MISO said last week it will begin discussions next month on inverter-based resource performance requirements as the industry inches toward standardization.
Patrick Dalton, a power studies engineer, said during an Interconnection Process Working Group meeting Tuesday that the RTO has an imperative to get ahead of potential IBR performance issues noted in recent NERC disturbance reports. Dalton told stakeholders that by June, MISO hopes to have detailed performance requirements that can be drafted for the tariff.
“We are seeing this as part of how reliability attributes work,” Dalton said, referencing the grid operator’s ongoing discussion on attracting generation with certain system reliability attributes. Staff have defined six attributes as essential: availability, delivering long-duration energy at a high output, rapid start-up times, voltage stability, ramp-up capability and fuel assurance. (See MISO Considers Resource Attributes as Thermal Output Falls.)
“The level of alarm continues to increase here,” he said, noting that one of two disturbances near Odessa, Texas, caused about 1 GW of solar resources to trip offline in ERCOT. “If there is any silver lining of these NERC reports, it’s that these events can be prevented if we were to implement standardized functions.”
MISO has time to avert issues, Dalton said, because most IBRs have yet to come online. He said the time to act is a “luxury” that other regions don’t have.
The RTO said standard IBR requirements are likely to benefit voltage stability, small-signal stability, voltage control and detection of short-circuit faults.
The discussions coincide with and are inspired by FERC’s notice of proposed rulemaking issued last year to implement IBR reliability standards (RM22-12). The grid operator said it will draw on the Institute of Electrical and Electronics Engineers’ recent standard for the resources’ interconnection and performance (IEEE 2800-2022) to form its requirements.
FERC on Tuesday approved Great River Energy’s request for transmission rate incentives for two MISO Multi-Value Projects (MVPs) it is working on: the Iron Range-Benton County-Cassie’s Crossing project and the Big Stone South-Alexandria-Cassie’s Crossing project (ER23-513).
The incentives for the two transmission projects include construction work in progress (CWIP) for the Iron Range project and the recovery of 100% of prudently incurred costs in the event they are abandoned.
GRE is an electric generation and transmission cooperative in Minnesota that provides wholesale electric service to 28 co-ops there and in Wisconsin. The Iron Range and Big Stone projects are both part of the MVPs that MISO approved in its 2021 Transmission Expansion Plan.
Iron Range involves the construction of a new 150 mile, double-circuit, 345-kV line from Minnesota Power’s existing Iron Range Substation to GRE’s existing Benton County Substation, replacing some existing lines and upgrading substations. GRE owns 52.3% of it, with the rest belonging to Minnesota Power, and its total cost is $969.9 million.
The Big Stone project involves the installation of a new 128-mile, single-circuit, 345-kV line between the Big Stone substation in South Dakota and the Alexandria substation in Minnesota, and a second 345-kV line being added between Alexandria and Monticello substations. The total cost of the project is $573.5 million, but GRE is only responsible for $27.5 million, as multiple firms are building the line.
Both lines should relieve potential reliability issues, while the Iron Range line is expected to help connect renewable power to market as well.
FERC said that because the two projects cleared MISO’s planning process, which evaluated whether they would improve reliability, they are entitled to a rebuttable presumption that they meet commission requirements for incentives. Firms also have to prove that the incentives sought are connected to the investments being made, meaning they address demonstrated risks or challenges the transmission developer faces.
The Iron Range project is the largest transmission dollar investment ever made by GRE, and with multiple permits and owners, it created a more complex negotiating, decision-making and implementation process. Both the capital structure of 50% debt and 50% equity for both lines and the CWIP for Iron Range should ensure GRE can make the needed investments without lowering its credit rating.
FERC agreed that the incentives were tailored to meet the project’s risks, with the CWIP helping GRE avoid higher costs on the project itself and other investments.
GRE also won approval for the abandoned plant incentive to deal with regulatory and siting risks that are outside of its control. FERC found the incentive would protect GRE and its member co-ops if the projects are canceled for reasons beyond its control.
Christie’s Concurrence
Commissioner Mark Christie concurred with his colleagues, saying that while the order complies with FERC’s current transmission incentives policy, those should be revisited. The CWIP incentive effectively makes consumers the bank for transmission development, while the abandoned plant incentive makes them the insurer of last resort, he said.
