MISO members have reopened the suggestion that the grid operator enact resilience criteria within its footprint, saying it has a role to play in preparing to withstand and recover from high-impact, low-probability events that wreak havoc on the system.
During an Advisory Committee teleconference Wednesday, several members said MISO could address resilience through projects that harden and build redundancy into the system, resource diversity and operational protocols. They said the RTO’s long-range transmission planning will reinforce the system, but it could do more in bolstering interregional links, which have proven invaluable during extreme weather events.
ITC Holding’s Brian Drumm said staff could establish minimum intraregional and interregional transfer levels.
“How do we know we’re resilient now if we don’t have metrics?” the Lignite Energy Council’s Jonathan Fortner asked, advocating for defined measures of adequate transmission capability and available generation.
The Union of Concerned Scientists’ Sam Gomberg said MISO “should be on the forefront” of partnering with national laboratories and agencies to understand evolving risks of climate change. He said the grid operator’s “blind spot” is that it doesn’t proactively analyze and plan for future risks “that the science is telling us are going to become numerous.”
Gomberg said MISO might define when heat waves and winter storms cross an “extreme” threshold. He said “smart, low-cost solutions or behaviors” could lower risks and that MISO, states and load-serving entities have a “huge opportunity” to save lives and lessen disruptive events’ economic devastation.
WEC Energy Group’s Chris Plante said the conversation was reminiscent of one the Advisory Committee held four years ago. He said continued attention on the topic without sets of criteria means that it is difficult to pin down resilience objectives.
MISO and SPP prepared stakeholders last week for the possibility they may come up empty-handed in their joint hunt for interregional transmission upgrades.
SPP’s Neil Robertson said that the grid operators are still “hopeful” they can identify at least one beneficial targeted market efficiency project (TMEP) in their study. But he also said there’s a “strong possibility” that they won’t find any recommended upgrades.
“I think the likely outcome is we’re not going to have any … candidates come out of this first study, but I don’t want to close the door on this just yet,” Robertson told stakeholders Friday during a MISO-SPP Interregional Planning Stakeholder Advisory Committee (IPSAC).
“The cost of the solutions may far exceed the budget,” Robertson said, adding, “We’re still refining the congestion dollar values.”
They have proposed that TMEPs cost $20 million or less, must not be greenfield projects, be in service by the third summer peak from their approval, and completely cover their installed capital cost within four years of service through avoided congestion.
The grid operators borrowed many of their standards from MISO’s and PJM’s TMEP criteria.
Stakeholders remained adamant that the grid operators are using a cost cap that’s too restrictive to result in any valuable projects.
American Clean Power Association’s Daniel Hall asked whether the absence of qualifying TMEP projects means that the RTOs might consider “tweaking” the criteria to increase the cost threshold or payback period.
Robertson said staffs plan to hold lessons-learned discussions following the study’s conclusion but probably wouldn’t change criteria “purely in the interest of getting Project A or Project B across the finish line.”
“There is merit in shifting [these] criteria or [those] criteria, but we have to balance all of the considerations,” he said. Staffs are looking for upgrade candidates that “truly give us the return on investment we’re looking for” and are not entertaining a change to the $20 million cost cap at this time, Robertson said.
Several stakeholders said inflation has dated the proposed TMEP cost threshold.
Clean Grid Alliance’s Natalie McIntire argued that “the value of dollars changing” means that the cost maximum is “ripe for reconsideration.”
“You should consider keeping up with inflation,” she told the RTOs’ planners.
American Electric Power’s Brian Johnson agreed and said MISO should “right-size the figure to match market conditions.” He said with the current criteria, a TMEP would have to be “almost across the street” for MISO and SPP to recommend it.
The grid operators said they will announce any project candidates during a Dec. 12 IPSAC meeting.
Robertson also said the RTOs are working out a way for one RTO’s transmission owners to fund an upgrade on the other RTO’s system when it stands to benefit them. Robertson said situations where a TO will overwhelmingly benefit from a project on the other side of the seams are becoming increasingly commonplace.
He said the grid operators could “pass the funding across the fence” should there be cross-border construction under MISO and SPP’s interregional planning process.
NEPOOL stakeholders will consider whether to increase the age limit for members of ISO-NE’s Board of Directors this week, as the grid operator looks to expand the pool of candidates for the job.
