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November 19, 2024

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PJM MIC Briefs: June 5, 2024

Additional Parameters for Demand Response Endorsed

VALLEY FORGE, Pa. — PJM’s Market Implementation Committee endorsed by acclamation a proposal to add two energy market parameters for economic demand response. (See “First Read on Proposed Demand Response Energy Market Parameters,” PJM MIC Briefs: May 1, 2024.) 

The changes would allow DR providers to set a cap on how long they can be dispatched and a minimum interval before they can be committed again after being released from a previous dispatch. 

FERC last July approved a PJM proposal to tighten performance assessment interval triggers, allowing pre-emergency demand response to be deployed without prompting a full capacity call for all resources. (See FERC Approves PJM Change to Emergency Triggers.)  

PJM’s Pete Langbein offered an amendment to the proposed Manual 11 revisions to state that energy market parameters cannot supersede a load management deployment in the capacity market, a stipulation he argued already is reflected in the status quo language. 

Langbein gave the example of a DR resource that had been released from an energy market commitment and was in the middle of a minimum release time when it was called on for capacity. If that resource did not respond and followed its energy market parameter, it could be subject to Capacity Performance (CP) penalties and testing requirements. 

PJM plans to ask the Markets and Reliability Committee for endorsement at its Aug. 21 meeting, followed by the Members Committee on Sept. 25 and a FERC filing in October. The filing likely would ask for a sixth-month implementation period. 

PJM to Refile Portions of Rejected CIFP Proposal

PJM laid out its plan to refile several components of its Critical Issue Fast Path (CIFP) proposal rejected by FERC in February, which focused on the CP construct and market seller offer caps (MSOC). (See FERC Rejects Changes to PJM Capacity Performance Penalties.)  

PJM’s Walter Graf said the components selected for refiling were those that order rejecting the order either indicated support or did not touch on. For items where PJM received minimal feedback from the commission, Graf said PJM’s future filing is likely to be fairly similar. 

The proposal includes “clarifying revisions” to the definition of Capacity Performance quantified risk (CPQR), MSOC values for planned generation based on net cost of new entry (CONE), segmented offer caps, and a forward-looking energy and ancillary service (EAS) offset for offer caps and the minimum offer price rule (MOPR). 

The proposal would allow generators that intend to participate in the energy market regardless of whether they clear in the capacity market to offer into Base Residual Auctions (BRAs) at least as high as their capacity performance quantified risk (CPQR) value. 

In its October 2023 transmittal letter, PJM said allowing generators likely to remain in operation regardless of their position in the capacity market would avoid over-mitigating market sellers with a low or negative avoidable cost rate (ACR). The filing argued that the status quo market seller offer cap (MSOC) prevents some market sellers from fully representing their costs to deliver capacity — a dynamic it said could be leading some resources not subject to the must-offer requirement to avoid participating in the capacity market entirely. 

PJM does not plan for the refiling to include many of the core changes addressed in its original filing, such as limiting bonus payments for generators that overperformed during emergency conditions to only committed capacity resources, excusing generators whose price-based offers exceeded their cost-based offers from CP penalties and third-party review of unit-specific MSOC proposals. 

PJM is not including a process for calculating alternative offer caps if it determines that a market seller’s proposed MSOC did not conform to the tariff as it awaits a FERC ruling on its rehearing request. The refiling also will exclude an element of PJM’s original proposal to remove the physical penalty option for fixed resource requirement entities. The PJM Power Providers (P3) and Electric Power Supply Associated (EPSA) have jointly requested rehearing on that element of FERC’s rejection of ER24-98. 

PJM is not seeking to move forward with a standardized CPQR calculation because the specificity the commission sought would be difficult to uniformly produce across resource classes, Graf said. But he added that the calculation PJM proposed to use could be used by market sellers to aid in their own CPQR proposals. 

Exelon’s Alex Stern said he’s glad PJM is reviewing the commission’s rejection order because the resource adequacy concerns which prompted the filing have only grown over the past year. 

Energy Efficiency Proposals Deferred While Complaint Pending

PJM, its Market Monitor and Affirmed Energy all delayed presenting proposals to revise how the RTO measures and verifies (M&V) energy efficiency resources due to a complaint the Monitor filed last week asking FERC to deny capacity market payments to 10 EE providers. (See PJM Monitor Alleges EE Resources Ineligible to Participate in PJM Capacity Market.) 

Aaron Breidenbaugh, of CPower, said he understood that the EE providers named in the complaint have been counseled to avoid discussing issues raised in the filing until the issue has been resolved. Because the filing argues that mid- and upstream EE programs have not met the Reliability Pricing Model (RPM) participation requirements, he said the complaint overlaps with the very issue before the MIC. 

Affirmed Energy’s Luke Fishback said the company withdrew its package from the June 5 agenda because it would be unproductive to engage with discussions about potential revisions to M&V requirements while the complaint about existing standards is pending. 

Exelon’s Alex Stern said the pending complaint can’t help but “put a chilling effect on not only these stakeholder discussions but also EE generally.” 

PJM Associate Counsel Chen Lu said he thinks the complaint is limited to the validity of post-installation measurement and verification (PIMV) reports filed for the 2024/25 delivery year and therefore would not clash with discussion about future M&V design. 

Marji Philips, of LS Power, rebuked PJM for a communication sent to EE market participants on May 31, which said the RTO will be delaying action on PIMV reports until the complaint has been resolved, effectively holding up all EE revenues in the process. She said the complaint is an allegation that must be substantiated before PJM can take action through a deficiency process in accordance with a FERC order. 

“It’s completely violative of any FERC procedure,” she said. ” … You don’t take an action based on a filed complaint.” 

Responding to questions about the implications of the PIMV delay for EE providers, Lu said no payments are made and prospective market participants are not subject to deficiency charges until PJM has makes a determination on the reports. If the reports were rejected, he said, entities would be considered unavailable during the delivery year and subject to deficiency charges. 

