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September 5, 2024

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MISO Seeking New Transmission Cost Allocation for Major Buildout

A month after filing a cost-allocation method for its long-range projects, MISO is on the hunt for a better approach to funding major transmission builds.

During a cost-allocation committee meeting Monday, the RTO opened the floor to stakeholder input on a new funding mechanism for the next round of long-range projects.

Staff have repeatedly said the separate-but-equal postage stamp rate divided between MISO Midwest and MISO South is meant to be temporary. The RTO has filed for FERC approval to use that design for the first two collections of projects from its long-range plan. (See MISO Finalizes Long-range Tx Cost Sharing Plan.)

MISO’s Jeremiah Doner said the grid operator is committed to applying a more permanent, “granular” cost allocation for future long-range projects.

“We want to have something with longevity in place,” Doner told stakeholders during the meeting.

Michigan Public Service Commissioner Dan Scripps, who chaired the committee, said the discussion on additional benefit metrics and quantifying them will continue well into 2023.

MISO envisions a new cost allocation for the third and fourth cycles of its multiyear long-range transmission plan. The planning will occur in four parts, with the first two focusing on the RTO’s Midwestern footprint and more immediate needs. (See MISO Long-range Tx Plan Overlaps with SPP Study.)

The third planning cycle will include transmission needs in MISO South. The fourth and final cycle will include MISO’s Midwest and South regions and solutions to increase transfer capability between the subregions.

The RTO will complete its first cycle of long-range projects in June and begin studying prospective projects in the second cycle in late spring or summer.

“We’re going to have to spend some time on what granularity means from a benefits perspective,” Doner said of cost-allocation talks for the third and fourth project batches.

He predicted that defining new reliability benefits will probably be most challenging. He said it’s easy to define reliability that satisfies NERC requirements, but it’s harder to pin down reliability that benefits regions, hardens the grid and leaves the system better positioned for extreme weather events.

Some stakeholders asked how the RTO will reconcile different allocations in the two halves of the long-range planning effort. Staff said cost-allocation methods morph over time.

“It’s a fair question. It’s a little hard to answer that from where we sit today,” Doner said.

Stakeholders are already advocating for a wider range of benefits in a new allocation design.

“If we’re really going to have a more granular cost allocation in place, we need to quantify more benefits,” Sustainable FERC Project’s Lauren Azar said. “As we’ve said ad nauseum, our current benefit metrics only identify a narrow slice of the benefits. So, there are a lot of free riders on our system.”

Currently, long-range cost allocation project benefits must support state or federal energy policies; address NERC issues and show reliability benefits across multiple zones; and demonstrate multiple types of economic value across multiple pricing zones with at least an overall 1:1 benefit-to-cost ratio over the first 20 years of service.

Several stakeholders said transfer capability could be a good resilience measure because the ability to flow power has been crucial during past winter storms. They also revived the debate on whether new generation should bear a portion of new transmission costs.

MISO will hold another cost-allocation workshop April 26.

“We’ve got some work ahead of us,” Scripps said, closing the meeting.

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Large New York Consumers Oppose National Grid Transmission Upgrades

A group of large electricity consumers opposes National Grid’s (NYSE:NGG) petition to New York state regulators to allow development of and cost recovery for 19 transmission upgrade projects (Case Nos. 20-E-0197 and 20-E-0380).

National Grid subsidiary Niagara Mohawk Power’s November 2021 petition to the Public Service Commission included a 2030 Regional Plan and also sought approval of cost deferrals and surcharge recoveries from its approximately 1.6 million electric customers.

But “it is not clear that all, or even many or any, of the proposed projects truly are needed at this time,” Multiple Intervenors (MI), an ad hoc group of more than 50 large commercial, industrial and institutional energy consumers, said Monday. MI was party to a recently concluded electric and gas rate proceeding for Niagara Mohawk.

None of the 19 projects was included in the $3 billion electric capital expenditures in a three-year rate plan approved in January, the group noted.

“Thus, the proposed projects either were not subjected to the typical scrutiny attendant in rate proceedings or, perhaps in certain instances, were subjected to such scrutiny and ultimately excluded from the long list of proposed projects used to justify the utility’s negotiated level of capital expenditures,” MI said.

National Grid argued in its petition that “each of the company’s Phase 1 solutions were designed after assessing existing reliability-based transmission projects – those projects already requiring upgrades to address condition issues, enhance storm resiliency, or improve operational performance – to minimize the cost to unbottle renewable energy,”

Under the New York Public Service Commission’s new transmission planning rules, Phase 1 projects are traditional utility investments that address system reliability or resilience issues, while Phase 2 projects are primarily intended to facilitate the state’s environmental targets. (See New York Adopts Groundbreaking Tx Investment Rules.) National Grid said it assessed existing reliability-based projects based on their ability to improve renewable energy deliverability as designed or improve deliverability if redesigned.

