In a now-familiar refrain, MISO is warning stakeholders of possible maximum generation emergencies should high load and high outages collide this spring.
Under probable load scenarios with expected outages, MISO expects to have:
99 GW of available capacity in March to cover an 88-GW peak demand estimate;
91 GW of available capacity in April to cover an 83-GW peak; and
101 GW of available capacity in May to cover a 91-GW peak.
However, the RTO said should elevated load and excessive outages enter the picture, it could find itself declaring an emergency to access its emergency-only resources in April and May. MISO said it doesn’t see itself exhausting its 12 GW of load-modifying resources and operational reserves, even in the direst situations.
In a worst-case scenario, the grid operator would have just 79 GW of non-emergency capacity in April should demand reach 88 GW. Under the same scenario in May, MISO would have 95 GW of capacity to handle a 104-GW demand peak. In both cases, staff would be forced to access emergency supplies.
MISO set its all-time spring peak of 111 GW in May 2018.
Over the past five years, the RTO has experienced an average 36.3 GW of forced and planned outages during spring monthly peaks. It saw its highest on-peak spring outages at 54.2 GW in April 2019.
MISO did not alter this year’s spring reliability outlook to include the loss of its firm contract path linking its Midwest and South regions through June 30. Staff said it wasn’t necessary to factor the line loss into its forecasts because it was unlikely to cause any operational impacts. (See MISO Midwest-South Transfer Service on Outage until July.)
The National Oceanic and Atmospheric Administration predicts higher-than-average temperatures for MISO South and a chance at higher temperatures across most of the Midwest, except for the northernmost portion of the footprint. NOAA also expects much of the Midwest to experience more precipitation than usual.
MISO ended winter without the serious reliability event it was steeling itself for. The grid operator had a 100.2-GW winter peak on Jan. 21, 2022, about 9 GW short of the all-time winter peak set in early 2014 during a polar vortex.
FERC on Monday granted MISO’s request to give generator interconnection customers an opportunity to reduce their time in the interconnection queue from more than 500 days to a single year.
In a letter order issued Monday, the commission said MISO could offer interconnection customers a faster finish time in return for proceeding without definitive network upgrade cost information (ER22-661).
The grid operator is hoping to whittle about 140 days from its generator interconnection process by cutting the days allotted for interconnection agreement negotiations and study and performing some study aspects simultaneously. (See Shorter Interconnection Queue Coming, MISO Says.)
Interconnection customers in the final phase of MISO’s three-part definitive planning process will now have a choice to spend 60 days in the stage without waiting on a network upgrade facilities study before proceeding to generator interconnection agreement (GIA) negotiations. Their other options is to spend about 150 days in a holding pattern while they wait on a final upgrade report.
GIA negotiations will be condensed from about 150 days to around 108 days under MISO’s plan.
FERC said the reductions stand to improve the interconnection queue’s efficiency.
The commission said it was appropriate for MISO to offer “each interconnection customer a choice between a timelier path to GIA negotiations with less cost certainty or a less timely path with more cost certainty entering into GIA negotiations, based on its preferences.”
FERC said generation developers that opt for the shorter path will do so with the “understanding that their assigned costs may be refined in the final interconnection facilities study report.”
MISO has said shortening the queue timeline will help it better align network upgrade planning with its transmission expansion plan, which is conducted on an annual basis.
For years now, the RTO has placed an emphasis on accelerating hold times for generation waiting for system access in its interconnection queue. Last month, the queue held 133 GW of projects, comprising mostly renewable generation.
Some stakeholders have expressed concerns that MISO can accomplish its goal. They say the real slowdown lies in the RTO’s notoriously time-consuming affected system analyses with its neighbors. Staff have said that if the new changes don’t meaningfully shorten queue wait times, MISO will pursue additional changes.
FERC on Friday accepted PJM’s revisions intended to increase transparency into and the efficiency of the RTO’s auction revenue rights (ARR) and financial transmission rights markets (ER22-797).
The commission’s decision marks a milestone for PJM after it and its stakeholders spent several years discussing changes to the markets after the GreenHat Energy default in 2018.
PJM filed the proposal in January after stakeholders endorsed the revisions at the Markets and Reliability Committee and the Members Committee in the fall with majority support. The FTR portion of the tariff revisions will take effect on Sept. 1, and the ARR portion on Feb. 1, 2023.
“We find that PJM’s proposal is just and reasonable because it enhances hedging opportunities for load and helps enhance market liquidity and future price discovery,” the commission said.
PJM’s proposal included revisions to its tariff and the Operating Agreement that were guided by the findings of a report developed by London Economics International (LEI).