“Just as consumers receive no interest for the money they effectively loan transmission developers through CWIP, they receive no premiums for the insurance they provide through the abandoned plant incentive if the project is never built,” Christie said.
FERC has a pending proposal to limit the adder for RTO membership to just three years after utilities join, and another one to eliminate the CWIP incentive altogether. Christie also wants the procedures and criteria for the abandoned plant incentive to be reconsidered.
“Revisiting all these incentives is imperative at a time of rapidly rising customer power bills,” Christie said.
New York Gov. Kathy Hochul on Wednesday released a legislative framework for the cap-and-invest program she is proposing to help the state meet its greenhouse gas-reduction goals.
Money gained from auctions of emission allowances would go into a climate action fund, at least 30% of which would be set aside for consumers and up to 3% for industrial small businesses that face increased costs from the program.
The remainder of the fund, minus operating expenses, would be used by the New York State Energy Research and Development Authority (NYSERDA) to help pay for the clean energy transition codified in the state’s Climate Leadership and Community Protection Act (CLCPA).
Hochul indicated that the Department of Environmental Conservation (DEC) would write the program regulations in consultation with NYSERDA. But she needs the State Legislature to amend state Environmental Conservation Law, Public Authorities Law and Finance Law to enable certain aspects of it.
The governor included the measure in the $227 billion executive budget proposal for fiscal year 2024 that she released Wednesday because creating the program would require spending $6.5 million and 10 full-time-equivalent employees.
DEC would prioritize affordability as it designs the program and design it to be able to link with similar programs in other states.
The program would ease clean-energy transition costs for consumers and make New York a better, more livable state.
It would prioritize disadvantaged communities and be designed to ensure proceeds of the allowances are invested in such communities and to avoid disproportionate burdens on them.
At least six regional public hearings would be held on the draft criteria for the program and on the draft list of disadvantaged communities.
Energy-intensive and trade-exposed facilities — those that use a lot of energy and are at competitive risk if that energy costs more in New York than in other states — would receive a no-cost allocation of allowances; DEC would determine what facilities qualify and how to allocate those allowances.
The Scoping Plan flagged the risk of “leakage”: an industrial operation that faces high costs in New York shifting production to states with looser rules. Leakage is doubly bad, the plan’s authors wrote, because not only is that operation still contributing to global warming, it is also economically harming New York by moving payroll and tax payments out of state.
The program would set a cap on greenhouse gas emissions, establish allowances for a percentage of those emissions, and shrink the percentage each year as the state moves to reduce emissions 40% from 1990 levels by 2030 and 85% by 2050.
An agreement signed by California’s three electricity planning entities will help coordinate resource and transmission planning in California to better reach the state’s clean energy goals while maintaining grid reliability, CAISO CEO Elliot Mainzer told the ISO’s Board of Governors on Thursday.
The memorandum of understanding signed by the California Energy Commission, the state Public Utilities Commission’s and CAISO is a “new blueprint for our state” thatprovides for closer links between the planning processes of each party, Mainzer told the board in his monthly CEO briefing.
In California’s divided energy planning process, the CEC forecasts demand while the CPUC handles resource planning and CAISO deals with transmission needs.
“All of those are [gears] that need to be synchronized so that we can effectively onboard resources in California,” Mainzer said.
Outmoded planning was partly to blame for the state’s rolling blackouts in August 2020, CAISO, the CEC and CPUC said in an October 2020 report to the governor. (See CAISO Says Constrained Tx Contributed to Blackouts.)
The recent MOU was signed in December and posted by CAISO to its website Jan. 19. It supersedes a 2010 agreement that included only CAISO and the CPUC.
The MOU draws closer links between the CPUC’s Integrated Resource Planning (IRP) process, the ISO’s transmission planning process, including its conceptual 20-year outlook, the CEC’s Integrated Energy Policy Report (IEPR), which identifies the state’s energy needs and its activities under Senate Bill 100, which requires all retail customers to be served with 100% clean energy by 2045.