Nat Grid Phase 1 (National Grid) Content.jpgThe table summarizes the capital investment, including cost of removal, and operating cost estimates, incremental right of way requirements and improvements to the import/export capability (headroom) of each region. | National Grid

MI countered that the proposed projects would expose customers to near-term and long-term rate impacts.

“The impacts that would flow from the proposed authorizations should not be evaluated in a vacuum,” MI said.

In addition to the more than $3 billion in budgeted electric capital expenditures approved through fiscal year 2025, the commission previously has authorized tens of billions of dollars in customer collections for various clean energy programs and initiatives, and wholesale energy prices have jumped substantially in 2022, MI said.

“Because customer funds are far from limitless, and rising energy costs have significant, negative impacts on economic activity, the commission needs to ensure that Niagara Mohawk’s electric rates are shielded from capital expenditures that are not truly necessary for safe and reliable electric service,” MI said.

The group also opposes the approval of cost deferrals and surcharge recoveries, saying there is no clear urgency to start and complete all of the upgrades proposed now during a major expansion of Niagara Mohawk’s normal electric capital expenditures budget and while large-scale renewable generation development is occurring at a slower pace than previously had been anticipated.

“Quite simply, the commission needs to proceed very cautiously, else future electric rates and prices will become less affordable for customers and even less competitive with other regions, thereby harming state and local economies that still are reeling from the effects of the COVID-19 pandemic,” MI said.

National Grid said the 2030 Regional Plan “represents timely solutions to excessive renewable energy curtailments or ‘bottling,’ which leads to the undesirable effect of chilling generation investments, increasing energy prices and continuing to rely on the generation commitment and dispatch of fossil-fueled resources.”

The Alliance for Clean Energy New York (ACE-NY) supports National Grid’s petition, noting that the utility deems several of the Phase 1 upgrades as needed to enable further upgrades that will alleviate constraints threatening renewable development.

“Indeed, Grid points to the high-execution risk that Phase 1 upgrades pose to subsequent Phase 2 upgrades if Phase 1 upgrades are not approved” in a timely manner in certain areas of the state, ACE-NY said. “National Grid emphasizes it has staged the deployment of both Phase 1 and Phase 2 projects to provide benefits in the time frames needed for current and planned renewable generation development.”

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California PUC Sets Biomethane Targets

The California Public Utilities Commission established biomethane procurement goals for the first time Thursday to help reduce methane emissions from landfills, dairies and natural gas use.

The decision requires gas utilities to substitute a portion of natural gas with biomethane, mostly derived from landfills, which emitted 21% of methane statewide in 2019, according to the most recent figures from the California Air Resources Board (CARB).

Methane is a more potent greenhouse gas than carbon dioxide, though it is shorter-lived in the atmosphere. Burning biomethane results in open-air emissions.

“Tackling methane and other short-lived climate pollutants is critical given our climate crisis,” Commissioner Clifford Rechtschaffen, the lead commissioner in the proceeding, said in statement. “This decision will reduce emissions from some of the state’s leading methane sources.”

The state has a mandate, under Senate Bill 1383 passed in 2014, to reduce short-lived climate pollutants such as methane by 40% below 2013 levels through 2030.

Senate Bill 1440, adopted in 2018, required the CPUC to “consider adopting specific biomethane procurement targets or goals for each gas corporation so that each … procures a proportionate share … of biomethane annually.” The state’s two largest gas corporations under CPUC jurisdiction are Southern California Gas and Pacific Gas and Electric.

The CPUC decision requires gas companies to purchase a total of 18 Bcf of biomethane annually by 2025 — potentially diverting 8 million tons of organic waste from landfills each year. Most of the waste would come from compost and the chipping and grinding of trees and other vegetation, the CPUC said.

The decision also establishes a midterm goal of procuring 73 Bcf of biomethane per year by 2030, representing about 12% of residential and small-business gas use. Utilities must secure a percentage of the total based on their proportionate share of the market.

Biomethane from dairies is already incentivized under other state programs, so it can be used only to fulfill the 2030 target after a gas utility procures enough biomethane from landfills to meet the 2025 target, the CPUC said. The decision limited dairy biomethane to 4% of the total for the 2030 goal. Dairies emitted 54% of methane in California in 2019, CARB said.

State law requires landfills to capture or destroy methane, including through burning the gas to break it down, but they continue to emit large quantities of methane.

A recent NASA study found that 30 large “super emitter” landfills produce about 40% of the total point-source emissions detected in a survey of more than 300,000 industrial facilities, dairies and landfills.

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FERC Orders Negotiations in Duke-Muni Contract Dispute

FERC on Monday conditionally approved Duke Energy Progress’ (NYSE:DUK) proposed changes to its supply contract with the North Carolina Eastern Municipal Power Agency (NCEMPA) but ordered the two parties to negotiate over how the pact should be changed to reflect the latter’s use of batteries to shave its demand charges (ER22-682).