Proposed enhancements to PJM’s current ARR/FTR market design. | London Economics
The RTO said its proposal aimed to recognize recommendations made in the LEI report and address concerns raised by the Independent Market Monitor and stakeholders. The proposal also sought to maintain the consultant’s conclusion that the existing FTR product is “reasonable and generally achieving the intended purposes” of serving as a financial equivalent to firm transmission service and to ensure “open access to firm transmission service by providing a congestion-hedging function.”
“The LEI report found that PJM’s FTR/ARR market design is achieving its dual purposes of facilitating the return of congestion charges to load and enabling hedging and supporting forward market activity, and overall is ‘creating overall positive value for load,’” the commission said. “However, the LEI report outlined potential enhancements to PJM’s FTR/ARR market design, focused on the themes of equity, efficiency and transparency, which PJM reflected in the instant proposal.”
The revisions make it so ARRs are allocated based on 60% of network service peak load, rather than zonal base load. They also provide additional self-scheduling options for ARR holders; add new FTR class types for on-peak weekday, on-peak weekend and holiday, general everyday off-peak and 24-hour products; increase the bid limits in all FTR auctions from $10,000 to $15,000; and add a $1/MW-period class clearing price floor for all FTR option products.
Protests
Several stakeholders protested portions of PJM’s proposal.
A group of consumer advocates — including the D.C. Office of the People’s Counsel, the Citizens Utility Board, the Delaware Division of the Public Advocate, the Maryland Office of People’s Counsel, the New Jersey Division of Rate Counsel, the Pennsylvania Office of Consumer Advocate and the PJM Industrial Customer Coalition — said they supported PJM’s proposal but maintained that it “does not go far enough in some respects.”
The advocates argued that even though a more direct alignment of congestion revenues and costs is “undoubtedly a step towards a more efficient and equitable FTR/ARR market,” the change doesn’t address situations where surplus congestion or auction revenues occur and “should be returned to the load that paid for the transmission upgrades that made those surplus revenues possible.”
Dominion also expressed support for portions of the proposal, but it argued that the revisions don’t fully address the “under-allocation of congestion revenues” for load and an inability of certain load-serving entities to “come close to covering their congestion costs.” Dominion said PJM’s filing “does little” to address “disparate outcomes” under the current ARR/FTR construct that “persistently creates results where the congestion cost recovery by LSEs varies greatly.”
The Monitor alleged that PJM’s filing “perpetuates or worsens fundamental flaws in the existing PJM FTR/ARR market,” saying the current market design “consistently failed to return the congestion revenues to the load that paid it.”
It also argued that the total congestion offset paid to load is “inequitable and varies by zone,” with some zones receiving more in offsets than the total congestion payments and other zones receiving less in offset. The offsets “are a function of the assignment of ARRs and the valuation of ARRs in the FTR auctions” and that the expansion or modification of the path-based rights available to load and the market will “simply change the arbitrary allocation of congestion among ARR holders and participants in the FTR market and will not correct the arbitrary allocation of congestion.”
FERC Determination
The commission said it determined the ARR market construct were just and reasonable and that the expansion of the source/sink combinations of the ARR allocation process “provides load the first rights to the transmission system before FTR holders can purchase such rights and, therefore, increases the network capacity allocated to load.”
“While not the sole purpose, one of the purposes of the FTR/ARR market is to return congestion charges to load, and this proposed change is consistent with that purpose,” FERC said.
FERC said the proposal’s call to replace zonal base load “protects zonal native load hedging ability by increasing up-front capability to load.” The commission said PJM’s selection of the 60% standard was a “reasonable limit at which additional value could be guaranteed” without significantly increasing violations or producing additional transmission constraints.
It also said that “PJM’s proposal to not award FTR options with a market-clearing price of less than $1 mitigates risk-free profit by ensuring all FTR options that clear have, at least at the time they were bid and awarded, actual value,” the commission said. “We also find that PJM’s proposal to create new FTR class types provides more flexible hedging opportunities.”
The commission said it disagreed with the challenges to how congestion surplus is allocated and the “fundamental nature” of a path-based FTR/ARR construct. It said the protests citing concerns regarding provisions of the existing FTR/ARR market construct were outside the scope of the proceeding.
FERC also disagreed with the Monitor’s argument that the revisions in the proposal do not return “sufficient” congestion revenue to load, saying it rejected the “foundational argument” that the “sole purpose of FTRs is to return congestion revenue to load and the market should therefore be redesigned to accomplish that purpose.”
