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November 1, 2024

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FERC Denies Missouri River Complaint Against SPP

FERC has denied a complaint by Missouri River Energy Services (MERS) that SPP violated its tariff by failing to give the utility any firm transmission rights in every annual allocation since 2016, resulting in more than $25 million in overcharges.  

In its June 27 order, the commission said Missouri River did not meet its burden to prove that SPP’s implementation of the allocation process violated the tariff, filed rate doctrine or two FERC orders or that the allocation process is unjust and unreasonable (EL24-3). 

MRES, an SPP load-serving entity, filed a complaint with FERC under several sections of the Federal Power Act. It alleged SPP violated its tariff, filed rate doctrine and commission Orders 681 and 890 by not awarding any long-term congestion rights (LTCRs) to the utility. MRES also claimed the RTO’s lack of transparency into its LTCR allocations violated the Energy Policy Act of 2005 and Order 890. 

The utility asked FERC to order SPP to refund the overcharge and allocate LTCRs from the date of the complaint. 

The commission found MRES did not identify specific tariff language it believed the grid operator had violated and said SPP’s tariff does not support its argument that the utility is entitled to receive its nominated LTCR allocation. It said the RTO didn’t deviate from its filed rate because the tariff’s LTCR process does not require it to allocate nominated rights. 

FERC also said Order 681 gives flexibility to grid operators in how they design their long-term FTRs and allows them to limit the amount available to ensure feasibility. It noted LSEs would not necessarily be able to obtain all of the long-term FTRs they request. 

“As an initial matter, we note that the commission accepted SPP’s LTCR tariff process, including how it determines feasibility and the amount of LTCRs to allocate, as compliant with Order 681,” FERC wrote. “Thus, the commission has already determined that SPP’s tariff meets the requirements of Order 681.” 

The commission said MRES did not support its allegation that SPP violated Order 890’s transparency requirements by not supplying the utility with certain data and calculations used in the LTCR allocation process. Instead, FERC found that Order 890’s transparency requirements do not require SPP to provide MRES with either the shift factor data or SPP’s specific software implementation of the simultaneous feasibility test. 

FERC pointed out that there are several reasons the LTCR allocation process could result in MRES not being allocated the congestion rights.  

“Contrary to Missouri River’s contention, the fact that Missouri River was not allocated LTCRs is not in and of itself proof of an implementation error,” the commission said. 

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PJM MRC/MC Briefs: June 27, 2024

Markets and Reliability Committee

Stakeholders Endorse Revised Proposal to Align Energy, Gas Schedules

VALLEY FORGE, Pa. — PJM’s Markets and Reliability Committee last week endorsed a proposal to align the day-ahead energy market commitment cycle with the daily gas nomination deadlines in order to give gas generators more certainty on when they should procure fuel. (See “PJM Presents Electric Gas Coordination Proposal,” PJM MRC Briefs: May 22, 2024.)

The package would time three intraday commitment runs for gas generators, targeted to be commensurate with the three gas nomination deadlines under the North American Energy Standards Board. PJM would attempt to notify any generators picked up during those runs of their commitment before the corresponding NAESB deadline.

The committee initially rejected the proposal, which fell below the two-thirds threshold with 51% sector-weighted support, after stakeholders raised questions around language asking generators to notify PJM of whether they have or plan to procure the fuel necessary to meet their commitments.

After the proposal was rejected by the MRC, members suggested removing the notification provisions, and a second vote approved the package by acclamation.

Paul Sotkiewicz, president of E-Cubed Policy Associates, said the draft manual revisions did not reflect language in the proposal approved by the Electric Gas Coordination Senior Task Force (EGCSTF) stating that the notification process is voluntary, does not carry penalties and is not meant to be punitive if notification is not provided.

PJM’s Brian Fitzpatrick said the language was intended to appear in the manuals and would be added before a vote. He said the notification process was meant to give PJM dispatchers additional insight into the status of the gas fleet.

He also argued that regardless of PJM’s intent, the Independent Market Monitor had said it may view the notification as mandatory and that generators failing to provide their fuel status to PJM could face a referral to the FERC Office of Enforcement.

“We’re faced with this direct threat that it’s voluntary and if we don’t do it, we’re going to get a FERC referral,” Sotkiewicz said.

Monitor Joe Bowring said there had been no threats to market participants. He said that while it was his view at the EGCSTF that the notification should be mandatory, he recognized that the proposal would make it voluntary and stated the Monitor would enforce the rules as written and approved by stakeholders.

“The fact that stakeholders voted to remove any provisions about the notification that generators should provide to PJM about whether they have procured the gas to meet their commitments is surprising,” he said.

Bowring told RTO Insider that part of the misalignment between the electric and gas markets stems from the difference between the daily cycle the gas industry operates on, which starts at 10 a.m., and the midnight starting time for the daily electric market cycle. He argued that proposals drafted by the EGCSTF have sought to shift the risks created by that misalignment from gas generators to load.

While shifting market times to align with the gas cycle would resolve many of the issues, Bowring said generators could also reflect pipeline requirements in their parameters, which would mitigate their risk and provide PJM additional visibility on when resources can operate.

First Read on Expanded ‘Know Your Customer’ Rules

PJM presented a proposal to widen the scope of its “know your customer” (KYC) requirements to include a new “beneficial owners” definition, which would require due diligence checks on individuals who hold 10% of the voting power within a member entity.

