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October 10, 2024

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Modeling Shows Vt. Can Hit Decarbonization Targets Through 2050

Initial modeling of potential decarbonization pathways for Vermont shows that the state can meet 2025, 2030 and 2050 greenhouse gas emission reductions targets set by the 2020 Global Warming Solutions Act (GWSA).

A team of consultants developed the model to support the Vermont Climate Council as it finalizes the pathways and strategies it will include in the state’s Climate Action Plan due Dec. 1, David Hill, managing consultant at Energy Futures Group, said on Oct. 5.

The GWSA mandates GHG emission reductions of 26% below 2005 levels by 2025, and 40% and 80% below 1990 levels by 2030 and 2050, respectively. The model showed the state could exceed the 2025 target and meet the 2030 and 2050 targets, Hill said during the council’s latest meeting.

Exceeding the first target, he added, is all about pace.

“You can’t just barely meet the target in 2025 and then ramp it up to meeting 2030,” he said. “There is what we might call overachievement in 2025, but that is all in the interest of meeting the targets both in 2030 and 2050.”

Emissions would decline from 7.3 million metric tons carbon dioxide equivalent in 2025 to 5.2 million and 1.7 million in 2030 and 2050, respectively, according to the model.

The results, Hill said, are based on the policies and programs that the council’s Cross-sector Mitigation Subcommittee sees as the most feasible for attaining the largest GHG emission reductions in the most cost-effective manner. As the council compiles a draft plan over the next month, it will consider the subcommittee’s policy and program suggestions.

All subcommittee recommendations still must undergo further equity analyses based on the council’s guiding principles for a just transition adopted in August.

When the draft plan is complete, the consultants will plug the plan into the model to analyze the council’s official emission reduction pathway choices. A report on that analysis is due on Nov. 15.

Major Pathways

The cross-sector subcommittee made its preliminary decarbonization pathway recommendations to the full council in July for the transportation, buildings, non-energy and electricity sectors.

Initial modeling considered scenarios that are based on the subcommittee’s draft recommendations, including three major actions for transportation, buildings and electricity. Those actions are to adopt the Transportation and Climate Initiative Program (TCI-P) and a Clean Heat Standard (CHS), as well as increase the current Renewable Energy Standard (RES) to 100%. (See VT Climate Council Puts Clean Heat Standard on the Table.)

Transport

The model showed that the transportation sector could achieve an 88% reduction in emissions by 2050 under the subcommittee’s draft actions.

That result relies on a transition to battery electric vehicles (BEV) along with adoption of biofuel and a reduction of vehicle miles traveled.

The model phases out the sale of new internal combustion engine (ICE) vehicles in the state by 2033, Hill said, but biofuel would be needed for about 90,000 ICE vehicles still operating in 2050. By 2030, he added, Vermont would have 160,000 registered BEVs.

To support those transportation sector changes, the model considers Vermont’s possible participation in a regional cap-and-invest program. TCI-P would position the state to raise the consistent revenues necessary to fund BEV adoption and charging initiatives.

The cross-sector mitigation subcommittee will likely make TCI-P participation a priority pathway for the council’s consideration, according to Gina Campoli, subcommittee member and environmental policy manager at the Vermont Agency of Transportation. Benefits of participation would include a 30% reduction in transportation sector emissions and proceeds of $20 million/year, she said during the meeting.

Buildings

In the buildings sector, the model showed a possible 83% reduction in emissions by 2050 from the subcommittee’s draft actions.

The results cover residential, commercial and industrial subsectors, with most reductions coming from residential and commercial buildings, Hill said. Improved space heating, he added, is the primary driver of reductions.

The model anticipates reductions coming from the adoption of efficient heating systems, such as heat pumps, combined with better building performance and a phaseout of fossil fuels for cooking and water heating.

A fossil-fuel phaseout, under the model, could be accomplished through appliance standards or a CHS.

The subcommittee continues to support the CHS as a priority for the council’s consideration, according to David Farnsworth, subcommittee member and principal at the Regulatory Assistance Project.

A CHS is an equitable option that allows Vermonters to exercise choices in how they transition their heating systems, Farnsworth said during the meeting.

“We would recommend that the Vermont [Public Service Commission] administer the standard, establishing growing annual obligations to achieve thermal load and the necessary reductions to meet GWSA requirements,” he said.

Electricity

Vermont’s current RES has already pushed the state’s electricity related GHG emissions to 83% below 1990 levels, according to a recent report from the Energy Action Network. Recognizing that lowering emissions is not the primary goal for the electricity sector, Hill said, the model demonstrates generation growth and supports a 100% RES.

Generation in the model grows from 6,600 GWh in 2020 to 12.2 GWh in 2050, the bulk of which would come from offshore wind in the ISO-NE system.

With very low emissions, the electricity sector is now positioned as a backbone to decarbonizing the transportation and building sectors, according to Ed McNamara, subcommittee member and director of the Regulated Utility Planning Division at the Vermont Department of Public Service.

The subcommittee, therefore, continues to support its recommendation that the full council consider including a 100% RES after 2030 in the Climate Action Plan, McNamara said.

“We’re not actually recommending a very specific RES design,” he said. “There are a lot of different factors to consider — new versus existing requirements, regional versus in-state requirements, distributed versus large-scale [generation].”

Every choice has significant policy implications for cost-effectiveness and effects on low-income Vermonters, he said, adding that the subcommittee suggests the council “do further research and study on how [the RES] should be designed.”

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Massachusetts Considers Approval of LNG Facility in Environmental Justice Community

Clean energy advocates are pushing the Massachusetts Energy Facilities Siting Board (EFSB) to reconsider its tentative approval of a liquefied natural gas (LNG) facility within one mile of a low-income, state-designated environmental justice community.

“The siting board declares this facility an energy bridge during the state’s transition away from a fossil fuel-based economy. But this project is the fossil fuel-based economy,” Cathy Kristofferson, secretary and treasurer for the Pipeline Awareness Network for the Northeast, said during an EFSB meeting on Oct. 6.

The proposed Northeast Energy Center (EFSB 18-04/D.P.U. 18-96) would liquefy and store pipeline natural gas for loading onto tanker trucks to serve National Grid customers with some capacity marketed to other gas distribution companies in the state.

The project would be located along Route 169 or Route 20 in Charlton, a town already overburdened with methane emissions from Talen Energy’s Millennium natural gas combined-cycle power plant and a landfill operated by Casella Waste Systems that was shut down for contaminating residential water wells, resident Maureen Doyle said.

The EFSB heard public comments on the $100 million facility proposed by Liberty Energy Trust, an infrastructure and development firm, but ran out of time for deliberation and a final decision.

Massachusetts-LNG-storage-and-shipping-facility-Location-map-(Liberty-Energy-Trust)-Content.jpgThe Massachusetts Energy Facilities Siting Board tentatively approved a $100 million LNG storage and shipping facility along Route 169 in Charlton, adjacent to Talen Energy’s Millennium natural gas combined-cycle power plant. The developer also proposed an alternate site along Route 20. | Liberty Energy Trust

On Sept. 20, the EFSB tentatively approved the project’s location at the Route 169 site, adjacent to the Millennium plant. The board acknowledged the site’s location within an environmental justice community but stated, “the project did not exceed the Environmental Notification Form (ENF) thresholds for air, solid and hazardous waste, or wastewater and sewage sludge treatment and disposal.”

