist today through bilateral transactions or within larger companies that maintain generation portfolios containing resources that can offset each other’s risks. Heinle said a PJM marketplace would increase transparency and improve price discovery.

Vistra’s Muhsin Abdur-Rahman said the proposal could also reduce the Capacity Performance quantified risk (CPQR) component of generators’ capacity offers to correspond with the reduced risk.

PJM Capacity Market Fuel Assurance Accreditation Concept

PJM’s Brian Fitzpatrick discussed a possible addition to the proposal being crafted by PJM that would create tiers of fuel security paired with the effective load-carrying capability (ELCC) model for each level. The proposal is currently focused on natural gas but would likely be expanded to other resource types as well.

Generators participating in the BRA would be required to indicate whether they will have dual fuel, single fuel with firm supply or single fuel without firm supply.

Fitzpatrick said the proposal is meant to help identify a lack of capacity on a gas pipeline or encourage greater fuel subscription to incentivize pipelines to expand, rather than creating another penalty structure for gas generators.

Paul Sotkiewicz, president of E-Cubed Policy Associates, said fuel supply needs to be looked at holistically, incorporating issues being addressed by the Electric Gas Coordination Senior Task Force and examining other fuel types as well.

NRDC Proposes Seasonal Market

The NRDC presented a series of priorities it believes CIFP proposals must address around managing resources’ performance risk, including accurately accrediting resources and avoiding double-penalizing resource characteristics through CP and accreditation.

Tom Rutigliano, senior analyst for the NRDC, said accounting for resources’ characteristics through accreditation is the most effective option, rather than creating eligibility criteria for capacity resources, penalties or combining approaches. He supported PJM’s proposal to expand the use of the ELCC model to all resource types on the basis that it can weigh generators’ performance against the disparate risks the grid faces for each hour throughout the year.

Creating a system like ELCC to evaluate multiple gas generators fueled by a single pipeline to determine the marginal capacity value could also improve accreditation by revealing whether a pipeline is likely to be oversubscribed during an emergency, he said.

Though he said it would likely be topic to explore after the CIFP process, Rutigliano suggested moving to a seasonal capacity market to resolve some of the issues that expanding ELCC would not address, including variable transmission constraints, price signals incentivizing winterization investments, and treatment of planned and maintenance outages.

Rutigliano said that subjecting resources, particularly intermittent ones, to penalties for underperformance owing to characteristics already priced into their accreditation amounts to penalizing them twice. During Elliott, he said, wind and solar both performed as expected, but solar resources were generally assigned penalties, while wind resources receive bonuses based on attributes included in their ELCC analyses.

Shanker Highlights Concerns with Market Structures

Consultant Shanker presented a series of suggestions for stakeholders to consider throughout the CIFP process impacting all proposals, including:

  • how the must-offer requirement relates to auction planning parameters and performance obligation during PAIs;
  • how power exported from PJM during emergencies affects the balancing ratio;
  • who is the beneficiary of export premiums if the capacity benefit of ties is removed;
  • how many of these issues result in hidden future transmission charges; and
  • how stochastic generation and common mode outages could cause locational impacts adverse to reliability.

The forecast pool requirement (FPR) and associated IRM are determined with the assumption that all resources holding capacity interconnection rights (CIRs) will offer into the capacity market; however, excepting intermittent resources from the must-offer requirement skews both parameters, Shanker said.

Shanker cited Independent Market Monitor studies showing that about half of such resources hold CIRs but have not been offering in auctions. Because the variable resource requirement (VRR) curve is derived from the FPR and IRM, this leads to overstatement of the reliability of the capacity procured through the BRA. He said the calculation of the capacity emergency transfer objective (CETO), capacity emergency transfer limit and locational deliverability areas’ reliability requirements cause the same issue. The issue also raises market power issues regarding holding CIRs but not using them, he contended.

Shanker also said that many market components, including the FPR, IRM and CETO, incorporate an infinite transmission assumption, which can also lead to overstated reliability by not taking location and intermittency into account, causing additional hidden transmission costs.

