PJM PC/TEAC Briefs: Oct. 6, 2020

Installed Reserve Margin Study Results

PJM stakeholders last week unanimously endorsed an installed reserve margin (IRM) of 14.4%, down from 14.8% required in 2019, along with new winter weekly reserve targets.

During the Oct. 6 Planning Committee meeting, PJM’s Patricio Rocha Garrido reviewed the 2020 R eserve R equirement S tudy (RRS) results, which determined the IRM and forecast pool requirement (FPR) for 2021/22 through 2023/24 and establishes the initial IRM and FPR for 2024/25. The results are based on the 2020 capacity model, load model and capacity benefit of ties (CBOT).

The 2020 capacity model is putting downward pressure on the IRM, Garrido said, with the average effective equivalent demand forced outage rate (EEFORd) of 5.78%, compared to 6.03% in the 2019 RRS. Garrido said the lower average EEFORd was caused by the increased representation of combined cycle units and gas turbines.

The CBOT — the help PJM can expect from imports during peak loads — is estimated to increase pressure on the IRM. Garrido said imports from neighboring RTOs have decreased from 1.6% in 2019 to 1.5% in 2020.

“We’re getting a little less help from our neighbors,” Garrido said.

The FPR is essentially the same as 2019, Garrido said, coming in at 1.0865 (8.65%) instead of 1.086 the previous year.

Garrido said the study results will also be used in the 2022/23, 2023/24 and 2024/25 Base Residual Auctions (BRA). He said delays in the 2019 BRA for 2022/23 necessitated the use of data from the 2020 study.

The PJM and world load models used are based on the 2002-2014 period that were approved at the August PC meeting. (See “Load Model Selection,” PJM PC/TEAC Briefs: July 7, 2020.) Analysis from the 2020 PJM Load Forecast Report released in January was also used.

Erik Heinle of the D.C. Office of the People’s Counsel asked if the IRM and FPR would be updated after the first BRA was conducted to make sure the modeling is kept accurate.

Garrido said the driver of FPR is load uncertainty, so the results of the BRA wouldn’t matter for the FPR and does not necessitate a recalculation. Garrido said the recalculation is triggered by a new load forecast, which will be released in January.

Garrido also won a same-day endorsement after conducting a first read of the 2020/21 winter weekly reserve targets, which are slightly changed from last winter.

The targets for December, January and February are 23%, 27% and 23%, respectively, compared to 22%, 28% and 24% last year.

Part of the reserve requirement study, the targets help staff coordinate planned generator maintenance scheduling and cover against uncertainties by ensuring that the loss-of-load expectation (LOLE) for winter is “practically zero,” according to the study. For the entire year, PJM sets the LOLE at one occurrence in 10 years.

Interconnection Queue Initiative

Ken Seiler, vice president of planning, discussed PJM’s plan for a series of workshops to explore ways to improve the efficiency and effectiveness of its interconnection queue process.

Seiler said more than 660,000 MW of generation requests has been studied since the inception of the interconnection process in 1999. More than 70,000 MW has been energized in that time.

“The process has served us well, but the process continues to change,” Seiler said. “We believe it’s time to take a look at some changes within the queue.”

Seiler said the interconnection process has seen many improvements over the years, including automation of tools and additional staffing. PJM currently has 122,000 MW in the interconnection queue with 88% of the megawatts made up of renewable generation sources.

The most recent queue that closed at the end of September has more than 560 projects, Seiler said, with more than 40,000 MW of energy requesting to be interconnected. Of the 560 projects, he said, 500 are either solar or storage.

Based on feedback from stakeholders and the increasing volume and size of the interconnection requests, Seiler said PJM decided it was time to take a “fresh look” at the interconnection process. Four workshops are proposed, including a review of the interconnection process, stakeholder presentations, PJM’s response to the stakeholder presentations and paths forward.

Seiler said the construct for the workshops would be based on federal policy and FERC Orders Indemnification Provision for PJM Tariff.) The first two workshops would take place before the end of the year.

Adrien Ford of Old Dominion Electric Cooperative asked if PJM is looking for feedback on how stakeholders should proceed at looking at the interconnection process or on things that need to be changed in the process.

Seiler said PJM is looking for both things that need to be changed and a process forward to make the changes. He said the RTO has already identified things that need to be changed, but there are also hidden problems that can be identified by stakeholders.

“We want to hear what everyone has to say and what objectives are there and what the end goal is,” Seiler said. “We want to hear everything before locking down a plan to move forward.”

Sharon Segner, vice president of LS Power, said she appreciated the idea of having the workshops but wondered why the RTO hadn’t drafted a problem statement and issue charge to start an official stakeholder process. Segner said it costs time and resources for members to address issues, but with a formal stakeholder process there’s an opportunity to change rules instead of simply having discussions.

Seiler said there hasn’t been a defined problem that would necessitate a solution, so PJM wanted to identify problems through a workshop first before initiating the stakeholder process.

Dave Anders of PJM said a similar workshop method was conducted when stakeholders began looking at the energy price formation issue in 2017. (See PJM Stakeholders Explore Price Formation, Seek Transparency.) Anders said the workshops are designed to expose areas of interest for members to address in the stakeholder process.

ELCC Data Submission

Andrew Levitt of PJM’s market design and economics department provided an overview of the effective load-carrying capability (ELCC) data submission requirements and the applicable deadlines for intermittent and limited duration resources.

ELCC, which is already used by MISO, NYISO and CAISO, evaluates reliability in each hour of a simulated year and compares a resource mix with limited resources against one with unlimited resources.

Members endorsed a joint stakeholder proposal at the September Markets and Reliability and Members committee meetings to use the ELCC method to calculate the capacity value of limited-duration, intermittent and combination (limited-duration plus intermittent) resources. The proposal was endorsed over the objections of the Independent Market Monitor and other stakeholders who said the proposal was flawed and could have profound and unforeseen effects on the capacity market. (See ELCC Method Endorsed by PJM Stakeholders.)

PJM is attempting to make a FERC filing by Oct. 30 to satisfy a paper hearing procedure started last year to investigate whether the RTO’s 10-hour minimum run-time requirement for capacity storage resources is unjust and unreasonable. (See FERC Partially O K s PJM , SPP Order 841 Filings.)

Levitt said PJM needs data submittals from certain resource types by Nov. 1 to release ELCC results by December, the soonest FERC is likely to approve the October filing. Levitt said ELCC could be in place for the 2022/23 BRA.

Under the new rules:

“Immature” and planned solar and onshore wind projects that intend to deliver capacity in 2022/23 must provide estimates of hourly historical production back to June 1, 2012, based on site conditions and historical weather. PJM defines an “immature” resource as solar and onshore wind projects that came into service after June 1, 2012.
Immature and planned offshore wind, landfill gas and hydro without storage that intend to deliver capacity in 2022/23 must provide estimates of hourly historical production back to June 1, 2012.
All energy storage resources, hybrids and hydropower with non-pumped storage must provide relevant physical parameters, including MWh of storage.

