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November 26, 2024

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PJM MRC/MC Briefs: Nov. 21, 2024

Markets and Reliability Committee

Stakeholders Endorse CIR Transfer Proposal

VALLEY FORGE, Pa. — The PJM Markets and Reliability Committee on Nov. 21 endorsed a proposal to create an expedited process to study interconnection requests that would reuse the capacity interconnection rights (CIRs) of a deactivating resource. 

The tariff revisions, proposed by East Kentucky Power Cooperative and Elevate Renewable Energy, were approved with 77% sector-weighted support and added to the Members Committee’s consent agenda, which also passed during the committee’s meeting later that day. (See “CIR Transfer Proposal Discussed,” PJM MRC Briefs: Oct. 30, 2024.) 

Under the proposal, PJM would study replacement resource requests in parallel with projects sorted into the standard interconnection queue with the aim of offering developers an interconnection agreement on an eight- to 10-month timeline. To minimize impacts on queue timelines, CIR transfers would be studied using the most recent phase 2 or 3 grid model developed for queue clusters. 

The process could be initiated within one year of a formal deactivation notice being received. The replacement resource would be required to interconnect at the same substation and voltage as the original resource, though it could be physically located elsewhere so long as it ties in at the same point. The maximum facility output and CIRs would have to be equal to or lesser than the deactivating generator. 

Paul Sotkiewicz, president of E-Cubed Policy Associates, said the proposal would allow developers to take advantage of transformers and other infrastructure already in place to avoid supply chain issues causing delays to construction across the U.S. 

“This is something that helps avoid some of the supply chain issues to get resources on quicker,” he said. 

Greg Poulos, executive director of the Consumer Advocates of the PJM States, said his members were divided on the motion, with some supporting it as an improvement that would speed development. Others are concerned that interconnection would remain too slow, in part because of the ability for generation owners to wait a year before transferring CIRs, and preferred a design the Independent Market Monitor offered during deliberations at the Planning Committee. If the MRC had not endorsed the proposal, Poulos said some advocates intended to move the Monitor’s proposal as an alternative. 

The Monitor’s package would have prohibited bilateral exchange of CIRs and instead created a PJM-administered process to shift headroom from retiring resources to any project in the queue or proposed by a developer that could resolve transmission violations associated with that deactivation. 

A third proposal sponsored by PJM at the PC was closer to the endorsed proposal — allowing CIRs to be traded after a deactivation — but would have imposed tighter eligibility limits, including outright barring storage, and required that any replacement resources that prompted network upgrades or would consume available headroom be removed from the expedited process and directed to submit an application to be studied under the wider queue. 

The language endorsed by the MRC and MC would allow projects with network upgrades to proceed so long as they cover associated costs. Developers also would be permitted to reduce the scope of a project to avoid network upgrades before proceeding. 

The EKPC-Elevate proposal received 51.8% support at the PC during the Oct. 8 vote, while PJM’s design received 40.6% and the Monitor’s received 11.1%.

Monitor Joe Bowring said he does not believe the expedited process would be an improvement, and PJM would continue to face challenges attracting new entry. He suggested it should expand its Reliability Resource Initiative to be retained as a long-term tool to speed interconnections when reliability issues are identified. The initiative — an in-development, interim accelerated interconnection process — would open 50 slots for high capacity factor projects to be added to Transition Cycle 2, allowing them to be studied in advance of projects that have yet to receive a queue position. 

He argued that a private, bilateral CIR trading process would introduce delays and create market power for holders of existing CIRs. Owners of deactivating assets would be able to pick the highest bidder for the replacement resource, rather than PJM being able to select the projects that would have the highest impact. Intermittent and storage replacement resources also would not be required to offer into the capacity market, meaning they may not provide the reliability benefit PJM is seeking through the process.

Third Phase of Hybrid Resource Rules Endorsed

Stakeholders endorsed by acclamation a proposal to implement the third phase of PJM’s hybrid resource rules, expanding the model to include non-inverter-based generation paired with storage.  

The language is slated to be voted on by the MC on Dec. 18. (See “1st Read on 3rd Phase of Hybrid Resource Rules,” PJM MRC Briefs: Oct. 30, 2024.) 

Participation in the energy and ancillary service markets would be along the lines of the Energy Storage Resource Participation Model detailed in Manual 11; capacity accreditation would focus on the storage element of the resource while taking into account the availability of the generation component. 

Hybrids with any component subject to the requirement that resources offer into the capacity market also would be subject to the must-offer rule. Hybrids with no component subject to the rule, such as intermittent generation or storage, would not be mandated to participate in the market. 

PJM’s Maria Belenky said a friendly amendment was offered following the first read in November to align the binding notice of intent requirement for hybrids with other resource classifications. She said stakeholders pointed out that a different timeline would exist for hybrids than all other planned resources under the original tariff language drafted. 

First Read on Quick Fix for Revising Load Drop Estimate Inputs

PJM’s Andrew Gledhill presented a proposal to grant PJM more flexibility to reflect errors in the availability of load management when calculating the unrestricted peak loads component of the load forecast.  

The revisions to PJM Manual 19: Load Forecasting and Analysis are being brought as a quick fix — allowing the issue charge and solution to be voted on concurrently — in an effort to have the changes effective for the 2025 load forecast. 

Gledhill said the change is intended to account for instances when load management deployments occur at times that participants are operating below their peak load, which would reduce the estimated load drop PJM is likely to receive. That includes holidays when industrial consumers are likely to be offline. 

If starting with the premise of peak load contribution rather than what the actual loads would be at that time, Gledhill said it’s likely inaccurate information would be included in the forecast. 

PJM’s Pete Langbein said that historically, peak loads were concentrated on hot summer days, but the RTO’s risk modeling has shifted the focus toward winter deployments, when the energy reduction capability can vary more significantly. Load drop estimates are used to calculate unrestricted load for forecasting, capacity compliance and the addback reported to the utility for the following year. The hourly forecasts also are an input into the effective load-carrying capability models used in resource accreditation. 

Manual Revisions to Clarify DASR Calculation for 30-minute Reserves

PJM’s Kevin Hatch presented revisions to Manual 13 to document how the day-ahead scheduling reserve (DASR) is used to determine when the 30-minute reserve requirement may be insufficient for procuring adequate reserves. 

The Operating Committee endorsed the language as a quick-fix proposal during its Nov. 8 meeting. (See “Stakeholders Endorse Quick Fix Solution on Day Ahead Scheduling Reserve Calculation,” PJM OC Briefs: Nov 8, 2024.) 

The 30-minute reserve is set at the greater of 3,000 MW, the primary reserve requirement or the largest active gas contingency, which Hatch said does not reflect the full range of operational risks dispatchers must account for when determining necessary reserves. The DASR calculation accounts for load forecast error and forced outage rates, both of which were factors that PJM sought to include in a dynamic 30-minute reserve formula stakeholders rejected in July. (See “Stakeholders Endorse Reserve Rework, Reject Procurement Flexibility,” PJM MRC Briefs: July 24, 2024.) 

Hatch said the revisions reflect an existing practice and no changes are being made to PJM processes. 

Manual 14D Periodic Review

PJM’s Madalin How presented a package of revisions to Manual 14D drafted through the document’s periodic review. The changes would correct grammatical errors and typos, and update communication protocols, including adding a new email address. 

The manual also would be updated to document that generators must provide reactive capability curves to PJM before they can come online and that reactive testing must be completed within 90 days of initiating commercial operations. 

Members Committee

Comment Period Opens on Cost Allocation Tariff Revisions

PJM told the MC that the Transmission Owners Agreement Administrative Committee had opened a 30-day consultation period on revisions to tariff Schedule 12, which details the solution-based distribution factor (SBDFAX) process for allocating the costs of Regional Transmission Expansion Plan projects (EL21-39, ER22-1606). 