“PJM’s proposal is not rendered unjust and unreasonable simply because the IMM thinks a further allocation to load would be desirable,” FERC said. “Consistent with commission precedent, we reiterate that ‘the purpose of FTRs to serve as a congestion hedge has been well established.’ FTRs were designed to serve as the financial equivalent of firm transmission service and play a key role in ensuring open access to firm transmission service by providing a congestion-hedging function.”
ERCOT interim CEO Brad Jones last week continued his push for a Texas gas desk in testimony before state legislators, who are toying with the idea creating a gas market monitor after disruptions in fuel supplies nearly collapsed the grid during last winter’s major storm.
Appearing Wednesday before the Senate Business and Commerce Committee, Jones compared ERCOT’s lack of transparency into the state’s natural gas system with looking through a peephole in the front door.
“We see images, we see shapes, but we don’t necessarily see the full picture of what we need to see. We don’t have a full view of the reliability situations in the gas market,” he said. “This is important today in our market as we try to assess the reliability of natural gas generators to get the fuel they need to produce the generation we need.”
Jones told the committee that ISO-NE, NYISO and PJM all have gas desks manned by staff 24/7. He has for several months pitched the grid operator’s board and stakeholders on the idea of having staff who “can gather that information and make sure we have the situational awareness we need at ERCOT.”
“We don’t know when a pipeline is out for maintenance or a compressor station on outage for something that is broken,” Jones said.
ERCOT’s Brad Jones (right) testifies before a Texas Senate committee as (left to right) Division of Emergency Management chief W. Nim Kidd, Railroad Commissioner Wayne Christian and PUC Chair Peter Lake listen. | Texas Senate
In October, he said staff “discovered by happenstance” that one generator it was counting on for power during a future low-wind day would not be able to operate because its gas supply transportation system would be undergoing maintenance. After a few calls and with the regulators’ help, staff was able to identify the transportation company and have the maintenance outage rescheduled “in a very cooperative way.”
“It was very helpful they did that, but the key is we didn’t know the information we needed to know,” Jones said.
For the moment, Jones believes the grid operator can get the information it needs through “voluntary cooperation,” but with the Texas Energy Reliability Council’s lead. The agency is made up of leaders from ERCOT, state regulators and industry. It has been meeting once or twice a month lately, helping improve coordination between the electric and gas sectors.
Asked whether Jones needed anything from legislators to make the gas desk a reality, he said not for the time being.
“The TERC has the capability to work through these issues,” he said. “Absent a cooperative environment, which I fully believe we have with the gas companies, TERC has the ability to make those recommendations to the legislature for the next legislative session.”
Increasing Oversight
The back-and-forth revealed that legislators may be conflating an operations desk like some gird operators have with the market monitors that keep an eye on wholesale electricity markets.
However, the gas industry is commonly seen as the weak link in ERCOT’s ability to meet demand with supply. While the grid operator’s generation and transmission facilities were required to be winterized and inspected before this winter, gas facilities don’t have to meet the same requirements until next winter.
The Railroad Commission (RRC), which regulates Texas’ intrastate oil and gas industry, is seen as being too chummy with the industry it regulates and has been accused of slow-walking regulatory changes. The commission’s first winterization rules allowed companies to opt out for a $150 fee, but that was changed after political pushback. (See Texas Senators Call for New RRC Weatherization Rules.)
A joint report by FERC and NERC pointed to the lack of consistent natural gas supplies to power plants as among the major causes for the widespread outages that followed last year’s winter storm. Natural gas supplies again dropped this year during several cold fronts, indicating shut-in production at Texas natural gas facilities, Bloomberg said.
“We need to continue our oversight responsibilities,” Committee Chair Charles Schwertner (R) said. “I think what happened last February has in some part the responsibility and blame of the legislature for lack of oversight.”
RRC Chair Wayne Christian was evasive in several of his responses to the committee. He told the committee there is “no state, nation, anything” that has daily monitoring and reporting of the gas supply.
Christian, who faces accusations of ethics violations, is in a Republican primary runoff with oil and gas attorney Sarah Stogner, who gained attention with a racy video involving her riding a pumpjack.
“I hesitate to add another layer of government regulation to the free market natural gas system.” Christian said.
He may not have a choice. Sen. Donna Campbell (R) said she might file legislation to gain greater transparency into the natural gas market when the 88th Texas legislature goes into session next January.
“I haven’t heard of any agency that wants more regulation by the legislature, but I will take that up,” Campbell said.
Offshore wind developers and experts, including representatives of three of the six winning bidders in last month’s federal New York Bight auction, see robust supply chain opportunities growing in the Northeast.
