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November 13, 2024

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PJM MIC Briefs: Dec. 7, 2022

Limited Support for Co-located Load Proposals

A poll by the Market Implementation Committee last month found little support for two competing proposals on capacity offer opportunities for co-located load — one from the Independent Market Monitor and the other a joint package from Constellation Energy and Brookfield Renewable Partners.

Given the opposition, which comments from the poll suggest cut to the core of the packages, stakeholders last week agreed it would be best to focus on finetuning and clarifying how co-located load not directly interconnected with the grid is treated under the status quo rules. (See PJM Opens Poll on Co-Located Load Proposals)

Currently, generators serving customers who are solely connected to their supply must relinquish a portion of their capacity interconnection rights (CIRs) equal to the amount being provided to the co-located load. 

The Constellation/Brookfield proposal, which received 16% support overall, would have allowed generators serving such customers to retain their CIRs in exchange for the generation capacity remaining available to the grid when called upon — essentially turning the portion of generator serving the co-located load into a peaking unit. Constellation’s Jason Barker said during last month’s special session that the imagined arrangement under the proposal would be a nuclear facility supplying power for highly interruptible load, namely hydrogen electrolyzers.

Poll respondents said they believed that not requiring co-located load to pay for benefits received from the grid — such as synchronized reserve and scheduling — would leave other interconnection customers with having to pick up the cost. Commenters also said the arrangement would effectively allow generators to sell their capacity twice. Those in favor of the proposal said it could prevent generator retirements and the resulting increase in capacity prices and decrease in reliability.

The IMM package would have followed the existing practice of requiring generators to reduce their capacity offer equal to the power draw from the co-located load, while also levying additional charges on the load and administrative requirements on the generator. The proposal received 8% support overall and 9% against the status quo.

Commenters on that plan said they wanted additional details on cost allocation and answers to jurisdictional questions on how the provisions could be implemented. They also expressed concerns about potential overreach into areas addressed by reliability studies. Some respondents said they preferred the package’s stronger accounting for benefits received by co-located load.

Monitor Joe Bowring said the poll results suggest PJM should discontinue discussion of the two proposals and instead focus on clarifying the existing rules. Stakeholders largely agreed Wednesday that co-located loads will continue to exist and that the rules governing their relation to the grid should be clarified.

“While Exelon and other stakeholders are not supportive of the two options on the table, we do think that there would be value in potentially clarifying the status quo rules,” Exelon’s Sharon Midgley said.

Manual Revisions for Day-ahead Zonal Load Bus Distribution Factors Endorsed

The MIC endorsed by acclamation a package modifying how PJM conducts its day-ahead load bus distribution factor analysis and associated manual revisions. The changes still require approval by the Markets and Reliability and Members committees, which will likely vote on them during their January and February meetings.

Under current practice, the RTO calculates the hourly distribution factor for an individual node based on the percentage of state estimator load for that node as of 8 a.m. the prior week. For example, when building estimates for the July 14 market day, data from July 7 at 8 a.m. is currently used for every hour throughout the day.

Under the proposal, distribution factors would be calculated based on real-time data from each hour of the respective weekday of the previous week. So, when looking at 5 p.m. on July 14, data from the corresponding real-time interval on July 7 would be pulled.

The lookback period would use the most recently available day of the week where all 24 hours of data are available, meaning if one hour of data was unavailable for a day in the previous week, data would be drawn from the week before that.

Feedback on Issue Charge, Problem Statement for Combined Cycle Modeling

PJM will be revisiting a proposed issue charge and problem statement on modeling combined cycle units in the market clearing engine to incorporate stakeholder concerns about potentially making market design changes to resolve issues with the scale of the computational challenges.

Concerns raised during the first read of the documents include whether it’s more appropriate and feasible to find a hardware or software solution to the issue, the potential for market power rules to be watered down by switching from multiple schedules per facility to one, and the broad scope of the issue charge.

The current design of the market clearing engine looks at each schedule a generator offers into the energy market as a separate logical resource. While most resources have either one or two, it’s possible for the number to be much higher — particularly for combined cycle units — which exponentially increases the solution time. The problem statement says that a typical 2×1 combined cycle unit would have at least six configurations, meaning that if it offers two schedules into the market, it would be represented by 12 logical resources.

“Based on the last several years of experience with a multi-schedule model in the current MCE and discussions with GE, it is apparent that the multi-schedule model in the MCE with the ECC model will have a significant performance impact that will jeopardize the clearing of the day-ahead and real-time energy markets in the approved clearing timeframe with sufficient accuracy,” the document says.

Paul Sotkiewicz, of E-Cubed Policy Associates, questioned why PJM could not increase its computational capabilities with additional hardware or by using algorithms that can cut down on the number of branches the engine has to compute.

“I don’t think PJM has exhausted nearly all the venues and possibilities, including talking to others who may be more up to date on the more advanced algorithms that are out there,” he said.

Sotkiewicz was also “alarmed” that PJM is seeking to potentially make market design changes with an envisioned six-month timeframe to meet the requirements of a vendor hired without consulting stakeholders. PJM’s Keyur Patel said GE has been hired to develop a market engine product for combined cycle modeling — work it is engaging in concurrently with other RTOs — and aims to begin its PJM work by the end of next year, assuming associated rules have been approved by then.

Patel said PJM re-examines hardware requirements every three to four years and does not believe that hardware or algorithm changes would be enough to resolve the issue.

“There is no other technology available at this point that we can solve it in two hours or [a] two-and-a-half-hour time frame,” he said.

Bowring said the use of multiple schedules for each generator was implemented to provide greater market power protections and that it would be a mistake to revert that change to solve a technical issue at the expense of those protections.

“It’s important not to let a technical issue, as it’s presented, undercut market power mitigation,” he said.

While PJM has considered switching to a single schedule, Patel said other options are on the table as well.

PJM Considering Increasing FTR Bid Limit of 15,000 per Entity

PJM presented a problem statement and issue charge exploring the ability to increase the cap on the number of bids a single corporate entity can place in FTR auctions from 15,000 to 20,000 under quick fix rules, with an endorsement sought at next month’s committee meeting.

The RTO is considering the increase following the transition to weekend on-peak and daily off-peak class types, which has had the effect of requiring two bids to trade the same number of hours of an FTR as prior to the transition, according to the problem statement.

PJM senior engineer Emmy Messina said it may be necessary to delay the increase if the RTO finds that existing technology is insufficient to process the higher number of transactions; however, she does believe those upgrades are technically feasible. 

“I do believe there are ways we can solve allowing for 20,000 bids if we find that the resources don’t look like they can support it today. Maybe it’s getting upgraded hardware,” she said.