The proposal, put forward by NextEra Energy’s Michelle Gardner, will get a vote at the Participants Committee this week.
A provision of the current ISO-NE and NEPOOL rules, in place since the Participants Agreement was adopted in 2004, prohibits anyone over the age of 70 from being elected or re-elected to the board.
Gardner plans to argue that best practices have changed since 2004, according to her presentation. Her proposal would raise the age limit to 75.
Two other RTOs have age limits of 75, and the rest have no limits at all, she says.
“In recent years, the age limit has contributed to difficulty in finding high-quality director candidates to serve on the ISO board,” according to Gardner’s presentation. It’s “challenging for actively employed executives to serve” on the board because of the time commitment it requires. And as many executives are now working full-time jobs into their 60s, “the present age limit shortens their service window.”
ISO-NE’s Code of Conduct also limits the ability of stakeholders to consider candidates who have been recently affiliated with market participants or are invested in companies that interact with ISO-NE. FERC’s interlock rule also comes into play.
ISO-NE spokesperson Matt Kakley said the grid operator supports the change.
“Making this change would bring ISO New England in line with our ISO and RTO peers and corporate best practices,” Kakley wrote in an email to RTO Insider. “Increasing the age limit will allow for a broader pool of candidates while maintaining existing parameters laid out in our Code of Conduct and FERC’s interlock rules.”
The board will meet on Tuesday, the day before the Participants Committee, for its first public meeting as part of a commitment by ISO-NE to the New England states to be more accessible and transparent.
Hawaiian Electric (HECO) said last week that it is accepting applications for Charge Up Commercial, a three-year pilot program aimed at reducing the upfront costs for the installation of electric vehicle charging station infrastructure.
The $5 million “make-ready” pilot program will provide up to 30 applicants as much as $90,000 each to install the infrastructure necessary for Level 2 EV charging stations. HECO will install and maintain all infrastructure up to the charging station location, while applicants are responsible for buying, installing and maintaining the charging station itself. Applicants must also install a minimum of four and maximum of six charging ports.
The pilot program is available for non-residential locations such as stores, office buildings and fleet facilities, as well as apartments and condominiums, on all the islands except for Kauai.
The charging stations will dovetail with HECO’s commercial EV charging rates, which apply a time-of-use rate to reduce energy costs during the midday hours when there is an abundance of solar energy on the grid.
Charge Up Commercial is also compatible with HECO’s EV Charging Station Rebate program, which offsets some of the cost of installing an EV charging station for commercial and multi-unit dwellings.
In the Charge Up Commercial handbook, HECO CEO Shelee Kimura said part of the pilot program’s value is to provide charging ability to EV owners who live in apartment buildings or condominiums, where it is generally more difficult to charge EVs in than a house. Kimura noted that apartments and condominiums “make up a full 37% of Hawaii’s housing stock.”
HECO will accept additional applications on a rolling basis if there are leftover funds after the first 30 applicants.
Duane Highley, Tri-State Generation and Transmission Association | U.S. Energy Association
Solving workforce issues, making transformers easier to replace and improving forest management are among the issues dominating the attention of the Electricity Subsector Coordinating Council, Co-chair Duane Highley said Friday.
The ESSC has been discussing how the industry can deploy federal funding from the Inflation Reduction Act and the Infrastructure Investment and Jobs Act “that would basically triple the rate of expansion of our energy transition,” Highley said during a United States Energy Association virtual press briefing on transmission.
“The No. 1 factor that’s limiting us right now is labor availability. There’s just not enough people,” said Highley, CEO of Colorado-based Tri-State Generation and Transmission Association. “And so despite the will — we might have all the money in the world — if we don’t have the people, we’re not going to get it done. And this is a global problem. It’s not even just limited to us.”
Highley said the ESSC’s wildfire working group is completing efforts with the U.S. Forest Service and Bureau of Land Management to create master special-use permits that will simplify the removal of vegetation under transmission lines.
“We’ve had, in the past, to get separate permits for every single forest district, every single company,” he said. “And what we’re on the verge of completing now … is a master special-use permit that’s going to allow [access] to be negotiated once. And then we can get in and do the work we need to do without so many extra hoops to jump through.”
