Both houses of the Vermont Legislature have approved a bill updating the state’s Renewable Energy Standard to move it toward 100% renewable electricity by 2030.
It would require most retail electricity providers to make renewable energy at least 63% of their annual load by the end of 2024 and 100% by the end of 2029. Municipal retail electricity providers and a provider serving a single customer at 115 kV have until the end of 2034.
Scott offered his opinion of the measure right in the headline of a Feb. 27 news release, referring to it as the “Potential Billion Dollar Rate Hike Bill.”
He said: “There is clearly a more affordable and equitable alternative to H.289. We can and should do better.”
Scott said the Public Service Department conducted an 18-month public engagement process to produce a proposed bill providing better progress toward the state’s mandated emissions reduction targets than H.289.
Legislators did not consider the department’s work as they drew up H.289, which carries a potential 10-year price tag of $1 billion, he said.
Both houses of the General Assembly passed the measure with more than the two-thirds majority needed to override a veto.
Environmental and clean-energy advocates hailed passage of H.289 and said it would slow climate change, a priority objective for many Vermonters.
The Vermont Natural Resources Council thanked legislators who pushed back against the “fake narrative that a renewable energy future is too expensive.” It said H.289 would double the power produced within the borders of Vermont, which is 48th in the nation for percentage of power generated in-state.
The Sierra Club’s Vermont Chapter and Renewable Energy Vermont said the measure would double the amount of renewables Vermont utilities must build in-state to 20% of the electricity they deliver; add efficiency and lifecycle greenhouse gas metrics that limit the eligibility of new biomass plants to meet the new standards; prevent classification as a source of new renewable power any lands newly flooded in the future by Hydro Quebec; and phase out off-site or “virtual” net metering, a program to increase access to community solar.
In a news release, Lauren Hierl, executive director of Vermont Conservation Voters, said: “After the recent flooding and other climate disasters facing Vermont communities, it’s encouraging that Vermont is on the cusp of adopting one of the most ambitious renewable energy standards in the country. This bill is an important step in Vermont’s efforts to cut climate pollution and leave a better Vermont for future generations.”
The U.S. Department of Energy is looking to boost interregional transmission with its announcement May 8 of 10 proposed National Interest Electric Transmission Corridors (NIETCs), where projects could be eligible for a share of $2 billion in federal loans and special permitting under FERC’s backstop permitting authority.
DOE defines a NIETC as a geographic area where “it is determined that consumers are harmed, now or in the future, by a lack of transmission in the area and the development of new transmission would advance important national interests for that region, such as increased reliability and reduced consumer costs.”
But beyond those findings, the department looked at factors such as reliability, resilience, congestion, consumer costs and future generation demand growth, “which is a very important issue right now,” the official said. “And for some of these also, we’re looking at what ultimately unlocks clean energy and allows for clean energy resources to interconnect to the grid.”
Energy Secretary Jennifer Granholm said the preliminary list includes areas that are high priority for more transmission buildout. “This program is going to help us build out transmission capacity quickly and efficiently for the people who need it most without compromising on the quality of environmental reviews or community outreach.”
The list includes corridors as narrow as 0.3 miles across and as wide as 345 miles east to west, for example:
the New York-New Jersey corridor, 4 miles wide and 12 miles long, providing an interregional connection between PJM and NYISO, as well as interconnection points for offshore wind projects;
the Plains Southwest corridor, running 345 miles east to west and 220 miles north to south, covering portions of Kansas, New Mexico, Oklahoma and Texas; and
the Mountain-Northwest corridor, 0.3 miles wide and 515 miles long, running from Oregon to Nevada.
Some corridors also stretch over multiple parallel or adjacent sections, such as the Mid-Atlantic corridor, covering parts of Maryland, Pennsylvania, Virginia and West Virginia with parallel lines 2 miles across and up to 180 miles long.
These and the other corridors on the list all have one or more potential transmission projects under development, which a NIETC designation could help accelerate, according to the DOE announcement.
Other considerations include co-location with an existing highway or transmission right-of-way, and the potential to get more renewable energy online and increase transmission capacity between the Eastern and Western interconnections. The longest potential NIETC, the Midwest-Plains corridor, runs 780 miles, beginning in Kansas, crossing Missouri and Illinois and ending in Indiana.
The proposed corridors on the list could be reconfigured through further public and industry input, DOE officials said. But projects located within any NIETC corridor are eligible for federal loans drawn from a $2 billion fund set up by the Inflation Reduction Act.
NIETC projects also could be eligible for permitting through FERC’s backstop authority, established in the Infrastructure Investment and Jobs Act, allowing the commission to permit projects in a corridor if state regulators don’t have permitting authority or have delayed project approvals.
FERC has yet to decide if and how it might use the backstop permitting option, but the issue is on the commission’s agenda for May 13, when it is expected to vote on its long-awaited transmission planning and cost allocation rule.
The senior DOE official stressed that the NIETC designation process is separate from any FERC decision on its backstop permitting authority but said the backstop authority can only be used for a project in a NIETC.
‘A Few Backyards’
The NIETC announcement was the latest in a string of initiatives DOE has rolled out in recent weeks expanding transmission capacity across the country and streamlining the permitting process. On April 25, DOE launched its Coordinated Interagency Authorizations and Permits (CITAP) program, which is intended to cut environmental permitting time for transmission projects to two years.
