A bill to provide funding to deal with Washington’s droughts received strong support in a legislative hearing Friday.
The Washington Department of Ecology, the Washington Public Utility Districts Association, the Washington Water Trust, and the Washington Conservation Commission testified in favor of House Bill 1138 before the House Agriculture and Natural Resources Committee. Fifteen people signed in as supporters but did not testify.
The bill by Rep. Mike Chapman (D) would create a $2.5 million drought relief fund every state budget biennium, with the 2023-2025 biennium starting July 1. If the governor declares an official drought for part of the state, that fund would be increased up to $3 million.
The Washington Senate unanimously passed the same bill in 2022, but the legislative session expired before the House could vote on it.
When a major drought unexpectedly hit most of Washington in summer 2021, the state had to scramble to find money internally to help rural areas and small cities deal with the effects. Because the drought occurred after the 2021 legislative session had ended, no money had been set aside.
“When [the legislature] completes the budget, you cannot know the streams situation in July, August or September,” said Bill Clarke, representing the Washington Public Utility Districts Association. Washington’s legislative sessions usually end in March or April each year.
In 2021, Gov. Jay Inslee declared emergency drought conditions for roughly two-thirds of the state. The declarations triggered measures including moving water withdrawal allowances from one area to another, finding other emergency water supplies and dealing with situations when water has become scarce enough to hamper the passage of salmon up and down streams.
Inslee blamed the 2021 drought on climate change.
The bill would provide a stable pool of money for drought relief, said Ria Berns of the state ecology department.
“It will lessen a drought’s impacts on the state’s economy,” Jon Culp, of the state conservation commission, said.
FERC on Tuesday approved Public Service Company of Colorado’s (PSCo) request to use the social cost of carbon to help dispatch its generation for the next few months (ER23-158-001, et al.).
The utility has to use the price on carbon to limit the use of its highest emitting power plants under Colorado’s clean energy law. The price on carbon has to be factored into its generation dispatch until PSCo joins an “organized energy market,” which will occur April 1 when it joins SPP’s Western Energy Imbalance Service (WEIS) market.
Once in the WEIS, a price on carbon will no longer be used because the energy market does not price that externality.
The carbon price will only be applied to plants that PSCo owns or contracts with, not spot purchases. The utility told FERC that the carbon price should make more carbon-intensive generation dispatched less often, leading to natural gas and renewables being used more than they would have otherwise.
The carbon price is expected to raise PSCo’s systemwide production costs by about $8.3 million over the first three months of this year. The wholesale customers that fall under FERC regulation will wind up paying $664,000 of that, PSCo said.
FERC found the request to be just and reasonable. Including the state-determined social cost of carbon in its generation dispatch will allow PSCo to meet Colorado’s energy policies, the commission said.
Holy Cross Electric Association asked FERC to reserve the right to reopen the case if PSCo does not join the WEIS as scheduled, but the commission said the cooperative failed to explain why continuing to use the carbon price in such a situation would be unjust and unreasonable. If it does become so, Holy Cross or any other entity would be able to file a complaint at FERC and prove that, the commission said.
The NYISO Business Issues Committee on Wednesday approved proposed tariff revisions to rules for capacity resource interconnection service (CRIS) expiration and transferring.
The revisions are intended to facilitate increased capacity deliverability headroom while lowering the cost of new entry in the capacity market.
The ISO is looking to complete relevant software upgrades by the fourth quarter. The changes would go into effect immediately after FERC approval. (See NYISO Finalizes CRIS Tariff Revisions.)
Although the proposal passed with 90.36% support, there were multiple abstentions. The Long Island Power Authority (LIPA), which called for a roll call vote, was the only stakeholder against it.
David Clarke, director of wholesale market policy at LIPA, said the utility “recognizes the value of many of the CRIS transfer and expiration proposals” but has concerns regarding the “three-year CRIS expiration rule as applied to external unforced capacity deliverability rights.”
“Recent experience has shown that the process to procure external capacity does not align well with the New York capacity market and creates significant challenges to acquire available resources from external control areas with three-year forward commitments for participation in the short-term NYISO capacity market,” Clarke said.
The proposal “places external controllable lines at a competitive disadvantage with internal resource supplies” and “does not address important issues with respect to maintaining CRIS for inter-ISO capacity sales,” he said.