The MRC is set to vote on the tariff revisions on July 24, with the Members Committee vote on Aug. 21.

Assistant General Counsel Eric Scherling said the proposal is intended to improve PJM’s understanding of which individuals contribute to the most risk profile of an entity and to align KYC definitions with corporate standards.

The beneficial owner definition is applicable to those who own, control or hold 10% or more voting power of an entity, either directly or together with family members. While the overall KYC design was based on the U.S. Treasury Department’s Financial Crimes Enforcement Network (FinCEN) rules, Scherling said PJM determined to use a lower 10% threshold for the beneficial owners definition.

The proposal also requires that PJM conduct background checks on beneficial owners, board of director members and principals of non-publicly traded members. Those entities would be responsible for providing a list of names for each of those categories and government-issued identifications, though the latter does not apply to boards unless requested by PJM.

For publicly traded entities, municipal power authorities and co-ops, only a list of principals, beneficial owners and board members would be required, though background checks could also be requested by PJM.

PJM Chief Risk Officer Carl Coscia said less information is requested for public entities because those data are already captured by Securities and Exchange Commission regulations, and the RTO’s aim is to have members validate that the information is timely and accurate.

Stakeholders questioned whether the proposed definitions could inadvertently capture shift supervisors or staff on real-time desks that have operational control over significant company assets but don’t necessarily make long-term strategic decisions.

Monitor, PJM Present Processes to Enable Multi-schedule Modeling

PJM and the Monitor presented two proposals to revise how the Market Clearing Engine (MCE) selects energy market offers to enable the implementation of multi-schedule modeling. (See “Stakeholders Discuss Path Forward on Multi-Schedule Modeling,” PJM MIC Briefs: June 5, 2024.)

Stakeholders considered both packages last year during a process to determine a methodology for winnowing generator schedules down to the most cost-effective offer forwarded to the MCE. Those discussions resulted in a PJM proposal using a formulaic approach being filed at FERC, which was rejected in March. (See “Stakeholders Endorse Multi-schedule Modeling Solution,” PJM MRC/MC Briefs: Dec. 20, 2023.)

The commission stated that PJM’s proposal would compromise market power mitigation by only considering the cost of market-based offers on the EcoMin parameter, even if that offer would be more expensive than a cost-based offer at higher outputs. The Monitor described the issue as the “crossing offer curves” scenario throughout the stakeholder process and in protests to the PJM proposal at FERC.

During the Market Implementation Committee meeting June 5, PJM’s Keyur Patel said the RTO planned to advance a proposal co-sponsored by it and GT Power Group, which received the second-highest degree of support during an October 2023 vote. The joint proposal retains PJM’s formulaic approach and seeks to address the crossing curves issue by selecting generators’ market-based offers only when they pass the three-pivotal-supplier (TPS) test under nonemergency conditions and select cost-based offers only when a resource fails the TPS test.

A joint proposal offered by the Monitor and GT would replace the formula with having market sellers choose the most economic cost-based offer to forward to the MCE.

Deputy Monitor Catherine Tyler said the formula in the PJM/GT proposal ignores market realities and retains some of the same problems that led FERC to reject the RTO’s original proposal. She argued that the formula would commit dual-fuel generators to operate on less economic fuels when the relative costs of fuels change during the operating day.

Bowring told RTO Insider that he considered a central flaw in PJM’s proposed formula to be that it only considers the highest-cost hours equal to the minimum run time and could therefore select the higher-cost fuel for the entire day rather than recognizing that, for example, gas was cheaper in the morning and oil was cheaper in the afternoon.

“That is not a logical, competitive or least-cost solution,” he said.

Bowring said that his goal is to try to reach a consensus before the next MRC meeting.

Responding to questions about why market sellers might prefer PJM’s formula over selecting from their own offers, GT’s Tom Hyzinski said some participants may prefer to have the RTO make that determination.

The “IMM wants the market participant to pick the schedule. PJM uses a formula to pick the schedule for the market participant. The market participant likely does not want to pick the schedule but would prefer PJM to pick the schedule. [The] IMM has not proposed an alternative formula that either PJM or the market participant can use to make the selection,” Hyzinski said.

Bowring said any market participant can use PJM’s formula, which has been provided in a spreadsheet, to make the choice.

“The generation owner ultimately and appropriately makes the decision about what fuel to burn. The Market Monitor’s proposal provides more flexibility to generation owners, including the option to use the PJM formula if they think that is preferable,” he said.

During the June 5 MIC meeting, Constellation Director of Wholesale Market Development Adrien Ford said her company was concerned about the precedent of PJM reviving past packages after a stakeholder-endorsed proposal was rejected by the commission. She said she may seek to waive the truncated voting rules to allow both proposals to be voted on alongside each other. She added that action would not presuppose Constellation’s position on the two proposals; rather, her concern was retaining options for stakeholders under the unusual situation.

Ford told RTO Insider on July 1 that the company plans to move the PJM/GT package at the MRC’s next meeting.

Consumer Advocates Seek Wider Scope for Deactivation Task Force

The Maryland Office of People’s Counsel and Illinois Citizens Utility Board proposed revisions to the issue charge framing the work of the Deactivation Enhancement Senior Task Force (DESTF) to includes several areas of concern around the future of resource retirements in PJM.

