In response to a request from FERC Chairman Richard Glick and NERC CEO Jim Robb, the North American Energy Standards Board (NAESB) confirmed Thursday it will launch a forum aimed at addressing concerns raised after the winter storm of February 2021.
According to a press release from NAESB, the organization has not yet settled on a time or agenda for the forum, but an organizational meeting has been scheduled for 2-4 p.m. CT on Aug. 30 to “discuss the next steps the organization will take to host the forum.” The meeting will be held on Zoom and open to any interested parties.
Glick and Robb suggested the forum in a joint letter on July 29 addressed to NAESB COO Jonathan Booe and board Chairman Michael Desselle, citing FERC and NERC’s joint report on the storms. (See FERC, NERC Call for NAESB Forum on Gas-electric Issues.) The report called for FERC to establish “a forum in which representatives of state legislatures and/or regulators with jurisdiction over natural gas infrastructure [can] identify concrete actions” to improve reliability of the natural gas system as it relates to the bulk electric system.
The winter storms led to widespread generation outages, derates or failures to start that caused more than 23 GW of manual firm load shed mostly in Texas, the biggest firm load shed in U.S. history. According to the FERC-NERC report, natural gas facilities accounted for more than 50% of generation failures, both in terms of the number of units and their total nameplate capacity. (See FERC, NERC Release Final Texas Storm Report.)
Stakeholders in the ERO Enterprise have increasingly come to see the interdependency of the U.S. gas system and electric grid as a significant vulnerability, because of natural disasters like last year’s storms and cyber incidents like the ransomware attack on Colonial Pipeline in May 2021. (See Colonial Hack Sparks Competing Recommendations at FERC.) In their July letter, Glick and Robb said NAESB is “uniquely positioned” to organize the needed dialogue between the gas and electric industries; in their press release, NAESB’s leadership said they appreciated the confidence.
“NAESB has a long history of bringing diverse groups together to find consensus-based solutions to industry problems,” Valerie Crockett, vice chair of NAESB’s Wholesale Gas Quadrant, said in the statement. “While NAESB was not necessarily asked to develop specific standards in response to this request, it can serve an important role by recommending activities that appropriate entities within the energy markets may undertake to support grid stability.”
NAESB did announce a standards project aimed at improving gas and electric coordination in December but has not released any subsequent updates about the initiative. Booe told ERO Insider earlier this month that action had stalled after the organization was unable to “find consensus from our groups” about the appropriate direction of the project, but that Glick and Robb’s call for the forum might help reinvigorate the initiative.
The ERCOT Board of Directors could finally unveil its choice to lead the Texas grid operator in its continued recovery from last year’s winter disaster.
The Texas Public Utility Commission has posted an open meeting notice, as it is required to do whenever two or more commissioners meet together, in advance of Tuesday’s board meeting. The notice indicates the commission will “receive information, and may give information and participate in discussion … and possible action regarding ERCOT CEO selection and ERCOT CEO compensation.”
Texas Gov. Greg Abbott is said to be exerting unusual control over ERCOT. | Twitter
However, according to a well sourced article last week by The Texas Tribune, it is Texas Gov. Greg Abbott who wields the power to choose ERCOT’s next CEO. The Tribune reported that the governor, who is locked in a close re-election campaign with Beto O’Rourke and appealing to his base through a heavy reliance on Twitter, has nixed a search committee’s preferred finalist, former CAISO CEO Steve Berberich, and has unsuccessfully urged Phil Wilson, CEO of Lower Colorado River Authority, to take the position instead.
Berberich has been painted as a No. 1 draft pick because of his ISO and information technology experience. A Texan, he served as TXU Energy’s IT vice president before joining CAISO in 2005. He retired from the California grid operator in 2020 and currently lives in McKinney, Texas, according to his LinkedIn profile. (See CAISO CEO Steve Berberich Retiring.)
Those close to the search told the Tribune the only reasons they were given for Abbott’s veto is because Berberich’s last job was in California. Attendees at SPP’s Markets+ development session last week in Portland, Ore., expressed surprise when the story broke; Berberich had a reputation for speaking colorfully and directly, as he did toward the end of his tenure when he warned of California’s reliability problems.
Berberich apparently had strong support from the market and ERCOT’s board. The directors met in an urgent conference call July 29 that turned into a long executive session. They adjourned the call without voting on any matters.
If no announcement comes this week, it may have to wait until the board meets again in October. That would be perilously close to winter and its potential for more extreme weather. That is also about the time the PUC is expected to take up the second phase of its market design.
Alison Silverstein, an Austin-based energy consultant with regulatory experience at both FERC and the PUC, told RTO Insider she was “appalled” by Abbott’s move, which has not been denied. She said her criteria for picking ERCOT’s next CEO would be “someone with proven experience in running the grid.”
“I don’t care if the [next CEO] is from California or one of ours,” Silverstein said. “I want the best possible person with rock-solid reliability and policy experience and management experience, because the safety of all Texans is the most important factor. Can this person run ERCOT to move us all to a better place in terms of grid reliability?”
Beth Garza, a senior fellow with public policy research firm R Street Institute and ERCOT’s Independent Market Monitor from 2014 to 2019, pointed to ERCOT’s statutory status as the “independent organization” responsible for managing the grid.
“There’s a reason for that,” she said Friday. “Most people would say that’s independent from the market participants and the industry. The other part of that independence is you want an organization that is focused on the best and most appropriate technological ways to deal with whatever the problems are.”
And so Brad Jones, who was appointed as ERCOT’s interim CEO in the wake of the February 2021 winter storm that almost collapsed the Texas grid, is left cooling his heels. What was supposed to be a three-month temporary assignment has now turned into a 15-month gig. Jones has consistently said he doesn’t want the job on a fulltime basis; he said in April that he planned to leave ERCOT in June. (See “Jones: Will Stay as Interim CEO,” Overheard at GCPA’s 2022 Spring Conference.)
“I want to ensure they get the right person into this role,” he said during the Gulf Coast Power Association’s Spring Conference.
It is now August, and Jones is still waiting.
According to the Tribune and confirmed by ERCOT staff, the PUC, with its Abbott-appointed commissioners, reviews and approves every piece of communications before the grid operator releases it. “ERCOT does not speak for Gov. Abbott on what, if any, involvement he’s had,” has been staff’s response.