Director of Market Operations Tim Horger said he believes PJM can handle the increase to 20,000 bids in a single auction. However, he cautioned against increasing the number too sharply beyond that.

“I do think we need to be careful with opening the floodgates and going [to] 50,000 [or] 100,000 bids. Let’s do this in baby steps,” he said.

DR Worried by Decline in Synchronized Reserve Prices 

Synchronized reserve prices have dropped significantly since the start of October, when new market rules were implemented. Prices were at or below 2 cents/MWh for 95.53% of the hours in October and 97.7% in November, a sharp uptick from previous months. Prices were at those levels 71.81% of the time in September and 36.47% in October 2021. (See FERC Approves PJM Reserve Market Overhaul.)

Synch Reserve Histograms (PJM) Content.jpgSynchronized reserve prices have mostly been below the new offer cap of 2 cents/MWh, which was reduced from $7.50 when PJM overhauled its reserve markets, effective Oct. 1. | PJM

 

“There’s a couple driving factors we believe to be there: One, the offer cap rule going from $7.50 down to the 2 cents, as well as impacts from the must-offer requirement expanding the pool, if you will, of resources that we can procure reserves from,” said Brian Chmielewski, manager of market simulation.

Bruce Campbell, of Campbell Energy Advisors, said that the low prices could push demand response resources out of the synchronized reserve market, which may result in them not being available when the system is tight, even if prices are high.

“There is a concern in the demand response community. … The community is interested in continuing to provide these services, but not interested in providing them for free,” he said.

Chmielewski said PJM is monitoring the price movements and will be providing updated statistics monthly. However, given that market changes are only two months old, it would like to see additional production data before making recommendations for potential changes.

Bowring said the lower prices reflected supply and demand fundamentals and that there is no evidence that eliminating the arbitrary $7.50 adder to offers had any significant impact on clearing prices.

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Study: IRA Will Cut PJM Emissions and Energy Costs

A new study projects that the Inflation Reduction Act will reduce PJM’s carbon emissions while delivering more affordable power.

“Passage of the Inflation Reduction Act this summer threw the full financial weight of the federal government behind the clean energy transition. As a result, CO2 emissions and electricity costs in the nation’s largest electricity market, the PJM Interconnection, will both decline sharply through 2030,” co-author and Princeton Assistant Professor Jesse Jenkins wrote in an email announcement of the study by Princeton’s Zero-carbon Energy Systems Research and Optimization Laboratory. He was joined by Qingyu Xu, Neha Patankar, Mike Lau, and Chuan Zhang in authoring the study.

Using GenX, an open-source optimization and planning model, the study assessed the law’s impact on energy prices, emissions and investments in the PJM grid from 2023 through 2035. The results suggest that carbon-free generation could make up 60% of the PJM supply in 2030, compared to 48% without the passage of the IRA.

With more clean energy coming onto the grid, the study estimated that CO2 emissions could fall 37% over 2019-21 levels, while without the law emissions would be expected to rise approximately 12%.

The study posits that these outcomes are made possible by the tax credits, grants, rebates and loans made available for carbon-free generation, vehicle and building electrification, energy efficiency and carbon capture and storage for natural gas facilities.

“The production tax credit for new carbon-free generation and the production tax credit [PTC] for existing nuclear are the most important provisions in terms of their aggregate impact on the evolution of PJM capacity, emissions and cost,” Jenkins told RTO Insider in an email. “The bulk of new capacity additions are wind and solar leveraging the PTC, and maintaining the substantial existing nuclear fleet across PJM provides a critical foundation for this new carbon-free generation to build on, rather than ‘run to stay in place’ and expend new renewable generation to replace existing carbon-free nuclear generation.”

This could be achieved, the study says, while achieving reductions in the cost of power by lowering wholesale rates, making it cheaper for states to meet their clean energy policy goals through subsidies, and growing electric demand to spread fixed costs.

“This study finds that, due to passage of IRA, the PJM region could cut CO2 emissions from power generation by 80-90% by 2035 while keeping average bulk electricity supply costs for [load serving entities] comparable to or lower than levels experienced in recent years,” the study says.

The study estimates the average 2030 cost for bulk energy for LSEs in the PJM region at $42/MWh — 5% to 10% lower than without the IRA. It notes that costs were $50.20/MWh in 2019 and around $61 in 2021.

The study identified several roadblocks to reaching the projections it made, as well as for maintaining them into the future.

States would have to make their own investments and policy changes to promote the deep decarbonization, for which the study contains a “cost-optimized blueprint.” The roadmap applies two policy constraints to the model to show the impact of a clean energy standard (CES) requiring increasingly carbon-free generation and a CO2 cap-and-trade system.

The CES modeling assumes that 55% of generation will be carbon-free by 2025, 70% by 2030, and 85% by 2035. The cap-and-trade program would have decreasing emissions relative to 2005 levels of 58% by 2025, 80% by 2030 and 95% by 2035.

The expiration of PTCs for nuclear generators could cause the gains made in emission reductions to backslide after 2032.

“Unless equivalent policy support is extended beyond 2032, our modeling finds 12 GW [0-33 GW] of the PJM nuclear fleet is likely to retire by 2035, with new natural gas capacity and generation increasing to fill the resulting gap and meet growing demand, reversing some of the emissions progress achieved through 2030,” the study said.

Independent Market Monitor Jo Bowring said he believes the study includes both optimistic assumptions and outcomes regarding energy demand, prices and the penetration of intermittent resources into the PJM market.

“It’s obviously a very optimistic view of cleaner, faster and cheaper,” he said.

Bowring also noted that the third quarter State of the Market Report calculated the revenue received by nuclear generators over their avoidable costs and found that the resource type is profitable, including under laws such as Illinois’ Climate & Equitable Jobs Act, which he said eliminates the need for additional subsidies to keep the resource competitive.

He also questioned whether the scale of intermittent development is realistic given the low penetration currently seen in PJM and said the study’s LMP estimates for 2025 — which range from the mid $20’s/MWh to the low $50’s — are optimistic given that PJM has been in the $70/MWh range in 2022.

Jenkins said the IRA “fundamentally changes the economics of decarbonization across PJM,” however it will take an acceleration in renewables coming online for the full potential of the law to be seen.

“However, realizing that full potential — including both savings for electricity customers and reductions in CO2 emissions — will require accelerating the rate of renewable energy deployment and, in particular, grid interconnection, relative to recent trends in PJM. That’s a challenge the region as a whole already had a lot of reasons to proactively tackle, and the Inflation Reduction Act gives PJM stakeholders millions (of dollars in savings and avoided emissions) more reasons to do so,” he said.

