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November 5, 2024

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FERC Accepts All 6 ISO/RTO Order 895 Compliance Filings

WASHINGTON — FERC on July 25 approved all the jurisdictional ISO/RTO compliance filings with Order 895, which established rules for sharing credit information among the organized markets.

Issued in June 2023, Order 895 directed the six grid operators to create procedures for sharing credit information about wholesale market participants with each other. The order is intended to “improve their ability to accurately assess market participants’ credit exposure and risks related to their activities across organized wholesale electric markets.”

FERC said the rules will help prevent market participants from defaulting, thus forcing the ISO/RTOs to collect the costs from other market participants. Before the order, the grid operators’ own confidentiality rules would have prevented them from sharing market participants’ information.

“Market participants increasingly operate in multiple organized wholesale electric markets, whether directly or through affiliated entities, and their trading activities have become more complex and sophisticated,” FERC said in Order 895. “These developments have complicated the ability of any individual RTO/ISO credit department to develop a complete, accurate and up-to-date picture of a market participant’s overall financial condition due to real or perceived barriers to information sharing among RTOs/ISOs.”

FERC found that CAISO’s (ER24-155), ISO-NE’s (ER24-138), NYISO’s (ER24-95), PJM’s (ER24-156) and SPP’s (ER24-289) filings satisfied the order’s requirements, including that they protect the data they collect from other markets. Their proposals went uncontested and, in some dockets, without any interventions.

While the commission found that MISO’s proposal allows it to share information and to use credit information received from other ISO/RTOs, and the RTO said it would treat such information from another market as confidential, such language was absent from its tariff revisions (ER24-165). FERC directed MISO to submit a compliance filing in 60 days spelling that out in its tariff.

The accepted revisions went into effect the next day. Though they were issued at the commission’s first open meeting with new Commissioners Lindsay See and Judy Chang, they did not participate in the orders.

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FERC Accepts SPP Congestion Hedging Changes

FERC filed a letter order July 25 accepting SPP’s proposed tariff revisions to implement congestion hedging improvements, ending a journey through the stakeholder process that began six years ago (ER24-1775). 

The commission found SPP’s proposal will “improve market participants’ ability to hedge congestion costs by allowing SPP’s models to reflect congestion more accurately; allocating [long-term congestion rights], [incremental LTCRs] and [auction revenue rights] more broadly and equitably among eligible entities; and distributing surplus auction revenues more equitably.” 

SPP’s change request is a result of the stakeholder-driven Holistic Integrated Tariff Team’s work in 2018/19. The team’s charges included developing a high-level policy recommendation that aligns the grid operator’s transmission planning processes and resource adequacy needs with its markets and tariff requirements. 

Staff and stakeholders developed a package of eight congestion-hedging policies that were approved by the board and state regulators in February. (See “Congestion-hedging Policies’ Implementation,” SPP Board of Directors/Members Committee Briefs: Feb. 5-6, 2024.) 

SPP said the changes better align the network models it uses in the simultaneous feasibility test with the studies it uses to grant transmission service. That will prevent some transmission paths from not capturing all congestion and other paths that look feasible but do not offset the congestion experienced by load.  

The RTO is changing the process for awarding LTCRs and ILTCRs and the annual ARR allocation of ARRs by using a two-step, single round process in the second round of the LTCR allocation, knocking off two rounds. Eligible entities will be allowed to nominate 50% of their ARR nomination cap, reduced by the LTCRs awarded. Entities that receive a higher number of LTCR awards will nominate fewer ARRs in the first round of the ARR allocation. 

Also, SPP will break the simultaneous feasibility test performed during the second round of the LTCR/ILTCR allocation and the first round of the annual ARR allocation into five equal subrounds. Because breaking the simultaneous feasibility test into smaller increments makes it less likely that large portions of awards will go to a single entity, LTCR/ILTCR and annual ARR awards will be allocated more broadly and equitably. 

The grid operator is changing the distribution of surplus auction revenues by awarding them in greater proportions to eligible entities that received a lower proportion of LTCRs and ARRs tied to firm transmission service. The new approach will be phased in halfway into the first year (2025/26) to reduce the effect of revenue shifts. 

The revisions exclude transmission service reservations that do not source at a resource or a resource hub in the commercial model from being verified and used for LTCR and ARR nominations. SPP will apply the same exclusion when assessing grandfathered agreement transmission rights, and transmission service reservation holders will be allowed to update existing services’ sources to specific resources or resource hubs in the commercial model without triggering an aggregate transmission service study process. 

