PJM stakeholders asked a federal appellate court Wednesday to require the RTO to exercise more oversight over transmission owners’ end-of-life (EOL) projects, saying some of the replacements should be subject to regional planning and competition.
The D.C. Circuit Court of Appeals heard 80 minutes of oral arguments in a challenge to commission rulings that EOL projects are the exclusive province of the transmission owners (20-1449).
In August 2020, the commission accepted a TO-initiated filing adding EOL projects to the planning procedures of tariff Attachment M-3 (ER20-2046). Four months later, the commission rejected proposed tariff changes supported by stakeholders including American Municipal Power, LS Power and consumer advocates that would have moved such projects under the RTO’s planning authority. The commission upheld its rulings last August. (See FERC Rejects Challenges to Decision on EOL Projects in PJM.)
“When the need arises because a facility has been retired, we want PJM to be involved in deciding: Is that a need that gives rise to a plan or a project with regional benefits, in which case it should be regionally planned?” Erin Murphy, an attorney for appellants, told the D.C. Circuit panel, which comprised Judges Neomi Rao, J. Michelle Childs and David Tatel. “Or maybe it is a project that’s local and can be locally planned. What we don’t want is a world in which transmission owners get to make that decision for themselves and decide to locally plan projects, even when as here it’s clear that they actually have projects with regional benefits.”
The appellants said FERC’s rulings result in balkanized planning for EOL projects. In 2018, they noted in a brief, “there were $8.5 billion worth of transmission projects planned, with the largest driver being the need to address end-of-life conditions.”
Speaking on behalf of the TOs, attorney John Longstreth said PJM already has authority to override local EOL projects when there’s an overlap between the local project and a regional project. “PJM gets to plan that project. … We can’t stop that,” he said. “So that protects this regional planning authority.”
In rejecting rehearing, FERC concluded that the Consolidated Transmission Owners Agreement (CTOA) with PJM was “ambiguous” as to planning EOL projects. But the commission sided with the TOs, noting that they had continued to plan EOL projects after the agreement was signed, “with PJM’s acquiescence.”
Rao pressed FERC attorney Susanna Chu on why the commission did not consider the justness and reasonableness of the local planning of EOL projects. Locally planned projects are allocated only to a TO’s zone rather than regionally.
“FERC’s position here seems to me very peculiar,” Rao said. “By choosing the transmission owner proposal, you are choosing one particular allocation of cost. And then why isn’t it incumbent on FERC to determine whether that cost allocation is just and reasonable?”
Chu responded that the rulings did not involve complaints over cost allocation. “The commission accepted it as just and reasonable, but on the basis that it didn’t change the status quo — the existing cost allocation remained the same,” Chu responded.
“Actually, on FERC’s view, it did change the status quo,” Rao shot back. “So at least, at a minimum, FERC’s internal reasoning is unreasonable, maybe, or arbitrary and capricious.”
The TOs intervened to challenge FERC’s description of the CTOA as ambiguous, saying it “interferes with and adds uncertainty to” the transmission planning process. FERC said the TOs’ claim should be dismissed because they failed “to demonstrate that they have suffered any concrete injury.”
Sen. Joe Manchin (D-W.Va.) said last week he won’t call a hearing on President Biden’s nomination of Richard Glick to remain as FERC chair, dimming the five-year commissioner’s chance of returning for a second term.
Manchin, chair of the Senate Energy and Natural Resources Committee, said through a spokeswoman that he would not bring Glick’s renomination up for a hearing despite his backing from Biden. Manchin “was not comfortable holding a hearing,” spokeswoman Sam Runyon said in an email Thursday, declining further comment.
Glick joined the commission in November 2017 after serving as general counsel for the Democrats on the committee. Biden named him chair in January 2021 and renominated him for a new term in May.
But Manchin — who was angered earlier this year by the commission’s proposal to consider greenhouse gas emissions in natural gas infrastructure certificates — never endorsed him.
At an ENR Committee hearing in March, Manchin accused Glick of pursuing a partisan climate agenda that undermined U.S. energy security. Although Glick defended the original policy statement at the hearing, a month later FERC walked the policy statements back, labeling them as drafts and saying any new rules would apply only to future projects (PL18-1). (See FERC Backtracks on Gas Policy Updates.)
FERC Chairman Richard Glick took part in the commission’s annual technical conference on reliability last week.
| FERC
Glick’s fortunes also may have suffered from Manchin’s testy relationship with Biden.
When Manchin — a pivotal vote in the 50-50 Senate — announced in December that he would not support the president’s Build Back Better climate plan, the White House blasted him for what press secretary Jen Psaki called “a sudden and inexplicable reversal in his position and a breach of his commitments to the president and the senator’s colleagues in the House and Senate.” (See Manchin Says ‘No’ on Build Back Better.)