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DOE Announces $2.5B Loan to EV Battery Manufacturer Ultium

The Department of Energy’s Loan Programs Office (LPO) announced Monday it is providing a $2.5 billion loan to Ultium Cells, the joint venture of General Motors (NYSE:GM) and Korean battery producer LG Energy Solution, to help finance the construction of new lithium-ion battery manufacturing plants in Michigan, Ohio and Tennessee.

One of the plants, in Warren, Ohio, is already online, producing cells, according to Brooke Waid, a company spokesperson. A plant in Spring Hill, Tennessee, has begun installation of equipment and is expected to be online in late 2023, while construction of a Lansing, Michigan, facility began in September and will continue through 2023. Production there should begin in 2024, Waid said.

The three plants are expected to produce 130 GWh of EV batteries, the equivalent of saving 480 million gallons of gasoline per year, according to the LPO. The projects funded will also create 6,000 construction jobs and another 5,100 jobs in plant operations. The Warren workforce includes 700 members of the United Auto Workers, according to a DOE press release.

“DOE is flooring the accelerator to build the electric vehicle supply chain here at home — and that starts with domestic battery manufacturing led by American workers and the unions that support them,” Energy Secretary Jennifer Granholm said in the release. “This loan will jumpstart the domestic battery cell production needed to reduce our reliance on other countries to meet increased demand.”

EVs now account for more than 5% of all new car sales in the U.S., a key industry benchmark for market growth, according to industry analysts. President Joe Biden wants half of all new car sales to be EVs by 2030. The Infrastructure Investment and Jobs Act includes $7.5 billion to help build out a national network of EV chargers, and the Inflation Reduction Act includes tax credits of up to $7,500 for new EVs and $4,000 for used EVs.

The Ultium batteries use “large format, pouch-type cells,” according to GM. The cells “waste less space and can stack on top of each other like pancakes or vertically like slices of toast. This simple modular design makes it easy for engineers to optimize energy density and vehicle layout,” according to information on the automaker’s website.

In other words, the batteries cost less and can provide more range, according to GM.

The company says it is also working to source as many of its materials as possible from the U.S. as it works toward its goals of producing 1 million EVs per year by 2025 and eliminating all tailpipe emissions from new light-duty vehicles by 2035.

The importance of domestic supply chains and manufacturing jobs was a common theme in reactions to the loan from state and federal government officials.

Michigan Gov. Gretchen Whitmer (D) quickly hailed the loan in a tweet, saying “This will bring supply chains home and ensure Michigan is the best place to innovate, design, and manufacture the future.” The Lansing plant should create 1,700 jobs, Whitmer said.

Quoted in the DOE press release, Sen. Sherrod Brown (D-Ohio) also spoke of the growing competition between states to grab their share of EV manufacturing dollars and jobs. “This loan will support Ohio in taking another step to lead the country and the world in producing sustainable technology and electric vehicles that Americans will need and drive over the next century,” Brown said.

Domestic Supply Chains

The Ultium loan caps a series of administration announcements aimed at expanding the domestic supply chain for batteries, a particular weak point for the industry. Lithium-ion batteries are critical for EV market growth, and China currently controls upwards of 60% of the global market for raw lithium refining and processing.

In October, DOE announced $2.8 billion in grants to 20 companies to supply minerals critical to battery production and bolster domestic manufacture of batteries for electric vehicles and the grid. The companies will use the money to build or expand facilities in 12 states to extract and process battery materials such as lithium and graphite and to manufacture battery components, in some instances, from recycled materials. (See DOE Awards $2.8 Billion to ‘Supercharge’ Battery Production.)

The grants were part of the American Battery Materials Initiative launched by the White House and DOE, to help build out a critical mineral supply chain in the U.S. and in partnership with U.S. allies.

The White House is also hosting an Electrification Summit on Wednesday, where transportation electrification will be a key topic.

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PJM Stakeholders Review Proposals on CIRs for ELCC Resources

The PJM Planning Committee last week reviewed a slate of proposals to address capacity interconnection rights (CIRs) for effective load-carrying capability (ELCC) resources.

The proposals aim to set long-term accreditation rules for intermittent resources, as well as transitional rules until those changes can be fully implemented.

The bulk of the differences among the five packages of governing document and manual revisions is how resources would be accredited during the transition, ranging from capping their capacity at their current CIR holdings, to granting them higher CIRs at the onset and having load pay for the associated transmission upgrades.

“That was really where the bulk of our conversations to date took place: What do we do with existing queue units? How and when do we make these changes effective?” PJM’s Brian Chmielewski said during the first read of the packages at the PC’s meeting Dec. 6.

LS Power’s Package E received the largest share of support in an October poll, at 44%, followed by Packages D and I from PJM, which received 40% and 28%, respectively. (See “Poll Opened to Gather Support for Packages on CIR for ELCC Resources,” PJM PC/TEAC Briefs: Oct. 4, 2022.)

The company’s proposal would immediately limit a generator’s accreditation to its CIRs, require facility owners seeking higher accreditation to re-enter the interconnection queue at the back of the line and require that they be responsible for any transmission upgrades associated with the higher accreditation.

Package I was reworked after the poll results with the aim of creating a compromise proposal. It would cap existing generators’ accreditation at their CIRs, as Package E does, but it would also allow them to participate in a transitional system capability study to evaluate if they can utilize existing headroom on the transmission system until it is claimed or the transition process is completed.

To be eligible to receive a transitional study, an existing generator must request a CIR uprate from PJM within 30 days of the passage of the package, if it is ultimately selected by stakeholders. The higher CIRs being sought cannot involve any physical modifications to the facility. While it was originally envisioned that only ELCC resources, namely wind and solar, would be eligible for this process, it was widened to all resource types at stakeholders’ request.

Chmielewski said that under the anticipated path the proposal would take for endorsement through the stakeholder process, the request window would open Feb. 2 and the studies completed by April 21.

 pjm energy storage RegDTom Rutigliano, NRDC | © RTO Insider LLC

Tom Rutigliano, of the Natural Resources Defense Council, said prohibiting resources seeking higher accreditation from utilizing existing headroom until their request can be processed would “artificially exclude capacity from the market for most of the remainder of the decade.” Both Packages E and G preclude the use of transmission headroom.

“From the environmental point of view, it’s really important whatever package we get to doesn’t leave that transmission idle while excluding capacity from the capacity market. That’s just throwing out something valuable for no reason,” Rutigliano said.

PJM’s Package D would conduct new generator deliverability tests and apply higher CIRs for existing wind and solar resources — including those still in development but already holding interconnection service agreements — starting with the 2023 Regional Transmission Expansion Plan. Any upgrades identified would be paid for by load.