“The work of ERCOT is so important that I want its CEO and staff’s first priority to always be the integrity of the reliability of the ERCOT power system, minute to minute, every single day,” Silverstein said. “They should be able to operate our grid without having to care about the consequences of political agendas. The CEO’s first job is to make all the essential decisions to protect grid reliability … to run the organization that ensure the reliability of the grid and its resilience. If the CEO has to ask permission to take actions to protect the grid, we’ll lose the grid. We cannot have second guessing.”
Garza agreed, saying, “Politics and power system engineering may not be the best combination.”
Energy Advisory Committee OKs Report
The State Energy Plan Advisory Committee (SEPAC), referred to as a “little-known board of energy executives, oil and gas entrepreneurs and power utilities officials” by The Dallas Morning News, also raised consternation with industry observers last week as it held its second meeting.
The committee was created by legislation passed last year and charged with preparing a “comprehensive state energy plan” that evaluates barriers preventing “sound economic decisions” and the ERCOT market’s structure and pricing mechanisms. The plan, due to the state legislature Sept. 1, must also look at ways to improve the grid’s reliability, stability and affordability.
The committee comprises 12 members appointed by Abbott, Lt. Gov. Dan Patrick and House Speaker Dade Phelan. Chaired by LCRA’s Wilson, its members include NRG Energy’s Bill Barnes, Pedernales Electric Cooperative CEO Julie Caruthers Parsley and Oncor’s Daniel Hall, as well as consultant Joel Mickey and Mike Greene, retired staffers from ERCOT and Energy Future Holdings, respectively.
“Conveniently, the governor chooses Phil Wilson as the chair, because he’s got a large organization [behind him],” Garza said, noting SEPAC’s lack of resources.
The other members come from outside the electric industry, with their lack of expertise exhibited when Patrick Jenevein — with some wind development experience at a small Chinese clean energy projects company (Tang Wind Energy) but primarily focused on natural gas — suggested that coal is a renewable resource, according to energy consultant Doug Lewin.
Lewin was among public onlookers during Wednesday’s meeting, when SEPAC approved a draft of its report 7-5. At least one committee member voted against the draft because of a lack of time to review it, Lewin reported.
The report includes a recommendation that renewable resources be required to provide backup energy, despite thermal resources’ well documented contribution to the dayslong power outages after the winter storm. (See FERC, NERC Release Final Texas Storm Report.)
The report itself has not been publicly released, part of a pattern of secrecy surrounding SEPAC. Its meetings have been posted on the secretary of state’s website, which requires a sophisticated expertise with searches, but they were not livestreamed.
“I’m concerned about the legislature getting advice on something as important as electricity and natural gas policy from an organization that has met only twice and whose [members] haven’t had a significant amount of time to review the material that was developed,” Silverstein said, adding that its members were voting “blind.”
SEPAC “took a vote without the members being able to actually review the contents in detail,” she said. “So, if I were in the legislature, I would use this report, whatever it will ultimately contain, as just another piece of paper. I would not attach any significant weight to it.”
Garza was among several subject-matter experts who testified before the committee during its June meeting. She said at the time she thought it was a “check-the-box exercise” and would amount to little. However, Garza said she found the discussion to be “very valuable” and found herself wishing the PUC “would put themselves in a position to hear that kind of input and discourse.”
“There’ll be a report that goes to the legislature. I have every confidence it’s a report and will be written and given to the legislature,” she said. “What will it contain? Will the contents of that report be meaningfully developed with debate back and forth? No. They took input during one meeting and a second meeting to look at the document.
“You can’t just say, ‘I like a policy; let’s do it without doing an extraordinarily detailed analysis,’” Silverstein said. “It is my hope that the legislature will not jump too quickly to adopt any superficially appealing policy path, but rather rely on the kind of research and analysis on implications and alternatives that can truly give us reliability and affordability and resilience, rather than to catchy headlines.”
MISO and SPP said Friday they have numerous constrained flowgates that could become candidates for smaller, cross-border transmission projects.
The RTOs unveiled a list of their congested flowgates ripe for targeted market efficiency projects (TMEPs) during an Interregional Planning Stakeholder Advisory Committee (IPSAC) teleconference. It’s the first time they have searched for TMEPs. (See MISO, SPP Take on 2nd Interregional Planning Effort.)
The grid operators said that based on preliminary day-ahead market data, they have “numerous” constraints that have amassed a half million dollars or more in congestion annually.
SPP’s Neil Robertson said the frequently congested Neosho-Riverton flowgate on the Kansas-Missouri border was unsurprisingly “prominent” on the list of the most chronically congested permanent flowgates. With $71.6 million in market-to-market (M2M) charges since 2015, the flowgate is responsible for 20.9% of the $341.87 million in M2M settlements.
Neosho-Riverton’s $27 million of congestion charges the last two years is second to the Fargo-Sheyenne flowgate in North Dakota, which racked up about $36.5 million in congestion during 2020-2021.
The rest of the six most congested flowgates each accumulated anywhere from $12 million to $19 million in congestion charges during that timeframe. Robertson said staffs “commonly” found congestion in the Dakotas and along the Arkansas-Oklahoma and Kansas-Missouri borders.
Robertson said the RTOs are using their day-ahead market congestion values in their analysis because the “nuts and bolts” of their market clearing engines differ.
MISO and SPP are trying to get the most accurate congestion data, Robertson said, because congestion data determines which flowgates could use transmission improvements and how project costs are split between the RTOs.
He said the grid operators had gathered a “preliminary sampling” of congestion values that will be refined in the coming weeks. He also said staff are considering evaluating certain temporary flowgates for TMEP solutions and that some temporary flowgates could become permanent.
Robertson said the RTOs are borrowing from the MISO-PJM TMEP playbook, which has approved three small portfolios since 2017. MISO and PJM are working on another possible set of projects.
MISO and PJM TMEPs must cost less than $20 million, completely cover installed capital cost within four years of service and be in service by the third summer peak from their approval. The projects are assessed using a shorter time horizon than interregional market efficiency projects.
“We had to start somewhere, as I like to put it … moving the conversation forward,” Robertson said. He added that MISO and SPP could tweak some of the existing criteria.
