FERC has approved a new reliability standard intended to prevent conflict between registered entities’ protective relay settings and grid operators’ ability to protect reliability, nearly a year after NERC’s Board of Trustees approved the standard.
NERC’s board adopted the standard, which was developed as part of Project 2021-05 (Modifications to PRC-023), at its meeting in Tucson, Ariz., last February. (See “New Standards Sent to FERC,” NERC Board of Trustees/MRC Briefs: Feb. 15-16, 2023.) The commission gave its assent to PRC-023-6 (Transmission relay loadability) Jan. 25 in a delegated letter order (RD23-5).
As explained in NERC’s petition for approval, the new standard is intended to retire “redundant and unnecessary language that has contributed to confusion regarding” the applicability of previous versions of the standard to power swing blocking (PSB) relays. PSB, also called out-of-step blocking, is installed in long-distance transmission relays to prevent tripping during stable power swings.
Project 2021-05 was initiated after stakeholders expressed concerns that the standard “could lead to increased reliability risk by entities limiting or disabling their [PSB] elements.” The specific issue, according to NERC, was requirement R2, which mandated that transmission owners, generator owners and distribution providers set their PSB elements “to allow tripping of phase protective relays for faults that occur during the loading conditions used to verify transmission line relay loadability.”
NERC told FERC in its petition that the team for Project 2021-05 determined that this requirement is redundant because R1 addresses the same “fault condition” as R2 and “requires the same entity response.” R1 provides a set of criteria for entities to use to “prevent [their] phase protective relay settings from limiting transmission system loadability … for all fault conditions.”
The team observed that noting a specific fault condition, as R2 does, is unnecessary because R1 already covers all conditions. In addition, R2 “does not support directly the purpose of the … standard,” which mandates that protective relay settings not interfere with “operators’ ability to … protect system reliability and [shall] be set to reliably detect all fault conditions and protect the electrical network from these faults.”
NERC’s petition also noted that PRC-027-1 (Coordination of protection systems for performance during faults) “addresses the same reliability concern as … R2 in a much clearer and more comprehensive fashion.” That standard requires entities to coordinate their protection systems to ensure they operate in the intended sequence when faults occur.
The ERO said that in the event that a PSB relay did not allow tripping, “an unintended sequence of tripping” could result in other relays tripping through backup protection systems.” This would mean the coordination was not designed properly, a violation of PRC-027-1. NERC considered this further evidence that the older standard’s requirement was unnecessary, because an entity could still be audited for the PSB failing to trip.
In approving the standard, FERC noted it received no comments, protests or motions to intervene when the ERO’s petition was published in the Federal Register. The new standard will take effect on April 1, 2024, the intended effective date of PRC-023-5. The latter standard was approved in May 2021 to replace the currently effective standard PRC-023-4, but NERC asked FERC in its petition to let the new standard supersede it.
FERC on Jan. 29 approved ISO-NE’s proposal to create a day-ahead ancillary services market and retire the current Forward Reserve Market (FRM), effective March 1, 2025 (ER24-275).
Dubbed the Day-Ahead Ancillary Services Initiative (DASI), ISO-NE and NEPOOL jointly filed the proposal at the end of October. The new market will procure operating reserves and fill any gaps between the amount of energy procured in the Day-Ahead Energy Market (DAEM) and the load forecast.
“We are pleased with the approval by FERC to create a day-ahead ancillary services market that, together with today’s Day-Ahead Energy Market, creates a single, jointly optimized day-ahead market,” ISO-NE told RTO Insider in a statement.
With climate change increasing weather variability as the resource mix shifts toward weather-dependent resources, DASI will “encourage reliable resource performance and prepare the system on a day-ahead time frame with the flexibility needed to manage these new operational uncertainties,” ISO-NE said.
ISO-NE and NEPOOL noted in their joint filing that the existing DAEM “only procures energy to meet bid-in demand, and if the load forecast exceeds the amount of cleared energy from physical suppliers, there remains what the ISO refers to as a day-ahead ‘energy gap.’”
The RTO currently relies on out-of-market solutions to identify resources to fill these energy gaps and provide operating reserves.
“This process results in both under-compensation to those resources identified to provide these capabilities during the operating day and no specific financial obligation or incentive for such resources to be prepared to perform in real time in accordance with the operating plan,” the proposal said.
The ancillary services market will be run in conjunction with the existing DAEM; it will procure 10-minute spinning and non-spinning reserves and 30-minute operating reserves. It will also include an “Energy Imbalance Reserve” product, which is intended to fill energy gaps between the DAEM and the load forecast.
“DASI will provide targeted compensation and clear financial obligations and incentives for the flexible resources on which the region currently relies, and on which it will increasingly rely as the region heads into the future,” the filing said.