Langbein said PJM is reviewing the May 31 communication and plans to send out an update on how it intends to proceed with the PIMV reports and EE payments. 

PJM Presents Revised CONE Values

The Brattle Group presented revised financial parameters used to calculate net CONE for the 2026/27 Base Residual Auction (BRA).  

Net CONE is one of the inputs used for defining prices on the Variable Resource Requirement (VRR) curve. (See “Update Re-evaluation of CONE Inputs,” PJM MIC Briefs: May 1, 2024.) 

PJM in April proposed reviewing the financial inputs to net CONE to account for shifting market conditions since the 2022 Quadrennial Review. Increasing interest rates were among the major contributors, PJM’s Skyler Marzewski said. The change is being pursued through the quick fix process, which allows an issue charge to be brought and voted on concurrent with a proposed solution. 

“We’re trying to make sure net CONE would be better aligned with the financial conditions that we’re currently seeing,” Marzewski said. 

Brattle recommended increasing the after-tax weighted-average cost of capital (ATWACC) from the 8.85% used in the quadrennial review to 10%, which increases the cost to construct a combined cycle resource — currently the reference resource — by $15 to $18/kW-year. The cost of combustion turbines increased by $10 to $12/kW-year and battery electric storage systems by $18 to $20/kW-year. 

Given market volatility, Brattle’s Bin Zhou recommended adjusting the financial parameters for at least the next few auction cycles. 

Responding to stakeholder questions about how the review was conducted, Brattle’s Sam Newell said it relied on the same study approach as the quadrennial review. 

Marzewski said Brattle also is considering whether PJM needs to reconsider the overall cost for a new resource, with preliminary analysis suggesting there’s no need at this time. Newell encouraged market participants to reach out to Brattle with any specific market information to assist its reevaluation of financial parameters or cost indexing. Increased turbine prices could be one such data point, he said. 

Stakeholders Discuss Path Forward on Multi-Schedule Modeling

PJM intends to move forward with an alternative solution for selecting schedules in the market clearing engine (MCE) to facilitate its multi-schedule modeling design, which is expected to significantly increase computing times under the status quo schedule selection approach. (See “Stakeholders Endorse Multi-schedule Modeling Solution,” PJM MRC/MC Briefs: Dec. 20, 2023.) 

FERC in March rejected the multi-schedule modeling proposal endorsed by stakeholders in December 2023. That package would have introduced a formula to evaluate generators’ offers and select one expected to produce the lowest total dispatch cost and forward only that offer to the MCE.  

The commission rejected that proposal, citing the “crossing offer curves” scenario the Monitor raised, under which PJM’s proposed formula would select market-based offer based on its dispatch cost at EcoMin even if it would be notably more expensive than a cost-based offer at higher outputs. 

“PJM’s proposal would largely eliminate market power mitigation in the day-ahead Energy Market by selecting for consideration in PJM’s market clearing optimization software a single offer per resource solely on the lowest dispatch cost at EcoMin … it would no longer mitigate a seller’s offer to the offer producing the lowest total production cost by considering the entire offer curve for each of a seller’s offers,” the commission wrote. 

PJM’s Keyur Patel said the RTO planned to advance the MIC proposal co-sponsored by PJM and the GT Power Group, which received the second-highest degree of support during an October 2023 vote. That proposal attempts to address the crossing curves issue by selecting market-based offers only when a resource passes the three pivotal suppliers (TPS) test under non-emergency conditions and select cost-based offers only when a resource fails the TPS test. 

Several stakeholders took issue with presenting a proposal that was voted on months in the past as the presumptive motion to advance at the MRC. It was suggested a proposal sponsored by the Monitor during last year’s deliberations should be considered at the MRC as well and the truncated voting rules waived to allow the two to be voted on side-by-side. 

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PJM OC Briefs: June 6, 2024

PJM Presents Black Start Manual Revisions

PJM presented the Operating Committee last week with a set of revisions to Manual 12 regarding fuel assurance requirements for black start resources.  

The RTO said the language approved June 6 was included in the package the OC advanced two years ago but inadvertently was excluded from manual revisions approved by the Markets and Reliability Committee in November 2022. (See “Black Start Fuel Requirements Advance to Members Committee,” PJM MRC Briefs: Oct. 24, 2022.) 

The effort established a new category of “fuel-assured” generators and required at least one such unit to be committed in each transmission zone. The criteria to qualify as a fuel-assured unit vary based on resource type, including connections to multiple interstate gas pipelines, on-site fuel storage and dual-fuel capability. 

The latest manual revisions create an exception to allow fuel-assured black start resources to avoid penalties if they fall below mandated consumable storage levels because they responded to a performance assessment interval (PAI) or if the storage vessels were taken out of service for regulatory inspections. 

The changes also remove a fuel assurance notification requirement from Manual 12 and replace it with a stipulation that generators must provide verification they have adequate fuel and consumables upon PJM request, along with an annual verification requirement in the black start test form.  

The language is set to go before the OC for an endorsement vote July 11 and the MRC on July 24. 

PJM Details Temporary Exception Submission Process

PJM’s Lauren Strella Wahba presented the process for market participants to submit temporary exceptions in Markets Gateway once software updates go live Aug. 1.  

The “Daily” and “Real Time Temp Except” fields have been used as an interim solution since FERC approved PJM’s real-time temporary exception design last November. (See “Stakeholders Endorse Real-time Temporary Exception Manual Revisions,” PJM MIC Briefs: Feb. 7, 2024.) 

Rather than submitting supporting documentation to PJM by email, the “Exception” page of Markets Gateway will have buttons for uploading documents, though the email option will remain as a fallback. 

Market participants withdrawing an active temporary exception will be required to first restore their cost-based and price parameter-limited schedules. 

PJM Reviews May Operating Metrics

Inaccurate weather forecasting caused several days of high load forecast error in May, PJM’s Marcus Smith told the OC. Conditions were warmer than expected between May 16 and 21, which follows a trend of load forecasts becoming highly sensitive to numerous variables when temperatures are around 70 degrees Fahrenheit. 