Phil Sussler, of the Maryland OPC, said there are stakeholder processes focused on allowing new generation to clear the interconnection queue faster, proactive transmission planning, responding to localized load growth and thermal generation retirements promoted by economics and government policies, but none of those deliberations are occurring in a coordinated manner.

Clara Summers, of the Illinois CUB, said the advocates’ proposal is not meant to slow any of those discussions, but rather to rework the scope of the DESTF to allow it to take on a wider slate of issues.

“Our effort is really meant to supplement, not supplant, that existing work,” she said.

Several consumer advocates have argued that PJM’s existing stakeholder processes around resource retirements have been scattershot and siloed into subcommittees in a way that prevents holistic solutions.

The expanded key work activities and scope section of the issue charge would include:

    • education on transmission technologies that can resolve transmission violations prompted by deactivations, including grid-enhancing technologies and energy storage;
    • education of the alternatives other RTOs have to reliability-must-run contracts that pay generators to continue operating past their deactivation date;
    • updates and follow-up on any revisions to PJM’s process for transferring capacity interconnection rights, which are being drafted through the Planning Committee; and
    • drafting proposals to establish cost-effective alternatives to RMR agreements.

The out-of-scope section of the issue charge would also be widened to exclude proposals focused on expanding the justifications for entering RMR agreements with generators, particularly for resource adequacy purposes.

First Read on 2 PJM Proposals to Revise Reserve Markets

PJM presented two proposals to enable the RTO to have the 30-minute reserve requirement dynamically change to reflect system conditions without affecting other reserve procurement categories and how deployment signals are conveyed to market participants.

The MRC is slated to vote on the proposals during its July 24 meeting; if endorsed, they will advance to the MC on Aug. 21.

The changes to the reserve requirement definition would shift the 3,000-MW procurement target to a formula selecting the greater of the peak load forecast times the average forecast error and forced outage rate, the primary reserve requirement or the largest active gas contingency.

PJM’s Emily Barrett said the static requirement doesn’t account for the varying risks PJM experiences day to day, which can often lead the reserves that the RTO actually requires to exceed 3,000 MW.

The proposal would allow PJM to increase specific extended reserve requirements without having to scale up all three requirements and over-procure reserves. Barrett said the primary use case would be extending the 30-minute reserve requirement without also having to procure a correspondingly higher amount of synchronized and primary reserves.

Allowing the three to be increased individually would align operational decisions with the markets to reduce out-of-market commitments, PJM’s Kevin Hatch said.

The second package would send reserve deployment instructions through resources’ basepoints as the primary notification that they are being called on to provide reserves. PJM would continue using the existing automatic notifications and all-call signal; however, the basepoint instructions would be considered the starting point for resources’ commitments and the 10-minute window in which they are expected to ramp up.

Members Committee

Stakeholders Elect Sector Representatives to Nominating Committee

The MC elected representatives to the Nominating Committee for each of the five sectors. The committee identifies candidates to serve on the PJM Board of Managers and advances them to be voted on by the MC. The 2025 sector representatives are:

    • Rory Sweeney, of the Northern Virginia Electric Cooperative, represents the Electric Distributor sector;
    • Jordan Nader, of the North Carolina Utilities Commission, represents the End Use Customer sector;
    • Marji Philips, of Rolling Hills Generating, represents the Generation Owner sector;
    • Sean Chang, of Shell Energy North America, represents the Other Supplier sector; and
    • Denise Foster Cronin, of the East Kentucky Power Cooperative, represents the Transmission Owner sector.

In addition to the five sector representatives, three members of the board serve on the committee: two voting members and one non-voting member who serves as the committee chair. The board selected Jeanine Johnson to serve as chair in May, while David Mills and Charles Robinson serve as voting members.

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Phillips, Christie Debate Loper Bright’s Impact on FERC Order 1920

The Supreme Court’s decision in Loper Bright Enterprises v. Raimondo is already making waves in the rehearing process on FERC Order 1920, with commissioners releasing dueling statements about what the end of Chevron deference will mean for the transmission rule. (See related story, Supreme Court Ends Chevron Deference to Administrative Agencies.) 

Commissioner Mark Christie released a statement after the court’s ruling June 28 arguing that the commission should reform the order on rehearing given the lack of Chevron deference, while Chair Willie Phillips released a statement July 1 arguing that 1920 is on firm legal footing even with the doctrine’s end. Ultimately, the issue will come down to a different commission than the one that approved the order, as three new members will have joined. 

Phillips argued that FERC’s authority to regulate regional transmission planning and cost allocation has long been recognized by bipartisan majorities of the commission and the D.C. Circuit Court of Appeals. 

“It could hardly be otherwise,” Phillips said. “Both regional transmission planning and cost allocation are practices that have exactly the type of ‘direct effect’ on commission-jurisdictional rates that the U.S. Supreme Court has held brings a matter within this commission’s jurisdiction. Indeed, our authority to regulate regional transmission planning and cost allocation is essential to the commission’s ability to ensure that customers have access to reliable, affordable supplies of electricity — our most fundamental statutory responsibility.” 

Order 1920 builds on Order 1000, which was upheld by the D.C. Circuit in South Carolina Public Service Authority v. FERC using Chevron deference. The Supreme Court held in Loper Bright that settled precedents would not be disturbed by its decision, so Order 1000 is safe. 

