The Massachusetts Senate on Thursday passed a bill 37-3 that would adjust the state’s existing offshore wind procurement price cap if enacted.
As passed, the bill amends Gov. Charlie Baker’s proposal (H.4204) to remove the existing OSW price cap, allowing instead a 10% increase over the winning per-megawatt-hour bid of the state’s previous procurement round. Under the current process, regulators cannot approve a bid that exceeds the winning bid of a previous procurement.
The total bid increase, however, must come from performance-based economic development and employment opportunities that support low- and middle-income populations and diversity, equity and inclusion programs.
Baker’s proposal became part of An Act Driving Climate Policy Forward (S.2819) (Drive Act) through a series of amendments (H.54524) in the House of Representatives that compile a broad set of policies for decarbonizing energy, transportation and buildings. The bill preserves Baker’s proposal to transfer the authority for selecting winning bids from the state’s utilities to the Department of Energy Resources (DOER).
The Drive Act is now before the House for final reconciliation and will go to the governor for his signature.
An amendment to the Drive Act introduced by Sen. Julian Cyr (D) and adopted during Thursday’s session would create a new phase in the state’s 83C OSW procurement process by tacking on 4.4 GW to an existing 5.6 GW procurement authorization.
The new authorization “would have Massachusetts realize one-third of President Biden’s goal to have 30 GW of offshore wind by 2030,” Cyr said on the Senate floor. “It establishes the trajectory for Massachusetts to realize the 15-20 GW of OSW needed under the pathways forecast in the Massachusetts 2050 Decarbonization Roadmap.”
Cyr’s amendment includes protections for coastal and marine environments and wildlife as well as provisions to ensure that federally recognized tribes have a voice in the OSW development process.
Funding
The Drive Act reduces Baker’s proposed $750 million Clean Energy Investment Fund in H.4204 to $100 million. Directives for the center’s funding include clean energy research and workforce and port infrastructure development.
An additional $100 million would be allocated to an Electric Vehicle Adoption Incentive Trust Fund and $50 million to a Charging Infrastructure Deployment Fund. Incentives under the EV fund support passenger car or light-duty truck purchases under $50,000.
A new interagency coordinating council would oversee the infrastructure deployment fund and deliver a report on deployment strategies to the legislature within a year of the bill’s effective date.
Transportation
A plan by the Massachusetts Bay Transportation Authority to electrify its bus fleet by 2040 would become law under the Drive Act, and all the authority’s passenger bus purchases or leases would have to be zero-emission vehicles starting in 2028.
An amendment introduced by Sen. Brendan Creighton (D) and adopted by the Senate would direct MBTA to purchase only electric rail cars by 2031. In addition, the authority would have to develop emission-reduction plans for each of its commuter rail lines.
Senators defeated another amendment that would have required electrification of public fleets, including state fleets and school buses, by 2035.
“Adoption of the provision requiring a phased plan for the electrification of commuter rail that prioritizes environmental justice communities is a welcome decision,” Veena Dharmaraj, director of transportation for Sierra Club Massachusetts, said in a statement.
Sierra Club, she added, is “disappointed” that legislators are reluctant to set fleet electrification targets.
“Communities across the state should not have to wait until 2050 to benefit from pollution-free school buses and municipal and transit fleets,” she said.
Buildings
In keeping with Massachusetts’ efforts to establish a net-zero stretch code that local governments can adopt, the Drive Act would allow a demonstration project for up to 10 municipalities to restrict fossil fuel use in new building construction. DOER would collect data from the project to help assess the effect of fossil-fuel free development on building emissions and costs.
An amendment introduced by Sen. Rebecca Rausch (D) and passed by the senate would direct utilities to provide public annual reports on the amount of natural gas and electricity used in buildings of more than 25,000 square feet.
Environment Massachusetts supported the amendment.
The bill “doesn’t do nearly enough to address the energy we use in our buildings,” Ben Hellerstein, state director for the nonprofit, said in a statement.
Senators defeated a separate amendment that would have established a large buildings energy performance standard like one passed last year for Boston.
The bill also addresses the decision-making process for the Department of Public Utilities’ ongoing investigation (Docket 20-80) into the role of gas distribution companies in reducing greenhouse gas emissions. Regulators would be required to hold an adjudicatory proceeding before approving any state gas utility’s decarbonization plan submitted under the investigation.
Adjudicatory processes would allow constituents to participate as intervenors in hearings and depositions.
Massachusetts’ gas utilities filed proposals with the DPU in March for reducing gas system emissions. Stakeholders have asked the DPU to expand the opportunity for input on the utilities’ proposals in the docket, including provision of technical evidence and cross-examination of utility witnesses.
PJM Market Implementation Committee members last week unanimously endorsed a revised proposal from the RTO and its Independent Market Monitor to address start-up cost offer development.
At the MIC’s April 13 meeting, Tom Hauske, principal engineer in PJM’s performance compliance department, reviewed the joint proposal to revise Manual 15: Cost Development Guidelines that came out of discussions at the Cost Development Subcommittee (CDS).
The CDS initially brought two proposals for first reads to the October MIC meeting. (See “Start-up Cost Offer Development,” PJM MIC Briefs: Oct. 6, 2021.) But a vote on the proposals was postponed to allow more discussions and have stakeholders reach consensus on a single proposal.
Manual 15 currently allows the start-up costs for combined cycle units to include fuel costs after generator breaker closure and synchronization to the grid, a feature not available to other unit types, such as steam and nuclear plants. The revisions align start-up costs for all units with a soak process, or units that use steam turbines.
PJM’s revised steam unit start-up cost offer procedure. | PJM
For units with a soak process, including steam, combined cycle and nuclear units, some of the soak costs are included in the start-up costs from PJM’s notification to the “dispatchable output” and from the last breaker open to the shutdown process.