Getting Away from Bespoke Transformers
Maria Robinson, DOE Grid Deployment Office | U.S. Energy Association
Highley and Maria Robinson, director of the U.S. Department of Energy’s Grid Deployment Office, also spoke of efforts to improve the supply of transformers.
Highley said the ESSC, a public-private partnership formed to improve energy resilience after the Sept. 11, 2001, terrorist attacks, has made major strides. “We’re much better today than we were two decades ago,” he said. “One of the things we’re looking at hard right now is the Defense Production Act capabilities that [the Department of Defense] has been given, and it might allow them to engage in helping make transformer supplies better.”
Robinson cited the Solid State Power Substation Technology Roadmap, a research and development effort being led by DOE’s Office of Electricity to reduce the criticality of substation components.
“One of the biggest issues is that transformers … are made to spec. They’re not modular in any way, shape or form,” Robinson said. “And there’s a lot of investment going into research to allow for more modular parts, recognizing that when you’re ordering a very specific design, it could take months or years for that to come in. And from a resilience perspective, we want to make sure that we’re able to rebuild more quickly than that.”
Ukrainian officials said earlier this month that Russia’s strikes on the nation’s infrastructure had destroyed about 30% of its autotransformers.
Asked what lessons the Russian attacks might hold for U.S. resilience efforts, Highley said: “Defense in depth; redundancy. It’s what’s always saved us, no matter what happens, whether it’s weather, cyberattack or physical kinetic attack.”
Florida’s Transmission Stands Tall
Philip Moeller, Edison Electric Institute | U.S. Energy Association
Also speaking at the briefing was former FERC Commissioner Philip Moeller, now executive vice president of the Edison Electric Institute, who touted the hardening investments made by Florida’s utilities before Hurricane Ian in September.
“In the last hurricane, we didn’t lose any transmission structures in Florida,” Moeller said. “So that tells you that the infrastructure investments — the hardening, the adaptation, the resilience — actually pay dividends.”
Moeller cited studies estimating that power outages in Florida can result in economic losses of $1 billion per day.
“So to the extent you can invest to correct those outages, that’s a pretty good bargain,” he said. “It also points out [the optionality value of] transmission. … As populations change; when congestion occurs; as public policies change; as fuel choices change, transmission is the infrastructure that gives us optionality.”
Robinson said DOE has $10.5 billion in funding to improve grid resilience and innovation through matching grants, “specifically looking at some of that hardening work that needs to happen, both at the transmission and distribution levels.”
Moeller said additional federal funding also will help expand cybersecurity programs to “more of the smaller energy companies and utilities throughout the country, so that we can have a more comprehensive approach toward the cyber threats that are out there.”
More East-west Transmission
Michael Skelly, Grid United | U.S. Energy Association
Highley and Michael Skelly, founder and CEO of transmission developer Grid United, also talked about the need for more interregional transmission to address reliability problems and the solar duck curve.
“We need a national will to build national transmission east [to] west. So much of what we have now is north to south,” Highley said. “The RTOs even tend to be oriented north to south — if you look at CAISO, you look at SPP, if you look at MISO — and that’s why we have duck curve problems. … A duck curve exists because the sun sets on a time zone all at once. And if you could move that east and west, you wouldn’t have a duck curve at all.”
Skelly was asked whether Texas policymakers might consider making ERCOT FERC-jurisdictional by interconnecting with the Eastern and/or Western grids in response to the blackouts following the February 2021 winter storm.
“I would say the chances of Texas joining the rest of the country, electrically speaking, are between zero and none,” Skelly replied. “But I do think that the prospects for DC connections between ERCOT and elsewhere are fairly good.”
ERCOT currently has transfer capacity of only 1,200 MW with “the outside world, as we in Texas, like to call it,” Skelly said. His company is proposing a project that would connect West Texas and El Paso. He also mentioned Pattern Energy’s Southern Spirit project, a 400-mile line between East Texas and Mississippi.
“I think we’ll see more projects like that. And they’re beneficial, because … ERCOT has tremendous amounts of wind and solar. And these lines would allow ERCOT to share that abundance with the rest of the country, and also provide reliability to ERCOT during stressful grid conditions,” Skelly continued.