“Order 1000 is the sort of the foundation for this Order 1920,” Christie told RTO Insider on July 1. “But the Chevron deference is not available, and so my point is that lifeline is now not available on court challenges to Order 1920. So … we’re going to have the opportunity to do substantial amendments to 1920 when we get to the rehearing stage, and I hope that we’ll be able to do that.” 

Phillips argued that Order 1920 fits easily into the South Carolina precedent in that it does not promote particular public policies, dictate specific outcomes or include any selection mandate, and its cost allocation proposals rest on well-established principles. 

“As such, Commissioner Christie’s assertions about Loper Bright’s implications for Order No. 1920 cannot be squared with the court’s actual holding in that case,” Phillips said. “As always, I respect Commissioner Christie’s regulatory perspective on how we should exercise the regulatory ‘discretion’ that Congress vested in this commission. But his disagreement with how the commission exercised that discretion in Order No. 1920 does not provide a logical or reasonable basis for calling into question whether we have that authority in the first place.” 

Christie argued that it was clear when Order 1920 was issued that it would not work, and that was made more clear by the many petitions to strike it down, many of which came from states and their organizations, such as the National Association of Regulatory Utility Commissioners.  

But they were also joined by PJM, the National Rural Electric Cooperative Association and more. Given Loper Bright, FERC should fix its issues before it winds up before the courts, Christie said. 

“The commission still has an opportunity to amend Order No. 1920 into a true compromise that will promote sensible long-term transmission planning while protecting consumers and respecting and elevating the important role of states throughout the process,” Christie said. 

Two major issues Christie would like to see changed are the requirement that regional plans take into account the supply preferences of large customers, which he argued would spread the costs of their choices to every customer impacted by the cost allocation, and Order 1920’s language around state input in cost allocation. 

While the order requires developers to give states six months to hash out an agreement on cost allocation, FERC did not require the relevant transmission providers to file it. That was based on yet another court case, Atlantic City v. FERC, which said transmission owners have the right to file their own rates. In their requests for rehearing, parties argued FERC could get around that. 

Christie also noted that the order stops short of requiring transmission providers, which include the ISO/RTOs, from even reporting on their efforts to get states to agree to a cost allocation method. 

“It says that even if the states in a region agree, the transmission provider does not even have to file it,” Christie said. “I absolutely object to that, because that totally goes against what was promised in the [proposed rule]: that state agreements would be recognized.” 

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NERC Promises 1st ITCS Results by August

NERC last week published an overview of its work on the Interregional Transfer Capability Study (ITCS), laying out the overall strategy and technical approach for the project and outlining the documents to be released beginning this August.

The Overview of Study Need and Approach reviews the work done on the ITCS since Congress ordered the study in last year’s Fiscal Responsibility Act. The law requires NERC to deliver to FERC by December a study on the total transfer capability between neighboring regions, additions to transfer capability that could strengthen grid reliability, and recommendations to meet and maintain total transfer capability.

Work on the ITCS began after FERC approved the ERO’s plan for funding the study last August. (See FERC Approves NERC Transfer Study Funding Request.) NERC is in overall control of the study through the ERO Executive Leadership Group, which is led by NERC Chief Engineer Mark Lauby, with participation from leadership of the regional entities. The ERO also formed the ITCS Advisory Group in the early days of the project to give industry stakeholders input into the project’s direction. (See SERC to be ‘Well Represented’ in ITCS Group.)

In the overview document, the ERO emphasized the “unprecedented” nature of the task assigned by Congress, calling the ITCS “the first comprehensive study of transfer capabilities between adjacent transmission planning regions [that] will use 12 years of data, capturing a wide variety of operating conditions and historical weather events … to determine potentially deficient areas.”

Congress required that NERC base the ITCS on transmission planning regions identified in FERC Order 1000. The project team has further subdivided these regions in some cases “to provide more granular analysis of transfer capability limitations, especially under specific weather scenarios.” NERC said this approach was necessary because some of the planning regions, particularly in SPP, covered large geographic areas with significant internal transfer constraints.

According to the overview document, the ITCS report will consist of three documents. Part 1, to be issued in August, will present a transfer capability analysis for 2024 and 2033, covering both summer and winter for each year. Total transfer capability will be calculated “by determining the amount of additional transfers that can be added to base transfers already modeled while respecting contingency limits,” and will comprise two parts:

    • Base transfer level, indicating “scheduled power flows between areas in the starting case.”
    • First contingency incremental transfer capability, which simulates the amount of extra power that can be transferred during an unexpected event.

NERC will use the transfer capability limits between each neighboring region as a “critical input into Part 2,” which will be published in November. The goal for Part 2 is to identify conditions in areas that might experience energy deficiencies, such as extreme weather scenarios; determining areas where deficiencies are severe enough to justify additions to interregional transfer capability; and “prioritizing interfaces for transfer capability increases.”

The ERO will limit its recommendations to target megawatt ranges of transfer capability and will not recommend any actual transmission projects to meet its targets.

Under Part 3, which will be published in the same document as Part 2, NERC will provide recommendations to meet and maintain transfer capability based on the results of the transfer capability and energy deficiency analyses in parts 1 and 2 respectively. These may include further studies to measure progress addressing risks and ensure that recommended additions can be maintained reliably, technology that may address transfer capability limitations, and enhancements to regulatory mechanisms, policies or standards.