NCEMPA, which serves 32 cities and towns with municipal electric distribution systems, asked FERC in 2019 to issue an order declaring that its “full requirements” power purchase agreement with Duke permitted it to use battery storage to reduce the munis’ load during the peak hour each month that is used to determine capacity charges. FERC granted NCEMPA’s request in September 2020 (EL20-15), a ruling that was upheld by the D.C. Circuit Court of Appeals in January. (See DC Circuit Upholds FERC on Duke-Muni Battery Dispute.)

The capacity charge — based on NCEMPA’s pro rata share of the demand on Duke’s system during the one-hour coincident peak (CP) — is intended to cover Duke’s fixed costs and provide a return on its infrastructure investments.

New Contract Sought

DEP responded to the commission’s 2020 order by seeking to reopen the PPA, telling FERC that a revised rate design was needed because of statements by NCEMPA members announcing their intention to procure enough storage to reduce or eliminate their capacity charges “by superficially reducing or eliminating their demand only during the single CP hour of the month.” Since December 2020, NCEMPA and its members have issued solicitations for almost 150 MW of battery storage, DEP said.

The company said NCEMPA’s peak shaving was shifting capacity costs to four other wholesale requirements customers and that DEP’s retail customers also could be harmed because they pay a portion of the fixed costs.

DEP’s revised PPA would replace the current 12-CP methodology with a process that compares NCEMPA’s CP demand with its monthly non-coincident peak (NCP). In any month in which NCEMPA’s NCP exceeds its CP by 200 MW or more, the difference between the CP and the NCP minus 200 MW would be added back to the CP for setting demand charges.

The company told FERC the amended PPA is needed because “DEP’s system planning can no longer merely assume that the monthly coincident peak is the appropriate proxy for each customer’s use of the system.

“DEP’s limited visibility into NCEMPA’s intended time and magnitude of load management and demand cost mitigation measures creates real-time operational problems in so far as DEP must ramp (expensive and carbon-intensive) generation to meet NCEMPA’s anticipated load only to have NCEMPA members deploy demand cost mitigation measures, creating temporary and artificial load reductions to which DEP must quickly respond in real time,” it said, adding that the operational challenges will increase as it integrates more solar onto its system.

The company also proposed to change the nearly one-year notice period for proposed changes to the PPA. It currently gives the parties 60 days to reach an agreement on an amendment; if they are unable to agree, a 240-day informal dispute resolution process follows. DEP proposed shortening the notice and negotiation period from 300 days to 60 days, saying the current contract allows one party to “effectively hold the change hostage for almost a full year.”

NCEMPA protested, saying Duke’s proposal would penalize the development of distributed energy resources and that it violates cost-causation principles because the 200-MW threshold is arbitrary. It also complained that DEP would apply a cost allocation method that deviates from the conventional 12-CP method only to NCEMPA.

Ruling

FERC voted 4-1 to conditionally approve the revised PPA, effective March 1 and subject to refund pending settlement judge procedures.

The commission noted it has “previously accepted modification to a 12-CP methodology where the applicant sought to address cost shifting due to load-control measures.”

“Here, DEP has presented arguments that its current demand allocation method may fail to appropriately align costs with beneficiaries given the changing operational conditions on DEP’s system,” FERC said. “We find these arguments persuasive.”

The commission also dismissed NCEMPA’s argument that the revised PPA is unduly discriminatory, saying, “DEP’s departure from the 12-CP methodology … is not novel.

“Each of DEP’s wholesale customers has negotiated unique terms in their respective agreements based on their individual circumstances,” it said.

But the commission said it wasn’t convinced that DEP’s adjusted capacity charge calculation and 200-MW threshold are just and reasonable. It also said DEP’s proposal to modify its notice provisions from 300 to 60 days is “not adequately supported.” NCEMPA said it would consider some reduction in the duration of the informal process but that 60 days was too short for it to secure the necessary governing board consideration and approval.

Dissent from Clements

Dissenting was Commissioner Allison Clements, who said the commission should have rejected DEP’s proposal without prejudice and that the majority’s order “sets too low a bar for the filing party’s proposed rate to become effective as the hearing process moves forward.”

Clements said DEP failed to demonstrate how its rate proposal reflects its transmission planning. She also questioned why DEP doesn’t use NCP demands in allocating costs for all DEP customers.

“At minimum, a five-month suspension period is warranted in this case,” she said. “To the extent that the hearing process stretches beyond the 15-month refund period, NCEMPA risks being subjected to unjust and unreasonable or unduly discriminatory charges without any recourse.”

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Draft Study Weighs Tradeoffs of CO2 Pricing, FCEM for ISO-NE

A new draft study evaluating ways to decarbonize New England’s power sector finds multiple advantages for carbon pricing, but also significant tradeoffs that underscore the tough choices facing policymakers.