The MOU’s provisions include a requirement that the CEC, CPUC and CAISO “implement a joint work plan” on the CEC’s IEPR and SB 100 proceedings to align the three parties’ planning processes and maintain a flow of information between them. For example, under the new MOU the CPUC must incorporate the CEC’s longer-term forecasts into its IRP process, and CAISO has to supply the results of its transmission planning and interconnection studies to the CPUC for resource planning.
CAISO intends to “put that MOU into practice [this year] and … to transition from what I’ve characterized as sort of reactive transmission planning to much more leading and proactive transmission planning,” Mainzer said.
The ISO expects to release its annually updated transmission plan in May and to “identify the forward-looking zones where we think the next big resource batholiths will be opened up,” he said. “Our hope and expectation is that we’re going to be using [our] transmission planning … to do a much more effective job of shaping queuing and procurement … because we simply can’t be in the place of having to react and then we need 5,7, 10 years to get developed.”
“Transmission is a leading indicator of planning rather than a lagging indicator,” Mainzer told the board. “I’m hoping to be here by the end of this next year with a significant improvement in establishing those orders of operations.”
As an example of the need to improve the process, Mainzer cited CAISO’s efforts to deal with its “Cluster 14” queue of interconnection requests, which he detailed in his memo to the board.
“In April 2021, the ISO received 373 interconnection request applications totaling more than 50 gigawatts (GW) of renewable generation and more than 100 GW of energy storage in the Cluster 14 application window,” Mainzer said in the memo. “This was more than three times the average of 113 applications over the last decade, and more than double the previous high of 155. Because of the challenge for the transmission owners and the ISO to process that many applications, the ISO extended the phase 1 study process by a full year.”
At least 160 of the applications are moving to phase 2, and “that number may yet grow to more than 200 projects representing more than 67 GW, since a number of interconnection customers are still in the final validation process.”
The next group of interconnection requests, Cluster 15, could generate 300 new applications by April, putting additional strains on transmission planners, Mainzer wrote.
“The excessive number of applications also provides even more impetus to move forward with overhauling our interconnection process in keeping with the objectives of the recently signed MOU with the CPUC and the CEC to focus on prioritization through alignment of state resource planning, ISO transmission planning, procurement processes, and the interconnection process,” he said.
A political war is looming over the interpretation and implementation of both the Infrastructure Investment and Jobs Act and the Inflation Reduction Act, with Sen. Joe Manchin (D-W.Va.), a key architect of both laws, attacking the White House on its efforts to circumvent what he sees as their clearly stated congressional intent.
Sen. Joe Manchin (D-W.Va.) | Senate Energy and Natural Resources Committee
“The United States has an all-of-the-above energy policy that supports using all of our God-given resources in the cleanest way possible,” Manchin said Thursday in his opening remarks at a Senate Energy and Natural Resources Committee hearing on the Department of Energy’s implementation of the IIJA. “That’s how we shore up energy security, achieve energy independence, while also addressing climate change.
“It is my intention to make sure that these laws are implemented swiftly, effectively and in line with that clear congressional intent, which I can assure you, this administration doesn’t seem to want to do, but we’re going to make sure they do it,” said Manchin, who chairs the committee.
Manchin’s opening salvos came as Deputy Energy Secretary David Turk faced the committee’s first meeting of the 118th Congress to report on DOE’s progress in rolling out the new programs funded by the IIJA. Keeping largely on message throughout the hearing, Turk stressed DOE’s commitment to getting the money out “urgently, but right.”
Sen. John Barrasso (R-Wyo.) | Senate Energy and Natural Resources Committee
Sen. John Barrasso (R-Wyo.), ranking member on the committee, was doubtful from the outset, noting that between the IIJA and IRA, DOE had received a “staggering” amount of money — close to $100 billion — on top of its $40 billion annual appropriation.
“The question is not whether the department is going to waste taxpayer dollars, but how to reduce the amount that it will waste,” Barrasso said. He cited a letter from DOE Inspector General Teri Donaldson, noting that her office had received insufficient funds from the two laws relative to the amount of money to be monitored.