Congress mandated that the ERO study transfer capabilities only within the U.S.; the documents submitted to FERC this year will focus on the U.S. However, NERC said in the overview that it already concluded the study “would be incomplete without a thorough understanding of the Canadian limits and available resources.” Transfer capabilities between Canadian provinces and from the U.S. to Canada therefore will be the subject of a fourth report, to be released in the first quarter of 2025.

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PJM Consumer Advocates File Complaint on EE Market Design

Three state consumer advocates filed a complaint against PJM with FERC last month, alleging the RTO’s treatment of energy efficiency resources is unduly discriminatory and is not properly documented in its governing documents (EL24-118).

The complaint contends PJM treats EE resources differently from any other class by removing EE that clears in the Base Residual Auction (BRA) from the supply stack and adding those megawatts on top of the load forecast, a process known as the “addback.” By not counting cleared EE toward meeting the reliability requirement and instead increasing the amount of overall capacity procured by the amount of EE, the advocates argued the RTO is robbing consumers of the ability to lower their capacity costs through EE programs. 

“This places unjustified upward pressure on prices, deprives the marketplace of the benefits of energy efficiency and foists unreasonable costs onto PJM consumers to pay for that energy efficiency out of the market,” the complaint said. It was jointly filed by the New Jersey Division of Rate Counsel, Maryland Office of People’s Counsel and Illinois Citizens Utility Board. 

The advocates requested that FERC hold a technical conference with PJM, stakeholders and member states to reconsider how EE participates in the market. 

The complaint also argued that a change as significant as the addback is not appropriate for PJM to make through its manuals and should have been filed as a tariff revision. Without FERC oversight of the change, the advocates argued there has been no ruling on whether it comports with past orders requiring EE participation in capacity markets. 

“The addback should have been filed with the commission for review because it profoundly alters how an entire class of resources participates in the Reliability Pricing Model and affects capacity clearing prices,” the advocates wrote. 

The advocates’ filing joins a complaint the Independent Market Monitor filed May 31 arguing that 10 EE providers had not demonstrated their resources met the BRA participation requirements and asked the commission to either bar those market participants from receiving BRA revenues for the 2024/25 delivery year or order PJM and the Monitor to open investigations to determine their eligibility (EL24-113). (See Monitor Alleges EE Resources Ineligible to Participate in PJM Capacity Market.)

The same day, PJM sent an email to EE market participants stating that it planned to delay approval of post-installation measurement and verification (PIMV) reports and defer capacity payments until the Monitor’s complaint is resolved. A second email said the PIMV reports continue to be under review, but the RTO did not plan to subject affected entities to capacity market deficiency charges and will continue payments to those companies, subject to refund depending on the outcome of the complaint. Replacement transactions will also be allowed for EE providers. 

“Any capacity payment associated with [EE] resources for the 2024/2025 delivery year is not evidence of the validity of the PIMV report or represent evidence that PJM has or will approve the provider’s PIMV report,” the email states. “Additionally, PJM is continuing to review the sufficiency of the PIMV report during the pendency of the Market Monitor’s complaint, and any rejection of the PIMV report will result in capacity resource deficiency charges for any shortfall determined. Finally, PJM may further initiate audits of M&V plans and PIMV reports submitted by energy efficiency providers for the 2024/2025 delivery year, which could result in billing adjustments based on the outcome of such additional review.” 

Four U.S. senators sent a letter to the commission in response to the Monitor’s complaint recommending a technical conference to consider the “proper role for energy efficiency in FERC-jurisdictional wholesale electric markets.” 

The letter, signed by Sens. Angus King (I-Maine), Martin Heinrich (D-N.M.), Sheldon Whitehouse (D-R.I.) and Chris Van Hollen (D-Md.), said EE has the potential to shrink capacity procurements, delay or avoid transmission upgrades, and reduce consumer bills. 

“FERC has, on several occasions, expressed support for energy efficiency participating in the wholesale markets. We are concerned, however, that in some regions, energy efficiency is not fully participating in wholesale markets, and other regions are considering rule changes that may negatively impact energy efficiency’s role in the future,” the senators wrote. “For instance, PJM recently announced that it was intending to suspend payments to energy efficiency providers until a complaint recently filed by the PJM Independent Market Monitor concerning energy efficiency is resolved. The status quo is becoming untenable.” 

While many EE providers have spoken out against the Monitor’s complaint and PJM’s actions on PIMV reports throughout the stakeholder process, some expressed support to RTO Insider for the consumer advocates’ complaint on the grounds that removing the addback could allow EE to demonstrate its potential as a competitive resource. Those individuals requested anonymity to discuss the pending complaints the Monitor has filed against their companies. 

In a protest to the Monitor’s complaint, attorneys representing Affirmed Energy said FERC’s Office of Enforcement has opened an investigation into the company based on a referral by the Monitor and makes identical claims to the Monitor’s complaint. It asked the commission to consider the overlap between the two in how it proceeds. 

“The reality here is that both the IMM and the Office of Enforcement are seeking now to enforce their own policy preferences for rules that do not exist. Our position, in both the complaint case and the investigation, is that Affirmed Energy fully followed the market rules,” the company argued. “The IMM claims the conduct of Affirmed Energy and other sellers violates the tariff; the Office of Enforcement makes the same claim about Affirmed Energy. They are both wrong.”  