He said using a $20 million cost cap, a third summer peak in-service date, and drawing on two years’ worth of historical congestion to determine project needs seems to make sense for the RTOs. The thresholds will ensure that a TMEP study doesn’t encroach on other, longer-term interregional planning on the MISO-SPP seam, he said.
Robertson said MISO and SPP have “vast” support to move ahead with the TMEP concept.
American Clean Power Association’s Daniel Hall asked the RTOs to share whether a project candidate barely misses or slightly overshoots the project criteria. He also said while ACP is a “strong supporter” of a TMEP study, he doesn’t want to see the projects become “Band-Aid solutions to more efficient and effective” projects.
Robertson said MISO and SPP are holding off on finalizing any criteria until they have a better picture of congestion data.
The RTOs don’t plan on recommending a list of TMEP projects until the end of the year. They don’t envision designing regional cost-allocation methods or filing with FERC for approval of a TMEP process until the first quarter of 2023.
MISO and SPP will hold another IPSAC teleconference Sept. 20.
With three coal plants slated for closure within the next 10 years, Arizona regulators, utilities and community members are exploring ways to repurpose the facilities, including options for clean energy generation.
Salt River Project (SRP) is launching a study to see which sustainable energy options would be viable at the site of the Coronado Generating Station, which is slated for closure by 2032. Hydrogen generation and solar with battery storage are among the technologies the study might explore.
SRP is in the process of finding an engineering contractor to help with the repurposing studies, a company representative said during an Aug. 1 Arizona Corporation Commission (ACC) workshop.
In addition, the city of St. Johns, near the Coronado facility, wants to investigate the feasibility of converting the coal plant to nuclear power generation. SRP has been working with the Gateway for Accelerated Innovation in Nuclear (GAIN) on the issue. GAIN is a U.S. Department of Energy Office of Nuclear Energy initiative to accelerate the commercialization of advanced nuclear technologies.
Asset Inventory
Amanda Ormond, co-director of the Just Energy Transition Center at Arizona State University, said during the Aug. 1 workshop that she’s hopeful ASU will receive a grant to look at repurposing the Coronado Generating Station and the Cholla Power Plant, which is scheduled to shut down in 2025. Arizona Public Service is part-owner and operator of the Cholla plant.
Ormond said the study would include an inventory of assets at the power plants, including items such as buildings, roads and water treatment systems. The condition of the assets would also be assessed.
The next step, Ormond said, would be to match the assets with types of businesses that could use them. The study would look at possibilities on a regional level, rather than one coal plant at a time. Ormond said she expects a decision on the grants next month.
The third Arizona coal-fired power plant slated for closure is the Springerville Generating Station, operated by Tucson Electric Power. TEP plans to close one unit at Springerville in 2027 and shut down the final unit in 2032.
The upcoming coal plant closures follow the shutdown in 2019 of the 2,250 MW Navajo Generating Station near Page, Ariz., which SRP operated.
Plant Closure Impacts
The ACC opened a docket in January 2021 to take a closer look at the impact of coal plant closures on surrounding communities. The Aug. 1 workshop was the second commission workshop on the topic.
The commission also held 11 town hall meetings in coal plant communities in April, May and June. In addition, a series of virtual town hall meetings took place last week. ACC staff plan to file recommendations in the matter by the end of September.
Repurposing the Arizona coal plants was also discussed during task force meetings organized by the ACC in March and April.
Ormond said during task force meetings that Arizona State University and Joseph City have been discussing potential new uses for the Cholla Power Station. In addition to renewable energy production, ideas included office space, metal and battery recycling, manufacturing, automotive salvage, or railcar and locomotive repair, according to a written summary of the meeting.
Task force participants noted that the coal plant owners will play a large role in determining the facilities’ future.
National Issue
Repurposing shuttered coal plants is an issue that’s being debated across the U.S.
Creative reuses include the conversion of the Blackhawk Generating Station in Beloit, Wis., into a student union athletics facility at Beloit College, Bloomberg reported. In other cases, retired coal plants have been turned into restaurants or offices.
Some of the facilities are being eyed for hydrogen production. In New Mexico, Escalante H2 Power (EH2) wants to convert the Escalante Generating Station, a coal-powered plant shut down in 2020, into a hydrogen production and power facility. (See Clean Hydrogen Interest Builds in New Mexico.)
The federal government has taken an interest in the future of coal plant communities. In January 2021, President Biden established through an executive order the Interagency Working Group on Coal and Power Plant Communities and Economic Revitalization.
The goal of the Interagency Working Group (IWG) is to coordinate federal aid to revitalize the economies of coal, oil and gas, and power plant communities. In an initial report, the working group identified 25 priority regions that have been hard-hit by reductions in coal production and consumption.
IWG created a clearinghouse of federal funding opportunities that may be available to energy communities.
The working group is soliciting public comments on the challenges facing energy communities and recommendations on how the federal government can help address those challenges. Comments will be accepted through Sept. 9 and may be submitted here.
The California Air Resources Board has named Steven Cliff, administrator of the National Highway Traffic Safety Administration, as CARB’s new executive officer.
Cliff will replace Richard Corey, who retired at the end of June after serving in that role since 2013. (See CARB Top Exec Corey to Retire.) Cliff will start work at CARB on Sept. 12.
CARB’s board made the appointment, which Chair Liane Randolph announced on Friday.
“He is the right choice to implement the board’s vision during this crucial decade as we move ahead with the ambitious policies and programs to tackle the state’s climate emergency and continue to prioritize equity both within CARB’s workforce and in the communities we serve,” Randolph said in a statement.
Cliff is a familiar face at the California agency. He has held a variety of positions at CARB, starting as an air pollution specialist in 2008. While serving as CARB’s deputy executive officer from 2017 to 2021, Cliff’s work included overseeing regulations for all vehicles in the state, including passenger cars and medium- and heavy-duty vehicles.
In October 2021, President Biden nominated Cliff to serve as head of the NHTSA. He was confirmed by the Senate on May 26. Before his nomination, Cliff worked at NHTSA as a senior adviser and deputy administrator, according to his LinkedIn profile.
His transportation experience also includes a stint as assistant director for sustainability at the California Department of Transportation from 2014 to 2016.
Cliff returns to CARB at a critical time. The agency this year is finalizing its climate change scoping plan, a roadmap to bring California to carbon neutrality by 2045. After CARB released a draft version of the plan in May, Gov. Gavin Newsom called on the agency to take “even bolder action” to address climate change. (See Newsom Calls for ‘Bolder’ Climate Action in Calif.)