Manual 14C Update

Mark Sims, PJM’s manager of infrastructure coordination, provided a first read of changes to Manual 14C: Generation and Transmission Interconnection Facility Construction.

Sims said minor changes are being proposed to Manual 14C as part of the biennial cover-to-cover review. Some of the changes include an update of the with the latest Tariff provisions clarifying the filing process for title transfers and associated title documentation in Section 5.

New sections on cost tracking for baseline projects and another for supplemental cost tracking are also being proposed, Sims said.

PJM will seek approval of the changes at the Nov. 4 PC meeting.

Transmission Expansion Advisory Committee

IEC Project Status

Questions over the status of the controversial Independence Energy Connection (IEC) transmission project were raised during a market efficiency presentation at the Oct. 6 TEAC meeting.

Nick Dumitriu, senior lead engineer for PJM, provided an update on the 2020/21 long-term market efficiency window. Dumitriu said the 2020 Market Efficiency Analysis Assumptions whitepaper was shared with the PJM Board of Managers for consideration at their Sept. 15 meeting.

Dumitriu said a preliminary market efficiency base case was posted Sept. 4, and a retooled base case is expected to be posted by the end of October. The final base case and congestion drivers will be posted in December before the start of the 2020/21 long-term window.

LS Power’s Sharon Segner asked if Transource Energy’s Independence Energy Connection running between Maryland and Pennsylvania will be examined by PJM during the reevaluation analysis scheduled to be completed between October and December as part of the Regional Transmission Expansion Plan (RTEP).

PJM — Transource’s proposed alternative plan for the eastern segment of its Independence Energy Connection project | ea

PJM selected the $383 million IEC — its largest market efficiency project to date — during the 2013/14 long-term planning window to address congestion in the AP South interface. The RTO has since reviewed its benefits to the grid several times, determining in each round that the project remains the most effective way to reduce load costs. (See Updated: Transource Files Reconfigured Tx Project.)

Tim Horger of PJM said the RTO has continued to look at the status of the project and is “taking seriously” the project review.

The project received a certificate of public convenience and necessity (CPCN) from Maryland in July. (See Md. PSC OKs Independence Energy Connection Deal.)

PJM — Sharon Segner, LS Power | © *RTO Insider*

Horger said PJM is deferring a review of the project pending a ruling from the Pennsylvania Public Utility Commission. Transource is seeking the PUC’s approval of land acquisition, siting and construction for a 230-kV line in Franklin and York counties. The record closed with the filing of reply briefs in late September (Docket # A-2017-2640200).

Horger said an update on the project will be provided at the November TEAC meeting.

Segner said PJM has an Operating Agreement requirement to continue reevaluating projects until all required permits have been received.

Horger said the project is in a unique situation where a CPCN has been issued by one of the states involved in the permitting process. He said there are “a lot of moving parts” involved in the project, including reliability impacts.

“LS Power would maintain the position that you have an obligation to follow your Operating Agreement under all circumstances,” Segner said.

October 12, 2020

PSPS Relief Funds Not Spent as Intended, CPUC Says

A big part of $612 million intended to provide battery backup to homes in high fire-threat areas has been gobbled up by customers who use electricity to pump well water instead of helping the low-income and medically vulnerable residents it was meant for, the California Public Utilities Commission said Thursday.

The CPUC approved $830 million for its Self-Generation Incentive Program (SGIP) in January, with $612 million dedicated to “equity” and “equity resiliency” subsidies to aid residents who face repeated public safety power shutoffs (PSPS) by utilities to prevent wildfires. Thousands of the program’s targeted customers rely on electrically powered medical equipment to keep them alive. (See California PUC Devoting $1.2B to Self-generation.)

In its decision, the CPUC authorized investor-owned utilities to collect $166 million annually from ratepayers from 2020 to 2024. However, the commission did not include income criteria for the well-pump grants, which are part of the program, nor did it prevent customers from applying for funds for their vacation homes.

“We were seeing some second-home residents” receive the hefty grants, which pay the full cost of battery storage and solar cells to charge the units, said Commissioner Clifford Rechtschaffen.

The program’s “very clear focus was on helping the most vulnerable customers and communities in high fire-threat areas and ones that had been affected by multiple PSPS events,” Rechtschaffen said. “In particular, we targeted medical baseline customers, low-income customers and critical care facilities in disadvantaged communities.”

“The program provides very, very generous subsidies,” he said.

PSPS Relief Funds — Portable solar and batteries are meant to help medically vulnerable customers during power shutoffs under the state’s SGIP program. | *Edison International*

More than eight months after the decision took effect, with one of California’s worst fire seasons in full force, the state’s three large investor-owned utilities haven’t started reaching out to medically vulnerable customers, Rechtschaffen said.

Instead, developers of storage systems have targeted households with wells, regardless of income, and scooped up much of the funding that was supposed to last through 2024. Commissioner Martha Guzman Aceves said an informal analysis by her staff showed that only a small percentage of the storage contractors were licensed by the state.

Pacific Gas and Electric has already committed its $270 million share of the multi-year program and has hundreds of customers on a waiting list, Rechtschaffen said. Southern California Edison and San Diego Gas & Electric have doled out 50% and 60% of their shares, respectively, he said.

Half the applications have been for well-pump programs, while 30% have been for medically vulnerable customers, he said.

In his proposed decis i on, Rechtschaffen wrote that “if current trends continue, incentive awards to electric-pump … customers threaten to severely limit the … funds available to the many other types of eligible residential and non-residential customers.”

He proposed adopting income eligibility criteria for grants that haven’t already been funded, requiring households to show they fall below 80% of an area’s median income and that a well provides water for their primary residence.

“Requiring electric-pump well customers to meet the same income eligibility restrictions required of most other …. residential customers levels the playing field and helps ensure that other types of customers with critical resiliency needs have the opportunity to use equity resiliency budget funds,” he wrote.

The decision would apply the new criteria to grants that were submitted but not fully funded as of Aug. 17, when Rechtschaffen issued a letter advising utilities of the commission’s concerns.

Several commissioners expressed unease about applying new rules retroactively to those who have already filed for funding.

“We evidently made a serious omission” in not restricting the funds based on income, said Commissioner Genevieve Shiroma. But “to now go back and say, ‘Oops,’” and change the rules for pending applications, “I’m very uncomfortable with that,” she said.

CPUC President Marybel Batjer said she shared her colleagues’ worries about retroactivity but believes the program must be fixed.

“I’m very concerned about the equity program and it being oversubscribed so quickly when this was [planned] to be a three-year rollout,” Batjer said. “On balance, I think we have to address it. And I agree, Commissioner Rechtschaffen, with your assessment, but I do feel we need more consideration on this item.”

The commissioners voted unanimously to put off a decision until their next meeting on Oct. 22 so they could gather more information and weigh their options.

October 12, 2020

CAISO Adds Scarcity Pricing to Policy ‘Roadmap’

CAISO said Wednesday it plans to begin a stakeholder initiative on scarcity pricing with an issue paper and formal start in January.

The planned measure is a response to the energy emergencies of August and September, which required CAISO to order rolling blackouts Aug. 14-15. The state avoided additional blackouts only through extraordinary conservation measures, including removing Navy ships from shore power.