The revisions would address a FERC order granting a complaint from the Long Island Power Authority and Neptune Regional Transmission System regarding components of the SBDFAX method. 

Merchant transmission facilities would be considered “responsible customers” within the zone they are interconnected to be assigned a portion of the transmission enhancement charges associated with RTEP projects. If material modifications are made to the boundary of that transmission zone, merchant transmission owners would have the option to have the DFAX analysis separated from that zone. 

Required transmission enhancements approved by the PJM Board of Managers prior to Dec. 11, 2023, will be located in the zone of the relevant TO, while enhancements approved after that date would be located in the zone where the physical enhancements are sited. 

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Constellation Complaint Seeks Formal Data Center Co-location Rules

Constellation Energy filed a complaint against PJM at FERC on Nov. 22, opening up another regulatory front in the debate over co-locating data centers at existing nuclear plants (EL25-20). 

Constellation alleges that PJM’s tariff is unfair because it does not contain rules for interconnected generators to follow when seeking to provide service to fully isolated, co-located load. 

The issue already was in front of FERC in other proceedings, with the commission taking a universal look at co-located load in a recent technical conference. (See FERC Dives into Data Center Co-location Debate at Technical Conference.) 

Exelon, from which Constellation was spun off, also has pending reforms to its interconnection rules that led to protests from the nuclear plant owner. (See Exelon, Constellation at Loggerheads over Data Center Co-Location.) 

“While nothing in the tariff suggests any prohibition of fully isolated co-located load, some local utilities are taking advantage of the lack of tariff rules to thwart competition to serve large end use loads, thereby delaying by several years and significantly increasing costs to serve data centers that are critical to national security, economic development and other national priorities,” Constellation’s complaint said. “This lack of tariff rules is allowing transmission owners across the PJM system to treat generators seeking to serve fully isolated co-located load differently.” 

PJM released guidance for the issue in April 2024, which explains how the RTO has been reviewing co-location. The complaint said that should be included in the tariff. FERC might decide that it has to weigh in on other issues, but those could be dealt with in a paper hearing. 

The complaint argues that rules are needed so market participants understand what they have to do to enter into generator co-location deals. They also would ensure utilities understand the FERC jurisdictional rules applicable to fully isolated, co-located load and “cease exercising their monopoly power to thwart competition.” 

“It is necessary to establish consistency across the PJM footprint and avoid the current circumstance of each of the transmission owners in PJM deciding whether and to what extent they will follow PJM’s guidance,” the complaint said. “Otherwise, we will be left with a mishmash of co-location rules at the federal level that are driven by the self-interests of each of the transmission utilities.” 

That mishmash already is starting to happen based on how different Exelon’s pending rules would treat co-located demand compared to how PPL Electric Utilities dealt with the 300-MW data center co-located at the Susquehanna nuclear plant. 

Data centers are a national security priority due to the new technologies driving them, such as artificial intelligence. Their increasing size has made them difficult to connect to the grid, as that often requires new transmission. Building out the required lines takes several years and leads to higher costs for other consumers, the complaint said. 

“As a matter of simple engineering, it is more efficient to locate large loads next to large generation, when possible,” Constellation said. “One longstanding option that has been available to any load since the beginning of open access has been to connect directly to a generator either fully independent of the network grid or with a reduced reliance on the grid.” 

Data centers have pursued contracts for fully isolated, co-located load, “networked co-located load” where they rely partly on the grid and partly on a nearby power plant, and a “networked load” configuration that relies entirely on the grid. The last two have formal rules in PJM’s tariff, but fully isolated co-located load lacks formal rules, with the tariff also saying nothing that indicates the configuration is inconsistent with the RTO’s rules. 

The issue of the less formal guidance on co-location came up when FERC recently rejected the expansion of a co-located data center at the Susquehanna nuclear plant. (See FERC Rejects Expansion of Co-located Data Center at Susquehanna Nuclear Plant.) The amendments to the Susquehanna deal were proposed in large part so PJM’s guidance would be binding on the parties. 

FERC rejected them in part because it questioned whether the RTO planned to offer interconnection services on equivalent terms to all similarly situated interconnection customers. FERC’s order acknowledged the guidance was “not part of the PJM tariff, has not been approved by the commission and was not before the commission in the instant filing.” 

The complaint notes that PJM has completed studies for potential co-located loads at three Constellation generation sites, which indicated none of those would have been able to draw power from the grid.  

Exelon reviewed the deal at Constellation’s LaSalle Clean Energy Center in Illinois, but then refused to do so at the other two units, insisting that the generation owner or its customer first must apply for retail service and designate what sort of wholesale transmission service it would take from Exelon. The utility holding company then stopped working with the data center at the LaSalle plant, the complaint said. 

Connecting a major data center to the grid can take five to 10 years, and in a global race for new technology, any delay is harmful to the national interest, the complaint said. 

“This interconnection delay imposes unquantifiable risks and costs to the national economy and security and advances in AI,” the complaint said. “Each year that hyperscale data centers await interconnection to the grid risks another year of losing ground to competing nations.”  

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US, Canadian Leaders Discuss Affordability of Energy Transition

BOSTON — Energy leaders from the U.S. and Canada grappled with the challenges of balancing decarbonization and affordability at the New England-Canada Business Council’s (NECBC’s) Executive Energy Conference on Nov. 20-21, discussing how collaboration could lower the cost of the clean energy transition on both sides of the border.

Retail electricity rates in New England are rising faster than nearly all other regions in the U.S., while Hydro-Québec plans to spend billions of dollars to meet demand growth, which it expects to put “upward pressure on electricity rates.”

To juggle major investments preparing for load growth, upgrading aging infrastructure, and incorporating and balancing intermittent renewables, “there needs to be a different way to look at how the investment is funded,” said Nicola Medalova, COO of National Grid’s New England electric business.

Central Maine Power CEO Joseph Purington echoed Medalova’s concerns, saying the increase of public policy costs in electric rates is “not sustainable.”

“We have to start thinking about public policies and the public policy component of the bill,” Purington said. He wondered if some of those costs should be “spread across as a tax instead of as a part of your electric bill.”

The potential loss of federal clean energy funding with the incoming Trump administration likely will add a layer of difficulty for states looking to meet their climate goals without overburdening ratepayers.

Electricity bills can be a regressive funding mechanism to support public policy initiatives: Rising energy costs disproportionately affect low-income individuals, who often are forced to choose between paying energy bills and covering other essential needs like food and health care.

Discount rates can do only so much to mitigate the issue, Medalova said, adding that rate pressures can drive up economy-wide living costs. “Whenever you give a discount, somebody else is picking up the weight of that bill.”

North of the border, political uncertainty in Canada similarly threatens the availability of federal funding, said Monica Gattinger, a political studies professor at the University of Ottawa. Gattinger said public opinion shows climate change has been “dropping like a stone” in the public’s list of priorities, adding that a conservative government “would likely reverse many, if not all, of these policies.”

Competing Priorities

Speakers at the conference discussed a wide range of solutions to help balance the often competing priorities of affordability, reliability and decarbonization.

Medalova and Purington both emphasized the need to unlock retail demand flexibility, a sentiment that was echoed by several other speakers throughout the conference.

ISO-NE CEO Gordon van Welie highlighted the RTO’s finding from its 2050 Transmission Study that a 10% reduction in the 2050 peak load could reduce the required transmission buildout by about a third.

The RTO projects the region’s peak demand to more than double by 2050 and estimates the transmission buildout could cost up to $26 billion. (See ISO-NE Prices Transmission Upgrades Needed by 2050: up to $26B and ISO-NE Analysis Shows Benefits of Shifting OSW Interconnection Points.)

