Page 121 – RTO Insider

March 25, 2024

PJM MRC/MC Briefs: March 20, 2024

Stakeholders Reject Changes to EE Measurement, Verification

VALLEY FORGE, Pa. — PJM’s Markets and Reliability Committee rejected four proposals to revise how the RTO determines how much capacity energy efficiency programs can enter into the capacity market. (See “PJM MIC Briefs: March 6, 2024.)

The proposals were built off the package PJM brought to the MRC in February, which sought to delineate the boundary between the two baselines against which EE providers can measure the savings from more efficient equipment and tighten qualifications for the baseline load, which tends to yield higher calculated savings than the standard baseline.

The PJM proposal received 51% sector-weighted support, short of the two-thirds threshold required. A proposal from Vistra Energy received 66.5% support, an alternative from CPower carried 38% support and another from Affirmed Energy had 31.5% support.

The PJM proposal would have required, among other changes, that EE providers have a contract with each individual end user, demonstrate that certain more efficient equipment would not otherwise have been installed, and account for any “leakage” of EE products purchased in one region but installed in another.

Affirmed Energy and CPower both brought alternate proposals they argued would not significantly impact EE participation in the capacity auction while still meeting PJM’s goal of enhancing measurement and verification of that capacity.

The Affirmed proposal focused on the impact to mid- and upstream EE programs, which seek to encourage retailers and manufacturers to offer more efficient products and share those products’ capacity market savings. Capturing savings at the retail level allows for small purchases to add up to the 100-kW threshold for EE participation in the wholesale market, a scale small residential consumers are unlikely to meet, Affirmed’s Luke Fishback said.

Fishback said PJM’s data collection requirements would require EE providers to receive consumer data for each retail EE product customer and enter a contract with each to obtain sole rights to enter those savings into the capacity market, which he argued would not be feasible and would eliminate much of that market’s aggregation.

The CPower proposal targeted PJM’s causation requirement for EE to qualify for the baseline load, which would have required that customers install equipment specifically to receive capacity market revenues. Senior Vice President Kenneth Schisler argued this would disqualify projects with multiple consumer benefits, such as home renovations improving insulation that may also be damaged by humidity.

The CPower proposal would have replaced PJM’s language stipulating that a project “would not have occurred absent participation in the wholesale market” with the need for “a direct connection to participation in the wholesale market.”

Both alternatives also took issue with PJM’s proposal that state technical reference manuals used to measure EE savings under the baseline load must be less than three years old. The Affirmed proposal would shift that to six years, and the CPower proposal to five.

Fishback said most TRMs issued by PJM states would have been invalidated under PJM’s proposal, requiring EE providers to instead study meter data, which he said would take too long to complete for the 2025/26 Base Residual Auction (BRA).

After the committee rejected the three proposals, Vistra offered a fourth revising PJM’s proposal to include a transitional period for the TRM limitations. Manuals less than five years old would be permitted for the 2025/26 BRA, four years for the following, and three years for 2027/28 and onwards.

Revised Reserve Requirement Study Values Endorsed

Stakeholders endorsed revised installed reserve margin (IRM) and forecast pool requirement (FPR) values accounting for inputs that changed following FERC’s approval of PJM’s critical issue fast path (CIFP) filing reworking its approach to risk modeling and accreditation. The new values were endorsed with 88% support at the MRC and passed by acclamation at the MC on March 20. (See FERC Approves 1st PJM Proposal out of CIFP.)

PJM’s Patricio Rocha Garrido said the need to recalculate was driven by several analytical developments since figures were approved by the committee in October and by fine-tuning made in recent months, as well as by parameters updated to better reflect resource pool changes. (See “Stakeholders Endorse Revised RRS Values,” PJM PC/TEAC Briefs: Feb. 6, 2024.)

The revised figures raise the IRM to 17.8%, an increase from 17.7% in the 2023 Reserve Requirement Study (RRS) results endorsed in October. The FPR would decrease to 0.9387, down from 1.1165 in the October values.

The Planning Committee voted in February to reset the two values, moving the figures in a similar direction to that endorsed by the MRC last week. The PC endorsed an IRM of 17.7% and an FPR of 0.9440.

Several resources that had submitted a notice of intent to offer into the capacity market were removed from the resource mix after PJM determined they are unlikely to come online prior to the start of the delivery year. Deactivations that were recently announced or not included in the original analysis were also removed from the expected available generation.

PJM and its Independent Market Monitor found that the characteristics of some resources had changed enough to warrant reclassifying their effective load carrying capability (ELCC) class. One of the prime reasons for this was a generator being reconfigured to run on a different fuel.

Some resources were also identified as having incorrect installed capacity (ICAP) values, particularly pseudo-tied generation, and some that had ambient derate tickets with variable megawatt reductions did not have the variability captured in their data.

MRC Amends Large Load Adjustment Forecast Issue Charge

The committee voted to revise an issue charge framing ongoing stakeholder discussion of how capacity assignments from forecasted large load additions are assigned to market participants in the same transmission zone. The proposal expands the scope of the discussion to consider load-serving entities (LSEs) able to control large load addition (LLAs) forecasts in their region. (See “1st Read of Proposal on Capacity Obligations Resulting from Large Load Additions,” PJM MIC Briefs: March 6, 2024.)

Mike Cocco of the Old Dominion Electric Cooperative (ODEC) said the unrevised language could grant sole control over the ability to submit forecasts to electric distribution companies (EDCs), including for any LSEs within their footprint. He argued that allowing a market participant to affect another participant’s load forecast is contrary to PJM’s basic market principles.

Joshua Burkholder of American Electric Power (AEP) said he supported the amendment as a minor clarification and improvement to the issue charge, noting that AEP was one of the document’s co-sponsors.

Dominion’s Jim Davis, the other co-sponsor, said the proposal being considered by the Market Implementation Committee will reflect some of the clarifications in the issue charge.

The proposal would exclude LLAs from the calculation of base zonal scaling factors and apply that load to the obligation peak load of the zone it is projected to be added to. LLAs are determined by PJM using information from LSEs about expected load growth and are detailed in the RTO’s annual load forecast reports under Table B-9.