Relations appeared to have improved when Manchin agreed to the smaller Inflation Reduction Act, and the senator took part in Biden’s signing ceremony in August.
But Manchin was angered anew earlier this month when Biden referred to the Brayton Point power plant in Somerset, Mass., during a speech. Part of Brayton Point — New England’s largest coal-fired plant when it shuttered in 2017 — is being repurposed to a subsea cable manufacturing facility to service the offshore wind industry. “We’re going to be shutting these [coal] plants down all across America and having wind and solar,” Biden said on Nov. 4.
“Comments like these are the reason the American people are losing trust in President Biden,” Manchin responded in a statement Nov. 5. “Being cavalier about the loss of coal jobs for men and women in West Virginia and across the country who literally put their lives on the line to help build and power this country is offensive and disgusting. The president owes these incredible workers an immediate and public apology, and it is time he learn a lesson that his words matter and have consequences.”
White House Press Secretary Karine Jean-Pierre said later that Biden’s words had been “twisted.”
“The president was commenting on a fact of economics and technology: As it has been from its earliest days as an energy superpower, America is once again in the midst of an energy transition,” Jean-Pierre said.
Sen. Joe Manchin joined colleagues as President Biden signed the Inflation Reduction Act into law in August. | The White House
Manchin’s surprising criticism of his party’s president — coming days before the midterm elections — was unconvincing to conservatives, who noted the senator’s crucial support for the IRA.
New York Post commentator Miranda Devine criticized what she called Manchin’s “faux outrage.”
“He knew what Biden was when he caved in and voted for the so-called ‘Inflation Reduction Act,’ which was the Green New Deal in disguise,” she tweeted.
“Well, sorry, Sen. Manchin, but you single-handedly gave this president more, not less, power to gut our fossil fuels with the idiotic climate bill!” commentator Laura Ingraham tweeted. “You helped create this monster.”
‘Confident’
Whatever the reason for Manchin’s decision, it appears to leave Glick little more than a month to complete his legacy at the commission. Although Glick’s term expired June 30, he can remain in his post through the end of the lame duck congressional session, scarcely enough time to complete all of the major rulemakings he began, including transmission planning and cost allocation (RM21-17) and interconnection policy (RM22-14), in addition to the pipeline policy statement.
“Like I’ve said before, I worry about the things I can control. The things I can’t control, I don’t worry about,” Glick told E&E News during a break in the conference. He added that he spoke to Manchin on Wednesday night and was not told much more than the statements released by the senator’s office. “We’ll see what happens,” Glick said.
Glick left the conference early, citing another appointment.
Speaking in October at the American Council on Renewable Energy’s (ACORE) Grid Forum, Glick said Senate Majority Leader Chuck Schumer (D-N.Y.) and his backers in the White House were “working hard towards confirmation.” (See Scenario Planning, Magical Thinking and Energy Efficiency.)
“They are confident,” Glick said, before turning fatalistic. “We have a lot of day-to-day work to do. [I] try to focus on that on a daily basis, and whatever happens, happens.”
ClearView Energy Partners cited Energy Information Administration data that West Virginia produced almost 91% of its power from coal in 2021, and noted that the state exports about half the power it generates.
“The impact of ‘shutting down’ all coal capacity appears to bode ominously for West Virginia’s economy, independent of Chairman Manchin’s personal investments in the coal sector,” ClearView said. “The White House’s overall decarbonization agenda may be overshadowing Chairman Manchin’s concerns over FERC policy — and the pending renomination may be one of the few levers available to him to push back against it.”
Deadlock?
News of Manchin’s decision sparked discussion on Energy Twitter over how long the commission might be without a fifth commissioner and whether it would face a deadlock between Democrats Allison Clements and Willie Phillips and Republicans James Danly and Mark Christie.
But while Christie was highly critical of the Democrats’ original pipeline policy statement, he has often sided with them on other issues, with Danly often the lone dissenter.
Former FERC Chairman Neil Chatterjee said a 2-2 party split would not deadlock the commission.
Christie “is already at the table negotiating on transmission. And if three votes come together on pipelines, they will move forward regardless of who is chair,” he tweeted. “I had 2-2 for almost a year, and we got a ton of significant things done. … Everything at FERC will be fine.”
At FERC’s annual reliability technical conference on Thursday, commissioners focused on the work needed to prepare the bulk power system for a world of rapidly developing challenges.
Commissioner Willie Phillips | FERC
“Much has been said about mistakes that have happened in the past. Much has been said about some of the near-misses and misses that we’ve had on our system,” Commissioner Willie Phillips, who served as moderator, said in his opening remarks. “What I would like to focus on is the future. I would like for you to help me see around the corner [and] what your thoughts are on best practices that we can use.”
He continued, “Help us see where the gaps are with our regulatory regime, so that we can make sure that we direct the right and specific changes to [NERC’s] reliability standards, which I don’t think anybody can argue are a great foundation.”