Winston Morton, CEO of Climative, said there is a large amount of remaining potential in energy-efficiency upgrades. He added that these gains have been constrained by the limited scale of state energy-efficiency programs and the gap in capital needed to finance building retrofits.

“We’ve got to attract private capital into the market as quickly as we can,” Morton said, noting that he sees “a positive return on investment for every retrofit.”

Along with transmission needs, load growth also will pose significant resource adequacy challenges for the Northeast.

“We’ve got to figure out how to balance load growth and electrification efforts with reliability,” said NERC CEO Jim Robb, adding that he is “a big advocate of natural gas generation, because it’s so flexible and it can help meet the afternoon ramp.”

Natural gas is the dominant source of electricity generation in New England, and gas-fired generation has been increasing steadily in recent years.

energy

From left: Robin Main, Hinckley Allen; Serge Abergel, Hydro-Québec Energy Services; Nicola Medalova, National Grid; and Central Maine Power CEO Joseph Purington | © RTO Insider LLC

“There is a critical need for gas throughout the year,” said Richard Levitan, president of energy management consultancy Levitan & Associates.

Toby Rice, CEO of EQT, one of the largest U.S. gas producers, pitched attendees on the need to increase natural gas pipeline capacity into the region.

“We’ve hit a wall,” Rice said. “We just need more infrastructure to connect markets.”

Rice chided environmentalists for opposing pipeline projects and argued that additional gas infrastructure would help reduce emissions by displacing coal or oil.

“They should be supporting pipelines because of their concern for climate,” he said.

While replacing coal or oil with natural gas can bring some emissions reductions depending on how much methane is leaked from the system, coal and oil make up only a small fraction of the generation mix in New England, Québec and the Maritime provinces, apart from Nova Scotia.

Increased gas generation has caused greater power system emissions in New England in the past year, and a long-term rise in gas consumption would likely undermine the climate goals set by New England states. Massachusetts state law includes sector-specific emissions limits with increasingly stringent decarbonization targets through 2050.

Rice also argued that increasing LNG export capacity would drive down global emissions, although the climate case for exported LNG is murky. One peer-reviewed study published in October found exported LNG to have a 33% larger carbon footprint than coal over a 20-year period.

Van Welie expressed skepticism that New England would see new pipelines, citing a lack of customers. However, he stressed that existing resources must not be retired faster than new renewables are deployed, especially with anticipated load growth. An ISO-NE study on deep decarbonization published in October found a significant need for clean, dispatchable resources to balance renewables. (See ISO-NE Study Lays Out Challenges of Deep Decarbonization.) The study singled out small modular nuclear reactors (SMRs), synthetic natural gas and multiday energy storage as potential solutions to help meet these needs.

Rudy Cuzzetto, a member of the Legislative Assembly of Ontario, discussed the province’s work to help commercialize SMRs. Ontario likely will have the world’s first full-scale SMR — with a capacity of 300 MW — in operation by 2029, he said.

“The world is looking at Ontario right now,” Cuzzetto said. “We are going to be a powerhouse in Ontario [and] be able to export electricity across the world.”

Québec’s vast hydropower resources also could help to fill the need for dispatchable power, said Serge Abergel, COO for Hydro-Québec Energy Services.

Despite a drop in exports in 2023 from low reservoir levels, Hydro-Québec has indicated that long-term changes to the role that its hydroelectric resources play on the grid could bring savings across the Northeast. (See Québec, New England See Shifting Role for Canadian Hydropower.)

“We are interested in optimizing our grid for our neighbors,” Abergel said. “Let’s have a conversation on regional planning for the long term. Maybe we can save some ratepayer money.”

In theory, increased bilateral transmission capacity between the two countries could provide significant benefits when paired with a surplus of renewables on the New England grid. This would allow New England to export cheap power during periods of excess renewable generation, while enabling Québec to conserve hydropower and send power back to the U.S. during renewable lulls.

Abergel said the company sees “significant savings, especially when you start looking at 2040 and onward.”

Responding to Abergel’s pitch, van Welie said this dynamic would require agreements to provide “a reciprocal benefit” between regions and to ensure Hydro-Québec sells the power back to New England at a reasonable price during periods of low renewable generation.

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CARB Clean Vehicle Incentives Down Sharply for 2024/25

California regulators approved a $35 million package of clean transportation incentives for fiscal 2024/25, a steep drop in funding that is raising concerns about the fate of programs not funded by the package. 

The California Air Resources Board approved a funding plan Nov. 21 that divides the money among three programs: 

    • $15 million for the Clean Off-Road Equipment project (CORE), which provides incentives for the purchase of zero-emission off-road equipment such as forklifts and cargo loaders. 
    • $15 million for the Innovative Small e-Fleet (ISEF) project, which offers incentives for medium- and heavy-duty ZEVs for fleets of 20 or fewer vehicles. There’s also funding for “innovative solutions” such as truck sharing. 
    • $5 million for the Zero-Emission Truck Loan pilot project to help fleets buy zero-emission medium- and heavy-duty trucks. 

This year’s $35 million in clean transportation funding compares to a $624 million incentive package approved in 2023, a record-breaking $2.6 billion in incentives in 2022 and a $1.5 billion package in 2021. 

“This year’s state budget was a challenging one, with reductions across the board to many key state agencies and programs,” CARB Chair Liane Randolph said. “Funding allocations for air quality and climate change programs were unfortunately no different.” 

While last year’s incentive packages were funded by a variety of sources, including cap-and-trade dollars and the state general fund, this year’s funding came only from the state’s Air Quality Improvement Fund. 

CARB Executive Officer Steven Cliff said the funding package is aimed at small fleets and small businesses and seeks to benefit disadvantaged communities. The CORE and ISEF programs historically have had more demand than available funds, said Cliff, adding that though the funding is less this year, it’s “certainly meaningful.” 

Programs Left Out

CARB’s approval of allocations to only three programs means other incentive programs will go without additional funding this fiscal year. That includes the Hybrid and Zero-Emission Truck and Bus Voucher Incentive Project (HVIP), which has helped fund the purchase of more than 14,000 medium- and heavy-duty clean vehicles since it launched in 2009. 

As of Nov. 21, the HVIP website said the standard voucher portion of the program was out of money. The program still had funds available in certain set-asides, including those for transit and drayage trucks. 

Tim McRae, vice president for public affairs at the California Hydrogen Business Council, said the HVIP funding shortfall comes at a “pivotal point” for the fuel cell electric vehicle industry. New manufacturers and new products are entering the market, giving truck buyers more choices, he said. 

“We must have incentives in the next six to eight months to get these platforms off the ground. Otherwise, the whole industry, including customers and end users, will suffer,” McRae said during the CARB board meeting. 

In contrast to HVIP, McRae said, the ISEF program has less of a track record, and the CORE program targets vehicles that generally don’t emit as much pollution as the heavy-duty trucks that HVIP targets for replacement. 

Among the newly available fuel cell electric vehicles is a zero-emission garbage truck that is being tried out in California. The garbage truck was developed by Hyzon in partnership with New Way Trucks.  

In a trial with Mt. Diablo Resource Recovery, the fuel cell trucks demonstrated consistent power over a range of at least 125 miles, including at least 1,300 cart lifts, with greater fuel efficiency than traditional diesel trucks, Hyzon said in an announcement this month. 

Nick Barrett with Hyzon said the company was on the verge of closing several large orders for the fuel cell trucks. 

“HVIP is absolutely required to complete these sales and get these trucks on the road,” Barrett told the board. 