Projects such as the LNG facility are required to fill out an ENF. The form initiates the process for the facility to receive approval from the Massachusetts Environmental Policy Act Office to ensure the proposal aligns with state laws, including the Executive Office of Energy and Environmental Affairs’ Environmental Justice Policy.

The local production and distribution of LNG “offers greater reliability and less environmental impact than more distant LNG sources that may be available,” Andre Gibeau, an attorney for the EFSB, said during the meeting. The proposed project is also “centrally located with respect to existing LNG storage facilities in the commonwealth,” he said.

According to a 2019 report by The Oxford Institute for Energy Studies, the natural gas combusted to chill LNG to minus 162 degrees C equals 11 to 13% of the gas produced at the wellhead, “which means that LNG has significantly higher emissions than a typical pipeline gas value chain.”

The proposed facility would include a pipeline extension from the Tennessee Gas Pipeline and be capable of producing 250,000 gallons per day. The plant would be able to store about 1 million gallons of LNG in 10 tanks.

Last week’s meeting occurred as gas prices in Europe and Asia hit record highs. The U.S.’ domestic supply insulates it somewhat from global spikes, but prices in the U.S. have doubled this year, rising to the highest levels since 2008. That could greatly increase heating bills this winter after years of unusually inexpensive fuel.

The EFSB will vote on the LNG facility during its next meeting, which has not yet been scheduled.

The board has yet to replace its environmental justice representative since former representative Shalanda Baker took a position as deputy director for energy justice and secretary’s adviser on equity at the U.S. Department of Energy earlier this year.

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PG&E Shuts off Power During Wind Storm but Limits PSPS

Pacific Gas and Electric (NYSE:PCG) implemented extra-targeted public safety power shutoffs (PSPS) Monday as powerful offshore winds gusted through drought-stricken Northern and Central California, prompting a red-flag warning from the National Weather Service.

The weather conditions were like those in October 2017, when firestorms driven by high winds and dry conditions tore through Napa, Sonoma and neighboring counties, killing 44 people and leveling thousands of structures. The 22 major wine country fires, some of which PG&E equipment started, were among the most destructive fires in state history at the time.

Napa and Sonoma were two of the more than 20 counties affected by Monday’s PSPS, including Monterey and Santa Barbara counties in Central California.

“This safety shutoff is due to a dry, offshore wind event expected to start Sunday night and bring wind gusts of up to 50 mph by Monday morning,” PG&E said in a news release. “As a result of this wind event, combined with extreme to exceptional drought conditions and extremely dry vegetation, PG&E began sending advanced notifications Saturday to customers where PG&E may need to proactively turn off power for safety to reduce the risk of wildfire from energized power lines.”

The state’s largest utility said it expected to blackout 25,000 customers in “very targeted” areas starting at 4 a.m. Monday and continuing through Tuesday.

The number of customers potentially affected was a small fraction of those impacted by PG&E’s PSPS events in October 2019, which left nearly 2.4 million residents in the dark, some for up to a week, and caused an uproar among ratepayers and public officials. (See California Officials Hammer PG&E over Power Shutoffs and Calif. Regulators Bash PG&E’s Power Shutoffs.)

PG&E’s widespread use of PSPS in 2019 followed the wine country fires and the Camp Fire of November 2018, which killed at least 84 people and razed much of the town of Paradise. State fire investigators determined the cause of the Camp Fire was a broken PG&E transmission line that sparked dry vegetation. The fire exploded, driven by offshore winds like those that blew Monday.

In September 2020, PG&E blacked out 172,000 customers, or about 499,000 residents, in portions of 22 counties in the Sierra Nevada foothills, the Sacramento Valley and the northern San Francisco Bay Area. Since then, under intense pressure from the California Public Utilities Commission and the governor’s office, PG&E has made efforts to limit the scope and duration of its PSPS events. (See CPUC Orders Changes to PG&E Shutoff Rules.)

The utility set up a Wildfire Operations Center, which is staffed 24 hours a day in fire season. It is installing 1,150 weather stations, adding more than 400 high-definition fire cameras, and reserving 65 helicopters to speed line inspections and restoration work after shutoffs, it said.

The addition of 1,000 sectionalizing devices and switches have helped limit the size of PSPS outages, PG&E said.

“The scope of [Monday’s] overall event represents less than 0.5% of all PG&E customers,” the utility said, adding that “weather ‘all-clears’ will occur as early as Monday evening with restoration expected to begin Tuesday afternoon.”

“Once conditions are clear, PG&E electric crews will begin patrolling in the air, in vehicles and on foot to visually check de-energized lines for hazards or damage to make sure it is safe to restore power,” it said.

A tree falling on a PG&E line is suspected of starting this summer’s Dixie Fire, the second largest in state history, and a tree falling on a PG&E line, which remained energized despite a surrounding PSPS event, started last year’s fatal Zogg Fire, the California Department of Forestry and Fire Protection (Cal Fire) concluded.

Last month, the Shasta County district attorney’s office filed four manslaughter charges against PG&E in the Zogg Fire, marking the fourth time in five years the utility has faced charges in disasters related to its gas and electric systems. (See PG&E Denies New Manslaughter Charges.)

PG&E pleaded guilty to 84 counts of involuntary manslaughter in the Camp Fire, but it has denied the most recent manslaughter charges.

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Two New ERCOT Directors Named, Replacing Current Board

The Texas Public Utility Commission on Monday announced that a new chairman and second independent director have been selected for ERCOT’s Board of Directors, replacing the eight market segment representatives sitting on the board.

The PUC said in a release that the ERCOT Board Selection Committee had chosen Paul Foster, president of Franklin Management and founder of Western Refining, as the board’s chair and Carlos Aguilar, CEO of Texas Central Partners, as the first two directors for ERCOT’s new board.

Foster and Aguilar will join PUC Chair Peter Lake, interim ERCOT CEO Brad Jones and the Office of Public Utility Counsel’s Chris Ekoh on the board. Lake is a non-voting member, as will be ERCOT’s CEO.

The PUC said the board’s composition meets the requirements of Senate Bill 2, which replaced the five independent directors and eight market segment representatives with eight independent directors chosen by a selection committee appointed by Texas’ political leadership.

The two directors will give the board a quorum and allow it to meet Tuesday morning without the previous directors to consider ERCOT’s request for an expedited approval of amended bylaws to comply with SB2.

The PUC release quotes the commission and ERCOT’s leadership with expressing “their gratitude to the outgoing board members for their service to Texas.”

SB2 requires each board member to be a Texas resident with executive-level experience in finance, business, engineering, trading, risk management, law or electric market design. When the February winter storm nearly brought the ERCOT system to total collapse in February, Texans frustrated with the ensuing long-term outages directed their ire toward the six board members who lived outside the state. (See ERCOT Chair, 4 Directors to Resign.)

The remaining six board members are expected to be named in the coming months. The selection committee is working with a search firm to find the directors. (See Search Firm Chosen to Find New ERCOT Board Members.)

Foster has previously chaired the University of Texas System Board of Regents and been a member of the Texas Higher Education Coordinating Board, the University of Texas System Lands Advisory Board and the El Paso Branch of the Dallas Federal Reserve Bank.