The company said PJM has approved EE programs offered by Affirmed for the past 10 years, and the complaint follows stakeholders rejecting proposed changes to the EE market participation rules. (See “Stakeholders Reject Changes to EE Measurement, Verification,” PJM MRC/MC Briefs: March 20, 2024.) 

It argued that the complaint and investigation both delve into “fundamental policy questions” that should instead be considered through a public proceeding such as a technical conference. 

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MISO Warns Members of Rising Budgets

EAGAN, Minn. — MISO said its cost of doing business is set to escalate within the next four years, spawning bigger operating budgets and heftier member dues.

According to its own estimates, MISO said its base operating expenses could range from $412 million to $447 million by 2028, reflecting a 5.4 to 7.2% compound annual growth.

By 2028, the tariff rate MISO charges to its members could be 56 cents to 68 cents/MWh. Currently, MISO’s tariff rate is 47 cents/MWh. The RTO assumed a flat load profile of 717 TWh to make its estimate.

MISO also said project investments and other operating expenses combined could add more than $100 million to its annual budgets over four years. CFO Melissa Brown said salaries, benefits and computer maintenance comprise nearly 80% of MISO’s cost structure today and are expected to rise. She said the RTO going forward will have little opportunity to reduce costs to make up for heightened expenses.

“The labor market for MISO remains tight. A lot of our staff is getting poached, especially our experienced staff,” Brown said during the Advisory Committee’s meeting June 26. “It’s a challenge.”

The RTO’s 2024 base operating budget stands at $357 million, though it estimates it likely will end the year $5 million underbudget because of a higher-than-expected employee vacancy rate and stiff competition for staff.

Brown said MISO is recruiting new college graduates, even with the understanding those employees may leave within three to five years.

Members asked whether the RTO is using longevity bonuses for its employees.

“Right now, on the benefits side, there is nothing we’re not considering,” Brown said with a laugh. She confirmed MISO offers retention bonuses.

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MISO Leadership Issues Urgent Call for In-Service Dates

EAGAN, Minn. — MISO’s system is at the mercy of faster interconnections of new resources and retirement delays, executives said in a quarterly address to the board and stakeholders.  

MISO CEO John Bear said he wants to get to the bottom of why resources can’t be built sooner. MISO is sitting on a stockpile of about 50 GW across 316 projects that have been approved to connect to the system but are experiencing holdups in construction. According to MISO, the projects experience an average of 650 days to commercial operation.  

Bear said the mostly intermittent generation in the queue isn’t a full substitute for the baseload generation that continues to fall off its system. 

“You’ve got a mismatch of reliability attributes coming on the system,” Bear said during a June 27 board meeting. “We’ve got a lot of work to do to slow down the retirements and speed up the additions coming onto the system.”  

Senior Vice President and Chief Customer Officer Todd Hillman likened the “enormity” of MISO’s transition to a Rubik’s cube where members twist cubes to get one side monochromatic and then realize other sides remain multicolored. He said he expects hitches as utilities work out how to solve the puzzle.  

Hillman said members want to achieve decarbonization while paying attention to reliability and affordability. But he also said MISO expects anywhere from 12 GW to 14 GW of load growth in coming years from data centers alone.  

“That would be like adding 11 million homes. And these have much higher capacity factors than homes. That’s just a gigantic addition to a grid that’s already stressed,” Hillman said. He added that “poor visibility into the magnitude and timing of large load additions is putting at risk our ability to reliably accommodate them.” 

MISO said announced load additions in the footprint from manufacturing projects and data centers total more than 8 GW. Broken down, the projects account for 3 GW apiece in MISO’s South and Central regions and 2.4 GW in the North region. All projects aim to be online by 2030.  

Stakeholder Services Executive Director Suzie Jaworowski said MISO maintains and updates a list of announced load additions so members can decide how to prepare.  

Last month, MISO and the Organization of MISO States said if members don’t delay retirements or bring more resources online than typically occur historically, a potential 2.7-GW deficit next year could balloon to 14 GW in 2029. (See OMS-MISO RA Survey: Potential 14-GW Capacity Deficit by Summer 2029.)  

Bear said MISO should delve into probabilistic load forecasting. He said it’s clear its deterministic load forecasting based on historical experiences won’t keep MISO best prepared.  

Despite striking more than 20 GW in generator interconnection agreements last year, MISO experiences an average of just 5 GW per year of nameplate capacity coming online. In a separate meeting, Vice President of System Planning Aubrey Johnson also said longstanding construction lags persist and MISO and developers need to find ways to accelerate in-service dates.  

“The number of gigawatts coming online is insufficient for what we’re seeing coming,” he said during a June 25 meeting of System Planning Committee of the MISO Board of Directors. 

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Extensions Likely for MISO’s Term-limited Board Members

EAGAN, Minn. — MISO and its board are scrutinizing the steps they can take to preserve institutional knowledge on the board of directors as they confront half of the board members reaching term limits this year or next.  

Three MISO board members’ terms are ending at the end of this year; two of them are restricted by MISO’s three-term limit. Board members Phyllis Currie and Mark Johnson have been fixtures on the board since 2016 and are prevented from seeking additional terms. MISO Director Nancy Lange is up for re-election for her third and final three-year term.  