DASI will replace ISO-NE’s FRM, which provides forward seasonal payments for resources to provide 10-minute non-spinning reserves and 30-minute operating reserves. ISO-NE has said the FRM is incompatible with the implementation of DASI.
ISO-NE noted that an analysis of projected DASI revenues based on a 2019-2021 study period found that the initiative would increase annual wholesale market costs by about $104 million, or about 1.1%. The study indicated that the ancillary market would generate “substantial revenues” for storage resources, ISO-NE added.
The joint filing was supported in comments by the New England States Committee on Electricity, the Electric Power Supply Association, the National Hydropower Association and the New England Power Generators Association.
Meanwhile, LS Power expressed concern that replacing the FRM with DASI could decrease revenue for flexible resources.
“The overall DASI proposal will cut revenues for flexible generation by as much as 94%,” the company wrote in its comments, adding that DASI could introduce “unreasonable and undercompensated risks” for peaking resources.
In response, ISO-NE disputed LS Power’s revenue calculations. The RTO noted that its impact assessment found that total net revenues for ancillary service suppliers would decrease by only about $5 million annually, adding that this assessment “may understate the revenues that will be earned by reserve-capable suppliers, compared to those currently earned through the FRM.”
The DASI filing requires ISO-NE’s Internal Market Monitor “to issue ad hoc reports on the competitiveness of any major market design change within one year of the effective date of operation, and on its performance within three years.”
The RTO recognized requests from stakeholders for longer-term reserves and wrote that it plans to kick off discussions on longer-term products for the real-time and day-ahead markets in 2025.
FERC found that DASI will “materially improve operating reserve resource readiness, efficiency and day-ahead price formation in ISO-NE without undue increases in wholesale market costs.”
The commission expressed skepticism of the concerns raised by LS Power, writing that the company “does not demonstrate that revenue levels under DASI, which result from market-determined clearing prices, will not be just and reasonable for the purpose of procuring and compensating operating reserves.”
In a concurring statement, Commissioner Allison Clements expressed strong support for the changes.
“The DASI reforms appear to be an important step forward for ISO New England’s ancillary services market and one reflecting the region’s evolving operational needs as its resource mix changes,” Clements wrote.
“For a proposal of this complexity to have near universal support in the record and unanimity in the stakeholder process is a testament to the hard work and productive collaboration of many in New England,” she added. “It is worth taking a moment to give credit where credit is due.”
New Jersey’s mass transit agency has abandoned a more-than-$500 million plan to build a gas-fueled emergency resiliency generator amid sustained opposition from environmental groups.
NJ TRANSIT, which runs 12 commuter rail lines linking the state with New York and Philadelphia, said the plan — known as TransitGrid Central Facility — was “not financially feasible.” The agency said it would take the $503 million in federal grants designated for the plant and use the money for other projects, including a new bridge, upgrading of a rail yard and expanding a rail terminal.
The transit agency walkback comes after a year in which the New Jersey Department of Environmental Protection (DEP) in April put in place the final rules for a tough new environmental justice law and held a series of “public engagement” sessions around the state to solicit residents’ concerns about environmental issues.
NJ TRANSIT proposed the 140-MW gas generator and microgrid in Kearny, N.J., after Superstorm Sandy in October 2012 caused widespread and prolonged power outages that severely affected rail service for nearly a week. Despite the agency’s statements the generator would be used for only resilience, opponents for years have argued the state shouldn’t be creating new gas plants as it strives to cut carbon emissions and rely on renewable energy.
“While the TransitGrid procurement process provided valuable knowledge for the future, it showed the funding would be better used to protect these other critical points around the state,” NJ TRANSIT CEO Kevin S. Corbett said in a release Jan. 26 that announced the shift in funding away from the project.
The release said “all of the these affected projects within the Sandy Resilience program are critical pieces of rail infrastructure, including bridges, safe haven storage yards and infrastructure located directly on waterfront properties bearing the brunt of past and future storm events.”
The release added that because the agency proposed the project, “multiple improvements to the affected power grid have been enacted that have functionally made the MCF as envisioned at that time much less necessary than other critical resiliency projects.” In particular, PSE&G has made “significant investments in power grid resiliency under a program called “Energy Strong” throughout the region that has greatly increased power reliability,” the release said.
Anjuli Ramos-Busot, director of the New Jersey Sierra Club, welcomed the agency’s reversal on the “harmful project,” saying her organization had said for years that it’s not financially viable.
“This decision recognizes that gas is not the future for New Jersey and [we] hope that we can continue to move in the right direction toward renewable energy alternatives, battery storage and incorporating climate resilience into everything that we do,” she said. “This decision is a win for the local communities who are overburdened with air pollution, particularly Kearny.”