Barrasso raised questions about DOE’s announcement in November of a $200 million grant to Microvast, an American company that produces battery components and has 80% of its operations in China. In a January 2022 filing to the Securities and Exchange Commission, Microvast acknowledged that doing business in China does present substantial risks because of its government’s control of the business environment and foreign investment.
But the company is partnering with General Motors on a battery component factory to be located in the U.S., and the two companies are matching the DOE grant with a $300,000 investment.
Turk maintained that while the company had been “selected” for the grant, it has yet to receive any money. DOE is now in award negotiations with Microvast and GM, which will involve extensive due diligence, he said.
In a letter to Barrasso, Kathleen Hogan, DOE deputy undersecretary for infrastructure, stressed that such “thorough post-selection, risk-based due-diligence” was standard practice at the department. She also said that while Microvast’s technology was developed in China, the DOE grant would be used for a first-ever U.S. manufacturing facility, “obviating the typical risk of intellectual property.”
‘Asleep at the Switch’
The current tension between Manchin and the White House is rooted in their very different views of the fundamental goals of the IIJA and IRA. Biden hailed the IRA as an unprecedented investment in climate action. For Manchin, it’s about ensuring the energy security of the U.S. and the country’s ability to maintain its leadership as a global superpower to help its allies in the face of Russia’s invasion of Ukraine and its weaponization of energy.
“That’s why we said, let’s do a piece of legislation that uses the resources that we have … to be energy independent, using the fossil, horsepower we have, investing $369 billion to create the new technology — less carbon, if you will — but also not replacing what we need now until we have the other that can do the job. That’s all we tried to do. And I don’t know why we’re in denial,” he said Thursday.
Manchin sees such denial in the Internal Revenue Service’s late December release of guidelines for the IRA’s electric vehicle tax credits, in which the agency announced it was delaying guidelines on the law’s domestic content requirements until March.
As originally written, to qualify for the full $7,500 tax credit, an EV’s battery must contain a certain percentage of critical minerals sourced in North America or from a country with which the U.S. has a free trade agreement, and a certain percentage of other battery components must be sourced in North America. If one of the domestic content requirements is not met, a consumer may only get half the credit. While delaying the guidelines on domestic content, the IRS is allowing EV buyers to claim the full $7,500 credit.
Manchin has introduced a bill that would require the IRS to implement the domestic content requirements immediately and make them retroactive to Jan. 1, but he has been unsuccessful in bringing it to the Senate floor for a vote. (See IRA’s EV Tax Credits Spark Senate Debate.)
He also criticized recent guidelines from the White House Council on Environmental Quality directing federal agencies to factor in greenhouse gas emissions when evaluating projects, arguing that they will favor renewable projects over fossil fuels.
Both issues are not under DOE jurisdiction, though Turk said the department was consulting with the IRS on the EV rules.
Responding to Manchin and Barrasso, Turk acknowledged that the U.S. “has fallen asleep at the switch” on building out clean technology supply chains for batteries, as well as solar panels. “China really has a stranglehold now on mineral processing and all these intermediate steps, so we’re in a hole right now,” he said.
But he defended DOE’s grant-making process, which requires applicants to be U.S.-owned and operated, with U.S. headquarters. “The vast majority of our [IIJA] grants are competitive, and these are administered by civil servants. They’re done that way for a reason: to ensure integrity in the process; to ensure fairness in the process,” he said.
Input from industry experts and intelligence officials are also part of the review process, Turk said.
Turk also promoted DOE’s progress on IIJA implementation, reporting that of the $62 billion DOE received in the bill, $37 billion has been made available to communities across the country. Turk’s list of specific funding opportunities included $7 billion for regional hydrogen hubs, $750 million for electrolyzer manufacturing, more than $5 billion for “game-changing carbon management programs” and $3.9 billion for grid modernization.
The law’s $2.8 billion for battery materials processing and component manufacturing has been paralleled with more than $92 billion in public and private investment in battery manufacturing across the country, he said.
On the IIJA’s hydrogen hubs, Turk reported that DOE’s solicitation, released in September, drew close to 80 concept papers, 33 of which the agency identified as promising and asked for full applications, setting an April 7 deadline for submissions. Turk expects awards to be announced by the fourth quarter of the year, but he said that Energy Secretary Jennifer Granholm might “try to move that timeline up.”