The May average hourly forecast error was 1.51%, with an average peak error of 1.81%, falling near the 25-month average for both figures. 

PJM presented the daily peak forecast error for May 2024 to the Operating Committee. | PJM

The month saw one shared reserve event, a high system voltage action, a geomagnetic disturbance (GMD) action and 20 post-contingency local load relief warnings (PCLLRWs). 

PJM’s Kevin Hatch said the GMD action was in effect May 10 and 11 after two transformers were in violation for 10 minutes. Geomagnetically induced current (GIC) was seen on multiple transformers, and two reactive control devices tripped offline.  

While increased geomagnetic activity was seen for a week after May 10, Hatch said the action was not needed for the entirety of the period and the grid experienced no major impacts. 

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NV Energy IRP Describes $1.76B Cost Jump for Greenlink Projects

Rising costs of materials and labor and an increased use of H-frame structures as an environmental mitigation have contributed to a $1.755 billion increase in the projected cost of NV Energy’s Greenlink transmission projects. 

The costs for Greenlink North and Greenlink West, estimated at $2.484 billion in 2020, grew to $4.239 billion as of May 2024 — a 70.6% increase. 

NV Energy disclosed the figures in its 2025/27 integrated resource plan, filed with the Public Utilities Commission of Nevada on May 31. 

Of the $1.755 billion cost increase for the Greenlink projects, NV Energy attributed $340 million to the rising costs of materials, equipment and labor. 

“Inflation has played a major role,” Shahzad Lateef, NV Energy’s senior project director for transmission development, said in the filing. 

The Bureau of Land Management is requiring NV Energy to use an additional 160 miles of H-frame structures to mitigate risk to desert tortoise and sage grouse habitat, an extra cost of $124 million. Shorter span lengths and more expensive materials contribute to a 42% higher cost for H-frame structures compared to the guyed-V lattice structures that were previously planned, according to the filing. 

Other environmental mitigations will add about $30 million to Greenlink costs. 

Costs have also gone up $252 million because of changes in project scope, NV Energy said, and new estimates have added $101 million in sales and use taxes that previously weren’t included. 

‘Vital’ to Renewables

Greenlink West will be a 525-kV line along the west side of Nevada from Las Vegas to the Fort Churchill substation near Yerington. In Northern Nevada, Greenlink North will connect the Robinson Summit substation near Ely to Fort Churchill via a 525-kV line. 

The Greenlink lines, combined with the existing One Nevada line, will form a transmission triangle around the state.  

“The Greenlink projects are vital to the robust development of renewable resources throughout Nevada as well as low-cost reliability for the growing load,” Ryan Atkins, NV Energy’s vice president of resource optimization and resource planning, said in the filing. “The Greenlink project remains the best alternative to meet [NV Energy’s] future transmission needs despite the cost increases.” 

Breaking down the costs by project, cost estimates for Greenlink West have increased from $1.22 billion in 2020 to $1.907 billion. Greenlink North costs have gone from $854 million to $1.490 billion. 

And the costs for “common ties” in the project — including a substation expansion at Fort Churchill and 345-kV connecting lines to nearby areas — have grown from $410 million to $841 million. 

John Tsoukalis, a principal with The Brattle Group, also provided testimony regarding the Greenlink projects as part of NV Energy’s IRP filing. 

Tsoukalis said the Greenlink projects would increase the resilience of the NV Energy system, particularly in the case of an outage of the One Nevada Line. 

Greenlink also could increase interconnections with nearby entities, potentially enhancing the benefits of NV Energy’s participation in the Western Resource Adequacy Program (WRAP), Tsoukalis said. 

Tsoukalis estimated the Greenlink projects would reduce costs to NV Energy customers by $50.8 million per year. Customer benefits would increase by about $57.3 million a year, as operating costs and purchased power costs declined and off-system sales revenues grew by $38 million a year, he projected. 

Those gains would be offset slightly by reductions in short-term wheeling revenues, market congestion revenues and bilateral trading profits. 

The next steps in the BLM permitting process for Greenlink West will be publication of the final environmental impact statement, expected this month, followed by a record of decision in August and a notice to proceed in December. 

For Greenlink North, BLM is expected to release a draft environmental impact statement in July. 

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Paper Examines How to Properly Value DER Grid Contributions

A new paper examines how the electricity sector can properly value distributed energy resources so they can be deployed efficiently as non-wires alternatives to reduce grid operating costs and delay system upgrades. 

Published in the latest issue of Electric Power Systems Research, “Valuing distributed energy resources for non-wires alternatives” was written by Nicholas Laws, Michael Webber and Dongmei Chen of the University of Texas’ Walker Department of Mechanical Engineering. 

With electricity demand growing because of electrification, population growth and other factors, distribution utilities need to increase overall capacity and upgrade equipment to maintain reliability. 

“However, those traditional actions related to the wires and poles of the distribution system might not keep pace with load growth that will accommodate rapid electric vehicle adoption or widespread installation of electric heat pumps as a way to reduce on-site fuel use for space and water heating,” the paper said. “As a consequence, there is an acute need for non-wires alternatives that can be used to improve overall system performance. Some of those alternatives include demand response and distributed energy resources, such as local power generation and/or storage.” 

DERs can help meet growing demand at a lower cost than gold-plating the grid, but traditional utility funding models and market signals are not adapted to deploying them properly. 

The trick is making it so that DERs and the distribution system both benefit from the investment. DERs can be built to serve a customer’s need without any thought to their impact on the grid, but getting the price signals right can ensure they are available to address overloaded and other problem areas on the system. 

“Valuing DER for non-wires alternatives appropriately is a difficult task,” the paper said. “The framework proposed in this work accounts for both the system planner’s perspective and the DER investor perspectives.” 

The paper advocates for a “bilevel optimization framework” to minimize system planning costs while ensuring that DER developers get their required rate of returns. 