Jordan Shoesmith, Copenhagen Offshore Partners | NECA
There is $500 million of state funding available in New York for supply chain infrastructure, including ports, manufacturing and other types of investment, with a potential of $2 billion in total investment, said Jordan Shoesmith, head of business development in the U.S. for Copenhagen Offshore Partners.
The Danish company owns the southeasternmost lease area off Massachusetts and won the smallest lease area in the New York Bight auction in February. Six companies offered more than $4 billion for leases representing 5.6 GW of offshore wind capacity in the New York Bight. (See Fierce Bidding Pushes NY Bight Auction to $4.37 Billion.)
The public funding is not only “a lot of money, but also a huge opportunity to deliver the kind of real supply chain that’s going to last for generations,” Shoesmith said during the Northeast Energy and Commerce Association 2022 Renewable Energy Conference Thursday.
Carrie Cullen Hitt, NOWRDC | NECA
Supply chain issues are challenging for everyone in the business, and increasingly, both from a regional and international perspective, leadership from the federal administration and even the states could be quite helpful, said panel moderator Carrie Cullen Hitt, executive director of the National Offshore Wind Research and Development Consortium.
The consortium recently selected six organizations to receive a total of $3.4 million for projects related to supply chain efficiency, asset monitoring and inspection.
“New innovation is happening really quickly in terms of the materials that will be used and where and how they will be produced, so it’s really great to see some response from industry now that we actually see real commitments and deployments start to occur,” Hitt said.
Nabil Hitti, National Grid Ventures | NECA
With the “obvious” scaling of OSW in the U.S., “it’s crucial to get the supply chain … moving in the right direction urgently,” said Nabil Hitti, head of U.S. offshore wind at National Grid Ventures, which launched a joint venture, Community Offshore Wind, with RWE Renewables on Wednesday.
The partnership secured the largest lease area in the recent auction, nearly 126,000 acres, where it plans to develop up to 3 GW of capacity.
State solicitations are tending to put more weight on environmental benefits and economic investments that a project will bring, including the developer’s willingness to invest in supply chain development and jobs programs, said Christen Wittman, project director at Attentive Energy, provisional winner of the second-largest lease in the recent auction and a subsidiary of TotalEnergies.
“You’ll see developers submitting into New York, New Jersey and other states really full packages of what the project will look like and what commitments we would intend to make for the full structure and supply chain … but also incorporating elements of demonstrating project viability [and] risk mitigation,” Wittman said.
New Jersey is pushing its next solicitation back to early next year while the state considers an independent, coordinated transmission buildout, and New York released a draft OSW renewable energy certificates solicitation on Friday for comment. The state has not set a date for the official release of the solicitation.
New York’s strategy “is about being savvy with the investments in order to accelerate deployment,” said Adrienne Downey, principal engineer and U.S.-Canada manager at Sweden-based floating project developer Hexicon. Downey served previously as principal engineer for OSW at the New York State Energy Research and Development Authority (NYSERDA), which manages the state’s solicitations.
“We know that we achieve cost benefits if we work on deployment … but also that the Public Service Commission has taken a very enlightened and nuanced view that now we can create and cultivate a self-fulfilling prophecy of a declining cost curve by investing strategically in the supply chain,” Downey said.
Transmission Choices
States and RTOs are taking a more proactive approach to transmission, and in addition to the PJM-New Jersey state agreement approaches, there is also NYSERDA’s approach with the mesh-ready system design, which is also trying to solve these issues with innovative policy choices, Shoesmith said. “I think more and more we’ll see policymakers heading that direction.”
There’s legislation in Massachusetts (H.4515) to include a requirement for a transmission-only solicitation to occur this year, he said.
“We’ll see if it actually gets passed in time for that to happen, but I think it is something we have to think about very proactively,” Shoesmith said.
Al McBride, ISO-NE | NECA
ISO-NE has been working in partnership with the transmission owners and distribution companies to identify how interconnection studies and cluster studies are done, said Al McBride, director of transmission services and resource qualification at ISO-NE, speaking on a panel about state goals and grid policy.
“That’s in the near term, and in the longer term we’re also undertaking a 2050 study looking at what the transmission system might need to look like after all of these resources have entered and the system is changed to more transportation and heating being provided by electricity,” McBride said.
The grid operator is working to update how resources are accredited for the full capacity market to capture the balance between intermittent and baseload generation, according to McBride.
Others just want to get going with their projects.
“Put turbines in the water and let people see what the actual implications are and the actual benefits, and I think it becomes a lot less intimidating,” Wittman said. “To kick off site investigations by the end of the year is key for us.”
