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October 2, 2024

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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.”

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ERCOT’s Legal Issues Continue to Mount

ERCOT’s legal woes intensified Wednesday, with a Texas appeals court ruling against the grid operator’s long-held claim of sovereign immunity from civil litigation and blame being laid on Gov. Greg Abbott in a U.S. bankruptcy court for the high market prices that contributed to several electric providers going under following the February 2021 winter storm.

The Fifth District Court of Appeals in a 12-1 ruling found that the grid operator’s immunity claim has no basis in Texas law. The case is destined for review by the Supreme Court of Texas. The high court last year avoided making a determination on ERCOT’s claim to sovereign immunity. (See Texas Supremes Sidestep Ruling on ERCOT Lawsuit Shield.)

“The Supreme Court has not extended sovereign immunity to a purely private entity neither chartered nor created by the state, and this court will not create new precedent by extending sovereign immunity to ERCOT,” Justice Erin Nowell wrote in the opinion (05-18-00611-CV).

Bill Magness Dan Woodfin (ERCOT) Content.jpgERCOT’s Bill Magness (left) and Dan Woodfin speak to the press after the February 2021 winter storm. | ERCOT

Meanwhile in Houston, former ERCOT CEO Bill Magness testified that he was following Abbott’s orders when he directed wholesale power prices to remain at their $9,000/MWh price cap for 33 additional hours. That resulted in $16 billion in market charges that the grid operator’s Independent Market Monitor said were incorrect. (See Texas PUC Won’t Reprice $16B Error.)

Magness said he was told by former Public Utility Commission Chair DeAnn Walker that Abbott wanted the commission and ERCOT to do everything possible to prevent further outages, even as generators were thawing out and returning to service.

Walker followed Magness to the stand Wednesday. While she didn’t exactly corroborate Magness’ testimony, she did say Abbott had told her to “get the power back on” and keep it on. Walker spent several days at ERCOT’s main operations center in Taylor, where she was joined by Abbott adviser Ryland Ramos.

According to Magness’ log of contemporaneous notes, tweeted by Houston Chronicle investigative reporter Jay Root, Walker said Abbott had told her it was “imperative” that the outages not resume. “She was sent to make sure that did not happen, and to come up with solutions to potential problems that could send the system back into outages,” Magness wrote.

Abbott has disputed the account. In statements to the media, Abbott’s gubernatorial campaign has said that he only “instructed everyone involved that they must do what was needed to keep the power on and to prevent the loss of life.”

ERCOT decline to respond to the developments, saying it can’t comment on pending or active litigation.

At issue in the proceeding before the U.S. Bankruptcy Court for the Southern District of Texas is $1.9 billion in market charges ERCOT assigned to Brazos Electric Power Cooperative during the high-price period last February. Brazos is not disputing how much energy it bought to compensate for its own plants that did not run, but it argues it should owe about $800 million (21-03863).

The cooperative filed for Chapter 11 bankruptcy last March when it became evident it wouldn’t be able to pay the billions it owed. As of December, ERCOT said Brazos was still $1.89 billion short to the market. (See ERCOT’s Brazos Electric Declares Bankruptcy.)

Attorney Charles Gibbs, who represents Brazos’ largest member, CoServ Electric, popped in to the Infocast ERCOT Market Summit last week to deliver a brief update on the case.

“This will play out over the next few years. That’s the financial overhang of the storm,” he said.

Gibbs predicted that the judge overseeing the case, David R. Jones, will likely find in favor of Brazos. He said Jones may find the charges are not a legal good, or associated with priority claims, but noted that what took place during the storm was hardly the ordinary course of business.

“It can’t be a charge incurred during the ordinary course of business,” Gibbs said.

What happens if the ruling goes against ERCOT? he was asked.

“How does ERCOT pay? They’re a clearinghouse,” Gibbs said. “What assets do they have?”

The Fifth District ruling only adds to the grid operator’s legal problems. If upheld by the Texas high court, it would open the door to hundreds of lawsuits from Texas citizens seeking compensation for family members who died and property damage.

Attorney Majed Nachawati, with Fears Nachawati, said in a statement to RTO Insider that he looks forward to getting justice for his clients.

“We remain hopeful that state and federal prosecutors will hold the power companies and corrupt politicians accountable in the criminal justice system as well,” he said. “The public demands accountability, and we all must do our part to eliminate corruption and greed that harms everyone.”

The appeals court ruling stems from a lawsuit filed by energy investment company Panda Power Funds over $2.2 billion it said in invested to build three power plants in Texas. Panda said the decision was based on ERCOT projections that indicated energy supply shortages for years to come. The company has alleged the grid operator committed fraud and that Panda is selling power for less than what it expected because of the erroneous projection.

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Energy Bar Weighs OSW in Oregon, California

Three newly proposed call areas off the Oregon coast mean offshore wind could be a multistate affair in the West, requiring integrated planning and transmission, panelists said at Thursday’s annual meeting of the Energy Bar Association’s Western Chapter.