Gas Stoves
While not directly related to either the IIJA and IRA, the political war over gas stoves was also on the agenda, with both Manchin and Barrasso railing against any attempt to ban the stoves in existing or new construction.
The Consumer Product Safety Commission triggered the controversy in January when Commissioner Richard Trumka raised the possibility of a ban because of the health hazards they present. The remark set off a firestorm of opposition and statements from both the CPSC and the White House that no such ban was being considered.
Manchin attacked both the CPSC and DOE, which on Wednesday issued proposed efficiency standards for cooktops, both electric and gas, framing the action as yet another attempt by the Biden administration to “find ways to push out natural gas.”
He said he and Sen. Ted Cruz (R-Texas) would be introducing a bill to prohibit the banning of gas stoves. “The federal government doesn’t have any business telling American families how to cook their dinner,” he said.
DOE’s proposed standards would limit the amount of electricity or gas a stove top can use per year. For electric stoves, those with open-coil cooking elements would be limited to 199 kWh/year and those with smooth element tops to 207 kWh/year. Gas stoves would be limited to 1,204 kBtu/year. DOE will be accepting comments on the proposal through April 3.
Sen. Josh Hawley (R-Mo.) | Senate Energy and Natural Resources Committee
Echoing Manchin, Barrasso asked Turk to pledge that no money from the IIJA would be used “to ban or restrict the use of natural gas in new buildings.”
Thursday’s hearing also marked the debut of Sen. Josh Hawley (R-Mo.) as the newest Republican member of the committee. A controversial figure — he was the first senator to declare he would object to certifying Biden’s election in 2020 — Hawley spent his time browbeating Turk over the closure of an elementary school in his district, where radioactive waste was found in a nearby creek and later in the school itself.
Manchin intervened to explain that DOE has no jurisdiction to take action in the matter, and negotiations are ongoing with the U.S. Army Corps of Engineers, the agency that does.
The cost of New York zero emissions credits is set to fall 14% for the next two years after the state agency that administratively sets ZEC prices issued its biennial price adjustment on Tuesday.
The New York Department of Public Service laid out the change in a letter to the state’s Public Service Commission. The letter explains that ZEC prices for Tranche 4 (April 1, 2023 – March 31, 2025), will be set at $18.27/MWh, down from $21.38/MWh for Tranche 3 (April 2021 to March 2023) (Case-15-E-0302).
Tranche 2 (April 2019 to March 2021) ZECs were priced at $19.59/MWh.
ZECs are subsidies for nuclear facilities that load serving entities purchase monthly from the New York State Energy Research and Development Authority to prevent those facilities from retiring. They play an integral role in the PSC’s Clean Energy Standard because they keep economically distressed nuclear plants, such as Nine Mile Point, James A. FitzPatrick and R. E. Ginna, online and use the collected funds to help build more renewable generation, which will replace the load generated by these nuclear plants.
Adjusted every two years, the ZEC is calculated by subtracting an adjustable reference price (currently $37.78) from the Zone A forecast energy price and rest-of-state forecast capacity price (currently $43.34/MWh). The difference between those is then subtracted from the social cost of carbon, which is currently set at $23.83/MWh.
The PSC has capped the number of ZECs that can be purchased, and that cap will be reduced should any facility close. Should any facility fall below the mandated production level of 85% of historical production for any two-year period, the PSC will further reduce the ZEC cap.
The program is intended to keep nuclear plants open until March 31, 2029, at which point New York expects to have installed enough additional renewable capacity to compensate for anticipated nuclear retirements.
Incidents of deliberate physical damage to bulk power system facilities rose by 77% last year, driving home the danger posed by malicious actors, the Department of Energy reported this week.
DOE’s annual summary of electric emergency incidents and disturbances — based on reports submitted by utilities to the Office of Cybersecurity, Energy Security, and Emergency Response (CESER) — includes the type of event, demand loss in megawatts, number of customers affected, and region.
Out of the 390 incidents recorded in last year’s spreadsheet — up from 387 in 2021 — 163 involved deliberate physical damage to BPS equipment, a significant fraction of overall incidents and a major rise from the 92 recorded in 2021. The report also cites cybersecurity events (9), severe weather (95), fuel supply deficiency (5), generation inadequacy (4), system operations issues (87), and transmission interruption (27).