Calpine Proposes Changes to Dual Fuel Classification

Calpine’s David “Scarp” Scarpignato presented a quick-fix proposal expanding the definition of dual-fuel resources to include units that start using their primary fuel and operate on secondary fuel. He said some gas-fired resources can start multiple times on the fuel present in the portion of pipeline leading to the generator, even if the pipeline feeding into that segment is offline or the generation owner has not entered a fuel contract. The quick-fix process allows for a problem statement and issue charge to be brought concurrent with a proposed solution.

The proposal would revise the Manual 34 definitions of dual-fuel combined-cycle and combustion turbine resources to require that they be capable of starting independently using “behind-the-fuel meter source” and then operate on the secondary fuel.

First Read on PJM Regional Planning Proposal

PJM’s Michael Herman presented a first read of the RTO’s proposal to create new long-term regional planning scenarios informing the development of the Regional Transmission Expansion Plan and state initiatives through the State Agreement Approach (SAA). (See “Stakeholders Long-term Regional Transmission Planning Proposal,” PJM PC/TEAC Briefs: March 5, 2024.)

The proposal would add five new scenarios: two base cases focused on reliability needs eight and 15 years out; two policy scenarios looking at new entry backed by state legislation eight to 15 years in advance; and an additional policy scenario including higher generation entry not backed by signed legislation. The two-year planning cycle would be extended to three years because of the increased number of scenarios. PJM’s current 10-year voltage analysis would be performed on the eight-year base scenario and include thermal analysis.

Herman said the scenarios are designed to capture evolutions the grid is expected to undergo over the next 15 years, namely 44 GW of load growth, 30 GW of generation deactivations and increased renewable energy penetration.

Ryann Reagan, of the New Jersey Board of Public Utilities (NJ BPU), said the new paradigm would provide the PJM planning team with a valuable new tool and that could aid other states follow NJ’s lead with using the SAA to pursue clean energy objectives.

Governing Documents Revisions Endorsed Through GDECS Process

Several changes to PJM’s governing documents were endorsed by the committee in line with the recommendations made by the Governing Document Enhancement and Clarification Subcommittee (GDECS). The revisions were approved by acclamation with no objections and several abstentions. (See “Other MRC Business,” PJM MRC/MC Briefs: Feb. 22, 2024.) 

PJM’s Michele Greening said terms being added to the documents’ definition sections are already defined in the existing language, but that language has not been duplicated in the definition section.

On March 20 and during the first read of the changes at the Feb. 22 MRC meeting, several stakeholders questioned if some of the package’s recommendations exceed the inconsequential nature of revisions typically drafted through the GDECS.

PJM also presented a first read on another set of revisions recommended by the GDECS, including a change to lowercase several references to “end-use customer” in the tariff around load management participation in the capacity market.

PJM’s Daniel Vinnik argued the terms were capitalized through a scrivener’s error and were not meant to suggest that consumers participating in demand response programs must be PJM members.

The second set of GDECS revisions are set to be voted on by the MRC on April 25 and the MC on May 6.

Other Committee Business:

Consideration of a quick-fix proposal to expand the winter availability window for demand response resources was spiked to the April 25 MRC meeting to give more time for sponsors to consider continuing pursuing changes through the expedited stakeholder process. Bruce Campbell, of Campbell Energy Advisors, said the sponsors may only seek endorsement of the issue charge next month, which would open a standard stakeholder process to explore if changes to the load participating in demand response programs and market changes made through the CIFP process warrant changes to the availability window.

PJM’s David Hauske presented a first read on a proposal revising the Operating Agreement, Tariff and manuals to add definitions of three synchronous condenser parameters — condense startup costs, condense-to-generate costs and condense energy use. He said the parameters are in use and there would be no change to PJM practices.

Members Committee

Advocates Concerned About Transparency over Filing Rights Changes

Greg Poulos, executive director of the Consumer Advocates of PJM States presented consumer advocates’ concerns over the openness of discussions between PJM and transmission owners on revising the consolidated Transmission Owners Agreement (CTOA) to shift Federal Power Act Section 205 filing rights from PJM members to the RTO.

Exelon Director of RTO Relations Alex Stern laid out the proposed changes to the Members Committee during its Feb. 22 meeting, where several transmission representatives noted that changes to the CTOA are made through negotiations between the Transmission Owners Agreement-Administrative Committee (TOA-AC) and the PJM Board of Managers. (See “TOs Considering Handing PJM Transmission Planning Filing Rights,” PJM MRC/MC Briefs: Feb. 22, 2024.)

While advocates have been pushing for PJM to plan more proactively, Poulos said negotiations to expand its filing rights and other associated changes to the balance between stakeholder and RTO authority should be public. He said that transmission owners speaking during the February MC meeting argued that the changes could have benefits to consumers; however, those consumers’ representatives do not have a voice at the table where those changes are being considered.

March 25, 2024

FERC OKs $142M Grand Gulf Settlement with Entergy Arkansas

Entergy will pay its Arkansas affiliate $142.3 million under a settlement FERC approved March 21, the latest in the ongoing billing dispute over the utility’s Grand Gulf Nuclear Station (ER22-958, ER23-435, ER23-816, ER23-1022, ER23-1164, EL24-5).

The company’s System Energy Resources Inc. (SERI) sells energy and capacity from the 1,443-MW nuclear plant in Port Gibson, Miss., to Entergy Arkansas and the utility’s three other operating companies under a cost-based formula rate.

Grand Gulf’s Unit Power Sales Agreement has been the subject of complaints of overcharging by regulators in Arkansas, Louisiana, Mississippi and New Orleans since 2017.

SERI said the new settlement is part of a $588 million deal filed in 2022. (See Entergy Offers Regulators $588M to End Grand Gulf Complaints.)

FERC also approved a partial settlement over Grand Gulf last April. (See FERC OKs Partial Settlement in Entergy Grand Gulf Row.)

In addition to the payment to Entergy Arkansas, the new settlement specifies that SERI will use a return on common equity of 9.65% in its monthly billings to the utility effective November 2023 and that no settling party can propose a change to the rate until at least June 30, 2026.

SERI also agreed to use a capital structure with an equity ratio not to exceed 52%.

The commission said the settlement was in the public interest because it was uncontested and appears to be fair and reasonable.