FERC on Thursday modified its discussion of a previous order rejecting Invenergy’s request to waive SPP’s financial security posting requirements, denying a rehearing request by operation of law.
The commission said in a letter order that it continued to find Invenergy’s waiver request does not address a concrete problem, as required under FERC’s four-part waiver criteria (ER21-2807).
Invenergy Wind Development and Invenergy Solar Development asked for the rehearing after the commission in December found that developer did not demonstrate that its potential loss of posted financial security “is a concrete problem that warrants waiver.” (See FERC Splits on Waivers from SPP IC Process).
The renewable developer said it had eight interconnection requests pending in the same SPP queue cluster as another developer. It alleged that the RTO said the study would need to be redone because requests higher in the queue were withdrawn from an earlier cluster. Invenergy said a discussion with SPP staff about the upgrades and assigned cost allocations left its questions unresolved.
Invenergy said that, faced with the choice of withdrawing its requests or posting a third financial security to preserve its option to stay in the queue and avoid losing previously paid security amounts, it chose to post security under protest for three of its eight projects.
FERC said Invenergy’s waiver request would address the potential to lose its posted financial security if it were to withdraw from the queue with a corresponding impact on the cost and timing of the remaining and lower queued interconnection customers.
“We continue to find that this potential loss is not a concrete problem that warrants waiver of the tariff as Invenergy has not been confronted with forfeiture of its financial security at this time,” the commission said.
Commissioner Mark Christie, who dissented from the previous order, concurred this time, saying it “represents the least bad alternative at this time.”
“It is undeniable that the commission’s ‘case-by-case’ implementation of its waiver policy has allowed it to, in this instance, provide undue preference for one interconnection customer over another without adequate justification,” Christie said. “Here, however, my colleagues have taken advantage of this discretion to reach outcomes that are both arbitrary and unduly discriminatory, and in doing so have undermined whatever value remained of the commission’s four-pronged waiver ‘test.’
“I hope going forward, we can reexamine the commission’s waiver policies to provide clear guidance that can be consistently and fairly applied going forward,” he said.
The California Energy Commission adopted a key report on gas decarbonization last week and opened a proceeding to explore options to replace gas derived from fossil fuels with options that include green hydrogen and electric heat pumps.
“The importance of this really can’t be overstated,” Commissioner Andrew McAllister said. “This is a generational shift, and we’re laying the foundation” for the transition away from fossil gas over the next quarter century, he said.
The report approved March 9 was one of four volumes in the Energy Commission’s 2021 Integrated Energy Policy Report, a biennial roadmap of state energy policy. It examined major issues, including the potential impact of the replacement of gas space- and water-heating with electric heat pumps, the affordability of natural gas as demand declines, and maintenance of aging gas infrastructure.
It addressed the potential for generating green hydrogen on-site at solar arrays and using gas produced from organic waste along with plans to retire the Aliso Canyon Natural Gas Storage facility in Southern California, site of a massive methane leak in 2015. An independent consultant is currently assessing options for closing Aliso Canyon between 2027 and 2035 and replacing its role as the region’s primary gas storage facility.
“The particular challenge is how to transition away from reliance on Aliso Canyon, recognizing the importance it plays in the reliability, safety and economic hedging for the greater Los Angeles area and Southern California more broadly,” the IEPR report said.
Another topic was the grid’s dependence on natural gas to meet demand as the state tries to achieve its 100% clean energy goal by 2045.
“The role of gas generation in the electricity system is shifting with the addition of large amounts of renewable generation, primarily solar and wind,” it said. “Gas generators not only ensure reliability but are key enablers of increasing amounts of renewable resources, which are the primary source of greenhouse gas emission reductions in the electric sector.
“A stable grid is essential to achieving emission reductions from electrification of residential and commercial buildings and electric vehicles to decarbonize the transportation sector,” it said.
The report noted that “defining pathways for gas system decarbonization and addressing key policy issues associated with the gas transition” require a long-term planning process that does not currently exist. As a start to fixing the situation, the CEC unanimously approved a new proceeding examining gas decarbonization strategies.
“As California decarbonizes its energy system, the state faces rapidly emerging gas issues,” the order instituting an information proceeding (OIIP) said. “These issues include declining long-term gas demand from building electrification, the critical interdependencies between the gas and electricity systems, and the potential role of renewable gas, renewable hydrogen, and other low carbon fuels and technologies.
“One of the overarching themes of the 2021 IEPR is that to address these issues the state needs a comprehensive, inclusive, long-term gas planning process to ensure a safe, reliable and equitable transition away from fossil gas,” it said. “This OIIP launches a proceeding to continue the dialogue on gas transition topics and begin carrying out the 2021 IEPR recommendations.”