The draft of the Pathways Study, commissioned by ISO-NE and written by the consulting firm Analysis Group over the last year, was presented to the NEPOOL Participants Committee on Tuesday.

It looked at four policy approaches: a status quo scenario in which the New England states continue their unilateral clean energy policies; a forward clean energy market (FCEM) to compensate non-emitting resources; a net carbon pricing plan to price emissions from generators; and a hybrid approach which combines the latter two.

In theory, all four approaches can achieve “substantial” levels of decarbonization, the draft report says, but they come with unique challenges and costs.

Policy approaches (Analysis Group) Content.jpgThe differences between the policy approaches laid out in the study | Analysis Group

Net carbon pricing would be cost-effective, a standard which the report says the other solutions fall short of. It would “create price signals that incent all substitutions that can reduce emissions,” it says.

Carbon pricing would also result in the lowest social cost, a 28% decrease from the cost of the status quo. Importantly, however, it wouldn’t be the cheapest option for consumers; that prize goes to the hybrid plan, which would reduce customer payments, unlike the others.

Carbon pricing would also be the most feasible approach to develop, the report says, because policymakers have more experience creating that type of design than something like the FCEM.

“While there is experience with market-based systems for environmental attributes … the FCEM would involve certain policy design elements that have not been used previously and would likely require significant time and effort to develop,” the report says.

However, carbon pricing is less well-suited to coordinating individual state policies and clean energy targets.

ISO-NE has been a supporter of carbon pricing but has struggled to find consensus in the stakeholder process and particularly among state policymakers. (See ISO-NE: States Must Lead on Carbon Pricing)

NESCOE, representing the New England states, has opposed the concept of incremental carbon pricing administered by the grid operator, arguing in 2020 comments to FERC that “consumers could be exposed to costs exceeding several billions of dollars each year.”

Locational marginal prices (Analysis Group) Content.jpgThe distribution of locational marginal prices under each of the possible policy solutions | Analysis Group

 

The hybrid approach involves combining a carbon price sufficient to provide revenue adequacy for existing clean energy resources (like the Millstone nuclear plant, used as an example in the report) with an FCEM that provides incremental compensation only to new clean energy resources. It’s a “completely novel” approach and the report raises questions about its feasibility for that reason.

One other issue found with the FCEM and hybrid approaches is storage “churning,” in which battery owners “consume otherwise-curtailed variable renewable energy and earn net revenues through energy losses,” the report says. The conditions leading to that inefficiency would be caused by frequent and large negative LMPs, which occur in those two scenarios.

In effect, the storage resources would be being paid to generate clean energy credits for clean energy resources even though the energy wouldn’t be replacing carbon-intensive generation.

Another advantage the report finds for carbon pricing is that it would provide incentives for fossil fuel generators to reduce their carbon-intensity when it’s cost-effective to do so, although the scope for those emissions reductions is “limited given current technologies,” it finds.

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Massachusetts Commission Deliberates Emissions Cap for Heating Fuel

The Massachusetts Commission on Clean Heat is on an “aggressive” timeline to produce a preliminary recommendation for capping greenhouse gas emissions from heating fuels, according to a top state environmental official.

As part of its mandate, the commission must quickly identify policies to inform the still-undetermined building sector emissions sublimit in the state’s forthcoming 2025/2030 Clean Energy and Climate Plan (CECP), Judy Chang, undersecretary of Energy and Climate Solutions at the Executive Office of Energy and Environmental Affairs (EEA), said during a commission public meeting Tuesday.

Massachusetts’ 2021 climate law calls for EEA to establish emissions limits and sectoral sublimits by July 1 along with a plan to achieve the limits. Over the next month, Chang said, the commission will identify policies, programs, initiatives and incentives that would achieve a building sector sublimit and an economy-wide emission-reduction target of 50% below 1990 levels by 2030.

After the commission makes its preliminary policy recommendations, it will refine them into a final report for Gov. Charlie Baker in November.

The 22-member commission has held four meetings since its launch in mid-January and is now “deliberating on some of the suggestions that they might have and exchanging ideas with each other,” Chang said.

Commission meetings, however, are closed to the public. EEA is conducting stakeholder engagement on the commission’s work through three public information sessions.

“We want public input, but I also wanted the commission members to have … the flexibility and the freedom to debate, and it’s through that process that we get the most productive and efficient outcome,” Chang said.

EEA will share information on the commission’s work during a public meeting on March 24. Another public meeting is scheduled for April 14 to give stakeholders a combined update on the commission and the 2025/2030 CECP.

Informing the CECP

EEA Secretary Kathleen Theoharides released an interim 2030 CECP in December 2020 as an update to the state’s existing climate plan at the time. The statutory requirements for the interim update changed in late March 2021, when Gov. Baker signed the state’s next-generation climate policy into law.

Under the law, a 2025/2030 CECP must be completed this summer with statewide limits and at least six sectoral sublimits that are accompanied by plans to achieve each limit. Another update with 2050 sublimits and related plans is due next January.