The U.S. Bureau of Ocean Energy Management (BOEM) identified the Oregon call areas Thursday, shortly before the meeting. Last year, BOEM said it would offer leases in two offshore wind areas in Northern and Central California, the first offshore wind developments on the West Coast.

“The growing Pacific Coast scale of this, which has just been expanded [with that day’s BOEM announcement] … sets in motion a whole set of speculation about coordination across the region,” said Adam Stern, executive director of Offshore Wind California.

The three large areas off the coast of southern Oregon could support up to 17 GW of generating capacity total. BOEM said in a presentation last week it intends to consider 3 GW for “near-term commercial development.” The presentation, which first identified the proposed call areas, was published Thursday in preparation for Friday’s meeting of the BOEM Oregon Intergovernmental Renewable Energy Task Force.

Five study areas off California’s north and central coasts could potentially support 21 GW of offshore wind, according to a study published in 2020 by the National Renewable Energy Laboratory (NREL). BOEM ultimately decided to pursue commercial development of 4.6 GW: 3 GW in the Morro Bay Call Area off the Central California coast, and 1.6 GW in the Humboldt Call Area off the Northern California coast. (See BOEM to Offer Leases for Calif. Offshore Wind.)

New Southern Oregon Call Areas (BEOM) Content.jpgThree newly identified call areas off the Southern Oregon Coast could eventually generate 17 GW. | BOEM

The northernmost point of the Humboldt Call Area and the southern boundary of Oregon’s Brookings Call Area are about 60 miles apart.

An auction for the California’s first offshore wind leases is expected this fall, pending approval by the state Coastal Commission.

The auction will be like last week’s sale of six leases in the New York Bight, which drew competitive bids totaling nearly $4.4 billion. It was the “nation’s highest-grossing competitive offshore energy lease sale in history, including oil and gas leases,” the U.S. Interior Department said in a news release. (See related story, Fierce Bidding Pushes NY Bight Auction to $4.37 Billion.)

“These results are a major milestone towards achieving the Biden-Harris administration’s goal of reaching 30 GW of offshore wind energy by 2030,” the department said.

The New York auction’s high prices are potential harbingers of lease prices in California, EBA panelists said.

Ports Problematic

California, however, is different from the East Coast in several ways, including the need for more expensive floating wind turbines for its deeper waters and a lack of port infrastructure to build and support offshore wind farms, panelists noted.

“The ports are a huge issue in California,” said Ella Foley Gannon, a partner at law firm Morgan Lewis in San Francisco. “Our ports are not well situated to these wind areas.”

The NREL study found “distance to port” in California would be a major driver of construction, operation and maintenance costs for offshore wind farms. Major ports in Los Angeles, the San Francisco Bay Area and San Diego are either too distant, unsuitable or both.

Floating wind turbines can be assembled in port and towed to sea, saving time and money, but bridges in San Francisco and San Diego create obstacles, it noted. “The Golden Gate Bridge, for example, has an air draft limit of 67 meters, rendering all of the San Francisco Bay ports unsuitable for floating wind turbine assembly,” it said.

Expanding and improving lesser ports that are closer to the wind areas is one possibility, but that will require large upfront investments.

Theodore Paradise, executive vice president for strategy at Anbaric, a developer of offshore transmission, said the West Coast will need infrastructure more like the East Coast’s to attract top-dollar bids.

“I think part of what we’re seeing in the New York Bight today is a tipping point around confidence over infrastructure,” Paradise said.

The East Coast had public-private partnerships emerge to develop port facilities, he said.

New Jersey is building the New Jersey Wind Port, which can serve the New York Bight and other East Coast wind development areas. The state appropriated $400 million for the first phase of the project, including channel dredging and establishing marshalling and manufacturing sites. Private companies such as Siemens Gamesa Renewable Energy have applied to be tenants.

California Gov. Gavin Newsom’s fiscal year 2023 budget includes $45 million for port development, but far more will be needed, panelists said. The $1.2 trillion infrastructure bill signed by President Biden in November contains $17 billion for port upgrades, some of which could go toward development for offshore wind, they said.

‘Planning Big’

Another factor is transmission, which is more cost-effective when built to encompass larger offshore wind areas, they said. In Germany and the Netherlands, projects are being planned on a large scale with 2-GW cables, they said.

Early experience with smaller East Coast projects created a “spaghetti of cables across the ocean floor,” costing far more to develop and more per megawatt, Paradise said. California and Oregon could learn from that experience and develop state or regional transmission plans, he said.

He likened offshore transmission to the Texas Competitive Renewable Energy Zones transmission project, which transports wind energy from West Texas and the Texas Panhandle to population centers in the eastern part of the state.

CAISO recently included offshore wind in its inaugural 20-year transmission plan, a positive step, panelists said. The ISO said the state needs approximately $8 billion for 500-kV and HVDC lines to carry 7 to 13 GW of offshore wind to major urban areas. (See CAISO Sees $30B Need for Tx Development.)