PJM presented an updated proposal addressing start-up cost offer development at last week’s Market Implementation Committee meeting after being sent back to a subcommittee for more work on the issue.
Tom Hauske, principal engineer in PJM’s performance compliance department, provided a first read of the revised PJM/Independent Market Monitor proposal to revise Manual 15 that emerged from 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 so more discussions could take place and have stakeholders reach a consensus on a single proposal.
Manual 15 currently allows combined cycle units to include fuel costs after generator breaker closure and synchronization to the grid in their calculations of start-up costs that other unit types, like steam and nuclear units, cannot. The proposed revisions would align start-up cost for all units with a soak process, or units that use steam turbines.
Comparison of a 2×1 combined cycle unit with a pseudo-modeled 2×1 combined cycle unit when dispatched on a parameter-limited schedule | PJM
For units with a soak process, including steam, combined cycle and nuclear units, some of the soak costs would be 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, would maintain the status quo, with start-up costs including costs from PJM notification to first breaker close and from last breaker open to the shutdown process.
The revised proposal features several other changes to Manual 15 to provide additional guidance and clarification, 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.
Hauske said PJM’s intent is to 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.
“We’re trying to avoid the possibility of putting someone in a compliance trap where a unit today could wind up having a smaller start-up cost and then have a fuel-cost policy penalty,” Hauske said.
The committee will be asked to endorse the proposal at next month’s meeting.
Minimum Run Time Guidance Endorsed
Members unanimously endorsed PJM’s proposal addressing pseudo-modeled combined cycle minimum run time guidance after stakeholders asked for more time last month to analyze the changes.
Hauske reviewed the proposal that included adding language to Manual 11: Energy and Ancillary Services Market Operations that would require market sellers to update the minimum run time of any subsequent pseudo-modeled unit to remove the associated steam turbine start-up time included in the parameter limit when it’s dispatched.
Hauske said market sellers can model a combined cycle generation unit as multiple “pseudo units” that are made up of a single combustion turbine and a portion of a steam turbine. But he said the potential exists for one or more of the pseudo-modeled units to operate for a period beyond the minimum run time parameter limit compared to an identical non-pseudo-modeled combined cycle unit if the market units of a pseudo-modeled combined cycle unit are dispatched at different times because the steam turbine takes extra time to reach operative levels.
PJM would provide guidance developed in the initiative to any pseudo-modeled combined cycle unit requesting an adjustment during the review period, Hauske said, or to existing pseudo-modeled combined cycle units with an approved unit-specific minimum run time parameter.
The proposal will receive a final vote at the Markets and Reliability Committee meeting next week. Hauske said PJM wants to have a final endorsement at the next MRC meeting because the RTO’s unit-specific parameter adjustment process started Feb. 28, and PJM must provide a determination on the requests by April 15.
Manual 18 Revisions Endorsed
Stakeholders unanimously endorsed manual revisions conforming with several FERC orders related to PJM’s capacity market.
revisions to the application of the minimum offer price rule, which became effective by operation of law in September when the commission deadlocked (ER21-2582);
an October compliance filing to amend several sections of Attachment DD of the tariff establishing a replacement market seller offer cap (EL19-47);
restored tariff provisions reinstating the prior backward-looking energy and ancillary services (E&AS) offset for the 2023/24 Base Residual Auction and beyond (EL19-58); and
the removal of the 10% cost adder for the reference resource used to establish the variable resource requirement curve (ER19-105).
Bastian said language in section 3.3.2 was updated to reflect that the net E&AS of the reference resource combustion turbine will be calculated using the forward-looking methodology with the application of the 10% adder for only the 2022/23 delivery year. The net E&AS will be determined using the historical approach and without the application of the 10% adder for all other delivery years.
The revisions also delete language in section 5.4.5.2 describing the consequences of accepting a state subsidy after electing the competitive exemption or certifying that a resource is not state-subsidized.
Members will vote on the manual changes at next week’s MRC meeting for final endorsement.
Critical Gas Infrastructure Approved
Stakeholders unanimously approved an issue charge to address critical gas infrastructure recommendations for demand response.
Jack O’Neill of PJM’s demand response department reviewed the problem statement and issue charge addressing the recommendation for DR participation found in the FERC and NERCreport on last February’s winter storm in Texas and other parts of the South.
The report included a recommendation “to require balancing authorities’ operating plans (for contingency reserves and to mitigate capacity and energy emergencies) to prohibit use of critical natural gas infrastructure loads for demand response.”