Under FERC Order 2222, which requires all jurisdictional RTOs/ISOs to allow DER aggregations to participate in wholesale markets, system planners will have to work with DER investors to plan efficient distribution power systems. 

The paper ran a study of the optimization it proposed on a 20-year lifecycle for some upgrades: including four power lines and three transformers.  

Without any DERs or battery storage, it found upgrades would total $8.41 million, which fell to $6.43 million with the utility investing in batteries. While the batteries save money over time, they effectively doubled the upfront costs of the utility. 

But paying DERs to do the same avoids the higher capital expenditure from the utility up front and cuts costs over 20 years to just $5.42 million. DERs cut back required grid upgrades to just one line and one transformer — instead of four lines and three transformers — while the batteries still required three lines upgraded and two transformers. 

The right price signals can help DERs offset their costs through energy sales, which also lower systemwide power costs, the paper said.  

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ERCOT TAC Endorses Rule for Inverter-based Resources

ERCOT stakeholders and staff came to an agreement last week on a rule change that imposes ride-through voltage requirements on inverter-based resources, a result of more than a year’s worth of back-and-forth redlined comments and negotiations.

During a special June 7 conference call, the Technical Advisory Committee endorsed a change to the Nodal Operating Guide (NOGRR245) that aligns ERCOT’s rules with NERC reliability guidelines and the most relevant parts of the Institute of Electrical and Electronics Engineers’ standard for IBRs interconnecting with the grid.

ERCOT’s Board of Directors remanded the NOGRR back to TAC in April, directing the language — approved by the committee over staff’s objections — be modified to address staff’s reliability concerns. (See ERCOT Board of Directors Briefs: April 22-23, 2024.)

A pair of IBR-related voltage disturbances in West Texas in 2021 and 2022, dubbed the Odessa Disturbances, only added urgency to the measure’s eventual passage. (See NERC Repeats IBR Warnings After Second Odessa Event.)

TAC has held a workshop and two conference calls devoted to NOGRR245 since April.

Staff said the revisions in their latest comments, submitted June 5, addressed their concerns and reflected TAC discussions offering compromise on generation interconnection agreements, requiring all IBRs maximize up to the equipment’s full capability. Staff said they will support an exemption process allowing them to assess reliability risk and costs during a review and a one-time exemption process with no after-the-fact exemptions for performance failures or later discovery.

However, staff said they would not support a “subjective commercially reasonable” standard and would only support considering cost during the exemption process if the solution is “clear, objective, quantifiable and repeatable regardless of technology, unique commercial characteristics or plant age.”

(“Commercially reasonable” is defined as terms “conducted in good faith and in accordance with commonly accepted commercial practice.”)

TAC accepted the comments but added gray-box language with potential modifications that would enable entities to meet the applicable ride-through requirements when they have not yet added a “technically feasible” change. The modifications are for those entities where the upgrade costs are less than 40% of the full, in-kind replacement cost of a plant’s inverters or turbines and converters.

Members accepted a friendly amendment to extend the gray-box language’s effective date from August to March 2025.

Speaking for the ad hoc “joint commenters” stakeholder group, Eric Goff said the group’s latest comments represent a “serious and good faith commitment” to making the upgrades. He said their comments have been updated to allow for immediate implementation of the standards and to decouple software and more expensive hardware ride-through considerations.

“We think that this maximization procedure meets ERCOT’s goals. … I think we have the same intention and desires or very similar intentions and desires,” Goff said.

TAC endorsed the NOGRR in an 18-1 vote, with 10 abstentions. Demand Control 2, a member of the retail segment, cast the lone opposing vote. The municipal, retail and power marketing segments accounted for nine of the abstentions.

Demand Control 2 CEO Chris Hendrix told RTO Insider that the joint commenters’ proposal was not posted until the night before the conference call and didn’t allow enough time for full consideration. He also said ERCOT’s 40% threshold for replacement costs was arbitrary, “extremely” high, and didn’t consider the life of generating units or existing contracts.

“Either the threshold should be a lot lower or some aspect of commercial reasonableness added,” he said.

Hendrix motioned to table the change. However, he was unable to secure a second.

TAC members did not celebrate the NOGRR’s passage, although American Electric Power’s Richard Ross did promise to award Luminant’s Ned Bonskowski with one of his Gold Star awards for staying up until 2 a.m. June 7 to compare the ERCOT and joint commenters’ proposals.

“I’ve never received a higher honor in my professional career,” Bonskowski said.

“Don’t forget to put that on your performance review,” Ross replied.

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State Regulators Discuss Affordability, Utility Incentives at NEECE

MYSTIC, Conn. — Top utility commissioners from four New England states emphasized the need for regulatory innovation to preserve affordability amid the clean energy transition at the New England Energy Conference and Exposition (NEECE) on June 5. 

“Inequity is probably the most significant concern when it comes to the clean energy buildout,” said Ed McNamara, chair of the Vermont Public Utility Commission. 

As transmission and distribution costs associated with enabling electrification accelerate, protecting low-income customers will become increasingly important, McNamara said. 

“The customers with low incomes are not the ones buying [electric vehicles] or installing heat pumps,” he said. “They’re not benefiting from more stable heating and transportation prices due to electrification, but they’re still paying the cost to upgrade the distribution grid.” 

Marissa Gillett, chair of Connecticut’s Public Utilities Regulatory Authority, said regulators’ primary job is to interpret legislative directives and find “the most cost-effective way to implement the policy goals that are being articulated.” 

“I’ve been a huge proponent of utility regulators taking more of a driver’s seat position,” Gillett said. She stressed the importance of including communities that historically have not been involved in utility proceedings. “The more perspectives we have at the table the more robust our decision-making will be.” 

Gillett said one of the major challenges for regulators in the clean energy transition is the “information asymmetry that all utility regulators — and frankly stakeholders — have to grapple with.” 

“I don’t think there’s any malintent to it; it’s just a simple reality of utilities having information, and utility regulators really having to learn how to ask the right questions and be prepared with new and creative ways to interpret data,” Gillett said. 