The first of the day’s two panels focused on the reliability challenges emerging because of multiple transformations occurring, with the North American power grid becoming more decarbonized, more decentralized and more digital. NERC CEO Jim Robb outlined the issues that the ERO has identified in recent years, such as the behavioral differences between renewable and traditional generation resources; difficulties in controlling a large number of small, distributed generators; and the spread of cyberattacks from criminals and state-backed organizations.
Asked by FERC Chairman Richard Glick for their thoughts on the issues that the commission and NERC should be prioritizing, Robb’s fellow panelists had a wide range of responses. Michelle Bloodworth, president and CEO of America’s Power — a trade organization that advocates on behalf of the U.S. coal generation fleet and its supply chain — warned that the expected retirement of 93 GW of coal plants between now and 2030 would deprive the grid of generators with the “attributes” — including availability, fuel security and voltage stability — needed to maintain stable operation.
“I do think that it’s under FERC’s legal authority to ensure that we’re sending market signals so those resources do not exit the market,” Bloodworth said. “I also think that it’s in FERC’s responsibility under Section 215 [of the Federal Power Act] to … provide the financial support that is needed to retain those assets that provide those attributes, until resources with equivalent characteristics come online.”
But instead of incentivizing utilities to keep these assets and the safety they provide, Bloodworth said that current policies tend to have the opposite effect of encouraging entities to retire their coal plants prematurely. She urged FERC to “play a large role in … determining how we value those attributes” that contribute to reliability “with a sense of urgency” so that utilities can plan their generation needs properly.
Building on Bloodworth’s point, Mark Ahlstrom — vice president of renewable energy policy at NextEra Energy Resources, which calls itself the world’s largest producer of wind and solar energy — told commissioners they “need to actually get down to defining what ‘essential reliability services’ are.”
Calling himself “a representative from the inverter-based side of the world” — referring to the fact that solar and wind facilities, unlike coal plants, connect to the grid through inverters — Ahlstrom said the lack of agreement on what is necessary may have prevented his industry from pursuing the best paths.
“I’ve often said … give me some energy, some electronics, software and a definition of what you need, [and] we can give you anything you want. We just really haven’t clearly defined what is essential,” he said.
Asked by Commissioner Allison Clements about the challenges to managing the clean energy transition, Ahlstrom said that while there are “many pathways [that] all could reach the destination,” the difficult part is coordinating among the many different stakeholders helping to build the BPS. Tricia Johnstone, director of operational readiness at CAISO, added that while NERC’s reliability standards “provide a really good basis for us right now,” the ERO will have to work to ensure they are proactively adapting to the rapid changes.
“For an operator, your day-to-day measure [of] ‘are we doing a good job as a balancing authority’ is [NERC’s] BAL standards and measures, and that’s what we’re monitoring in the control room to make sure that we’re in balance,” Johnstone said, referring to the family of standards that govern resource and demand balancing. “But with some of the technologies — [for example], battery storage ramps very fast, and it will actually send our measurements where we don’t want them to be.”
She said the question for utilities and regulators should be how “those [standards] need to evolve in the future, so as the resource mix changes, do those measurements need to be adjusted?”
Emerging Cyber Challenges
In the second panel, which focused on cybersecurity, Phillips opened by noting that successful cyber defense requires “buy-in from the leadership” and full commitment to establishing a culture of safety, not just compliance. Phillips called NERC’s Critical Infrastructure Protection (CIP) standards a “floor” that can still “never keep up with the threats that we face,” and asked panelists “do you have the resources, do you have the intelligence, do you have the technical capability to … identify and respond to cybersecurity threats?”
SERC Reliability CEO Jason Blake acknowledged the cyber threat landscape as “daunting,” with “well funded [and] aggressive” adversaries who are “only getting more sophisticated.” Coupled with the dedication of the global cyber threat community, the increasing use of remote controls for grid monitoring and control, along with digital communications between utility staff, has expanded the “attack surface” available for these adversaries to target.
While Blake also reported taking “great pride [in] where this industry is today” and called the electric industry’s progress on cybersecurity far ahead of many other industries, he reminded the commission that considerable work will be needed on an ongoing basis just to stay even with the threats.
“We are not perfect, and we cannot rest, and you have to understand that concept as you move forward,” Blake said. “So how do you do that? I think you go in with the larger vision [and] overarching framework to make sure that you are constantly striving your organization, to advance it to meet the security challenges of today and tomorrow. It’s not enough just to try to achieve baseline compliance … what you’re wanting to do is … drive a continuous improvement mindset where you’re really advancing and pushing people.”
The work required to keep the CIP standards up to date was a major topic of discussion at the panel, with Clements suggesting that the deliberate pace of NERC’s standards development process might not be capable of keeping up with the emerging threats. She asked panelists for suggestions of how to make regulated entities more “nimble” while avoiding approaches that would “add another layer of bureaucracy or processes to it.”