Units that don’t have a soak process, like combustion turbines and reciprocating engines, maintain the status quo, with start-up costs that include costs from the time of PJM’s notification to the first breaker close and from the last breaker open to the conclusion of the shutdown process.
“We’re not implementing soak time at this point,” Hauske said. “We’re just allowing generators that have a soak process to include those costs in the startup cost.”
The revisions feature several other changes to Manual 15 to provide additional guidance and clarification, Hauske said, including equations to calculate start-up costs, station service calculations for units with and without a soak process and unit-specific parameter limits on includable costs.
Manual 15 currently allows generators to include an additional labor cost in their start-up costs, Hauske said, but generators already are permitted to include the labor cost in the unit’s capacity offer through its avoidable cost rate (ACR). The proposal calls for eliminating the labor cost language in the tariff and Operating Agreement offer cap sections and the start-up cost calculation so all the operating labor is includable in the ACR.
Hauske said PJM will provide a six-month window for implementation to allow market sellers the opportunity to have their fuel costs or net generation used for the offset to be reviewed by the Monitor prior to the proposal going into effect.
The proposal will be presented as a first read at the April 27 Markets and Reliability Committee meeting.
In early 2021, stakeholders endorsed PJM’s proposal on stability limits capacity constraints that included language limiting lost opportunity cost (LOC) credits for any generation reduction required to honor the stability limit in the RTO. The limiting of LOC compensation led to debates among PJM members. (See “Stability Limits Endorsed,” PJM MRC/MC Briefs: Jan. 27, 2021.)
FERC ruled in February that PJM is within its rights to refuse (LOC) payments to generators that are temporarily required to limit output to prevent loss of synchronization and additional strain on the system during transmission outages. (See FERC: PJM Right to Block Gen Stability Limit Payments.) The tariff changes take effect June 1.
Zhenyu said PJM will use a new generator output constraint to enforce the stability limit for real power megawatt-only limits. He said the shadow price of the constraint will not be included or reflected in locational marginal pricing (LMP).
To provide greater transparency, Zhenyu said PJM added a new section to Manual 11 related to stability limits that describes the modeling, clearing and reporting process on the stability limit in the market. Updated language related to stability limits in Manual 28 included additional clarification that LOC credits are not paid for megawatts associated with a stability limit reduction.
Paul Sotkiewicz of E-Cubed Policy Associates said he disagreed with FERC’s decision on LOC payments. Sotkiewicz also disagreed with the proposed manual language, saying the changes don’t provide for “workarounds or a reconfiguration change” between PJM and the transmission owners to find ways to eliminate a stability problem.
“There’s a very easy workaround that eliminates the transient stability problem, and what I find alarming here is that there’s not going to be any effort made to do that,” Sotkiewicz said.
Phil D’Antonio of PJM asked Sotkiewicz to elaborate on a possible solution in the manual language. D’Antonio said his perspective has been that adjusting the system in an outage situation resulting from instability and limitations can end up “pulling the system apart even more.”
Sotkiewicz said he would want to look for “easy switching options” that are available to “eliminate the transient stability limit.”
“We’ve actually been in conversations with PJM operations, and we have found those solutions in the past,” Sotkiewicz said.
D’Antonio said he’ll take the suggestion back to PJM’s operations group for additional discussions before the next MIC meeting.
The committee will be asked to endorse the manual revisions at the May MIC meeting.
Intelligent Reserve Deployment Changes
Damon Fereshetian, senior engineer in PJM’s real-time market operations, provided a first read of additional updates to Manual 11 and Manual 28 related to intelligent reserve deployment (IRD).
Stakeholders in December endorsed a PJM proposal to improve the deployment of synchronized reserves during a spin event. (See “Synchronous Reserve Endorsed,” PJM MRC/MC Briefs: Dec. 15, 2021.)
The proposal created an IRD, which is a security-constrained economic dispatch (SCED) case simulating the loss of the largest generation contingency on the system and for which approval of the case will trigger a spin event. The proposal included taking the megawatts of the largest generator contingency and adding them to the RTO forecast to simulate the unit loss. PJM can then flip condensers and other inflexible synchronized resources cleared for reserves to energy megawatts and procure additional reserves to meet the next largest contingency.
Fereshetian said Manual 11 changes include the addition of new language that an approved IRD case “supersedes” any other approved real-time SCED cases for the same target time to be used as the reference case for the locational pricing calculator (LPC). In the verification section, PJM added clarifying language that the response to a synchronized reserve event is “based on the resource following dispatch instructions and is capped at the expected response.”
Manual 28 included minor clarifying changes.
The MIC will be asked to endorse the revisions at its May meeting.
Manual 29 Revisions
Natasha Holter, manager of PJM’s market settlement operations, provided a first read of revisions to Manual 29: Billing as part of the periodic review.
Holter said there were no “substantive changes” in the manual language and mostly included updates to terminology and reference materials.
Several new subsections were added to the manual, Holter said, including one called “Billing Notifications” that features language providing guidance on how to obtain notifications for billing statements. Another subsection, “Billing Adjustments,” added language to describe what a billing adjustment is and how to identify one.
Stakeholders will be asked to endorse the revisions at the May MIC meeting.
Several big voices in Massachusetts and D.C. politics are turning up the heat on ISO-NE as FERC considers the grid operator’s proposal to delay elimination of its contentious minimum offer price rule (MOPR) by two years.
In a speech outside ISO-NE headquarters last week, Sen. Ed Markey lambasted the organization as secretive, part of an “oil and gas conspiracy,” and standing in the way of the transition to clean energy.
“Instead of giving us the green light for our clean energy revolution, ISO New England is proposing to send us on a detour,” Markey said. “By proposing to delay the elimination of a rule that puts fossil fuel generation ahead of cleaner, cheaper alternatives, ISO New England is risking reliability and cost savings for residents across Massachusetts.”