Providing Storm Resiliency
The Department of Environmental Protection outreach effort comes amid a realization among government officials, planners and developers in New Jersey and elsewhere that community outreach and securing local buy in are key to implementing energy projects and ensuring they advance smoothly.
New Jersey until late last year had six planned gas generating plants, and the Kearny plant was one of three such facilities in North Jersey that for years have drawn particularly vigorous opposition because of their proposed locations in overburdened communities. Only one of the three North Jersey plants now remains on the drawing board.
On Oct. 11, developer Competitive Power Ventures (CPV) withdrew its plans for a 630-MW gas-fired generating plant under development in the Keasbey section of Woodbridge, which local residents opposed. CPV said after it abandoned the gas-fired plant, which would have been the company’s second in that township, that the plant was no longer feasible because market conditions had changed. (See Electric vs. Gas Skirmish Rising in NJ.)
Superstorm Sandy stimulated the development of the third controversial gas plant by the Passaic Valley Sewerage Commission (PVSC), which describes itself as the fifth-largest publicly owned wastewater treatment facility in the U.S. The facility lost power for three days after the 2012 storm, resulting in 840 million gallons of raw sewage pouring into the Passaic River and New York Harbor.
Newark-based PVSC wants to build a $600 million “integrated natural disaster resiliency project” that would serve as a standby power generation facility. The plant would include three 24-MW combustion turbine generators and two 2-MW natural gas-fueled generators.
Early on, PVSC also planned for the plant to provide “peak load management” service to PSE&G’s grid when it came under heavy load demand. But the agency withdrew that plan in June 2021 in the face of public opposition. Activists have urged the PVSC to consider powering the resiliency project with renewable energy. But the agency has said gas would be a better option, although the project website says that “doesn’t mean that renewable energy and alternative fuel sources aren’t an option down the road.”
Public Concern
Opposition to the three projects has surfaced frequently at the DEP’s public engagement meetings, and the issue was highlighted by a speaker at an Oct. 17 meeting in Hudson County, which includes Kearny, the site of NJ TRANSIT’s now-abandoned project. The series of meetings is supported by the federal EPA’s Region 2 office.
Elizabeth Ndoye, a Hoboken, N.J., resident and a member of Don’t Gas The Meadowlands, a group that opposes the development of fossil fuel generators, gave the DEP’s October meeting a succinct snapshot of how she feels climate change has impacted her life.
“I am a 75-year-old mother who will never be a grandmother,” Ndoye told the meeting in Union City, N.J. “Because my daughter-in-law refuses to have grandchildren because we are living in a time of climate crisis. So I am being robbed of the natural joy of most women on this planet.”
As a dedicated environmentalist, she said, she takes pride in CPV’s abandonment of plans to create a gas-fueled plant in Central New Jersey.
“We stopped it in Woodbridge,” she said, and concluded her comments by saying New Jersey Gov. Phil Murphy (D) must “stop these horrible carbon-based dirty fossil-fuel projects.”
Confronting Historic Injustice
In New Jersey, concern that communities were not being heard in decisions over environmental issues led to the enactment of the state’s environmental justice law, which took effect in April with the adoption of the final rules. On signing the law in September 2020, Murphy called it a “historic step” that made the state “home to the strongest environmental justice law in the nation.”
The law requires the DEP to evaluate environmental and public health impacts of certain facilities on overburdened communities (OBCs) when they seek permits. The DEP says it makes New Jersey the first state able to “issue denials for new facilities that cannot avoid disproportionate impacts on OBCs or serve compelling public interest.”
At the heart of the law, according to the DEP, is the legislature’s belief that “historically, New Jersey’s low-income communities and communities of color have been subject to a disproportionately high number of environmental and public health stressors” stemming from the “numerous industrial, commercial and governmental facilities” placed in those communities.
The new environmental justice law means that while the DEP in the past looked at the pollution impact of potential facilities over wide geographic areas, the state also now must look at the local impact and how it affects “a community’s fundamental right to live, work, learn and recreate in a clean and healthy environment,” the DEP says.
Applicants seeking environmental permits for certain pollution-generating facilities must follow new procedures that include identifying environmental and public health stressors from the proposed facility. Applicants also must ensure that meaningful public participation by members of the host community takes place.
The law also empowers the DEP to take into account those stressors and study the concentration of facilities in a given area.
High Density Environmental Impact
Kandyce Perry, director of the office of environmental justice, opened the Union City meeting by saying that though the meeting was part of an ongoing public input solicitation process, the area around the meeting was distinct.
“Here in Hudson County, the densest county in the state, which is already the densest state in the country, communities are contending with compacted neighborhoods that abut against industry, traffic congestion and historic brownfield sites,” she said.