The revisions go before the Management Committee on Jan. 25, and the ISO anticipates obtaining Board of Directors approval and filing with FERC before the end of the first quarter.
Winter Storm Price Impacts
Rana Mukerji, NYISO senior vice president of market structure, presented the committee with the ISO’s monthly market performance report for December, highlighting how the winter storm significantly impacted energy prices across New York. (See FERC, NERC Set Probe on Xmas Storm Blackouts.)
The storm drove up natural gas prices, causing the locational-based marginal pricing to reach an average of $110.17/MWh, more than double the $52.47/MWh seen in November 2022 and nearly 130% higher than the $47.99/MWh from December 2021.
When asked about how the storm can be viewed historically, Mukerji said it was “certainly exceptional” and that the closet comparison is the 2013/14 polar vortex.
Bouchez Named Consumer Liaison
NYISO announced that Nicole Bouchez, principal economist of market design, would be taking over the duties of consumer impact and interest liaison, replacing Tariq Niazi, who retired at the end of last year.
Bouchez has been with NYISO since 2003 and principal economist since 2011. She was also co-chair of the Integrating Public Policy Task Force, a joint group with the New York Department of Public Service that solicited stakeholder proposals on carbon pricing, in 2017-2018.
Bouchez said consumer interest is an exciting area and enables her to continue being involved in market design discussions.
Battery electric trucks, including over-the-road big rigs as well as smaller delivery van and box trucks, are expected to play a major role in decarbonizing the nation’s transportation sector, which accounts for 29% of all CO2 emissions.
The North American Council for Freight Efficiency (NACFE) has already demonstrated that even large Class 8 trucks traveling regular routes of up to 200 miles daily can replace diesel-powered big rigs. (See Report: Electric Heavy-duty Trucks Can Now Replace Some Diesels.)
That report, rich with details from onboard electronic monitors on 13 participating fleets in 2022, kept track of mileage driven, speed, the state of the battery charge, the amount of power provided by regenerative braking, the weather and the number of deliveries in real time. It concluded that electric fleets could deliver freight at lower costs based on the cost of diesel fuel and electricity during the testing.
And because electrics have fewer systems than modern diesels, and therefore lower maintenance costs, NACFE argued in 2022 that total cost of ownership of an electric would be lowered than that of a diesel vehicle.
This year NACFE is planning to look just as closely at eight charging depots used by trucking companies and freight divisions of some manufacturers that have switched from diesel to at least 15 electric trucks. Planning is already well underway. But the identities of the participating companies — and utilities — have not been released.
NACFE announced the project in a recent newsletter.
The in-depth look at the operation of charging depots of freight carriers and manufacturers with fleets that run 100 to 300 miles daily on prescribed routes, often called regional haulers, will run from mid-September to the end of the month.
“They are the ones that are making these decisions,” Mike Roeth, NACFE executive director, said of the switch that has begun in favor of electrics over diesels. “There is no typical depot, but it’s not uncommon for a site to have 40 or 50 trucks, maybe 100 trucks.”
And that means replacing diesel with electric take close cooperation with a company’s local utility. NACFE has been talking with some of these utilities as well, said Roeth.
“When you [are running] 75 or 100 [electrics], you are talking 4, 5 or 6 MW,” he said. “The utility needs to be heavily involved.”
He added that utilities appear to be more interested in a depot converting to a large number of electric trucks at once rather than adding a small number of electrics annually.
“There’s a lot of investment involved,” he said. “I think the utilities will actually like that because they will have more certainty that [the charging depots] are going to need the power.”
Roeth said NACFE, created initially to help trucking companies wring more efficiency out of existing diesel vehicles, has focused on battery electric systems rather than electric fuel cell trucks or high-tech diesel engines capable of burning hydrogen because battery electrics are simpler and available now.
Acknowledging that the U.S. Department of Energy has allocated more money for hydrogen in future trucking, Roeth argued that the budget does not mean the department favors hydrogen.
“The government is spending money on hydrogen because it’s a harder nut to crack. It’s a harder solution, and we’re not there yet,” he said.
“We are going to need [hydrogen fuel cell vehicles], but they are not the quick answer that people think. Our research and work shows that it is pretty clear and straightforward to electrify and go battery electric with whatever vehicle you can, and then use hydrogen where [electrification] just can’t be done. Hydrogen is going to follow electric trucks by eight or 10 years,” he said.