Known for his affinity for wordplay and developing new acronyms, the senator said the MOPR should be called “Minimizing Our Potential for Renewables,” and that ISO-NE should be called the “dependent” system operator because “it’s dependent on gas and oil.”
“They have been in the past, they are today and their rules say they want to be in the future as well,” Markey said.
Markey’s speech also elicited support from Department of Energy official Jigar Shah.
“Time to find solutions instead of holding up clean energy projects waiting for more studies,” tweeted Shah, director of the DOE Loan Programs Office.
The two-year “transition” to eliminating the MOPR from ISO-NE’s capacity market, now in front of FERC for a decision, has received a high level of scrutiny from environmental advocates, elected officials and the renewables industry who have questioned ISO-NE’s claims about reliability worries stemming from an influx of renewables and possible corresponding retirement of merchant generators. (See ISO-NE Sends MOPR Filing to FERC, Teeing up Big Decision)
In an email to RTO Insider, ISO-NE spokesperson Matt Kakley defended the process that produced the proposal.
“Our robust, federally-approved stakeholder process includes the ISO, the energy industry, representatives from the New England states and advocacy groups. ISO New England’s proposals are fully examined and discussed before undergoing review by our federal regulator prior to implementation,” Kakley said.
Markey’s claims of conspiracy, Kakley added, are “so outlandish they do not warrant a response.”
“In addition, we are independent of the resources competing in the wholesale markets and do not favor any resource type over another. In fact, ISO New England employees work every day to ensure that all energy resources can compete in the market, can interconnect safely to the regional power grid and can operate reliably,” he said.
A Senatorial Plea to FERC
Markey also wrote a letter, along with Sens. Elizabeth Warren (D-Mass.) and Bernie Sanders (I-Vt.) calling on FERC to reject the filing and force ISO-NE to immediately remove the MOPR.
“At the very moment when New England should be fully embracing the transition to renewables and the related socioeconomic opportunities, this decision to undermine state actions and renewable energy deployment is a terrible and ill-timed mistake,” the senators wrote.
They specifically called on federal regulators to use their authorities under Sections 205 and 206 of the Federal Power Act to “require immediate reform” of the MOPR.
“In doing so, FERC will signal that renewable energy should be allowed to fully and freely compete in wholesale markets,” they wrote. “This will ultimately lead to lower prices for household customers and facilitate our overdue and necessary transition to a decarbonized electricity grid.”
Experts have said that FERC could respond to the filing in several possible ways, including accepting it, rejecting it outright or sending it back with a finding that the status quo is unjust and unreasonable and an explicit order to immediately terminate the rule.
A major battery storage project built by Pacific Gas and Electric (NYSE:PCG) and Tesla (NASDAQ:TSLA) is ready to help California deal with the reliability problems it encountered in the past two summers, PG&E said Monday.
The utility said its 182.5-MW Elkhorn Battery facility had been “fully energized and certified for market participation by” CAISO earlier this month. The project’s 256 Tesla Megapack battery units sit on 33 concrete slabs on Monterey Bay and can discharge 730 MWh of electricity for up to four hours, providing energy and ancillary services to the grid.
“We are ushering in a new era of electric system reliability and delivering a vision into the future for our customers with the commissioning of the Tesla Megapack system in Moss Landing,” PG&E CEO Patti Poppe said in a news release. The utility owns and will continue to operate the units, it said.
The Elkhorn facility now ranks among the world’s largest battery energy storage systems (BESS), and it sits beside the No. 1 largest, Vistra’s (NYSE:VST) 400-MW Moss Landing facility, along with Vistra’s gas-fired Moss Landing Power Plant.
Moss Landing’s racks of non-Tesla batteries were shut down after overheating incidents in September and February triggered fire alarms, set off sprinklers and melted equipment.
“Vistra is in the process of conducting repairs, commissioning facility systems and implementing enhancements to improve the original design of the facility,” the company said in its initial findings on the September incident, released in late January about two weeks before the second incident occurred.
PG&E purchases Moss Landing’s output, along with energy from four other large BESSes: the 200-MW Diablo Storage System in Contra Costa County, the 60-MW Coso Battery Storage in Inyo County, the 63-MW NextEra Blythe system in Riverside County and the 50-MW Gateway system in San Diego County. All went online in the last two years.
Batteries for Reliability
In June 2021, the California Public Utilities Commission ordered PG&E and the state’s two other large investor-owned utilities, Southern California Edison and San Diego Gas & Electric, to procure 11.5 GW of new resources in the next three years to head off shortfalls.
It ordered the IOUs and other load-serving entities to purchase another 3 GW of additional capacity through supply- and demand-side programs to prevent shortages during potentially extreme heat waves in the summers of 2022 and 2023. (See CPUC Orders Procuring 3 GW of Capacity.)
The transition from fossil fuels to clean energy in California and other Western states has increased wind and solar generation while coal and gas plants have retired.
Reliability problems arose during Western heat waves in 2020 and 2021, as solar power waned on hot summer evenings but demand remained high. CAISO ordered rolling blackouts in August 2020 and declared energy emergencies both years.
Responding to the CPUC orders, PG&E said it hopes to have 3,300 MW of in-state battery storage under contract by 2024. More than 955 MW of that is already connected, and about 1,400 MW of storage capacity is scheduled to come online in 2022 and 2023, it said. PG&E won approval from the commission Thursday to contract with nine more proposed battery storage projects, totaling 1,600 MW, that could start operating between 2024 and 2026.
CAISO said it has added more than 2,400 MW of battery storage since the 2020 blackouts and expects to add 2,100 more by June.
The ISO posted a video in March on “California’s historic embrace of battery storage to support the grid as we transition to a carbon-free system.”
“Last summer was a pivotal moment for battery storage, and we felt it was important to document the story and to share our experiences and the lessons we learned,” CEO Elliot Mainzer said in a statement on the video.