Natural gas infrastructure in PJM | PJM
PJM began discussions with curtailment service providers (CSPs) through the Demand Response Subcommittee (DRS) to identify impacted loads for the 2021/22 winter season, O’Neill said, and the committee developed a preliminary definition of critical gas infrastructure loads.
O’Neill said CSPs have cooperated with PJM to identify impacted loads in the RTO’s DR Hub application so dispatchers have “operational awareness.” PJM estimates about 20 facilities of critical gas infrastructure load participate as DR in the RTO’s wholesale markets, amounting to about 95 MW of winter capability and 190 MW of summer capability.
The key work activities of the issue charge include defining critical gas infrastructure loads and PJM market participation rules in compliance with FERC/NERC recommendations and developing a transition mechanism if new participation rules impact member’s capacity commitment.
Work on the issue is assigned to the DRS and is expected to last 12 months. O’Neill said the goal is to file any necessary tariff changes with FERC in the first quarter of 2023.
Operating Reserve Clarification Endorsed
Stakeholders unanimously approved an issue charge to address clarifications and potential enhancements to the rules for paying operating reserve credits to resources running when requested by PJM.
Phil D’Antonio of PJM’s energy market operations department reviewed the problem statement and issue charge developed by the RTO to find opportunities to strengthen incentives for supply resources to operate consistent with PJM’s directions.
PJM pays energy uplift to market participants under specified conditions to guarantee that competitive market outcomes “do not require efficient resources to operate for the PJM system at a loss,” D’Antonio said. Uplift payments are one of the incentives for generation owners to offer energy for dispatch based on short-run marginal costs and to operate units through the direction of the RTO’s operators.
D’Antonio said PJM wants to clarify the definition of “operating as requested by PJM” in both the tariff and manuals because it “lacks the type of systematic approach” found in the definition of “following dispatch,” which is used in assessing balancing operating reserve deviation charges. He said PJM and the Monitor have debated the meaning of the definition and want to clear it up.
Key work activities in the issue charge include determining a definition of “operating as requested by PJM” as it relates to payment of operating reserve credits. It also seeks to establish alternative rules addressing the megawatt level to which balancing operating reserve credits should be paid to resources found not to be closely following PJM’s commitment and dispatch instructions.
D’Antonio said stakeholder discussions led to an additional key work activity to determine how intermittent resources are treated under the definition of “operating as requested by PJM” with respect to dispatch megawatts and/or forecast megawatts.
Stakeholders will work on the issue at the MIC beginning in April, D’Antonio said, with the potential for scheduling of special MIC meetings as needed. Work on the issue is expected to last around nine months.
FERC last week ruled that New York transmission owners (NYTOs) can exercise a right of first refusal (ROFR) for upgrades to their transmission facilities without being bound by other developers’ cost caps.
The commission’s ruling Friday adds rules for implementing a federal ROFR for upgrades that are part of another developer’s public policy transmission project under Order 1000 (EL22-2-001).
FERC had ruled in April 2021 that the NYTOs — Fortis’ Central Hudson Gas & Electric (NYSE:FTS); Consolidated Edison and Orange and Rockland Utilities (NYSE:ED); the Long Island Power Authority; the New York Power Authority; Avangrid’s New York State Electric & Gas and Rochester Gas & Electric (NYSE:AGR); and National Grid’s Niagara Mohawk Power (NYSE:NGG) — have a federal ROFR under the ISO-TO Agreement and other “foundational agreements” (EL20-65). (See FERC Confirms NYTOs’ Right of First Refusal.)
NYISO filed tariff changes to implement the ROFR in October under Federal Power Act Section 206 — requiring it to demonstrate that its existing rules were unjust and unreasonable — after stakeholders were unable to reach consensus on a filing under the lower threshold of Section 205. (See “MC Nixes ROFR Tariff Changes,” NYISO Management Committee Briefs: Aug. 25, 2021.)
The commission agreed with the ISO that the lack of rules governing the ROFR “will likely result in disputes at the commission and in court, which will cause delays and potentially harm competitive transmission development in New York.” It noted that the commission has already accepted tariff provisions implementing federal ROFRs in CAISO, PJM, SPP, MISO and ISO-NE.
The tariff revisions create separate categories for public policy transmission projects: new transmission facilities and upgrades to existing transmission facilities.
Under the new rules, which are effective as of Oct. 12, 2021, a NYTO will have 30 days to notify NYISO if it does not intend to exercise its federal ROFR for an upgrade. In such cases, the ISO will designate the upgrades to the developer that proposed the project.