Environmental groups on Friday appealed the New York Public Service Commission’s approval of a cryptocurrency miner’s purchase of a gas-fired power plant to the Supreme Court in Albany County.
The Clean Air Coalition of Western New York and the Sierra Club argue that the PSC did not weigh the impact of its decision on greenhouse gas emissions and disadvantaged communities.
The PSC voted Sept. 15 to allow a subsidiary of Digihost Technology to buy the 60-MW Fortistar North Tonawanda peaker plant, where the Canadian company had already begun crypto mining operations. FERC in December also signed off on the sale. (See FERC OKs Sale of NY Power Plant to Crypto Miner.)
Earthjustice filed the petition on behalf of the two environmental groups. New York’s Climate Leadership and Community Protection Act, the groups assert, allows deviation from greenhouse gas-reduction mandates only with justification — and not at all, if the deviation would disproportionately burden disadvantaged communities, such as North Tonawanda.
By ramping the Fortistar plant up from a sporadically used peaker to a continuously running crypto miner, the sale would increase emissions without justification and negatively impact nearby residents, Earthjustice argued.
The argument strikes at the Wallkill Presumption, a state policy in place since the early 1990s by which the PSC undertakes only reduced review of ownership transfers if it determines there will be no monopolistic or anticompetitive result.
The PSC said environmental concerns were beyond the scope of its initial, limited review of the proposed Fortistar sale; it could look only at whether the transaction would create an opportunity to exercise horizontal or vertical market power or create potential to harm ratepayers. There would be no such impact, six of the seven commissioners said, and therefore the PSC would not undertake an expanded review.
FERC also found no impact on horizontal or vertical competition, no adverse impact on rates, no impairment of regulation and no cross-subsidization.
Cryptocurrency mining has been under fire in New York for the carbon footprint of its huge electrical demand, and the state recently placed a two-year moratorium on permits for carbon-fueled operations. That first-in-the-nation move does not halt existing operations. (See NY Slaps Moratorium on Certain Crypto Mining Permits.)
The crypto operation at the Fortistar plant has been the target of noise and environmental complaints, although it also has supporters, as do other mining operations in the economically stagnant upstate region.
In regulatory filings, Digihost said there would be no change in the day-to-day operations after the purchase. The same company running it under contract since 2002 would continue to operate it, and it would sell whatever electricity it does not use on site on the wholesale power market.
In response to critical comments during the state review — including by Sierra Club and the Clean Air Coalition — Digihost said it intended to convert the plant to run on renewable natural gas and then hydrogen. It said this would make it entirely powered by zero-emissions sources by 2025 and thereby compliant with New York’s increasingly stringent climate protection laws.
The environmental groups are seeking to have PSC’s Sept. 15 approval vacated and for payment of court costs for bringing the action.
“The Public Service Commission can no longer ignore the impacts of its decisions, especially when they run counter to public benefit and endanger the air quality for communities already burdened with a disproportionate amount of pollution,” Roger Downs, conservation director for the Sierra Club Atlantic Chapter, said in a news release Friday. “Allowing a failing gas-fired power plant to be acquired and revived by an energy-hungry crypto mine, without considering the environmental impacts, runs counter to the intent of the climate law and the justice it seeks to advance.”
“New York’s landmark climate law means that agencies can’t ignore the climate and environmental justice consequences of their decisions,” said Dror Ladin, senior attorney at Earthjustice. “We’re calling on the court to hold agencies accountable and ensure that cryptocurrency miners don’t get a free pass to heat our planet and damage our communities.”
WASHINGTON —The Bureau of Land Management is updating its 2012 Western Solar Plan to increase renewable energy development on public lands in the West, loosening key technical criteria for prospective projects and adding five states to the area covered by the plan.
BLM officials speaking at a public meeting at the Interior Department on Friday said a new, expanded solar plan for the region could include Idaho, Montana, Oregon, Washington and Wyoming, along with the six states already covered by the plan: Arizona, California, Colorado, Nevada, New Mexico and Utah.
The BLM is proposing to expand the Western Solar Energy Plan to include Idaho, Montana, Oregon, Washington and Wyoming. | Department of the Interior
The 2012 plan also excludes projects from public lands with slopes greater than 5% and where solar insolation — the amount of energy that can be produced — is less than 6.5 kWh per square meter per day.