Scarcity pricing had been part of the ISO’s efforts to enhance its day-ahead market and extend the Western Energy Imbalance Market from a real-time to a day-ahead market. But the shortages caused a reassessment, Brad Cooper, the ISO’s senior manager of market design policy, said during a web conference on the annual update to CAISO’s three-year policy initiatives road m ap.

“Prompted by the conditions that occurred this summer, we’re now planning a separate initiative that we’re going to prioritize for next year that’s going to explore enhancements to our scarcity pricing provisions,” Cooper said.

“Recently FERC approved our … Order 831 compliance filing, which in some cases raises the bid cap to $2,000, but it does that in relationship to fuel costs,” Cooper said. “Last summer, a lot of times, prices outside the ISO went above $1,000, and that was not driven by fuel costs but by scarcity conditions. Those events really drove home the need to improve our market pricing in those scarcity conditions.”

In September, CAISO’s Market Surveillance Committee recommended the ISO pursue a scarcity pricing initiative to deal with the types of severe shortfalls seen in mid-August and over Labor Day weekend. (See CAISO MSC Urges Scarcity Pricing for Emergencies.)

“The experiences of mid-August again signal the urgency of such an initiative,” the committee said in its unanimous opinion, which it forwarded to the CAISO Board of Governors. “These conditions will likely grow more frequent, and the region is in need of a more coordinated approach to managing scarcity conditions.”

CAISO Scarcity Pricing — Scarcity pricing will be part of CAISO’s policy roadmap come January. | *CAISO*

Prices during the Western “heat storm” in August rose to $1,000/MWh or more and showed the need for higher-priced import offers during times of regional scarcity, the committee said. CAISO and market participants have noted that ICE prices for imported energy from neighboring states rose from $1,500 to $1,750 at the Palo Verde trading hub, which feeds into Southern California.

Scarcity pricing is triggered in markets when systems become so strained that reserve margins meant to protect the grid from collapse are threatened, as happened during the August blackouts.

A root cause analysis of the August blackouts by CAISO and other California agencies showed transmission constraints prevented ample, available imports from reaching the CAISO market and did not cite scarcity conditions. (See CAISO Says Constrained Tx Contributed to B l ackouts.)

Cooper said he hopes to see an issue paper released soon after Jan. 1.

“We haven’t worked out the detailed schedule yet, but that’s our goal,” he said.

Other major initiatives in the roadmap include resource adequacy enhancements, day-ahead market enhancements and an effort to the extend the Western Energy Imbalance Market from a real-time to a day-ahead market.

All three could help CAISO meet its reliability issues as it switches from a market largely dependent on natural gas generation to one that plans to meet its capacity requirements through renewable energy and storage, ISO staff members said during the web conference.

A high priority is addressing the state’s summer evening net demand peak, after solar power goes offline but demand remains high during heat waves. The energy emergencies of August and September occurred under such conditions.

“A robust RA program is critical to ensuring reliable resources are procured with the right operational attributes and are available to the CAISO in order to serve load in all hours,” said Lauren Carr, an infrastructure and regulatory policy specialist with the ISO who presented the RA initiative.

The 2021 roadmap of policy initiatives is expected to go before the Western EIM Governing Body and the CAISO Board of Governors in December.

October 11, 2020

FERC OKs LS Power Acquisitions

FERC on Thursday approved LS Power’s acquisition of two generating facilities in PJM, rejecting the Independent Market Monitor’s request for behavioral mitigation measures to address market power.

The commission approved LS Power’s purchase of the Panda Hummel Station, a 1,096.5-MW natural gas-fired facility in Pennsylvania owned by several individuals and Siemens Financial Services, a subsidiary of Siemens AG (EC20-5 5).

Separately, the commission approved LS Power’s purchase of Jersey Central Power & Light Co.’s 50% interest in the Yards Creek Pumped Storage Station, a 420-MW facility in New Jersey (E C 20-65). The commission had approved LS Power’s purchase of the other 50% share of Yards Creek from PSEG Fossil LLC, a subsidiary of Public Service Enterprise Group, on Sept. 1 (EC20-4 9).

The Market Monitor argued that the three purchases should be considered together, saying they would increase concentration in some locational energy markets, have a significant impact on PJM’s market for regulation and increase concentration in the capacity market. Concentration in the Eastern Mid-Atlantic Area Council and MAAC locational deliverability areas (LDAs) would drop.

The Monitor said generators with market power can avoid mitigation by using varying markups in their price-based offers and by offering different operating parameters or using different fuels in their price-based and cost-based offers.

Because of that, it said LS Power’s combined cycle and combustion turbine resources should be prohibited from submitting price-based incremental energy offer curves that include both positive and negative markup relative to the cost-based offer. It also said they should be barred from submitting price-based offers with higher economic minimum output megawatt limits than the cost-based offer and required to submit cost-based offers for all available fuel types for dual fuel units.

The Monitor also expressed concern over the concentration in the ownership of fast-start resources, which it said allows sellers with high market shares the ability to use physical operating parameters to exercise market power. It said LS Power should be required to submit operating parameters for its fast-start units that meet PJM’s parameter limits.

The Monitor said pumped hydro units in PJM are not mitigated when their owners fail the three pivotal supplier test, allowing them to strategically withhold economic energy or to produce excess, uneconomic energy. It said the company should be required to follow the day-ahead schedule produced by the PJM hydro optimizer in real-time operations for Yards Creek and Seneca Generation, a 484-MW pumped storage facility in Pennsylvania.

LS Power’s pump storage units should also be prohibited from submitting simultaneous dual offers for both RegA (slow regulation) and RegD (fast regulation) products in PJM because it can result in uneconomic solutions, the Monitor said.

Finally, the Monitor said, LS Power should be required to make capacity offers at no greater than the net avoidable cost rate (ACR) because structural market power in PJM’s capacity market is endemic.

The commission rejected all of the Monitor’s proposed restrictions. It said the Monitor failed to show that the transactions will increase market power and said its proposed restrictions on offers from LS Power’s combined cycle and combustion turbine units “relies on existing perceived limitations of PJM’s market power mitigation.”

FERC also dismissed the Monitor’s proposed mitigation on LS Power’s pumped storage units, saying it was “based on general concerns about certain elements of PJM’s market design that are not specific to the [Yards Creek] transaction. This Section 203 proceeding to evaluate the proposed transaction is not the appropriate venue for raising or addressing general concerns regarding market design.”

The commission said the transactions’ aggregate 1,517 MW is too small to have a material impact on the RTO’s ancillary services markets. It also rejected the Monitor’s call for limiting LS Power’s capacity offers to net ACR, noting that the company’s post-transaction market share in the MAAC LDA is 4.6%.

October 11, 2020

NY Officials Create Waste Emissions Panel

The New York State Climate Action Council on Thursday approved creation of an advisory panel on waste emissions to be established by Department of Environmental Conservation (DEC) staff.

The panel joins six other s set up in August, along with a Just Transition Working Group to ensure social equity in the council’s proceedings.