“As our climate gets warmer, the most vulnerable of our residents within Hudson County will be hit hard,” she said. “And this is why it is so important for government to hear directly from those of you who are most impacted by these experiences.”
Key deadlines already have arrived for MISO’s spring capacity auction, while the RTO has hiked its planning reserve margin for the 2024/25 planning year.
So far for the upcoming summer, MISO has accounted for nearly 161 GW in installed capacity across the footprint that whittles down to almost 129 GW in total seasonal accredited capacity. The RTO must meet a 135.7-GW summer planning reserve margin requirement.
MISO will use a 9% summer 2024 planning reserve margin, higher than the 7.4% annual planning reserve margin used in last year’s Planning Resource Auction. MISO said its shifting resource mix and a move to seasonal modeling for its reserve margin contributed to the increase. This year, the RTO said it’s using seasonal values, rather than annual, in its generator verification testing data, reflecting different capabilities of generators in different temperatures. The upcoming spring auction marks the second time MISO has divided its capacity auction by season.
MISO stressed Jan. 17 that it’s “too early in the process to make quantifiable conclusions” on how much supply it expects beginning June 1.
The grid operator plans to update its supply information based on the data it receives from market participants every other week through late March. It said it expects information on energy supply to change “significantly.”
MISO resource owners have until Feb. 1 to confirm their seasonal accredited capacity values with the RTO. Load-modifying resource owners also have until Feb. 1 to register to participate in the auction. As of mid-January, MISO said approximately 12.8 GW of load-modifying resources from prior years had not started the registration process.
MISO confirmed Jan. 30 it likely will try again with FERC in the third quarter to apply an annual megawatt cap to its interconnection queue.
FERC in December denied MISO’s request to annually cap submittals to its interconnection queue on concerns over too many cap exemptions, the formula to establish the cap and potential resource adequacy deficits from limiting new generation onto the grid. (See FERC Rejects MW Cap, Approves MISO’s Other Stricter Interconnection Queue Rules.)
MISO said it will apply the rules FERC did approve to the 2023 cycle of project requests, which has been on pause since last year for FERC’s decision on the package of more stringent interconnection requirements. The new rules include increased entry fees, an automatic penalty schedule for withdrawing projects and added proof that developers have secured locations for projects.
MISO said it will belatedly open its 2023 queue cycle project window on March 18 and close it on April 18. That cluster of projects will not be subject to a megawatt cap. Currently, the RTO’s online generator interconnection portal remains closed to new applications.
MISO hasn’t abandoned the idea of a megawatt cap on future queue cycles. The grid operator plans to again propose a megawatt cap that first could apply to the 2024 class of projects.
Aneta Godbole of MISO’s resource utilization team said FERC “provided good guidance that MISO will use in its future refiling efforts.”
“MISO will come back to the stakeholders once it is ready for further discussion,” Godbole said of a second cap filing during a Jan. 30 teleconference of the Interconnection Process Working Group.
At this point, the RTO intends to begin processing both a 2023 and 2024 cycle of generation project requests this year. It said if all goes to plan, it could place the 2024 queue cycle deadline at the end of the year.
“MISO is anticipating two cycles in 2024, but it depends on our work to reduce the backlog, the size of the 2023 cycle, the cap filing and approval of the” long-range transmission plan (LRTP) and the MISO-SPP Joint Targeted Interconnection Queue (JTIQ) transmission portfolios, Godbole said. MISO previously said the regional LRTP and the interregional JTIQ will help support new generation interconnections.
Additionally, MISO said either its 2024 or 2025 class of project requests will be the first to proceed under FERC’s Order 2023 queue requirements, depending on the final effective date.
Some stakeholders were incredulous that MISO could handle the workload of two queue cycles in a single year given the uptick in project submittals.
“There are a lot of factors on when we hold the next queue cycle,” MISO’s Andy Witmeier added. He said the RTO wants to be transparent about which factors it foresees dictating when it can open a 2024 queue cycle.
At the Jan. 24 Planning Advisory Committee, Witmeier called a megawatt cap a “vital tool.” He also said MISO won’t file to apply a megawatt cap retroactively to projects in the queue.
A new coalition called Transmission Possible launched Jan. 25 to support local, state and federal efforts to expand transmission, while a recent paper from the National Bureau of Economic Research (NBER) put some numbers on an issue that has often complicated those efforts.
The new group is led by Advanced Energy United, and it includes the American Council on Renewable Energy, Americans for a Clean Energy Grid, the National Wildlife Federation, the Environmental League of Massachusetts and the Northeast Energy Council.