Both the cost of shifting those upgrades to load and allowing existing generators to receive higher CIRs, or a transitional higher accreditation, have been points of contention for stakeholders throughout the process, with cost estimates reaching into the billions. (See Stakeholders Challenge PJM in Capacity Accreditation Talks.)

Package G, from E-Cubed Policy Associates, is similar to LS Power’s proposal, except in expanding the deliverability testing to include more months — particularly September, as there have been increasing reliability concerns at the start of the fall maintenance period.

The proposal would also allow generation owners retiring their assets to request an expedited CIR review for new generation being developed on the same site using the existing interconnection point.

PJM ZECs NOVECTom Hoatson, LS Power | © RTO Insider LLC

Finally, the newest of the five packages, K, was introduced by Tom Hoatson, director of Mid-Atlantic policy for LS Power, during last week’s meeting. It contains many of the same provisions as Package I while including an ask that the PJM Board of Managers direct the RTO to submit a request to FERC to clarify that the Reliability Assurance Agreement establishes CIRs as the hourly upper limit for the unforced capacity accreditation, commencing with the 2025/26 Base Residual Auction (BRA), scheduled for next June.

The introduction of the proposal comes from a concern that Package I runs too strong of a risk of not being actionable in time for the BRA, leaving that auction to be held under the current rules.

“We have an issue with that; we want this thing to finally be resolved. We’ve been going through this for two or three years; we have had multiple BRAs impacted by this,” Hoatson said. “I actually like Package I, but for the concern of it not being in place for June.”

The five packages will receive a first read at this month’s Markets and Reliability Committee meeting.

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DOE to Announce Major Advance in Fusion Technology

The Department of Energy is expected to announce Tuesday that scientists at the Lawrence Livermore National Laboratory have produced a nuclear fusion reaction that for the first time releases more energy than used to set off the process.

Fusion — fusing hydrogen into helium — is the process that powers the sun. Scientists have long chased the dream of harnessing the process to produce a net energy gain.

What’s new in this lab experiment is that the scientists used the pressure of rapidly pulsing laser blasts rather than magnetic fields to control the resulting super-heated plasma of hydrogen isotopes.

And they found that the process released more energy than used to produce the pulses.

The lasers used, said to be the most powerful in the nation, focused on a BB-sized pellet made of deuterium and tritium, two hydrogen isotopes, according to preliminary reports.

“This is like taking the first step in a child’s life,” said Andrew Sowder, senior technical executive at the Electric Power Research Institute (EPRI).

“It’s the first step. It’s not enough to make a practical source of energy. You’ve got to get much more out than you put in to make it economically worthwhile.

“You’ve got to prove that you can get more energy out than you put in. That is really what this step is. And no one else has done this before,” he said.

The success does not mean utilities will be able to build fusion reactors tomorrow, or anytime soon, he added, comparing the achievement to NASA’s early efforts to put astronauts in orbiting capsules, the first steps to sending astronauts to the moon and later building the space station.   

There are a number of privately funded efforts competing to achieve the same results, though none have yet done what LLNL has done. The lab’s initial mission was research for thermonuclear weapons.

But on Monday, just a day before the planned DOE announcement, the Canadian company General Fusion announced it had achieved a milestone: controlling the superheated plasma with compression alone for brief periods rather than with magnetic fields.

The success of the federal lab experiments is likely to energize the private sector as well, especially given the federal research funds available.

In October, DOE awarded $47 million to scientists working on fusion designs using powerful magnetic fields to control the plasma in which fusion can occur. DOE’s Advanced Research Projects Agency-Energy (ARPA-E) and Office of Science–Fusion Energy Sciences were funding 14 fusion research projects as of September.

The intensity of the research efforts and the public and private funding has convinced EPRI that now is the time to prepare for fusion reactors that might be built in the future.

“We have been scouting fusion for the last decade or so, scouting like you do looking for baseball talent,” Sowder said. “There are a lot of private sector developers out there. We are beginning to talk to them about working collaboratively.”

Among the promises of fusion is that it can produce carbon-free energy without the nuclear waste created by nuclear fission.

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PUC, ERCOT Face More Heat from Texas Lawmakers

Texas lawmakers once again put the heat on the state Public Utility Commission and ERCOT last week, raising questions over the PUC’s proposed electricity market redesign and how the two organizations work together.

A state House committee took first crack on Dec. 5 with a public hearing on the PUC’s proposed market changes. Two days later, a Senate sunset review committee examined the two organizations’ decision-making process and the commission’s lack of resources.

The two public meetings came a week after politicians complained the PUC’s recommendation would do nothing to quickly add gas-fired generation. They also asked the commission to hold off on any final market designs proposals until it gets final approval from the state legislature, which opens its 88th biennial session Jan. 10. (See Texas Politicians Assert Themselves in PUC’s Market Redesign.)

PUC Chair Peter Lake bore the brunt of lawmakers’ questioning before the House State Affairs Committee and the state’s Sunset Advisory Commission. He again defended the performance credit mechanism (PCM) that would require load-serving entities to buy performance-based credits from generation resources that meet reliability standards.

The market construct has never been used by a U.S. grid operator and was not recommended by the consulting firms that spent several months this year reviewing the PUC’s various proposed designs. (See Proposed ERCOT Market Redesigns ‘Capacity-ish’ to Some.)

House committee hearing (Texas House of Representatives) Content.jpgERCOT CEO Pablo Vegas, PUC Chair Peter Lake (left-right, facing seats) greet onlookers before the House committee hearing. | Texas House of Representatives

“The bottom line is the PCM indicates that we would deliver 10 times improvement in reliability for a fractional increase in costs, or any increase in costs at all,” Lake said.

Rep. Todd Hunter (R) asked Lake whether the PMC guarantees “new generation.”

“Yes, sir,” Lake replied.

Noting that Lake is not a lawyer, Hunter said, “Always remember when you said, ‘guarantee.’”

Lake was unable to provide Hunter a definitive date for how soon ERCOT would see new gas generation, although renewable generation continues to be brought online. That depends on “regulatory certainty,” Lake said.

Hunter asked the same question of the Independent Market Monitor’s Carrie Bivens, who said no capacity market design, as many view the PCM, would guarantee new generation. Katie Coleman, representing the Texas Association of Manufacturers, agreed. She said capacity markets “simply increase customer costs” while hoping for new generation, leading to only increased regulatory uncertainty.

“We are concerned about a scenario where we are paying very high costs and not getting additional reliability,” Coleman said.