Eric Miller, executive director of information technology infrastructure and real-time application support at MISO, suggested that there “could be benefit in trying to adopt existing frameworks.” For example, NERC collaborated with the National Institute for Standards and Technology (NIST) last year on a reference document mapping NIST’s Framework for Improving Critical Infrastructure Cybersecurity to the ERO’s CIP standards. (See NERC, NIST Update Cybersecurity Mapping.)
The benefit of this mapping, Miller said, is that at “a very high level, it’s very easy to communicate across the spectrum” the relationship between NERC’s standards and the NIST framework so that registered entities can identify actions that satisfy both. It can also help NERC’s standards development staff to find gaps in the standards and blind spots that are addressed by other frameworks.
All panelists felt that the CIP standards should not have to stand as the sole word on cybersecurity in the power industry. Brandon Wales, the executive director of the Department of Homeland Security’s Cybersecurity and Infrastructure Security Agency, said that utilities should have the flexibility to look beyond the minimum required of them and find the tools needed to meet their goals.
“Standards are never going to be there to address the acute problems we deal with, and so I wouldn’t say all emerging issues are behind the power curve, because there are many that can be fit within the existing structures,” Wales said. “But I do think that there are potentially a class of emerging issues that really test the foundations of what we are doing, and … we may need new areas that the existing frameworks don’t sufficiently capture the complexities of the network environment we deal with today.”
CAISO is moving toward a final plan to add a day-ahead market to its real-time Western Energy Imbalance Market, with the aim of having its Board of Governors and the WEIM Governing Body vote on the proposal in February.
The ISO plans to review a draft plan for the extended day-ahead market (EDAM) in a day-long meeting with stakeholders on Nov. 14. Comments on the final draft are due by Nov. 22, and CAISO expects to publish a final plan in early December.
The draft final proposal published Oct. 31 “reflects significant stakeholder input and design changes” compared with the initial draft in April and a revised proposal in August, CAISO said.
“The draft final proposal is a result of continuing extensive, open and collaborative stakeholder engagement, including more than 500 pages of stakeholder comments on the straw and revised straw proposals and stakeholder discussions during the numerous stakeholder meetings this year,” it said.
Major changes include a requirement that supply offers into the day-ahead market must have “associated transmission reservations.”
“In particular, a resource must be a designated network resource under the terms of the Open Access Transmission Tariff (OATT), have reserved firm point-to-point transmission, or have a legacy transmission contract,” the draft final plan said.
Transmission commitments have been a source of contention in the planning process.
The draft final proposal gives transmission customers and others extra time to plan their daily transmission and resource use by extending the deadline for the voluntarily release of transmission to the market from 6 a.m. to 9 a.m. on the day before delivery.
The plan calls for unscheduled transmission rights to be released to the market to optimize EDAM transfers.
“Stakeholders expressed concern that the timeline for releasing transmission rights to the EDAM … by 6 a.m. the day ahead is too early and may limit the ability of entities to enter into bilateral arrangements,” CAISO said in the draft. “They preferred to move the time closer to 10 a.m. when the day-ahead market runs.”
CAISO compromised with the 9 a.m. day-ahead deadline.
Resource Sufficiency
The EDAM’s resource sufficiency evaluation (RSE) proposal, meant to ensure that participants can meet their own internal needs before engaging in the market, has been another contentious issue during the EDAM design process.
The RSE is needed because balancing authority areas (BAAs) “across the West are not subject to a common resource adequacy or resource planning program” but EDAM must have a “common mechanism to ensure day-ahead supply sufficiency and avoid leaning on the pool of participants by any one EDAM participant,” the draft says.
The draft final proposal deals with the market’s approach to counting firm energy contracts in the day-ahead RSE, a particular area of concern for some stakeholders.
The contracts “are an important component of the supply portfolios of Western load serving entities and have been historically reliable and dependable sources of supply,” it said. But “for these types of firm energy contracts, while the delivery point to a BAA is known, the source and transmission path may not be known in time for the day-ahead market close [at 10 a.m.], when bids are submitted into the market.”
“Given the potential lack of resource and transmission specificity by the time of day-ahead market run at 10 a.m., stakeholders have expressed concerns regarding challenges that these arrangements raise, including the risk of the supporting resource potentially being double counted in how they are offered into the market and potential congestion price implications,” it said.
The draft final plan proposes allowing firm energy contracts to count toward the resource sufficiency evaluation while “strongly [encouraging] identification of the source or source BAA, particularly if it is located in EDAM footprint.”
“If [the] source BAA is not known, the arrangement will be modeled as a self-scheduled injection at the intertie of the sink BAA,” it says.