Gillett has overseen the PURA’s implementation the legislature’s mandate for a new performance-based regulation framework and has aggressively pursued increased utility accountability. The state’s utilities have been outspoken in their criticism of the new direction, complaining in public and behind the scenes about the state’s regulatory climate and arguing it is harming their ability to raise capital. 

Several other regulators also spoke about the need to reconsider utility incentive structures amid the clean energy transition.

“We definitely need to move [toward] stronger performance incentives that are really driving outcomes,” said Philip Bartlett, chair of the Maine Public Utilities Commission. “The key is to make sure [utility investments] are going to the places that are going to get us the biggest bang for our buck.” 

Jamie Van Nostrand, chair of the Massachusetts Department of Public Utilities, said regulators should be looking at “incentive mechanisms to align [the utilities’] interests with our interests in pursuing clean energy goals and maintaining affordability.” 

Van Nostrand specifically emphasized the need to support the deployment of virtual power plants and demand-side efforts to reduce the overall need for distribution infrastructure. 

Regarding transmission, Van Nostrand said there have been “huge technological breakthroughs over the last decade or so, whether it’s advanced reconductoring or grid-enhancing technologies, that could really potentially increase the capability of our transmission grid to carry more load.” 

“But we also know there’s a capex bias,” Van Nostrand said. “Utilities tend to want to build more stuff because they get to put it into the rate base and get a return on it. It’s our job as regulators to make sure … that utilities are considering this new technology than can potentially reduce costs.” 

Bartlett, who chairs a New England Conference of Public Utilities Commissioners working group on retail demand response, said well-designed time-of-use rates and DR programs can provide “a real opportunity” for cost-constrained customers to lower their electric bills. 

Effectively reducing demand also could “dramatically reduce the buildout of the grid” and provide cheaper solutions to preserving grid reliability during the most stressful hours of the year, he added. 

“If you can save hundreds of millions of dollars in new programs and fixes to keep things reliable, that’s huge,” Bartlett said. 

The event was the 30th annual NEECE, which is organized by the Connecticut Power and Energy Society and Northeast Energy and Commerce Association. 

Massachusetts Legislative Update

Massachusetts Rep. Jeffrey Roy, co-chair of the state legislature’s Joint Committee on Telecommunications, Utilities and Energy (TUE), gave an update on clean energy legislation currently under consideration. 

The legislature’s previous two sessions have produced significant climate bills, but lawmakers are running out of time to pass a bill by the end of the current session, which will conclude at the end of July. (See Mass. Lawmakers Aiming for an Omnibus Climate Bill in 2024.) 

While lawmakers are considering a range of proposals related to EV charging, power purchase agreements, advanced metering infrastructure, building decarbonization and retail electricity choice, the top clean energy priority for many in state government appears to be permitting and siting reform. 

“There is nothing more important to our clean energy goals than siting and permitting reform,” Roy said. He called the current siting process in Massachusetts “slow, complicated and intricate.” 

Mary Beth Gentleman, former assistant secretary at the Massachusetts Executive Office of Energy Resources and a member of the state’s Commission on Energy Infrastructure Siting and Permitting, said the state should be permitting “at least six times the amount of clean energy infrastructure as we are currently permitting.” 

Gentleman said transmission and distribution projects typically take seven years from application to the end of the appeals process. 

“At that rate there is little chance that we will be able to comply with the state carbon mandates,” Gentleman said. “Problem No. 1 is there are too many state and local permits, and all of them can be appealed.” Consolidating all required permits into a single process could simultaneously speed up the review and make it easier for the public to participate, she said. 

Roy said he is discussing permitting reform with his TUE co-chair, Sen. Michael Barrett, and the Healey administration to “craft a bill we can all agree on.” 

“I’m confident that we’re going to get a piece of legislation done by July 31,” he said. 

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MTEP 24 up to $5.8B; Clean Energy Group Asks for Alternative to Pricey Entergy Reliability Project

The cost of MISO’s 2024 Transmission Expansion Plan (MTEP 24) increased slightly to $5.8 billion, RTO planners said at a midyear checkpoint of the annual transmission planning cycle.

The preliminary MTEP 24 clocks in at 471 projects, stakeholders learned during a series of subregional planning meetings June 3-7. An earlier estimate pinned the MTEP 24 package at $5.5 billion. MISO has said this year’s MTEP marks a return to normal levels of investment following last year’s record-breaking $9 billion package. (See Early MTEP 24 Designates $5.5B in Transmission Spending.) 

MTEP 24 includes $688 million in generator interconnection projects and $952 million in baseline reliability projects. Everything else is designated by MISO as “other” and includes projects to address age and condition of facilities, accommodate load growth or meet transmission owners’ self-imposed reliability criteria.  

During a June 6 East Subregional Planning teleconference, MISO’s Amanda Schiro said the bulk of MTEP 24’s other project proposals are motivated by load growth and the age and condition of infrastructure.  

Schiro said MISO will continue to test projects for alternatives through the summer and share a preview and draft report of MTEP in September. She told stakeholders MISO is no longer accepting ideas for alternative projects.  

Return of Hartburg-Sabine Junction?

Again this year, MISO South contains a big-ticket baseline reliability project that has a clean energy group requesting an analysis of alternatives. 

Entergy Texas proposed a new 35-mile, 500-kV line and substation in East Texas at $409 million. The utility said the line would help prevent potential thermal overloading of “many” 230-kV lines that supply the Port Arthur area. MISO said Texas accounts for 42% of MISO South costs for MTEP 24 because of the large project.  

Last year, Entergy Louisiana proposed nearly $2 billion alone in a baseline reliability project to alleviate its Amite South load pocket; MISO ended up recommending an alternate solution to portions of the project.  

The Southern Renewable Energy Association (SREA) has asked that MISO explore resurrecting its $134 million, 500-kV Hartburg-Sabine Junction project in East Texas in place of Entergy Texas’ reliability project.  