Low-income Programs

The funding shortfall also pits two low-income, zero-emission vehicle incentive programs against each other. 

CARB’s Clean Cars for All (CC4A) program has been run for several years by air districts in different parts of the state. More recently, at the direction of the legislature, CARB launched a statewide incentive program for residents living outside of the participating air districts. 

CARB announced in September the launch of the statewide program, called the Driving Clean Assistance Program, with $242 million of funding. The program allows low-income participants to scrap their old vehicle in exchange for a grant of up to $12,000 to buy a new or used zero-emission car, motorcycle or e-bike. 

Now CARB is struggling to balance the funding needs of DCAP, which brings the low-income ZEV incentive to regions where it previously wasn’t available, and the air district’s CC4A programs, which have a track record of bringing incentives to hard-to-reach populations.  

Neither received any funding in the new incentive package. But $14 million recently was shifted from DCAP to the San Joaquin Valley CC4A program. 

“Unfortunately, we are basically talking about scraps,” said Randolph, the CARB chair. “We are talking about inadequate funding for getting vehicles to residents that could not otherwise afford cleaner vehicles.” 

Randolph said she would work with CARB staff on ways to optimize funding among the DCAP and CC4A programs. 

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ERCOT to Recommend RMR Agreement for Braunig

ERCOT says it will recommend that its Board of Directors approve a reliability-must-run (RMR) contract for one of three aging CPS Energy gas units, set for retirement, to maintain reliability in the San Antonio area.

The grid operator also told the Texas Public Utility Commission during its Nov. 21 open meeting that it is working with CPS and CenterPoint Energy to determine whether the latter’s controversial $800 million mobile generators could be moved to San Antonio as an alternative.

“I think this is an elegant solution to a number of issues that we’re facing,” PUC Chair Thomas Gleeson said in response.

CenterPoint’s 2021 lease of 15 32-MW generators and 13 smaller ones (between 1.2 and 5 MW) became a source of derision and political criticism when they went largely unused during the utility’s weekslong restoration after Hurricane Beryl. (See Texas Politicos, Residents Bash CenterPoint.)

ERCOT General Counsel Chad Seely told the PUC that grid operator staff, the two utilities and Life Cycle Power, the generators’ owner and operator, have been discussing moving the larger units and their 480 MW of capacity to the San Antonio area. He said the 15 large generators are the equivalent of two of the retiring plants, Braunig Power Station’s Units 1 and 2, and would provide greater reliability than CPS’ forced outage-prone assets.

That comes from “mainly the diversity of where those units can be located versus having two larger units that have the susceptibility of higher forced outages,” he said. “These are dual-fuel-capable units. They could be located in San Antonio with a higher shift factor. And obviously their start time is about 10 to 15 minutes, versus a longer lead time for Units 1 and 2.”

CenterPoint said in an emailed statement that its “top priority is finding a Texas-driven solution that helps address the growing energy needs of Texans and our strong economy.”

“We are optimistic that we will find a constructive solution that best serves our customers and Texas,” the utility said.

San Antonio’s municipal utility told ERCOT earlier this year that it planned to retire the three Braunig units, which date back to the 1960s, in March 2025. However, ERCOT said the resources, with a combined summer seasonal net maximum sustainable rating of 859 MW, were needed for reliability reasons and issued a request for RMR proposals in July. (See ERCOT, CPS Energy Negotiating RMR, MRA Options for Retiring Units.)

In the meantime, Seely said ERCOT will urge its board to approve an RMR agreement for Braunig Unit 3, the newest (1970) and largest (412-MW maximum summer rating) of the three units. It will ask the directors to defer any decision on the other two units so staff can continue to work on the feasibility of the mobile generators’ move. The board meets Dec. 2-3.

CPS has said each unit must be inspected and repaired — consecutively, not concurrently — if it is to operate beyond its retirement date. The utility has moved the unit’s suspension date up to March 2, allowing time for inspection and repairs that it says will take at least 60 days.

“If the board moves forward with an RMR agreement, that will allow us to move forward with that inspection work at the beginning of March in trying to get that unit back for the summer of 2025,” Seely said. “A lot of work has been done on the technical side. We do believe it is technically feasible to move those 15 units into the San Antonio area.”

“There are many factors being evaluated by ERCOT and the companies involved,” CPS spokesperson Miguel Vargas told RTO Insider in an email. “We remain engaged in ERCOT’s efforts to evaluate this alternative proposal.”

ERCOT says the RMR units will be important in addressing the South Texas export interconnection reliability operating limits staff established this year that will eventually be resolved by transmission projects underway. Their analysis revealed that under certain conditions, such as when high system demand coincides with an outage of a major transmission line or one or more generation units, lines that deliver power from South Texas into San Antonio could be overloaded and possibly lead to cascading outages.

ERCOT’s solicitation for must-run alternatives to Braunig’s retiring units resulted in one response. A 200-MW multi-hour energy storage resource responded within minutes of an Oct. 7 deadline, proposing to start in the summer of 2026 and end March 1, 2027.

The RMR contract would be ERCOT’s first since 2016. The grid operator entered into an agreement with NRG Texas Power over a previously mothballed gas unit near Houston. It ended in 2017, thanks partly to transmission facilities that increased imports into the region.

New Rules for Crypto Miners

The PUC approved a new rule requiring virtual currency mining facilities in ERCOT to annually provide information related to their electricity demand, location and ownership, giving the grid operator more transparency into the market (56962).

Under the rule, cryptocurrency miners with a total load above 75 MW will have to register with the PUC as a large flexible load, capable of adjusting their power consumption in response to prices. The facilities must file a five-year projection of expected peak load for each year, including the percentage of load that meets the definition as interruptible. The rolling five-year projection will be repeated each year.

“I think it’s really important that, as we’re looking at [Texas’] load growth, that this help us give ERCOT and the market an understanding of what those actual projections are from the cryptocurrencies’ standpoint,” Commissioner Jimmy Glotfelty said. “Having them look five years out every year is a really important component of this for reliability.”

The rule was mandated by state law as demand associated with virtual currency mining operations has grown rapidly in recent years, according to the U.S. Energy Information Administration.

PUC Completes Beryl Investigation

The commission approved several reports, including its investigation into two major weather events that hit the Houston area: a derecho in May and Hurricane Beryl in July.

At Gov. Greg Abbott’s directive, the PUC assessed local utilities’ emergency preparedness and their response to the two events (56822).

The PUC team made a number of recommendations to reduce the length and effect of power outages, including annual hurricane and storm drills between utilities, new performance standards and heavier fines, and a legal right to restoration timelines.

The investigation’s summary will be added as an addendum to the broader report that all state agencies are required to file ahead of Texas’ biennial legislative sessions. The 2025 session begins Jan. 14.

The PUC also approved:

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Chesapeake Solar Industry Prepares for Trump 2.0 ‘Solarcoaster’

BALTIMORE ― Solar industry veterans often refer to the shifting political and economic fortunes the sector has experienced over the past decade as “the solarcoaster,” and many at the Chesapeake Solar and Storage Association’s (CHESSA) 2024 Solar Focus conference were preparing for a bumpy ride during President-elect Donald Trump’s second term.  

But they also spoke about the industry’s resilience, and the fact that it still recorded strong growth during the first Trump administration, supported by state and corporate clean energy goals and ongoing cuts in the cost of solar panels, making solar increasingly competitive with other forms of generation.  

An affiliate of the national Solar Energy Industries Association, CHESSA is a regional trade association covering Maryland, Virginia and the District of Columbia, all jurisdictions with ambitious clean energy and emission reduction goals. 