Tagging requirements, introduced in the revised straw proposal, are also meant to “instill confidence” in firm energy contracts, it said.
A tagging mechanism or “e-tag” is a means of electronically monitoring and recording energy transactions for firm energy contracts. The proposal requires “all non-source-specific forward supply contracts [to] be tagged within three hours following publication of the day-ahead market results.”
Penalties for failing the RSE have been debated repeatedly during the market’s design.
The draft final plan proposes revising the consequences for failing the RSE by including a “tiered structure that provides a tolerance band under which a relatively minor failure does not constitute a resource sufficiency evaluation failure, but failures above the tolerance band are subject to scaled financial administrative surcharges.”
Montcalm County in rural north-central Michigan, a hotbed of anti-renewable energy activity since 2021, saw voters in four townships reject referendums that would have established guidelines for wind or solar projects.
Voters in three of the townships — Douglass, Maple Valley and Winfield — also recalled seven officials considered supporters of wind power. Three were the townships’ top officials: Supervisor Terry Anderson in Douglass Township, Supervisor John Schwandt in Maple Valley and Supervisor Phyllis Larson in Winfield.
Voters also rejected a proposal to regulate residential and commercial solar energy projects in Belvidere Township. Belvidere Township does have a wind regulation ordinance on the books that was approved earlier this year by the council.
With all four proposals defeated, wind or solar energy projects in those townships cannot go forward. Local governments’ zoning commissions must reconsider how to handle any potential projects that may come before them.
A group called Montcalm County Citizens United has led the fight against wind power in the rural county. | Montcalm County Citizens United
Disputes over renewable energy projects — to date, mostly wind farm projects — are not uncommon in Michigan. But in the past two years Montcalm County has been a center of local opposition, led by a group called Montcalm County Citizens United, which distributed lawn signs saying: “2 Tall, 2 Close, 2 Loud. Not In My Backyard.”
Apex Clean Energy has been working for four years to develop a wind farm in the county with up to 75 turbines (375 MW). The company has also added a solar energy component to the project.
Brian O’Shea, Apex’s director of public engagement, said the company was disappointed with some of the election results, charging voters had been misled by an “organized misinformation campaign.” But he said the company still planned to work with “with over 500 participating farmers and landowners to develop a responsible wind project in Montcalm County and help accelerate Michigan’s shift to clean energy.”
Michigan has at least 3,231 MW of wind power, 6.8% of its total generation, with 225 MW under construction, according to the Department of Energy.
Opponents of the Montcalm regulatory proposals overwhelmed supporters in all four townships. In Belvidere Township, with the solar proposal, the race was the closest with 600 against and 378 in favor. Douglass Township had votes on two proposals regulating wind farms, and both failed. The first proposal was defeated 812 to 297, while the second proposal went down 819 to 304.
The Maple Valley Township proposal failed 594 to 265. And the Winfield Township proposal failed 736 to 355.
Winfield Supervisor Larson lost her recall election by just 56 votes. She said she was targeted because she had cast the deciding vote on the township’s wind ordinance.
Local media reported that the election results are leading some to call for the state — which has a goal of generating 60% of its power from renewables by 2030 — to take control of siting of energy projects.
“What happened in Montcalm is part of a larger chorus of [grassroots opposition] to these projects,” Ed Rivet, executive director of the Michigan Conservative Energy Forum, a nonprofit that advocates for clean energy, told Bridge Michigan. “I don’t see the trend (of local opposition) suddenly disappearing,” Rivet said. “The more that goes on, the more it will lead to a policy discussion.”
Charlotte Jameson, chief policy officer for the Michigan Environmental Council, told MLive there is a growing consensus that the state must become more involved: “The siting issue is definitely one where you have environmental groups, utilities and labor in agreement that there needs to be some kind of solution here.”
Low-Cost Nuclear Power Reduces Electricity System Costs by $1.1B | Climate Action Council
ALBANY, N.Y. — New York could reduce its decarbonization costs by $1.1 billion, an 8% cut, if forecasts of lower cost advanced nuclear reactors are realized, the New York State Energy Research and Development Authority told the Climate Action Council last week.
Carl Mas, director of NYSERDA’s Energy and Environmental Analysis Department, shared a sensitivity analysis during the Nov. 7 meeting that found that deploying 4 GW of small modular nuclear reactors in upstate zones A-F by 2050 could displace 12 GW of intermittent renewables and 5 GW of firm resources or battery storage under a low-cost nuclear scenario aided by new federal funding.
The low-cost scenario assumes 2030 capital costs of about $6,000/kW (2020 $) versus more than $9,000/kW under the high-cost scenario based on recent nuclear projects.
Proponents of advanced nuclear designs — such as the NuScale small modular reactor recently certified by the Nuclear Regulatory Commission — cite their passive safety features and potential economies of scale compared with traditional custom designs that have been prone to cost overruns. In addition to producing zero-emission electricity, such designs could be used in industrial process heat and hydrogen production.