Aguilar has a background in global businesses and public-private development projects; his company is working to develop a high-speed train between North Texas and the Houston area. He has an undergraduate degree in mechanical engineering from Duke University and a doctorate in technological economics from the University of Stirling in Scotland.

“We welcome these highly qualified leaders, their expertise and insights into our relentless pursuit of grid reliability,” Jones said in a statement.

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NEPOOL Participants Committee Briefs: Oct. 7, 2021

BOSTON — For the first time since March 2020, following 20 months of exclusively virtual meetings because of the COVID-19 pandemic, the NEPOOL Participants Committee on Thursday met in-person, at the Colonnade Hotel in the city’s Back Bay.

There were strict safety protocols in place to attend the meeting. Everyone who attended had to be fully vaccinated and have provided verification in advance of the meeting. There is also a citywide mask mandate in Boston, which meant that all attendees wore masks or face coverings at all times except when actively eating or drinking.

ISO-NE Responds to NESCOE, Pledges Annual Open Board Meeting

In response to the New England States Committee on Electricity (NESCOE) vision statement last October and the organization’s report to the region’s governors on “Advancing the Vision,” ISO-NE’s Board of Directors issued a formal response Sept. 23, which the committee reviewed last week.

Among the initiatives and studies is a pledge to hold an annual open meeting. Beginning next year, the board will hold an open meeting focused on the electricity markets on even-numbered years; in odd-numbered years, the meeting will focus on transmission planning, with a potential link to the biennial Regional System Plan public forum, which was most recently held on Oct. 6. (See related story, Overheard at 2021 ISO-NE Regional System Plan Forum.)

The board said it has directed RTO management to prioritize transmission planning studies and analysis of market designs in support of the states’ clean energy goals.

“The board remains committed to working with the states and NEPOOL to achieve the region’s goals for a clean energy system that is reliable and efficient,” the board said.

ISO-NE has already begun its 2050 Transmission Study, the board noted, as requested by the states. The study will take a high-level look at scenarios to reliably incorporate clean energy and distributed energy resources beyond the RTO’s current 10-year planning horizon. The RTO will also work with the states to draft corresponding changes to the tariff to enable this type of transmission study on a recurring basis, the board said.

The board also noted that ISO-NE is evaluating “wholesale market frameworks that reflect states’ policies” through a series of working group sessions of the PC. The group has been considering a regional net carbon price, a Forward Clean Energy Market and a hybrid of the two concepts. Its work will be presented in the second quarter of 2022. The RTO is also developing a proposal to eliminate the minimum offer price rule from its capacity market.

Energy Market Value Falls

ISO-NE’s energy market value for September was $497 million (through Sept. 29), down $188 million from the updated August valuation and $290 million higher than the same month in 2020, according to COO Vamsi Chadalavada’s monthly report to the PC.

September natural gas prices were 12% higher than in August. Average real-time hub LMPs were 5% lower at $46.48/MWh. Daily uplift payments totaled $1.3 million over the period, down $2 million from the adjusted August value and $1.1 million less than September 2020.

Four new resources totaling 325 MW applied for an interconnection study: one battery and three solar-plus-solar projects, with in-service dates ranging from 2022 to 2023. The RTO is currently tracking 294 generation projects that total approximately 32,907 MW.

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PJM MIC Briefs: Oct. 6, 2021

ARR/FTR Market Task Force Proposal

Members endorsed a PJM and joint stakeholder proposal at last week’s Market Implementation Committee meeting to address the RTO’s auction revenue rights (ARRs) and financial transmission rights (FTRs).

The proposal, which was worked on at the ARR/FTR Market Task Force, was endorsed with 244 “yes” votes (84%), surpassing the necessary 50% threshold to move on for a vote at the Markets and Reliability Committee. In a separate vote asking if stakeholders prefer the proposal over the status quo, the proposal received 247 “yes” votes (93%).

Three other proposals presented for a non-sector-weighted vote at the MIC failed to reach the 50% threshold to be considered for endorsement at the MRC. An endorsement vote at the MRC will face a sector-weighted vote on the issue.

Brian Chmielewski, manager of PJM’s market simulation department, reviewed the PJM/joint stakeholder proposal, saying it was “strongly driven” by the findings of a report developed by London Economics International (LEI), a consultant hired by the RTO to conduct a “holistic review” of the ARR/FTR market.

LEI was hired on the recommendation of the “Report of the Independent Consultants on the GreenHat Default,” which called for an outside expert to review PJM’s FTR market and other PJM markets to evaluate the risks and the benefits of rule changes. (See “PJM Seeking Consultant on ARR/FTR Task Force,” PJM MIC Briefs: May 13, 2020.)

Comparison-of-FTR-auctions-(London-Economics)-Content.jpgComparison of FTR auctions across several RTOs/ISOs. | London Economics

Chmielewski said the PJM proposal aimed to consider the LEI recommendations and address concerns raised by the Independent Market Monitor and stakeholders regarding the ARR/FTR market. He said the proposal also sought to maintain the consultant’s conclusion that the existing FTR product is “reasonable and generally achieving the intended purposes” of serving as a financial equivalent to firm transmission service and “ensuring open access to firm transmission service by providing a congestion-hedging function.”

PJM’s proposal was broken into three separate areas as recommended by LEI, Chmielewski said, with an ARR track for “equity,” an FTR track for “efficiency,” and a transparency track for “simplicity.” 

<img src="//www.rtoinsider.com/wp-content/uploads/2023/06/140620231686784166.jpeg" data-first-key="caption" data-second-key="credit" data-caption="

Brian Chmielewski, PJM

” data-credit=”© RTO Insider LLC ” style=”display: block; float: none; vertical-align: top; margin: 5px auto; text-align: right; width: 200px;” alt=”Chmielewski-Brian-2017-08-10-RTO-Insider-FI.jpg” align=”right”>Brian Chmielewski, PJM | © RTO Insider LLC

Chmielewski said the ARR section was the main part of PJM’s proposal, and “far and away” the most time was spent speaking about the equity area and the allocation of rights. He said the ARR section was designed to answer a primary concern that the ability for some load to “efficiently hedge congestion costs can be deteriorated at times” when a “misalignment” occurs between the allocation of ARRs and congestion charges paid by load.

Some of the main features of the PJM proposal include a guarantee of 60% of network service peak load for each load-serving entity (LSE), Chmielewski said, which is meant to “protect zonal native load hedging ability with additional up-front capability.” He said the proposal also expands the source/sink availability for ARRs so that they “align with any source/sink that is available for bid in the annual FTR auction.”

Market Monitor Joe Bowring reviewed the IMM proposal, which only garnered 40 votes in favor (14%). Bowring said the purpose of the ARR/FTR design is to return congestion payments to the load that pays congestion.

Congestion is an overpayment by load, Bowring said, and 100% of that overpayment should be returned to load. Bowring disagreed with the LEI recommendation that load should be satisfied with receiving 50% to 75% of what is owed to load.

Greg Poulos, executive director of the Consumer Advocates of the PJM States, said he will present the IMM proposal at the MRC on behalf of the advocates as an alternative if the PJM/joint stakeholder proposal fails to be endorsed.