“I know ERCOT has had kind of a rough go in many respects. But one of the reasons that Texas has so much renewable energy — we lead the country in wind; we will soon lead the country in solar — is precisely because of its independence. You have one jurisdiction that can make decisions around grid expansion [with] fairly low barriers to entry. … So I don’t think things will change in terms of like FERC jurisdiction, but I do think there’s opportunities to connect us through these DC connections, and those will be beneficial all around.”
DTE Energy executives promised a more aggressive clean energy transition during their third-quarter earnings call Thursday.
Pointing to the Inflation Reduction Act, the utility’s leadership told financial analysts to expect a speedier resource changeover when it files a new integrated resource plan with the Michigan Public Service Commission in early November. CEO Jerry Norcia said the plan will detail how DTE plans to accelerate its decarbonization efforts.
DTE earned $311 million ($1.60/share) for the quarter, $21 million higher in a year-over-year comparison because of deferred tax amortization and lower operations and maintenance expenses.
Norcia said “climate change remains our generation’s defining public policy issue.” He said the utility is committed to investing in clean energy and grid modernization to ensure reliability against extreme weather and to accommodate new load from electric vehicles.
“We are focusing on updating and improving our aging infrastructure for this additional demand while continuing to provide safe, reliable and affordable energy,” Norcia said. “Two important factors affecting our grid are climate change and emerging electrification technologies. We need to build the grid of the future to ensure we can continue to provide clean, safe, reliable and affordable energy.”
Norcia promised a “shift towards renewables and natural gas and away from coal generation.”
CFO Dave Ruud said the IRA will help accelerate DTE’s clean energy transition and keep customer costs in check. Norcia said the legislation’s passage will have “a very positive impact” on the company’s IRP, lower the cost of renewable investments and improve the affordability of carbon-capture and storage technologies.
“We have now the opportunity to invest greater amounts in our renewables build-out, so very positive impact overall,” Norcia said.
He also said DTE’s voluntary renewables program, MIGreenPower, continues to show “substantial growth” with a new 400-MW customer joining this week, bringing the program’s subscription to 2.1 GW.
DTE Energy has a goal to achieve net-zero carbon emissions by 2050.
Last month, the Ann Arbor City Council voted 10-1 to fund a $500,000 feasibility study on breaking away from DTE Energy. City officials have said their existing clean energy plans are an obstacle to meeting the city’s goal to achieve carbon-neutrality by 2030.
Activist group Ann Arbor for Public Power said DTE “fails to provide reliable electricity, charges residents more than the national average and gets more than 50% of its power from coal.”
The earnings call came as DTE and Consumers Energy face an audit from the Michigan PSC over compliance with outage and safety regulations. Last summer, storms left Michigan ratepayers on extended outages, leading to inquiries from state regulators. (See Mich. PSC Issues Emergency Order Following Devastating Storms.)
Norcia said he thinks the audit will ultimately strengthen DTE’s relationship with the commission and better align their views on the utility’s investments. He said current discussions with PSC staff are “really collaborative.”
Norcia said DTE’s grid averages 99.9% availability and its best-in-class utility performance is about 99.97%. He said all of DTE’s capital investment plans are “pointed at how do we get to that 99.97% availability for our grid.”
“So, I feel that this process with the Commission will create stronger alignment,” Norcia said, adding that DTE has systems that must be “replaced, modernized and automated.”
The New Jersey Board of Public Utilities voted unanimously Wednesday to spend $1.07 billion on transmission upgrades to deliver 6,400 MW of offshore wind generation to the PJM grid, saying the projects would minimize costs, environmental impacts and permitting risks (Docket No. QO20100630).
The BPU made its selection from among 80 proposals submitted by 13 developers in response to a solicitation issued by PJM at the BPU’s request under FERC Order 1000’s State Agreement Approach.
The solicitation asked for four categories of transmission upgrade proposals, including Option 2 for new offshore transmission connection facilities — extending the PJM grid into the ocean — and Option 3 for new offshore transmission network facilities. (See PJM Sees Wide Range of Costs in NJ OSW Tx Proposals.)
Andrea Hart, N.J. Board of Public Utilities | NJ BPU
But Andrea Hart, BPU’s senior program manager for offshore wind, said BPU staff and consultants Brattle Group rejected those options as too costly, narrowing its selection to Option 1b proposals for new onshore transmission connection facilities and Option 1a proposals for upgrades to resolve reliability criteria violations resulting from the generation injections.