In addition to his professional credentials, Cliff has experienced the impacts of climate change firsthand. The Napa Valley native has been spending time rebuilding his family’s property after it was ravaged by the Atlas Fire — one in a group of October 2017 wildfires that became known as the Northern California firestorm.
Cliff received a bachelor’s degree and doctorate in chemistry from the University of California, San Diego. He completed a postdoctoral fellowship in atmospheric sciences at the University of California, Davis, where he has also worked as a research professor. Cliff lives in Sacramento.
VALLEY FORGE, Pa. — Illinois’ climate goals could cost other states in PJM and MISO tens of millions in transmission upgrades over the next two decades as coal and natural gas power plants are forced to retire, PJM said last week.
PJM’s Illinois Generation Retirement Study found that the state’s Climate and Equitable Jobs Act (CEJA) could require $700 million in transmission upgrades through 2030 and an additional $1.3 billion by 2045 in the Commonwealth Edison (NASDAQ:EXC), FirstEnergy (NYSE:FE), Duquesne Light Co. and American Electric Power (NASDAQ:AEP) zones in PJM, and the Northern Indiana Public Service Co. (NIPSCO) (NYSE:NI) zone in MISO.
PJM estimated $1.3 billion in transmission upgrades to address thermal violations and $718 million to fix voltage violations as a result of plant retirements forced by Illinois’ Climate and Equitable Jobs Act. | PJM
CEJA, which Gov. J.D. Pritzker signed in September 2021, requires Illinois to eliminate carbon emissions from its electricity sector, with coal and natural gas generators shuttered or converted to zero-emission resources by 2045.
PJM predicts the retirement of almost 12,000 MW of generation by 2030 and nearly 23,000 MW by 2045. The RTO’s study identified plants scheduled to retire or that are likely to retire under CEJA based on publicly available emissions data and published heat rates. The RTO said it confirmed its findings with plant operators.
It also looked at potential replacement generation based on the 200,000 MW in its interconnection queue, 95% of which is solar, wind or hybrids including renewables and storage.
‘Initial Snapshot’
PJM said the study is a “very initial snapshot” of CEJA’s impact and that it is not proposing projects for the Regional Transmission Expansion Plan (RTEP) based on it.
“The cost estimates identified in this study will not actually be charged to consumers today,” PJM said. “As the system evolves with retirements and additions, we will have a better sense of the necessary transmission that will be needed to alleviate any reliability violations.”
PJM’s David Egan, who presented the study results to the Planning Committee on Aug. 9, said transmission upgrade costs could be reduced if the new generation is connected in favorable locations near recently deactivated plants. But upgrades might need to be accelerated if existing generators retire earlier than modeled, he said.
Asked about the potential impact of the incentives for carbon capture in the Inflation Reduction Act, which is awaiting President Biden’s signature, Egan said, “As these mandates or laws change, we will be modifying our studies.” (See related story, House Passes IRA, Sends to Biden’s Desk.)
MISO Impact
PJM said it will combine its study with an analysis MISO is expected to complete late this year or early next to determine optimized interregional projects that could cut costs.
“Our study report is emphasizing that both PJM and MISO recognize the need to collaborate on case assumptions and work together on solutions when appropriate,” said PJM’s Dan Lockwood.
“We anticipate MISO will identify additional impacts and costs,” Egan said.
The study does not include MISO’s long-range transmission plan’s (LRTP) Tranche 1 projects or its additional LRTP study work in the Illinois area.
PJM focused its efforts on MISO facilities along the RTOs’ seam and reviewed results with NIPSCO, the MISO transmission owner facing the biggest impact.
Not Included
PJM did not attempt to estimate early retirements because of current CEJA operational limits on natural gas-fired generation. It also did not include new renewable generation expected to be added to the system under CEJA’s incentives. In support of the bill, the Illinois Commerce Commission in July released its first draft of the Renewable Energy Access Plan (REAP) to improve transmission capacity to support increased renewables.
Costs for reliability-must-run contracts for units that PJM may ask to operate beyond their desired deactivation dates also were not included in the study.
State Impacts
“This puts Ohio in a very precarious position of having to pay for the decisions of another state,” said Mike Haugh, of the Ohio Consumers’ Counsel.
Greg Poulos, executive director of the Consumer Advocates of the PJM States, said he hoped the RTO would look for “opportunities to reduce these costs.”
PJM encouraged stakeholders to attend their CEJA workshop on Aug. 22 to learn more about the law and how it would affect their current or future investments.
Thermal Violations
PJM also identified upgrades that would be needed to comply with the thermal, reactive, stability and short-circuit requirements of NERC standard TPL-001-4.1.
Upgrades for thermal violations are estimated at $1.3 billion (64% of the total), almost evenly split between the 2030 and 2031-2045 study periods. About 15% of the total is for ComEd.
Because not much new generation is projected for Illinois, the study predicts increased East-to-West imports will cause “numerous, significant” thermal reliability violations in both the 2030 and 2031-2045 scenarios, PJM said.
The study said 69 upgrades to PJM’s 138-kV system are responsible for 82% of the thermal upgrade costs, with 16 345-kV upgrades accounting for the remainder.
Voltage Issues
Fixing voltage violations is estimated at $718 million (36%). “Unlike thermal violations, which tend to be more linearly aligned with megawatt impacts, voltage violations are nonlinear,” PJM said.
Voltage instability is expected to emerge by 2030, with widespread violations expected in 2031-2045 from a lack of reactive support in the ComEd area and increased imports into Illinois to serve load.
“If not resolved with system upgrades, [the voltage stability problems] could lead to blackouts driven by voltage collapse,” the report said. “This is indicative of the need for additional transmission system expansion — reinforcements to existing lines or construction of new lines — on East-West transmission paths between ComEd and AEP.”
ComEd and NIPSCO proposed static volt-ampere reactive compensators to address the voltage instability concerns and synchronous condensers to replace the megavolt-amperes reactive (MVARs) capabilities lost with the plant retirements, estimating costs at $525 million and $193 million, respectively.
“Voltage issues generally need to be fixed near where” the generation is removed, said Egan.