MISO canceled the development of the market efficiency project in 2022 after Texas enacted a right-of-first-refusal law that delayed construction and Entergy built gas-fired plants in the area that made the line less beneficial. Attempts by transmission developers and clean energy groups to save the project have thus far failed. (See FERC Rejects Last-ditch Effort to Save Tx Project.) 

SREA said that because Hartburg-Sabine was proposed to connect to some of the same infrastructure as the new reliability project, it may be able to pull double duty to alleviate reliability problems in East Texas while providing economic value. However, SREA doesn’t know if the market efficiency project can solve the same contingencies.  

At the South Subregional Planning meeting June 7, MISO South Expansion Planning Manager Trevor Armstrong said MISO will study the potential for Hartburg-Sabine and present results of its analysis in September.

Entergy Texas did not respond to RTO Insider’s request for comment on whether it thinks Hartburg-Sabine might be a suitable substitution.  

Additionally, Entergy Texas last week announced it is seeking permission with the Public Utility Commission of Texas to spend more than $2.2 billion to build two new gas-fired power plants near Entergy’s line proposal — one in Port Arthur and another about 45 miles north of Houston. The utility said both plants would feature hydrogen-capable combustion turbines and one could be equipped for carbon capture.  

Entergy said it needs the plants online in 2028 to accommodate “extraordinary economic and population growth.

SREA Transmission Director Andy Kowalczyk said the association believes Entergy Texas must pursue the new plants because it hasn’t addressed its load pockets with meaningful transmission.   

“Our general stance is that we believe these sorts of procurements will continue to happen until Entergy addresses the load pockets with increased import capability that provides access to more capacity and market options,” he said in a statement to RTO Insider. 

He said Entergy had identified the the East Texas, West of the Atchafalaya, Amite South and Downstream of Gypsy load pockets as issues as far back as 2005. He said that while other Entergy companies focused on Amite South and Downstream of Gypsy with transmission projects in MTEP last year, the focus on alleviating load pockets doesn’t appear to have extended to Entergy Texas.

How MISO can plan for load growth has become a point of focus for some stakeholders.  

At the Planning Advisory Committee’s meeting May 29, MISO’s Environmental sector requested that the RTO modify its annual transmission expansion planning and generator interconnection study procedures “to accommodate new, large lumpy loads like data centers and manufacturing.”  

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SPP Files to Incorporate Western Entities into RTO

SPP reached a major milestone June 4 in its efforts to expand into the Western Interconnection when it filed bylaw amendments at FERC to place seven Western entities under its tariff (ER24-2184). 

The revisions would make the RTO the first grid operator with markets in both major interconnections. 

SPP said its expansion would create economic and reliability benefits for all its member companies through access to a larger generation fleet, greater geographic diversity and increased efficiencies in SPP’s energy markets. 

The efficiencies would come by using a single market “optimized solution” across the DC ties that connect the Western and Eastern Interconnections. SPP said that would increase resilience by “leveraging” diverse resources through 510 MW of bidirectional capability, bringing price convergence across the ties. 

“Years of collaboration among SPP staff, existing RTO members and Western entities has resulted in a revised tariff that meets the unique needs of all the entities we serve, and I couldn’t be more thrilled,” SPP CEO Barbara Sugg said in a statement. 

The grid operator said its newest members can expect to see more than $200 million in annual benefits. It said the Integrated Marketplace saved Eastern Interconnection members $3.6 billion last year. 

SPP’s RTO West is scheduled to go live in April 2026. 

The bylaw amendments were approved during the May 7 meeting of the Board of Directors and Members Committee. The board also approved a package of 16 tariff revisions that include establishing a Western balancing authority area and managing transactions across the DC ties. 

Settlements would be based on transmission service reservations during the market’s first four years. After that, they would be based on transmission congestion rights. (See “Bylaw Changes for RTO West,” SPP Board of Directors/MC Briefs: May 7, 2024.) 

SPP has been working quietly with parties interested in evaluating the benefits and requirements of RTO membership since October 2020. Initial RTO expansion terms and conditions were approved in July 2021, and the DC tie terms and conditions in July 2022. 

The entities pursuing RTO membership are: 

    • Basin Electric Power Cooperative; 
    • Colorado Springs Utilities; 
    • Deseret Power Electric Cooperative; 
    • Municipal Energy Agency of Nebraska; 
    • Platte River Power Authority; 
    • Tri-State Generation and Transmission Association; and 
    • the Western Area Power Administration’s Colorado River Storage Project Management Center, Rocky Mountain and Upper Great Plains regions. 
  • The expansion would add Arizona, Colorado and Utah to SPP’s current 14-state footprint and increase the size of its service territory in Wyoming. SPP’s Regional State Committee, composed of regulators from the RTO’s states, would add four new seats to accommodate the new members. 

Representatives from the seven entities would serve on the Members Committee and SPP’s key stakeholder group, the Markets and Operations Policy Committee. Also, several Western-specific working groups would be formed to focus on issues affecting the new members. 

Tri-State CEO Duane Highley, who led SPP member Arkansas Electric Cooperative Corp., said his organization is “enthusiastically” looking forward to participating in RTO West as it looks to advance its energy transition. 

“The full benefits of the RTO, including a day-ahead market, an ancillary services market, efficient regional transmission planning, common transmission tariff and participatory governance model, help us to further reduce costs for our cooperative members across the West,” he said. 

“The RTO offers unprecedented access to regional transmission and generation resources that will help us reach our emission-reduction goals, add more renewable energy, manage customer costs and ensure the reliability of our electric grid,” Colorado Springs CEO Travas Deal said. 

JTIQ

MOPC on June 7 approved a tariff revision request that establishes a cost-allocation framework for projects in the Joint Targeted Interconnection Queue (JTIQ) with MISO. 

The change (RR620) addresses chronic transmission issues along the seam with MISO related to generator interconnection requests and implements cost-allocation policies already approved by SPP’s state regulators. It also memorializes and defines how the JTIQ process will be implemented and applied once executed. 