New York waste emissions — Martin Brand, NYDEC | *NYDPS*

“We’re going to evaluate emissions and mitigation strategies for a wide range of these waste generating sectors, including the traditional municipal and commercial solid waste generation infrastructure; facilities like transfer stations, landfills and waste-to-energy; and municipal combustors and co-gen facilities,” DEC Deputy Commissioner Martin Brand said. (See NY Seeks Comment on Proposed Emissions Limits.)

The DEC also plans to look at all the handling, transportation and disposal aspects for that infrastructure, including some of the large-scale construction and demolition debris and materials processing activities around the state, Brand said.

New York’s Climate Leadership and Community Protection Act (CLCPA) directs the DEC to measure greenhouse gas emissions on a common scale using the carbon dioxide equivalence metric (CO2e) and the 20-year global warming potential (GWP20) of each gas, as derived from the U.N.’s Intergovernmental Panel on Climate Change (IPCC).

In addition, the CLCPA mandates that 70% of electricity consumed in the state should come from renewable resources by 2030 and that electricity generation should be 100% carbon-free by 2040.

Robert Howarth, Cornell University | *NYDPS*

“The waste stream overall for the greenhouse gas emissions for the state is smaller than fossil fuel use, but it’s not trivial — about 20% of statewide emissions are coming from this industry and these sources,” said CAC member Robert Howarth, Cornell University professor of ecology and environmental biology.

If looked at in detail, 95% of the total emissions from waste in New York is methane, not carbon dioxide, said Howarth, who recently published a study that shows methane emissions have grown as carbon dioxide emissions have declined, leaving New York’s total GHG emissions in 2015 virtually unchanged from 1990. (See NY Study Highlights Rising Methane Emissions.)

“When we think about the panel, I suggest that the membership be focused not on who the economic players are in the waste industry, but rather on where the GHG emissions are actually coming from,” Howarth said. “Our goal, of course, is to reduce those, so I would suggest a big focus on landfills, certainly on water treatment plants.”

Gavin Donohue, CEO of the Independent Power Producers of New York (IPPNY), said it is “really appropriate” how DEC has decided to reach out to local government authorities and waste management experts to help inform the panel’s deliberations.

Flexible Generation

Of all the topics being covered by the panel on power generation, resource mix is especially important, said Public Service Commission Chair John Rhodes, who leads the advisory panel.

“Which resources need to come up, which resources need to come down, and how do we get resources into the mix that can provide flexibility, which is going to be a big theme of our panel,” Rhodes said.

There also are a series of topics surrounding equity in terms of access to clean energy solutions, access to new jobs in the burgeoning industry and affordability for the many low-income New Yorkers who face a heavy energy burden, he said.

The panel intends to finalize its work plan in October before briefing the CAC on priority policies and strategies in December, ahead of making final recommendations in March, Rhodes said, noting it would evaluate the costs and benefits of recommended strategies, informed by the value of carbon established in accordance with the CLCPA.

A NYSERDA report last year shows GHG emissions from waste management (MMtCO2e), 1990–2016. | *NYSERDA*

“In New York we’ve seen a number of studies that look at decarbonization, that try to inform the discussion and create greater awareness of the issues, such as how to manage electrification, how to create flexibility and, importantly, how to avoid overbuilt scenarios of extreme new peaks, which are the bane of every system,” Rhodes said.

“I was glad to see carbon pricing on the agenda, but you didn’t list interaction with other panels,” Howarth said. “I’d like to see carbon pricing done in a context of all fossil fuel use, including transportation and housing and all, and not simply in the electricity sector.”

“That was a deliberate punt,” Rhodes said. “You’re right, carbon pricing certainly should be discussed economywide. It’s a little above my pay grade to think about who should take that on, which I could see being a Climate Action Council-level issue.”

Anne Reynolds, executive director of the Alliance for Clean Energy New York (ACE NY), brought up biofuels and renewable natural gas and asked Rhodes if the panel considered defining the term “emission-free.”

“There’s a requirement for 70% renewables by 2030 and 100% emissions-free by 2040, and the statute’s pretty clear on what counts as renewable but a little more vague on what counts as emission-free after that,” Reynolds said.

The topic did not come up on the panel but should be dealt with, Rhodes said.

CAC member Paul Shepson, dean of Stony Brook University School of Marine and Atmospheric Sciences (SoMAS), asked what panel or panels would consider methane emissions, particularly if in big cities they prove to be coming from natural gas infrastructure.

“Many of the panels are going to be dealing with the issue of methane emissions,” said CAC Co-chair and DEC Commissioner Basil Seggos. “We may want to charge every panel with considering that, and then find a way to bring all the panels together in a joint session to cross-fertilize recommendations, rather than creating a new panel.”

Administrative Law Judge Molly T. McBride will conduct two public comment hearing webinars for the proposed emissions rule on Oct. 20, and the DEC will accept public comments until Oct. 27.

Grid in Transition

NYISO CEO Rich Dewey presented on the grid operator’s Grid in Transition initiative, which is taking place in conjunction with a state-mandated grid study underway by the New York State Energy Research and Development Authority and Department of Public Service to identify distribution upgrades, local transmission upgrades and bulk transmission investments needed to meet the state’s clean energy goals (Case No. 20-E-0197).

“Upstate New York is pretty carbon-free already, in terms of the supply, and downstate there’s a high intensity of carbon producing power plants,” Dewey said. The challenge will be to move that power into New York City to displace the generation that’s coming from those resources, and that will be instrumental to how we achieve those goals.”

Tammy Mitchell, chief of bulk electric systems for the DPS, presented an overview of the grid in New York and how her office and the PSC regulate utilities, renewable energy programs and electric rates.

“Notably, the commission-approved energy affordability program provides $237 million in bill assistance to about 937,000 low-income utility customers to offset electric utility costs,” Mitchell said.

Donohue said that “renewables and what we have today, wind, solar and storage, are not going to get us to where we need to go all alone. We need new technologies … what do we need to do marketwise to attract those new technologies?”

The goal that electricity be 100% carbon-free by 2040 is the real challenge, especially getting rid of that last small percentage of nonrenewable resources, Dewey said.

“We feel pretty comfortable that 70% by 2030 can be achieved by wind, solar and storage — you just have to make the right kind of investment, and they have to be located in the right spot,” Dewey said. “But we do not believe we can get to 100% carbon-free electricity without some sort of development of these newer technologies that can be dispatchable, that can be available and still be carbon free.”

The ISO is a big proponent of markets as the way to achieve the state’s environmental goals, he said.

“You take that risk off the ratepayers and you put it on the investors,” Dewey said. “Our approach is carbon pricing, but it’s not just carbon pricing. … The types of resources we need are a little bit different when you start thinking about backstopping the intermittency of the renewables, so you’re going to need units that can respond quickly, ramp quickly.”

October 11, 2020

PG&E Under Scrutiny in Deadly Zogg Fire

California fire investigators are looking at a distribution line as the possible cause of the Zogg Fire, which killed four residents and destroyed more than 200 structures southwest of Redding, Calif.