Hart said most of the Option 2 proposals connected only a single project to each offshore substation, resulting in no reduction in the number of export cables compared with a baseline scenario without coordinated procurement. In addition, transmission-only projects would not qualify for the 30% federal investment tax credit available to generation projects, foregoing as much as $2.2 billion in subsidies. The Option 3 proposals, which were contingent on Option 2, were also rejected. “Staff remains optimistic that the costs of a coordinated transmission will continue to decrease, which could open the door for procurement of option two facilities through a future SAA solicitation,” she said.
In addition to $575 million in necessary Option 1a upgrades, staff selected what it called the Larrabee Tri-Collector Solution, which includes parts of FirstEnergy’s Jersey Central Power and Light’s 1b proposal (NYSE:FE) and pieces of Mid-Atlantic Offshore Development’s Option 2 proposal.
The Mid-Atlantic Offshore Development proposal will provide routes to three points of interconnection on Jersey Central Power and Light’s transmission system: the 230-kV Larrabee substation, two 500-kV transmission lines to the Smithburg substation, and one 230-kV line to the Atlantic substation. | Mid-Atlantic Offshore Development
The centerpiece of the $504 million project will be a new substation adjacent to JCP&L’s existing Larrabee substation. Mid-Atlantic Offshore Development, a joint venture of Shell New Energies US (NYSE:SHEL) and EDF Renewables North America (OTCMKTS:ECIFY), will build the AC portion of the new Larrabee Collector Station to accommodate three future HVDC circuits. The project will include sufficient land for the installation of up to four DC converter stations. “This will ensure robust competition is maintained — upholding open-access transmission principles — throughout future OSW solicitations,” the board said.
The collector station will use existing JCP&L rights of way to distribute up to 4,890 MW to three points of interconnection (POI): the Smithburg 500-kV, the Larrabee 230-kV substation and the Atlantic 230-kV.
Although the BPU’s order does not provide a shore crossing solution under the SAA, its order noted that the MAOD proposal identified the National Guard Training Center at Sea Girt as the preferred crossing point.
The board said the Larrabee collector is “an innovative transmission solution, creating a single onshore POI while leveraging existing rights of ways, an outcome that would not have been possible without coordinated planning and a competitive solicitation.”
“The awarded projects also position the state to seek direct federal funding for future expansions of the OSW transmission grid, including the potential to award a full OSW backbone in connection with the board’s future OSW solicitations, and preserves preferable interconnection locations and transmission corridors for future use,” the board said.
Although the MAOD-JCP&L Option 1b solution was intended to connect three 1,200-MW HVDC systems, PJM said the equipment in the AC substation can handle up to 4,530 MW of future injections from DC converter stations.
“PJM’s analysis suggests that this provides an excellent platform for accessing additional headroom on the PJM system with modest additional upgrades in the future,” the BPU said.
The Missing Link
The SAA solicitation was intended to provide sufficient transmission to provide 6,400 MW of OSW capacity, helping the state meet its original goal of 7,500 MW of OSW by 2035. Ocean Wind I, which was awarded offshore wind renewable energy certificates for 1,100 MW in the state’s first OSW solicitation, is not eligible to use the capacity resulting from the SAA.
The BPU acknowledged that the transmission projects it selected under the SAA would not prevent future OSW generators from proposing different landing points or different routes from their landing points to the Larrabee collector.
BPU Chair Joseph Fiordaliso | NJ BPU
As a result, the board said it will require a successful bidder in its third OSW solicitation, scheduled for the first quarter of 2023, to “prebuild” a single corridor from the shore crossing to the Larrabee collector, ensuring a single onshore transmission corridor.
In September, Gov. Phil Murphy increased the state’s OSW goal to 11,000 MW by 2040. The board’s order directs staff to begin a second round of coordinated transmission planning to meet the increased goal, potentially including a new SAA solicitation.
Pending approval of the PJM board, the RTO will include the projects selected by the BPU in its Regional Transmission Expansion Plan as baseline public policy projects.