“These criteria were developed based on early limitations for the prior prevalent technology, concentrated solar, rather than the current prevalent technology, photovoltaic systems,” Leslie Hill, counselor to the director at BLM, said. “So we’re interested in whether the BLM should continue using technology-based criteria to exclude lands from solar development. “
Such criteria are “static, inflexible.” Hill said. “So, they don’t change as technology or technological feasibility changes.”
In addition, Hill said, “the BLM has more experience evaluating potential solar development on public lands. More is known about avoiding or minimizing resource impacts from solar projects, and solar development demand has [grown] beyond the Southwest and California.”
The Washington event was the first of 12 in-person “scoping” meetings the BLM will hold in the coming weeks to gather public input on changes the agency should consider to the plan to increase solar development in the region. In addition to the D.C. meeting, in-person sessions will be held in each of the eleven states being considered in the plan.
“We’re mindful of balancing the needs of clean energy with our responsibility to manage important environmental, cultural and historic resources on our public lands,” BLM Director Tracy Stone-Manning said in opening remarks at Friday’s scoping session. “As we work through this process, BLM intends to work with states, tribes, local governments and the public.”
Based on input from these and other stakeholders, the BLM will draft a “programmatic environmental impact statement” (PEIS), which “will predominately evaluate the environmental effects of potential modifications to improve and expand the BLM’s utility-scale solar planning,” according to a December announcement in the Federal Register.
Individual projects on federal land must undergo an extensive environmental review under the National Environmental Policy Act (NEPA). Hill described a PEIS as a “broad, high-level NEPA review.”
“We won’t be analyzing specific solar energy projects,” she said. “However, the analyses in this programmatic EIS will allow for greater efficiency in preparing NEPA documentation for individual projects by reducing repetitive analysis.”
The scoping period will end on Feb. 28. BLM is planning to release a draft of the PEIS this summer, with another comment period to follow, Hill said.
41 Projects Permitted
Beyond the need to update a 10-year-old plan, the main impetus for the new PEIS is the Biden administration’s drive to deploy more solar on public lands as part of its “all-of-government” approach to counter or slow the mounting impacts of climate change.
In his 2021 executive order on tackling the climate crisis, President Biden ordered the Interior secretary to review siting and permitting processes for renewable energy projects on public lands with the goal of increasing “renewable energy production on those lands … while ensuring robust protection of our lands, water and biodiversity.”
But even before Biden took office, the Energy Act of 2020 set a 25-GW target for renewable energy development — solar, wind and geothermal — on public lands by 2025. BLM says it has permitted 41 solar projects, 23 of which are in operation, totaling about 3.7 GW. The remaining 18 projects, totaling 5.5 GW, are classified as “pending construction.”
California leads the West, with 11 projects in operation and eight pending construction.
Under the Western Solar Plan, BLM created “solar energy zones” (SEZs) totaling 284,918 acres across the 97.9 million acres the agency classified as available for potential renewable energy development. Project development was encouraged in these areas, which were considered to have low potential for environmental or other permitting conflicts.
More than 78 million acres were excluded from development, based on a range of environmental and other criteria, such as whether the land provides critical habitat for endangered species or includes “traditional cultural properties and Native American sacred sites.”
Another 19 million acres were labelled “variance” areas, in which solar development was allowed, based on a careful and detailed environmental review to assess for “anticipated conflicts with sensitive and high-value resources.”
The BLM is also seeking input on whether to include these smaller regional plans in the review for the PEIS.
‘Smart From the Start’
Only two people spoke at Friday’s in-person session, but they represented some of the conflicting interests BLM will need to integrate into its review.
Ben Norris, senior director of regulatory affairs for the Solar Energy Industries Association, raised three issues that would help increase solar development on federal lands, beginning with an increase in the amount of land open for new projects.
Norris supported the expansion of the Western Solar Plan into new states, but he said, “The solar industry is also concerned about the large disparity between lands available for oil and gas leasing and lands available for solar. At least 30 times as much onshore acreage is open to oil and gas as compared to solar.”
SEIA also supports the elimination of the current technical criteria for excluding land from solar development — the 5% slope and 6.5 kWh/m2/day insolation requirements. The approval process for projects in variance areas should be streamlined, he said.