SPP’s Market Monitoring Unit said the grid operator’s proposal will create more equity in allocating ARRs, LTCRs and ILTCRs and a more equitable distribution of surplus auction revenue among market participants owning firm transmission rights. It supported the revised method of distributing surplus auction revenues.   

Intervening in the docket were American Electric Power Service Corp., on behalf of its affiliates Public Service Company of Oklahoma, Southwestern Electric Power Co., AEP Oklahoma Transmission Co. and AEP Southwestern Transmission Co.; Evergy Kansas Central, Evergy Metro and Evergy Missouri West; Kansas Electric Power Cooperative; Lincoln Electric System; Midwest Energy; Missouri River Energy Services; Omaha Public Power District; Public Citizen; Western Farmers Electric Cooperative; and Xcel Energy Services, on behalf of affiliate Southwestern Public Service Co. 

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DC Circuit Declines Entergy Challenge of MISO Seasonal Accreditation

The D.C. Circuit Court of Appeals rejected Entergy’s challenge of MISO’s seasonal capacity accreditation and generator outage rules, two years after FERC approved the rules.

The court in a July 26 order decided FERC adequately explained why it allowed the new capacity accreditation and denied Entergy’s petition for review (22-1335).

Entergy argued that MISO’s new capacity accreditation would result in volatile and fluctuating capacity scores and that MISO’s seasonal outage rules for generators were burdensome.

MISO’s capacity accreditation assigns values based on resources’ performance over the past three years. The accreditation calculation gives a heftier, 80% weight to the 65 hours in a year when supply is the tightest and gives all other hours in a year a 20% weight.

Entergy contended MISO’s method over-relied on just 65 hours, and a generator’s accreditation could be tremendously affected if a planned outage happened to occur during some of the riskiest 65 hours. The company made similar arguments when requesting a rehearing of FERC’s 2022 approval. (See Regulators, LSEs Ask FERC to Reconsider MISO’s Seasonal Capacity Accreditation.)

But the D.C. Circuit decided FERC appropriately evaluated the accreditation style using a MISO-created analysis that compared existing and proposed accreditation methods to actual resource availability over 11 days containing emergency conditions in 2021. MISO found its old methodology overestimated resources’ offerings anywhere from 8 to 22%, while its new process was off by just 1%.

The court said FERC was correct to assume MISO’s new accreditation would be “more accurate than its prior approach when predicting resource performance during periods of highest demand.”

Entergy argued MISO’s 11-day sample size was too small. But the court said its hands were tied on considering MISO’s sample size because Entergy didn’t specifically raise that concern in its rehearing request with FERC. The court cited the Federal Power Act’s “unusually strict” exhaustion requirement.

The court also noted MISO uses a three-year rolling average when taking stock of a resource’s availability for accreditation, reducing year-to-year accreditation volatility.

“If bad luck besets a resource one year, the impact of such bad luck is blunted by the fact that other years can help balance out an anomalous season,” the court said.

The court didn’t see anything amiss with MISO’s generator outage length and notice requirements, either. It agreed with FERC that MISO’s 31-day limit “would give generators enough time to perform maintenance, while also ensuring that generators would be online for the majority of each season.” It disagreed with Entergy that the threshold would hinder necessary, extended outages.

MISO requires capacity resource owners either must acquire replacement capacity or pay penalties if they are offline for more than 31 days in a season and that they must notify it 120 days in advance of planned outages to be exempt from accreditation reductions.

“FERC reasonably explained that owners of such resources have four options: shortening maintenance; acquiring replacement capacity; opting out of the capacity market for a season while maintenance is undertaken; and scheduling maintenance so that it straddles two seasons, enabling planned outages of up to 62 days in length,” the court said. “As FERC explained, it is unfair for resources to go offline for more than 31 days in a season when distributors have paid for the resource’s commitment to supply electricity during that season.”

The court further said it made sense for MISO to require notification of outages before the start of a season so it can anticipate capacity supply.

MISO began using the seasonal, availability-based capacity accreditation in the 2023/24 planning year. FERC last year rejected Entergy’s attempts to secure waivers for two of its plants so it wasn’t affected by MISO’s accreditation rule, which assigns thermal units a zero-capacity credit when they take longer than 24 hours to start up. (See FERC Rejects MISO South Waiver Requests from MISO Accreditation Standard.)