The 56,000-acre fire started on Sept. 27 near the rural Shasta County community of Igo. Among the victims were a 45-year-old mother and her 8-year-old daughter, who died trying to escape the flames.

A PG&E distribution line, the Girvan 1101 12-kV circuit, serves customers in the area of Zogg Mine Road and Jenny Bird Lane, where the fire began, PG&E said in an incident r e port to the California Public Utilities Commission on Friday.

Wildfire camera and satellite data on Sept. 27 showed “smoke, heat or signs of fire in that area between approximately 2:43 p.m. and 2:46 p.m.,” it said.

“A PG&E SmartMeter and a line recloser serving that area reported alarms and other activity between approximately 2:40 p.m. and 3:06 p.m. [on Sept. 27], when the line recloser de-energized that portion of the circuit,” PG&E said. “The data currently available to PG&E do not establish the causes of the activity on the Girvan 1101 circuit or the locations of these causes.”

On Oct. 9, investigators with the California Department of Forestry and Fire Protection (CAL FIRE) told PG&E they had taken its equipment as part of their investigation of the Zogg Fire, PG&E said.

“PG&E is cooperating with CAL FIRE in its investigation,” the utility said. “This information is preliminary.”

CAL FIRE has not yet determined how the fire started, PG&E noted.

PG&E Zogg Fire — Searchers indentified at least four sets of human remains in the Zogg Fire. | *Shasta County Sheriff’s Office*

Involvement in another major fire would mark the fourth year in a row that PG&E equipment has been blamed for highly destructive conflagrations. Its equipment started the worst fires of the October 2017 “fire storm” in Napa and Sonoma counties and the November 2018 Camp Fire, which killed 85 people and destroyed the town of Paradise.

The company emerged from bankruptcy in June after agreeing to pay fire victims, local governments and insurers $25.5 billion in the 2017-18 fires and pleading guilty to 85 felonies stemming from the Camp Fire. (See PG&E Sentenced; Bankruptcy Plan App r oved.)

CAL FIRE also determined that a PG&E transmission line started the Kincade Fire, which tore through Sonoma County wine country in October 2019.

The company has avoided blame so far for any of the major wildfires of 2020, one of the worst fire seasons on record. A series of massive fires sparked by lightning on Aug. 17-18 includes the August Complex, the first California wildfire to exceed 1 million acres. It was 67% contained as of Sunday, state and federal fire officials said.

In total, more than 8,000 wildfires have burned nearly 4 million acres in California this year.

Until Friday’s report — which PG&E also sent to the U.S. Securities and Exchange Commission — only one other investor-owned utility in California had fallen under suspicion for starting a major fire in 2020. (Calif. IOU s Escape Blame for Fires so Far.)

In a Sept. 15 r e port to the CPUC, Southern California Edison said the U.S. Forest Service had asked the utility to remove a section of its overhead conductor as part the agency’s investigation of the Bobcat Fire, still burning in the mountains and foothills northeast of Los Angeles.

SCE said it had experienced a “relay operation” on the 12-kV circuit at approximately the same time and in the same place as the fire started, but it contended that a fire camera had recorded smoke from the blaze prior to the incident.

“While USFS has not alleged that SCE facilities were involved in the ignition of the Bobcat Fire, SCE submits this report in an abundance of caution given USFS’ interest in retaining SCE facilities in connection with its investigation,” the utility told the CPUC.

October 11, 2020

PJM OC Briefs: Oct. 8, 2020

PJM stakeholders unanimously endorsed two manual changes at the Oct. 8 Operating Committee meeting.

Darrell Frogg, senior engineer of generation for PJM, reviewed updates to Manual 14D: Generator Operational Requirements.

Frogg said section 7.5.1 was changed to reflect that cold weather operational exercises will no longer be administered by PJM and instead be handled by generation owners. The RTO is recommending that generation owners self-schedule testing of resources that have not operated in eight weeks leading up to Dec. 1.

One change was made from the first read in September, Frogg said. Section 7.3, critical information and reporting requirements, calls for providing notification to PJM dispatchers at least 20 minutes prior to a change in state of each generating unit and will include any changes of more than 50 MW to the output of a self-scheduled resource that is not following the security-constrained economic dispatch (SCED) basepoint. Frogg said the change resulted from stakeholder questions.

Vince Stefanowicz, senior lead engineer of generation, reviewed updates to Manual 10: Pre-Scheduling Operations in a periodic review. The changes include several clarifying changes but nothing substantive, he said.

Stefanowicz said minor changes were made from the first read, including replacing the term “eDART Installed Capacity (eDART ICAP)” with the term “eDART Reportable MW” in Section 2.1, generation outage reporting overview. Stefanowicz said several stakeholders expressed concern over possible confusion with the capacity market term of ICAP.

Both manual updates will go to the Oct. 29 Markets and Reliability Committee meeting for first reads and final endorsements in November.

Day-ahead Schedule Reserve Update

David Kimmel, senior engineer of performance compliance, review e d the preliminary proposed changes to the 2021 day-ahead scheduling reserve (DASR) requirement. He said the numbers may slightly change when the measure is brought for final endorsement in November.

The DASR is the sum of the requirements for all zones within PJM and any additional reserves scheduled in response to a weather alert or other conservative operations. It is the sum of the three-year average of under-forecasted load forecast error (LFE) and the three-year average of eDART forced outages.

Kimmel said the preliminary 2021 DASR requirement is 4.78%, slightly lower than the 2020 requirement of 5.07%. He said the number comes from the LFE component of 2.18% and the forced outage component of 2.6%.

Stakeholders will be asked to endorse the changes at the next OC meeting. The final 2021 DASR value will be incorporated into Manual 13 changes and be implemented in January.

Manual First Reads

Stakeholders heard several first reads of minor manual changes.

Maria Baptiste of PJM rev i ewed updates to Manual 3A: En e rgy Management System Model Updates and Quality Assurance. Baptiste said the changes include correcting grammatical mistakes and updating references to the behind-the-meter generation (BTMG) rules that took effect in September 2019. (See “Non-retail BTM Generation Rules Endorsed,” PJM MRC/MC Briefs: Sept. 2 6, 2019.)

Lagy Mathew of PJM revie w ed updates to Manual 3: Tran s mission Operations. Mathew said the changes featured minor clarifications, including defining the term “extra-high voltage (EHV)” lines as those equal to or greater than 345 kV.

Kevin Hatch of PJM reviewe d updates to Manual 12: Bala n cing Operations to address changes from the five-minute pricing and dispatch Market Implementation Committee special sessions. Hatch said PJM has been working with the Independent Market Monitor to identify sections of Manual 12 to be updated and to improve transparency on the dispatch process.

Hatch said the changes include updated terminology for “day-ahead market” instead of the outdated “two-pass system.”

Stakeholders will be asked to endorse the changes at the November OC meeting.

October 11, 2020

MISO Market Subcommittee Briefs: Oct. 8, 2020

MISO has at once rebranded and postponed its attempt to develop more sophisticated modeling software that can accommodate different combinations of combined cycle units and their dependencies.