“I think a key thing is planning big and planning for scale,” OSW California’s Stern said. “We need to achieve a state-based supply chain in order for this to create the jobs and other benefits associated with offshore wind. And that’s only going to happen if there are high targets and there is a supporting infrastructure investment that the state of California can make in its ports, in its grid and in some of the other resources that will be needed to make this possible.”

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IPCC Climate Report: ‘Half Measures No Longer an Option’

The latest report from the U.N. Intergovernmental Panel on Climate Change (IPCC) carries a stark and urgent warning: The intensifying impacts of climate change are outpacing nature’s and societies’ abilities to adapt to or mitigate them.

Further, the report says, humans’ reactions — or lack of reactions — to climate change can increase the vulnerabilities already being caused by “the dynamic interactions among climate-related hazards.”

In the U.S., higher temperatures could “increase power system costs by about $50 billion by the year 2050,” the report says.

Heat waves could trigger soaring power prices in spot markets, with heavy impacts for low-income and disadvantaged consumers, the report says. Similarly, disruptions to weather patterns can also affect demand peaks and curves as residential and commercial customers respond to short-term “weather shocks” and longer-term changes.

“The energy system is really integral to thinking about the entire climate change issue,” said Delavane Diaz, a project manager at the Electric Power Research Institute (EPRI), who worked on the IPCC report.

Electricity systems can be especially vulnerable to extreme weather events, Diaz said.

“Depending on the climate impact driver, whether it’s extreme heat or flooding or wildfire, it can affect all elements of the system,” she said, from upstream fuel supplies to generation to consumption patterns.

Other power system vulnerabilities identified in the report include:

  • the impact of drought on water supplies, not only for hydropower generation but for the cooling systems needed for fossil fuel plants;
  • reduced output from photovoltaic solar panels in high and extreme heat as well as the potential need for additional cleaning of panels because of wind-blown sand. Rising temperatures could result in a 1% decrease in solar power production per year until 2049, the report says;
  • potential damage to distribution and transmission lines caused by extreme weather events, resulting in longer and more frequent power outages, with disadvantaged communities disproportionately affected.

“Increases in windstorm frequency and intensity increase the risk of direct damage to overhead lines and pylons,” the report says. “Where the mode of failure is recorded, transmission pylons are seen to be more susceptible to wind damage, whilst distribution pylons are more likely to be affected by treefall and debris.”

Climate-resilient Development

The IPCC report’s 3,675 pages are largely focused on the environmental impacts of climate change and the cascading effects that disruptions in one sector can have across others.

“This report recognizes the interdependence of climate, biodiversity and people and integrates natural, social and economic sciences more strongly than earlier IPCC assessments,” IPCC Chair Hoesung Lee said. “It emphasizes the urgency of immediate and more ambitious action to address climate risks. Half measures are no longer an option.”

For example, the report predicts that ongoing climate-related disruptions to supply chains and trade will cause “large market and non-market damages” to the North American economy.

The report’s big-picture solution is a call for “climate-resilient development,” which Diaz described as “kind of integrating both the climate impacts and the potential for adaptation responses into the same planning process.”

“So, when you think about the electric power system, we want to be able to plan for future conditions in terms of maybe the temperature distribution shifting or the frequency of extreme events maybe increasing,” she said. “It’s both accounting for the changes that are linked to climate change at the same time as integrating adaptation options, which could include changes to the technologies themselves or the way that they are operated.”

Debra Roberts, co-chair of the IPCC working group that produced the report, also stressed the importance of holistic solutions. “Tackling all these different challenges involves everyone — governments, the private sector, civil society — working together to prioritize risk reduction, as well as equity and justice, in decision-making and investment,” Roberts said.

“By bringing together scientific and technological know-how as well as Indigenous and local knowledge, solutions will be more effective,” she said.

Limits to Adaption

Environmental groups echoed the reports warnings and its call to action. 

“Even small increases in warming can multiply harmful impacts in the future,” said Daniel Bresette, executive director of the Environmental and Energy Study Institute. “But that does not mean our situation is hopeless. We have a small window of time to act, so we need to act now.”

Cherelle Blazer, senior director of the Sierra Club’s International Climate and Policy Campaign, called on Congress to pass strong climate legislation — without specifically mentioning the stalled Build Back Better Act.

“Each day that passes without Congress passing legislation investing in climate, jobs and justice is another day of needless stress and suffering for millions of people in the U.S. and abroad,” Blazer said. “There are limits to adaptation, and a stark pivot away from the fossil fuel economy to clean, renewable energy is required.” 

At the same time, Diaz believes that the U.S. energy sector should not only look at the future through a climate lens, but should also include factors like decarbonization policy, technological innovation and socio-economic trends.

“It’s not to say that climate change isn’t a priority, but it really needs to be looked at in an integrated setting because these factors can interact with each other,” she said. “Simply trying to impose a future climate projection on the current system misses all of these other elements.”