Shanker also called for eliminating the capacity benefit margin (CBM) and capacity benefit of ties (CBOT) when determining PJM’s reliability requirement in order to ensure the RTO can meet its own needs at a capacity price that matches the cost of resources required to reliably meet grid requirements. He noted that this should logically change the price of emergency assistance and that associated export revenues would flow to native load rather than into any potential penalty and bonus structures added to the current CP design.

Conceptual Capacity Market Exchange Presented

Dick Brooks of Reliable Energy Analytics presented how PJM could use an always-on capacity exchange (AOCE) with further development of the concept.

A former software architect of ISO-NE’s forward capacity market clearing engine, Brooks said the project was developed as a strawman design for the clean energy transition and was being brought before the CIFP to demonstrate that other paradigms are being created.

The market would use a shorter auction advance timeline with capacity prices determined using an exchange and clearing price similar to day-ahead energy markets. Capacity resources would be approved by the RTO and enter offers into the market to be bid on by customers.

The RTO would continue to determine the total amount of capacity needed for a location and time, which the RTO would issue its own reliability bids to meet needs in the short or long term. Bids exceeding the total amount of capacity needed wouldn’t be cleared to receive capacity payments.

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DOE Releases National Clean Hydrogen Strategy and Roadmap

The Department of Energy released a comprehensive Clean Hydrogen Strategy and Roadmap Monday that shows an “all-of-government” approach to making hydrogen key to not only radical decarbonization of the U.S. economy, but also to the center of ongoing industrial policy.

The release came at the start of an annual DOE five-day technical review of hydrogen research and development projects, attended by more than 2,100 people.

DOE first announced it intended to develop a comprehensive plan in September when it announced it would fund regional hydrogen hubs. (See DOE Opens Solicitation for $7B in Hydrogen Hubs Funding.)

“President Biden’s clean hydrogen strategy is all about achieving the administration’s climate and economic goals to decarbonize our electricity sector by 2035 to reach net-zero emissions across the economy by no later than 2050 and to accelerate an American manufacturing boom,” Ali Zaidi, director of the Biden administration’s Climate Policy Office, said Monday.

“Clean hydrogen has the potential to dramatically reduce emissions from a variety of sectors as either a fuel or a feedstock, but particularly in the hardest to decarbonize: the industrial sector, heavy parts of the transportation sector, and some of the peaking elements of our power sector,” he said.

“Many of these applications have been seen as out of reach for near-term decarbonization. No more. We are rapidly advancing timelines for clean hydrogen deployment and deep decarbonization.”

Noting that up to $8 billion in matching grants were authorized in the Infrastructure Investment and Jobs Act, Zaidi said the clean hydrogen production tax credit will provide up to $3/kilogram for low-carbon hydrogen.  

“These programs are driving unprecedented levels of investment in building a clean hydrogen economy for the first time in this country,” he said. “There are already 12 million tons of clean hydrogen production facilities under development in the United States.”

Energy Secretary Jennifer Granholm, appearing electronically, described the road map as far more than just a government plan.

“Our road map lays out roles for the entire federal government. But this is also an all-of-America strategy. It’s a call to action for state and local and tribal governments for businesses in the nonprofit sector. It’s an invitation to environmental groups and energy justice advocates and more to help us shape this industry in a sustainable, holistic way,” she said.

Monday’s program introducing the 99-page document included interagency panels.

The report itself notes that the work is the result of months of workshops with government agencies, as well as industries, environmental groups and others.

“This inclusive and collaborative approach is critical to the success of this expansive technology. The report is meant to be a living strategy that provides a snapshot of hydrogen production, transport, storage and use in the United States today, as well as an assessment of the opportunity for hydrogen to contribute to national decarbonization goals across sectors over the next 30 years. The report will continue to be updated with collaboration across government through interagency coordination,” the study’s introduction states.

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NJ Legislators Probing Whale Deaths Hear No Clear-cut Conclusions

Mammal experts have found no evidence that a series of whale deaths on the New Jersey shore in recent months are related to preliminary undersea testing for offshore wind (OSW) projects, speakers told a New Jersey legislative committee May 18.