New York’s four current reactors — Nine Mile Point units 1 and 2, James A. FitzPatrick and R. E. Ginna — total 3,358 MW of capacity and produced about one-quarter of the state’s in-state generation in 2021. Each of the plants has received license extensions from the NRC allowing them to run for a 60-year lifespan.
Prior analysis found the state’s electric system costs would increase by $9 billion on a net present value basis if the plants shut down after only 40 years. Their current license terms expire between 2029 and 2046.
Current installed nuclear capacity & contribution in New York State | Climate Action Council / 2022 Go
Adding 4 GW of new nuclear capacity would more than double nuclear’s share of energy production from the current 31 terawatt hours. No new nuclear would be added under the high-cost scenario.
In both scenarios, Mas said, “a majority of the energy and installed capacity is from wind and solar in 2050.”
Nuclear’s competitiveness would be dependent on new lower-cost designs — aided by more than $2 billion in funding from the CHIPS and Science Act — and tax credits under the Inflation Reduction Act. The two bills represent a “significant ramp up” in federal investment in the technology, Mas said. (See A Nuclear Renaissance in the Making?)
Mas said transmission costs and a lack of operational flexibility could limit nuclear’s future role. “We could hypothesize that with more flexible new reactor designs, we might see nuclear playing a larger role,” he added. “If more transmission gets built for the whole system than what we modeled, you could see more energy flowing from upstate to downstate, and that could put a put additional economic value on upstate nuclear.”
The scenario assumes the technologies would not come online until at least 2040. The findings “reinforce the benefits of a more flexible policy framework that can adapt over time,” Mas said.
Low-Cost Nuclear Scenarios Adds 4GW by 2050 | Climate Action Council
“We’re looking at least a decade for when these types of projects can get up and going,” he added. “Frankly, we just don’t know yet … since some of these new modules are only now being authorized.”
Bob Howarth, a professor at Cornell University, questioned the assumption that New York’s nuclear fleet possessed a 90% capacity accreditation factor (CAF), saying that Europe’s fleet average is “closer to 72 or 74% CAF.”
Mas responded that market signals under deregulation had led to a “substantial uptick in the utilization and CAFs of the nuclear fleet.”
Gavin Donohue, CEO of the Independent Power Producers of New York, commended the presentation, saying it highlighted how the state needs to be flexible and “keep the door open” to new technologies.
Paul Shepson, dean at Stony Brook University, asked whether nuclear waste disposal was incorporated into the cost estimates.
Mas responded that “there is an end-of-life assumption in terms of cost” and that, in the absence of national plan to manage spent fuel, the waste will be stored “in-place” at reactor sites.
Next Steps
Sarah Osgood, executive director of the CAC, said that remaining redlines of the council’s scoping plan will be circulated for consideration throughout the month ahead of a planned vote on the document on Dec. 19.
NYSERDA CEO Doreen Harris, the CAC’s co-chair, said the remaining meetings would be extended to four hours to accommodate the longer discussions that are expected as the council completes work on the plan.
The meeting on Dec. 5 would be used to reach final resolutions on outstanding items before the Dec. 19 vote.
Registration is open for the next Climate Justice Working Group meeting on Nov. 16.
A Nevada advisory panel is recommending the state adopt a mileage-based road usage charge for zero-emission vehicles, creating a new transportation funding source to help replace declining gas tax revenue.
Under the panel’s recommendations, the per-mile road usage charge would initially apply to zero-emission vehicles but be extended to all new vehicles by 2035, replacing the state fuel tax.
And as a shorter-term measure, the panel said, the state should charge a special fee for registering electric vehicles until the road usage charge is in place.
The Nevada Sustainable Transportation Funding Advisory Working Group approved the recommendations during a virtual meeting on Wednesday. The group’s recommendations will be included in a report to the state legislature ahead of the 2023 session.
Assembly Bill 413 of 2021 directed the Nevada Department of Transportation (NDOT) to convene an advisory working group to study and make recommendations on sustainable funding options for the state’s transportation needs. The 29-member group started meeting in July 2021. (See. Nev. Looks to Other States for Ways to Replace Gas Tax Revenues.)
As cars become more fuel-efficient and more drivers switch to electric vehicles, the state is worried about the impact on gas tax revenue. Since 2010, fuel tax deposited in the State Highway Fund has dropped from 1.27 cents per vehicle mile driven to 1.03 cents per mile, according to a draft version of the working group’s report.
“Like all states, Nevada is heavily dependent on fuel taxes to generate funding for highways, bridges, local roadways, and activities related to maintaining and operating these facilities,” the draft report said.
Much of Nevada’s gas tax goes into the State Highway Fund, which is used to pay for highway construction, maintenance and repair. The NDOT-managed road system will need about $17 billion over the next 10 years, but funding from state and federal sources for that period is estimated at $11 billion, leaving a $6 billion gap.