In addition to the Larrabee collector, the BPU approved $575 million in upgrades to existing onshore transmission identified by PJM as necessary to support the OSW injections, including:
PSE&G’s proposed Brunswick to Deans and Deans subprojects and Windsor to Clarksville subproject: $40.3 million;
LS Power’s additional Hope Creek-Silver Run 230-kV submarine cable plus upgrade: $61.2 million;
Atlantic City Electric’s proposal to reconductor the Richmond-Waneeta 230-kV line: $16.9 million;
Transource’s North Delta A proposal: $109.68 million;
PPL to reconductor the Gilbert-Springfield 230-kV: $380,000;
PECO to replace four Peach Bottom 500-kV breakers: $5.6 million; and
BGE to upgrade one Conastone 230-kV breaker: $1.3 million.
Because the State Agreement Approach requires New Jersey to assume 100% of the costs of the $1.07 billion in spending, the bills of average residential customers will increase by $1.03/month, the BPU said.
The BPU said its selections would save $900 million over the baseline scenario, evidence of the board’s “prudent and careful” approach, BPU Chair Joseph Fiordaliso said.
BPU Commissioner Dianne Solomon | NJ BPU
But Commissioner Dianne Solomon said she was concerned about the costs of this and future transmission expansions. “I’m sure my fellow commissioners agree we must work with others in our region to oversee and share the costs of the build out of offshore wind,” she said.
The BPU’s order said “it may be beneficial, prior to initiation of the second SAA, to review with other states, both inside and outside the PJM region, the potential for jointly undertaking an offshore wind planning process and incorporating those larger needs into this future SAA. While such a multistate process may present additional complexities, it is also likely to reduce costs to ratepayers by identifying even more robust regional solutions by considering a wider range of public policy needs, and by enabling the sharing of costs with other states who participate in the SAA process.”
Comments
MAOD did not respond to a request for comment. FirstEnergy spokesperson Chris Hoenig called the award “a landmark development opportunity in new, regulated transmission assets.”
PJM CEO Manu Asthana called the BPU’s action “an important milestone in the development of offshore wind in the U.S.”
“We see the State Agreement Approach as a model for how states can leverage PJM’s processes to advance their policy goals,” he added.
The ERO Enterprise’s work preparing the bulk electric system for extreme winter weather is far from over despite the completion of the initial effort to update reliability standards in response to last year’s winter storms, members of NERC’s Board of Trustees said Wednesday.
Meeting virtually, the board voted unanimously to adopt the new standards EOP-012-1 (Extreme cold weather preparedness and operations) and EOP-011-3 (Emergency operations), along with their implementation plan. Both standards were produced as part of Project 2021-07, begun by NERC last year in response to its joint inquiry with FERC into the February 2021 winter storm that forced thousands of megawatts of generating capacity offline in Texas and led to several days of forced outages across the state. (See FERC, NERC Release Final Texas Storm Report.)
With the acceptance of the board, the new standards will now be submitted to FERC for approval.
NERC CEO Jim Robb | NERC
At Wednesday’s meeting, NERC CEO Jim Robb described the new standards as the fulfillment of a promise that he and FERC Chairman Richard Glick made at the height of last February’s crisis.
“I remember being on the phone with Chairman Glick … and the one thing that the chairman and I committed at that point — to each other and effectively to all the citizens of North America — was that we weren’t going to let the lessons of this event go unheeded,” Robb said. “And we reiterated that commitment in several forums … that enough was enough and that we were really going to move forward to make sure that whatever we learned out of this event would inform all of our actions around extreme weather and cold weather preparedness.”
The joint inquiry recommended that NERC implement significant changes to its standards, and Project 2021-07 was intended as the first part of a three-phase response to the report. Four of FERC’s recommendations are addressed by the new standards:
to require generator owners (GOs) that experience outages or other issues because of freezing to create a corrective action plan (CAP) for the affected equipment and determine whether to revise its cold-weather preparedness plan to account for the CAP;
to require GOs and generator operators to conduct annual unit-specific cold-weather preparedness plan training;
to require GOs to retrofit existing generating units and design new units to operate to a specified ambient temperature and weather conditions; and
to require transmission owners and operators, and distribution providers, to separate circuits used for manual load shed from circuits used for underfrequency load shed and undervoltage load shed, or serving critical loads.