Alex McDonough, a partner at policy consultants Pioneer Public Affairs, took a hardline view, predicting that Trump and congressional Republicans could target clean energy tax credits in the Inflation Reduction Act, including the 30% investment tax credit that has been critical for U.S. solar market growth.  

In the two-plus years since the law was passed, GOP lawmakers in Congress “have voted 54 times on different pieces of the Inflation Reduction Act to repeal,” McDonough said during a Nov. 19 panel at the two-day conference at the Marriott Baltimore Inner Harbor hotel. “We should take them at their word that they are putting this up on the table, and one of the potentially most damaging pathways to extend the 2017 tax bill that we could experience is if they start out with an opening negotiating position that fully goes after the IRA tax credits.” 

The buzz on Capitol Hill is that Republicans in the House of Representatives will have a budget reconciliation package to extend Trump’s signature legislation, the 2017 Tax Cuts and Jobs Act (H.R. 1), ready to introduce in the first week in January, McDonough said. Among its other business-friendly provisions, the law cut the corporate tax rate from 35% to 21%. It expires at the end of 2025, and the anticipated price tag for extending those cuts is about $5 trillion, McDonough said. 

Budget reconciliation is a legislative maneuver that allows budget bills to be passed on straight majority votes in both houses, which is intended to protect them from minority party filibusters. The Trump tax cuts and IRA were passed through the budget reconciliation process, as will be any bill to extend the 2017 cuts. 

Playing “Pollyanna” to McDonough’s tough pragmatist, Alison Kennedy, vice president at Boundary Stone Partners, another D.C. policy group, talked up the current conventional wisdom that the Republican states and districts that have benefited from a majority of IRA funds will help protect key provisions of the law. 

Factories are being built; jobs are being created, Kennedy said. “It’s time for these projects to shine. … 

“The communities, the states, those stakeholders; it’s their time to rise. It is their time to be involved in these discussions, to push, to call their Congress members … to say, ‘Yes, the IRA is making an impact in our communities.’” 

Ben Norris, vice president of regulatory affairs for SEIA, said the national trade group began preparing to defend the law even before President Joe Biden signed it in 2022. SEIA has been on the Hill meeting with the newly elected lawmakers who arrived in D.C. after the election and will bring its own members into town in December and January to talk with their representatives and senators. 

CHESSA Executive Director Robin Dutta | © RTO Insider LLC 

It’s one thing to show lawmakers the facts and figures ― like the 40,000 new solar manufacturing jobs created by the IRA ― Norris said. “It’s quite another to meet the proprietors of such a new facility, who are actually employing these folks in the districts of some of the lawmakers who are going to be taking some of these hard votes.” 

But both he and McDonough cautioned against depending too much on support from certain Republicans — for example, the 18 GOP representatives who in August sent a letter to House Speaker Mike Johnson (R-La.) asking for protection for the IRA tax credits that are benefiting their constituents. 

Republican majorities will be slim in both houses, so GOP lawmakers could have little wiggle room on a budget reconciliation vote to extend the 2017 tax cuts, McDonough said. 

“If we get to a point where there’s a tax bill on the floor that extends the 2017 tax cuts and includes all the IRA provisions in there, cutting them in any which way, they will vote for it,” he said. “They will have to vote for that bill for political reasons; because if that bill fails, they will be responsible for an income tax hike for every American.” 

An Industry That Adapts

With Trump returning to the White House, renewables — solar, wind and storage ― are facing a major change in the political and social narratives surrounding the industry. For four years, the industry has benefited from current Energy Secretary Jennifer Granholm’s urgent calls to “deploy, deploy, deploy” clean energy projects. 

But North Dakota Gov. Doug Burgum (R) and fracking executive Chris Wright, respectively Trump’s picks to lead the Interior and Energy departments, will be pushing a “drill, baby, drill” agenda aimed at “U.S. energy dominance” and “energy independence.” Trump is calling for a buildout of baseload energy — that is, natural gas or possibly nuclear ― aimed at cutting consumer energy prices. 

The anticipated retreat from President Joe Biden’s clean energy goals — such as a 100% carbon-free electric grid by 2035 — already is refocusing industry attention, and hopes, toward states and cities, like Maryland, Virginia and Washington, D.C., that have passed strong clean energy policies. 

Maryland has committed to a 60% reduction in the state’s greenhouse gas emissions by 2031, while Virginia’s Clean Economy Act of 2022 mandates the state’s two investor-owned utilities — Dominion Energy and Appalachian Power — to provide 100% clean generation by 2045 and 2050, respectively. 

Kennedy and others expect that Trump’s other policies, such as tariffs on all imports, will increase utility bills. “I don’t have a solution for how to make them not go up,” she said. 

She sees an opening for renewables if the new administration truly gets behind an “all-of-the-above” approach to energy policy and the solar industry positions itself as integral to the Trump narrative of energy dominance and independence.  

Solar and storage are critical to meeting new demand from data centers and together accounted for about 80% of new power on the grid in 2024, Kennedy said, citing figures from the U.S. Energy Information Administration. 

“How are we showing what manufacturing jobs are leading to this and telling those stories and drawing those lines to conclusions to allow Republicans to see the benefits and how we are manufacturing and deploying domestically,” she said. “It’s hard to argue with jobs.” 

Norris noted that the U.S. solar industry is slated to hit a major milestone by the end of the year, with domestic supply chains producing enough solar panels — about 40 GW of capacity ― to cover current demand, according to figures from SEIA and industry analysts Wood Mackenzie. 

“That means no more modules from overseas, potentially,” he said. “The idea of making all that go away through a sort of arcane piece of tax and financial legislation, I think it’s going to be unappealing to most.” 

But Walter McLeod, managing director of Monarch Strategic Ventures, which invests in clean energy, said Republicans could undercut the solar ITC through further corporate tax cuts. In 2017, Trump had proposed cutting the corporate tax rate to 15%, but settled for 21%, McLeod said during a panel on federal policy Nov. 20. 

“We should all expect that he’s going to take a second bite at [that],” he said. “When the number goes below 18% … the demand for the ITC at the corporate level will substantially drop off, and that could crush the market indirectly.” 

In other words, if corporate taxes are low enough, companies may not have the “appetite” or need for the tax credits generated by solar development.  

But McLeod and other speakers on the Nov. 20 panel also see new opportunities for the industry as it navigates wherever the solarcoaster takes them in the days and months ahead. 

“We’re an industry that adapts,” said Lara Younes, director of mergers and acquisitions and structured finance at Lydian Energy, a utility-scale solar developer. “We’ve already experienced a bunch of headwinds over the last years, and I think we should continue to be flexible, … optimistic and creative in whatever way we can.” 

Ian Gallogly, vice president of acquisitions for CleanCapital, which invests in and owns solar and storage projects, said a focus on performance, outcomes and national security, sometimes favored by fossil fuel companies, also could work for renewables. 

Robin Dutta, executive director of CHESSA, argues that the intermittency of solar or other renewables is being misrepresented. 

The intermittency narrative ― the sun doesn’t always shine, the wind doesn’t always blow — doesn’t take into account that renewables provide multiple, diverse options to meet growing demand in the U.S., Dutta said. 

“You have wind; you have land-based wind; you have offshore wind. You have residential solar and [commercial and industrial] and large-scale, and you’ve got energy storage, short-duration … behind-the-meter, standalone,” he said. “We have all of these solutions. Between solar and storage, we can play such a huge role in American energy dominance.” 

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MISO Draws in Experts for Probabilistic Planning Symposium

CARMEL, Ind. — MISO further embraced the industry’s move to chance-based transmission planning by hosting a Probabilistic Planning Symposium at its headquarters.

The grid operator and consulting firm Energy and Environmental Economics pulled together stakeholders, other RTO planners, researchers and tech representatives to probe prospective planning methods and fret over the shortcomings of current practices Nov. 19-20.