“Much of America’s transmission infrastructure was built in the 1950s and ’60s, and even though the technology has come a long way since then, we really haven’t made any significant improvements to the grid in 70 years,” said Verna Mandez, a director at Advanced Energy United who is overseeing Transmission Possible. “America and its energy needs are growing, and building interregional transmission lines is the way we ensure we have a reliable power grid that cost-effectively delivers energy from where it’s generated to where it’s needed.”
Transmission Possible’s campaign will encourage regional collaboration among states to plan lines across their transmission lines. It will endorse state policies that encourage the buildout of transmission lines.
The campaign will support deployment of immediate solutions to grid congestion, such as high-performance conductors and grid-enhancing technologies (GETs). It will also host a resource hub for decision-makers, stakeholders and the public about the role of transmission in ensuring grid reliability and accelerating the transition to clean energy.
Reaching the goal of 100% clean electricity by 2035 will require as many as 91,000 miles of new transmission lines over the next decade, while in the interim, the deployment of GETs could unlock as much as 40% more capacity from existing lines.
National Bureau of Economic Research Paper
A recent paper from the NBER put some firm numbers on a commonly cited barrier to transmission expansion: When lines open up isolated patches of the grid to greater competition, it cuts the prices for local generators.
“Power Flows: Transmission Lines and Corporate Profits” by Catherine Hausman, an associate professor at the University of Michigan’s Gerald R. Ford School of Public Policy, examined the issue using publicly available data on generators in MISO and SPP. While other papers have mentioned the issue of utilities trying to protect their generators’ income, Hausman estimated how fully expanding the two regions’ grids to fully tap their rich wind resources would impact generators’ profits.
The cost of transmission constraints has been on the rise, averaging $300 million to $400 million from 2016 to 2020, while spiking up to $2 billion in 2022 because of rising curtailments and higher natural gas prices.
“The transmission network until recently basically did what it needed to: connecting thermal power plants to load in population centers,” the paper said. “But in a world with increasing quantities of renewable generation, the existing network doesn’t match the spatial distribution of generation.”
Lower natural gas prices in the 2010s also flattened the marketwide marginal cost for electricity, which minimized the impact of constraints.
“But with natural gas prices surging up, the marginal cost curve has rotated, and dispatching the ‘wrong’ unit — because of something like a regional transmission constraint — has gotten much more expensive,” the paper said.
The $2 billion from 2022 could be justified if the cost of building new transmission is very high, but the paper noted that many grid observers have argued that the planning process does not lead to socially optimal investments, especially when it comes to long-distance lines crossing regions.
“The rise in wind energy in recent years has decreased profits for fossil incumbents — but crucially, by less than it would have had the market been fully integrated,” the paper said. “That is, fossil incumbents have been partially protected from new competitors by a lack of transmission.”
The overall impact masks important differences, with the paper finding that firms in MISO South (Entergy’s territory) would lose the most because it has poorer transmission connections to the rest of the market.
If the grid were fully expanded, just four firms would stand to lose $1.6 billion, or three-quarters of the total inefficiencies seen in 2022. In other years, the number would have been smaller, but those firms’ share would have been similar.
The firms that would have benefited the most are in Iowa, Illinois and Missouri, and they would have brought in about $1 billion in 2022, while wind farms would have earned an additional $800 million. The wind farms’ extra profit would have been spread wide across many facilities, though the paper noted that NextEra Energy owns many of them in the region.
Entergy Arkansas and Entergy Louisiana would lose the most from the expanded grid, at a combined $930 million in 2022. Renewable energy advocates and others have alleged that the firm has tried to delay or cancel transmission improvements, the paper said.
“The results in this section suggest that the current planning process is problematic given the fact that market integration is expected to bring very large losses to some incumbents,” the paper said.
American Transmission Co. will pay $75,000 to the Midwest Reliability Organization for violations of NERC’s facility rating standards, according to a settlement approved by FERC on Jan. 26.
NERC filed the settlement with the commission as part of its monthly spreadsheet notice of penalty at the end of December (NP24-4). FERC said in its filing Jan. 26 that it will not review the MRO settlement, along with an additional nonpublic spreadsheet NOP concerning infringements of NERC’s Critical Infrastructure Protection standards, leaving the penalty intact.
ATC owns and operates high-voltage transmission lines in Wisconsin, Minnesota, Michigan and Illinois. The settlement involves violations of FAC-009-1 (Establish and communicate facility ratings) and its successor FAC-008-3. According to MRO, the violations began in December 2009 and ended in August 2022, and involved facilities in both its footprint and that of ReliabilityFirst. However, NERC’s spreadsheet NOP did not indicate whether the regional entities would share the penalty.