The delay marks the third time MISO has pushed back an effort at combined cycle generation modeling. It also renamed the more involved process “multiple configuration resource” modeling.

MISO Director of Business and Digital Transformation Dhiman Chatterjee announced the further delay during an Oct. 8 Market Subcommittee call. MISO projects it will be able to model combined cycle interdependencies sometime late in 2025 at the earliest.

MISO first planned to put improved combined cycle modeling in place by 2020, then delayed until 2022, and again into mid-2023. The RTO said its current market platform couldn’t technically handle the software. (See “At Least 1 Market Project Delay,” New MISO Platform Headed to the Cloud.)

MISO now says General Electric is delaying delivery of a new market clearing engine beyond original expectations, making combined cycle modeling an even more distant prospect.

Chatterjee also said MISO experts, already working on other priorities, will be further taxed by implementation of FERC Order 2222, which requires RTOs to enable aggregators of distributed resources the opportunity to compete in organized markets.

MISO has previously said it could save anywhere from $14 to $34 million annually if it implemented enhanced combined cycle modeling.

“This is beyond frustrating,” Xcel Energy’s Kari Hassler said. “I’m flabbergasted MISO continues to push this project out even though there are substantial savings to be had … This is a product that the entire footprint needs.”

Stakeholders asked if MISO could do something in the meantime to incrementally model combined cycle generators. Chatterjee said MISO is trying to be as transparent as possible about the challenges of implementing the modeling on its existing market platform.

“I just find it odd that [General Electric] said this is so complex of an ask when they’ve done something similar in SPP, and SPP has had it for about three years now. The complexity level is not extremely high,” Hassler said.

Chatterjee said SPP in fact encountered some technical difficulties when it introduced similar modeling. He also said SPP’s market clearing engine and interfaces are different from MISO’s.

“The tools are all customized, individualized for each RTO, and that’s why it’s so complex,” Chatterjee said.

“We’ll try to be ready, and if an opportunity presents itself, we’ll jump on that,” he added.

MISO Braces for 2nd Hurricane

At the time of the Oct. 8 meeting, Executive Director of Market Operations and Resource Adequacy Shawn McFarlane said MISO was preparing for the then-Category 3 Hurricane Delta, the 25th named storm of the 2020 Atlantic hurricane season.

“Unless you’ve been living under a rock, you know we have another hurricane forming in the Gulf and headed to Louisiana,” McFarlane said.

While Hurricane Delta’s projected landfall is only about 10 miles east of where Hurricane Laura made landfall, McFarlane said the relatively good news was that the new storm is weaker and faster-moving. He also said a weekend landfall means less load to be possibly interrupted.

“So on a relative basis, that is a better situation,” McFarlane said.

MISO decla r e d conservative operations and a transmission advisory for its South region beginning Friday.

McFarlane warned that Entergy’s Louisiana territory is still experiencing transmission line outages from the last storm. Hurricane Laura’s landfall on Aug. 27 brought MISO’s first load-shed orders and widespread transmission damage. (See MISO Keeps Advisories in Effect a Week After L a ura.)

“Certainly, we’re not as resilient as we could be because of Hurricane Laura,” he said.

IMM Reassures Stakeholders on Coal Self-commitments

MISO’s Independent Market Monitor reiterated that most coal self-commitment decisions in the footprint are made prudently.

Last month, Monitor David Patton provided the Board of Directors with analysis showing that most of the footprint’s coal self-commitments are profitable. (See MISO IMM Rebuts Uneconomic Coal Com m itment Studies.) This time, he brought the results to stakeholders.

“We don’t see the level of concern that prior studies have indicated,” Patton told stakeholders.

The Union of Concerned Scientists has released its own study concluding that Xcel Energy, DTE Energy, Cleco Power and Consumers Energy repeatedly make uneconomic coal generation commitments, costing ratepayers. (See UCS Analysis Knocks Coal Self-commitme n ts.)

Patton said self-committed coal dispatch returned fewer revenues in 2019 only because all energy prices were lower across MISO.

MISO Communication System Still a Source of Frustration

MISO has conceded again that its communication system for emergency resources needs to be more user-friendly.

The acknowledgment came during a review of load-modifying resource performance for an early 2019 generation emergency.

Market participants use the nonpublic MISO Communication System (MCS) to update availability of their load-modifying resources for use in emergency conditions.

“I know the MCS is not the most beloved system, but it does provide important information to MISO,” MISO Corporate Counsel Jacob Krouse told stakeholders during an Oct. 7 Resource Adequacy Subcommittee conference call. MISO stakeholders have long criticized MCS as being clunky and difficult to navigate. (See Stakeholders: M ISO System Fix Too Late for Summer.)

MISO issued a maximum generation event Jan. 30-31, 2019, in its North and Central regions during a record cold snap. While it called on more than 180 LMRs, only 21% met their expected load reduction. MISO levied almost $3 million in penalties to underperforming LMRs, and nine market participants sought alternative dispute resolution that lasted until early 2020.

Krouse said during the course of the dispute resolution, market participants indicated they were confused about what data they needed to input into the MCS. Some market participants weren’t following MISO’s requirement to furnish the MCS with their most up-to-date LMR availability data either, Krouse said.

He also noted that the MCS contained “default values inconsistent with LMR registration information,” which was fixed with monthly updates.

Krouse said there was confusion among MISO market participants on whether scheduling instructions would come from the MCS or another MISO mode of communication.

Krouse said MISO is working on MCS improvements following discussion from the Demand Response and MCS Alignment Task Team, formed last year. Further MCS improvements might be rolled out in mid-2021.

October 11, 2020

MISO Lays Out Seasonal Capacity Options

MISO resource adequacy staff are considering multiple options in the RTO’s effort to implement a sub-annual capacity mechanism and define new reliability criteria.

MISO has said it could define unique seasonal system reliability requirements as a bulwark against its increasing emergency events outside summer months. The RTO’s analyses indicate an emerging wintertime loss-of-load risk. MISO said it could be in the position of facing a winter peaking situation when electrification picks up in 2035 and beyond.

The shift could prompt MISO to issue a sub-annual reserves requirement based on a seasonal resource adequacy construct.

Stakeholders attending a virtual Resource Adequacy Subcommittee meeting Oct. 7 asked if MISO would run a Planning Resource Auction (PRA) four times per year.

MISO Director of Research and Development Jessica Harrison said several options are under consideration, including an annual construct that reflects sub-annual needs, one annual auction with seasonal or monthly segments, multiple seasonal auctions or monthly auctions across the planning year.

MISO is also exploring the use of additional risk assessments beyond loss of load, including the expected unserved energy calculation, where MISO calculates the expected amount of energy when load is set to exceed generation.

Senior Manager of Resource Adequacy Coordination Lynn Hecker said there could be additional “administrative burden” on MISO and its members if it develops separate planning reserve requirements and resource accreditations for each season.

“That’s really on the MISO to-do list, to get a better idea of what — if any — administrative burden … the proposed construct options might create,” she said.