Beyond that, directors Todd Raba, H.B. “Trip” Doggett and Barbara Krumsiek will conclude their third and final terms at the end of 2025. 

However, MISO has said it’s open to retaining board members using waivers, which allow a director to stand for election to one more three-year term beyond the three-term limit. (See “Waivers May be Necessary to Retain Directors Past Term Limits,” MISO Board of Directors Briefs: March 23, 2023.) 

MISO last used a waiver for board members in 2017, when members retained Baljit “Bal” Dail for an additional three-year term to keep his IT expertise on the board. Dail served 12 years on the board. (See MISO Board of Director Briefs: Dec. 10, 2020.) 

At a June 26 Advisory Committee meeting, Alliant Energy’s Mitch Myhre, who sits on MISO’s Nominating Committee, said MISO is evaluating how it can be “proactive” about maintaining experience on the board by securing seasoned candidates and making sure terms overlap.  

Myhre said the Nominating Committee’s work to search for suitable replacements and to pursue waivers will begin in earnest this month.  

Wisconsin Public Service Commissioner Marcus Hawkins said he was worried about the potential for the board to experience a “knowledge cliff” anyway if MISO chooses to exhaust all possible term-limit extensions for term-limited members. He joked that he saw something similar occur within his homeowners’ association.  

MISO’s Nominating Committee is charged with vetting and selecting MISO Board of Director candidates, who are put to a vote of membership. The committee’s members change yearly, and the committee is composed of three board members and two stakeholders, one of whom typically is from a state public service commission. This year, directors Bob Lurie, Jeff Lemmer and Theresa Wise sit on the Nominating Committee. All three were elected at the end of 2023.  

Lurie said the committee this year is taking a “multiyear view of the search,” with MISO having so many important reliability initiatives ongoing simultaneously and the impending exodus of board members.   

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Galt Power Fined $1.5M Following Anti-Manipulation Investigation

FERC has approved a $1.5 million civil penalty on Galt Power following an investigation finding manipulation violations in the creation of renewable energy credits (RECs) (IN20-5). 

The commission’s Office of Enforcement determined that Galt, a wholesale power marketing company, conducted prohibited “wash” trades — transactions designed to cancel each other out, carrying no financial risk — to generate RECs in Massachusetts.  

“Galt repeatedly prearranged its two schedules between ISO-NE and NYISO for the same volumes during the same time intervals, a hallmark of wash trades,” the Office of Enforcement found.  

The office determined that Galt generated RECs by sending power from two New York wind farms from NYISO to ISO-NE, while scheduling imports to NYISO from ISO-NE that would kick in when the prior transactions were projected to lose money.  

“Galt willingly lost money on the NYISO-to-ISO-NE transactions to obtain Class I RECs but did not absorb those losses or flow the power on net. Instead, it scheduled the ISO-NE-to-NYISO transaction to mitigate or eliminate any losses,” the office found.  

The office also found that Galt made false statements concealing the wash trades to APX, the operator of the NEPOOL Generation Information System.  

“We do not want to let them know about hedge transactions,” read one internal email from an APX employee. 

Following the office’s findings, Galt has agreed to pay a $1.5 million fine to the U.S. Treasury, along with about $372,000 to the state of Massachusetts for disgorgement and interest. The company also will be required to submit two annual compliance reports.  

According to the agreement, Galt “neither admits nor denies the alleged violations.” 

FERC accepted the agreement June 28, finding it “is a fair and equitable resolution of the matters concerned and is in the public interest.” 

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ERCOT, IMM Share Details on Ancillary Services Study

ERCOT staff have made a pair of preliminary recommendations as part of their collaboration on an ancillary services study that is due to Texas regulators before the end of the year. 

Jeff Billo, ERCOT director of operations planning, told the Stakeholder Advisory Council on June 24 that staff have been “thinking through this stuff” and running the analyses. ERCOT is working with the Independent Market Monitor and Public Utility Commission staff on the study. 

Jeff Billo, ERCOT | © RTO Insider LLC 

“We really think that we have the right services and the right methodology for quantifying those services today,” Billo said. Unsurprisingly, he said ERCOT plans to use the current mechanisms and is not proposing any changes to those products. 

Billo said the first preliminary recommendation covers the frequency control portion of ancillary services: regulation, responsive reserve service and the frequency-response portion of ERCOT Contingency Reserve Service (ECRS). Staff’s other recommendation is to examine the benefits of determining some portion of AS quantities closer to the operating day based on daysahead forecast conditions rather than an annual calculation. 

Some ERCOT stakeholders and the IMM have objected to the heavy use of ECRS since its first use last year, saying it has added billions of dollars in costs to the energy-only market. The grid operator procures capacity resources that can be brought online within 10 minutes and sustained at a specified level for two consecutive hours. (See “Contentious NPRR Revising ECRS Passes over Monitor’s Objections,” ERCOT Board of Directors Briefs: June 17-18, 2024.) 

Billo reminded TAC of where ERCOT was in 2021, when he told the committee that staff were going to a conservative operations approach, setting aside larger amounts of operating reserves than before.