Erik Heinle of the D.C. Office of the People’s Counsel reviewed the group’s proposal, which was identical to the PJM proposal except that 100% of the surplus allocation was given to ARR holders. The OPC proposal received 95 votes in favor (34%).

Jau-Jia Guo of American Electric Power reviewed the company’s proposal that called for a commitment to implement a more “granular” ARR/FTR product design, including quarterly peak and off-peak ARR products. The AEP proposal received 57 votes in favor (21%).

The PJM/joint stakeholder proposal will now go to the MRC for endorsement.

Energy Efficiency Add-back Endorsed

Stakeholders endorsed the PJM/IMM proposal addressing the energy efficiency (EE) add-back in Reliability Pricing Model (RPM) auctions.

The proposal, which called for modified language to section 2.4.5 of Manual 18 to reflect revisions to the EE add-back method, was endorsed with 208 “yes” votes (90%). Members also endorsed changes to the status quo with 207 votes in favor (90%).

Jeff Bastian, senior consultant with PJM’s market operations, reviewed the joint PJM/IMM proposal addressing the calculation of the EE add-back mechanism. Members unanimously endorsed an issue charge presented by the Monitor at the August MIC meeting. (See “Energy Efficiency Add-back Issue Charge Endorsed,” PJM MIC Briefs: Aug. 11, 2021.)<img src="//www.rtoinsider.com/wp-content/uploads/2023/06/140620231686784167.jpeg" data-first-key="caption" data-second-key="credit" data-caption="

Jeff Bastian, PJM

” data-credit=”© RTO Insider LLC” style=”display: block; float: none; vertical-align: top; margin: 5px auto; text-align: right; width: 200px;” alt=”Bastian-Jeff-2019-03-06-RTO-Insider-FI” align=”right”>Jeff Bastian, PJM | © RTO Insider LLC

Bastian said the EE add-back mechanism is applied to capacity auctions to prevent the “adverse reliability impact” associated with double-counting EE as both a capacity resource and a reduction in the forecasted peak load. Bastian said the current method of determining the add-back megawatt quantity applied to a Base Residual Auction does not require it to match the megawatt quantity of EE resources that clear in that auction.

The add-back quantity in a BRA will normally exceed the cleared quantity, Bastian said, resulting in an artificial increase in the clearing price. The proposal rewrote language in Manual 18 to permit PJM to calculate the EE add-back in the capacity market clearing so that the total EE add-back megawatts offset the total cleared EE megawatts in the BRA.

Bastian said the solution “introduces an iterative approach into the auction clearing process” so that the EE add-back megawatt quantity applied to an RPM auction matches the megawatt quantity of EE resources cleared in the auction.

Bastian said PJM is seeking final endorsement at the Oct. 20 MRC to have the manual language in place for the 2023/24 BRA. PJM is currently asking FERC for a delay of the BRA, pushing the date from Dec. 1 to Jan. 25. (See PJM Proposing 2-Month Capacity Auction Delay.)

Start-up Cost Offer Development

Nicole Scott and Tom Hauske of PJM provided a first read of two proposals addressing start-up cost offer development worked on in the Cost Development Subcommittee, while some stakeholders questioned the scope of the changes coming from the subcommittee.

Scott said the issue charge for start-up costs was developed in the CDS for review and possible modifications to Manual 15. Scott said some of the key work activities included the calculation of start-up cost-based offers for steam units, combustion turbine units, combined cycle units and diesel units and a discussion on the consistency of start-up cost parameters with the start-up and notification times.

The CDS developed two proposals for consideration, Scott said, the first a joint PJM/IMM proposal and the second a clarification proposal from stakeholders. Scott said the two proposals agree on most of the start-up cost changes to Manual 15, but they differ around the issues of start-up costs, start fuels, station service and additional labor costs for combined cycle units.

Hauske said the PJM/IMM proposal calls for providing an equation to calculate start-up cost, addressing station service for non-combined cycle units, more clarification around the start maintenance adder and a definition for equivalent service hours.

Hauske said the main issue the PJM/IMM package attempted to address is the discrepancy in Manual 15 on how start-up costs are calculated. He said the manual currently allows combined cycle units to include fuel cost after a generator breaker closure and the synchronization to the grid in their calculation of start-up costs that other unit types like steam and nuclear cannot utilize.

The PJM/IMM proposal revises Manual 15 calculations for start-up cost, start fuel and station service to be consistent for all unit types, Hauske said, and it only includes costs prior to first breaker closure and after the last breaker opens.

<img src="//www.rtoinsider.com/wp-content/uploads/2023/06/140620231686784168.jpeg" data-first-key="caption" data-second-key="credit" data-caption="

Tom Hyzinski, GT Power Group

” data-credit=”© RTO Insider LLC” style=”display: block; float: none; vertical-align: top; margin: 5px auto; text-align: left; width: 200px;” alt=”Hyzinski-Tom-2017-08-22-RTO-Insider-FI.jpg” align=”left”>Tom Hyzinski, GT Power Group | © RTO Insider LLC

Tom Hyzinski of GT Power Group provided additional information of the clarification proposal. Hyzinski said the proposal was meant to offer an alternative to the PJM/IMM proposal that tries to maintain the status quo but contains some clarifications to the manual language to highlight current practices.

Hyzinski said the PJM/IMM proposal does more than just clarify language by “making a substantive change” to the way start-up costs are recovered for combined cycle units. He said the clarification proposal attempts to explain the current actual practice with combined cycle units without making significant manual updates.

Calpine’s David “Scarp” Scarpignato said he was under the impression the CDS was mainly focused on minor clarifications like the Manual 15 revisions regarding the incremental and no-load energy offers endorsed at the September MIC meeting. (See “Manual 15 Revisions Endorsed,” PJM MIC Briefs: Sept. 9, 2021.)

Scarpignato said the manual changes presented in the PJM/IMM proposal are “extremely substantive.”

Dave Anders, PJM’s director of stakeholder affairs, said the CDS has a charter approved by the MIC and can take on work within the scope of the charter. Anders said the subcommittee simply needs to let the committee to which it reports know what is being discussed.

Scarpignato said he would still like to see the issue come through the MIC where there is more stakeholder participation. He requested that a second first read be conducted at the November MIC to go over the issues more thoroughly with the committee.

“I know you guys understand it, but it’s pretty detailed for the rest of us,” Scarpignato said.

Bowring said he wanted to see the issue proceed for a vote at the November MIC since it has been “thoroughly reviewed” at the CDS, but he said he wouldn’t be opposed to having more discussion.

“I think people understand it; some just don’t like it,” Bowring said. “It is complicated, but lots of stuff at PJM is complicated.”

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PJM PC/TEAC Briefs: Oct. 5, 2021

Transmission Expansion Advisory Committee

NJ OSW Proposals

PJM received 79 proposals addressing both the onshore and offshore demands of New Jersey’s ambitious offshore wind program as part of the RTO’s “state agreement approach” under FERC Order 1000.

Aaron Berner, senior manager in PJM’s transmission planning department, presented the results of the competitive solicitation process at last week’s Transmission Expansion Advisory Committee meeting. The submission window was open from April 15 to Sept. 17.

Berner said proposals were received from both transmission owners and merchant developers and included 57 projects that featured cost commitment provisions to cap costs. He said through “multiple combinations” of different proposals, even more potential solutions are available beyond the initial 79 proposals.