If MISO moves to a sub-annual version of the capacity auction, Hecker said it would reduce its focus on summer peak modeling and forecasting in favor of pinpointing multiple loss of load risk hours throughout the year, called resource adequacy hours. RA hours would likely occur in summer and winter.

Harrison said MISO must decide if it should rely more on forward-looking projections or historical data to establish accreditation and reserve requirements using resource adequacy hours.

“In a time of slower-paced change, that’s reasonable; in a time of fast-paced change, that’s less reasonable,” she said of historical data being a predictor of system conditions.

Seasonal capacity auctions might give way to more seasonal economic outages, MISO and members said.

Harrison said MISO will be mindful of a seasonal auction’s possible effect of corralling too many generation outages into shoulder seasons. The RTO might consider must-offer obligations on capacity resources for each sub-annual period.

“The more granular we go, the more complex it will be to implement,” Hecker said.

The State Authority Quandary

The possibility of new reliability requirements has MISO and members probing the complicated relationship between MISO and state authority.

Some stakeholders have said that a move toward additional reliability criteria could infringe on state jurisdiction over resource adequacy and that MISO’s existing annual local clearing requirements and planning reserve margin are sufficient for reliability needs. (See MISO Closer to Se a sonal Capacity, Reliability Reqs.)

To date, no states have ever requested that MISO increase or decrease a planning reserve margin, said MISO Managing Assistant General Counsel Michael Kessler.

The MISO Tariff stipulates that states have the authority to superse d e the RTO and set their own planning reserve margins, but they cannot change MISO’s local reliability requirements or local clearing requirements. MISO would have to incorporate a state-set planning reserve margin into its planning resource margin requirements if it received a special state margin figure for a set of jurisdictional utilities. The Tariff also prohibits MISO from developing a resource adequacy requirement that conflicts with “state reliability or safety standards.”

Kessler said there’s “no other entity … than a state authority” that can alter MISO’s planning reserve margin requirement.

Some stakeholders questioned why states wouldn’t also have at least some authority over local reliability requirements or local clearing requirements if resource adequacy is ultimately the states’ prerogative.

Six of MISO’s ten local resource zones include territory from two or more states.

“Our interpretation of the Tariff — our literal reading of it — is that states do not have the authority to create a different local reliability requirement other than the one established by MISO,” Kessler said.

If a state chooses to set a lower planning reserve margin, the local clearing requirement of a local resource zone would still apply, Kessler said, with MISO still responsible for procuring capacity up to the requirement. Costs of the extra capacity procurement would be uplifted to the entire MISO footprint.

WEC Energy Group’s Chris Plante asked whether states could use a different loss of load risk than MISO’s one-day-in-10-years standard. A state’s decision to rely on a two-days-in-10-years risk would seem to affect zonal clearing and reliability requirements, he said.

“We haven’t had to work through a scenario where some of these mechanics would apply,” Kessler said, adding that MISO could pursue a deeper legal analysis of interaction between the Tariff and state law.

Plante has noted that states already largely rely on MISO’s recommended margins to set their resource adequacy plans.

“I think states increasingly look to MISO to establish their reserve margins,” he said during a special Aug. 21 MISO teleconference to discuss resource availability.

Zone 7 Reliability Requirements Questioned

Stakeholders are expressing consternation over draft 2021/22 PRA reserve requirements. This year, MISO began factoring unavailable generation due to planned outages into its loss of load expectation (LOLE) modeling, result i ng in higher local reliability requirements for almost all local resource zones.

MISO is estimating it needs a 9.4% unforced capacity (UCAP) planning reserve margin, up from last year’s 8.9% figure. Translated into an installed capacity basis, MISO needs an 18.3% reserve margin requirement in 2021, compared with 18% last year. (See MISO Planning Reserve Margin t o Climb in 2020.)

The need for more padding is the most dramatic in Lower Michigan’s Zone 7. Some stakeholders said it was unfair that a few individuals in MISO’s modeling group could have such an outsized impact on capacity requirements.

Customized Energy Solutions’ Ted Kuhn asked for “guardrails” in the LOLE modeling inputs process so members could expect more stability in the results.

MISO said its LOLE analysis showed that Lower Michigan runs the risk of more peak demand days in September than other local resource zones.

MISO plans to publish final LOLE results by Nov. 1.

MISO seasonal capacity — MISO’s UCAP planning reserve margin 2011-2021 | *MISO*

For the 2020/21 planning year, Zone 7 cleared at a cost of new entry price of $257.53/MW-day, due in part to a new MISO rule banning capacity resources from taking extended outages. (See MISO: New Outage Rules Boosted M i ch. Capacity Prices.)

MISO Independent Market Monitor David Patton sa i d two resources in Zone 7 raked in a combined $154 million in the 2020/21 Planning Resource Auction despite being on outages over the entire summer.

“Those resources are effectively unavailable even though we pay them the same,” Patton said during an Oct. 8 Market Subcommittee conference call.

Patton said he has long calculated leaner capacity margins than MISO projects because of the RTO’s failure to incorporate outages into its capacity picture.

Meanwhile, Planning Adviser Davey Lopez said MISO’s short-term resource availability and need fixes were successful in freeing up an additional 5-10 GW in capacity over the past year, as planned.

MISO launched new Tariff rules early last year to introduce demand response capability testing, seasonal documentation of the availability of load-modifying resources and a 120-day notice period for planned generation outages. (See “Near-term Filings,” MISO to Continue Resourc e Adequacy Talks in 2019.) The rules were meant as a stopgap measure to buy the RTO more time to flesh out bigger ideas.

“We are striving to come up with longer term solutions. The first phase was intended to buy time,” Lopez said, adding that MISO must continue working on the longer-term PRA changes. “Capacity margins continue to erode.”

October 11, 2020

NEPOOL Markets Committee Briefs: Oct. 6-8, 2020

The New England Power Pool Markets Committee last week rejected ISO-NE’s proposal for recalculating the dynamic delist bid threshold (DDBT) for Forward Capacity Auction 16, along with several proposed amendments to the RTO’s plan, none of which attracted the necessary 60% for endorsement.

The DDBT issue consumed half of the first day of the committee’s three-day meeting.

The DDBT for FCA 15 for 2024/25 is $4.30/kW-month. The Tariff requires the threshold, which was last updated in 2017/18, be recalculated for FCA 16 (2025/26).

The RTO proposed recalculating the DDBT annually using publicly available data, saying it would address transparency concerns and keep the threshold aligned with current and expected market conditions.

It would make the DDBT the average of the preceding FCA price and the price the capacity that cleared in the preceding FCA intersects with the estimated system-wide demand curve for the upcoming FCA. The threshold would not exceed the net cost of new entry (CONE) or fall below 75% of the preceding FCA price; the net CONE limit would apply if the two overlapped.

Jeffrey Bentz, director of analysis for the New England States Committee on Electricity (NESCOE), expressed concern in his presentati o n that setting the DDBT too high or at net CONE could improperly allow some bids to escape the scrutiny of a market power review. NESCOE proposed lowering the upper bound to 85% of net CONE or 125% of the prior auction clearing price, saying it would strike a better balance between the design objectives of providing adequate review to prevent market power and limiting unnecessary administrative interference.