“The potential of lithium-ion batteries had been talked about and anticipated for a long time,” he said. “Now they are a central part of our toolbox to make sure that supply and demand are balanced, and the system remains reliable even during the most challenging conditions.”
The Bonneville Power Administration is on target to enter the Western Energy Imbalance Market (WEIM) in early May after agency executives met Monday to make a final determination on its market readiness.
“BPA is on track to start participating in the Western EIM on May 3. Barring any unforeseen setbacks, we are a go,” agency spokesperson Doug Johnson told RTO Insider.
The federal power marketing agency was initially scheduled to begin transacting in the WEIM on March 2, along with Pacific Northwest utilities Avista and Tacoma Power, but in January it decided to delay entry by two months because of customer training and technology issues. (See BPA Postpones Western EIM Entry by 2 Months.)
During a stakeholder meeting in late March, BPA officials said the agency was on course for the May 3 entry despite remaining issues related to market technology. But they noted that they would still meet privately April 18 to make a final decision, citing the need for a smooth integration to best serve stakeholders. (See BPA ‘Full Speed Ahead’ on May EIM Entry, but Issues Remain.)
The decision came without fanfare or notice on the agency’s website. Johnson called it a “procedural, but important, step in our march to participation.”
That march began in 2018 with a long series of stakeholder meetings leading to a September 2019 signing of an EIM implementation agreement, followed by last September’s official decision to commit to joining the market. Over the course of those developments, BPA was already engaged in an exhaustive process to prepare its customer base of publicly owned utilities for the complexity of market integration.
BPA will be the most significant entrant into the WEIM since the market commenced operation in November 2014 with PacifiCorp, and its two utilities’ six-state territory, as its pioneering member.
With 15,000 miles of high-voltage transmission and 31 hydroelectric projects under its control, BPA will be the largest transmission and hydro provider in a market that now includes 16 members with territories spanning most of the Western Interconnection.
The agency controls about three-quarters of the transmission in the Northwest, making its system a vital link between the Northwest’s massive network of hydroelectric dams and WEIM areas in California and the Southwest that are becoming increasingly reliant on solar energy. The flexibility of hydro generation is particularly well suited to firming up the variable output of intermittent renewable resources.
BPA also owns more than 50% of the capacity on the California-Oregon Intertie, which links the Northwest into the CAISO system in Northern California, and — along with the Los Angeles Department of Water and Power — is half-owner of the Pacific DC Intertie, a 500-kV line that delivers energy into Southern California. LADWP began participating in the EIM last year.
New York’s Climate Action Council on Monday agreed to form new committees to help develop the state’s plans for reducing natural gas use, expanding alternative fuels and adopting economy-wide measures to cut emissions.
The CAC is holding public hearings through June 10 on its draft scoping plan that lays out steps needed to achieve the emission limits set by the Climate Leadership and Community Protection Act. The council has received 8,000 written comments and heard 200 people comment through four of 10 hearings, CAC Director Sarah Osgood said.
“While others would prefer that the climate actions happen faster, we also heard concerns about affordability of electricity and the cost of the transition, specifically the cost associated with moving homes to all electric,” Osgood said. “A number of commenters expressed concerns about potential job losses among energy and utility workers and encouraged the council to take action that would ensure that the issue would be addressed.”
Administrators are planning to provide a distilled summary of the comments a month after the close of the comment period, Osgood said.
Committee Tasks
State officials and contractors presented outlines of what committees on gas system transition, alternative fuels and economy-wide measures could focus on in the coming months, with the council meeting at least monthly or more often as the workload increases over the summer, Osgood said.
The CAC will recruit volunteers for the committees to start meeting in May so the council can complete a final scoping plan by year-end that shows how the state will reduce economy-wide greenhouse gas emissions 40% by 2030 and no less than 85% by midcentury from 1990 levels, she said.
The gas transition will outline a coordinated plan to downsize the gas system, led by the Department of Public Service and supported by the New York State Energy Research and Development Authority (NYSERDA), Long Island Power Authority, New York Power Authority and the Department of Environmental Conservation.
The committee will consult with utilities, environmental justice groups and sectoral experts and draw upon successful plans in other jurisdictions, as will the alternative fuels committee in developing draft guidelines on the use of hydrogen, renewable natural gas and other biofuels.
DEC Deputy Commissioner Jared Snyder opened a discussion about the economy-wide committee, which will look at the certainty of emission reductions, the certainty of carbon price impacts on disadvantaged communities and affordability, and some competitiveness issues, such as the risk of leakage from carbon pricing.
NYSERDA will provide the council with analyses on existing carbon pricing knowledge and experience in other jurisdictions as well as the effects of a price on carbon specifically in New York, said Vladimir Gutman-Britten, assistant director of policy and markets.
“We want to share data on some of the key policy design choices in pursuing a system like this and the particular tradeoffs that might come with it,” Gutman-Britten said. “This analysis will help elucidate the impact of such a carbon tax on emissions and a variety of macroeconomic metrics, such as economy-wide energy spending, leakage of emissions and economic activity.”
State planners, he said, are not endorsing a policy of carbon pricing but choosing it because of limitations on modeling tools available, adding that “while we will be evaluating this one type of policy, we still think it would provide insights into how other approaches might work.”
Additional analysis may include potential effects of a large-scale investment program, including a sense of scale and the kinds of emissions reductions such a program might be able to yield under different spending choices, Snyder said.
The idea is “to unpack the kind of impact that pricing and an investment program might have on specific clean energy solutions … key technology things like EVs, heat pumps and things like that so we can better understand how the economics of those solutions change as a result of different policy choices the state will make,” Snyder said.
Kevin Hansen senior vice president and head of public policy at Empire State Development, the state’s main economic development agency, urged the economy-wide committee to continue “to think about impacts on businesses and workers and the issue of leakage.”