“Most solar development on BLM land occurs in these variance areas, which highlights the need to expand existing priority areas, and the current variance process can be complex, time-consuming [and] resource intensive,” Norris said. “A more efficient variance approval process with increased transparency will reduce permitting times and increase regulatory certainty.”
Nathan Marcy, senior renewable energy and wildlife policy analyst with Defenders of Wildlife, said his organization supports “well-planned” development of solar on public lands, provided it does not “worsen the biodiversity crisis through impacts to sensitive species.”
He called for BLM to use a “smart from the start” approach to renewable energy development on public lands, which first identifies “areas with sensitive resources that are not compatible with solar energy development.” All current environmental criteria for exclusion zones should be maintained and possibly expanded to “consider additional criteria, in particular regional habitat connectivity” — maintaining corridors for wildlife to move through existing habitats.
In designating new solar zones, Marcy said, “We urge the BLM to strongly consider mine lands, brownfields and other disturbed sites. We would also stress the importance of locating SEZs near transmission infrastructure as the lack of access to transmission has limited their effectiveness thus far.”
RENSSELAER, N.Y. — NYISO on Friday announced that it had completed the final interconnection studies for its Class Year 2021 (CY21) group of projects.
The 27 wind, solar, energy storage and transmission expansion projects, which total 7,452 MW, had gone through multiple rounds of decision-making. (See “Class Year 2021,” NYISO Operating Committee Briefs: Dec. 15, 2022.) Assuming NYISO sticks to its timetable, Class Year 2022 will begin the week of Feb. 12. (See “Decision Process and Timeline,” NYISO Class Year 2021 Cost Allocations Advance to OC Vote.)
“These projects will help move the state closer to the ambitious clean energy mandates of the Climate Leadership and Community Protection Act,” Zach Smith, vice president at NYISO, said in a statement. “As pleased as we are with this major accomplishment, we’re already preparing to begin the next class year.”
In an accompanying white paper, NYISO has sought to accelerate the Class Year process by balancing flexibility with grid reliability because of the influx of new projects in the interconnection queue.
These efforts have included eliminating elements of the system reliability impact study, engaging stakeholders in the interconnection process more and improving the management of “material modification” requests from developers.
NYISO said it is also investing in its engineering, legal and technical teams to ensure projects move quickly through the interconnection process without sacrificing critical analysis needed to support grid reliability.
AUSTIN, Texas — Texas regulators last week continued their deliberations of proposed ERCOT market redesigns, narrowing their focus to the favored performance credit mechanism.
To the disappointment of some, however, the Public Utility Commission did not take a vote on whether to recommend the market mechanism to lawmakers as its preferred design. The Texas Legislature opened its 88th session Jan. 10 and has been openly skeptical of the PCM, as it is known, and wants to see new dispatchable generation (i.e., thermal) added to the system. (See ERCOT Survives One Test, Faces Another.)
Michele Richmond, who leads a trade association representing ERCOT generators and wholesale marketers that supports the PCM, said she found the long day’s discussion to be “very good,” but still wanting.
“A decision is what gets movement on new investment. A recommendation to the legislature is not a decision. It’s a recommendation,” she told RTO Insider following the Jan. 12 meeting. “The commission should adopt a decision on [the market design]. And then, if the legislature wants to weigh in, if they want a new direction, then that’s what should happen.”
Following the 2021 deadly winter storm, lawmakers directed the PUC to establish a reliability standard to ensure operations during extreme heat and cold weather and when output is reduced from weather-dependent wind turbines and solar panels. The commission has promised to send its preferred market design to the legislature for its feedback, as PUC Chair Peter Lake reminded his fellow commissioners and those listening.
“If implemented. We still have to hear from the legislature,” Lake said of one suggested market change. “Subject to consideration by the legislature,” he said of another.
“Today’s discussion was a deliberation, not making a decision on anything or recommending anything,” Lake said in concluding the day’s discussion.
The commissioners agreed to return to their open meeting room Thursday to continue their deliberations, with the goal of selecting a “policy direction” to fulfill their statutory obligation and ensure “reliability during periods of low non-dispatchable power.” They will return on Jan. 26 to issue a final order.
That would be just fine with Richmond. Her Texas Competitive Power Advocates (TCPA) organization has said its members are committed to adding 4.5 GW of additional thermal generation to the ERCOT system if the PCM is adopted under the “right framework.”