The settlement says ATC submitted a self-report in October 2017 indicating that it was not compliant with FAC-008-3, followed by a second self-report involving two additional violations of the same standard in the first quarter of the following year. Because MRO determined that both violations began before FAC-008-3 became effective in 2013, the RE processed them under the earlier standard.
In the first self-report, ATC indicated that the rating for a winter season line segment was incorrect because the utility had not correctly recorded the segment’s temperature. The utility’s second submission reported a “bus section rating that did not reflect an equipment rating and a line conductor rating discrepancy that affected the transmission line facility rating.”
After discovering these issues, ATC ordered an independent evaluation of its data sets and found rating errors in 47 facilities — one substation and 46 transmission lines. MRO observed that this amounted to less than 5% of ATC’s total facilities.
Nineteen of the misratings were “lower than the actual rating of the most limiting element,” MRO said, which “and may have prevented system operators from utilizing the full capability of these facilities.” More serious were the 28 facility ratings that exceeded the most limiting element, which the RE said could have resulted in equipment overloads and damage to critical equipment.
Most of the equipment involved was never actually operated above the corrected rating; however, one 138-kV cranking path facility did exceed the corrected rating for five minutes at one point. MRO said this event posed a moderate risk to grid reliability because the involved line was part of the utility’s black-start restoration plan, although the RE also noted that the risk of damage to equipment was “highly unlikely” and that load on this segment would likely not reach its actual rating during a system restoration event.
ATC’s mitigation actions include updating its substation equipment and line database, correcting any incorrectly assigned relays, and updating procedure and process documents used in updating facility ratings. The utility also performed internal training, defined and documented its approach to quality checks, and completed evaluations and extent-of-condition reviews for its data sets and mitigation plans.
MRO gave ATC mitigating credit for self-reporting the issues and for cooperating in the enforcement process. The RE also considered the utility’s internal compliance program “as a mitigating factor in the penalty determination” because of its important role in the enforcement process. According to MRO the ICP empowers ATC’s employees to “go directly to the most senior leader and/or” the company’s Board of Directors, and “directs operational staff to be involved in the investigation of noncompliance and the creation of mitigation.”
WESTMINSTER, Colo. — The competing efforts by SPP and CAISO to build and deploy an RTO in the Western Interconnection have sometimes been painted as a race in which the winner will be first grid operator to reach the finish line.
Hold your horses, now (pun intended).
Some in the West have come to the conclusion there are likely to be two day-ahead markets in the West: CAISO’s Extended Day-ahead Market, and SPP’s Markets+ and/or RTO West. They’re also saying it is now time for CAISO and SPP to begin talking about seams issues.
“We are accepting the possibility of two day-ahead markets,” Vijay Satyal, deputy director of regional markets for Western Resource Advocates (WRA), said last week during SPP’s first Markets+ Participants Executive Committee (MPEC) meeting of the year. “For now, we will seek to ensure there’s little seams impact from possible bifurcated day-ahead markets in the West.”
Satyal raised the possibility of two markets several times during the meeting. WRA, a nonprofit environmental law and policy organization, has maintained for five years that the region’s economic, reliability and environmental benefits are maximized with one large Western RTO.
Now, Satyal says, “the sooner, the better” that CAISO and SPP start talking with each other.
SPP said its Markets+ staff and CAISO began regular informal monthly meetings in July to discuss the design and status of both markets. The RTO has much more regular communication over reliability issues with CAISO as a neighboring reliability coordinator in the West.
Carrie Simpson, SPP’s senior director of seams and Western services, said the conversations include “making our seams as seamless as possible” and present an opportunity for SPP to work with CAISO and stakeholders to find a better way to mitigate the risks on both sides.
“This could be one of those areas that we’ve worked for improvement. This [design item] is a good way to just recognize that [participants] might have to carry more [flexibility reserve] because this type of product is coming in,” she said, noting tariff language brought forward by the Markets+ Seams Working Group (MSWG). “The seams group felt it was appropriate to allocate the uncertainty costs to these types of transactions. It allocates the cost to those who are buying from CAISO to sell into SPP because of the uncertainties around those types of transactions.”
Chelan County Public Utility District’s Tuuli Hakala chairs the MSWG. She suspects most members of her team joined to work on those very issues.
“My expectation is that as we’re working through protocols, we’re identifying elements where this is an area where this policy could be improved through formal coordination,” she said.
Satyal said he didn’t think the discussions between the grid operators go far enough or give enough transparency to stakeholders that might be affected by both market footprints.
“It is going to be extremely important to build interoperability agreements (i.e., seams management) so that we have better coordination between the two markets,” he told RTO Insider. He called for agreement on issues “involving either reliability management or the economic impacts, transmission and greenhouse gas management that come with two adjoining markets at work together.”