Fixed or Mileage-based Fees
The working group recommended that the road usage charge give electric vehicle drivers an option to pay either a fixed annual fee, allowing unlimited mileage, or a charge based on actual miles traveled.
That’s similar to the system used in Utah, where owners of electric or hybrid cars pay an alternative-fuel vehicle fee on top of the regular annual registration fee. But EV owners can choose to pay per mile instead of the alternative fuel vehicle fee. The per mile fee is capped at the amount of the alternative-fuel vehicle fee.
This year, Utah’s flat registration fee for an electric vehicle is $123 and the charge per mile is 1.52 cents.
In addition to the road usage charge, the working group is recommending other ways to boost revenue for transportation projects. Those include increasing vehicle registration fees; indexing fuel taxes to keep up with construction cost increases; and allowing counties to adjust their portion of the gas tax for inflation.
The working group considered several other revenue-raising measures but decided to not recommend them for further analysis at this time. Those included an EV battery tax, a tire tax and a parcel delivery fee.
Other State Programs
Oregon rolled out the nation’s first road usage charge program in 2013, according to the National Conference of State Legislatures (NCSL). Participants in the voluntary program, called OReGO, may drive gas-powered or electric vehicles. The per-mile charge is 1.9 cents. Drivers of gas-powered vehicles who participate in the program receive a credit for gas tax when they pay at the pump. EV drivers are eligible for reduced registration fees.
In 2020, Virginia started imposing an annual highway use fee on EVs, alternative fuel vehicles and vehicles with a fuel economy of 25 miles per gallon or more. In July, Virginia gave drivers who pay the annual highway fee another option: participating in the mileage-based Mileage Choice Program. Participants install a device in their cars to track mileage.
At the federal level, the Infrastructure Investment and Jobs Act (IIJA) of 2021 established two new grant programs for exploring road usage charges as a replacement for the gas tax, NCSL said.
The Strategic Innovation for Revenue Collection program will support pilot projects proposed by states, metropolitan planning organizations or local governments. With $15 million set aside for each of five fiscal years, the program will focus on road usage charge issues such as data privacy, administrative costs, implementation and equity.
The IIJA will also establish a pilot program for a national motor vehicle per-mile user fee, which could potentially be used to bolster the federal Highway Trust Fund.
FERC last week approved Vistra Corp.’s request to bypass MISO’s generator interconnection procedures to quickly add battery storage projects at two retiring fossil fuel plants (ER22-2632).
Vistra was seeking a waiver of MISO’s replacement generator rules so it could add 37-MW battery storage projects to partially replace output at two power plants in Illinois: its Joppa Power Plant, owned by the company’s Electric Energy Inc. subsidiary, and the Edwards Power Plant.
Ordinarily under its replacement generation rules, MISO requires the same generation owner to assume ownership of existing interconnection rights for a new facility. In its Nov. 8 order, FERC permitted Vistra to circumvent that requirement and allowed two subsidiaries — Joppa BESS (Battery Energy Storage Systems) and Edwards BESS — to assume the existing rights without entering the RTO’s interconnection queue.
Vistra explained that the storage ownership should remain separate because the projects’ investors did not bargain for liability of retiring fossil fuel generation. FERC agreed and said Vistra requested the one-time waiver in good faith.
“We find that Vistra’s request does not raise queue-jumping concerns because the necessary transfers do not involve unaffiliated entities outside of the interconnection queue, and Vistra pledges that Joppa BESS and Edwards BESS will maintain ownership until the energy storage facilities reach commercial operation, consistent with the transferability restriction,” the commission said.
Joppa, with six coal units totaling 948 MW of capacity and five gas units with 239 MW of capacity, closed in September. The 560-MW coal-fired Edwards facility is slated to idle Jan. 1. Both plants are closing to settle complaints of excessive pollution brought forward by environmental organizations.
Vistra is developing the storage projects under Illinois’ Coal-to-Solar Energy Storage Grant Program, part of the state’s Climate and Equitable Jobs Act. The company will receive $81 million over 10 years to build the two facilities, which are supposed to enter commercial operation no later than June 1, 2025, in order to stay grant-eligible.
Vistra said if it had been forced to enter the projects into MISO’s generator interconnection queue, it would miss the grant deadline. It currently takes about three years for a generator to complete the queue, though MISO is working to minimize the wait.
In a concurrence, FERC Commissioner Allison Clements said the “effect of granting this waiver is that a brownfield site of existing generation on the transmission system can be expeditiously re-used.”
Clements called for a re-examination of RTO rules that restrict a generation owner’s ability to hand over their interconnection rights to unaffiliated entities. She said the waiver “highlights the increasingly strained reasoning underpinning the transferability restrictions in MISO’s and other transmission providers’ generator replacement rules.”