Specific details of the proposals were not provided.

The four project categories included:

  • Option 1a: onshore upgrades on existing facilities, with 45 proposals submitted;
  • Option 1b: onshore new transmission connection facilities, with 22 proposals submitted;
  • Option 2: offshore new transmission connection facilities, with 26 proposals submitted, and;
  • Option 3: offshore network with eight proposals submitted.

“We’re characterizing this as a very robust response,” Berner said. “We have a number of different types of proposals that have been received for all of the options.”

Berner said PJM is “moving forward” to begin evaluating some of the issues around reinforcing networks and preparing reviews of the offshore elements of the proposals. He said PJM is collaborating with consultants with offshore wind expertise to “better evaluate” the projects.

Staff from PJM and the New Jersey Board of Public Utilities provided details last month to stakeholders during a special meeting of the Planning Committee, advising them on how the winning proposal would link to the new offshore wind projects New Jersey is soliciting. (See PJM, NJ Staff Brief Stakeholders on State Agreement Approach.)

NJ-OSW-Project-Solicitation-(PJM)-Alt-FI.jpgPJM gave an example of how proposals to New Jersey’s solicitation for offshore wind transmission projects may look. | PJM

 

The BPU has already awarded three offshore wind projects in two solicitations: the 1,100-MW Ocean Wind 1 and 1,148-MW Ocean Wind 2 projects, both developed by Ørsted, and the 1,510-MW Atlantic Shores project, a joint venture between EDF Renewables North America and Shell New Energies US. The BPU is planning to hold three more solicitations over the next five years to help the state reach its goal of supplying 7,500 MW of offshore wind by 2035. (See: NJ Awards Two Offshore Wind Projects.)

Berner said the BPU has issued a guidance document indicating certain processes to be employed going forward during the project evaluations. New Jersey retains the right to elect to move ahead with any of the projects and is targeting the end of 2022 to make final decisions.

Transource Update

Berner provided an update on the Independence Energy Connection (IEC) East and West transmission project in Maryland and Pennsylvania and its impact on the 2021 RTEP.

The Pennsylvania Public Utility Commission voted 4-0 in May to reject a series of related applications and petitions filed by Transource Energy for the siting and construction of high-voltage electric transmission lines in Franklin and York counties. The PUC denied the project based on concerns about whether the need established in the PJM planning process met the requirement for needs specific to Pennsylvania. (See Transource Tx Project Rejected by Pa. PUC.)

Transource’s plan for the eastern section of the project originally proposed extending 15.8 miles of transmission lines from a new Furnace Run substation in York County, Pa., to the Conastone substation in Harford County, Md. An updated configuration released in October 2019 increased the size of the new substation in Pennsylvania and added four miles of lines connecting to an existing right of way that would feed into two upgraded Baltimore Gas and Electric substations.

The western segment of the IEC project called for a 230-kV double circuit transmission line running 28.8 miles from Franklin County, Pa., into Washington County, Md.

Berner said PJM performed a sensitivity study to determine any reliability impacts associated with the removal of the IEC project from the RTEP. He said PJM found “a number” of thermal issues, but none of the issues needed immediate addressing.

“The magnitude of these violations is not significant at this point, so we’re not concerned about moving forward quickly with a reliability reinforcement,” Berner said.

The PJM Board of Managers endorsed the RTO’s recommendation to suspend the IEC project at its Sept. 22 meeting because of the “permitting risks” and to remove it from the pending RTEP models, Berner said. He said PJM has yet to do a benefit-to-cost ratio recalculation associated with the project.

PJM will begin to review any impacts to the interconnection queue following the determination of reinforcements for the baseline RTEP reliability, Berner said, and will include the update in future market efficiency studies.

Berner said PJM is not cancelling the IEC project at this time and will allow it to play out in the courts. Transource officially appealed the PUC decision in June, filing cases in the U.S. District Court for the Middle District of Pennsylvania and another in the Commonwealth Court of Pennsylvania. (See Transource Challenges Pa. PUC Decision in Court.)

“We’re going to let this continue to work its way through the various processes,” Berner said. “But we felt it was prudent to move forward with suspending the project.”

Planning Committee

Reserve Requirement Study Results Endorsed

Stakeholders at last week’s Planning Committee meeting unanimously endorsed an installed reserve margin (IRM) of 14.7%, up slightly from the 14.4% required in 2020.

Patricio Rocha Garrido of PJM’s resource adequacy department reviewed the 2021 reserve requirement study (RRS) results, which determine the RTO’s IRM and forecast pool requirement (FPR) for 2022/23 through 2024/25 and establish the initial IRM and FPR for 2025/26. The results are based on the 2021 capacity model, load model and capacity benefit of ties (CBOT).

2021-reserve-requirement-study-(PJM)-Content.jpgThe 2021 reserve requirement study (RRS) results versus the 2020 RRS results | PJM

 

Rocha Garrido said the results differed slightly from the numbers presented at the August PC meeting. (See “2021 IRM Results,” PJM PC/TEAC Briefs: Aug. 31, 2021.) In the process of reviewing the preliminary results, PJM discovered that some of the generating units were duplicated and had to be removed from the study, he said.

The calculated IRM moved from 14.64% to 14.66%, Rocha Garrido said, and the recommended IRM was bumped up from 14.6% to 14.7%. The recommended FPR also went from 1.0887 to 1.0894.

Adrien Ford of Old Dominion Electric Cooperative asked if the removal of the generators impacted previous years of the RRS or if it was just this year.

Rocha Garrido said the units were introduced erroneously this year, so the error only applied to the 2021 study.

He said the recommended FPR of 1.0894 was a modest increase from 1.0865 for 2020. The FPR is the most important parameter of the study because it is used in the reliability requirement calculation for Reliability Pricing Model auctions.

The 2021 capacity model is driving the increase in both the FPR and the IRM, Rocha Garrido said, with the average effective equivalent demand forced outage rate (EEFORd) of 5.8%, compared to 5.78% in the 2020 RRS. The higher average EEFORd was caused by the increase in the average unit size, going to 175 MW in the 2021 RRS compared to 159 MW in 2020 because of the removal of effective load-carrying capability (ELCC) resources from the model.

“Having more smaller units is better for reliability than having larger units,” Rocha Garrido said.

The CBOT — the help PJM can expect from imports during peak loads — is also estimated to increase pressure on the FPR and IRM. Rocha Garrido said imports from neighboring grid operators as a share of all generation decreased from 1.54% in 2020 to 1.47% in 2021.

A review and vote on FPR and IRM will take place at the November Members Committee meeting with final approval at the December PJM board meeting.

Manuals 14A and 14B Updates

Jonathan Kern of PJM’s transmission planning department provided an update to Manual 14A: New Services Request Process and Manual 14B: PJM Region Transmission Planning Updates reflecting proposed changes to the generator deliverability test and related procedures. Kern presented the initial draft of the proposed changes at the August 10 PC meeting. (See “Winter/Light-Load Generator Deliverability Update,” PJM PC/TEAC Briefs: Aug. 10, 2021.)

The purpose of the changes is to consider the “evolving resource mix” in PJM’s planning process, Kern said, and is relevant to the interconnection queue studies and the RTEP baseline studies.