March 25, 2024March 26, 2024

SPP Board Approves Markets+ Phase 1 Tariff

SPP’s Board of Directors approved the initial tariff for its Markets+ service offering in the Western Interconnection March 25, clearing the way for its filing at FERC.

Board Chair John Cupparo called the action an important step, but not the last, in continuing SPP’s development of the day-ahead market. Markets+ is just one of several western expansion initiatives, which include SPP RTO West and an imbalance market.

“We don’t know exactly what the outcome is going to be [as] SPP continues to prudently pursue this western expansion, given the long-term potential of this expansion,” he said. “Another way to say that is five, 10, 15 years from now, I wouldn’t want to be in the position of answering the question, ‘Why didn’t you pursue this?’”

SPP is competing with CAISO’s Extended Day-ahead Market (EDAM) to attract western entities to Markets+. FERC already has approved the bulk of EDAM’s tariff, and last week, Portland General Electric and Idaho Power signaled their intent to join the CAISO market. That increases EDAM participants to five members. (See CAISO Wins (Nearly) Sweeping FERC Approval for EDAM and CAISO’s EDAM Scores Key Wins in Contested Northwest.)

SPP’s Markets+ development phases. | SPP

“Based on experience in the West, it is always a challenge to completely get our arms around what entities in the West will do and what they’ll ultimately decide,” said Cupparo, a Colorado resident with western utility experience. “We’re still entering that phase right now. There are many variables and diverse perspectives that will influence these decisions.”

The tariff’s filing will complete the first phase of the Markets+ development. SPP lists 38 western entities as having participated in drafting the tariff and its protocols.

The grid operator hopes to receive FERC approval by year’s end. In the meantime, SPP and interested participants will develop and negotiate funding agreements for the second phase. SPP will file at FERC a financing approach, projected to be about $140 million plus financing costs.

Once FERC has approved the tariff, SPP will begin acquiring and modifying the necessary software, hardware and related processes. Phase 2 work will begin next year after the financing approach is approved.

“I think we’re probably several years away from parties participating in Markets+ and deciding that they’ve gotten comfortable with the regionalization to the level where they’re now interested in pursuing an RTO,” said Antoine Lucas, SPP’s vice president of markets.

The motion to approve the tariff cleared the Members Committee’s advisory vote, 15-1, with four abstentions. The Natural Resources Defense Council’s Christy Walsh cast the lone dissenting vote over concerns the tariff isn’t complete.

Markets+ stakeholders and SPP staff have been working together since last year putting together the tariff’s various pieces. The Markets+ Participants Executive Committee has held 86 votes on tariff language since August, with an average approval rating of 97.72%. Several identified tariff elements were postponed because of the time necessary to resolve them.

Lucas reminded members the tariff they were voting on does not include the second phase. That will include contractual obligations that set cost recovery and financial obligations associated with the market’s implementation.

“This being a standalone service, the funding for that service will be taken care of by the participants in the process itself,” he said.

CFO Sterzing Resigns

SPP CEO Barbara Sugg announced during a break in the call that Deborah Sterzing submitted her resignation March 22 as the grid operator’s chief financial officer.

“We hate to see her go. We certainly wish her well in her continued career within our industry,” Sugg said.

David Kelley, vice president of engineering, has been appointed interim chief financial officer. He is already involved in several financial activities for SPP, Sugg said.

Sterzing joined SPP in February 2023. She replaced longtime CFO Tom Dunn, who retired in 2022 after 21 years at the financial helm.

March 25, 2024March 26, 2024

NE Energy Officials Stress the Need for Dispatchable Resources

As intermittent renewables proliferate in New England, the region must do a better job incentivizing reliable, dispatchable resources that can support the grid as it decarbonizes, speakers at Raab Associates’ New England Electricity Restructuring Roundtable emphasized March 22.

“We cannot remove conventional generation before we stand up its replacement,” said Charles Dickerson, CEO of the Northeast Power Coordinating Council, adding the region will face shortfalls if it fails to heed this warning.

“The more renewables we have, the more I get prickly around adequacy,” Dickerson added. “It’s not how much is there; it’s how much is there when you need it.”

Gordon van Welie, CEO of ISO-NE, said the RTO’s ongoing efforts to reform its capacity market should help New England more efficiently ensure resource adequacy, but added that more changes likely are needed to align the region’s wholesale electricity markets with the clean energy transition. (See ISO-NE Moving Forward with Prompt, Seasonal Capacity Market Design.)

“I can’t miss the opportunity to make a pitch about carbon prices,” said van Welie, who has long expressed support for the concept but has indicated ISO-NE would need support from all New England states to proceed. (See ISO-NE: States Must Lead on Carbon Pricing.)

Van Welie said the RTO anticipates increasing renewable energy will reduce revenues from the energy market, requiring more money to come from the capacity market and state-led power purchasing agreements. A carbon price could help prevent an over-reliance on the capacity market and PPAs, van Welie said.

“You’d tax the carbon emissions at source, put that into the offer price, but then you would rebate the money that you’re collecting from those carbon emissions directly back to load at the wholesale level, so you’d mitigate the price impact,” van Welie added. He called the mechanism “an elegant way of trying to balance the consumer impact with the incentives needed to drive the thing you want, which is to reduce carbon emissions.”

Dickerson noted that inverter-based resources also bring new challenges related to ride-through capabilities and cybersecurity threats, and that standardization is needed to ensure resources meet the technical requirements needed for grid reliability.

“We’ve had no less than five or six episodes across the country where an inverter-based resource may have tripped offline because of what we can call a normal blip,” Dickerson said. “Not only did that particular inverter-based resource come offline, it took all the inverter-based resources offline that were connected to it. That’s unsustainable.”

While Dickerson stressed that the risks associated with inverter-based resources have already arrived, van Welie said the Eastern Interconnection likely is “fine for the next five years,” with problems likely emerging “around 10 years out.”

Batteries can use synthetic inertia to help mitigate the loss of spinning thermal resources, “but the inverters need to be designed to do it,” van Welie said, adding this will likely require some type of regulation.

Commissioner Katie Dykes of the Connecticut Department of Energy and Environmental Protection acknowledged the need to ensure grid reliability as the resource mix changes but said the region must continue to accelerate the deployment of clean energy.