Customer costs have become a large concern in Texas. According to the U.S. Energy Information Administration, retail prices there rose from $0.09/kWh to $0.11/kWh in the last year. Customer bills were the nation’s seventh highest before this year, Stoic Energy consultant Doug Lewin said.

The PCM design relies on load-serving entities purchasing performance credits that are awarded to resources through a retrospective settlement process based on availability during the 30 hours of highest risk, according to their load-ratio shares during those same periods. This allows generators and LSEs to trade PCs in a voluntary forward market, with generators required to participate in the forward market to qualify for the settlement process.

However, as Lewin pointed out, the PUC has not analyzed which 30 hours the PCM would have paid last year in a market where ERCOT “administratively” sets the demand curve.

“One of the biggest problems with the PCM is it will take fantastic foresight by ERCOT to set the demand curve AND for the generators to anticipate and be ready for those 30 hours,” he tweeted. “If it’s hard to predict (and it will be), they may not be ready.”

Lake said the PUC plans to vote on its preferred market design Jan. 12, two days after the legislature goes into session and despite a letter from a bipartisan Senate committee directing the commission to hold off on “holistic” market designs without “further consultation” with lawmakers.

Sen. Charles Schwertner (R), who chairs the Business and Commerce Committee that sent the letter after a Nov. 17 hearing on the proposed market design, also chairs the Sunset Committee. He told Lake during the Sunset Committee’s Dec. 7 hearing that he had yet to receive a response to the Senate’s letter.

“I’ve been preparing for this hearing and another one earlier this week, but I look forward to responding to that letter,” Lake said.

Before the House committee earlier, he said the PUC would not “operationalize anything before getting guidance from you all and the Senate.”

“We have asked you to make recommendations, [and] you are making them,” Rep. Richard Peña Raymond (D) told Lake. “I don’t really get why [members of the Senate committee] don’t want you to make them.”

The PUC will command the floor when it holds an open meeting Thursday. It has asked ERCOT stakeholders and the public to provide feedback on the PCM and five other market designs by noon Thursday.

Sunset Commission: PUC ‘Woefully Underfunded’

The Sunset Committee’s hearing followed the release of the Sunset Advisory Commission’s report on PUC, ERCOT and the Office of Public Utility Counsel. The review was accelerated by two years after last year’s disastrous winter storm.

According to the report and its six areas of concern, the PUC and its staff of about 200 is “woefully underfunded” and dependent on “those it oversees for [the] analysis it needs to make strategic decisions.” The report also found the regulatory commission does not have the manpower to analyze data and lacks policies and procedures in some areas.

“We were surprised to see PUC only has about 200 staff to not only regulate three industries, but also to implement significant changes to improve the grid, while also navigating its new governance structure and relationship with ERCOT,” the Sunset Advisory Commission’s review director, Emily Johnson, told the committee.

In comparison, the Texas Railroad Commission that regulates the state’s oil and natural gas industry has about 1,000 staffers.

“The lack of resources, as you all have identified and the Sunset Commission identified, has made implementing all of the tasks you gave us very, very difficult,” Lake said. “We have essentially the same amount of employees but have done 200% more rule-makings.”

Sunset Commission staff said they support the PUC’s efforts to fund a data analytics team and to bring in additional engineering skills. With that, they said, the PUC “cannot truly fulfill expectations” to ensure ERCOT reliability.

The report dinged the PUC for its informal directives to ERCOT, saying that means the agency “does not always adhere to best practices for openness, inclusiveness, and transparency.”

Schwertner quoted the report and said it deserves focus: “The state would benefit from a more clearly defined, fully transparent process when decisions that affect the entire electric industry and millions of Texans are made.”

Lake said the commission has improved in that area and will wait on further direction from the legislature.

Sunset Commission staff also authorized ERCOT to develop a policy to exclude the PUC’s commissioners from participating in certain Board of Directors’ executive session discussions. They said this would allow the board to review sensitive matters “without PUC influence but would not inhibit the commission’s ability to adequately oversee ERCOT.”

The grid operator said it supports the recommendation.

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NERC Repeats IBR Warnings After Second Odessa Event

Addressing the performance issues of inverter-based resources (IBR) has become a “paramount” priority for the ERO, according to a new analysis of yet another IBR-related service disruption released Thursday by NERC and the Texas Reliability Entity.

The report covers the June 4, 2022, disturbance, when the Texas interconnection lost 2,555 MW of solar PV and synchronous generation near the town of Odessa. NERC has dubbed the event the 2022 Odessa disturbance to differentiate it from a similar event that happened just over a year earlier in the same location, which led to a total reduction in output of 1,340 MW. (See NERC-ERCOT Report Reviews Texas Solar Issues.)

Noting the resemblance between the two incidents, the report’s authors called for “immediate industry action” to ensure that IBRs do not pose a threat to grid reliability, a sentiment echoed by NERC CEO Jim Robb on social media.

“Enough evidence already!” Robb said in a retweet of the official NERC Twitter account’s post announcing the new report. “Time to move forward to develop the requirements to stop these inverter-based events. Inverter-based resources are a key part of the grid and will continue to grow and they will be developed and modeled in a way which supports reliability!”

Lightning Arrestor Triggers Resource Trips

The disturbance began at 12:59 p.m. when a lightning arrestor failed at a synchronous generation plant near Odessa, causing a B-phase-to-ground fault on the 345-kV bus. This fault was cleared by protective relaying in about three cycles; meanwhile, generator protection on a neighboring unit misoperated because of current transformer saturation, causing additional generation to trip and runback.

In all, 844 MW of synchronous generation tripped in the Texas RE footprint: 535 MW at the first location and an additional 309 MW at a synchronous generation plant in South Texas that tripped because of loss of excitation caused by an automatic voltage regulator that was in manual mode instead of automatic. In addition, 1,711 MW of solar PV generation — more than twice as much — was lost, much of it from large, grid-connected facilities in the West Texas footprint.

Causes of solar PV reduction (NERC) Content.jpgCauses of solar PV reduction | NERC

According to the report, most of the solar PV sites that responded abnormally to the disturbance in 2022 did so in the 2021 Odessa event as well. Inverter instantaneous AC overcurrent was identified as the leading cause of reduced output in 2022 at 459 MW, followed by inverter phase jump with 385 MW. Neither of these was listed as a cause of reductions in 2021. At the time of the 2022 disturbance, solar PV output made up about 16% of ERCOT’s resource mix, while wind accounted for about 10%; the rest was composed of synchronous generation.

In their analysis, NERC and Texas RE observed that of the solar facilities involved in the 2021 disturbance, only one “was able to deploy mitigating actions between events that resulted in appropriate ride-through performance” in the 2022 event. Although several of the others did implement various changes intended to prevent the causes of reduction in 2021, they suffered reductions for other reasons in the second event. (One made no changes and was not involved in the 2022 disturbance.)