“[I said we] were going to not walk up right to the edge of the cliff, but we were going to take a few steps back, and we were going to operate with higher reserve margins in real time,” he said. “The idea there is that we’re operating with a lower risk compared to how we historically operated, and that has also driven a change in the amount of ancillary services that we’re getting.” 

ECRS and other products have become necessary with the increased addition of renewable resources and the resulting growth in load variability, Billo said. He said ECRS was needed to address increasing net load ramps causing greater intra-hour risk and fewer online reserves available to recover frequency after a large unit trips. 

“We see the greater exposure when we have forecast misses and so that’s why you’ll see, during especially those ramp times, that we’re getting higher amounts of ECRs to cover that kind of higher exposure,” Billo said. 

Also playing a role in the increased use of AS was the public’s anxiety over ERCOT’s ability to meet demand following the disastrous and deadly 2021 winter storm that nearly brought down the Texas grid. 

“I think that prior to Winter Storm Uri, there were lots of times where we had watches or we went into [energy emergency alerts] and the public didn’t really notice and didn’t really care,” Billo theorized. “Post-Uri, I think as we saw in 2021, there were times where we would go into a watch and that there’d be a lot of attention on that from the public, but also from state leadership. I think the message that we got … was, ‘ERCOT, we don’t want you to go into a watch and an EEA as much as you have in the past.’ 

“In my mind, that is a criteria change for how we operate the system and the amount of reserves we’re procuring,” he added. 

The IMM’s deputy director, Andrew Reimers, told TAC the IMM’s study is intended to estimate the reliability value of different levels of reserves to inform AS procurement targets. He said the Monitor is focusing on reserves that are responsive within minutes to hours.  

The IMM is using 10,000 random draws of a Monte Carlo simulation for each hour in the study period to determine how reserve levels influence loss-of-load projections, given probabilistic distributions of unplanned outages and net load forecast errors. Its staff are using historic hours from June 2023 to June 2024 to compare the capacity at risk to different reserve levels. 

“The timeline is definitely a challenge,” Reimers said. “We’re trying to triage this to do the best study that we can given the relatively limited amount of time we have to go on. Ultimately, that means prioritizing what we can getting the results that we can and then figuring out what things have to be left for future work.” 

“We’ve had a lot of really good conversations with the IMM. I don’t know if by this September that we’ll agree on all of the details, but conceptually, I think we agree on the framework,” Billo said. “Some of the things we still need to think through are around data. It’d be great if we used 10 years of data, but the forecasts have improved. I’m trying to quantify what my risk is of a forecast error; I really don’t want to use forecast data from 10 years ago.” 

Billo asked for stakeholder input before he presents a study update to the Board of Directors during its Aug. 19-20 meetings. An AS workshop will be held after the Aug. 28 TAC meeting and a final report posted to the commission before October. 

The PUC also plans an AS workshop in the latter half of October. It’s asking for TAC feedback on which ERCOT and IMM information presented Aug. 28 would be most helpful in filing comments at the commission (55845).  

The study is a requirement of legislation passed last year by Texas lawmakers. It directs the PUC to review the type, volume and cost of AS and determine whether those services are necessary in the ERCOT market. The law also requires the commission to evaluate whether additional services are needed for reliability. 

Separately, ERCOT staff will begin discussions with stakeholders in July on the grid operator’s 2025 AS methodology. (Billo said ERCOT won’t have time to incorporate learning from the PUC study’s results.) 

Staff plan to present its proposal during the October board meeting, allowing for PUC review before next year. ERCOT’s annual requirement to update its AS methodology now includes commission approval. 

Members Endorse 7 Changes

TAC approved a protocol change (NPRR1190) that would recover demonstrable financial loss arising from a manual high dispatch limit (HDL) override to reduce real power output, should the output be used to meet qualified scheduling entity load obligations. 

The change’s approval came after an attempt to table NPRR1190 until further IMM review came up short. The measure passed 22-6 with an abstention. 

The consumer segment provided all six opposing votes over concerns that the change incorrectly expands the opportunity for entities to receive compensation for scheduled-but-not-provided energy under out-of-market ERCOT actions. Supporters noted the infrequent occurrence of the conditions covered by the NPRR and the language that prevents recovery of lost opportunity costs stemming from an HDL override, according to the committee’s report. 

The motion to table failed 8-19 with a pair of abstentions. The consumer segment favored tabling. 

Members also endorsed three other NPRRs, an Other Binding Document revision (OBDRR) and single changes to the Planning Guide (PGRR106) and the Verifiable Cost Manual (VCMRR) that, if approved by the Board of Directors, would: 

    • NPRR1215: clarify that the day-ahead market’s energy-only offer credit exposure calculation zeros out negative values, with any zeroed-out values being included in the calculation of the percentile difference. 
    • NPRR1216, OBDR051 and VCMRR039: align the protocols with the PUC’s order establishing an emergency pricing program for the wholesale market. During an emergency offer cap (ECAP) effective period, the systemwide offer cap is set to the ECAP, with a value equal to the low systemwide offer cap. 
    • NPRR1225: update the protocols to align with the PUC’s declaratory order on ERCOT’s settlement systems. The grid operator added revisions to meet the commission’s order that exclusions be effective March 4, 2024, when the transfer of Lubbock Power and Light retail customers to retail electric providers began. 
    • PGRR106: clarify which transmission projects are included in the Transmission Project Information and Tracking report.