Despite MISO’s relatively recent move to its current accreditation method, it isn’t here to stay for long. MISO again plans to modify its accreditation style so nearly all resources are valued based on a combination of probabilistic and historical availability. (See MISO: New Capacity Accreditation Filing Imminent.)

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New Western ‘Regional Organization’ Could be Folsom-based

The new “regional organization” (RO) envisioned by the West-Wide Governance Pathways Initiative might be based near CAISO’s headquarters in Folsom, Calif., according to a straw proposal from the initiative’s RO Formation and Governance Work Group. 

The proposal was among a handful floated by the group during a July 25 public meeting to discuss the logistics of establishing and governing the RO, designed to assume independent authority over CAISO’s Western Energy Imbalance Market (WEIM) and Extended Day-Ahead Market (EDAM) under “Step 2” of the Pathways Initiative. 

Another proposal would have the RO be incorporated as a 501(c)(3) nonprofit public benefit organization (like CAISO, ISO-NE and NYISO), rather than a 501(c)4 social welfare organization (MISO, ERCOT) or 501(c)6 mutual benefit nonprofit (SPP, Western Power Pool and Western Resource Adequacy Program). PJM stands alone among RTOs/ISOs in its status as a limited liability corporation. 

Work group participant Lisa Tormoen Hickey, senior regulatory attorney at Interwest Energy Alliance and member of the Pathways Launch Committee, said the work group considered how each type of corporation could serve multiple state interests and various types of utilities, and support the potential for the RO to expand its service offerings in the future to include functions such a transmission planning. 

“But we mostly looked at how they would operate, employing people and renting or owning real estate and other property as necessary to be organized and operate as a viable entity in — or serving — multiple states in the West,” Tormoen Hickey said. 

The work group determined that a 501(c)(3) structure would provide advantages in supporting the RO’s efforts in fulfilling “public purpose,” while offering further nonprofit tax advantages by allowing the new organization to obtain tax-exempt financing, which reduces the costs of long-term financing and bonding. 

Another proposal calls for the RO to be incorporated in Delaware because of the state’s “well-developed” body of corporate law and “experienced and knowledgeable” judges and the “ease” of dealing with its secretary of state.  

“We can incorporate in any Western state, and most of them have adopted fairly standard nonprofit statutes, but they do have differences related to their amount of oversight and strict rules for formation of a board, whereas Delaware is quite flexible and considered to be a leader for corporate governance, both nonprofit and for-profit,” Tormoen Hickey said. She noted that incorporating in Delaware also could avoid the political controversy of incorporating in a Western state. 

“I’m completely in agreement that the body of Delaware state laws is probably the most mature for formation, and it’s certainly been where most of the markets are incorporated, in terms of a legal precedent and body of laws standpoint,” said committee member Scott Miller, executive director of the Western Power Trading Forum. 

Question of ‘Co-location’

But the work group could be courting controversy with its straw proposal to make Folsom the RO’s principal place of business, even as the Pathways Initiative seeks to create an entity that operates independently of CAISO and California oversight. 

“Any Western state that we choose would present a question of perception of bias and control rather than independence of that state, and we considered all of that, but we consider that to be a limited actual risk,” Tormoen Hickey said. 

In developing the proposal, she said, the group considered the RO’s “actual center of direction control and coordination” and the location of its most “significant volume” of operations. It also factored in the extent of interaction between the RO and CAISO and the potential for sharing employees between the two. 

“The RO will have its own employees; we do not yet know whether they will be few or larger in number, depending on how Step 2 [of the Pathways Initiative] shapes up,” she said, referring to the outcome of the California legislation needed to release CAISO’s governance from state control. 

“We do want the RO to rotate its physical presence around the West. We will recommend that it [hold] meetings physically in various states around the West because that will enable stakeholder engagement and a feeling of representation within each of those states,” Tormoen Hickey said. 

“The reality is, given this step with the RO, and even if we go to [Step] 2.5, which envisions a slightly larger employment structure for the RO than [Step 2], the interaction with CAISO seems to suggest that co-locating in Folsom makes the most efficient sense, and particularly since we’re building an organization that’s a hybrid organization,” Miller said. 

Launch Committee member Connor Reiten, vice president of government affairs at Portland-based PNGC Power, said the “perception” of the RO’s home base is going to be important in the Northwest, making it important for it reach out and engage in individual states. 

“Putting this principal place of business wherever it makes the most sense from a legal perspective, from a recruiting perspective for the staff, all those elements, I think that’s most important to focus on,” said Connor Reiten, vice president of government affairs at PNGC Power. 