Director of Economic and Policy Planning Christina Drake said when she joined MISO, planning was carried out on a relatively gradual timeline compared to the urgency today.

“We’re seeing these loads come on quicker than we can keep up,” she told attendees.

Drake said of late, MISO is having “friendly but frank” conversations with companies whose building goals are stymied by the limits of today’s transmission capacity.

She said just a few years ago, MISO was met with skepticism that its third, most aggressive planning scenario — which predicted electrification stimulating significant demand — would ever come to pass.

MISO announced earlier in November that it will revise its three, 20-year transmission planning futures — which envision the clean energy transition at a walk, a jog and a run — to be more in touch with recent realities of surprising load growth and accelerated clean energy goals. (See MISO Pauses Long-range Tx Planning in 2025 to go Back to the Futures.)

“And now we’re getting feedback that we think you’re near your top end on your load [predictions],” Drake said. “The drivers are changing. It’s no longer electrification; it’s things with hydrogen and data centers. That’s very different.”

Drake said the pace of change is so dramatic that MISO’s planning modeling is becoming unsolvable. “Our tools have never seen this. It’s pushing our models to the brink,” she said. “Now we’re projecting things 10 years faster.”

SPP Manager of Transmission Planning Kirk Hall seconded experiencing trouble trying to produce realistic models.

“We’re having to constantly add fictitious equipment … just to get our reliability models to solve,” he said.

“If you’re asking if the probabilistic planning tools are sufficient? The answer is no,” NYISO Director of System Planning Yachi Lin said.

Lin said New York’s past 35 years contained little in the way of transmission planning. Recent years, on the other hand, have contained about $15 billion in transmission and distribution investment, she said, owing to the state’s progressive climate goals.

Lin said New York City alone has an “acute” problem of having to retire several aging, combined cycle units, while new, zero-emission generation needs to occupy as little acreage as possible. She said advanced technology is years away, with a “big gap of getting there.” Lin likened transmission planning around those unknowns to layering up slices of Swiss cheese.

“There are holes, we know. But hopefully, if you have enough slices, you can cover the gaps,” she said.

Drake said building an economic model takes an amount of work that’s often not appreciated. She said it’s a level of challenge that’s on par with delivering a baby.

“It took a solid nine months, and there was a lot of crying and pain in the middle,” she joked of creating a successful model.

Drake added that just to get a model to solve today takes an “intense” effort. She said she felt like bringing planners a “Gatorade and a towel” after they’re successful.

ERCOT Power Systems Engineer Eric Meier also said that there aren’t any tools “off the shelf” today that can effectively evaluate probabilistic planning.

Drake said grid planners’ challenges are compounded by trying to anticipate yearly bouts of increasingly extreme weather and generation outages.

“This is new territory for all the RTOs,” she said.

Benjamin Hobbs, Johns Hopkins University | © RTO Insider LLC

Drake said extreme weather instances are driving an “insatiable” need to improve interregional transfer capability, evidenced by MISO’s new interregional studies with SPP and PJM.

During the symposium, grid planners named other obstacles to identifying the most useful transmission projects decades in advance.

MISO Senior Manager of Policy and Regulatory Planning RaeLynn Asah said load growth is the greatest uncertainty for today’s planning.

“It’s astronomical — I don’t know what word I want to use. It’s so large, and it’s so unknown,” Asah said.

Asah also said too-slow regulatory processes and seized-up supply chains are sources of anxiety. “They are a big deal. They keep me up at night,” she said.

However, Asah said there’s reason for hope. She said MISO is building a new planning model designed to be more responsive so MISO more easily can incorporate stakeholder suggestions and influence the model.

“I want to end on hope instead of the things we can’t do yet,” she said.

Lin said retaining a planning staff is becoming more challenging with stiff competition between planning organizations. “It’s a friendly competition among the ISOs/RTOs. And that’s great, but we always want to make sure our people are taken care of,” she said.

Climate Unknowns

MISO dedicated panels to climate change, a little-used phrase among the politically agnostic grid planner.

Argonne National Laboratory engineer Neal Mann said the lab’s projections of future weather patterns across a range of scenarios through midcentury and end of century seek to predict the more frequent heating and cooling degree days in addition to risks like flooding.

Mann said planners might want to “use their neighbors like a battery” to tap into their supply when they fall short.

The Electric Power Research Institute’s Parag Mitra said EPRI’s Climate Resilience and Adaptation Initiative (READi) collaborative model helps planners make decisions that will make the system more durable against ever more dangerous weather. Mitra said planners need to have a good understanding of how weather can affect assets.

Christina Drake, MISO | © RTO Insider LLC

Con Edison’s William Gunther said his utility is analyzing future multiday wind lulls and high midday solar output that is squirreled away in storage for later use. He said a Con Edison climate vulnerability study delved into how high substations need to be positioned due to sea level rise as well as the potential for undergrounding lines when temperatures are too hot for transformers to be in the open air.

Mitra said while there is a need for scenario-based planning that draws on probabilities of extreme events, it’s also valuable to analyze extreme events after the fact to pinpoint where conditions began a downward slide. He said demand response also can play a role in climate resilience.

But University of Michigan Professor Michael Craig said he discouraged planners from assigning climate disaster probabilities for planning purposes.

“When we think about climate change, I want to advise against using probabilities. Because we do not know … a meaningful probability of future climate scenarios,” Craig said. “Climate change is not a problem for 30 years from now; it’s increasing extremes today and tomorrow and the year after.”

Instead, Craig advocated stress testing solutions in modeling against wide-ranging degrees of extreme heat, extreme storms and extreme drought.

“It’s not like we hit 2050 and it turns over. Every year, those dice get loaded; every year you might have more extremes,” he explained.

New Analytics

Johns Hopkins University professor Benjamin Hobbs advised grid planners to adopt stochastic programming, which mulls multiple scenarios simultaneously and uses decision trees to come up with the most beneficial investments. He said MISO comes close to stochastic planning with its futures-based planning.

“The grid that you’re building needs to be nimble to be adaptive to economics, policy, climate,” Hobbs said.

Hobbs said a stochastic approach is useful for MISO, which contains states with and without carbon limits and renewable portfolio standards.

He said MISO could plug in variables like technological advancements, load growth, fuel costs, capital costs and carbon costs and limit potential solutions by constraints like siting limitations, emissions reduction standards and Kirchoff’s circuit laws.

Bilal Khursheed, Microsoft | © RTO Insider LLC 

Hobbs said he wasn’t suggesting planners could “naively” load up variables and expect a model to pinpoint the best grid solution. “What you’re getting from the model is suggestions,” he said. “All forecasts are wrong, so it’s important to consider a wide range of them.”

Iowa State University professor James McCalley made a case for adaptive co-optimized expansion planning, which shows the costs of grid expansions based on a specific future build (or a core) and the costs of adaptations to the original plan that may be necessary.

McCalley said the adaptive approach is a “cousin” of stochastic planning but not the same because the method is designed to show costs through time.

“I would make the case that both of these methods are useful tools in a planner’s toolbelt to understand the best way forward,” he said.

McCalley said adaptive co-optimized planning shouldn’t be a substitute for the PROMOD commitment and dispatch model, Siemens’ PSS®E Power Simulator or EPRI’s Electric Generation Expansion Analysis System. Rather, he said the method should be layered over them as an application to guide decisions.

McCalley said planners should continue to use their deterministic tools and introduce new, probabilistic analyses until they form a “single integrated method of doing the work.”

McCalley said he knows firsthand from his experience as a PG&E planner in the late ‘80s that deterministic planning leaves much to be desired. He recalled being grilled over planning practices in front of the California Public Utilities Commission.