PJM’s Sami Abdulsalam said renewables’ ability to provide voltage support is limited. “A megaVAR is a megaVAR once it reaches the grid,” he said. But solar and wind cannot provide MVARs when they are not generating power, unless they also have storage, he said.
Impact on Individual TO Zones
PJM reported the need for the following upgrades on individual TOs:
ComEd: $100 million through 2030 to address thermal overloads, most for a new 138-kV line from Haumesser to West Dekalb to Glidden. ComEd expects an additional $160 million in thermal upgrades after 2030.
AEP: $63.5 million to solve thermal overloads through 2030, almost 80% to rebuild the 138-kV AltaVista-Otter-Johnson Mountain-New London line. After 2030: $178 million to solve thermal overloads, about 85% for a new 345-kV Segreto-Cook line and a rebuild of the 138-kV West End Fostoria-Woodville line.
FirstEnergy: $320 million to address thermal violations caused by an increase in East-to-West power flow by 2030, and about 60% for reconductoring five 138-kV circuits: two between Leroy Center and Mayfield, and three from Charleroi to Union Junction, Westraver and Yukon. After 2030, FirstEnergy estimates $180 million in upgrades to address thermal violations, more than 80% to reconductor the following 138-kV lines: Mitchell-Shepler Hill Junction, Peters-Union Junction, Yukon-Smithton, Leroy Center-Mayfield and Richland-Lockwood (AEP).
Duquesne: $180 million, most for new 138-kV facilities, including a new Elrama substation, two new ties and one new line. About 35 circuit miles of 138-kV reconductor is also needed.
NIPSCO: $125 million in upgrades over the study periods to address thermal-based reliability criteria violations.
PJM Chief Information Security Officer Steve McElwee provided the Operating Committee a security update, saying Russia has continued to show restraint in retaliatory attacks against Western nations supporting Ukraine.
Although there had been concern that Russia would launch widespread cyberattacks, “their focus so far has been to augment their physical attack against Ukraine,” McElwee said.
In contrast, the NotPetya attack had “no boundaries on which organizations were victimized,” he said. The June 2017 malware attack on the websites of Ukrainian banks, ministries, newspapers and electric utilities also resulted in infections in Western Europe, the U.S. and Australia.
Researchers said the attacks they are seeing against Ukraine are contained to prevent collateral damage. However, McElwee said criminal and hacktivist groups like Killnet continue to threaten attacks and casualties on Russia’s behalf. “Most recently, they’ve been targeting Lockheed Martin,” he said.
Hybrid Manual Language Endorsed
The committee endorsed manual language conforming to FERC’s July 12 order accepting PJM’s clarifications on its rules for hybrid resources and mixed technology facilities (ER22-1420-002). The RTO filed its proposal on March 22.
The changes affect Manual 10: Pre-Scheduling Operations and Manual 14D: Generator Operational Requirements. In Manual 14D, the changes concern metering requirements, outage reporting and voltage schedules, with a new section 13 for mixed technology facilities.
Second ‘First Read’ on Max Emergency Status for Coal Plants
PJM postponed a vote on competing RTO and Independent Market Monitor proposals for managing remaining run hours for coal-fired and other generating resources limited by fuel shortages or environmental restrictions.
PJM added references to coal- and natural gas-fired generating units subject to Illinois’ Climate and Equitable Jobs Act (CEJA).
The Monitor had multiple additions, including changing the reference to “fuel” to “fuel and consumables.” It also added more detail to the conditions that qualify as “fuel limits” for being eligible for maximum emergency status. They would be defined as physical events that affect the infrastructure used to “procure, treat or transport fuel or consumables” that are beyond owner control — meaning the generator has no other procurement options.
“Temporary” interruptions would be limited to seven days, with generators required to provide a projected delivery date from the supplier.
The IMM would create a new availability status for “fuel/consumables conservation” that would allow committed capacity resources with 10 days or less of inventory that do not qualify for the maximum emergency fuel limit to make its unit unavailable for economic dispatch. Such units would be subject to a penalty equal to their daily capacity value based on the Base Residual Auction price.
IROL-CIP Cost Recovery
PJM presented a first read on a procedure for obtaining reimbursement for compliance with NERC Critical Infrastructure Protection standard CIP-002-5.1, which requires identification of generating units that are critical to the derivation of interconnection reliability operating limits (IROLs).
Resources identified by PJM as an IROL critical resource would submit their capital and recurring costs for review by the RTO and Monitor annually. PJM would make monthly payments to the generators.
The issue will be brought to a vote at the OC’s meeting next month.
New Cold Weather Advisory
Members heard a first read of manual changes to comply with NERC standards for cold weather preparedness: EOP-011 (Emergency Preparedness and Operations), IRO-010 (Reliability Coordinator Data Specification and Collection) and TOP-003 (Operational Reliability Data).
PJM is creating a new cold weather advisory to clarify RTO and member actions for gathering and reporting information required by the NERC standards. The advisory would be issued more than 24 hours in advance of a cold spell — likely three to five days in advance — and would precede the issuance of a cold weather alert.
The changes will affect Manual 14D: Generator Operational Requirements and Manual 13: Emergency Operation.
Generation owners will be required to ensure updated information on their units’ temperature operating limits in Markets Gateway.
PJM added a recommendation to its Cold Weather Preparation Guideline and Checklist to take into account the effects of precipitation and wind during cold weather preparation.
The committee will be asked to endorse the changes at its next meeting.
Manual 39: Nuclear Plant Interface Coordination
Darrell Frogg of PJM reviewed proposed changes to Manual 39: Nuclear Plant Interface Coordination as a result of a periodic review. The changes include updated references to NERC’s mission and its mandatory standards, as well as a list of revisions to plant-specific nuclear plant interface requirements.
The committee will be asked to endorse these changes at its next meeting.
PPL Dynamic Line Ratings Implementation Confirmed for Sept. 12
PPL (NYSE:PPL) is continuing plans for introducing dynamic line ratings to the double-circuit 230-kV Susquehanna-Harwood and the 230-kV Juniata-Cumberland lines on Sept. 12, PJM’s David Hislop told the committee.
A “go/no go” determination will be announced on Aug. 31, two weeks before the transition.
Assuming a decision to “go,” PJM will begin posting PPL’s forecasted DLRs at 3 to 4 p.m. on Sept. 12, and begin using the company’s ambient tables for reliability studies and the day-ahead market for Sept. 14. The RTO will then begin posting PPL real-time DLR data at 12 to 1 p.m. on Sept. 14.