SPP and MISO have been working since 2020 to identify projects along their seam that can help unlock new generation and resolve congestion issues in the absence of interregional projects. They have agreed on a direct billing approach that assigns 90% of the JTIQ portfolio’s $1.06 billion in costs for its five projects to generation. Load will cover the remaining 10%. (See MISO, SPP Propose 90-10 Cost Split for JTIQ Projects.) 

“The revision request determines how we’ll treat costs, security requirements and congestion-hedging mechanisms,” SPP’s Aaron Shipley told MOPC members. “We feel the benefits help provide some longer-term solutions and a different way to think about chronic issues … hopefully bringing added capacity to that area and helping those issues.” 

The measure passed with 89% approval over opposition from renewable interests. While recognizing the need to facilitate more generation in areas that have been “struggling,” they said the framework risks the JTIQ’s success. 

“The reason we are where we are today is in part because of the failure of our interregional planning processes to produce anything meaningful,” the Advanced Power Alliance’s Steve Gaw said. “This is the first time that projects are even at a point where there could be some projects that come out of this. The only reason it’s moving forward is because the costs are being assigned to generators, and that should not be the way we look at how we do regional planning. We should be looking at how this potentially gets us to a point where we have [a] significant look at who’s benefiting and how those benefits flow.” 

The RSC (June 10), and the board and the MC (June 12), will take up RR620 in similar special meetings. SPP will coordinate the FERC filing with MISO, which also has several special meetings set up in June. The RTOs are targeting a filing by August. 

SPP will seek board approval of the JTIQ portfolio if FERC accepts the tariff revisions and updates to its joint operating agreement with MISO. 

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FERC Sets Dynegy’s MISO Market Manipulation Case for Hearing

Nearly a decade after the MISO capacity auction in which Dynegy was found to have manipulated clearing prices, FERC has directed hearing and settlement procedures in the case (EL15-70, et al.).

The commission’s June 6 order initiated a hearing to resolve the issue while denying Dynegy’s request for oral argument before FERC. The commission had been considering briefs from Dynegy and complainants Public Citizen and the Illinois Office of the Attorney General on whether Dynegy should refund $429 million to Illinois ratepayers.

Two years ago, FERC staff concluded that Dynegy knowingly manipulated the 2015/16 Planning Resource Auction to produce Southern Illinois’ Zone 4 clearing price of $150/MW-day. FERC’s arrival at that conclusion followed a twisty course, including an abruptly closed nonpublic investigation, an initial finding that cleared Dynegy with little explanation, a remand from the D.C. Circuit Court of Appeals and an announcement that the commission would revisit its decision. (See FERC Staff Finds Dynegy Manipulated 2015 MISO Capacity Auction.)

In its briefs, Dynegy maintained the process unfurled unjustly, saying FERC’s order on remand “reflects bad policy, is fundamentally unfair and is inconsistent with existing norms.” It said the commission improperly raised questions about the “finality” of its decision to close the investigation while “importing” nonpublic information gathered in an investigation under Federal Power Act Section 222 into a public proceeding under Section 206.

“According to Dynegy, this departure from policy, this departure from policy ‘threatens public confidence in the integrity of [FERC’s] enforcement process’ and ‘negatively affect[s] the perceived fairness of commission investigations,’” the commission said.

Dynegy also argued its due process was violated because the commission’s Office of Enforcement had to file a remand report outlining allegations in a Section 206 proceeding using evidence from its closed, nonpublic investigation. Because of the nonpublic nature of the investigation, Dynegy said it couldn’t participate in discovery or cross-examination.

It claimed the remand order exceeded FERC’s authority because, according to the commission itself, a Section 206 filing isn’t the “proper vehicle to prosecute claims of market manipulation.”

The Illinois AG and Public Citizen fired back that “Dynegy cannot now claim, at this late stage of the proceeding, and at the risk of further delay, that its procedural rights have been violated due to the absence of an evidentiary hearing that it never requested.”

FERC said its actions were “an appropriate response” to the D.C. Circuit’s findings, were consistent with its precedent and do not rise to violations of due process.

“We acknowledge that this case, and the issues that the commission must address on remand, present complicated questions regarding the interplay of the closed FPA Section 222 investigation and resolution of the still-pending FPA Section 206 complaints,” FERC said. It added that it takes seriously its decisions to disclose nonpublic information from its investigations and doesn’t foresee itself regularly releasing such information in the future.

“However, we continue to conclude that submission of the remand report and the opportunity for parties to submit initial and reply briefs was an appropriate response,” the commission said.

FERC also pointed out that it’s allowed to release nonpublic information from an investigation and that it’s common practice for it to initiate further briefings following a remand, “particularly where an appellate court rules that the commission failed to adequately explain its decision.”

Dynegy also argued that it wasn’t made aware via Enforcement staff that its behavior leading up to and during the 2015/16 auction could constitute market manipulation. It said it didn’t have a legal or regulatory requirement to sell capacity, nor was it “on notice” that FERC expected it to do so.

The commission didn’t buy the second argument from Dynegy and ruled the company had “adequate notice that its behavior could constitute market manipulation under relevant commission regulations and precedent.”

FERC pointed out that Enforcement staff said in their briefs that Dynegy took pains ahead of the auction to increase the chance an offer from it would set the clearing price in Zone 4. Staff said Dynegy “engaged in a scheme to amass and hoard megawatts that might otherwise have been offered into the 2015/16 auction at a zero price, thereby increasing the likelihood that a non-zero-priced Dynegy resource would be the marginal resource and set the Zone 4 clearing price.”

The division said evidence pointed to Dynegy expecting that the 2015/16 auction would clear below its lowest non-zero offer of $108/MW-day. Rather than submit all its supply at the cost-based $108 price, Dynegy engaged in pre-auction sales at approximately $66/MW-day until it offloaded enough supply to create a specific gap and therefore ensure its own resource would set the clearing price in the zone.