Howard Gugel, NERC’s vice president of engineering and standards, told trustees that these four recommendations were chosen for the focus of the first phase because the joint report suggested they be completed before the winter of 2022-23. The remaining six recommendations are intended to be addressed in the second phase, to be completed before winter of next year.
Trustees Support Standards, with Reservations
While board members supported the new standards in general terms, their comments made clear that this week’s vote is not the end of the conversation. Trustee Sue Kelly called Project 2021-07 merely “a down payment” on the work needed to properly address the grid’s vulnerability to severe weather, specifically saying that “this version of EOP-012 should [not] be the end of the discussion on winterization of generating units.”
She noted that the standard, as written, allows GOs to essentially opt out of implementing freeze protection measures by giving them the authority to define the “technical, commercial or operational constraints” that would “preclude the ability” to install these measures. She warned that this concession to GOs would “leave their reliability coordinators with a reduced set of generation resources to work with during the winter season.”
Howard Gugel, NERC | NERC
Observing that EOP-012-1 requires GOs to document “fuel supply and inventory concerns” in their cold weather preparedness plans, Trustee Jim Piro asked Gugel whether generators “have the ability to cause the upstream system” — specifically natural gas pipelines that feed generators — “to also winterize their systems.”
Gugel acknowledged that the standard does not give GOs that power. He suggested that such a requirement “could be placed within their fuel contracts” and added that the joint report does recommend separately that the gas industry do something to address winter preparedness in its own system.
Piro also asked whether the standard gives NERC any visibility into GOs that do opt out of the freeze protection measures, so that their potential unavailability can be factored into the organization’s winter reliability assessments. Gugel said NERC does have several means of gathering that data, from requesting it as part of the normal information gathering for the reliability assessments, to issuing alerts to compel utilities to report whether they have opted out.
While calling the new standards “a major step forward,” Trustee Roy Thilly reminded attendees that winter preparedness is “a very complex issue” that “is going to impose some pretty significant costs” on utilities. He made clear that although he sympathizes with the financial concerns of the industry, NERC cannot let this issue influence its decisions about changes that may be needed to ensure reliability.
“NERC has been, and needs always to be, concerned with and understand the cost it’s imposing on industry through reliability standards. We do that by looking at cost-benefit analysis, and we rely very heavily on industry … [which] is really in the best position to inform that analysis,” Thilly said. “But the issue of the ability to recover through rates and market tariffs is outside of NERC’s jurisdiction and … our control.”
“It’s very important that NERC urge FERC, RTOs, municipal and co-op boards and councils, and states, to take the steps necessary to enable recovery by industry participants of reasonable costs incurred to comply with mandatory NERC reliability requirements,” he added. “But it’s beyond our scope to get there, and we can’t not adopt a needed reliability standard because of concerns [about] cost recovery.”
FirstEnergy on Wednesday reported third-quarter earnings of $334 million (58 cents/share) on revenues of $3.5 billion, down from $463 million (85 cents/share) on revenue of $3.1 billion a year earlier.
Excluding special charges or credits, the company’s operating earnings were 79 cents/share, at the top of analysts’ guidance range. That compares to operating earnings 82 cents/share a year ago.
“Our continued solid results, together with the ongoing efforts to strengthen our culture, accelerate improvement in our balance sheet and achieve operational excellence, are creating positive momentum at FirstEnergy and positioning us to capitalize on significant opportunities for growth through long-term, customer-focused investments,” John W. Somerhalder II, board chair and interim CEO, said in a statement accompanying the results. “I’m confident our leadership team and committed employees will continue to drive these strategies to transform the company into a best-in-class utility.”
The company updated its full-year forecast for adjusted earnings to a range of $1.145 billion to $1.260 billion ($2.01- $2.21/share) based on 571 million shares outstanding.
The company reported that power deliveries for the third quarter were flat, with a 2% uptick in industrial demand offsetting a decline in residential and commercial demand.
The company’s regulated transmission business showed improved results, primarily from the company’s ongoing capital investment program, which yields guaranteed income.
In its quarterly report filed with the Securities and Exchange Commission, the company said it had recalculated transmission and distribution expenses as demanded by a FERC audit issued earlier this year.