NESCOE also proposed limiting the maximum rate of change in the DDBT from auction to auction to 30% of net CONE.

In a me m o to the committee, ISO-NE’s Matthew Brewster wrote that NESCOE’s proposals would “constrain the DDBT value relative to the [RTOs’] proposal under various conditions, which could undermine this key enhancement achieved with the new DDBT calculation method. … By preventing the DDBT from adjusting to reflect projected market conditions for the next FCA, the amendments would cause the DDBT to remain a lagging, or ‘stale’ estimate of the appropriate delist bid review threshold.”

The memo also said that “while NESCOE suggests a one-directional remedy within the DDBT for (potential) errors” in net CONE, it does “not appear to provide a reasoned basis for the numerical value of the proposed cap at 85% of net CONE.” Additionally, NESCOE’s other proposed DDBT cap of 125% of the last FCA clearing price “has only a superficial symmetry with the floor present in the ISO’s design.

“The underlying assumption of this 125% cap is that the supply curve becomes flat at prices 25% higher than the last FCA clearing price,” the memo continued. “However, that outcome is not supported by theory … nor is it plausible in practice. The supply curve generally is increasingly steep as quantity increases (up to the point where prices reach true net CONE).”

The NESCOE amendments failed with only 34% support.

The committee also rejected proposals by Calpine and Vistra Energy’s Dynegy unit to address what Bill Fowler, president of Sigma Consultants, said is the disadvantage faced by resource owners having to lock in static delist bids four months before the FCA.

At the September Markets Committee meeting, Fowler said the DDBT should be set at a “reasonable margin” — 50 cents to $1/kW-month — above the expected clearing price. (See “Change to Delist Bid Threshold,” ISO-NE Challenged on Wind, S olar, Storage Revenues.) Fowler revised the pro p osal last week, calling for “a small cushion” varying with the level of the expected clearing price, declining to zero if the expected clear is at net CONE. It won only 49% support.

Also rejected was a Calpine/Dynegy proposal to eliminate the obligation to commit to a bid price in October and make the October static delist finalization requirement a cap on auction prices.

ISO-NE’s proposed DDBT changes, the last vote, received only 44.5%. The RTO will file the proposal with FERC despite the lack of stakeholder endorsement.

Support for Forward Reserve Market Sunset

On a voice vote, the committee approved ISO-NE’s p r oposal to sunset the forward reserve market (FRM) to avoid conflicts with its proposed Energy Security Improvements (ESI) initiative, which is awaiting FERC action. (See ISO-NE S ending 2 Energy Security Plans to FERC.)

The FRM awards obligations for 10-minute non-spinning reserves and 30-minute operating reserves, but the RTO said it is becoming unnecessary because of ESI and transmission investments and market changes that address locational constraints and reward resource flexibility.

The RTO’s proposal included two alternatives. If FERC issues an order approving ESI as filed before Dec. 31, the RTO will file a “non-contingent” Tariff change by the end of 2020 to sunset the FRM on June 1, 2025, coinciding with the start of the 2025/26 capacity commitment period.

If FERC does not rule on ESI before the end of the year, the RTO would file a “contingent” FRM sunset that would take effect if FERC approves ESI as filed.

If FERC rejects ESI, the RTO will not file either Tariff change. The RTO said future discussions with stakeholders on reserves might be necessary if this is the eventual outcome.

The RTO plans a vote by the Participants Committee in November.

RTO Seeks Modifications for EERs, RAs

Ryan McCarthy of ISO-NE prese n ted proposed modifications to the qualification process for energy efficiency resources (EERs) to better account for expiring measures. The RTO also wants to change the monthly reconfiguration auction (RA) and bilateral qualification rules to better account for new financial assurance and performance accounting rules.

The proposal would set the seasonal qualified capacity to the lower of the amount of capacity that has cleared as “new” in prior FCAs or the amount of measures marked commercial plus FCA cleared non-commercial MWs on critical path schedule (CPS) monitoring. The proposed methodology would apply to both the FCA and all annual RA qualifications.

NEPOOL — The proposed methodology by ISO-NE is expected to increase energy efficiency qualification values. | *ISO-NE*

An EER will have two years from the start of the commitment period in which it first received a capacity supply obligation to install its measures. Previously cleared EERs will have until May 31, 2027, to install all measures.

As additional EE clears in the FCA, the capacity will be factored directly into the load reconstitution process. The RTO said the proposal will better align qualified capacity with its performance capabilities.

The RTO would assign monthly qualification to resources that become commercial during the capacity commitment period. The monthly qualification will track delayed commercial resources and allow non-commercial capacity to participate in monthly RAs and bilateral qualifications.

The Markets Committee will vote on the proposals next month. EER qualification changes would become effective in February 2021 for FCA 16. The monthly qualification changes would become effective in January 2022 and implemented for the March 2022 monthly reconfiguration auction and bilateral qualification period.

GIS Working Group to Consider Massachusetts ‘Clean Generation’ Changes

The MC agreed to direct the Generation Information System (GIS) Operating Rules Working Group to consider changes to the GIS and the GIS Operating Rules to reflect the addition of “Clean Existing Generation” (CES-E) to the Massachusett s Clean Energy Standard. The changes were requested by the Massachusetts Department of Environmental Protection.

NEPOOL counsel Paul Belval of Day Pitney said in a mem o that DEP revised its regulations to include a requirement that retail load-serving entities subject to the standard have a certain percentage of energy from “Clean Existing Generation Units.”

Clean existing generation units are nuclear or hydroelectric units with a nameplate capacity of at least 30 MW that began commercial operation before Jan. 1, 2011, and satisfy specific geographic requirements. In addition to adding a new category in the GIS, the DEP regulations pose two additional rule changes. Multiple co-located GIS generators could have their generation aggregated, and certain annual caps on qualifying output would have to be allocated among those GIS generators. Also, certain generators in Newfoundland and Labrador could be eligible. That would require a slight expansion of the area where qualified generators can receive unit-specific certificates in the GIS.

The committee is not being asked to vote on any changes to GIS rules, the memo said, but should refer issues to the working group to discuss and determine potential rule revisions.

Order 841 Compliance Update

Jennifer Wolfson of ISO-NE upd a ted the committee on the RTO’s plan for responding to an Aug. 4 FERC order on the RTO’s second Order 841 compliance filing. (See FERC OKs Most of ISO-NE 2nd S t orage Compliance.)

The RTO proposes Tariff changes to comply with two FERC directives. The first change would address FERC’s concern that the Tariff language preventing double payment for charging energy at the retail and wholesale levels would allow host utilities to decide whether an electric storage resource (ESR) may participate in its markets. It would be effective in the first quarter of 2021.

The second responds to FERC’s directive that the Tariff include the bidding parameters the RTO will use to account for the state of charge and duration characteristics in the day-ahead energy market. It would be effective Jan. 1, 2026.

The RTO will seek votes on the proposed revisions at the committee’s next gathering on Nov. 9-10 and at the Participants Committee’s Dec. 3 meeting.