The clean heat commission’s work on the building sector is one of many public processes underway in Massachusetts to support development of the CECP.

As they relate to heating fuels, those public processes are giving “conflicting signals,” Martyn Roetter, a director at the Neighborhood Association of the Back Bay in Boston, said in comments to EEA during the public meeting Tuesday. He asked the commission to consider how the various initiatives and proposals will provide “consistent and coherent” guidance on fossil fuels.

At the city level, Roetter said, Boston has enacted a stringent emissions ordinance for large buildings. The state, on the other hand, has released a draft net-zero buildings code for municipalities to adopt that “includes the option in new construction to use fossil fuels,” he said. (See Mass. Legislators Call for Fossil Fuel Ban in Net-zero Building Code.)

In that context, he added, Massachusetts Attorney General Maura Healey determined in 2020 that towns are bound by state law to allow new fossil-fuel hookups.

And new recommendations from the state’s gas utilities under the Department of Public Utilities’ investigation of the role of those utilities in decarbonization “sets the stage for the indefinite, continued use of large, extensive networks of pipelines,” he said.

National Grid (NYSE:NGG), Eversource Energy (NYSE:ES), Liberty Utilities and Unitil (NYSE:UTL) released initial proposals in mid-February for their long-term climate plans in that docket (20-80). The utilities’ proposals, while not identical, all include recommendations for hybrid heat pump/natural gas installations and decarbonization of gas networks over time through blending with renewable natural gas or hydrogen.

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DOE’s ‘Better Climate Challenge’ Targets 50% Emission Reductions

More than 90 companies, state and local governments, universities and other organizations have pledged to cut their greenhouse gas emissions 50% by 2030 as part of the Department of Energy’s newly launched Better Climate Challenge.

“You’ve committed to cut your operational greenhouse gas emissions at least in half in 10 years,” said Secretary Jennifer Granholm, during a virtual kick-off event on Monday. “That means everything within the fences — the heating, the cooling, ventilation, lighting for buildings, the cars, trucks in fleets, the electricity you use and more.”

Challenge participants — which range from major corporations such as General Electric, Harley-Davidson and IKEA to small towns, such as Glen Falls, N.Y. — pledged to reduce their scope 1 and 2 GHG emissions by at least 50% within 10 years. They are also expected to establish organizational plans with benchmarks, including ambitious energy efficiency goals, “typically 20%,” according to a fact sheet on the challenge.

But beyond the emission reductions, the initiative is also aimed at unleashing the kind of “big collective action” needed to combat global climate change, Granholm said. Challenge participants have committed to “sharing the details and the data to demonstrate how you [cut emissions],” she said.

Gina McCarthy (DOE) Content.jpgGina McCarthy, White House National Climate Advisor | DOE

The goal, she said is “to figure out what works, what actually needs work [and] what that tells us about the way going forward.”

The initiative is an extension of the DOE’s Better Building Challenge, a decade-long effort to improve the energy efficiency of residential and commercial buildings via public-private partnerships and information sharing, Granholm said.

The challenge is yet another part of the Biden administration’s goal of cutting the country’s carbon emissions in half by 2030, the U.S. commitment to the global community as part of the UN Paris climate agreement. Biden’s executive order on federal procurement has also committed the government to “lead by example” by cutting emissions from its buildings in half by 2030.

National Climate Advisor Gina McCarthy said climate action has become a brand differentiator for consumers and voters. “Your constituents in state and local government, your customers in the private sector are all looking to leading the way, and you are standing tall by making sure they know what your values are.”

Secretary of Housing and Urban Development Marcia Fudge, who noted the participants in the challenge include seven affordable housing organizations, said disadvantaged communities are especially vulnerable to the impacts of climate change.

“HUD funds billions of dollars in disaster recovery work in cities and towns devastated by natural disasters,” Fudge said. “We see the impacts firsthand, and the years it takes to rebuild after these climate events. The more we can do now on the climate mitigation front, the less we will have to spend on rebuilding our communities.”

 Advancing Equity

The need for urgent, collective action on climate change was underlined Monday by a new report from the UN Intergovernmental Panel on Climate Change, warning that the catastrophic impacts of global warming — floods, drought, heat waves — were fast outpacing the world’s ability to adapt to or mitigate them. (See IPCC Climate Report: ‘Half Measures No Longer an Option.’)

Marcia Fudge (DOE) Content.jpgMarcia Fudge, Secretary of Housing and Urban Developement | DOE

“Environmental health and human health are interlinked; we see climate change as the greatest environmental health threat of this century,” said Jon Utech, senior director of the Office for a Healthy Environment at the nonprofit Cleveland Clinic, another challenge participant. “It’s already having a dramatic impact on the health of our patients and the communities we serve. We see taking on this challenge as a major health initiative.”