“We really have to scale up all our efforts in regards to clean energy if we’re going to achieve our goals,” Dykes said.

Dykes said carbon pricing is “an important tool,” but added it’s “just one tool, and we need a number of different tools in order to see the new entry coming in that can maintain reliability at a rate that ratepayers can afford.”

Dykes added that future procurements could extend to developing generation technologies like advanced nuclear, geothermal and hydrogen fuel cells. She said she’s heard from developers that investing in advanced nuclear projects makes little sense in restructured markets compared to vertically integrated markets.

“We can’t afford to take those types of things off the table,” Dykes said. “We have to figure out how to accommodate them.”

The commissioner highlighted the efforts of Connecticut, Massachusetts and Rhode Island to coordinate offshore wind procurements — bids are due for all three states March 27, with the winning bids to be selected in August. (See New England States Delay Offshore Wind Solicitations.)

Dykes called the coordinated procurement “a template for multistate coordination,” while advocating “predictable, regular auctions” going forward.

“We’re in a moment of extraordinary collaboration,” Dykes said. “That’s what gives me encouragement.”

Liz Anderson, chief of the Energy and Ratepayer Advocacy Division at the Massachusetts Attorney General’s Office, stressed the need to keep ratepayer interests front and center. Anderson said the region should consider the cumulative impacts of programs and investments on electricity costs when designing programs, noting that skyrocketing costs will hinder the clean energy transition.

“A lot of conversations are happening in silos,” Anderson said. “We need to start thinking more holistically about all these costs together.”

March 25, 2024March 26, 2024

‘Converting to EVs not Sufficient’ to Reach Climate Goals

WASHINGTON ― Working at a state transportation department used to be pretty humdrum, according to Tim Sexton, who started his career at the Department of Transportation in Washington state.

“Transportation used to be departments of highways or departments of roads,” said Sexton, who now is assistant commissioner for sustainability, planning and program management at Minnesota’s DOT. “Now you have some states … saying, ‘You know, we can do more,’ and what we’re saying is, anything that touches transportation, and especially transportation and climate, we want to have a role in and want to try to lead on … and it’s partly out of self-initiative, but also partly because our hand is being forced.”

Sexton was one of four panelists speaking about how to build clean, sustainable transportation systems, at the 2nd Annual U.S. Tech for Climate Action Conference. The conference’s tech focus notwithstanding, the transportation panel was less concerned with specific technologies and more interested in digging into the research, policies and public-private partnerships needed to ensure access to clean, convenient mobility across a broad range of urban and rural environments.

“As we start to look at state goals for decarbonizing the economy, transportation plays a role” as a top emitter of greenhouse gases at both national and state levels, Sexton said of Minnesota’s more holistic approach. “We look at this as a three-legged stool of vehicles, operations and fuels. A low-carbon fuel standard … could be a big part of the solution, too, so let’s get involved with that.”

The Minnesota DOT also has waded into the politically sensitive topic of locating transmission along existing transportation rights-of-way, Sexton said. “The biggest obstacle to transmission is property rights, and if you have linear corridors that mirror our highways, that could really facilitate a lot of transmission,” he said. “How do we support that in a way that balances competing needs?”

Colin Tetreault, senior manager for climate change and sustainability services at EY, formerly Ernst & Young, agreed that the past 10 to 15 years have seen “a better understanding of an evolutionary thesis of what we’re solving for.”

“We used to think about kind of single-passenger conveyance, or how do we move a car from point A to point B,” Tetreault said. “That model [and that] decision calculus [is] changing … to how do we move goods, ideas, people and services safely, effectively, affordably, efficiently and equitably?”

The equity and environmental justice focus in transportation policy also is a major change, he said. “When you think about access to food, to health, to education, it is a … travesty that people do not have good access to transport and what that does to hinder community- and state-level growth. … These things don’t exist in a vacuum because they are layered together,” he said.

“Converting to EVs is not sufficient … to get us to net zero by 2050,” said Gretchen Goldman, director of climate change research and technology at the Department of Transportation, referring to President Joe Biden’s goal for economywide decarbonization. “And so that means also investing in transit … and really making sure that we’re diversifying in mode choice in lots of ways.”

A priority for DOT is focusing on different contexts and different communities, and how to apply new technologies “because it’s not going to be the same as what it looks like in urban spaces and similarly on tribal nations and lands.”

Greening Rideshares in NYC

In New York City, combining transportation equity and decarbonization has meant looking closely “at modes of transportation that are used on a day-to-day basis in everyday lives of New Yorkers, but are simultaneously modes of transportation that we have control over,” said Isabelle Thomas, policy adviser for living streets and public spaces.

Exhibit A, Thomas said, is the Green Rides Initiative, which has set a target for all vehicles in the city’s rideshare fleet ― taxis, Ubers and Lyfts ― to be either zero emission or wheelchair accessible by 2030. For 2024, 5% of “all high-volume for-hire trips” will have to be zero-emission or wheelchair accessible, rising to 15% in 2025 and 25% in 2026 and then increasing by 20% per year to reach 100% by the end of the decade, according to a city website.

Overseen by the city’s Taxi and Limousine Commission, the initiative means “we’ve already taken care of a part of what is a 78,000-vehicle fleet that’s on our streets every day,” Thomas said.

NYC also is working on electrifying its school bus fleet by 2035, drawing on a combination of state and federal funds, Thomas said. On March 18, Mayor Eric Adams announced New York City had received $61.1 million in federal funds from the Infrastructure Investment and Jobs Act, which would be used to buy 180 new electric school buses (ESBs), quadrupling the total number of ESBs in the city’s fleet.

An additional $15 million from the U.S. DOT will go toward a “freight-focused” electric truck and vehicle charging depot to be located in the Hunts Point Food Distribution Center, one of the state’s busiest trucking hubs, according to the announcement’s press release.

Another key component of NYC’s strategy for transportation decarbonization, Thomas said, is ensuring all New Yorkers can find DC fast chargers within 2.5 miles of where they live or work.

Building a Used EV Market

Consumer engagement was a major factor for Minnesota’s adoption of California’s Advanced Clean Cars II (ACCII) rule, which requires that all new light-duty vehicles sold in the state be zero emission by 2035.