“Ultimately, the issue of perception from our perspective is going to be making sure that when we are interacting with the RTO, we’re not feeling like we’re having to go to Folsom every single time there’s a board meeting or otherwise, and that these things are happening in the states that are affected by this market,” Reiten said. 

Lynn Mostoller, executive director of New Mexico’s Renewable Energy Transmission Authority (RETA), cautioned the Pathways backers about using of the term “co-location” in its proposal. 

That “pricked my ears because my board chair is particularly California-takeover-phobic in this whole process,” Mostoller said. Avoiding the term could minimize controversy about the move, she added. 

“I assume there would be completely separate offices. It would just be in the city of Folsom, not a backroom in the CAISO offices,” Mostoller said. 

‘Working’ Proposals

The work group also floated a series of “working” proposals, including: 

An RO board consisting of seven members who “meet the knowledge and skills requirements” outlined in a board selection procedure. “When we looked at this, we were trying to balance making sure we had a large-enough board to ensure that we had adequate diversity — regionally, knowledge and experience to govern the market rules, but at the same time, not end up with a 20-person board or unmanageable number of board members,” said committee member Jim Shetler, general manager of the Balancing Authority of Northern California.  

    • No board seats to be reserved based on sector, knowledge or skill. “We think that the nominating committee and the board and their selection process should have the freedom to weigh what is the right person or right set of skills and knowledge needed a particular time,” Shetler said. 
    • A collaborative relationship between the RO and CAISO boards, with joint meetings to be held to consider issues of joint authority. 
    • Allowing the RO’s Formation Committee to deal with details related to the transition of responsibilities from the Western Energy Markets (WEM) Governing Body to the RO board. 

More complete descriptions of all proposals can be found here and here.  

The group also shared a timeline for establishing the RO, which includes:

    • creating a Formation Committee by December 2024; 
    • developing a corporate structure, drafting a tariff and bylaws, and selecting a Nominating Committee and executive search firm to select board members between January and August 2025; 
    • signing of California legislation to alter CAISO governance by the end of the state’s 2025 legislative session, followed by a filing of tariff language with FERC and recruitment of the RO’s board and executive team; and 
    • filing incorporation documents, seating board and hiring staff in fall 2025. 
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FERC Requires More Intel on MISO’s New Capacity Accreditation Method

FERC said it needs more explanation behind MISO’s plan to accredit resources based on a combination of their projected availability and historical performance during periods of high system risk.

The commission handed MISO a deficiency letter July 25 concerning several aspects of its proposed direct loss of load capacity accreditation method and gave it 30 days to respond (ER24-1638).

Under the proposed method, generators’ capacity credits would be determined by a two-step process that marries historical performance of individual generators with a probabilistic performance during simulated loss-of-load events. (See MISO: New Capacity Accreditation Filing Imminent.)

First, MISO would calculate a probabilistic, resource-class average accreditation using its loss-of-load modeling. It would tailor resource class-level accreditations to individual generators based on their availability during both normal operating conditions and high-risk hours, including hours containing low margins or hours with an emergency event in place. MISO plans to give greater weight to hours that contain emergency or near-emergency conditions in the ensuing accreditation.

Most resources’ credited capacity would shrink under the new method. Resources would be divided by fuel type: gas, coal, hydro, nuclear, energy storage, pumped storage, wind and solar. MISO said the new process would satisfy both a prospective and retrospective approach to accreditation and wants it in place for the 2028/29 planning year.

But FERC wanted to know if MISO would consider deliverability limits in either the individual or resource-class level accreditation calculations. It asked whether a resource is required to obtain full deliverability rights to receive the maximum capacity accreditation and asked if the accreditation would differentiate between resources interconnected at MISO’s basic, unguaranteed energy resource interconnection service or the higher-quality, firm network resource interconnection service.

FERC was also interested in how the 1,950-hour limit that MISO intends to use in its probabilistic model for high-risk hours would help it take the best measure of resource availability.

MISO proposed to gauge resource availability using the riskiest 65 hours, or 3% of a season, across 30 weather years in its loss-of-load modeling. The 1,950 hours include all the times when loss of load occurs and then draw on hours when available generation comes within 3% of load or less.

However, that limit does not kick in if MISO’s modeling shows more than 1,950 hours when loss of load occurs. The RTO said it did not want to “dilute” real loss-of-load risk in its accreditation.