Several of the speakers who addressed the Assembly Science, Innovation and Technology Committee said there’s clearly more whale activity on the New Jersey shore now than a few decades ago. But why that is and how it is linked to the deaths requires careful and lengthy scientific analysis, which has yet to be completed.

“In all cases, including those animals in which evidence of ship strike was found, the pathology results are still pending,” said Sheila Dean, director of the Marine Mammal Stranding Center (MMSC), of Brigantine, N.J. She said the organization is investigating the deaths under a permit from the federal National Oceanic and Atmospheric Administration (NOAA) Fisheries, and the work is ongoing.

“This means that the final cause of death has not been determined,” she said. “To assign blame before the scientific data is analyzed, interpreted would be premature.”

Of nine whale deaths under scrutiny, three were floating out at sea, so the MMSC could do little in the way of analysis, she said. The organization did necropsies on the remaining six, she said.

Historically, studies have shown that whale injuries and deaths on the East Coast are commonly the result of being hit by ships, becoming entangled in cables or fishing nets or being felled by disease, speakers told the committee.

Danielle Brown, lead humpback whale researcher for Gotham Whale, a New York City-based advocacy organization, said whale sightings in the New York Harbor began to increase around 2011, and strandings began escalating soon after.

“The most recent mortality event may have begun in 2016,” she said, referring to the pattern of deaths. “But strandings and interactions between humpback whales and human activities have been on the rise long before that.”

The difficulty in understanding whale activities and their interactions with humans is that data is scarce, she said.

“Ultimately, the takeaway here is that things are changing rapidly in New Jersey, especially when it comes to humpback whales, and there are many data gaps,” she said. “These whales are now a consistent part of our ecosystem.”

OSW Moratorium

The hearings were triggered by the persistent suspicion raised by some project opponents that the whale deaths are somehow tied to offshore wind projects. No construction has begun on any New Jersey shore wind projects, and the developer of the first project, Ørsted, is conducting only preparatory sea floor analysis.

Ørsted’s 1,100-MW Ocean Wind 1, which is the state’s first offshore wind project and was approved in 2019, is scheduled to begin construction next year. The state Board of Public Utilities (BPU) subsequently approved two more projects, the 1,148-MW Ocean Wind II and 1,510-MW Atlantic Shores, in the state’s second solicitation in 2021. (See NJ Awards Two Offshore Wind Projects.)  

The projects have faced opposition from the tourism and fishing industries, as well as some residents, who are concerned about the impact and fear turbines will mar the view of the sea and deter visitors. The commercial fishing sector fears they will not be able to fish as much in the areas they work at present.

The whale deaths have provided opponents with another issue to raise. Republican Reps. Jeff Van Drew and Chris Smith in March held a hearing on the issue. Van Drew has called for a moratorium on the OSW project development while the whale deaths are investigated.

The issue was one of many raised by Cape May County in a resolution passed May 23 stating that the county “objects to and opposes” Ørsted’s two New Jersey projects” and wants to stop the projects unless the developer agrees to mitigate the impact. The county also has appealed a ruling by the New Jersey Board of Public Utilities granting Ørsted an easement across Cape May property so an underground cable could be installed linking Ocean Wind 1 with the grid. (See County Contests Tx Easement for NJ’s 1st OSW Project.)

The resolution said the “recent, unprecedented deaths and strandings of marine mammals” on the Jersey coast are of “utmost concern” to the county, adding that the State of New Jersey’s claim that there is no connection between the deaths and the OSW projects is “inconsistent with reality.”

The resolution says that in a 2018 lawsuit filed in federal court, the state itself opposed offshore drilling by arguing that “seismic testing activities” would have a “negative impact on marine mammals’ health and abundance” and hurt tourism. The resolution says the county does not find “acceptable” the state’s argument that it does not know what is causing the whale deaths “but that they somehow know for certain that the deaths are not related in any way to the activities” of Ørsted.