TCPA members have banded together to create a website that points out it takes time and regulatory certainty to build new power plants. It includes a countdown clock that indicates a new power plant could come online as soon as April 25, 2025, assuming the PUC reaches a policy decision Thursday.
“I heard some pretty good consensus that something needs to be done,” Richmond said. “I think the point that was made is that [the PCM] does get new investment.”
The PCM, one of six alternatives studied by a San Francisco consulting firm, rewards generators for performance credits based on their performance during a determined number of scarcity hours. Those credits must be bought by load-serving entities based on their load during those same hours or exchanged by LSEs and generators in a voluntary forward market to hedge against negative outcomes in the retroactive settlement process. (See Proposed ERCOT Market Redesigns ‘Capacity-ish’ to Some.)
Katie Coleman, who represents Texas Industrial Energy Consumers, said the PCM is nothing more than a capacity market, anathema to many ERCOT stakeholders. Commissioner Will McAdams appeared to wince as one speaker mentioned “capacity market” in his testimony.
“It’s got all the problems a capacity market usually has,” Coleman said of the PCM while preparing to return from a weekend getaway. “It’s purely an administrative way for the government to order certain dollars to generators. The only difference with the PCM is that it’s backward looking.
“It diverts dollars to generators. It’s going to cost consumers billions of dollars,” Coleman added. She said that given most reliability events are caused by operational issues such as unpredictable weather or outages, the PCM won’t materially improve reliability.
The consultant’s own report to the PUC argues the PCM would result in an extra $460 million in annual system expenses by 2026, about a 2% increase over projected system costs. The firm, Energy and Environmental Economics (E3), did not recommend the mechanism, saying it was too complex. Instead, it put forth a forward reliability market as a “more suitable fit.”
E3’s Zach Ming, defending the firm’s report, said that under the PCM, generators receive credits “by being available, not by being dispatched.”
Stoic Energy’s Doug Lewin, a dedicated follower of all things ERCOT, said the PCM’s biggest problem is that it is “convoluted and extremely complicated.”
“That makes it hard to finance,” he tweeted. “Few investors, if any, will put money into long-term assets based on this. But existing generators will get a windfall.”
State Sen. Charles Schwertner (R), who chairs the powerful Business and Commerce Committee, reiterated his committee’s “serious concerns” with the PCM in a Jan. 11 letter to the PUC.
“Given … the clear absence of consensus among energy experts, advocates, and industry, unilaterally moving forward with a market design change such as the [PCM] option without consultation and collaboration with both the Texas House and Texas Senate is imprudent,” he wrote.
The PCM does have its supporters in Texas Gov. Greg Abbott and ERCOT CEO Pablo Vegas. Abbott, who has appointed all five commissioners in the last two years, said in his own filing that the mechanism “must be given strong consideration.”
“The fact that generators have already publicly committed to build thousands of new megawatts of dispatchable generation resources if the PCM is adopted and implemented by the PUC further supports this point,” he wrote.
Vegas said the mechanism “seems to offer the best combination of incentives that move our grid from a system characterized by extreme pricing, physical scarcity and conservation notices” by incenting generators to be available.
He said it will take staff as much as three and a half years to develop the PCM market system.
So, what will happen in the meantime? Vegas and the commission agree a bridge is needed for ERCOT to get by until the PCM is implemented. For the time being, that will consist of additional ancillary services and continued use of reliability unit commitments. RUCs have been in place since the summer of 2021 and raised concerns over the stress imposed on older generators.
The PUC raised the use of reliability must-run resource deployments, which haven’t been issued since 2017. ERCOT ended NRG Energy’s Greens Bayou Unit 5 RMR contract in 2017; the unit was retired shortly thereafter. (See “NRG to Retire 806 MW of Mothballed Resources,” ERCOT Briefs: Week Ending Dec. 11, 2017.)
“I would strongly encourage this commission to avoid any type of policy path that relies on RMR in any way,” NRG’s Bill Barnes said. “An RMR contract means that you’re putting new dollars into one of the oldest, most inefficient resources on our grid. It is literally one of the worst uses of capital.”
“It concerns me that the only options we have are continued RUC and RMR,” Commissioner Lori Cobos said.