FERC asked how MISO would factor load forecast error and effective margin into the weighting calculation for risky hours to capture future uncertainty.

The RTO should also explain how it will model and dispatch storage with the new method, FERC said, pointing out that stakeholders had asked it to delay the filing of the proposal until it can improve its loss-of-load modeling of storage.

FERC said MISO needs to justify its strategy to use resources’ planned outages to decrease the capacity availability of resource classes in its probabilistic model. It pointed out that the RTO currently allows exemptions for planned outages in its accreditation.

The commission asked after MISO’s criteria for establishing resource classes, including the operating characteristics and any quantitative thresholds it looks for to sort resources.

And FERC questioned MISO placing oil, gas and dual-fuel resources in the same resource class. It asked MISO if there was a minimum number of megawatts or individual resources it requires before forming a new resource class. The commission appeared to suggest that it perceived operating differences between dual-fuel, oil and gas resources.

Finally, the commission was interested in knowing more about how MISO would handle instances when a market participant disputes the class their resource is categorized into. It also requested MISO’s final deadline for making resource-class level accreditation calculations in the event that resource classes change by more than 3% and at least 30 MW.

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NW Senators Urge BPA to Delay Day-ahead Market Decision

All four U.S. senators representing Oregon and Washington have urged the Bonneville Power Administration (BPA) to delay its decision to join a Western day-ahead electricity market until developments play out further around SPP’s Markets+ and CAISO’s Extended Day-Ahead Market (EDAM).

In a July 25 letter addressed to BPA Administrator John Hairston, Democratic Sens. Jeff Merkley (Ore.), Ron Wyden (Ore.), Maria Cantwell (Wash.) and Patty Murray (Wash.) called on the federal power marketing administration to “act carefully and deliberately” before selecting a market.

The letter lays out the need for a “reliable, resilient and clean electrical grid” to achieve “the economic and environmental goals of the Pacific Northwest,” including electrifying transportation and buildings and “meeting the demands of our growing manufacturing and data center industries.”

It also points to the requirement for continued reliable service for residents and businesses in the face of “increasingly frequent extreme weather events.”

The senators’ letter additionally signals a preference shared by many state officials, environmental groups and large energy users across the West: that the region would benefit more from one organized electricity market than from two.

“In light of these major challenges, we share your view that ‘Bonneville’s customers and electricity consumers across the Pacific Northwest may achieve more benefits from participants coalescing around one regional market in the West,’” the senators wrote, quoting from a policy letter circulated by Hairston in January.

The letter comes about four months after BPA staff published a recommendation that the agency choose Markets+ over EDAM and just over a month before it is expected to issue a draft record of decision on its selection. A final decision is slated for November. (See BPA Staff Recommends Markets+ over EDAM.)

“Given ongoing uncertainties and the changing landscape with regard to both day-ahead electricity markets, we are concerned that BPA has expressed a preference for one market before complete and final information is available for clear decision making,” the senators wrote.

Among those uncertainties, according to the senators, is the fact that the Markets+ tariff, which SPP filed with FERC in April, is still under review by a largely new slate of commissioners and could face deficiency letters that take additional time to resolve.

Although not cited in the letter, PacifiCorp, the first utility to fully commit to EDAM, has asked FERC to reject the Markets+ tariff without prejudice, letting SPP refile it without a provision that would allow Markets+ participants to contribute their transmission rights in nonparticipating systems. (See SPP Markets+ Tariff Sparks Concerns for PacifiCorp, NV Energy.)

FERC issued a mostly clean approval of CAISO’s EDAM tariff last December.

The senators also raised a particularly heated topic in the West right now: the potential impact of seams between Markets+ and EDAM, which they said “may prove challenging to resolve, leaving ratepayers unable to realize economic and reliability benefits.”

In response to this concern from stakeholders, both BPA and SPP have said they have ample experience dealing with market seams and would be able to reliably manage the transfer of energy between the two markets. (See SPP’s Experience with Seams Could Help Markets+.)

14 Questions on ‘Leaning’

The senators acknowledged one of BPA’s primary reservations about committing to EDAM — CAISO’s state-run governance — and it credits the agency with spurring a regional effort to increase the ISO’s independence.

“The firm position taken by BPA that governance reforms were necessary helped inspire the West-Wide Governance Pathways Initiative last year. We see this effort has made real progress, culminating with NV Energy’s recent announcement that it intends to join EDAM,” the senators wrote.