Like Utech, other executives speaking at the launch event focused on the opportunities they are seeing and actions they are taking for decarbonization in their industries or sectors. Traci Forrester, executive vice president for environment and sustainability at steel maker Cleveland-Cliffs, framed the challenge as another step toward decarbonization of heavy industry in the U.S.

Cleveland-Cliffs is rolling out a “closed-loop, steel recycling program where all of our hot metal contains 28% recycled steel,” she said. The company — the Largest Flat‑Rolled Steel Producer in North America — is also working with DOE to “evaluate potential future use of carbon capture technology for steel mills.”

Echoing HUD Secretary Fudge, Maurilio León, CEO of the Tenderloin Neighborhood Development Corporation in San Francisco, spoke of decarbonization as a path toward equity for low-income communities that historically have had little access to energy efficiency or clean energy technologies.

“Currently, 80% of the community that we serve earns less than $15,000 a year,” he said. “By building quality, energy-efficiency homes, we can advance equity in a real way by supporting low-income families to spend less on utility costs and more on other basic essentials, such as food, medicine, health care.”

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FERC Rejects PJM’s FTR Credit Requirement Proposal

FERC on Monday rejected PJM’s proposal to modify the calculation of the financial transmission rights credit requirement and opened a show-cause proceeding to examine the justness and reasonableness of the existing requirement (ER22-703).

PJM establishes the FTR credit requirement for market participants on a portfolio basis that considers five factors, including:

  • a financial exposure calculation for each FTR path based on its historical value;
  • the addition of an increment for portfolios considered to be undiversified;
  • the application of a 10-cent/MWh volumetric minimum charge;
  • the subtraction of auction revenue rights (ARR) credits in an FTR participant’s account; and
  • the subtraction of the mark-to-auction value.

The proposal included several changes, including:

  • replacing the current approach of calculating collateral based on FTR historical value with an initial margin calculation from a historical simulation (HSIM) model using a 97% confidence interval;
  • removing the undiversified adder;
  • removing the component relating to the long-term FTR credit recalculation, because prices will be updated in real time under the HSIM model;
  • revising the 10-cent/MWh volumetric minimum charge to apply after ARR credits or mark-to-auction value adjustments; and
  • revising the tariff to provide that, at time of settlement, gains result in a decrease to, and losses result in an increase to, the credit requirement.

PJM filed its proposal with the commission in December after stakeholders endorsed it in October. (See PJM Stakeholders Endorse Initial Margining Proposal.) It was part of a two-year stakeholder process at the Financial Risk Mitigation Senior Task Force (FRMSTF) and resulted from efforts to strengthen the RTO’s FTR credit and collateral rules in response to a report by expert independent consultants on the GreenHat Energy default in 2018.

PJM said that the proposal addresses one of the last recommendations in the report that it has yet to implement: “eliminating the undiversified adder.” The RTO said it would be “a major step forward in advancing the overall recommendation to move the tariff’s FTR credit policy toward credit and collateral best practices in the energy commodity and financial derivatives industry.”

But much of the stakeholder debate in October centered around the confidence interval, with some advocating for 95% and others for 99%, ultimately settling on 97% as a compromise. The confidence interval refers to the “statistical certainty that a given value will exceed the range of possible outcomes (i.e., the losses in portfolio value over the margin period of risk) produced by the HSIM model,” according to PJM.

That proved to be the main sticking point for FERC, which said PJM “failed to demonstrate” that the proposal “reasonably calibrated to ensure that market participants will be required to provide adequate collateral relative to the risks of their positions.”

“Further, based on that record, we are concerned that PJM’s existing FTR credit requirement may no longer be just and reasonable,” the commission said.

Confidence Interval

The RTO argued that imposing a 99% confidence interval instead of 97% might “force some market participants to unwind market positions or to decide not to continue participation in the FTR auctions and FTR markets entirely.” A 97% interval “is designed to converge at a 3% failure rate over time,” it said, explaining that back-testing results are “satisfactory” if the total failure rate “agrees with the confidence interval used in the model.”

FTR collateral (PJM) Content.jpgEstimated confidence intervals for total FTR collateral | PJM

It conducted back-testing for 10,724 zonal path prices and found 139 failures for a 1.3% failure rate, which was less than the 3% failure rate expected with a 97% interval. The RTO said back-testing found the current FTR credit requirement has a potential 8% market failure rate.

“PJM contends that the FTR credit revisions increase collateral for some FTR market participants when the new methodology calculates those positions represent unreasonable credit risk to PJM and its members,” the commission said. “PJM asserts that it must be a market risk manager to protect PJM members from the risks of FTR defaults that potentially result in losses to PJM members that are not active participants in FTR markets.”

Stakeholder Responses

A group of stakeholders, including DC Energy, American Electric Power, Appian Way Energy Partners, Exelon, Old Dominion Electric Cooperative and Shell Energy N.A., jointly filed comments saying the proposed revisions would “better protect ratepayers” and “bring PJM closer to standards used in commodities and futures markets.”