Proposed-default-deliverability-requirements-(PJM)-Content.jpgThe proposed default deliverability requirements for wind and solar under PJM’s proposal for generator deliverability test modifications of light-load, summer and winter periods  | PJM

 

Kern said PJM intended to provide a first read of the manual updates at the PC meeting, but the RTO is still in the process of “fine-tuning the procedure to ensure repeatability” and that the results “make sense.” He said PJM is also examining the impacts to the interconnection queue.

Most of the analysis is expected to be completed by November, Kern said.

“Since there are a lot of changes, this extra time will allow stakeholders some time to digest the proposed changes,” he said. PJM has added proposed changes to the summer period to go along with the winter and light-load periods since the information was first presented in August to “harmonize” the three tests, Kern said. He added that the ramping limits for wind and solar were also refined for the three periods using ELCC studies.

Manual First Reads

Several manual updates resulting from cover-to-cover reviews received first reads:

  • Michael Herman of PJM’s transmission planning department provided a first read of Manual 14B: PJM Region Transmission Planning Process Update. Herman said one of the most significant changes came with the addition of a new section adding detail around the incorporation of end-of-life (EOL) needs in the RTEP, which were part of the tariff attachment M-3 discussions. In December, FERC rejected a stakeholder proposal to move EOL projects under the RTO’s planning authority, siding with transmission owners who argued that it would violate their rights. (See FERC Rejects PJM Stakeholder EOL Proposal.) The commission also accepted the TO sector’s own tariff amendments concerning EOL projects in August 2020, rejecting arguments in rehearing requests by more than a dozen load-side stakeholders. (See FERC Accepts PJM TOs’ End-of-life Revisions.)
  • John Reynolds of PJM’s resource adequacy planning department provided a first read of Manual 19: Load Forecasting and Analysis Update. Reynolds said the most significant change was adding battery storage to the list of forecasted items in the load forecast model overview in Section 3.1.
  • Joseph Hay of PJM’s infrastructure coordination department provided a first read of Manual 14F: Competitive Planning Process Update changes to the proposal fee structure to conform to the PJM Operating Agreement. Hay said the language in Manual 14F was not in agreement with the latest changes to the OA, which states, “All proposals in any RTEP window are subject to a non-refundable deposit of $5,000, except for project proposals submitted with cost estimates of $5 million or less. In addition to the $5,000 non-refundable deposit, the proposing entity must pay all actual costs incurred by PJM to evaluate the submitted project proposal.”

The committee will be asked to vote on the manual changes at next month’s meeting.

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PJM Operating Committee Briefs: Oct. 7, 2021

Synchronous Reserve Deployment Initiative

PJM stakeholders will vote next month at the Operating Committee on two different proposals seeking to improve the deployment of synchronized reserves during a spin event.

Ilyana Dropkin, an engineer in PJM’s performance compliance department, provided a summary of the initiative, developed in the Synchronized Reserve Deployment Task Force (SRDTF), at last week’s OC meeting. The task force was endorsed at the March OC meeting, and stakeholders received education around synchronized reserves and created a matrix to develop proposals. (See PJM OC Endorses Synchronized Reserve Discussion.)

Synchronized reserve events are emergency procedures triggered by PJM to maintain grid reliability in accordance with NERC’s Resource and Demand Balancing (BAL) standards. The RTO invokes those procedures under conditions such as the loss of multiple generating units at the same time or a sudden influx of load.

The task force examined ways to secure controlled deployment of synchronized reserves throughout emergency events by using tools like real-time security-constrained economic dispatch (RT SCED) to have consistent pricing and dispatch signals. The goal was to ensure BAL compliance during the recovery and maintain a reliable transition in and out of emergency events and to also define clear rules and expectations that address how PJM operators approve RT SCED cases around a synchronized reserve event.

Dropkin said the task force developed two different proposals: PJM’s intelligent reserve deployment (IRD) proposal, and a separate one by the Independent Market Monitor. In a nonbinding poll taken by stakeholders, PJM’s proposal received 75% support, while the IMM’s received 9% support. Sixteen percent of stakeholders preferred the status quo.

Michael Zhang, senior lead engineer in PJM’s markets coordination department, provided a first read of the PJM proposal. He said IRD is a SCED case that simulates the loss of the largest generation contingency on the system and for which the approval of the case will trigger a spin event.

The proposal calls for taking the megawatts of the largest generation contingency and adding them to the RTO forecast to simulate the unit loss, Zhang said. PJM would then be allowed to flip condensers and other inflexible synchronized resources cleared for reserves to energy megawatts and procure additional reserves to meet the next largest contingency.

Zhang said some of the significant changes over the status quo include updating the economic basepoints to replace all-call instructions and having active constraints controlled by IRD so that deployed resources don’t have negative impacts on the constraints.

Siva Josyula, Monitoring Analytics | © RTO Insider LLC

“IRD is an out-of-the-box solution,” Zhang said. “It’s fully optimized to deploy reserves and optimize economic solutions.”

Siva Josyula of Monitoring Analytics provided a first read of the IMM proposal. Josyula said the concept is to make sure reserves are deployed in proportion to the cause of the spin event and the resources that are deployed during a spin event are those that clear and are being compensated for providing synchronized reserves.

The proposal calls for using a reserve deployment tool that generates new dispatch signals, Josyula said. The total megawatts to deploy is equal to those lost or required for area control error recovery.

Manual 1 Changes Endorsed

Stakeholders unanimously endorsed manual changes to enshrine emergency protocols created in the wake of the onset of the COVID-19 pandemic at last week’s Operating Committee meeting.

Chris Moran, senior lead analyst with PJM’s NERC compliance team, reviewed the updates to Manual 1, Attachment F: Control Center and Data Exchange Requirements, which details how the RTO’s market operation control centers conduct remote operations in emergency situations. Moran first presented the manual changes at the September OC meeting. (See “Manual 01 Changes,” PJM Operating Committee Briefs: Sept. 10, 2021.)

The attachment was originally developed and implemented at the start of the pandemic to provide guidance for remote operations in case of control center staff illnesses. The temporary attachment, which took effect in April 2020, was set to expire Dec. 31.

As the pandemic progressed, Moran said, it became evident to PJM staff that the attachment needed to become a permanent part of the manual and to apply more broadly than just COVID-19. He said the language changes include replacing COVID-19 with “exceptional circumstances,” which PJM defines as “an event or effect that can be neither anticipated nor controlled, including, but not limited to, any act of a public enemy, war, insurrection, riot, fire, severe weather, natural disaster, flood, civil unrest, explosion, pandemic or other public health emergency.”

Moran said the RTO had made one change to the proposed definition after the September OC meeting, removing language that said an emergency was valid if “reasonably determined by PJM.” Moran said existing manual language puts the decision to implement remote operations “solely on the market operation centers.”

“The market operation centers are the ones who have to make the call whether or not they need to conduct remote operations,” Moran said. “This is a last-resort option.”

The attachment changes also include updating NERC contact information for PJM.

Adrien Ford of Old Dominion Electric Cooperative thanked PJM for bringing the issue forward to the committee and making changes to “appropriately focus that the [control centers] would be making the decision” on remote operations.