“This is a proactive request that WRA feels is important and in the interest of the public, ratepayers and customers,” Satyal said. “The next year and a half are critical for both markets to come to the table and agree on a principle statement around the seams, to agree on what are the operational areas and then what are the specific practices that require coordination. [CAISO and SPP] have had initial discussions, but if there’s going to be a true transparent stakeholder process … the utilities and market participants that are going to sign participation agreements should be aware and be part of this.
“Doing so now would make future seams agreement work more flexible to update and propose to FERC for approval,” he added, calling for a seams evaluation or study scenarios that look at three different levels of power flows as the ideal next step. “It’s important that all parties come to the table and support the two market operators in the minimum elements of a seams framework.”
MMU, MSC to Collaborate
SPP’s Market Monitoring Unit and the Markets+ State Committee (MSC) agreed to collaborate on clearly defining an observed participant obligation gap in the tariff that was identified by state regulators.
At issue is a 2022 FERC Notice of Proposed Rulemaking related to “duty of candor.” It would require all entities communicating with the commission or other organizations — e.g., the MMU — about FERC matters to provide “accurate and factual information” (RM22-20). (See FERC NOPRs Would Require ‘Candor,’ Improved Accounting for Renewables.)
Oregon Public Utility Commissioner Letha Tawney called into the meeting and said the MMU’s “continued concern” of a weakness in the existing Markets+ tariff “concerns the MSC.” She said the committee is seeking rules that “explicitly apply” to all entities, with everyone held to the same expectations.
“We all know when there is trust, and that is built on transparency, and the rules apply to everyone who participates … and you are seeking those customer benefits that an efficient, well-functioning market can deliver. From that perspective, we are all very aligned,” Tawney said. “We all know from our shared experience in the West that there is a fragile trust that the West has begun to build in the concept of security-constrained economic dispatch.”
The MMU argued before the MPEC in November that “duty of candor” language was missing from the tariff. Asked for examples of duty-of-candor violations, Monitor Keith Collins said he could offer hypothetical examples, but he would be breaking FERC rules by giving specific examples of what counts as privileged information.
“There are times when we asked for more information, and we would expect that information to be accurate and factual,” Collins said. “Unfortunately, that has not always been the case, and that can create some problems for us.”
“It remains unclear to MSC members that all market participants will have the same obligations in how they respond to requests for information from the MMU outside of a specific market-manipulation situation,” Tawney said. “There have been challenges [in the Eastern Interconnection] to holding everybody to that obligation to respond.”
The Markets+ legal subgroup will assist the MMU and MSC in determining any changes that need to be made in addressing the issue and bring recommendations to MPEC’s Feb. 20 virtual meeting. If consensus is not reached, the MPEC will move forward with the existing tariff language.
The MPEC also asked the MSC to update the Interim Markets+ Independent Panel (IMIP) that is overseeing the first phase of the market’s development.
Independents Sector Changes
MPEC members unanimously endorsed a recommendation from the Independents sector to create a Markets+ Interim Governance Task Force that would review and process governance issues before they go to the committee. The group’s makeup is subject to MPEC’s determination.
Those issues include the weighting of votes within the sector, a sticking point since last year, and potential improvements of Markets+ sector definitions. (See IMIP Approves SPP Markets+ Governance Tariff Language.)
The Independents sector has also proposed that its votes be calculated on a single-vote-per-member basis, with at least half of the sector reserved for Markets+ participants, stakeholders with at least 1 MW in the market’s footprint or stakeholder organizations with at least five members, a majority of whom must be involved in wholesale markets.
The sector is a catch-all comprising public information groups, independent power producers, markets and other participants that aren’t investor-owned or public power utilities.
“It’s a very broad sector,” said Kylah McNabb, speaking for the National Resources Defense Council. “This helps the Independent sector manage itself, given our diversity.”
Draft Tariff Posted
Stakeholders endorsed several more pieces of tariff language during the meeting, with SPP posting the draft’s 592 pages Jan. 26. MPEC members have until Feb. 9 to submit their comments on the tariff and its 14 attachments detailing the market’s services, terms and conditions.
The IMIP will take up the tariff for approval in late February. The SPP Board of Directors will then consider it during a special meeting in late March, after which it will be filed at FERC.
SPP is hoping for the commission’s approval in about nine months, allowing it to begin Phase II of Markets+’s development.
HOUSTON — The Gulf Coast Power Association’s membership has elected Beth Garza, a senior adviser for R Street Institute and long-time presence in the ERCOT market, to a two-year term as president.
Garza joined R Street after 11 years with Potomac Economics. She served as the ERCOT Independent Market Monitor’s deputy director or director for Potomac until 2019.