TAC Passes Contentious Outage Measure over Staff’s Objections
ERCOT stakeholders on Monday declined to consider staff’s appeal of a tabled revision request that would create a process allowing the grid operator to review, coordinate and approve or deny all planned outages.
The Technical Advisory Committee instead approved its version of the nodal protocol revision request (NPRR1108), as amended by several joint commentators. The measure now goes before the Board of Directors for its consideration April 27-28.
The measure was passed unanimously, 26-0 with a pair of abstentions, during an emergency webinar Monday after it was tabled following more than an hour of discussion last Wednesday during TAC’s regularly scheduled meeting.
The measure was also tabled at the Protocol Revision Subcommittee (PRS) last November over concerns that staff’s proposal was inflexible and could lead to an inability to get planned outages completed. That would lead to decreased reliability in the months when there is higher demand on ERCOT’s generation fleet, they said.
Staff drafted NPRR1108 to meet the requirements of legislation passed last year in the wake of the February winter storm that nearly brought the ERCOT grid to its knees. Senate Bill 3 included a provision that the grid operator “shall review, coordinate and approve or deny requests by providers of electric generation service … for a planned power outage during any season and for any period of time.”
Under ERCOT’s original proposal, staff would review and coordinate all planned outages, including those submitted more than 45 days before the outage’s planned start. The revisions would:
define a process for calculating a maximum megawattage of planned outages that would be allowed for each day of the next rolling 60 months, based on a capacity assessment;
require that a planned outage, or change to an approved outage, submitted more than 45 days in advance of the planned start time would no longer be “accepted” but would be approved on a first-come, first-served basis if the resulting aggregate planned outages are below the daily maximum megawattage for each day of the proposed outage’s duration; and
require that a planned outage or change to an approved outage submitted less than 45 days in advance of the planned start time would be evaluated against the maximum daily planned resource outage capacity (MDRPOC) and for impacts on transmission reliability.
Dan Woodfin, ERCOT’s vice president of system operations, complained that the grid operator last November asked for stakeholder feedback within months. The lack of input has pushed back the methodology’s implementation to fall 2023, he said.
Reliant Energy Retail Services’ Bill Barnes, acting as the PRS advocate, said the NPRR included many inputs subject to discretion.
“Stakeholders needed to fully assess the methodology needed to see the results of the calculations,” he said, explaining why the measure has remained tabled.
The two sides have traded competing versions of their comments, with ERCOT filing the last Sunday night. In the comments, staff proposed to allow nuclear generators to schedule planned outages, even if the resulting outage capacity would exceed the MDRPOC. They also agreed with the residential consumer segment that they should prove a report to TAC on the MDRPOC’s effects.
Stakeholders stuck with the joint commentators’ filing, which requires the MDRPOC for outages more than seven days ahead of the operating day be posted twice each to provide greater transparency and reduce the risk of potentially large changes when “stale monthly long-term MDRPOC projections” are replaced by the near-term projections less than seven days ahead of the operating day.
They also call for outage guardrails that are sensitive to concerns about weather variations during outage seasons to provide predictable minimum outage windows for resource owners and still allow ERCOT to deny outages on days over the MDRPOC.
ERCOT legal counsel Nathan Bigbee fired back Monday over the notion that the outage-approval process should be subject to TAC approval.
“There seems to be kind of a disconnect between industry in general and the ISO over what exactly the methodology should be,” he said. “It seems likely the methodology we prefer is a methodology TAC would not endorse. Having that control would lead us down a path less in the interest of reliability. That’s why we don’t think it’s appropriate. Ultimately, the board is going to be the arbiter of those decisions.”
ERCOT can file additional comments on NPRR1108 with the board or appeal the decision to the Public Utility Commission for an appeal.
Unsecured Credit Limit Lowered
TAC on Wednesday approved a measure that reduces unsecured credit limits from $50 million to $30 million, but not before a back-and-forth between one member and a staffer over uplift that resembled Monty Python’s classic “Argument Clinic” sketch.
“I fundamentally disagree with your concept of how the market works,” Kenan Ögelman, ERCOT’s vice president of commercial operations, told Morgan Stanley’s Clayton Greer.
PRS amended NPRR1112 in March to reinstate unsecured credit limits. ERCOT responded with comments that said eliminating unsecured credit “will reduce the inconsistent cross-subsidization of credit exposure and provide a more level playing field for market participants.”
Members disagreed. Garland Power and Light’s Dan Bailey said staff’s response was “the most ridiculous problem ERCOT has tried to solve without solving the problem.”
“From a market and consumer standpoint, taking a nuclear approach to credit is a little bit questionable,” he said. “Why ERCOT would think this is the right direction to go has left me scratching my head. I’m baffled to see that ERCOT is going down this path.”
TAC rejected an motion to amend the measure with ERCOT’s comments, 3-16 with 11 abstentions. It attracted approval only from the two residential consumer representatives and retailer Reliant Energy.
A motion to approve PRS’ recommended version passed 23-2 with five abstentions. The residential consumer representatives cast the two opposing votes.
RUC Process Changes Endorsed
The committee approved a pair of rule changes related to reliability unit commitments (RUCs), which have been increasingly used by ERCOT since last summer as part of its conservative operations approach.
NPRR1124 is intended to ensure generation resources recover their actual fuel costs when they are RUCed by setting the start-up price and minimum-energy price to the start-up cap and the minimum-energy cap.
The measure was opposed by all six consumer segment representatives, who objected to consumers bearing the increased costs.
TAC also approved a motion related to NPRR1092, which lowers the RUC offer floor to $250/MWh from $1,500/MWh, as amended by clarifying ERCOT comments April 6. Members approved the measure in March, pending an impact analysis from staff. (See “RUC Offer Floor Lowered to $250,” ERCOT Technical Advisory Committee Briefs: March 30, 2022.)