Winter Weekly Reserve Target Update

Patricio Rocha Garrido of PJM’s resource adequacy planning department reviewed the results of the 2021/22 winter weekly reserve target analysis, saying the numbers differed slightly from 2020/21. PJM’s estimated 2021/22 winter weekly reserve targets | PJM

The targets for December, January and February are 24%, 27% and 21% respectively, compared to 23%, 27% and 23% last year.

The December value is slightly higher because PJM is “seeing a little bit more load uncertainty” in the month, Rocha Garrido said, while February is seeing a “little less load uncertainty.”

Patricio Rocha Garrido, PJM | © RTO Insider LLC

Rocha Garrido said the targets are part of the reserve requirement study and help PJM staff to coordinate planned generator maintenance scheduling over the winter months. The objective is to “cover against uncertainties” related to load and forced outages by ensuring that the loss-of-load expectation (LOLE) for winter is “practically at zero,” he said.

The winter weekly reserve target for each month is the highest weekly reserve percentage, rounded up to the next integer value. Rocha Garrido said the targets are only recommendations to PJM’s Operations Department.

Rocha Garrido also presented the target numbers in a separate presentation at the Oct. 5 Planning Committee meeting. The OC and the PC will be asked to endorse the results at their November meetings.

Day-ahead Schedule Reserve (DASR)

David Kimmel, senior engineer in PJM’s Performance Compliance Department, reviewed preliminary proposed changes to the 2022 day-ahead scheduling reserve (DASR) requirement.

The DASR is the sum of the requirements for all zones within PJM and any additional reserves scheduled in response to a weather alert or other conservative operations. It is the sum of the three-year averages of both the under-forecasted load forecast error (LFE) and eDART forced outage rate component. PJM’s 2022 day-ahead scheduling reserve requirement (DASR) components | PJM

Kimmel said the final 2022 DASR requirement is 4.43%, slightly lower than the 2021 requirement of 4.78%. He said the number comes from the LFE component of 2.04%, which is down 0.14% from last year, and the forced outage component of 2.39%, down 0.21% from last year.

The value will be incorporated into Manual 13 changes and be effective through April 30, after which it will be replaced with the day-ahead secondary reserves. Kimmel said the change is dependent on FERC’s review and action on reserve price formation and PJM’s operating reserve demand curve (ORDC).

The OC will be asked to endorse the changes at its November meeting.

Manual Updates

Several manuals were reviewed in first reads as part of a periodic review:

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Stakeholder Soapbox: Transmission Planning Needs to be Improved — And We Already Know How to Do It

Johannes-P-Pfeifenberger-(The-Brattle-Group)-Content.jpgJohannes P. Pfeifenberger | The Brattle Group

Both reliability and clean energy related public policies are increasing the need for and benefits of large-scale regional and interregional transmission to avoid increased total electricity costs. Most studies of decarbonization find that a cost-effective end result requires at least a doubling of the delivery capacity of the U.S. transmission network.

Proven industry practices show that the industry already knows how to put together transmission plans based on co-optimizing generation and transmission to reliably and cost-effectively link anticipated future generation with anticipated future load. Any reasonable estimate of future generation reveals that each region will have a generation mix that is very different from today’s. But as FERC said in its recent Advanced Notice of Proposed Rulemaking, “transmission planning processes generally do not plan for the needs of anticipated future generation.”

In a new report, analysts from the Brattle Group and Grid Strategies offer some solutions that need to become standard practice, based on some proven examples of forward-looking, multi-benefit planning by some RTOs/ISOs and other grid planners in the U.S. and abroad. (See related story, New Tx Study Calls for Holistic Planning Across Regions.)

Rob-Gramlich-(Grid-Strategies)-Content.jpgRob Gramlich | Grid Strategies

The U.S. has been investing between $20 billion and $25 billion annually in improving the nation’s transmission grid. Over 90% of these investments are justified based on: (1) the local reliability criteria of transmission owners, including the replacement of the many aging transmission facilities built before the 1970s; (2) the local and regional reliability upgrades triggered by generation interconnection requests, which are now dominated by renewable generation and storage resources in many regions; and (3) the reliability criteria associated with regional planning processes conducted by grid operators. To date, only a small portion of transmission spending is justified on economic criteria and full analysis of broader regional and interregional benefits and costs.

The prevalent approach to transmission planning can be described as inefficiently reactive and incremental. It fails to take account of the large economies of scale and scope that exist in more holistic forward-looking plans. It fails to capture the co-benefits that exist in “reliability,” “economic,” and “public policy” based transmission facilities. Improved practices will significantly reduce electricity costs relative to status quo planning.

Costs associated with the prevalent planning approaches can be shown to be excessive when comparing studies under the current approach versus a holistic plan. For example, our report compares the results of a recent “regional” offshore wind analysis with the results of PJM’s generation interconnection studies. PJM’s study shows that the current generation interconnection study process (evaluating one interconnection cluster at a time) approximately doubles the transmission-related costs of integrating offshore wind generation compared to a more proactive, regional study process.

Improve Planning Processes

The planning processes can be improved by taking advantage of the last decade’s proven industry experience. MISO’s Multi-Value Project planning effort was a great example. It was proactive by incorporating anticipated future generation and load. It was multi-value, considering reliability, public policy, production costs and other benefits. It was scenario-based, finding a “least regrets” set of lines that were valuable under multiple potential future states. And it was portfolio-based, finding efficiencies and a less contentious cost allocation approach compared to considering projects individually.

MISO’s MVP plan is only one example. SPP’s Integrated Transmission Planning, numerous CAISO economic planning efforts, New York’s public policy transmission planning, and ERCOT’s CREZ and long-term system assessment approaches are all great examples of what can and should be done routinely.

These examples of successful, effective and proactive transmission planning demonstrate that we have proven and workable planning methodologies that can be employed. RTOs, their stakeholders and members, states, and FERC should see to it that these methods become the rule, not the exception. Thus far we do not have any good examples of joint interregional planning efforts that could lead to efficient interregional transmission infrastructure, but we’ll need to have that as well to achieve an efficient, reliable and resilient network.

The Planning Imperative

It will be critical to improve the existing processes for transmission planning and generation interconnection with proactive approaches that employ the above methodologies. Without such improved planning, we will not be able to build the more cost-effective, more flexible electricity grid necessary to meet reliability, economic and public policy needs at lower overall costs. In fact, without improved planning processes we may not even be able to bring online the clean-energy resources necessary to achieve the public policy mandates in place today.

Johannes P. Pfeifenberger, The Brattle Group’s practice leader for electricity wholesale markets and planning, is an economist with a background in electrical engineering and over 25 years of experience in electricity markets, regulation and finance.

Rob Gramlich is founder and president of Grid Strategies LLC, which provides economic policy analysis for clients on electric transmission and power markets in pursuit of low-cost decarbonization. He serves as executive director of Americans for a Clean Energy Grid and the WATT Coalition.

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Regulators Debate Competition in Entergy’s Texas Footprint

Texas regulators last week discussed the lack of competition in Entergy Texas’ (NYSE:ETR) footprint in the state’s southeastern portion, questioning whether the costs that previous commissions have allowed the utility to recover have benefited ratepayers.