“We went around the state and everybody said, ‘We should have more electric vehicles in the state, but we can’t get them here. [We] have to go to another state because of where we are in the middle of the country.’ You had to go quite a way to get an electric vehicle,” Sexton said.

According to Conservation Minnesota, a nonprofit advocacy group, only about half the models of EVs available on the market are for sale in the state.

Public health and equity also were drivers for ACCII, Sexton said, “If we don’t have vehicles coming into the state, especially new vehicles, we’re not going to have a used vehicle market either, and without that used vehicle market, not everyone is going to be able to get into an EV.”

Sexton also talked about Minnesota’s approach to transmission siting along highway rights-of-way, working with a group called NextGen Highways to look at the opportunities and challenges. To begin with, rights-of-way are a “constrained resource,” he said. “There [are] not unlimited amounts of it. …

“There’s a lot of stuff buried alongside the road and underneath it, whether it’s water, sewer, fiber,” which requires “being really thoughtful about when, how [and] where are we allowed to access” these sites, Sexton said. Permitting these projects means making sure “you have evaluated all the options, and this is the best path,” he said.

According to a 2022 NextGen feasibility study, undergrounding HVDC and broadband lines in highway rights-of-way could help prepare Minnesota’s grid for transportation electrification ― and the installation of DC fast chargers ― while increasing opportunities for remote work, online learning and other online services. The result could be an overall decrease in vehicle miles traveled in the state, the report says.

Sexton sees potential in linking reduction of vehicle miles traveled to rethinking and reform of land use, such as making communities more pedestrian and bicycle friendly. “I don’t know if I want to live in a community [where] everybody has a car and everybody is driving and spending two hours one way to get to work,” he said. “Even if it’s not polluting, is that the way you want to live?”

Going Further, Faster

While providing unprecedented funding for a range of decarbonization initiatives, the IIJA and Inflation Reduction Act have posed challenges for state government agencies that have to interpret and implement the new programs. But, Sexton said, the direction coming from federal agencies is as important as, if not more important than, the money.

Panelists generally agreed that cross-agency and cross-stakeholder input and planning are essential parts of designing and implementing effective, successful programs. Tetreault favors working with regional economic development agencies, rather than industry trade groups.

Economic development agencies are more likely to look at “smart, equitable, clean and green jobs … [as] a growth vertical. Latching onto that in order to indicate there’s economic prosperity coupled with decarbonization tied to things like transportation, I think, carries a message further,” he said.

Minnesota has formed a Sustainable Transportation Advisory Committee, which includes regional development agencies, state and local government officials, and some of these agencies’ strongest critics, Sexton said. “We made the commitment that we would respond, not that we’d accept every recommendation, but we’d facilitate the conversations,” he said.

At the same time, Tetreault also stressed the importance of regulatory certainty for driving capital to specific markets, regardless of federal incentives. The best policies provide both carrots and sticks, he said. “Capital will follow certainty. It will stay where it’s treated well. [It] will continue to grow where it feels warm.”

In the face of the coming elections and potential regulatory changes, public-private partnerships could provide a way to use existing policy with capital, and provide a broader range of creative financing options, he said. State and sub-state contracts could include “things like disclosure [and] environmental performance standards,” he said.

“Providing a vector for the capital markets to have verifiable opportunities and then to keep [them] verifiable through good disclosure management systems … we can align public and private for quick reaction,” he said. “Working together, we go further, and we go faster.”

March 25, 2024March 26, 2024

DOE Study Adds to Case for Interregional Offshore Grid

An interregional transmission network for the East Coast’s offshore wind could produce almost $1.6 billion annually in generation savings and improved reliability versus radial lines, according to a study released by the U.S. Department of Energy last week.

The Atlantic Offshore Wind Transmission Study calculated substation and cable costs for a 2050 “low-carbon” scenario with 85 GW of offshore wind from Maine to South Carolina. The analysis considered four offshore transmission topologies against a reference case using radial lines for each project with no links between offshore platforms:

- an intraregional topology with connections within regions;
- an interregional topology connecting diverse regions;
- an inter-intra topology combining the links in the interregional and intraregional topologies; and
- a backbone grid that adding interregional plan an additional cable running from Maine to South Carolina.

The analysis, by researchers from the National Renewable Energy Laboratory and the Pacific Northwest National Laboratory, found that each of the four networked topologies had higher benefits than costs and that the interregional plan produces the highest benefit-to-cost ratio and total net value.

Networking offshore transmission would reduce offshore wind curtailments (1 to 2 percentage points below the radial topology) and the use of higher-cost generators, DOE said. It would also increase reliability by providing alternatives during outages of other transmission lines or generation, particularly during winter peak conditions.

“In modeled estimates using the radial topology in 2050, price differences between suitable POIs for offshore wind averaged over $100/MWh,” the report said. “This price difference is higher than the average wholesale electricity prices in recent years in some Atlantic market regions. High price differences indicate that offshore transmission with interlinking platforms can consistently flow power from lower- to higher-price regions to benefit electricity consumers by reducing the costs of generating electricity.”

Intraregional, interregional, and backbone transmission topologies | National Renewable Energy Laboratory

The researchers’ modeling of the networked transmission showed that flows on all interlinks go both directions every season, with an average utilization rate of 50 to 60% of the available capacity on each line. An interregional grid with a 14,000-MW capacity could displace up to 4,700 MW of firm generation capacity, the researchers said.

The base radial plan is estimated to cost $96.3 billion. The interregional grid would add $11.4 billion in capital costs, with annualized capital and operations and maintenance costs of $840 million. But DOE said it would produce benefits of $2.4 billion annually, a benefit-to-cost ratio of 2.9.

The backbone topology provides the second-largest ratio of 2.7, with annualized costs of $1.47 billion and benefits of $3.9 billion per year.

The analysis envisions building offshore transmission in phases to reduce development risk and assumes the first offshore wind projects would be connected to the grid with individual radial lines. But researchers said, “early implementation of high-voltage direct current (HVDC) technology standards is essential for future interoperability.”

The only potential negative identified by researchers: Offshore wind could be vulnerable to extreme weather in the ocean and at landing points.