They said there could be “unintended consequences” for PJM’s FTR markets because of “significant differences” in initial margin under a 99% confidence interval that “may cause some participants to reduce participation in the FTR market or liquidate FTR positions.”

The Independent Market Monitor said it supported PJM’s filing but requested FERC direct the use of the 99% confidence interval instead of 97% “based on industry standards.” A 97% confidence interval means that market participants “will be provided a subsidy of collateral-related costs and will not be required to cover a significant portion of their potential default risk at the expense of the entire PJM membership,” it said.

The Organization of PJM States Inc. also advocated for the use of a 99% confidence interval. It argued that the commission needs to protect load-serving entities “from uncovered losses that are directly or indirectly passed along to electric ratepayers” and that PJM “does not provide sufficient detail of the impacts on protection of nonparticipants and, ultimately on electric ratepayers, from the consequences of default risk exposure.”

Findings

The commission said it agreed with OPSI and the Monitor that the record “fails to support” a 97% interval, saying the RTO conceded that its independent auditors “validated the HSIM model at a 99% confidence interval rather than the 97% confidence interval as proposed.”

“Given that the proposed FTR credit revisions would result in lower aggregate collateral levels than PJM’s current collateral levels, we find that the lack of support regarding how the HSIM model used at a 97% confidence interval establishes reasonably calibrated collateral levels for riskier portfolios means that PJM has not met its burden to show that the FTR credit revisions are just and reasonable, particularly in light of the significant recent defaults involving the FTR market, and we reject the revisions on that basis,” FERC said.

The commission directed PJM to make an informal filing within 60 days of the date of the order to either show cause why its FTR credit requirement remains just and reasonable and not unduly discriminatory or preferential or explain what tariff changes will remedy the commission’s concerns. Stakeholders may respond to PJM’s filing within 30 days.

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MISO Stakeholders Uneasy Over Long-range Tx, JTIQ Overlap

MISO stakeholders continue to voice frustration over two transmission projects included in both MISO’s long-range planning and its interregional Joint Targeted Interconnection Queue (JTIQ) study with SPP.

Multiple stakeholders during Tuesday’s Planning Advisory Committee meeting asked why the RTO continues to show the projects on both its long-range and JTIQ maps. (See MISO Long-range Tx Plan Overlaps with SPP Study.)

Andy Witmeier, the grid operator’s director of resource utilization, said a long-range allocation mechanism is in place while MISO and SPP are just beginning cost-sharing negotiations for JTIQ projects. (See MISO, SPP Regulators to Engage on Tx Cost Allocation.)

Witmeier said while MISO is keeping its options open, it’s almost certain that the two recommended lines in both plans will end up in the long-range analysis. “The benefits to MISO far exceed the costs. The benefits to SPP are small,” he said.

Comparison of Long Range Tx Projects (MISO and SPP) Content.jpgComparison of projects in MISO’s long-range transmission plan (left) and MISO and SPP’s JTIQ study. The overlapping projects are in the Dakotas and Minnesota. | MISO and SPP

 

MISO’s Jarred Miland said staff is finalizing long-range project recommendations and will have the first of four portfolios ready for the Board of Directors’ approval in June.

The RTO has said repeatedly that its long-range plan takes precedence over the JTIQ’s project proposals.

“Shouldn’t there be some way of discussing the [project] hierarchy?” energy consultant Kavita Maini asked.

Maini said that MISO should devise some way to allocate a portion of costs to SPP because it knows the other RTO will benefit from the two projects. Other stakeholders chimed in, asking staff to find some way to ensure SPP’s load shoulders some costs, even if they are small.

Otter Tail Power’s Stacy Herbert, who also represents MISO’s transmission owners sector, said many stakeholders seem to mistakenly assume that the two JTIQ projects will move ahead despite the minimal benefit to SPP. She pointed out that historically, the two grid operators don’t ultimately agree on potential projects.

“Projects that move forward are those that have a more even sharing of benefits,” Herbert said. She also said that SPP could share in the long-term project costs through export charges once they are built.

Clean Grid Alliance’s Natalie McIntire asked that the RTOs quickly schedule their JTIQ meetings this year so stakeholders have notice when the next discussions will occur.

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IMM Report: PJM Capacity Auction Results not Competitive

The results of PJM’s 2022/23 Base Residual Auction were not competitive, according to a report released last week by the RTO’s Independent Market Monitor.

The 141-page report, coming nearly eight months after PJM announced the results, concluded that the noncompetitive nature of the auction came from “economic withholding by resources” that used offers consistent with the net cost of new entry (CONE) times the “expected average balancing ratio” offer cap, but not consistent with competitive offers based on the “correctly calculated” offer cap.