Cost Cap Controversy
The new rules revise NYISO’s voluntary cost-containment requirements, clarifying that transmission upgrades will not be subject to any cost cap. The ISO said that requiring a NYTO to accept another developer’s cost cap would undermine the NYTOs’ federal ROFRs.
A group filing as “New York Consumer Advocates” — including the New York Public Service Commission, New York State Energy Research and Development Authority (NYSERDA), New York City and the Natural Resources Defense Council — protested that the lack of cost containment on upgrade projects would subject consumers to higher costs. Transmission developer LS Power separately contended it would undermine competition by causing developers to stop proposing cost-containment measures.
The commission sided with the ISO, saying that “making a developer’s proposed cost cap binding on the NYTO would raise complex implementation issues because the developer’s cost-containment proposal may or may not represent a reasonable expectation of the NYTO’s upgrade costs.”
It added: “While Order No. 1000 required evaluation of competitive proposals that result in the selection of the ‘more efficient or cost-effective’ transmission solution to an identified regional transmission need, it did not mandate that the transmission provider select the least-cost transmission project or apply cost containment for any project.”
FERC noted that four other grid operators — PJM, SPP, MISO and ISO-NE — either do not subject upgrades to a competitive evaluation process or do not allow nonincumbent developers to include upgrades in their proposals.
In a joint concurring statement, Commissioners Allison Clements and Mark Christie said they share the “absolutely legitimate” cost concerns expressed by the PSC and NYSERDA.
Christie went further in a separate statement, noting that NYISO is a single-state grid operator and that its agencies may reject a proposed transmission project because it is “too costly to consumers or that less costly alternatives are available.”
“And, of course, the ultimate recourse for consumers and consumer advocates concerned about the costs of New York’s — or any other state’s — public policies is to the ballot box,” he added.
Community solar advocates offered a compromise while Dominion Energy (NYSE:D) stood its ground in the latest round of filings last week over the minimum charge for customers who subscribe to shared solar projects.
The parties filed comments in response to the recommendation by Virginia State Corporation Commission hearing examiner D. Mathias Roussy Jr. that the commission approve its staff’s “Alternative Option B,” of a $55.10 minimum monthly charge — about $20 less than Dominion’s proposed charge of more than $75/month (PUR-2020-00125).
The utility had said anything less than that would result in cost shifts to nonparticipating customers. But commission staff, legislators and the Virginia Department of Energy had joined solar advocates in expressing concern that Dominion’s proposed charge is too high to encourage participation in the shared-solar concept. (See Stark Choice for Va. Regulators on Shared-solar ‘Minimum Bill’.)
Expected to launch in July 2023, the shared-solar program would allow apartment dwellers and those in homes unsuitable for rooftop solar to offset part of their electric bills by purchasing a share of solar projects remote from their homes.
Roussy’s recommendation satisfied neither Dominion nor advocacy groups, the Coalition for Community Solar Access and Appalachian Voices, which filed comments on the March 9 deadline.
Dominion said it stands by its proposal. “The company has consistently advocated for a minimum bill that is narrowly tailored to recover only those costs contemplated by the statute and regulations governing the shared solar program,” its counsel, Jontille Ray, argued. “As has been noted already in this proceeding, the minimum bill is not a company creation; it is a requirement of law.” Ray said that qualifying low-income customers would be exempt from the minimum bill.
Writing for Appalachian Voices, William Cleveland of the Southern Environmental Law Center called for adoption of CCSA’s minimum bill proposal of $7.58 per month. “Given Dominion and staff’s inclusion of non-incremental costs in their proposals and failure to produce any evidence or analysis of cost shifts or related cost-benefit analyses, the commission should select a minimum bill that does not rely on those omissions,” Cleveland said. “Unlike Dominion’s proposed minimum bill and Staff Alternative Option B, the low level of CCSA’s minimum bill — $7.58 — would deliver considerable savings to participating customers and help create a workable program.”
CCSA was more willing to compromise. After reviewing the back-and-forth in hearings before the SCC, Eric Wallace, counsel for the group, wrote, “With a $20 administrative charge component (as estimated by Dominion) factored in, CCSA’s proposal increases to a $20 minimum bill plus a $6.58 charge, so customers pay $26.58.”
CCSA’s original $7.58 proposal factored in a $1.00 administrative charge. CCSA’s revised proposal “is substantial relative to the $15-$20 range for other minimum bills around the country.” In Dominion’s South Carolina service territory, a minimum charge of $13.50 was recently approved for shared solar residential customers, he said.
Andy Farmer, the SCC’s interim director of the Division of Information Resources, told NetZero Insider Monday that the agency “does not have a specific timetable for issuing a final order in this case.
“An order could be expected in a few months,” he said.