DOE’s report adds to earlier research on the benefits of a planned Atlantic offshore grid, including a 2023 Brattle study that estimated coordinated transmission planning could produce at least $20 billion in transmission-related cost savings, 60 to 70% fewer shore crossings and a reduction of about 50% in marine transmission cables (2,000 fewer miles) on the seabed. (See OSW Transmission Planning Must be Interregional, Networked and Start Now.)

Implementation Steps

DOE’s study was accompanied by an action plan from DOE’s Grid Deployment Office that identifies the steps researchers said would be required to implement the transmission buildout. It calls for establishing collaborative bodies spanning the Atlantic Coast this year to plan transmission and cost allocation during the second half of the decade.

It encourages RTOs and other transmission providers to simultaneously evaluate multiple benefits beyond reliability or production cost savings.

In its transmission planning and cost allocation rulemaking, which FERC is expected to finalize this year, the commission proposed developing long-term scenarios for use in regional planning, with an increased role for states in facility selection and cost allocation. FERC has also proposed a minimum set of benefit categories with methods to quantify them (RM21-17). (See FERC Watchers Weigh in as Transmission Rule Approaches Finish Line.)

Among the “Immediate Actions Before 2025” in the action plan is voluntary cost-allocation assignments. “Transmission cost allocation is a notoriously thorny issue that is intensified by the scale of projects and large price tags associated with interconnecting offshore wind,” DOE said. “In fact, the Business Network for Offshore Wind [recently renamed the Oceantic Network] described the issue of who pays as ‘the hardest single problem for transmission.’”

‘Most Thorough Analysis’ to Date

DOE called its two-year study the most thorough analysis to date of options to bring the East Coast’s wind energy — projected to be a key part of the region’s decarbonization — ashore.

The study focused on the offshore region between Maine and South Carolina and the onshore grid in those states, plus Vermont and Pennsylvania due to their proximity to the Atlantic. The 85-GW scenario for 2050 projects 27 GW of OSW injection into ISO-NE; 19 GW into NYISO, 26 GW into PJM and North Carolina, and 13 GW into the SERC Reliability Corp. region in North Carolina and South Carolina. Offshore wind would represent more than 20% of generation in NYISO and PJM and more than 40% in ISO-NE.

The report identifies potential transmission corridors considering environmental concerns and other uses such as military zones and shipping channels. The researchers cautioned that their analysis did not have the level of detail of interconnection studies and was not intended to prescribe exact injection points.

March 25, 2024March 25, 2024

WEIM Expert Calls for Fast-start Pricing to Address ‘Anomalies’

Fast-start pricing could fix certain “price anomalies” in CAISO markets more effectively than existing mechanisms for compensating ramping resources, the Western Energy Imbalance Market Governing Body’s market expert told the group.

“The primary objective of fast-start pricing is to provide a more efficient price signal when fast-start units are dispatched to meet load,” Susan Pope, an electric power consultant appointed to assist the WEIM body, said during the group’s March 19 monthly meeting.

“The more accurate fast-start pricing signal cannot always and will not always be provided by either the flexible ramping product or shortage pricing,” Pope said.

Out of the six FERC-jurisdictional organized markets, CAISO alone doesn’t use fast-start pricing, a mechanism that factors the cost of starting and operating gas-fired peaking units into the wholesale market price.

According to a June 2022 analysis published by Powerex and the Portland, Ore.-based Public Power Council (PPC), CAISO and its Department of Market Monitoring (DMM) have actively opposed fast-start pricing and instead chose to rely on out-of-market payments to individual units to enable them to break even on daily variable costs.

But absent fast-start pricing, market prices may not reflect the cost of meeting incremental load when starting and operating natural gas units to meet peak demand, undermining the accuracy of pricing in the WEIM — and, paradoxically, causing participants to potentially pay more than necessary in some intervals.

“The understated price could incorrectly encourage parties to schedule additional exports, even though the price for meeting the export schedule in the dispatch could turn out to be higher than the understated price they actually end up paying,” Pope said. “The flip side of this is that the price signal for incremental supply is also understated, which sends the wrong signal to encourage incremental supply to offer the dispatch.”

Pope also pointed out the 2022 report may have substantially overstated the potential price impact of fast-start pricing due to a lack of nonpublic data CAISO since has gained access to.

In December, CAISO presented its own analysis of fast-start pricing and sought stakeholder feedback for developing its scope.

Flexible Ramping and Shortage Pricing

Other pricing mechanisms, such as the flexible ramping product and shortage pricing, won’t fix the fast-start pricing issue, Pope said, because while they can overlap and trigger simultaneously, they operate under different grid conditions and provide distinct functions.

“The underlying reason why the flexible ramping product and shortage pricing will not fix the fast-start pricing anomaly is at root because the three pricing enhancements are aimed at fixing different things,” Pope said. For example, fast-start units could be dispatched to meet load when there is neither a flexible ramping constraint nor a capacity shortage, meaning that neither of the alternatives can be relied upon to substitute fast-start pricing.

Impact on the WEIM

The use of fast-start resources to meet incremental load would increase locational marginal prices and potentially reduce emissions, Pope said.

“One of the possible benefits of fast-start pricing is to enable others who are not required to bid or offer into the market to see the higher price and choose to participate, and by their participation, offer the opportunity to displace the start-up of more costly emitting units,” she said. The higher prices also could improve market efficiency by increasing the number of bids and offers, she added.

The potential environmental impact of not using fast-start pricing was a key concern outlined in the 2022 analysis, which identified that lack of the price signal could weaken carbon-pricing programs.

“The calculation of wholesale market prices in CAISO-operated markets not only excludes the cost of starting and operating natural gas peaking units, it also excludes the cost of GHG emissions from those units, which can be among the highest in the grid,” the report reads. “This undermines a key goal of carbon-pricing programs, including California’s cap-and-trade program as well as programs being explored by multiple other Western states.”

Fast-start Pricing in Other Markets

Examining the efficiency of fast-start pricing in other RTOs and ISOs can offer CAISO insight into how the mechanism could operate in its markets, Pope said.

Fast-start pricing has been a feature of NYISO since 1990 and MISO since 2010, and independent market monitors are divided on their views on the mechanism.

According to Potomac Economics, the IMM for NYISO, MISO and ERCOT, fast-start pricing has “significantly improved real-time price formation in MISO” and “has led market price signals to better reflect system conditions and provide better performance incentives for flexible resources when fast-start units are deployed” in NYISO.