Staff said it will cost between $50,000 and $75,000 and take four to six months to change the RUC offer floor, as proposed by the Independent Market Monitor. The measure still needs regulatory approval and prioritization.
The motion passed 25-1, with Luminant opposing and two representatives each from the cooperative and independent power marketer segments abstaining.
Ögelman Addresses Concerns with Board Interactions
Ögelman responded to stakeholder concerns about their interactions with the board’s new Reliability and Markets Committee, saying that the directors are still working through the structure they want.
“The board’s trying to figure out how they want to do business and what they might want to do differently,” he said. “Right now, we have to beg everyone to be patient with us and work with the board to give them the processes they want. They have a vision … they’re just not ready to share it yet.”
Ögelman was responding to a clarification request from the Wholesale Market Subcommittee, which reports directly to TAC. ERCOT’s bylaws require TAC to report to the full board, rather than a board committee; any bylaw changes would require a vote of the full membership, Ögelman said.
Two More SCT Directives Approved
TAC endorsed staff’s response to two additional directives issued by the PUC related to the Southern Cross Transmission (SCT) project, a merchant long-haul HVDC transmission line that would connect ERCOT with systems in the SERC Reliability region.
In responding to the 14 PUC directives, ERCOT staff found they would not need to study and determine transmission upgrades to address congestion caused by SCT (No. 6). Staff determined in the second directive (No. 8) that as of Jan. 1, 2021, DC ties should be required to have at least a 0.95 power factor leading/lagging reactive power capability, which several revision requests have already addressed.
The SCT would be capable of carrying 2 GW of power between Texas and SERC over a 400-mile, double-circuit 345-kV line. The project has FERC approval and a waiver from the commission’s jurisdiction. It also has a certificate of convenience and necessity granted by the PUC in 2017 to Garland Power & Light, which owns the project’s western endpoint.
The PUC last year directed its staff to file a memo asking the proceeding’s parties for suggestions on accelerating the project, which has been under regulatory review for more than seven years (46304). (See Texas Regulators Boost Southern Cross Project.)
ESRs’ Minimum Duration Set at 2 Hours
TAC’s unanimously approved combination ballot included a recommendation from the Reliability and Operations Subcommittee to set a minimum duration threshold of two hours for energy storage resources (ESRs). Lower-duration ESRs would be prorated to their continuous real power capability for two hours.
The combo ballot included two additional NPRRs, a Nodal Operating Guide revision (NOGRR), two revisions to the Planning Guide (PGRR) and a change to the Settlement Metering Operating Guide (SMOGRRs):
NPRR1117: aligns the protocols with the Settlement Meter Operating Guide revisions to allow for losses in short runs of connecting lines to be disregarded when the ERCOT-polled settlement meter (EPS) is not physically placed at the point of interconnection (POI).
NPRR1125: clarifies that ERCOT may use available financial security held for other market activities should there be payment defaults in either of the two securitization proceedings. The change also specifies the prioritization for applying the securities when there are concurrent defaults for either invoices or escrow deposit requests.
NOGRR239: delineates the responsibilities for providing security for data transmitted between ERCOT, qualified scheduling entities and transmission operators.
PGRR096: establishes requirements for the consistent representation of distribution generation resources, distribution energy storage resources, settlement-only distribution generators and unregistered distributed generation in steady-state base cases.
PGRR098: enables corrective action plans to be developed under certain outage scenarios to the existing reliability performance criteria.
SMOGRR025: allows for losses in short runs of connecting lines to be disregarded in instances where the EPS meter is not physically placed at the POI and requires calculation to verify that the watts copper losses are below 0.001%.
A flood in a substation that damaged multiple pieces of equipment could be the future for many utilities as the grid adapts to climate change, according to a new Lessons Learned report released by NERC last week.
“Substation Flooding Events Highlight Potential Design Deficiencies,” one of six reports published last Wednesday, did not disclose details of the incident such as the date, location, or even the utility and regional entity involved. This is a common practice with NERC’s Lessons Learned documents, which are intended to “provide industry with … information that assists [it] with maintaining the reliability of the bulk power system” rather than to shame individual companies.
The incident began with a heavy storm that dropped nearly 6 inches of rain and hail on a 230-kV transformer station over two and a half hours. During the sudden influx, which was beyond any expectations of the facility’s designers, about 8 inches of water collected in a relay room in the basement of the substation control building, submerging “numerous [250-V DC] control equipment connections.”
Compounding the heavy rainfall was the lack of suitable pumping capacity. While sump pumps were in place at the facility, staff found that they could not keep up with the pace of the flooding, and additional pumps could not be installed for several hours. Even the existing pumps were undermined by the placement of their outlets, which were so close to the substation that staff realized the water they pumped out was “flowing back into the basement through cable trays.”
The transmission owner’s staff were not totally unprepared for the events: NERC noted that facility personnel had relocated “critical power system equipment” above the grade as recommended in a previous Lessons Learned report on a similar flooding incident. As a result, no load loss was reported as a result of the event, and no system operating limits were exceeded during the flooding.
However, enough equipment was left submerged in the basement to cause multiple problems with circuit breakers and bring almost 500 MW of generation offline.
Five breaker issues were reported: Two breakers operated on false failure inputs and three on false trip inputs. The first failure input led to the loss of one circuit and two generating units connected to the line terminal; after multiple attempts to restore the circuit, the equipment had exceeded the number of reclosing attempts and could not be reclosed without an inspection.
The second false failure input resulted in the loss of one circuit and four generation units. No generation or transmission facilities were lost because of the false trip inputs, and the circuits were returned to service just over an hour after the event began. Once additional pumps had been brought online, the pump outlets were moved so the water would not drain back into the basement, and heating and drying equipment were brought into the basement.