Prey Fish Migration

Yet the state’s position is shared by federal officials. A spokeswoman for NOAA, which in a January press conference said it did not believe the survey work on offshore wind projects could be tied to the whale strandings, told NetZero Insider in an email two weeks ago that it has not changed that position.

“At this point, there is no evidence to support speculation that noise resulting from wind development-related site characterization surveys could potentially cause mortality of whales, and no specific links between recent large whale mortalities and currently ongoing surveys,” said NOAA spokeswoman Andrea Gomez.

The Final Environmental Impact statement for Ocean Wind 1, which the U.S. Bureau of Ocean Energy Management (BOEM) released in May, concluded that the impact of the project on whales would be “moderate” but that the cumulative impact of the project, along with others, would be moderate to major for the North Atlantic right whales. (See BOEM: Major Visual, Scientific Impacts from NJ’s 1st OSW Project.)

A federal judge on May 17 rejected the argument that an offshore project could harm whales, including the North Atlantic right whales, an endangered species, in a lawsuit against the Vineyard Wind 1 offshore wind project. The judge ruled that the originators of the lawsuit, Nantucket Residents Against Turbines, had not made their case. (See Lawsuit Against Vineyard Wind over Threat to Whales Tossed.)

Shawn M. LaTourette, commissioner for the New Jersey Department of Environmental Protection, told the Assembly committee hearing that one explanation for the increased number of whale strandings is that one of the prey fish that whales eat, menhaden, are moving “landward,” as the habitat of the small fish gets disrupted by climate change.

“And as these prey fish move landward, their predators are following them. Their predators include whales,” he said. “The culprit is a changing climate, and our inability societally to get it under control.”  

But one lawmaker was skeptical of the argument.

“It’s a little hard for us to just assume that that affirmation is real,” said the lawmaker, who was not identified in the audio feed of the meeting, asking for scientists to testify who could “confirm your affirmation.”

LaTourette said the explanation was the product of work by state-employed scientists who compiled the state’s Scientific Report on Climate Change released in June 2020.   

Sound, Vessel Strike, Disease Impact

Douglas Nowacek, a professor of conservation technology and environment and engineering at Duke University, told the committee he didn’t agree with the argument that undersea sonar used to analyze the sea-bed floor could be severely damaging the whales.

Nowacek, who said he has spent 20 years looking at the effects of noise on cetaceans — aquatic mammals such as dolphins and whales — said there could be two types of noise sources at use undersea. But neither would have a major impact on disorienting a whale, he said, adding that he agreed with NOAA Fisheries on this issue.

One type of sound, high-resolution geotechnical, is used to map the ocean bed and also to look at babies in the womb, he said. But the frequency of that source would be too high for a whale to hear, he said.

“Those high frequency sources I would consider de minimis [of little importance] in their potential for impact on basically all marine mammals,” he said. “They are extremely high frequency, which is out of the hearing range of these animals, and they’re also … absorbed extremely quickly.”

The second source, boomer markers or chirpers, which are used for oil and gas exploration, would be too weak to harm a whale when used for OSW projects, he said. These need to analyze only the top 50 meters or so of sea-floor sediment, and so the intensity is perhaps 100,000 times lower than the intensity when they are used to look for fossil fuel sources thousands of meters into the sea bottom, he said.

“Can the sources disorient animals such that they would die instantly? No?” he said. “Do we worry about them getting a little disoriented and deviating around a path? That could certainly happen.”

Robert A. DiGiovanni Jr., chief scientist at the Atlantic Marine Conservation Society, said that when he began studying whale strandings in the New York area in the 1990s, he would see one about every 617 days. The frequency began to increase in about 2007, and by 2017 there was one about every 63 days, he said. It has been “hovering” around one every 26 days for a number of years, he said.

“We are currently in the middle of three unusual mortality events for large whales: the North Atlantic right whale, the minke whale and the humpback whale. All of them have started since 2016,” he said.

“Vessel strike and entanglement are the leading causes of mortality for the humpback whales and for the right whales,” he said. The minke whales are felled more by a “biological process, more of a disease process,” he said.