Her 35 years in the electric industry also have included leadership roles at ERCOT, NextEra Energy and Austin Energy, where she gained expertise in generation and transmission planning, system operations, regulatory affairs and market design. She has an engineering degree from the University of Missouri and is a registered professional engineer in Texas.
GCPA’s Board of Directors filled out its officers by selecting Brian Lloyd, vice president with Oncor, as vice president; Mark Egan, Energy Evolution Advisors’ founder, as treasurer; and Donna Benefield, senior vice president with NRG Energy, as secretary.
Outgoing President Mark Dreyfus made the announcement during the GCPA’s annual meeting Jan. 18. He said 2023 was a “fantastic” year with corporate memberships up from 137 to 153, its largest corporate membership on record. Individual memberships increased from 301 to 337. Registrations for meetings and conferences were up 28% over 2022 as the organization set attendance records for its annual spring and fall conferences and its MISO–SPP forum.
The attendance numbers resulted in strong financials for the organization. Total revenues exceeded $1.9 million, an increase of just over $400,000 from the prior year “because of the economic recovery and strong attendance memberships revenues,” and added $651,000 to the GCPA’s coffers.
The profits will be used to fund the organization’s scholarship program, which was resumed after the COVID-19 pandemic. Under the revamped program, GCPA will award ERCOT, MISO and SPP $20,000 each to go to outstanding students in their summer internship programs.
Dreyfus said the hunt continues for a new executive director with the experience and contacts “to really keep the organization moving forward.” Kim Casey announced her retirement last year; she was the fourth ED in GCPA’s history.
Solar advocates have petitioned FERC to take enforcement action against Arizona’s Salt River Project for setting rates that allegedly discriminate against customers with rooftop solar.
The rooftop solar rates are in violation of the Public Utilities Regulatory Policies Act (PURPA), according to the petition. It was filed Jan. 12 by the nonprofit advocacy group Vote Solar and two SRP residential customers with rooftop solar.
“SRP’s current policies for residential customer solar violate the commission’s rules and have decimated what was previously a robust market for solar,” the petition said.
The petition asks FERC to compel SRP to offer nondiscriminatory electric rates for rooftop solar customers as well as fair rates for buying electricity from those customers.
As an alternative to an enforcement action, the petition asks the commission to make a finding that SRP’s rates for rooftop solar customers violate PURPA.
PURPA is intended to encourage development of small power producers and co-generators and to reduce fossil fuel demand.
SRP said in a statement that it is reviewing the FERC filing.
“Based on an initial review, we believe the claims are without support and the background provided regarding SRP’s programs and support of its solar customers is inaccurate,” the utility said.
SRP said it has a number of rate options for rooftop solar customers and, as of September, had more than 54,000 residential customers with rooftop solar systems.
Solar Rate Plans
Rate disputes are often resolved by a state’s public utility commission, according to David Bender, an Earthjustice attorney who’s working on the case on behalf of Vote Solar.
But because SRP is not regulated by the Arizona Corporation Commission, the petitioners took their issue to FERC, Bender told RTO Insider.
If FERC doesn’t initiate an enforcement action within 60 days, the petitioners may bring an action in federal court.
According to the petition, SRP has separate rate plans for rooftop solar customers and nonsolar customers.
The solar customers pay a fixed monthly charge that is up to $25.44 higher than that paid by nonsolar customers, the petition said, while the kilowatt-hour charge and demand charge are the same for both types of customers.
In addition, the petition said, only non-solar customers are offered the EZ-3 time-of-use plan, which includes a “more advantageous” three-hour peak period: 3 to 6 p.m. or 4 to 7 p.m.
In contrast, the time-of-use plan offered to solar customers has a longer peak period that varies by season — 2 to 8 p.m. in the summer and 5 to 9 a.m. plus 5 to 9 p.m. during the winter, according to the petition.
“All of the solar-customer tariffs impose higher fixed charges and preclude solar customers from benefits available under tariffs for nonsolar customers,” the petition alleged.
SRP’s rates to buy electricity from solar customers also violate PURPA, according to the petition, which said that the 2.8 cents/kWh reimbursement under several of SRP’s tariffs is lower than the utility’s full avoided costs.
New Mexico Case
Bender worked on a similar case involving solar rates charged by the Farmington Electric Utility System, owned by the city of Farmington, N.M.
In that case, FERC declined to act on a petition filed in April 2019 by Vote Solar and several Farmington residential electric customers who had rooftop solar. The parties contested a “monthly standby charge” that the Farmington utility charged its solar customers.
They took their case to federal court. The case was dismissed in U.S. District Court, but a Court of Appeals reversed the decision. Farmington rescinded its additional charges for solar customers and, under the terms of a settlement, agreed to credit or refund customers who had paid the standby charge.