The Monitor concluded that market prices were “significantly affected by other flaws” in the capacity market rules and in PJM’s application of the rules, including the shape of the variable resource requirement (VRR) curve, the “overstatement” of the capacity of intermittent resources, the treatment of demand response, the minimum offer price rule (MOPR), the inclusion of energy efficiency and EE addback rules.

It also found that, although it played a smaller role in the 2022/23 auction compared to previous auctions, the rules “permitted the exercise of market power” without mitigation for seasonal resources “through uplift payments for noncompetitive offers, rather than through higher prices.”

“Although the impact was small in the 2022/23 auction, the issue should be addressed immediately in order to prevent the impact from increasing and because the solution is simple,” the Monitor said.

PJM’s capacity prices dropped significantly for delivery year 2022/23, falling by nearly two-thirds to $50/MW-day. Overall, the BRA, held May 19 to 25, cleared 144,477 MW of resources for the June 1, 2022, through May 31, 2023, delivery year, costing $3.9 billion, which was $4.4 billion less than the 2018 auction for 2021/22, after an adjustment for an increase in entities choosing to skip the auction by using the fixed resource requirement (FRR). (See Capacity Prices Drop Sharply in PJM Auction.)

Findings

The Monitor found that the 139,666.7 MW of cleared and uplift generation and DR for the entire RTO resulted in a reserve margin of 21.1% and a net excess of 7,660.2 MW over the reliability requirement, which is adjusted for FRR and price-responsive demand (PRD) of 132,006.5 MW. The net excess decreased by 530.1 MW from the net excess of 8,190.3 MW in the 2021/22 BRA.

RPM revenue (Monitoring Analytics) Content.jpgA scenario summary of RPM revenue in PJM’s 2022/23 Base Residual Auction | Monitoring Analytics

 

The downward sloping shape of the VRR curve had a “significant impact” on the auction results, the IMM said, resulting in more capacity cleared in the market than would have cleared with a vertical demand curve. If PJM had used a vertical demand curve, it said, total capacity market revenues for the 2022/23 BRA would have been $2.65 billion, a decrease of $1.25 billion (32.1%) compared to the actual results.

“From another perspective, clearing the auction using a downward sloping VRR curve resulted in a 47.3% increase in RPM [Reliability Pricing Model] revenues for the 2022/23 RPM BRA compared to what RPM revenues would have been with a vertical demand curve set equal to the reliability requirement,” the Monitor said.

Accuracy of the peak load forecast also had a significant impact on the results, the IMM said, showing that the forecast for the third incremental auction has been on average 4.3% lower than the peak load forecast for the corresponding BRA for the auctions between the 2017/18 and 2021/22 delivery years. Using the lower peak load forecast, the total capacity market revenues for the 2022/23 BRA would have been $3 billion, a decrease of about $900 million (22.4%) compared to the actual results.

Cleared UCAP (Monitoring Analytics) Content.jpgA scenario summary of cleared UCAP in PJM’s 2022/23 Base Residual Auction | Monitoring Analytics

 

The IMM said an increase in the Commonwealth Edison capacity emergency transfer limit (CETL) of 1,265 MW, or 22.7%, from its 2021/22 level also resulted in an increase of $128 million (3.3%) in revenues.

Dominion Energy Virginia’s election of the FRR lowered PJM’s reliability requirement by 18,233.8 MW. The IMM said that if Dominion had participated in the BRA, total capacity market revenues would have been $4.38 billion and that, excluding FRR resources, total revenues for the rest of the PJM capacity market would have been $4 billion, an increase of $92 million (2.4%) compared to the actual results.

Finally, the Monitor said that if no offers for DR were included in the BRA, total capacity market revenues would be $750 million higher, a 19.2% increase compared to the actual results.

Recommendations

The report included nearly two dozen recommendations for changes to the capacity auction.

The Monitor said PJM should evaluate the shape of the VRR curve because the current shape “directly results in load paying substantially more for capacity than load would pay with a vertical demand curve.” Excess capacity procured in a BRA should not be sold back in any incremental auction “at much lower prices,” it said, asserting that the sales suppress prices in IAs and “provide inefficient incentives for demand resource offer behavior.”

“Given PJM’s assertions of the benefits of over-procuring capacity, it has never been explained why load should pay a high price for capacity in a BRA and sell it back at very low prices in an IA,” the Monitor said. “Such sales are inconsistent with PJM’s assertion that additional capacity purchases have value.”

The IMM said an “enforcement of a consistent definition of capacity resource” is needed by PJM. It recommended that the tariff requirement be “enhanced” to require a capacity resource to be a physical resource and “should apply at the time of auctions and should also constitute a commitment to be physical in the relevant delivery year.”

The requirement to be a physical resource is not currently applied to DR and EE, the Monitor said, both of which are permitted to submit marketing plans rather than evidence of physical resources in the BRA. “The requirement to be a physical resource should be applied to all resource types, including planned generation, demand resources, energy efficiency and imports.”