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NERC’s Standards Process Changes Pass on Second Ballot

NERC’s second attempt to gain industry approval for proposed changes to its Standards Processes Manual (SPM) succeeded last week, as stakeholders gave overwhelming consent to the revisions.

The measure passed with 183 votes out of 260 members of the ballot body and only seven votes against it. Taking into account NERC’s weighting of the segments in the ballot pool, that gave the proposal a 97.49% approval. Twenty-eight members of the ballot body abstained, and 42 did not cast a vote.

The large number of positive votes is a significant turnaround from January when the first version of the SPM revisions went before industry. That proposal failed in March after garnering only 76 affirmative votes and 118 against it, for a weighted value of 37.7%.

NERC’s Board of Trustees issued an order to revise the SPM at its November meeting because of concerns that the ERO’s “deliberative” standards development process was not keeping up with the increasingly rapid pace of industry change. (See NERC Board Member Argues for Increased Authority.)

The initial proposal would have, among other things, removed the requirement for a final ballot to confirm the results of the most recent successful ballot and allowed standard authorization requests (SARs) proposed by the board to be posted for an informal rather than formal comment period. The latter change would have meant the SAR drafting team would not be required to provide a formal response to industry comments.

However, the negative reaction from industry was strong, with commenters such as the Northern California Power Agency fearing that the proposals would undermine “due process, openness and balance of interests.” Respondents objected to shortening later ballot periods on the grounds that this would give industry less opportunity to weigh in and to eliminating the final ballot, arguing that industry needed to be able to approve of any changes the standard drafting team made following a successful ballot. (See EPSA Forum Speakers Focus on Hurdles to Energy Transition.)

The newest set of changes were intended to allay these objections. Updates included clarifying that formal comment and balloting periods following the initial 45-day period “may be as few as 30 days” but must be at least that length, as opposed to the last proposal, which did not specify a time limit. The new revisions also removed language suggesting that SARs proposed by NERC’s board would not be subject to a 30-day formal comment period.

A standards action may still conclude after a successful ballot without requiring a final ballot, but only under very specific circumstances. The previous ballot must have achieved at least 85% weighted segment approval. In addition, the drafting team must have “made a good faith effort at resolving” industry objections, have responded in writing to comments and be proposing no further changes to the balloted documents.

These changes mostly met with approval from those who withheld their support last time, but some still registered objections to the second round of revisions. For example, Kimberly Turco of Constellation said that while removing the idea of allowing board directives to bypass the initial formal ballot was a good step, letting any SARs avoid the normal process should still be considered going too far.

“SARs that bypass formal posting/commenting are in direct conflict with the concept of ‘working with all stakeholder segments of the electric industry … to develop reliability standards,’” Turco said. “Allowing the latitude to bypass the existing input from the industry is not in the spirit of collegial development of the NERC reliability standards and may propagate a bias of individuals involved, including the Standards Committee, that may not recognize or appreciate specific nuances of the draft SAR when evaluated by the industry.”

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FERC Partially Approves PSCo’s Queue Changes

FERC on Friday partially approved Public Service Company of Colorado’s (PSCo) proposal to amend its generator interconnection process with changes intended to prevent unready projects from clogging the queue (ER23-629).

The Xcel Energy (NASDAQ:XEL) subsidiary in 2019 received commission approval to transition its interconnection process to a cluster study approach, but projects not ready to move forward have continued to slow the process for those that are ready. The unready projects end up withdrawing, leading to problems such as unreliable study results, cascading restudies and delays.

The most recent study cluster has been delayed for two years, PSCo noted, preventing the utility from meeting customers’ requested in-service dates and hindering future projects from estimating their interconnection costs.

Under PSCo’s existing rules, projects can qualify for the queue if they have offtake agreements, are part of a resource plan or have an in-service date. Developers can also enter a project into the queue if they submit additional security in lieu of making a “readiness demonstration.”

In its initial filing, PSCo sought to remove the option for projects to submit additional security, contending that developers picking that option have often wanted to use a large generator interconnection agreement to market their projects but wound up subverting the goal of a speedier processing of interconnection requests, even causing more advanced projects to withdraw from the queue process altogether.