Richmond said a phased-in PCM could be installed quicker than other proposed bridge mechanisms, pointing to TCPA’s comments. She said that would signal the market when to self-commit, reducing the need for RUCs and “would provide economic incentives for existing dispatchable resources to remain in service.”
“It has a number of components that exist in the market and are familiar to everybody, so it should be fairly easy to phase that in,” she said.
ERCOT: December Storm ‘Non-event’
ERCOT’s Dan Woodfin, vice president of system operations, called the December winter storm a “non-event,” despite the repeat of thermal outages and gas supply problems that were reminiscent of the 2021 winter storm.
He told the PUC that nearly 6 GW of coal and gas energy came offline after the cold weather swept through the state. Woodfin said global weather models predicted a significant cold weather event for Dec. 22, but the cold was “deeper and quicker” than the forecasts. ERCOT is reaching out to other grid operators who suffered similar under forecasts, he said.
Staff is also contacting generators that went offline to learn what happened. Woodfin said the weatherization requirements now in effect were effective in maintaining supply.
“We can see the grid we have now. The generators we have now are reliable. We just need more of them,” Woodfin told the commission, promising a full report in several weeks.
The PUC also approved its biennial report to the Texas legislature. The report highlights the previous two years since the commission was reorganized after the 2021 winter storm, going from three members to five, and documents in actions in regulating the state’s electric, telecommunications and water industries.
The PJM Planning Committee on Jan. 10 endorsed a proposed solution for capacity accreditation of intermittent resources under the effective load-carrying capability process.
Out of the five proposals before the committee, PJM’s Package I received 82.4% of stakeholders’ support. The proposal’s central feature is a transitional mechanism to allow resources seeking higher capacity interconnection rights (CIRs) to temporarily receive a higher capacity rating. (See PJM Stakeholders Review Proposals on CIRs for ELCC Resources.)
Only Package I cleared the 50% support threshold to advance to the Markets and Reliability Committee. PJM’s Package D received the next highest degree of support, with 34.9%. LS Power’s Packages K and E received 29.3% and 24.1% support, respectively, while Package G from E-Cubed Policy Associates was endorsed by only 7.1%.
How to define existing resources’ capacity rating until a permanent solution can be implemented remained the main sticking point throughout the PC’s discussions of the issue. Most of the proposals, including Package I, would require resources seeking a higher accreditation to re-enter PJM’s interconnection process at the end of the queue, which has been mired in a backlog spanning years.
Package I would also allow resources to utilize existing headroom on the transmission system through a transitional system capability study, though it would also cap the actual accreditation at the facility’s existing CIR. That headroom would be available so long as it is not claimed by another resource’s CIRs and until PJM has completed the process of transitioning to its new methodology of studying interconnection requests.
To be eligible to participate in a transitional study, the additional capacity must be deliverable without any physical modifications made to the generation resource, and an uprate request must be submitted to PJM.
During a special MRC meeting to “page turn” the proposal Friday, PJM’s Jonathan Kern said the RTO’s goal is to open a 30-day window for submitting uprate requests that would close on March 3.
Stakeholders noted that if the proposal was to be approved by the MRC and the timeline implemented, the window would be opening prior to FERC approval of the changes. Kern said the timing is envisioned to allow PJM to jump on implementation following a prospective commission approval and have everything ready to be included in the 2025/26 Base Residual Auction (BRA) scheduled in June.
“One of the primary goals here is to accomplish all of this in time for the 2025/26 BRA,” he said, noting that the target was part of the package approved by the PC. “We’re committed to making this happen, and this 30-day window is essential, PJM believes, to make this goal.”
The second-highest vote getter, Package D, was the only proposal that would have granted higher CIRs outside of the interconnection process. New deliverability tests would been conducted and been the basis for granting the higher CIRs for existing wind and solar resources starting with the 2023 Regional Transmission Expansion Plan. It was also the only proposal that would have allocated the cost of any transmission upgrades necessary to accommodate the higher capacity ratings to load rather than the generators.
LS Power’s Package K was built off PJM’s prevailing proposal but included a request that the RTO’s Board of Managers direct staff to submit a filing with FERC clarifying that the Reliability Assurance Agreement establishes CIRs as the hourly upper limit for unforced capacity accreditation starting with the 2025/26 BRA.