Staff said Dynegy then took steps to maintain the gap by increasing the price of the capacity component of its retail sales offers from $66/MW-day to $164/MW-day, resulting in 125.4 MW of unsold capacity, and refusing to offer a price to two customers for 385 MW of capacity.

“Dynegy also sought to increase the ‘gap’ by purchasing 50 MW of capacity for $61/MW-day — an act that made no economic sense given that it already held thousands of megawatts of unsold capacity,” Enforcement staff wrote.

The company claims its actions were “motivated by a legitimate intent to recover its costs,” not to commit fraud. It said after it lost money in the 2013/14 auction, it devised a strategy to recover its costs by offering capacity both prior to and in auctions. Dynegy said its attempts to receive price signals that could help it make decisions, including resource retirement, were “not only economically rational, but the only way for an independent power producer, reliant on market revenues, to stay in business.”

Vistra, which acquired Dynegy in 2018, said it disagrees with FERC setting the case for hearing. In an email to RTO Insider, Vistra insisted that the matter has “been investigated several times and adjudicated in Dynegy’s favor,” and it continues to believe “Dynegy’s actions were completely appropriate.”

“When FERC cleared Dynegy in 2019, they found that no market manipulation occurred and that the MISO 2015/2016 capacity auction results were just and reasonable. No new facts, circumstances or evidence have come to light in the five years since that decision,” Vistra said, adding that it will participate in the FERC-directed settlement discussions.

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FERC Allows Berkshire Utilities to Earn Market-based Rates in WRAP

FERC on June 7 approved tariff revisions by Berkshire Hathaway Energy subsidiaries PacifiCorp, Nevada Power and Sierra Pacific Power that will enable the utilities to earn market-based rates when participating in the Western Resource Adequacy Program (WRAP). 

As noted in the commission’s order (ER24-851), the Western Power Pool’s (WPP) WRAP does not intend to be a centralized market for capacity or energy, but rather a voluntary planning and compliance framework for resource adequacy that facilitates the ability of participants to meet capacity shortfalls through bilateral transactions. 

“As proposed, transactions in the [WRAP’s] Operations Program (notably the energy deployment and its associated total settlement price) would be market-based rate transactions conducted under existing authorities and frameworks on a bilateral basis between participants,” the commission wrote. 

The WPP’s initial plan was to avoid requiring WRAP participants to file individual market-based rate filings and instead rely on a structure of indexed-based prices to settle the bilateral transactions, contending the system would prevent the exercise of market power among participants. 

Despite that measure, FERC was concerned some participants still would be transacting in balancing authority areas (BAAs) in which they had been found to exercise market power, and that existing market-based rate requirements imposed on individual participants still would apply. 

“With regard to the price index component of WRAP’s structure, the commission found that the Western Power Pool’s proposal was ‘not sufficient to demonstrate that a price index may be used by specific participants that lack market-based rate authority or are subject to market-based rate mitigation,’ as it failed to address whether the proposed index-based price was a just and reasonable rate for such participants,” FERC noted. 

But recognizing that existing restrictions on market-based rate authority (MBRA) could impede a participant’s ability to transact at WRAP tariff-specified rates, the commission said such a participant could submit a Federal Power Act Section 205 filing “to seek new market-based rate authorization with appropriate mitigation or propose to amend its current market-based rate tariff to include tailored mitigation for the commission to consider.” 

No Market Power

In their Section 205 filings, the utilities pointed out they lack MBRA in their own BAAs, as well as in some first-tier — or interconnected — BAAs. 

“They note, however, that the WRAP tariff obliges them to deliver physical power to a neighbor in need, which could be to a balancing authority area where their market-based rate authority is mitigated. They assert that complying with the WRAP tariff could cause them to exceed the authority in their market-based rate tariffs,” the commission wrote. 

The three utilities proposed to rely on the liquid hubs specified by the WRAP: Mid-C in Washington and Palo Verde in Arizona. The utilities contended they would not set the market price for any transactions in the WRAP and would be price takers, with all sales settled at the price index for each region. 

“Applicants argue that allowing them to amend their market-based rate tariffs to use index prices when selling to counter-parties under the WRAP tariff would be just and reasonable under Order No. 697, where the commission stated it would allow mitigated sellers to use an index or locational marginal price proxy ‘on a case-by-case basis based on their individual circumstances’ rather than defaulting to cost-based rates,” FERC wrote. 

The utilities also argued that Mid-C and Palo Verde meet the commission’s liquidity requirements for use in jurisdictional tariffs. 

“PacifiCorp states that it routinely makes sales at both the Mid-C and Palo Verde hubs and has engaged in sales of millions of megawatt-hours at both the Mid-C and Palo Verde hubs since 2019. Nevada Power and Sierra Pacific did not make any representations about their sales at either the Mid-C or Palo Verde hubs,” but they did note they trade more frequently at the Mead hub in Nevada, FERC said. 

PacifiCorp said it trades only lightly at Palo Verde and, while trading more heavily at Mid-C, it does not report its transactions at either hub to price indexers and therefore could not influence the WRAP settlement price at either hub. 

The commission clarified that its acceptance of the changes to the market-based rate tariffs for the utilities is limited to WRAP transactions and predicated on program provisions that restrict the potential for the exercise of market power. 

“As applicants note, under the WRAP design, when load-responsible entities choose to join WRAP, once committed under the Operations Program, they are obligated to comply with its requirements, including requirements to make non-discretionary sales, or face charges for noncompliance,” the commission wrote. As such, the applicants and other participants in WRAP will have no discretion as to: whether to make a sale; the quantity of any sale; or the price of any sale. For any such sale, the applicants will act as a price taker and, therefore, will not know the WRAP settlement price until after the markets close.” 

But the commission also required the utilities to include in their triennial market power updates to details about their “transactions at or near the Palo Verde and Mid-C hubs, relative to the total volume of transactions at the Palo Verde and Mid-C hubs, respectively, to allow the commission to evaluate the applicants’ sales contribution to index formation.”