Among the incidents of physical damage, 90 were listed as involving “vandalism,” 57 as “suspicious activity,” 15 as “actual physical attack” and one as sabotage.
DOE did not provide details about how it defines these event types; the alert criteria listed in the report seem to be only loosely connected to the categories, with the same alert type provided for multiple types of events.
For example, “damage or destruction of [a] facility that results from actual or suspected intentional human action” is listed under both “suspicious activity” and “actual physical attack.” Additionally, there is some overlap between categories, with 10 incidents categorized as both “actual physical attack” and “vandalism.”
Most of the reported events resulted in no demand loss and affected no customers. The event with the biggest impact was December’s attacks on two Duke Energy (NYSE:DUK) substations in Moore County, North Carolina, when more than 45,000 customers lost power. The utility needed nearly a week to restore service to all those affected. (See Duke Completes Power Restoration After NC Substation Attack.) Investigators have yet to publicly identify any suspects or motives for the Moore County attacks.
The next-largest incident in terms of the number of people affected was the Christmas Day attacks in Washington state, when two men allegedly vandalized four electric substations in Pierce County, causing more than 21,000 customers to lose power. One of the men told police they committed the vandalism as part of a plan to burglarize a local business. (See Feds Charge Two in Wash. Substation Sabotage.)
By far the greatest number of physical security incidents — including the Washington attacks — occurred in WECC’s territory. The 73 WECC incidents affected more than 44,000 customers. SERC experienced 26 incidents, along with one event that it shared with ReliabilityFirst and three that affected it and the Texas Reliability Entity. These incidents, including those with RF and Texas RE, impacted more than 49,000 customers.
Events in the territory of the other REs affected a relative handful of people. Of the Midwest Reliability Organization’s six physical security incidents, one in Oklahoma affected 4,836 customers in July. The Northwest Power Coordination Council experienced 15 events, but only one — an event on Jan. 1 recorded as “suspicious activity” — affected 845 customers. RF reported several events in which the number of customers affected was unknown. Texas RE had no customers affected by its 17 incidents, although 1,521 were affected in a vandalism incident it shared with SERC.
FERC on Wednesday settled a dispute between NextEra Energy (NYSE:NEE) and Avangrid (NYSE:AGR) over whether the former should be responsible for upgrading a circuit breaker at the Seabrook nuclear plant in New Hampshire (EL21-3, EL21-6).
The two have been going back and forth on the project, which ISO-NE says is necessary to help support Avangrid’s New England Clean Energy Connect transmission line, since 2020.
NextEra, which owns and operates Seabrook, initially asked FERC to find that the plant should not have to take a financial loss in order to upgrade the breaker. Avangrid then filed a complaint arguing that Seabrook has been “unlawfully attempting to delay and unreasonably increase the costs of the breaker replacement.”
FERC essentially found that Avangrid’s reasoning for why Seabrook should replace the breaker was faulty, but that the nuclear plant can’t refuse to replace it because the breaker is a component of the generating facility and upgrading it is required by “Good Utility Practice.”
The nuclear plant’s interconnection agreement “does not permit Seabrook to refuse to replace the breaker when replacement is needed for reliable operation of the Seabrook Station and given the concerns in the record related to the impact of any unreliable Station operation on the reliable operation of the system,” FERC wrote.
And the principles of Good Utility Practice require Seabrook to replace the breaker before NECEC interconnects because the breaker will be “overdutied” once it does, the commission said.
An ISO-NE system impact study found that the breaker is operating at 99.6% of its capability now, but it would be at 101.2% once NECEC is in service.
While FERC has been considering the complaint, the two parties have been hashing out an agreement: The filing says that the breaker replacement is now scheduled for a fall 2024 refueling outage, with the commercial operation date for NECEC being December 2024.
According to FERC, both agree that Avangrid should pay for the direct costs of the breaker placement, but they disagree over whether the company should pay opportunity and legal costs.
FERC sided with Avangrid, saying that Seabrook can’t recover those additional costs.