“Probabilistic planning isn’t going to be a quantum leap for anyone. It’s going to be a journey, and we need to start now,” Mitra said.

AI Assistance

“Our grids are facing pressures like they’ve never faced before,” Microsoft’s Bilal Khursheed agreed, but offered AI as a means to lessen the tension.

Khursheed said the recent leaps in AI can better balance supply and demand in real time, improve resource utilization, assist in resource planning, better predict maintenance, provide the best insights to operators and speed the clean energy transition, among other things.

RaeLynn Asah, MISO | © RTO Insider LLC

“These advancements aren’t incremental. They’re truly transformational in nature,” he said.

Khursheed said grid planners should think of AI as “the brain of modern grid flexibility,” the internet of things as “the eyes and ears of the grid” and the cloud as “the backbone of the ecosystem.” He also said planners first must consider the “balancing act” of leveraging the most they can from existing assets before deciding to physically expand the grid.

“It’s not just about building more. It’s about spending only when we absolutely have to,” he said.

Khursheed said AI’s sophistication can defer capacity investments by harnessing virtual power plants to provide flexible resource adequacy. He said Microsoft recently worked with a “large western European” transmission operator and found that it could cut “overcommitted fossil fuel resources” by 17 GW over the length of the pilot program through high-performance AI computing that helps operators make better use of cheaper, carbon-free resources.

The pilot saved the operator “millions of Euros,” Khursheed said, and the topology optimizer is set to be rolled out on a large scale in the footprint.

Khursheed said transmission operators are shifting from being “reactive” when facing storms and temperature extremes and using generative AI to figure out earlier which assets are likely to take a hit and what transfer capability stands to be the most helpful.

However, Khursheed said Microsoft is risk-averse and thus far is making sure AI is providing more accurate data sooner to “drive levels of productivity we’ve not seen before” but not running the grid autonomously.

“There’s still a human-in-the-loop component,” he said.

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FERC Rules Against SPP Multiday Commitment Proposal

FERC on Nov. 21 rejected SPP’s proposed tariff revisions to implement a multiday economic commitment (MDEC) process, saying it introduces a potential gaming opportunity (ER24-2520). 

The commission agreed with the RTO’s Market Monitoring Unit that long-lead resources, such as coal plants, could intentionally lower their market offers below their actual costs to gain an out-of-economic-merit order and then receive a make-whole payment to which they would not otherwise be entitled. 

“SPP’s proposal would allow certain resources to unreasonably shift the risk that their costs are not recovered exclusively to customers, potentially leading to both inefficient market outcomes and gaming opportunities,” FERC said. 

The commission also said SPP had not adequately supported its assertion that its “analysis shows that [the proposed MDEC process has] the potential to create economic benefits to the market.” It said the RTO did not provide any information about the analysis or a “reasoned explanation” that showed the MDEC process would lower total production costs. 

“It is not clear how SPP’s proposal would result in a lower-cost commitment solution because long-lead resources could appear cheaper to the market than they really are, potentially displacing lower-cost resources and driving up market costs with no benefit to the market,” the commissioners wrote. 

SPP had argued that the proposed MDEC process would improve the methods by which long-lead resources, which account for about 34 GW of available energy, participate in SPP’s market. Currently, they cannot be committed in the day-ahead market, instead normally opting to self-commit as price takers. However, the increased prevalence of less expensive renewable and natural gas units has made coal units increasingly less economical to self-commit. 

Several public interest organizations protested SPP’s proposal, saying it would require the RTO to evaluate the economics of issuing commitment instructions to long-lead resources by comparing the expected production cost impacts of committing them before the day-ahead market closes using the real-time balancing market’s offers for all resources. 

“There was absolutely no evidence that the process proposed by SPP would actually work to reduce the uneconomic dispatch of coal resources in the market,” Earthjustice attorney Aaron Stemplewicz, who represented several public-interest groups in the proceeding, told RTO Insider via email. “The commission was correct to flag that it merely shifted risk from generators to the market and could easily have been manipulated to be a handout for uneconomic coal-burning power plants and other long-lead resources.” 

FERC’s order was without prejudice, allowing SPP or other grid operators to propose different MDEC processes. 

Cost-allocation Ruling Reaffirmed

FERC also rejected rehearing requests and sustained its previous approval of SPP’s tariff revisions allowing certain transmission facilities’ costs to be entirely allocated on a regional postage-stamp and cost-by-cost basis (ER24-1583). 

The commission modified its original order but reached the same result it did in May, when it found SPP’s capacity, flow and benefit analyses of the Sunflower Electric Power transmission facilities at the center of the proceeding provided benefits to the region as a whole. (See FERC Approves SPP’s Cost-allocation Revisions.) 

Several SPP transmission owners and municipal utilities and the Louisiana Public Service Commission filed rehearing requests of FERC’s order. They contended that the commission did not conduct the necessary cost-causation analysis and misapplied the “roughly commensurate rule” because it did not require a more granular, zone-by-zone benefits analysis of SPP’s proposal. 

FERC dismissed those arguments, along with others that claimed the commission failed to show that SPP’s capacity, flow and benefit criteria are linked to cost causation and that the order is “impermissible retroactive ratemaking.” 

Commissioners Mark Christie and Lindsay See filed separate concurring opinions, with both concurring only in the result of the proceeding and agreeing that the deciding factor for them was the support of the SPP Regional State Committee, which “has historically had a unique and authoritative role representing the states in SPP,” Christie said. 

“For me, the RSC’s unique role in representing the SPP states in difficult cost-allocation matters like these resolves this close case on the side of approval,” See wrote. 

In a Nov. 20 letter order, FERC also accepted SPP’s tariff revisions to calculate real-time balancing market (RTBM) prices should the system fail for more than 12 dispatch intervals and to extend the notification period for price corrections (ER25-71). 

The grid operator will use the day-ahead market’s LMPs, marginal congestion components and marginal loss components for RTBM settlements. The mechanism will accurately reflect prices had the RTBM system results not been able to calculate LMPs. 

The notification period is extended from five calendar days to five business days. 

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Amid Praise for Pathways Step 2 Milestone, Skeptics Remain Unmoved

The West-Wide Governance Pathways Initiative drew praise from many quarters Nov. 22 when its Launch Committee voted to approve its “Step 2” proposal to create an independent “regional organization” to oversee CAISO’s Western electricity markets. 

But it was quickly apparent the development — over a year in the making — is unlikely to shift views of those entities that remain skeptical about joining a market operated by CAISO and instead favor SPP’s Markets+. (See related story, Pathways Initiative Approves ‘Step 2’ Plan, Wins $1M in Federal Funding.) 

Counted among the strongest supporters of the final proposal, which was released Nov. 15, were the state utility regulators and energy officials largely responsible for launching the Pathways Initiative in July 2023. 

“It was only last summer that my colleagues and I across the West wrote a letter expressing our hope for an independent regional organization to oversee an expanded day-ahead market that includes California,” California Energy Commission Vice Chair Siva Gunda said ahead of the Launch Committee’s vote. “Since then, it’s amazing to watch how some of the brightest and most dedicated experts across diverse sectors in the West have come together to lay the foundations for this regional organization.” 

“The Launch Committee, the stakeholders — you stepped up to the request in the letter, working together, had success for [Pathways] Step 1, and [are] now voting on this foundational document that could really achieve the broad idea that was in our request,” New Mexico Public Regulation Commission Chair Pat O’Connell said. 

Oregon Public Utility Commissioner Letha Tawney said she appreciates the proposal “centers consumers” and provides “the opportunity for benefits in a different way that is exciting.” 