“No part of those rules is more in need of reconsideration than these transferability restrictions, which, at best, appear to impede beneficial commercial transactions and, at worst, may unduly discriminate against non-incumbent generation owners,” Clements wrote.
Voters in Ann Arbor, Michigan, on Tuesday overwhelmingly approved a tax increase to fund efforts to reduce the city’s carbon footprint, voting more than two to one for a 1-mill hike in property taxes for the next 20 years.
The tax will add $153 annually for an average property with a taxable value of $153,000 (half of the average fair market value of $306,000). In 2021, Ann Arbor property owners paid 50 mills.
Mayor Christopher Taylor, who was re-elected on Tuesday, said he was “incredibly excited about what we can accomplish” with the funding and “proud” that the city became the sixth locality in the U.S. to adopt a tax to fight climate change. (See Ann Arbor Mayor Confident Voters Will Pass Climate Tax.)
The tax proposal, which will raise about $7 million in its first year, passed on a vote of 37,451 to 15,244. The proposal won a majority of votes in every one of Ann Arbor’s 53 precincts.
Taylor, who introduced the ordinance to the city council in 2021, said city voters “understand that climate change is real and that everyone has to take action” to combat its effects.
The city has a goal of achieving net zero emissions by 2030.
Missy Stults, the city’s sustainability director, said there was a lot of work to do to “achieve this audacious and scientifically accomplishable goal.” She said she would begin working on funding proposals and present them for the city council to consider in the 2023 budget.
Of the projected $7 million raised by the new tax, $2 million is anticipated to go for renewable energy projects; $1 million will go for expanded composting; $1 million to develop more cycling and walking projects and $1 million will go for electrification projects, including building electric vehicle chargers. About $700,000 will focus on projects assisting low-income residents, with another $500,000 going to cut down on energy waste and another $500,000 for neighborhood resilience projects, including tree planting and developing rain gardens.
NiSource said last week that it intends to sell up to a nearly 20% stake in its Northern Indiana Public Service Co. (NIPSCO) subsidiary to cover the costs of grid modernization and its push to net-zero emissions.
During NiSource’s annual investor day at the New York Stock Exchange on Nov. 7, CEO Lloyd Yates said the company is willing to part with a 19.9% interest in NIPSCO. That will foot the bill for a 2040 net-zero emissions goal and approximately $15 billion in grid and gas infrastructure modernization and clean energy investments over the next five years.
NiSource plans to open the sale in the first quarter next year.
Yates said NiSource will “remain committed” to its NIPSCO operations, but it needs to improve a balance sheet that has been “constrained” for 20 years, forcing the company to issue equity. With a minority sale, Yates said NiSource wouldn’t have to issue equities through 2025.
“Our industry is going through massive change as technologies evolve and as customer expectations evolve, so we’ve refreshed our mission, vision and values,” Yates said. “We’ll need to drive supportive regulatory and legislative policies, favorable stakeholder environments and advances in technologies that are not currently economical to achieve, but we are optimistic.”
Yates said NiSource’s reworked business strategy should “drive a compelling total shareholder return of 9 to 11% annually.” He initiated a strategic business review of the utility when he became CEO in February.
NiSource’s new direction is “well positioned to drive long-term value for all stakeholders,” Yates said. He said the review identified about $30 billion worth of total long-term investment opportunities over the next decade.
“We have a long runway of investment opportunities and the ability to grow over a long-term horizon,” he said. “While the energy transition presents great opportunities, there’s a threat to those who don’t continue to move forward in a way that creates value. The actions we are taking help insulate NiSource from these threats.”
Shawn Anderson, senior vice president of strategy and chief risk officer, said a minority interest sale is NiSource’s best path forward.
“There’s a good precedent in the industry of this type of transaction being completed successfully. And it’s a very efficient means of financing our business,” he said.
Anderson also said affordability will be a focus during NiSource’s energy transition. He said through 2027, the company anticipates “low, single digit” increases in customer bills caused by energy efficiency measures, a disciplined operations and maintenance plan, commodity prices leveling off and an expanded customer base.
NiSource’s extensive natural gas infrastructure is “a critical component” to accelerated decarbonization, Anderson said. It will provide reliable baseload generation and be ideally situated for conversion to renewable natural gas or green hydrogen, he said
NiSource plans to retire its coal generation units by the end of 2030 and thereafter draw on a 51% mix of renewables and 35% natural gas generation. Energy efficiency, demand response and capacity purchases will make up the remainder.
By the end of 2025, NiSource expects to have spent $2.2 billion on renewable generation.
“We’re making the fastest transition away from coal. Seventy-four percent coal to zero in a single decade. A 90% reduction in emissions by 2030, including the 58% reduction we’ve already achieved. And now a goal of net zero by 2040,” Anderson said.