For its part, BPA said July 18 that it has ramped up participation in the Pathways Initiative as the effort moves into its second phase, which is focused on changing California law related to CAISO’s governance and establishing an independent Western “regional organization” to assume oversight of the ISO’s EDAM and Western Energy Imbalance Market. But an agency official also noted that the move did not indicate BPA was pulling back from its “leaning” in favor of Markets+. (See BPA Stepping up Participation in Pathways Initiative.)

The senators asked BPA to clarify the reason for its leaning by responding to 14 questions with detailed analysis by Aug. 25. Among them are requests for BPA to explain which of the two day-ahead markets it expects would bring lower energy costs to the Northwest, provide the greatest improvement to grid reliability and reduce greenhouse gas emissions by the largest amount. The senators also asked if the agency’s concerns about CAISO’s governance would be assuaged by California’s adoption of the Pathways Initiative proposal and, if not, what outstanding issues remain.

“BPA’s decision to join a day-ahead market is monumental; BPA must be able to demonstrate that it is in the best interests of communities across the Northwest that are reliant on BPA for both power and transmission services,” they said.

The senators concluded by saying that their letter should not be taken as favoring one market over the other.

“We share a strong belief that any decision of this magnitude warrants thorough evaluation of all options, including joining neither market at this time,” they said. “BPA should refrain from making any draft or final decisions until there is less uncertainty and BPA can prove that any decision will provide the greatest benefit to the entire Northwest.”

In a statement emailed to RTO Insider, BPA said it “understands the magnitude of this decision and is committed to ensuring we do the right thing for our customers and the region through the deliberative process we have engaged in so far. BPA is committed to fully evaluating the benefits and mechanics of day-ahead markets to accomplish this objective.”

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FERC Open Meeting Showcases Order 1920 Rehearing Debate

WASHINGTON — The ongoing debate around Order 1920 and its pending rehearing requests continued at FERC’s monthly open meeting July 25, a day after it came up at a House oversight hearing. (See related story, Order 1920 Debated at House Hearing with All 5 FERC Commissioners.) 

Order 1920 came after Order 2023, which set new standards for interconnection queues, and Order 1977, which implemented FERC’s new backstop siting authority for lines in National Interest Electricity Transmission Corridors. 

“I believe this suite of transmission reforms is balanced,” Chair Willie Phillips said. “And I believe it will give us what we so desperately need to meet the demand that we know is going up in our country; to bring all of those resources that we know are waiting in the wings.” 

Phillips also noted that a group of state regulators from around the country supported Order 1920 in a letter to FERC this week (RM21-17). 

But legal challenges to the order kicked off July 15 when FERC issued a notice that it had not acted within its 30-day statutory deadline for responding to rehearing requests. A group of Republican state attorneys general have filed an appeal of the rule with the 5th U.S. Circuit Court of Appeals — as have many other parties, including those that generally support it, in appellate courts around the country. 

The commission did not say why it had not acted on the nearly 50 rehearing requests filed, but former Commissioner Allison Clements departed at the end of last month, and three new commissioners have joined since the order was issued in May. 

One area even some supporters of the rule would like to see changed on rehearing is whether transmission providers should be required to file any alternative cost allocation schemes proposed by state regulators. Commissioner Mark Christie dissented from the order over the issue. 

“We’ll respond to every single issue raised” in the rehearing requests, Phillips told reporters after the meeting. “To the extent that there are improvements that can be made to the rule, I look forward to working with my colleagues on what those might be. I think you hear me joke all the time that it’s a perfect rule, but I do believe that while it’s a great step forward, we’re just getting started. We can make improvements.” 

Christie said ensuring FERC gets to rule on any cost allocation proposal from states is a change that should be adopted on rehearing. 

“That ought to be one of the top priorities in amending because I think there’s going to have to be several major amendments to this rule to make it something that certainly would be acceptable to the states,” Christie said. “And I think that would just be one of the many issues that needs to be changed. And I would hope that there will be a majority on FERC amenable to making those major changes because, otherwise, this rule is not going to work.” 

Phillips and Clements did not require any resulting state plans be filed in part because of a precedent in Atlantic City Electric Co. v FERC, they argued. Christie argued in the dissent that the case did not tie FERC’s hands that much.  

An alternate interpretation is before the commission on rehearing, with the Harvard Electricity Law Initiative’s Ari Peskoe arguing that the precedent only stops FERC from forcing utilities to cede their rights to file rate changes under Federal Power Act Section 205. 