The report noted that some facilities that tripped because of PLL loss of synchronism or inverter AC overvoltage protection in 2021, tripped on voltage phase jump in 2022, indicating that “any one of multiple layers of protective functions within the inverter can result in tripping.” Additionally, changes intended to prevent unnecessary feeder-level tripping that occurred in 2021 led to the same facilities falling victim to inverter-level protection and control issues in 2022.

Stakeholder Steps

As with the previous Odessa disturbance, the report’s authors provided a number of recommendations for NERC, FERC, ERCOT, utilities and other stakeholders.

First on the list was to update NERC’s reliability standards to address gaps in the performance of IBRs. Among the changes needed is a ride-through standard to replace PRC-024-3 (Frequency and voltage protection settings for generating resources). After the 2021 disturbance, NERC’s Project 2020-02 (Modifications to PRC-024) added the issue of IBR performance to its remit. The report said the 2022 event had driven home the “importance of enhancing this standard to a comprehensive ride-through standard.”

The report also noted the standard authorization request (SAR) developed by NERC’s Inverter-based Resource Performance Subcommittee that would require owners of IBRs to “identify, analyze and mitigate any identified abnormal performance issues.” The authors said that NERC “strongly recommends” the SAR be fast-tracked “to get mitigations in place as quickly as possible.”

Next, the report said that NERC will issue an alert to provide generator owners (GO) with recommendations for possible performance mitigations while the standards are being developed. A second alert will “ensure that all GOs of [IBRs] provide adequate proof that the dynamic models match actual equipment controls, settings and protections.” GOs will be required to report any discrepancies to the ERO Enterprise, along with transmission planners and planning coordinators, to ensure corrective actions are implemented.

Recommendations to GOs, generator operators (GOP), transmission owners and equipment manufacturers include checking their dynamic models to ensure accuracy and implementing regular validation processes while adopting applicable NERC reliability guidelines. For FERC, the report advises improving the “generator interconnection procedures and agreements to address issues pre-commissioning” that are not covered by NERC’s standards.

Finally, the report recommends that ERCOT “continue its strong stakeholder outreach and education program” to GOs and GOPs of IBRs to ensure they are implementing appropriate mitigation actions and conduct a system model validation effort to “ensure that those models reflect as-commissioned equipment settings and can accurately recreate system events.”

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PJM Operating Committee Briefs: Dec. 8, 2022

Revisions to IROL CIP Issue Charge Rejected

The PJM Operating Committee last week rejected modifications to its issue charge exploring the compliance costs for generators determined to be critical to maintaining interconnection reliability operating limits (IROLs) under NERC’s Critical Infrastructure Protection (CIP) standards.

The proposed revisions from the Independent Market Monitor, which received 22% support, would have rewritten a portion that states that facilities designated as critical “may face significant incremental compliance costs with no existing means to recover the costs” to instead say that they may face “incremental compliance costs.” They would have also rephrased a passage charging stakeholders with examining “how” costs should be recovered to “whether” they should be. The revisions would have also laid out steps for exploring a cost-of-service solution or allow for “cost recovery under current market mechanisms.”

Stakeholders were largely concerned that the language would lead to generation owners having to recover costs through their market offers, reducing their competitiveness and potentially forcing facilities identified as critical to retire.

“It would seem to me that, given all those issues at play, if we tried to recover these through a market mechanism of any sort, there’s no guarantee that any of those costs would be recovered,” said Paul Sotkiewicz of E-Cubed Policy Associates.

Jim Davis of Dominion Energy said the annual nature of the IROL review means that a generator could be designated critical one year, be required to reach compliance in approximately that long and then the following year no longer be considered a critical facility, making it even harder to recover costs.

Deputy Monitor Catherine Tyler said the language does not point to a specific solution. If the outcome were to be that generators recover the costs through the market, she argued that it would not be a significant enough expense to impact a facility’s competitiveness.

“We don’t think this is something that’s going to push these resources out of the market in any way; it would simply allow for an efficient way to take them into account in the market,” she said.

Review of Lessons Learned from June Outages in Ohio

PJM discussed lessons learned and improvements to procedures and training that can be made based on experiences from a storm in mid-June that left 240,000 customers in Ohio without power through a series of load-shedding orders between June 14 and 16. (See Vegetation Eyed in AEP Ohio Outages Following Storms.)

Donnie Bielak, PJM senior manager for dispatch, said the event represented the first time PJM staff experienced overlapping overloads and multiple cascading outage conditions. The closest incident he could point to was the cascading failure seen in California in 2011.

“This is the first time we’ve had our eyes on this kind of analysis,” he said.

A review of the incident recommended enhancing training to dispatch staff to include simulations with multiple overloads and potential cascading conditions, consider the tools used by dispatch staff to evaluate events with the potential for cascading outages, and improving dispatch procedures for additional clarity and decision-making guidance for pre-contingency load shedding.

PJM’s Jack O’Neill also reviewed the performance of demand response throughout the event, with analysis showing it performed at approximately 86% over the 21 hours it was called upon.

Fuel Supply Update

Production and inventories of coal and natural gas are improving despite price volatility, while inventories of distillate and residual fuel oil remain well below their five-year averages.

PJM Principal Fuel Supply Strategist Brian Fitzpatrick said congressional legislation that averted a railroad strike improves concerns about transportation of coal, but it’s unclear if ongoing delivery inefficiencies that have been seen over the past few years will be alleviated. Coal prices remain high, reflecting strong demand worldwide, while production is 3% higher than this time last year.

Natural gas is currently seeing record production levels, bringing inventories to 2.4% below the five-year average — a turnaround over reserves being at the lower end of the five-year range in recent months.

Inventories of distillate and residual fuel oil have both remained below the five-year range throughout the year, with approximately 30 to 40 days of supply currently available, Fitzpatrick said.

Other OC Action

Stakeholders endorsed manual revisions to clarify the internal network integration transmission service specific to cross-border processes, as well as administrative cleanup. Jeff McLaughlin said the revisions do not have an impact on rules or processes. The revisions still require the approval of the Markets and Reliability Committee, which is set to vote on the language in January.

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NJ Assembly Committee Advances Renewable Natural Gas Bill

A New Jersey bill to boost the use of renewable natural gas (RNG) and promote investment in supporting infrastructure has advanced amid vigorous opposition from environmental groups and strong support from business and union interests.

The state Assembly Telecommunications and Utilities Committee backed the bill (A577) Monday on an 8-0 vote, after more than an hour of testimony, sending it to be considered by a second committee before possible consideration by the full Assembly. The bill has not moved out of committee in the Senate.