NERC’s report noted that the TO is already taking steps to address the shortcomings revealed by the incident, including a complete overview of the drainage system on-site and a commitment to move all critical equipment above grade by 2023. The TO is also planning an extent-of-condition investigation to determine if similar issues exist at other transmission stations.
The report’s authors suggested that other TOs take similar steps by investigating whether suitable precautions have been taken at transmission stations that were previously known to be susceptible to flooding, as well as whether stations that were previously considered safe may now be in danger. NERC also recommended that facility owners determine how water might affect sensitive equipment if the flooding measures fail and make sure they have plans for handling rain when maintenance is underway on vital systems.
PJM is proposing the creation of a new subcommittee to continue discussions of interconnection process changes after work in the Interconnection Process Reform Task Force (IPRTF) finishes.
Jason Connell, PJM director of infrastructure planning, provided a first read of the draft charter of the Interconnection Process Subcommittee (IPS) at last week’s Planning Committee meeting. Connell presented the concept of the new subcommittee at the March 8 PC meeting. (See “Interconnection Subcommittee Initiative,” PJM PC/TEAC Briefs: March 8, 2022.)
Connell said PJM staff have continued internal discussions and talks with stakeholders about creating the new subcommittee to carry on discussions on additional interconnection issues identified in the IPRTF. He said the purpose of the IPS is to provide a stakeholder forum to “investigate and resolve specific issues related to the interconnection process and associated agreements, governing documents and manuals.”
Discussion topics featured in the charter include:
education on current and future interconnection processes and agreements with clarifications around implementation;
development of improvements of interconnection process rules in the tariff and related PJM manuals;
encouraging continued dialogue between stakeholders and PJM on best business practices and coordination with neighboring RTO/ISOs on interconnection.
Connell said PJM fields many questions from developers on how the RTO plans to implement aspects of the interconnection process not explicitly described in the manuals and the tariff. He said PJM wants to use the subcommittee as an “incubator” for discussions on complex interconnection issues and to come up with solutions.
The IPS will report to the PC, Connell said, but some of the issues to be discussed may impact operations and markets, requiring reports to the Market Implementation Committee and the Operating Committee. Connell said PJM intends to begin holding meetings of the new subcommittee by June and establish a near-term agenda if endorsed by stakeholders.
“PJM was very much in favor of doing this, as it has seen the benefits of the discussions that have taken place at the IPRTF over several months and the consensus that we’ve been able to build around the Planning Committee’s endorsed package,” Connell said. “We want to continue that dialogue in order to continually refine and improve the interconnection process to facilitate the renewable transition.”
Ken Foladare of Tangibl Group said his company supports the new subcommittee and the concept of having an “ongoing discussion” of the interconnection process. Many renewable customers will want process changes and improvements “quite frequently,” he said, asking if PJM could implement a process where proposed changes are considered annually in one batch instead of piecemeal because the number of changes “could get a bit difficult to manage.”
Connell said PJM would have to “look at the magnitude of the changes” proposed and “batch them appropriately” depending on their urgency.
“We certainly don’t want to overwhelm the standing committees with monthly changes as we’re moving through,” Connell said.
Sharon Midgley of Exelon said it “makes a lot of sense” to have the new venue for interconnection discussions. She said Exelon wondered how the subcommittee will “work mechanically” and how issues will be prioritized.
Dave Anders, director of stakeholder affairs for PJM, said the IPS will operate similarly to other subcommittees that report to a standing committee, pointing to the Cost Development Subcommittee as an example. He said Manual 34 stipulates that subcommittees are allowed to take on work that’s within the charter of the group.
Any disagreement among stakeholders in the group should be addressed by the PC, Anders said.
Midgley said she would like to see some expectation language included in the charter so that stakeholders “know the bounds and the rules under which we’re engaged” in the committee.
RSCS Charter
Monica Burkett, PJM senior lead knowledge management consultant, provided a first read of proposed changes to the charter of the Reliability Standards and Compliance Subcommittee (RSCS).
Burkett said the RTO is looking to improve discussions and find more efficiencies in the RSCS, including maintaining up-to-date information on issues. She said several changes are being proposed to improve what compliance information is provided and shared with stakeholders in the subcommittee.
Burkett said the charter updates include “simple tweaks” to language for clarification.
One item proposed to be removed from the charter language is the development of a list of functions performed by other registered entities “in support of PJM compliance.” Burkett said the list of functions are reviewed at the RSCS, but they are never developed by the subcommittee.
Under the responsibilities section of the charter, PJM removed the item “cooperate with PJM with regard to data requests and submittals related to NERC and regional reliability standards” and inserted “allow for exchange of best practices and discussions surrounding upcoming data requests related to NERC and regional reliability standards.”
The committee will be asked to vote on the charter at next month’s PC and OC meetings.
Manual 21A ELCC Changes Endorsed
Stakeholders endorsed an issue charge and manual revisions related to an effective load-carrying capability (ELCC) model run timing update and other changes to reflect the continuation of the current method of providing unit-specific backcasts only as requested. The endorsement received 182 votes in support (97.3%) and 182 votes (97.3%) favoring the changes over the status quo.
PJM rules allow voluntary submission of unit-specific wind and solar parameters for development of backcasts for newer resources, Bruno said, but current manual language has an expiration date of March 1 for voluntary submissions. The submission of unit-specific parameters for all wind and solar is mandatory after the expiration date.
The alternative method is to use a zonal backcast, Bruno said, which PJM has found to be an “adequate” process.
The quick fix called for removing the March 1 expiration date, which would allow PJM to continue the current practice in which newer resources can elect to submit the unit-specific data or use the zonal backcast.
Bruno said another change in the proposal would have the 2025/26 Base Residual Auction use the December 2022 ELCC run instead of the older July 2022 run. He said the change would allow for the most recent data to be used when calculating the accredited unforced capacity (UCAP) for the 2025/26 BRA, with the July 2022 run to be removed from the schedule.