“Atlantic City does not prevent the commission from amending the pro forma [Open Access Transmission Tariff] to include a process for filing all regional cost allocation methods approved by relevant state entities, regardless of the transmission provider’s approval,” Peskoe wrote in his rehearing request. “Imposing a process for filing relevant state entities’ cost allocation methods would not ‘deny [utilities] their right to unilaterally file rate and term changes.’” 

Some state regulators have made similar arguments in their rehearing requests, noting that FERC has given their counterparts in SPP cost allocation filing rights. 

But Christie also argued that additional changes would be needed for his support, including giving states the chance to approve the parameters and benefits used in the planning process. As written, he argued, the order will spread the cost of public policy lines to unwilling states, contrary to Phillips’ continued insistence. 

Christie noted that MISO Independent Market Monitor David Patton has repeatedly criticized the RTO’s Long Range Transmission Planning process, which was cited as the model for Order 1920 by supporters. Patton argues that the LRTP consistently overstates benefits, which leads to too much transmission being built. (See MISO IMM Knocks LRTP Benefit Calculations, RTO Poised to Add More Projects.) 

While Phillips and Christie have been engaged in an often-public debate on the merits of Order 1920, the majority on rehearing will include at least some of FERC’s three new members who are still getting up to speed on its voluminous record. 

“The commission works best when we have five members,” Phillips said. “What that really means is that when you have five commissioners, they bring with them all of their history, all of their experience [and] all of their expertise to bear. And I believe you get a better result; you get better orders; you get better outcomes because of that diversity of opinion. And so, because we have five now, I think we will get an even better order on rehearing.” 

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FERC Ends Section 206 Proceeding for New Brunswick Energy Marketing

FERC ruled July 25 that New Brunswick Energy Marketing does not appear to have horizontal market power in the New Brunswick (NB) balancing authority area, concluding a Section 206 proceeding that came out of a failed market share screening test (ER14-225-008, et al.).

The NB balancing authority includes parts of Northern Maine and Eastern Canada. NB Energy Marketing is a subsidiary of the crown corporation NB Power and is directly interconnected to the transmission systems of ISO-NE and the Northern Maine Independent System Administrator.

ISO-NE initiated a Section 206 proceeding after NB Energy Marketing failed a “wholesale market share indicative screen” in three of the four seasons in the 2020/21 study period, suggesting the presence of horizontal market power.

The proceeding aimed “to determine whether NB Energy Marketing’s market-based rate authority in the New Brunswick balancing authority area remains just and reasonable.” (See FERC Orders Section 206 Proceeding for New Brunswick Energy Marketing.)

Responding to FERC’s show cause order on horizontal market power, NB Energy Marketing made the case that the results of a delivered price test (DPT) and a sensitivity analysis indicate the company is not a pivotal supplier.

When accounting for NB Power’s capacity factors and average load, the company “has a market share generally less than 20% and does not contribute significantly to market concentration,” NB Energy Marketing wrote in its filing.

Based on this evidence, FERC terminated the Section 206 proceeding, concluding that “on balance, NB Energy Marketing has successfully rebutted the presumption of horizontal market power in the New Brunswick balancing authority area.”

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FERC Accepts NYISO Capacity Accreditation Changes, with 1-Year Delay

FERC on July 23 approved NYISO’s proposed tariff revisions to more accurately accredit natural gas resources’ capacity, but the commission delayed their implementation until 2026 (ER24-2096).

NYISO pitched the changes as a way to help improve winter reliability by accounting for gas supply constraints and correlated derates in its capacity accreditation framework, which measures resources’ marginal contribution to resource adequacy.

Among the changes is a requirement that generators tell it by Aug. 1 prior to each capability year how much of their capacity was covered by firm fuel supply.

NYISO had proposed implementing this provision beginning with the next capability year, which begins May 1, 2025. That would mean generators would have just a week after the revisions went into effect to make their determinations. But the ISO also said it and the New York State Reliability Council had not finalized the modeling changes needed to differentiate firm versus non-firm fuel in its resource adequacy models, nor were they likely to be finished by Aug. 1.

Though they supported the new rules, the Independent Power Producers of New York and the Ravenswood Generating Station asked FERC to delay implementation until next year. NYISO did not oppose the request.

“The problem was that without firm or non-firm definitions on Aug. 1, our capacity suppliers would have to elect” as firm resources, said Richard Bratton, director of market policy and regulatory affairs for IPPNY. “We should be in a good place by next spring in terms of what firm and non-firm mean, so that our generators can understand whether it’s economical for them to elect firm or non-firm for the following capability year.”