At issue is a transmission-to-competition rider the Public Utility Commission approved in 2006, allowing Entergy to recover $14.5 million annually over a 15-year period for expenses incurred in 1999 through 2005, plus carrying costs, a figure that amounted to $207 million. The order was a result of 2005 legislation (House Bill 1567), which allowed an investor-owned utility to recoup spending more for capacity under power purchase agreements than were included in its last rate case (31544).

“It troubles me that ratepayers in the southeast spent [$200 million] on the transition to competition, and they have nothing to show for it,” Commissioner Jimmy Glotfelty said during the PUC’s open meeting Thursday.

The order stipulated three true-up periods every five years, with the last occurring this year. Entergy’s final true-up, approved by the PUC on Thursday, reflected a cumulative overcollection of $3.1 million (51806).

Entergy-Texas-Region-Map-(Entergy)-Content.jpgThe Entergy Texas footprint creeps close to Houston. | EntergyThe utility, then known as Entergy Gulf States, opted out of ERCOT’s competitive market, eventually joining MISO in 2013.

“It seems to me competition has been good for the rest of the state,” Glotfelty said. “If this moves us toward a competitive market in that area, I think that would be prudent. Stakeholders need to tell us is it’s time to move forward with competitive choices in the southeast region.”

Commissioner Will McAdams echoed Glotfelty’s comments, saying expanding competition into the southeast has been “heavily debated” within the state legislature, where he once worked. He also noted opinions over whether Entergy Texas should join ERCOT’s competitive market have gone back and forth.

The February winter storm “has made people evaluate that maybe [competition] is not such a good thing,” McAdams said. “If consumers and ratepayers want to see any type of competitive benefit in the future, we should provide them a venue at the PUC during the interludes between legislative sessions, where they can speak in front of their elected representatives.”

Commissioner Lori Cobos reminded her peers that one of the reasons Entergy joined MISO was that it wanted to “garner some of the benefits of being in an actual RTO or ISO.”

“As a commission, we should continue to review whether that is producing the benefits that were proffered to us as joining MISO. This merits a lot deeper consideration,” Cobos said.

After listening to the debate, PUC Chair Peter Lake offered his opinion on what Entergy’s customers can do.

“If they want to have that conversation, they should let us know,” he said.

ERCOT to Continue Conservative Ops

ERCOT staff told the commission that they will continue with their conservative operations approach through the winter and into next summer because of maintenance outages during the shoulder months.

After assuring the commission they would recall or deny thermal maintenance outages should unseasonably warm or cold weather create tight conditions, staff did just that on Friday, issuing an advanced action notice for Monday. The grid operator said it expects to withdraw or delay approved or accepted outages from 3 to 9 p.m. to scrounge up 94 MW of capacity to meet expected demand.

According to the notice, ERCOT expects wind and solar contributions to amount to about 6 GW from 6 to 7 p.m.

Dan Woodfin, senior director of system operations, told the PUC the amount of thermal capacity taken offline for maintenance outages has increased this fall to 18 GW, up from 10 GW a year ago.

Woodfin and Kenan Ögelman, vice president of commercial operations, also briefed the PUC on the recently completed summer season that they summarized as cooler than normal, wetter than normal, less windy than normal and conservative.


ERCOTs-ancillary-services-expenditures-(ERCOT)-Content.jpgWith the exception of August 2019, ERCOT’s ancillary services expenditures this summer exceeded the previous two. | ERCOT

Average daily temperatures were 1 to 2 degrees cooler than normal, without the widespread temperatures across the state that generally mark Texas summers. ERCOT did set new monthly peaks for June (70.2 GW) and September (72.2), but the summer peak of 73.5 GW on Aug. 31 was far short of the projected 77.2 GW.

Additional solar resources led to higher solar generation June through August, peaking at a record 7.04 GW on Aug. 31. Wind energy also set a new demand peak, hitting 23.6 GW on June 25.

Ögelman said prices were relatively low during the summer, with few spikes. ERCOT committed more resources through reliability unit commitments than it has in previous summers — for more than 2,000 effective hours, compared to about 200 in 2020 — and spent more than $50 million each month during the summer procuring non-spin reserves and other ancillary services.

ERCOT has drafted a nodal protocol revision request (NPRR) that will allow non-controllable load resources to participate in non-spin reserves, Ögelman said. The measure has cleared the Technical Advisory Committee and goes before the Board of Directors next. (See ERCOT Technical Advisory Committee Briefs: Sept. 29, 2021.)

“There’s no good reason not to allow load to participate,” Ögelman said when asked the reason for the change. “You want all the resources that can provide value to that space providing value to that space. Secondarily, this adds more liquidity to that market.”

When Ögelman told the commissioners the NPRR may not be implemented until the middle of next summer, Lake said softly, “We can work on that.”

PUC Clarifies Securitization Order

Staff have filed draft orders codifying the commission’s response to ERCOT’s requests for debt-obligation orders that would allow the grid operator to securitize $2.9 billion in market debt as a result of high charges incurred during February’s storm (52321, 52322). (See Texas PUC Finances Market Debt over Lt. Gov.’s Objections.)

The commissioners agreed that companies that opt-out of ERCOT’s proposal to finance $2.1 billion in debt would have to form a new entity if they want to start serving unaffiliated customers. Upon re-entering the market, the entities would be assessed uplift charges.

An NPRR wending its way through the ERCOT stakeholder process would strengthen the grid operator’s market-entry qualification and continued participation requirements. The commissioners decided to wait on the NPRR, rather than direct ERCOT to develop and implement it.

In another storm-related docket, the commission agave staff the go-ahead to publish a rulemaking for public comment that cuts the high systemwide offer cap (HCAP) from $9,000/MWh to $4,500/MWh. It will become effective Jan. 1 (52631).

The HCAP is currently set by rule at $2,000 after it was stuck at $9,000 for too many consecutive hours during the storm but was to revert back to $9,000 on Jan. 1. The cap was designed to incent generation to come online during tight conditions. (See “Offer Cap Could be Halved,” Texas PUC Directs Tx Construction in Valley.)

“By no means will this be the only action we take on the ERCOT market design structure,” Lake promised.

Status Reports for Valley Project

Following the PUC’s directive last month to three utilities that they add a second 345-kV circuit to an existing transmission line in the Rio Grande Valley, Cobos requested quarterly updates on the project (52682).

Cobos asked that effective Nov. 1, AEP Texas, Sharyland Utilities and South Texas Electric Cooperative file progress reports detailing tasks, time estimates, coordination with ERCOT, delays, and reliability and safety measures necessary to complete construction.

In other actions, the PUC:

  • rejected Entergy Texas’ application to acquire a proposed 100-MW solar facility in southeast Texas, agreeing with an administrative law judge that the utility did not prove the acquisition was a cost-effective way to provide consumer benefits when compared to alternatives (51215);
  • signed off on a unanimous settlement agreement between AEP Texas, staff and other parties under which the utility will refund $23.4 million to ratepayers for transition bonds issued by its AEP-Central Division (51484);
  • granted requests by Southwestern Public Service (52072) and Texas-New Mexico Power (52153) to adjust their energy-efficiency cost recovery factors for the 2022 program year by $6.3 million and $7.2 million, respectively; and
  • assessed a $56,000 administrative fee against AEP Texas for exceeding SAIDI and SAIFI standards by more than 5% during its 2019 reporting year (52034).