“At the end of the day, we have to be delivering for consumers this essential service at a price they can manage,” Tawney said. “That is what underpins the Western economy, but it also is what delivers for our most vulnerable customers, and I so appreciate the Launch Committee digging in and figuring out how to deliver on that fiduciary duty that the regulators put out to the region and asked you to help us solve.” 

Michele Beck, director of the Utah Office of Consumer Services and a Launch Committee member, said she began participating in the Pathways effort “defensively,” which is how she thinks consumer advocates likely approach any such regional activities. 

“Working with this group helped me to build confidence in the effort and really optimism about the outcome, as I saw a genuine focus on the public interest, which has been mentioned before. I think our proposal really has the greatest public interest protections that we see in any regional proposals out there,” Beck said. 

Beck acknowledged that Pathways still has a lot of work ahead of it in the next year and that Step 2 did not address some “big issues” that “were properly” not within its scope.  

“But this is consistent with the incremental approach that we’ve been taking here in the West, and [Step 2] remains a very important milestone,” she said. 

Committee member Brian Turner, director of Advanced Energy United’s regulatory engagement in the West, said the Step 2 “proposed governance structure recognizes the electric grid is evolving and a greater diversity of resources and customers and load-serving entities and solution-providers all have an essential interest in efficient markets and the affordability and reliability they bring.” 

Nonvoting committee member Chrystal Dean, vice president of enterprise portfolio management at the Western Area Power Administration (WAPA), noted that WAPA’s Sierra Nevada region recently announced it will begin negotiations toward full participation in EDAM through its membership in the Balancing Authority of Northern California and that its Desert Southwest (DSW) region will partner with Arizona G&T Cooperatives on a study to assess the CAISO market’s benefits for the DSW balancing authority area. (See WAPA Sierra Nevada Region to Advance with EDAM and Arizona G&T Cooperatives Announces Pursuit of EDAM Benefits Study.) 

“Both of these efforts underscore WAPA’s commitment to exploring new opportunities like those described in this Pathways Step 2 proposal, and we are really excited to see that these steps will help WAPA continue to make decisions that align with our market principles,” Dean said. 

Committee co-Chair Kathleen Staks, executive director of Western Freedom, said that as a representative of commercial and industrial electricity customers, she’s seen a “remarkable increase in the number of companies that are actively engaged and paying attention and wanting to learn, and so I think they are. We’re seeing a sector that’s getting very excited about the opportunities to participate.” 

‘No Guarantee’

But the Pathways milestone failed to dispel skepticism about the effort from entities still firmly situated in the Markets+ camp. 

Britney Morgan of Arizona Public Service, the sole committee member to abstain from voting on the proposal, said while Step 2 would incrementally improve the independence of the governance of CAISO’s WEIM/EDAM, it “does not achieve independent governance, which was the ask of the regulars more than a year ago.” 

“Under Step 2 … CAISO remains as the market operator, which perpetuates existing inequities between market and state participants,” Morgan said.  

Rachel Dibble, vice president of bulk power marketing at the Bonneville Power Administration, acknowledged “the significant amount of work” the Launch Committee and work group put into the Phase 2 proposal but said the plan fell short of BPA’s expectation for fully independent market governance, administration and operations for CAISO’s markets. 

Dibble reiterated three concerns BPA has recently expressed about the proposal: that it will 1) leave the RO under a single, integrated tariff shared with CAISO; 2) leave market operations, supporting staff and management functions under CAISO board authority; and 3) maintain the ISO as the counterparty in contracts with market participants.  

In an email to RTO Insider, Lauren Tenney Denison, director of market policy and grid strategy at the Portland-based Public Power Council (PPC), voiced a view that aligns with BPA’s. 

“Individual PPC members will evaluate the risks and benefits of this proposal in making their market participation decisions,” Tenney Denison wrote. “That said, for PPC and most of our members, the Step 2 proposal advanced by the Launch Committee falls well short of our expectations for independent governance. The limited creation of a ‘policy setting’ organization that continues to rely heavily on CAISO in many areas — financial, regulatory and staffing, for instance — will not establish a regional organization or market administrator that is independent. While potential future evolution is possible, there is no guarantee this will occur.”

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Pathways Initiative Approves ‘Step 2’ Plan, Wins $1M in Federal Funding

The West-Wide Governance Pathways Initiative’s Launch Committee voted Nov. 22 to approve the group’s “Step 2” proposal to create a new Western “regional organization” to provide independent oversight for CAISO’s Western Energy Imbalance Market (WEIM) and Extended Day-Ahead Market (EDAM).

The proposal passed on a nearly unanimous vote, with one abstention by committee member Britney Morgan, a regulatory consultant with Arizona Public Service, who said while APS agreed the plan represented “incremental” progress toward the goal of bringing independent governance to CAISO’s markets, it did not meet the utility’s standard for independence.

APS has been a funder and strong supporter of SPP’s Markets+, which is competing with EDAM for participants.

Other committee members were effusive in their praise for the proposal, with some citing that incrementalism as benefit for a Western region that has been historically suspicious of developing a centralized market, while others noted the “diversity” of interests that came together to develop the plan.

“Because the proposal creates a Western entity staffed by Western people, we strongly support this proposal as the best option for all of us,” said committee member Ben Otto, speaking on behalf of the Northwest Energy Coalition, an ardent EDAM supporter.

RTO Insider will follow up with a more detailed story about the vote and related discussion.

The vote came two days after Pathways received a significant financial boost from the U.S. Department of Energy, which awarded nearly $1 million to underwrite its efforts to establish a Western “regional organization” (RO) to oversee CAISO’s Western Energy Imbalance Market and Extended Day-Ahead Market.

The award was issued through the Pathways Initiative’s philanthropy advisor Global Impact, which the group’s Launch Committee partnered with earlier in 2024 to secure outside funding for its operations, which so far have been supported by donations — and volunteered staff — from its participants.

The award was part of nearly $10 million the administration granted to six projects nationwide intended “to improve state and regional engagement in wholesale electricity markets.”

An abstract of the application Global Impact submitted to the DOE’s Grid Deployment Office shows Pathways applied for $985,109 over two years to “support stakeholder convening, materials development, facilitation and personnel costs to achieve the goals of Phase 3 of the initiative,” which will include “refinement and formalization” of the RO’s stakeholder process, creation of “final governance documents and tariff language” for the RO, and identifying and hiring of the RO’s board and initial staff.

The most recent spreadsheet posted on the Pathways website in August shows that six organizations have committed to fund the second and third phases of the effort, including Clean Energy Buyers Association, California Community Choice Association, Balancing Authority of Northern California, Western Freedom, Microsoft and Amazon.

The Pathways Launch Committee’s “Step 2” proposal released Nov. 15 said the RO, to be established next year, would start out with “limited staffing” on an estimated budget of $1.25 million to $1.5 million, which eventually could increase to $10 million to $14 million. (See Pathways Initiative Issues Final ‘Step 2’ Proposal.)

The proposal also said the committee recognized that startup funding for the RO likely will “be required before any market supported funding is available” and that due consideration “should be given to identifying funding that would not be considered as compromising [RO] board independence.”

“The recommendation is to consider sources such as DOE grant funding or ongoing support from the Pathways Initiative 501(c)(3) funding via Global Impact,” the Launch Committee wrote in the proposal. “There was little stakeholder comment on this recommendation, though general support existed.”

The award represents a sharp turnaround for Pathways, which earlier this year was rejected for $800,000 in DOE grants because the agency said it lacked details about the scope of activities to be covered by the funding, which would have been dispersed in $400,000 tranches over two years. (See Pathways Initiative Rejected for $800K in DOE Funding and Past Opponents Now See Legislative Pathway to CAISO Regionalization.)