Any changes to the plan will be communicated to OC stakeholders via Pardot.
PJM/IMM Proposal on Improving Renewable Dispatch
Members heard a first read of a PJM/Monitor proposal to improve the dispatch of renewable generators to address operational concerns.
PJM said it wants to increase the accuracy of renewables’ dispatch and improve its ability to forecast near-term changes in resource output. “As the number of renewable resources grows, it becomes increasingly difficult to manually manage the dispatch,” PJM said in its problem statement.
The proposal would require intermittent units to have an economic minimum of zero and to have an infinite turn down ratio — the difference between eco max and eco min.
The proposal also would require generators to update critical parameters every five minutes for real-time security-constrained economic dispatch (SCED) cases and hourly updates of parameters for intermediate-termed SCED cases. Current rules require hourly updates but provide limited guidance on specific parameters.
Wind resources are currently eligible for lost opportunity costs (LOC) when they are able to follow SCED dispatch instructions and have supervisory control and data acquisition capability to transmit and receive instructions from PJM. The RTO-IMM proposal would allow solar resources to qualify for LOC under the same rules.
PJM currently has no metrics measuring the impact of renewables’ dispatch. The proposal would establish metrics that the RTO would review monthly with stakeholders. Potential metrics include renewable forecast accuracy; curtailment frequency; real-time performance versus SCED expectations; and the accuracy of bid-in parameters.
The proposal also calls for development of a look-ahead tool to evaluate renewables’ impact.
Intermediate-termed SCED looks ahead about two hours, considering all resource types. The additional tool would be contingent on renewable forecasts reaching acceptable accuracy levels.
Implementation would be no earlier than the second quarter of 2023. The OC will be asked to endorse the proposal at its next meeting.
VALLEY FORGE, Pa. — PJM transmission owners last week, led by Dominion Energy (NYSE:D), presented the Transmission Expansion Advisory Committee with more than $400 million in supplemental projects.
Dominion outlined 13 supplemental projects totaling $366 million; all but two of them are the result of data centers or other “customer service” drivers. PJM has designated Dominion to construct a $603 million “immediate need” project to address short-term reliability issues resulting from data center growth through 2025. (See PJM Sees Additional $603M ‘Data Center Alley’ Tx Spend.)
In addition:
UGI (NYSE:UGI) presented a $33 million project to construct a new 230-kV switchyard (nine breakers in a breaker and half configuration) and two 230-kV supply lines of about 2.5 miles to serve a new large load customer in the Nanticoke area.
PEPCO (NASDAQ:EXC) presented plans for a $420,000 project to upgrade an obsolete relay on the 230-kV Ritchie-Oak Grove line (No. 23058) at the Oak Grove Substation.
PECO Energy said it will add a third 230/13-kV transformer at its Master Distribution Substation to relieve surrounding substations and provide capacity for growth at a cost of $800,000.
$24M in Additional Tx Upgrades Needed for Cheswick Retirement
PJM is recommending $24 million in additional transmission upgrades to address thermal violations resulting from the March 2022 retirement of the 567.5-MW Cheswick generating plant in the Duquesne zone. The Springdale, Pa., plant was the last coal-fired generator in Allegheny County.
In August 2021, PJM said its analysis concluded that new and existing baseline projects would resolve any problems resulting from the retirement.
But the RTO told the TEAC last week that it had discovered “missing N-1-1 thermal violations” during a review of the analysis results using 2023 summer and 2027 summer load flow models developed this year. “The further investigation confirmed that there was [an] issue in the study file used for the N-1-1 thermal analysis performed in 2021,” PJM said.
The RTO is proposing the installation of a series reactor on the 138-kV Cheswick-Springdale line ($9 million) and a transmission line rearrangement that includes the replacement of four structures and reconductoring the Duquesne portion of the 138-kV Plum-Springdale line ($15 million).
The projected in-service date is Dec. 31, 2024. Operating measures have been identified to address reliability problems before then.
The RTO said it also is conducting reliability analyses for the retirement of NRG Energy’s (NYSE:NRG) Joliet Units 6, 7 and 8 (1,381 MW) planned for June 1, 2023, in the ComEd zone, and the Dickerson combustion turbine (18 MW) scheduled to retire in the PEPCO zone on Oct. 23, 2022. The Joliet plants — which were converted to gas from coal six years ago — are closing because of the Illinois Climate and Equitable Jobs Act (CEJA), which requires the state to eliminate carbon emissions from its electricity sector. (See related story, Illinois Climate Bill Could Force $2B in Tx Upgrades, PJM Says.)
Officials said the Vineland CT (21.1 MW) in the ACE zone can retire as scheduled on Oct. 10 after an analysis found no reliability violations.
The U.S. House of Representatives passed the Inflation Reduction Act (H.R. 5376) on Friday, sending the $740 billion package of tax, health and climate provisions to the White House for President Biden’s signature.
House Speaker Nancy Pelosi announces the passage of the Inflation Reduction Act. | CSPAN
Democratic representatives standing before the speaker’s dais broke out in cheers and high-fives as Speaker Nancy Pelosi (D-Calif.) announced the final vote of 220-207, with four Republicans not voting.
Earlier in the day, Pelosi had vowed that once passed, the bill would head straight to Biden’s desk. “It will be ready in a matter of minutes for me to enroll it, and it will go directly to the president for his signature,” she said.
Biden, who watched the vote at the White House, quickly tweeted he would sign the bill in the coming week and also announced a celebration of the soon-to-be law on Sept. 6.
Passing the IRA “required many compromises. Doing important things almost always does,” Biden said.
National Climate Adviser Gina McCarthy was among other administration officials hailing the vote on Twitter, calling the IRA’s $369.75 billion in clean energy funding “our biggest climate investment ever, by far. This will save so many lives and create so many opportunities,” McCarthy said, crediting the bill’s success to “a broad, steadfast movement demanding a clean energy future.”
Senate Majority Leader Chuck Schumer (D-N.Y.), who negotiated the compromise version of the IRA with Sen. Joe Manchin (D-W.Va.), also took to social media, calling the IRA “the boldest climate package in U.S. history. … The Democrats got it done!” he said.