The issue charge and manual revisions now go to the April 27 Markets and Reliability Committee meeting for a first read.
Joseph Hay of PJM’s infrastructure coordination department reviewed the revisions that featured two main changes to the manual.
First, the critical energy/electric infrastructure information (CEII) in Manual 14F was referenced over to Manual 14B because the latter is the source document for PJM’s CEII. Hay said the change will eliminate the requirement to edit Manual 14F whenever a change is made to 14B.
The second significant update was that the Secure File Transfer Tool used to submit all proposals was replaced with a requirement to use “Competitive Planner” to submit proposals. Hay said the Secure File Transfer Tool is still available for stakeholders and will be used to submit supplemental data on an “as needed” basis.
The manual changes will see a vote at the April MRC meeting.
Transmission Expansion Advisory Committee
AEP Supplemental Project
A stakeholder questioned a supplemental project presented by American Electric Power at last week’s Transmission Expansion Advisory Committee meeting.
Will Burkett of AEP presented the need for work to be done on the Conesville-Bixby 345 kV line in Central Ohio. Burkett said the 51.1-mile line has seen total of 10 outages since 2015, and some of the failures have been “catastrophic in nature.”
Some of the reported damage to the wooden structure of the Conesville-Bixby 345 kV line in Ohio. | AEP
Of the 342 structures making up the line, Burkett said, 73% are wood structures installed in the early 1970s. An additional 25% of the structures are steel installed between 2010 and 2021, Burkett said, with the replacements “performed proactively” at and along major interstates. The remaining 2% of the structures are steel installed in the early 1970s.
The Conesville-Bixby 345 kV line in Central Ohio is proposed to be repaired. | AEP
Burkett said when the line was constructed in the 1970s, it used an H-frame design with wood poles and laminated crossarms rather than solid wood crossarms. He said 30 of the structures are currently rotting or have heavy rust and other serious flaws.
Sharon Segner, vice president at LS Power, asked if there is an in-service date associated yet with the project.
Burkett said AEP is working on a solution and doesn’t yet have a timetable or costs for the project.
“We’re just bringing the concerns we have out there, and we’ll work to develop solutions to address those needs and bring that back to stakeholders,” Burkett said.
Segner asked why the project “doesn’t appear to be going through a competitive process” despite being greater than 100 kV.
TEAC Chair Suzanne Glatz said the line is a supplemental project need, which is not subject to the competitive process in FERC Order 1000.
Segner said it will be “interesting” to see the price of the project when a solution is developed and expressed interest in “understanding the regional benefits” of the project.
“Obviously 51 miles of a 345 kV line likely has regional benefits,” Segner said.
Generation Deactivation Notification
Phil Yum of PJM’s system planning modeling and support department provided an update on recent generation deactivation notifications, including Energy Harbor’s large coal units in Ohio and West Virginia.
Energy Harbor requested deactivation of coal-fired units 5-7 of the 1,504-MW W.H. Sammis Power Station in the American Transmission Systems Inc. (ATSI) transmission zone in Stratton, Ohio. The company also requested the deactivation of the 13-MW diesel unit at Sammis.
Energy Harbor also announced that it requested deactivation of units 1 and 2 of the 1,278-MW Pleasants Power Station in the Allegheny Power Systems transmission zone at Willow Island, W.V.
Yum said reliability analyses are underway for the Sammis and Pleasants units. Energy Harbor requested a deactivation date of June 1, 2023 for the units.
The 1.9-MW Ottawa County Landfill in the ATSI transmission zone requested a deactivation date of May 31, while the 81-MW Essex 9 gas-fired generation unit in the Public Service Enterprise Group zone in New Jersey requested a deactivation date of June 1. PJM completed reliability analyses for both units, and no violations were identified.
ISO-NE last week shot back at renewable groups who have challenged its rules and claimed that gas-powered generators get preference, saying that their complaint with FERC should be thrown out (EL22-42).
The grid operator’s motion to dismiss filed Thursday comes a month after RENEW Northeast and the American Clean Power Association alleged that ISO-NE’s rules around capacity accreditation and operating reserves don’t adequately take into account the uncertainty of natural gas supply in the region. (See Renewable Groups Challenge Gas ‘Preference’ in ISO-NE Rules.)
Central to ISO-NE’s response is the fact that new rules are already under development.
FERC should dismiss the complaint “because it is an improper attempt to circumvent the New England stakeholder process and it invites the commission to impose a solution that reflects only complainants’ preferred outcome on their preferred timeline,” the RTO said.
ISO-NE is about to start work on a framework for resource capacity accreditation within the next few months, it said, an “enormously complex project with significant implications for the reliability of the New England grid.”
The project is budgeted to take two years, in line with ISO-NE’s proposed transition away from the contentious minimum offer price rule in its capacity market. The grid operator is also launching a day-ahead ancillary services project, which it says would be the “appropriate forum” for the renewable groups’ complaints about the reserve procurement process.
In asking FERC to toss the complaint, ISO-NE pointed to a previous case in California in which the commission dismissed a complaint seeking changes to CAISO’s market rules that were “directly related to market design issues [already] under review by [CAISO] as part of [a] revised market design proposal.”
ISO-NE also argued that the complaint should be dismissed on merit, saying that the region’s tariff explicitly contradicts the groups’ claims that gas generators have no obligations to report on their reserves or are excluded from fuel supply requirements. It also said that the relief proposed by RENEW and ACP is “unworkable.”
In comments on the FERC docket, several renewable and environmental advocacy groups have backed the complaint, while several generation companies have put their support behind ISO-NE.
The New England States Committee on Electricity and the attorneys general of Connecticut and Massachusetts said in comments that the changes proposed in the complaint are premature and that the issues of capacity accreditation and reserve procurement need more comprehensive treatment through the NEPOOL stakeholder process.