The bill directs the New Jersey Board of Public Utilities (BPU) to establish an RNG program in which utilities would procure the gas and invest in associated infrastructure.

A577 also would require the BPU to create a ratemaking structure to allow utilities to recover their investment and the operating costs incurred in providing the gas to consumers, and the costs of procuring it from a third party.

“A charge assessed to customers for the supply of renewable natural gas shall be regulated by the board and shall be based on the cost to the gas public utility of providing that supply,” the bill states.

The bill’s advance comes as the state otherwise seeks to minimize use of natural gas, with vigorous solar and offshore wind programs and an emphasis on electrification. The state masterplan calls on end-use consumption to be “largely decarbonized and electrified” by 2050.

RNG is biogas that has been upgraded for use in place of fossil natural gas, according to the EPA. The biogas used to produce RNG comes from a variety of sources, including municipal solid waste landfills, digesters at water resource recovery facilities and livestock farms.

‘Win-win’ or ‘Dirty’ Bill?

Supporters of the RNG bill, among them the New Jersey Chamber of Commerce and New Jersey Business and Industry Association, two of the largest business groups in the state, argued that the bill would create an alternative to electricity as the state seeks to reduce its carbon emissions.

Also supporting the bill were the New Jersey branch of the International Brotherhood of Boilermakers union and the New Jersey Energy Coalition, an advocacy group whose membership includes utilities and unions.

“This bill is a win-win,” said Chris Emigholz, a lobbyist for NJBIA. “It allows us to diversify our energy portfolio, which is always a good thing, doing it in a way that will allow us to get to our carbon reduction goals in a sooner manner.”

By backing RNG, “we’re allowing innovation to happen in our state, we’re creating more jobs, and we’re supporting economic development,” Emigholz said.

Michael Egenton, executive vice president at the New Jersey Chamber, called RNG a “versatile innovative fuel” that “reduces greenhouse gas that would otherwise be emitted from using the same amount of conventional natural gas.

“To effectively address our worldwide complex environmental challenges, we need a diverse portfolio of solutions that can work together,” he said. “Renewable natural gas helps decarbonize energy and combats climate change.”

But opponents said using RNG would be expensive and do little to reduce carbon emissions. It would simply force ratepayers to support investment in gas infrastructure and prolong the use of natural gas, they said.

“This bill would promote, perpetuate and inflate dirty gas in New Jersey,” said Matt Smith, New Jersey State Director of Food and Water Watch, who called it a “dirty-ass rip-off bill.”

“The climate science is quite clear that we need a rapid, planned, fair and an equitable transition off of polluting fossil fuel infrastructure and on to truly clean renewable sources,” he said. “This bill would take us in the opposite direction, specifically [it] will perpetuate and inflate dirty gas and more dirty gas infrastructure.”

He said studies have shown that the U.S. can only produce enough biogas and synthetic gas by 2040 to replace about 3%-7% of the country’s 2019 gas use, and so adopting RNG would have a minimal impact on reducing greenhouse gas emissions.

Doug O’Malley, director of Environment New Jersey, said RNG costs up to five times as much as conventional natural gas.

“We’re already seeing a 25% increase for gas prices right now,” he said. “And we now have a bill that would invest, provide subsidies and a cost recovery mechanism for a fossil technology, which will be at least five times as costly.”

In a Dec. 2 letter to the committee expressing concerns about A577, the New Jersey Division of Rate Counsel also noted the outsized cost of RNG compared with natural gas. The letter added that it is “unclear that relying on burning renewable natural gas for heat and cooking is more beneficial to the environment than natural gas.

“Both create emissions on consumption,” the letter said. “Although renewable natural gas may bypass the environmental impact associated with extracting natural gas from the ground, it is not clear how the legislature finds and declares that renewable natural gas is necessarily more beneficial.”

RNG “creates similar emissions to natural gas, costs more and at high rates of consumption could require costly equipment upgrades in the homes and businesses of thousands of consumers,” the letter, signed by Brian O. Lipman, director of the Division of Rate Counsel, said.

Ocean Energy Backed

The bill’s advance came about 10 months after the Senate backed S4133, which would prohibit any state agency from enacting a requirement that makes electricity the “primary means” of heating or providing hot water to commercial or residential buildings in the state.

The bill echoed so-called called “preemption bills” in about 20 states that were designed to prevent electrification requirements being enacted, but it died at the end of the legislative session in January with no action by the Assembly. Media reports have depicted the electrification preemption bills as a campaign waged by the natural gas industry to protect its interests.

Also in the last session, the Assembly Telecommunications and Utilities Committee passed a similar bill to A577, A5655, but it did not advance.

In a separate vote Monday, the committee also backed A4483, which would require the BPU to create a pilot project to study the potential of ocean power, especially wave and tidal energy. The bill requires the agency, within 12 months of the completion of the pilot, to work with the state’s Department of Environmental Protection to evaluate and file a report on the feasibility and benefits of using wave and tidal energy as forms of clean energy in the state.

The report must also include a strategic plan identifying wave and tidal energy generation goals, and a timeline by which they should be met.

Assemblyman Robert Karabinchak (D), one of three sponsors of A577, said as testimony began that RNG would be “obviously, in addition to the renewable energy sources that we are currently doing,” such as wind and solar.

“The most important thing is that all of the people in New Jersey have the ability to have a source of energy for their homes, their businesses,” he said.

Alternatives to Electricity

After the testimony, two Republicans expressed skepticism that the state could build an energy future based solely on electricity. Assemblywoman Beth Sawyer noted that, on a recent trip to see her son in California, she had taken note of multiple advisories to electric vehicle drivers not to charge their vehicles between 4 p.m. and 7 p.m. due to measures intended to prevent blackouts.

“So, if you’re going to ask the residents of New Jersey that they cannot charge their electric cars, which everybody is pushing, and then you’re going to try to electrify their homes — this is something that we have to think about,” she said. “Asking to go to one source of energy is not the answer.”

Assemblyman Christian Barranco, a union electrician who said he had done work for utilities, including PSE&G and Jersey City Power and Light, said that although he favors moving toward electrification of the state there are limits to how much the system can handle.

“Electrification is not a political dilemma,” he said. “Electrification is an engineering dilemma. We do not have the electrical generation capacity to electrify our energy sector. We cannot heat our homes and our public buildings with electric. It’s not feasible, from an engineering standpoint … We’re going to overload our grid in a moment’s notice if we continue to add electrical loads to our system.”

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FERC Considers Interregional Transfer Requirements

FERC commissioners and stakeholders offered their views on requiring minimum interregional transfer capabilities in a workshop last week that examined the contentious issue (AD23-3).