“The commission typically allows opportunity cost recovery so that the resource will be revenue-neutral and therefore indifferent towards the system operator’s decision as to which service the resource will provide,” FERC wrote. “That is not the case here.”
The Virginia House Commerce and Energy Committee voted to tighten regulation of electric utility rates as disparate interests lined up behind two bills.
Representatives of Gov. Glenn Youngkin (R), Attorney General Jason Miyares (R), Dominion Energy (NYSE:D), consumer groups, and environmentalists supported a pair of bills that the committee voted out unanimously. Democrats on the committee, environmentalists and clean energy advocates, however, opposed a third bill that they argued would stymie the goals of Virginia’s Clean Economy Act.
HB 1604, sponsored by Del. R. Lee Ware (R) would give the State Corporation Commission authority to reduce an investor-owned utility’s rates if it determines they would produce unreasonable revenue in excess of the utility’s authorized rate of return. Current law requires the SCC to set utility rates based on a group of investor-owned peers in the Southeast.
HB 1670, sponsored by Del. Daniel W. Marshall III (R), moves rate reviews for Dominion and Appalachian Power (NASDAQ:AEP) from every three years to every two years.
“This bill is part of three distinct pieces of energy legislation you’ll see today,” acting secretary of Natural and Historic Resources Travis Voyles said on behalf of the governor’s office. “These legislative efforts are central to the governor’s energy plan and the commonwealth’s ability to grow — grow population, grow jobs, grow businesses — by supporting a framework that makes certain the delivery of abundant, reliable, affordable, and increasingly clean energy.”
Democratic Del. Rip Sullivan also endorsed the two bills.
“This is one of those bills that a lot of people had a lot of opinions on; a lot of people got around literal and figurative and digital tables to talk it through,” said Sullivan. “The coalition of groups and entities that are supporting this bill, I don’t know if it’s unprecedented, but it is certainly, in my view, impressive.”
Rarely are Dominion Energy, Appalachian Voices, Virginia Poverty Law Center, Southern Environmental Law Center, Americans for Prosperity, and the governor’s office all supporting the same legislation, he added.
A third bill, HB 1770, requiring that the SCC approve the retirements of IOU electric generating plants, cleared the Republican-controlled committee on a 12-10 party-line vote. The requirement would not apply to any retirements identified in integrated resource plans filed with the SCC by July 1, 2023.
Sullivan and other members of the coalition backing the other two bills opposed the third, even though they all indicated it was better than it had been.
“The bill, in my view, is better than it was when it was first filed, better than it was two weeks ago, and better than it was yesterday,” said Sullivan.
While the legislation is on the right track and could be different by the end of the session when the House and Senate have to come together to pass any final legislation, Sullivan said he could not support HB 1770 as it stands now because it contains language that could be detrimental to the Clean Economy Act that he helped pass back in 2020, which sets Virginia on a path to decarbonization by mid-century.
The bill’s sponsor, Del. Terry Kilgore (R), said he was just trying to maintain reliability by requiring SCC approve generation retirements.
“This legislation brings important oversight to the SCC,” said Voyles, again speaking for Youngkin’s office. “This will directly improve the integrity of our grid and the reliability of power.”
Demand is growing in Virginia, and the legislation will ensure that no generation retires too quickly, preventing any gaps from occurring, he added.
Sullivan said that the Clean Economy Act already gives the SCC the authority to delay retirements as needed to maintain reliability.
The Clean Economy Act had clear language that laid out a plan to get to a clean energy future by mid-century, said Sierra Club Virginia Chapter Political and Legislative Director Connor Kish.
“Our concern with this language is it sort of cuts out the ability to have a set retirement date for these facilities that would help grow the industry as it continues to move towards a clean energy future,” he said.
Companion legislation for the three House bills voted out by the committee cleared the Senate Commerce and Labor Committee last week, but they have yet to receive a floor vote. (See Dominion-backed Bill Promises Savings, but Comes with Strings.)
FERC has decided to let stand SERC Reliability’s $75,000 penalty against Duke Energy Florida (NYSE:DUK) for violating NERC reliability standards (NP23-7), along with the regional entity’s settlement with the Tennessee Valley Authority for another set of violations, carrying no financial penalty (NP23-8).