PJM IMM Monitoring Analytics takes a dimmer view, finding that fast-start pricing distorts “the correct signal for efficient behavior” and inappropriately pays higher prices to inflexible generators.

And in 2023, CAISO’s DMM said fast-start pricing “is inconsistent with the features of locational marginal pricing that maximize market surplus and provide incentives for units to operate at the most efficient, socially optimal dispatch level.”

It’s unclear whether an existing fast-start pricing design could be added easily to the WEIM of the ISO’s Extended Day-Ahead Market. Even if the mechanism is effective in other regions, Pope said, market changes would be needed to reflect the scheduling and pricing modeling runs used for WEIM dispatch, which CAISO still is studying.

Regardless of the challenges, WEIM Governing Body members appeared open to considering fast-start pricing.

“It is a subject of great interest and much debate, and I think we could all use a greater understanding of this and how it applies in the current West,” said WEIM Governing Body member Robert Kondziolka.

March 25, 2024March 26, 2024

‘Evolution’ Key Theme at IPPNY 2024 Spring Conference

ALBANY, N.Y. — The Independent Power Producers of New York (IPPNY) celebrated its annual spring conference March 19 by marking the state’s transformation into a competitive energy market over the past 25 years with the inception of NYISO.

Industry experts from the government, business sector and advocacy groups shared their insights on New York’s progress in evolving its energy markets, echoing sentiments from last year’s conference. (See Overheard at IPPNY 2023 Spring Conference.)

FERC Chair Willie Phillips discussed how the commission’s priorities have shifted toward improving “transmission to figure out how to better integrate new resources onto the grid,” enhancing the “grid’s physical and cybersecurity infrastructure,” and promoting environmental justice, which he considers a “top priority.”

Suedeen Kelly, a partner at Jenner & Block and former FERC commissioner, concurred, saying that while the initial goals of establishing competitive markets centered around “efficiency, lowering costs and innovation,” they have shifted to include “decarbonization and the recognition of environmental and social justice” as the grid and energy markets have evolved and new generation technologies have emerged.

Kelly praised New York’s market evolution, thanking participants for their efforts “to continue to meet the challenges of new technologies and incorporating those technologies into your market, since you’re taking huge risks to do this.”

IPPNY President Gavin Donohue remarked in the same panel that the “competitive energy market has evolved into a bipartisan issue,” which will help to “lay the foundations for the future.”

New York Public Service Commission Chair Rory Christian emphasized the theme of market evolution during his keynote address, highlighting how the commission’s decisions ensure that New York’s energy markets continue to adapt with the times. “Our daily lives depend on our ability to wield the magic of new technologies” he said, and “our actions can mean the difference between opportunity and calamity and can have ripple effects that extend far beyond our state borders.”

“The commission has been able to lead and innovate,” he added, recognizing the need to develop a more holistic and adaptable approach that “ultimately culminated in a departure from vertically integrated utility models to a restructured wholesale energy market that incorporates competition.”

C. Lindsay Anderson, a professor of biological and environmental engineering at Cornell University, spoke about the growing recognition among New York energy stakeholders that to meet the state’s energy priorities and mandates and “to decarbonize everything, [we must] first decarbonize the power system.”

Panelists at the “Lobbying the Legislature and Executive Branch – Important Topics this Session” panel discussed how their clients and objectives have also evolved in response to New York’s policies.

Elizabeth Garvey, an attorney at Greenberg Traurig, noted how she’s observed a shift in how political and corporate clients focus on broader engagement.

“These years, unlike past years … [clients] really focus on all of [the market’s] issues wherever they sit in the energy economy … even if it doesn’t directly impact [them],” Garvey said.

She added that the state’s evolving market and policies have led to an “inflection point” where it has become increasingly difficult to tell clients “where they should park their capital” since “there are so many different things happening on so many different playing fields” both in New York and across the nation.

Will Hazelip, president of National Grid Ventures, US Northeast, said modernizing the transmission system is one of the biggest future challenges for New York and the country.

“Redoing the transmission system will help enable power to move around” and also help clients “know for certain when they can build and then plug in,” he said.

Phillips summarized the evolving perspective of conference panelists and the wider industry, saying, “As we celebrate the 25th anniversary of the [New York] market, the subtitle has been ‘cleaner, safer and cheaper,’” but “what I now say is ‘reliable, affordable and sustainable.’”

“We need a new generation to think differently about our problems,” Phillis said, noting how energy markets, technologies and policies have evolved.

The industry can no longer pretend “the benefits of our transition fall evenly on everyone,” he said.

March 25, 2024March 26, 2024

Texas PUC Establishes $5B Energy Fund

The Texas Public Utility Commission on March 19 adopted a rule establishing the Texas Energy Fund In-ERCOT Generation Loan Program, a $5 billion fund designed to bring new dispatchable power projects to the state.

The rule establishes the fund’s application process, project eligibility requirements, evaluation criteria and loan terms. The low-interest loans can be used for new dispatchable generation facilities or to expand existing facilities within ERCOT (55826).

Qualifying projects for the Texas Energy Fund (TEF) must add at least 100 MW of new dispatchable capacity to the grid. The PUC says the program can support up to 10 GW of new or upgraded generation capacity in ERCOT.

“As our state’s population and economy grow, so does the demand for electricity, and we must ensure Texans have the power they need, when they need it,” PUC Chair Thomas Gleeson said in a statement. “This rule lays a strong foundation for the Texas Energy Fund’s success and for future investment in the state.”

Speaking on a panel during the recent CERAWeek 2024 by S&P Global conference in Houston, NextEra Energy’s Michele Wheeler, vice president of regulatory and political affairs, said the market indicates the fund will be oversubscribed.

“We hope that’s the case,” she said.

NRG Energy’s interim CEO, Larry Coben, said in February the company plans to apply for up to $900 million in TEF loans to finance construction of two new natural gas-fired plants that would be available in 2026. Coben reiterated during CERAWeek that the two peakers and another baseload plant will add 1,500 MW to the Texas grid.

Companies can begin applying for the in-ERCOT program June 1. Initial disbursements for approved loans will be issued by Dec. 31, 2025.