The party-line vote followed more than three hours of heated debate with Democrats and Republicans exchanging familiar arguments — and mid-term election talking points — about the bill’s impacts, mostly in one-minute speeches on the floor. Republicans hammered away on claims that the bill on would increase taxes and inflation, and set IRA agents on working Americans, while Democrats hit back with bill provisions that would cap prescription drug costs for seniors on Medicare and accelerate the country’s shift to clean energy while lowering utility bills.
House Minority Leader Kevin McCarthy argued that under the IRA, “your energy prices will now go through the roof. I look forward to every Democrat who votes for this bill … [explaining it] to their constituents when they’re making a choice about whether they pay [for] the energy to heat their homes, or they cut back on the gas to fill their tank.”
“We have a climate crisis, and the deniers have undermined our ability to respond,” countered Majority Leader Steny Hoyer (D-Md.). “This bill responds and … consistent with the desires of the American people, will bring down the cost of energy for Americans by investing in developing and deploying cleaner, more sustainable energy technologies like electric vehicles and solar panels.”
Rocky Path to Passage
The version of the IRA that passed Friday has traveled a rocky path since September 2021, when Democrats first unveiled it as the $3.5 billion Build Back Better Act, a filibuster-proof budget reconciliation package with a range of social spending and clean energy incentives. Faced with opposition from the Senate’s centrist Democrats, Manchin and Sen. Krysten Sinema (D-Ariz.), Biden in October negotiated a trimmed-down BBB framework set at $1.75 trillion.
The House passed its version of BBB on Nov. 19, with a $2.2 trillion price tag, adding spending on progressive priorities such as four weeks of paid family and medical leave. BBB then went to the Senate, where negotiations hit a wall in December when Manchin walked away from further discussions.
“I have always said if I can’t go home and explain it to the people of West Virginia, I can’t vote for it,” Manchin said on Dec. 19 on “Fox News Sunday.” “And I cannot vote to continue with this piece of legislation. I just can’t. … This is a no.”
At the time, Manchin said the government should focus on inflation and the year-end surge in COVID-19 cases, driven by the fast-spreading Omicron variant. (See Manchin Says ‘No’ on Build Back Better.)
Manchin and Schumer resumed negotiations on the bill earlier this year, but Manchin balked at rising inflation figures in July, and once again appeared to close down talks on the legislation. (See Biden: ‘I Will not Back Down’ on Climate Action.)
The surprise announcement of a deal on the renamed Inflation Reduction Act came on July 27, followed by passage in the evenly split Senate on Aug. 7 — 51 to 50 — with Vice President Kamala Harris casting the tie-breaking vote. (See Senate Passes Inflation Reduction Act.)
Senate Republicans offered dozens of amendments during the Senate debate, two of which passed. A $35 per month cap on insulin prices for consumers with private insurance was stripped from the bill but was retained for Medicare patients. A second amendment revised the bill’s 15% corporate minimum income tax, exempting companies owned by private equity from the provision.
Prior to Friday’s debate, House Democrats also passed a resolution setting out the rules for the debate, which specifically closed off any attempts to further amend the bill. Under the rules for budget reconciliation, any changes in the House would have required the IRA to go back to the Senate for a second vote and possibly more Republican amendments.
‘Fully Unleashed’
For clean energy advocates and industry groups, the IRA’s expansion and extension of renewable energy production and investment tax credits was a big win. The bill extends existing wind and solar tax credits through the end of 2024 and then transitions them to technology neutral clean energy tax credits that continue through 2032. A direct-pay provision also allows nonprofit organizations, including electric cooperatives, to access the tax credits, which they have been unable to do. (See What’s in the Inflation Reduction Act, Part 1.)
“Electric cooperatives are leading the charge to reliably meet America’s future energy needs amid an energy transition that increasingly depends on electricity to power the U.S. economy,” National Rural Electric Cooperative Association CEO Jim Matheson said. “As co-ops continue to innovate, access to tax incentives and funding for investments in new energy technologies are crucial new tools that will help reduce costs and keep electricity affordable for consumers.”
Tom Kuhn, CEO of the Edison Electric Institute, the trade association for investor-owned utilities, said the 10-year time horizon for the credits will provide “much needed certainty to America’s electric companies over the next decade as they work to deploy clean energy and carbon free technologies. … This legislation firmly places the United States at the forefront of global efforts to drive down carbon emissions, especially when paired with the historic [research, development and deployment] funding” in the Infrastructure Investment and Jobs Act, he said.
CEO of Advanced Energy Economy Nat Kreamer called out the bill’s tax credits for solar, storage and other clean energy manufacturers. “Clean energy technologies will be fully unleashed,” Kreamer said. “Clean energy manufacturers and developers alike will now have the right financial tools and the policy certainty they need to produce and buy the components that power these innovative technologies here in America.”
Other provisions of the IRA expand the 45Q tax credit, which had been a particular focus for the carbon capture industry. The bill ups the per ton incentives for carbon and direct air capture, for example, from $50 to $85 per ton for carbon sequestered in geologic saline formations, and also provides a direct pay option.
Madelyn Morrison, external affairs manager for the Carbon Capture Coalition, said the IRA “reinforces the essential role carbon management must play in achieving midcentury climate goals while providing a critical pathway to creating and retaining the high-wage jobs base communities and families depend upon, and positioning our nation’s industrial, energy and manufacturing sectors as leaders in technology innovation.” (See What’s in the Inflation Reduction Act, Part 2.)
A panel of industry analysts Wednesday presented their estimates of how much the Inflation Reduction Act would reduce greenhouse gas emissions and its impact on average household energy costs.
The webinar hosted by Resources for the Future (RFF) came as the House of Representatives prepares to vote on the bill and its $369.75 billion in clean energy funding, which the Senate passed on Sunday. (See Senate Passes Inflation Reduction Act.)
Rhodium Group found that the average household savings from the IRA would run from a low of $27 per year to a high of $112 per year, depending on natural gas prices.
Rhodium Group estimates the IRA will produce modest home energy bill savings for the average American household. | Rhodium Group
RFF’s own analysis of the bill forecasts a 5 to 7% cut in retail electricity prices by 2030, which could translate to per kilowatt-hour savings of about a half to one-and-a-half cents by 2030, again depending on natural gas prices.