The commission announced last week that it would not review the settlements, which NERC submitted Dec. 29; the ERO submitted its monthly spreadsheet Notice of Penalty on that day as well, detailing SERC’s settlements with Virginia Electric and Power Co. for its facility ratings issues. (See related story, SERC Hits Virginia Electric with $320K in Penalties.)
Also approved last week were several settlements for infringements of NERC’s Critical Infrastructure Protection (CIP) standards (NP23-4, et al.). For these settlements, identifying information — including the utilities and REs involved, and when and where they occurred — was omitted, in accordance with NERC and FERC’s policy on CIP violations.
Duke Neglects to Coordinate Protection Settings
Duke’s penalty stems from a violation of PRC-001-1 (System protection coordination) that SERC discovered during a compliance audit in 2019. While the standard was not in place at the time of the audit, the RE determined that the violation began in 2012 when it was in effect.
Requirement R3 of the standard states that transmission operators (TOPs) must coordinate new protective systems and changes to protective systems with neighboring TOPs and balancing authorities, but SERC claimed that Duke failed to do so in 2012 and 2013 when it was conducting maintenance on its transmission lines.
The utility decided to change protective settings on its 115-kV line between Atwater and Quincy, increasing the timing on the zone 2 and 3 time distance relays to 45 cycles. However, it did not communicate the changes to the neighboring TOP, whose zone 3 relays remained set at 42 cycles. The mismatch remained in place until 2017, when the uncoordinated relays caused the neighboring utility’s breaker to trip, leading to a 63-MW loss of load on its system.
SERC found that this incident also constituted a violation of Requirement R5 of the same standard, which states that TOPs must inform neighboring TOPs of changes in their transmission systems that could require changes to the neighbor’s system. The RE said that Duke’s “failure to notify its neighboring TOP prevented the neighboring TOP from receiving sufficient information to review its systems and led to the transmission systems being mis-coordinated.”
Duke and its neighbor agreed to coordinate the timing cycles after this incident, and the changes were completed by May 2021. Additional mitigation actions by Duke include implementing setting changes to improve relay coordination and updating process documents to mandate coordination with neighboring transmission and generation owners.
TVA Reports Voltage, Maintenance Issues
The TVA settlements involve infringements of VAR-002-4.1 (Generator operation for maintaining network voltage schedules) and PRC-005-2 (Protection system maintenance). TVA self-reported both issues, which according to SERC comprised “multiple instances of smaller risk issues which, when aggravated, increase the overall risk of both to moderate.”
According to SERC’s filing, the utility initially reported its problems with VAR-002-4.1 on July 2, 2019, describing three incidents in which, as a generator operator, it failed to maintain the generator voltage schedule provided by its TOP as mandated by Requirement R2 of the standard. All three incidents occurred in April 2019 at TVA’s Watts Bar Nuclear Plant, located in Rhea County, Tenn. TVA later amended the self-report to include incidents at other nuclear and non-nuclear facilities it operated between 2018 and 2022, for a total of 287 excursions.
Mitigating actions undertaken by TVA include clarifying voltage schedule excursion requirements for responsible staff and updating equipment at affected facilities. The utility reported its completion of the mitigation plan on Feb. 2, 2022.
TVA’s violation of PRC-005-6 involved Requirement R3, which provides the schedule by which transmission owners, generation owners and distribution providers must maintain their protection systems and other components. The utility reported to SERC in May 2021 that it had discovered multiple instances of noncompliance; it had first detected the issues a year prior, but SERC determined that the violations extended as far back as 2015 and concerned PRC-005-2, the version of the standard that was in place at the time.
Places where problems were found include both transmission and generation facilities, some of which were also uncovered in the VAR-002-4.1 violation, such as the Cumberland Fossil Plant and Sequoyah Nuclear Plant. SERC and TVA identified various causes, including lack of internal controls and ineffective or inadequate internal controls. The utility’s mitigation steps included revising procedures within its PRC-005 program and creating training modules, along with testing and updates of equipment at affected facilities; the work is expected to be completed by August.
Because TVA is a federal government entity, SERC could not issue any monetary sanctions.