The initial proposal would have replaced the security option with a “generation deployment plan” that would require a developer to have a plan to secure permits, build the facility and finance it. The generation deployment option would also include a $7.5 million deposit, along with withdrawal penalties that vary by project size and rise the later in the queue a project pulls out.

The Solar Energy Industries Association, Avangrid and HQC Solar argued the changes were too stringent and would prevent independent power producers from entering the utility’s queue. But they did win support from NextEra Energy, which said that while the outcome would be more restrictive than FERC’s pro forma rules, the changes make sense in Colorado, where generators generally transact with load-serving entities that can trigger clusters of resources in the queue.

PSCo came back with a later filing that added an option for developers using the generation deployment option to pay a $7.5 million security payment and face the heightened withdrawal penalties, without requiring them to meet the other requirements, effectively restoring the security option — which SEIA said was better than the first proposal.

The proposal led to a deficiency notice from FERC, with staff asking how PSCo would evaluate what constitutes a reasonable permitting plan under the generation deployment plan. The utility said it would accept permitting plans that demonstrate an understanding of the land use and environmental permitting process in Colorado.

Staff also asked how the utility arrived at the $7.5 million security amount and associated withdrawal penalties. PSCo said the old withdrawal penalties were capped at $2.5 million, which was not enough, and that $7.5 million is still lower than average interconnection costs.

Security Option Remains

FERC rejected PSCo’s initial proposal, but it accepted the alternative in which projects can put up $7.5 million in lieu of being ready to deploy.

“We find that PSCo’s proposal to require interconnection customers to either meet the requirements under the proposed generation deployment option or one of PSCo’s three existing, unchanged, commercial readiness demonstration options alone is likely too stringent for independent power producers to meet,” FERC said. “Based on the record in this proceeding, many independent power producers currently use the security in lieu of a commercial readiness demonstration option in PSCo because it is difficult for them to meet the requirements for the other existing commercial readiness demonstration options.”

FERC also agreed with protesters that the milestones in the generation deployment option might be misaligned with typical development cycles and business practices for IPPs.

But allowing projects to post $7.5 million and raising withdrawal penalties will help speed up the queue because PSCo has shown that speculative projects are slowing the process down, FERC said. The higher security requirement will cut the number of speculative projects and thus the associated withdrawals and restudies.

In the two clusters run in 2020, projects representing 66% of the requested interconnection capacity withdrew from the queue, as did 30% the next year, which shows that the current security and withdrawal penalties are not enough to deter unviable projects from getting in line.

Other Penalties

PSCo had also asked to increase to $5 million the security and penalty for projects that sign an interconnection agreement but do not enter service (except for those posting the higher $7.5 million security). It had penalized such projects under a formula of nine times study costs, which topped out below $1 million.

FERC approved the $5 million figure, saying it will increase the likelihood that projects with an interconnection actually get built. The amount is justified because projects that pull out are especially problematic because they cause more restudies than earlier withdrawals, the commission found.

None of the new fines or security requirements will go into effect until 120 days after the rules become effective, which FERC said gives projects that entered the queue under the old rules enough time to pull out in light of the new risks. PSCo initially filed for a 30-day transition, but then offered the 120 days in a subsequent filing to avoid favoring its own generation when it holds upcoming resource solicitation that projects presently in the queue can participate in, FERC said.

Commissioner Allison Clements concurred with the order, saying further changes might be needed to make PSCo’s interconnection process fairer when it comes to how penalties are distributed. Withdrawal penalties are currently used to fund generation interconnection studies, but the tariff does not address how such funds should be distributed when they exceed relevant study costs — a risk that is now higher, she said.

“I encourage PSCo to assess whether further changes to its [large generator interconnection procedures] may be necessary in light of the commission’s approval of increased withdrawal penalties,” Clements said. “If PSCo’s proposal renders its existing mechanism for distribution of withdrawal penalties unjust and unreasonable and further changes are not forthcoming, then action pursuant to Section 206 of the Federal Power Act may be appropriate.”