However, supply chain issues could pose a significant roadblock, commissioner Jimmy Glotfelty said during the March 21 open meeting. He recounted a conversation he had during CERAWeek with a Siemens senior executive.

“He said, ‘Good luck with getting a combustion turbine before 2031,’” Glotfelty said. “If the market [is] seeing a massive delay in this major equipment, I think that is something that really has to be conveyed to the legislature and to us so that we don’t get in a bind.”

One of the TEF’s four programs, an early completion bonus, awards grants to new dispatchable generation facilities that meet certain planning requirements after June 1, 2023, and interconnect to the ERCOT grid before June 1, 2029.

The commission agreed with stakeholders to change the rule’s performance standards and ordered the revisions during the meeting. The performance availability factor (PAF) was reduced from 90% to 85% and the performance outage factor (POF) rose from 10% to 15%.

Gleeson said in a memo he was persuaded by commenters who said the performance metrics would be “very difficult to achieve” throughout the loan’s term for units operating under standard operating processes. The commenters said that because of the length of planned maintenance outages and “unforeseen operational issues” during the early years of a plant’s life, additional flexibility in the PAF and POF metrics is “both necessary and reasonable,” Gleeson said.

In addition to the In-ERCOT Generation Loan Program, the rule establishes TEF programs providing:

- completion bonus grants for new dispatchable generation projects that “consistently provide power generation over a 10-year period”;
- grants for companies to establish or secure back-up power resources; and
- grants to improve electric service resiliency and availability outside the ERCOT region.

The Texas Legislature could provide additional TEF funding in future years, the PUC said.

PUC staff determined switchable resources providing energy to both ERCOT and SPP are not eligible for the fund, as they are not totally committed to the Texas market. However, they will be eligible for completion bonuses because the law does not make a distinction between ERCOT and non-ERCOT resources.

“We want 100% of the new capacity generated to be dedicated to the ERCOT market,” PUC staffer David Smeltzer said.

The TEF is a result of legislation passed last year (Senate Bill 2627). Texas voters overwhelmingly approved the fund in November as a constitutional amendment. (See 2023 Elections Bring Billions for Texas Gas, Dem Wins in Virginia, NJ.)

“Voters … made it clear that reliable electricity is a top priority,” the bill’s author, state Sen. Charles Schwertner (R), said. “We must expand and strengthen our on-demand, dispatchable power generation in order to deliver the reliable electricity all Texans expect and deserve.”

ERCOT Preps for Solar Eclipse

ERCOT COO Woody Rickerson told the commission the grid operator is preparing for the April 8 total solar eclipse and does not expect reliability problems, using lessons learned from October’s annular eclipse.

“ERCOT will pre-posture the system just like we did previously as necessary to meet both [solar’s] down ramp and the up ramp,” he said.

The eclipse will cross Texas from the southwest to the northeast between 12:10 p.m. and 3:10 p.m. CDT, with sun coverage ranging from 81 to 99%, ERCOT said. Solar generation is projected to dip as low as about 7.6% of its maximum clear-sky output at about 1:40 p.m.

“That’s a pretty big ramp down,” Rickerson said. “We are fortunate that this solar eclipse is occurring in April and not August.”

ERCOT is working with solar forecast vendors to ensure models account for the eclipse’s effect. Ancillary services will be used for additional balancing needs. The first market notices will go out March 28, with additional communications to the market following.

The ISO breezed through a test case in October. Solar production dropped from just over 7,000 MW to 1,474 MW as the eclipse’s “ring of fire” traversed Texas. Natural gas resources helped compensate for the solar drop, increasing generation by more than 4,000 MW increase. (See ERCOT Smoothly Handles Annular Solar Eclipse.)

Texas A&M University’s Smart Grid Center has made public a visualization of the eclipse’s effect on solar generation across Texas. ERCOT has about 22 GW of installed solar capacity.

March 25, 2024April 2, 2024

PJM Awaiting FERC Response to Court Rejection of 2024/25 Capacity Auction Parameters

VALLEY FORGE, Pa. — The future of the 2024/25 Base Residual Auction (BRA) results is uncertain following a ruling from the 3rd U.S. Circuit Court of Appeals partly vacating a FERC order authorizing PJM to change an auction parameter after bids had been received (ER23-729). 

The court’s March 12 ruling found the commission violated the filed rate doctrine in accepting a PJM proposal to revise the locational deliverability area (LDA) reliability requirement for the DPL South zone, which covers much of the Delmarva peninsula.

PJM sought the change after identifying a nearly fivefold increase in capacity prices due to the interaction between a “misalignment” in resources that offered into the auction and the expected resource pool with the determination of the reliability requirement. (See 3rd Circuit Rejects PJM’s Post-auction Change as Retroactive Ratemaking.)

Speaking during the March 20 meeting of the Markets and Reliability Committee, Senior Counsel Chen Lu said the RTO anticipates court approval for a new course of action about early May, following a 45-day deadline for FERC to propose a new directive for PJM and about seven days for the court to review. He added PJM is not planning to request a rehearing or appeal of the ruling to the Supreme Court. That option is open to FERC and intervenors in the case.

PJM Vice President of Federal Government Policy Craig Glazer said if rehearing or an appeal is sought, that could delay PJM knowing how to proceed with the capacity results. He added that the courts don’t have hard timelines on which they must act, raising the possibility that uncertainty around capacity prices could extend into the delivery year, which starts in June.

“If rehearing is sought, it kind of freeze-frames everything,” he said.

Lu said PJM is assessing the feasibility of rerunning the auction with the original LDA reliability requirement parameter for DPL South with the existing offers submitted in December 2022.

PJM Senior Vice President of Market Services Stu Bresler said the RTO is in contact with FERC staff to provide perspectives on possible next steps. But he told the MRC he could not speculate about what those steps might be. If the auction did have to be run, he said the impact would likely spread outside the DPL South zone.

Paul Sotkiewicz, president of E-Cubed Policy Associates, encouraged PJM to remain in communication with FERC to encourage it to come to a resolution the court could accept as quickly as possible, noting that using the full 45 days it has to respond could put resolution of the dispute within a month of the start of the delivery year.

“We’re right before the delivery year at this point; it’s really cutting this close, so I’m wondering if there’s a way to accelerate that time frame,” he said.