The company’s other proposal would have immediately limited accreditation to a generator’s CIR level and required those seeking higher accreditation to re-enter the interconnection process at the end of the queue.
While Package E received the highest share of support in an October poll at the PC, PJM overhauled its Package I to include the transition studies and later expanded eligibility to all resources; originally only intermittent generation would have been permitted to utilize the existing headroom.
Package G would have also required resources to re-enter the transmission queue to receive higher accreditation, while also expanding deliverability testing into the shoulder months to capture increasing reliability concerns being seen in those seasons.
Stakeholders Endorse Changes to Generator Deliverability Test
VALLEY FORGE, Pa. — The Planning Committee endorsed by acclamation a PJM proposed slate of modifications to the generator deliverability tests to reflect the higher variability in dispatch as renewable resources continue to be added to the grid.
“We feel this set of changes is necessary to move in the right direction. It needs to be included in the planning process sooner rather than later,” said PJM’s Jonathan Kern.
The changes include merging the summer, winter and light load testing methods, redefining the light load period to reflect solar and wind output, and harmonizing the dispatch procedures. The proposal is intended to take a procedure that is fairly prescriptive and make it more reflective of the reality of what is being seen on the grid.
“We feel that this approach is going to provide a more realistic and conservative stress level than the existing procedure,” Kern said.
PJM will also be providing a software program that will allow for PJM’s results to be replicated by market participants. Kern said that is expected to roll out in the spring and should prevent the changes from causing additional work for transmission owners.
The proposal is set to go before the Markets and Reliability Committee on Jan. 25 for endorsement. If approved at that meeting, it could be implemented as part of the 2023 Regional Transmission Expansion Plan (RTEP).
Load Forecast for Northern Virginia Data Centers Continues to Climb
During the Jan. 10 Transmission Expansion Advisory Committee meeting, Sami Abdulsalam, senior manager of transmission planning, said the region set a summer 2022 peak of 21,156 MW, exceeding the forecasted 20,424 MW. The 2023 load forecast is showing a significantly sharper trend through 2040 than the past two annual forecasts. It’s anticipated that Dominion will see 4.2% to 5% annual load growth for the next 10 to 15 years and could nearly double by 2040. While PJM is still able to maintain voltages in the area, Abdulsalam said it’s becoming increasingly difficult to schedule outages.
The data center growth extends to the north into FirstEnergy’s APS zone, which is expected to see its load grow from an 8,412-MW peak last year to 9,568 MW in the 2028 RTEP, based on the 2023 forecast.
Though the latest forecast goes out to 2040, Abdulsalam said the RTO is only making recommendations on work needed to meet the load growth expected through 2028, which PJM feels is a proper balance between the lead time needed for projects and the risk in forecasting.
Director of System Planning Dave Souder said the Load Analysis Subcommittee worked with data center developers and operators to develop the forecast, including by visiting the region where the development is occurring.
“We have had the ability to actually go down to the Dulles Airport area, and the amount of construction is amazing,” he said.
PJM Reviews Baseline Reliability Projects
PJM reviewed three proposed packages of baseline reliability projects to address violations found in the first window, second cluster of the 2022 RTEP: 26 thermal and 25 voltage flowgate violations in the APS, BGE, MetEd and PECO areas.
Abdulsalam told the TEAC Tuesday that the preferred Option 1 solution has a $154.29 million price tag, less than half the cost of the other two proposals.
Option 1 resolves all violations by making upgrades to existing facilities, whereas both alternatives include the construction of new infrastructure or major rebuilding of existing facilities. The most significant portions of Option 1 are the reconductoring of 27.3 miles of the Messick Road–Morgan 138-kV line and replacing equipment at the two substations at a $49.23 million cost.
Option 2 includes the rebuilding of the Hunterstown–Carroll 115/138-kV corridor as a double circuit 230-kV line and equipment at each substation to handle the higher voltage. At a $148.83 million cost, the work to that line would constitute nearly half of the proposal’s $332.85 million cost
With the highest cost, Option 3 includes constructing a new 500/230-kV station named Rice, tapping the existing Conemaugh–Hunterstown 500-kV line and building 29 miles of new double circuit 230-kV lines from the Ringgold substation to the new Rice substation. A second new 500/230-kV substation designated Furnace Run would be built off the Peach Bottom-TMI 500-kV line. Altogether the package would cost $389.78 million.