“Between low and high natural gas prices, there’s roughly a swing of about over 10% in terms of retail electricity prices,” said Kevin Rennert, RFF’s director of federal climate policy.
But, he said, “having the IRA in place — and the clean electricity that is driven by the policy and incentives — actually reduces the effects of variability within natural gas. … Having more electricity on the grid certainly insulates you against price shocks.”
While they differed on details, all the speakers at the webinar agreed that their respective modeling programs found the IRA will provide energy savings across a range of variables. They also agreed that however sophisticated their software, some aspects of the bill would be hard to quantify.
Jesse Jenkins, head of Princeton University’s Zero carbon Energy systems Research and Optimization (ZERO) Laboratory, pointed to siting constraints for solar, wind and carbon capture projects. Examples include “the ability to scale up the workforce to deploy resources at this scale and the ability to expand networks like transmission and CO2 pipelines and storage to support this level of growth,” he said.
Clean Energy Incentives
In addition to natural gas prices, RFF’s analysis also factored in the potential clean energy incentives contained in the IRA, resulting in different scenarios with base and bonus levels of incentives. For example, the bill’s proposed technology-neutral clean energy investment tax credit (ITC), beginning in 2025, has a base of 6% of projects costs, but can be multiplied by five, to 30%, for meeting certain prevailing wage and apprenticeship requirements. (See What’s in the Inflation Reduction Act, Part 1.)
The technology-neutral incentives are “a big deal because it no longer will require an act of Congress for a new technology to be eligible for these credits,” Rennert said.
Another plus: the bonuses are “stackable” so that a single project can receive multiple bonus incentives, such as a bonus for meeting the prevailing wage and apprenticeship requirement and a second for project location in an “energy community” affected by the closure of a fossil fuel plant.
With such stackable bonuses, a project could earn a 50% ITC, Rennert said, and help slash GHG emissions from the power sector by as much as 75% — or an additional 4 billion tons of greenhouse gas emissions — below 2005 levels.
The ZERO Lab analysis also said the IRA’s clean energy incentives would cut power sector emissions 75% but pegged cumulative GHG emission reductions at 6.3 billion tons by 2030.
“The bill primarily reduces emissions by making clean energy cheaper,” Jenkins said. “It’s about making it cheaper and easier for businesses, for utilities, for households, for everyone across America to adopt cleaner energy sources, to make more efficient choices about upgrades to their businesses or homes and to electrify energy consumption in buildings and transportation.”
The law “could spur record-breaking growth in wind and solar capacity” depending on “how fast we can grow and continue smashing records each year,” he said.
While the U.S. added 15 GW of wind and 10 GW of solar in 2020, the ZERO Lab analysis shows the IRA more than doubling wind to 39 GW by 2030 and increasing solar almost fivefold to 49 GW.
Jenkins also sees the bill’s clean energy incentives having a ripple effect, making it “easier and cheaper for states or cities or companies at any level across the country to increase their climate ambitions. It also reinforces the economic benefits of any future federal regulations,” he said.
Oil and Gas Leasing
Both Rennert and Robbie Orvis, senior director of energy policy design at industry consultants Energy Innovation (EI), looked at the potential increase in GHG emissions that could be caused by the IRA’s oil and gas leasing provisions. The bill requires the Department of the Interior to complete stalled oil and gas leasing auctions in the Gulf of Mexico and off the coast of Alaska.
At Wednesday’s webinar on IRA impacts were (clockwise from top left) moderator Karen Palmer, Resources for the Future; Kevin Rennert, RFF; Robbie Orvis, Energy Innovation; John Larsen, Rhodium Group; and Jesse Jenkins, Princeton ZERO Lab. | Resources for the Future
It also links the permitting of solar and wind projects on federal land to corresponding sales of onshore and offshore oil and gas leases.
RFF estimates the new leases will generate about 20 million metric tons of GHG emissions by 2030, a figure that would be more than offset by the 4 billion-ton cut in emissions from the electric power sector, Rennert said.
Orvis detailed EI’s modeling assumptions ― that 2% of the millions of acres available for oil and gas leasing would actually be sold at auction, and emissions from any wells drilled would be spread out over time. EI’s conservative estimate of emissions from those wells came in at 50 million MT, Orvis said.
“And that means for every one-ton increase in emissions from the oil and gas lease provisions [in the IRA], there’s 24 tons of emissions reductions from all the other provisions in the bill,” he said.
EI’s estimate of GHG emission reductions is 37 to 41% below 2005 levels by 2030, he said. The bill would also create about 1.5 million full-time jobs by in the same time frame, which should increase the national gross domestic product by close to 1%, he said.
The IIJA Connection
John Larsen, who lead’s Rhodium Group’s energy system and climate policy research, acknowledges that IRA contains many provisions that would help households fully electrify their homes or use the bill’s other tax credits for much bigger energy savings than the firms’ more modest estimates.
Rhodium’s analysis represents “what happens on an aggregate basis from all provisions,” he said in an email to RTO Insider. But, in a separate research note, Larsen also says that the IRA reductions are just one part of other factors —”improving energy market conditions and technology deployment driven by current policy” that Rhodium anticipates will drive down home energy costs by $730 to $1,135 per year.
Similar to RFF, Rhodium’s analysis of the IRA includes scenarios based on oil and gas prices and associated emissions. Thus, higher oil and gas prices produce a lower estimate of emission reductions, while lower prices could drive higher emission reductions.
With three scenarios — low, middle and high emissions — Rhodium is projecting the IRA will cut emissions 31 to 42% by 2030 compared to a 24 to 35% base case using existing policies, including the Infrastructure Investment and Jobs Act.
Larsen expects that the IRA will provide added market momentum to IIJA’s funds for the development of emerging technologies like carbon capture and green hydrogen. (See What’s in the Inflation Reduction Act, Part 2.)
“The two bills are going to interact in a really important, powerful way,” he said.
“What the IIJA did was start that first level of deployment — demonstration projects, first commercial-scale [projects] — but there’s nothing after that to keep pulling that technology into the market. … We see the [difference] between a conventional hydrogen price and clean hydrogen getting closed in some instances because of the IRA tax credit provisions.”
Still, because of its “nascent nature,” Larsen does not expect green hydrogen to “contribute meaningfully to total GHG reductions through 2030; [the IRA] gets that technology to scale so it’s ready to go for the next wave,” he said.