“FirstEnergy completed an analysis during the third quarter of 2022 of these costs and how it impacted certain FERC-jurisdictional wholesale transmission customer rates for the audit period of 2015 through 2021,” the company said.
“As a result of this analysis, FirstEnergy recorded in the third quarter of 2022 approximately $45 million ($34 million after-tax) in expected customer refunds, plus interest, due to its wholesale transmission customers and reclassified approximately $195 million of certain transmission capital assets to operating expenses for the audit period, of which $90 million ($67 million after-tax) are not expected to be recoverable and impacted FirstEnergy’s earnings since they relate to costs capitalized during stated transmission rate time periods. …
“These reclassifications also resulted in a reduction to the Regulated Transmission segment’s rate base by approximately $160 million, which is not expected to materially impact FirstEnergy or the segment’s future earnings.”
SEATTLE — EPA on Wednesday announced it is distributing nearly $1 billion in grants to 389 school districts across the U.S. to buy cleaner buses, most of them electric.
Made available by the Infrastructure Investment and Jobs Act, the funding targets school districts in all 50 states, D.C. and U.S. territories, with a focus on assisting low-income, rural and tribal areas. Wednesday’s awards are the first in a five-year, $5 billion program created by the law.
The initial grants will help support the purchase of more than 2,400 clean school buses to “accelerate the transition to zero emission vehicles and produce cleaner air in and around schools and communities,” EPA said in a press release.
Vice President Kamala Harris joined EPA Administrator Michael Regan and Washington Gov. Jay Inslee at Lumen Field, home to the NFL’s Seattle Seahawks, to announce the funding. Harris pointed out that 25 million U.S. children take buses to school each day, but that “95% of our school buses are fueled with diesel fuel, which contributes to very serious conditions that are about health and about the ability to learn.”
Harris said the new buses would reduce incidences of childhood ailments such as asthma. She also cited reducing greenhouse gases and the economic boost to local industries involved in building the buses as additional reasons for the appropriations.
“Our electric school bus program really does represent an intersection of all these points, on top of the importance of investing in domestic manufacturing,” the vice president said. “We all know when, during the height of the pandemic, we saw what it means when we don’t have domestic manufacturing around things we need every day; it slows us down.”
“Not only does this stop climate change, but its stops asthma in our kids because they don’t have to breathe in diesel smoke,” Washington Gov. Jay Inslee told the audience.
EPA originally allocated $500 million for the 2022 grants, but it received so many applications that it almost doubled the pool of money available, Regan said. Ultimately, EPA distributed $913 million to 389 districts to purchase 2,463 buses, he said.
In Washington state, four school districts received a total of about $2.7 million. Each of them — Easton, Pomeroy, South Whidbey Island and Toppenish — are rural areas.
And while rural school districts dominated the national list of recipients, some large metropolitan ones, such as Atlanta and New York City, won among the largest rewards of about $9.9 million each.
“Those school districts who received an award can now proceed with purchasing new buses and eligible infrastructure,” EPA said in its announcement. The agency said it is partnering with the U.S. departments of Energy and Transportation to provide recipients “with robust technical assistance to ensure effective implementation.”
In a statement, Sue Gander, director of the Electric School Bus Initiative at the World Resources Institute, said the EPA program “marks a huge step forward in efforts to equitably electrify the nation’s school bus fleet. We are excited that school districts from coast to coast, large and small, urban and rural, will be receiving one or more electric school buses, including in twelve states and Washington, D.C, that previously had none on the way.”
Gander also had advice for bus makers. “For any manufacturers who are wondering about where to focus their investments, today’s announcement demonstrates loud and clear that the future is electric. It is time to step up and scale up production and job training for an inclusive transition.”
“Today’s announcement is the result of years of advocacy by families, students and community members seeking federal funding to facilitate their local school districts investing in a clean ride for kids,” Carolina Chacon, coalition manager for the Alliance for Electric School Buses, said in a press release. “These new electric buses will eliminate dangerous toxins in the air our children and communities breathe and reduce climate-harming pollution. For students and drivers, this means quieter rides, better health and fewer missed days of school or work due to preventable respiratory illnesses.”
Regan said EPA will soon establish a $1 billion pool to take another round of applications for clean bus grants. “Improving lives of young children around the country is near and dear to the EPA’s mission,” he said.