Other changes include accounting for a generator’s ability to store on-site fuel and for the temperature of generators’ cooling water. The revisions also eliminate the category of “capacity-limited resource,” defined as a generator that is able to take extraordinary measures to increase its output above its normal upper operating limit. NYISO deemed this no longer necessary based on the other provisions in the proposal.

FERC agreed that the revisions would help NYISO more accurately align resources’ stated capacity with their actual output capability and therefore better reflect their ability to meet the ISO’s capacity requirements. The commission directed NYISO to submit a compliance filing within 30 days reflecting the delayed implementation date of the fuel supply rule. Commissioners Lindsay See and Judy Chang did not participate.

NYISO anticipates its system will flip to winter peaking in the 2030s. Some zones are already winter peaking, according to its 2024 Gold Book.

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Robb Reviews Challenges of Changing Grid at WIRES

NERC CEO Jim Robb told grid stakeholders July 25 that the rapid pace of change in the electric grid has left the ERO dealing with “frontier issues” that challenge its traditional ways of operating. 

“I always like to start off, when I talk with folks, that we are in a pretty amazing period of time for the electric grid because of the pace of change that we’re seeing, and the fact that it’s coming at the grid [from] a number of different directions at the same time,” Robb said in his keynote address to the WIRES 2024 Summer Meeting in Boston.  

“So we’re having to rethink a lot of things; we’re having to kind of, I don’t want to say invent new physics, but we’re having to understand physics in ways that we haven’t had to before, and that’s made our mission quite challenging.” 

In his talk, Robb said one of NERC’s roles in recent years is “to help catalyze a conversation around the reliability of the system, and how that plays against … all the environmentally policy-driven changes that we’ve seen to the sector.”  

He described energy policy as a balancing act between “three competing dimensions,” comprising access and affordability of energy, energy reliability and security, and the sector’s environmental footprint and sustainability.  

“Where the industry gets in … trouble is when we overweight one of those dimensions and [don’t] pay attention to the implications for the other two,” Robb said. “Because they all work at cross purposes, right? We could build a really cheap electric system, but it probably wouldn’t be reliable and it probably would have an environmental impact we don’t like. We could build a 100% reliable system, but we probably wouldn’t be able to afford it and we may not like its environmental impact.” 

Robb warned that with the large amount of renewable generation coming onto the grid, natural gas is becoming an increasingly essential source of reliable, dispatchable generation. With that reliance, the traditional construct of gas and electricity as “two parallel systems that happened to grow up together” no longer works. He said regulators “need to take a fresh look at the gas system as it relates to electricity, recognizing that gas has a number of other very important things it needs to be able to do, but we need to fix that interface and make that work for the benefit of customers.” 

ITCS Progress

During the Q&A period, WIRES Executive Director Larry Gasteiger asked Robb about the Interregional Transfer Capability Study that NERC has been working on since Congress ordered it last year in the Fiscal Responsibility Act. 

Last month, NERC published an overview of its work on the ITCS so far. It plans to release the report in three tranches, with the U.S.-relevant publications to be concluded by November of this year and a further report on Canadian transfer capacity in the first quarter of 2025. (See NERC Promises 1st ITCS Results by August.) 

Robb acknowledged that the “little homework assignment from Congress” has become “an even bigger beast than we thought it was when we started.” He said NERC spent nearly a year creating the framework for the study and identifying the tools and models for carrying it out. 

One of the challenges Robb identified was that the FRA required NERC to base the ITCS on the transmission planning regions identified in FERC Order 1000. This created problems because of the size of some of the regions; in MISO, for instance, “you obviously need to look at MISO North different than you look at MISO South,” he said. 

Although the first results from the ITCS will not be released until next month, Robb said some “early insights” from the study include that interregional transfer capacity differs greatly from summer to winter, and from one region to another. The interplay between weather, changing demand, and the physical assets on the grid have made the job “complicated to work our way through,” he added. 

“The challenge with interregional transfer assessments is that it really has a little bit to do with the wires, but it’s got a lot to do with the generating resources in the various planning areas and the loads, and the nature of the weather patterns that we’re dealing with,” Robb said. “So, we’re doing a lot of scenario analysis, using the big storms that we’ve seen as ways to pressure-test the system. We also have to kind of forecast where we think new generation will come in, what it will look like and how it would be impacted by those weather systems.”