Winter Storm Uri lent new urgency to the conversation, commissioners said. The February 2021 storm blacked out much of ERCOT and resulted in the death of more than 200 Texans, showing the dangers of having too few transmission connections to support grid reliability in a crisis.

ERCOT has only 820 MW of transfer capacity with its neighbor SPP, and 436 MW of connections to Mexico, primarily for emergencies.

“We’ve been talking a lot about interregional transmission and interregional transfer capability. There’s an enormous reliability value,” FERC Commissioner Allison Clements said in the workshop’s first session Monday.

Clements cited several recent reports, including last year’s North American Renewable Integration Study (NARIS) by the National Renewable Energy Laboratory, that found interregional transmission expansion could generate up to $180 billion in net benefits through 2050.

A report released in August by researchers at the Lawrence Berkeley National Laboratory, and discussed by its lead author at the FERC workshop, found that 50% of transmission congestion value comes from 5% of hours, with “extreme conditions and high-value periods play[ing] an outsized role,” Clements noted.

And a Grid Strategies study published in February “found that each additional gigawatt of transmission ties between the Texas power grid and the Southeastern U.S. could have saved nearly a billion dollars for every additional gigawatt while keeping the heat on for hundreds of thousands of Texans” during Winter Storm Uri, she said.

“I’ve heard support from a very broad range of stakeholders for a minimum interregional transfer requirement, including the majority of participants in our FERC-NARUC-state task force,” she said, referring to the Joint Federal-State Task Force on Electric Transmission. (See States Back FERC Interregional Transfer Requirement.)

“Part of the appeal of a minimum transfer capability requirement, in addition to its specific reliability benefits, is that it could prove to be a mechanism for aligning regions around a clear goal, and then for unifying processes to reach that goal … so on the merits, specifically and more broadly, I’m a fan of this concept,” Clements said. “Of course, it raises real questions.”

For instance, she asked, what legal basis does FERC have for requiring minimum interregional transfers? And, “assuming that basis exists, how should the minimum be set between regions?”

PJM transferred electricity to MISO and MISO to SPP during Winter Storm Uri, limiting blackouts in MISO and SPP, Commissioner Mark Christie said.

“Those transfers were essential to keeping the lights on during that extreme weather event,” Christie said. ERCOT, which has sparse transmission connections with other grids to avoid FERC oversight, suffered the most.  

“We have interregional transfer capacity,” between regions such as PJM, MISO and SPP, Christie said. “The question is, is it enough? That’s the big question, and how can we get to that number of ‘what is enough?’”

Commissioner Willie Phillips said that in the months since FERC issued its Notice of Proposed Rulemaking on long-range transmission planning in April, “I have called for looking into whether the commission should require a minimum amount of interregional transfer capability.

“Interregional transmission picks from all of our big priorities,” Phillips said. “No. 1, reliability and resilience, because it strengthens the voltage and minimizes the likelihood of load shed. No. 2, affordability, because it allows ratepayers to access lower cost generation. And No. 3, sustainability, because it accommodates the demand for more clean energy.”

Many states and stakeholders have asked FERC to act on establishing interregional transfer requirements as they face the likelihood of more extreme weather events, he said.

Commissioner James Danly, who has expressed skepticism about FERC’s ability to impose transfer minimums, and Chairman Richard Glick, who has been supportive of the concept, did not attend Monday’s session.

Stakeholders Comment

Stakeholders took different positions on interregional transfers based largely on whether minimum requirements would benefit their regions or prove unnecessary and costly.

Neil Millar, CAISO’s vice president of transmission planning and infrastructure development, said the ISO depends on interregional transfers and sees the need for more transmission but believes its own transmission planning processes, including enhancements underway, will ensure CAISO has sufficient import capacity.

“Given our particular set of needs, the processes we have, as well as the issues that we’re trying to address by improving some of those processes, I’m afraid we’re not seeing a specific minimum interregional transmission capacity necessarily helping that conversation,” Millar said. “We would be prepared to put more emphasis on the existing processes and addressing the challenges within those processes.”

Georgia and other non-RTO states in the Southeast do not need FERC to impose a minimum interregional transfer capability, said Tricia Pridemore, chair of the state’s Public Service Commission.

“Georgia is an example to follow, not replace,” Pridemore said.  

“Existing state and FERC processes and rules have already been established, and they work,” she said. “The Federal Power Act expressly reserves [integrated resource planning] to the states, including transmission. In Georgia, we have a robust IRP process driven by short- and long-term planning research, hearings and commission-driven decisions.”

Before transmission plans go before the PSC, the Georgia Integrated Transmission System (GITS) develops proposals and works through potential conflicts, keeping “nasty cost-allocation, load-balancing and citing disagreements at bay,” she said.

GITS includes investor-owned utility Georgia Power; the Municipal Electric Authority of Georgia, the system operator for 41 electric co-ops; and Dalton Utilities, the “action agency” for the state’s 49 municipal utilities, Pridemore said. The entities also are active in the Southeastern Regional Transmission Planning (SERTP) process, which provides intra- and interstate collaboration, she said.

“Our bottom-up approach maintains reliability and does not put upward pressure on rates by constructing unnecessary or duplicative transmission assets,” Pridemore said. “This level of collaboration is a hallmark of Southeastern utilities.

“Georgia is better for maintaining a safe, reliable, affordable system all while not being told to do so from a top-down governance structure,” she said. “A minimum [interregional transfer] requirement may be right for an RTO state, but the processes, rules and collaboration I’ve outlined demonstrate there isn’t a need in a non-RTO state such as Georgia.”  

Liza Reed, research manager for electricity transmission at the Niskanen Center, said the Southeast and other regions remain vulnerable to crises because of their limited transfer capacity with neighbors.

The Washington D.C.-based “open society” think tank conducted a study that found most neighboring transmission planning regions in the U.S. have less than 5 GW of transfer capacity and some less than 1 GW, Reed said.

“These small values represent less than 10% and often less than 5% of the peak load in each region,” she said.   

Transfer capacity is 1% to 3% of peak load between SPP and ERCOT, PJM and NYISO, WestConnect and SPP, and between the non-RTO Southeast, including Florida, and adjoining regions, the study found.

Reed said that 15% is a “pretty standard resource planning margin” and recommended that 15% of peak load be used as a “starting level” for transfers between transmission planning regions.

“There’s ample evidence from the last few years alone that interregional transfer keeps the lights on and saves lives,” she said. “I encourage the commission to consider ways in which ERCOT can be consulted and involved in a minimum transfer requirement that does not leave the good people of Texas out in the cold again.”