Even more strategically, the release of the preliminary NIETC list comes less than a week before FERC is scheduled to vote on its long-awaited transmission planning rule, which administration officials again stressed is separate from the NIETC program, which may not be directly affected by the decision.
“We’re looking forward to a rule that will … give people certainty and stronger tools to make sure these projects get built,” John Podesta, White House senior adviser on international climate policy, said at the May 7 briefing. “[FERC] will at the end of the day render their judgment about how far to go in that regard, but I think it’s another important step to ensure we have the ability to cut through the red tape.”
The need for an acceleration of transmission planning and permitting remains pressing. About 2.6 GW of projects, mostly solar, wind and energy storage, are sitting in RTO and ISO interconnection queues across the country, according to Lawrence Berkeley National Laboratory’s 2024 Queued Up report.
To meet President Joe Biden’s 100% clean power goals by 2035, “we need to more than double our current transmission capacity,” Podesta said. “The truth is, if we can’t build critical clean energy projects through a few backyards, then no one will have a backyard.”
The May 8 announcement marks the beginning of the second of four phases of NIETC designation as outlined in the guidelines DOE issued in December. In the first phase, which ran from mid-December to early February, DOE gathered input from stakeholders.
The release of the preliminary list kicks off a 45-day comment period, which will run through June 24. Phases 3 and 4 will include a due diligence process and environmental reviews under the National Environmental Policy Act, which could take up to two years.
DOE has yet to state how many NIETCs may be on the final list or when it will be released.
Nearly 5.6 GW of new solar, wind and storage capacity was added in the U.S. in the first quarter of 2024, the American Clean Power Association reported.
The clean energy trade group said May 7 that capacity additions in the first quarter of 2024 were 28% higher than in the same period in 2023, putting utility-scale solar power installations over the 100-GW mark for the first time. It took 18 years to reach 50 GW of installed utility-scale solar but only four years to jump from 50 to 100, noted John Hensley, ACP’s vice president of markets and policy analysis.
“Given current trends and expectations, [we expect] that the next doubling will come in a relatively short time,” he said at a news conference.
At the close of the first quarter, installed clean power capacity stood at 269.88 GW nationwide, ACP said. The pipeline of projects under construction or in advanced development nationwide reached 174 GW, up 2% from the fourth quarter of 2023 and 23% from the first quarter of 2023.
Offtake mechanisms for clean energy projects under development | ACP
“So 2023 was already a great year, but we’re already off to an even better year here in 2024,” Hensley said. “Just to give you some sense, those 5.6 GW of projects that came online this year are about enough to power a million American homes.”
The projects ACP considers “in the pipeline” are either under construction or far along in the preconstruction process, he said. There are supply chain challenges, trade and tariff issues, and crowded interconnection queues, but “I will say that for the first time in quite a while, as we’ve looked at project delays, we’re starting to see that number slow pretty significantly,” Hensley said. “I mean, we were generally adding 10 [GW to] 15 GW of delays a quarter. We had 7 GW of delays in Q1 2024.”
As of the first quarter, ACP counts 151 GW of onshore wind, 101 GW of solar and 18 GW of storage operational nationwide.
In response to a reporter’s question, Hensley said the political situation in the U.S. introduces some uncertainty, but the industry is in a sound position: Customer demand for clean energy is increasing, technology costs are easing, and the economic benefits are spread across red and blue states.
“It may be kind of strange to concede that 80-plus percent of our projects are actually taking place in more conservative parts of the country,” Hensley added.
So much of what is being built is solar, which has a lower capacity factor than wind or fossil fuel-burning generation and needs more of a backstop. Wind was first to market, about a decade ahead of large-scale solar, Hensley noted, and there has been some balancing of wind-dominant generation portfolios. ACP expects to see developer interest in wind start to rebound in 2025 and beyond.
First-quarter additions and cumulative growth of U.S. clean energy capacity | ACP
“And again, let’s not forget about storage, we built close to 8 GW last year, another 8 to 10 this year,” Hensley added. “It’s starting to proliferate, and in more markets than just California and Texas. … We’re not quite there yet on that balanced mix, but I think that’s the direction that we see things go.”
By the Numbers
Datapoints from the report include:
4,557 MW of utility-scale solar came online in the first quarter of 2024; onshore wind and storage totaled about 450 MW each.
132 MW came online from South Fork Wind, the first major infusion of offshore wind in the nation.
NextEra Energy was the leading clean-power developer in the first quarter; its 1,829 MW of solar, 449 MW of onshore wind and 50 MW of battery storage made up 41% of the national total.
The nationwide development pipeline reached 94,462 MW of utility-scale solar in the first quarter, up from 81,509 a year earlier; 25,321 MW of onshore wind, up from 20,176; and 31,627 MW of batteries, up from 19,621.
66,959 MW of clean power capacity is now operational in Texas, the most of any state; California is second, at 35,002 MW, and Iowa is third, at 13,486.
1,964 MW of clean power came online in the first quarter in Texas, the most of any state; Florida was second, at 1,789 MW, and California was third, at 293 MW.
Texas led the U.S. in capacity under active construction in the first quarter, with 18,950 MW; New York led in capacity in advanced development stages, at 13,850 MW, though 4,000 MW of offshore wind fell out of its pipeline early in the second quarter.
Developers reported a cumulative 62 GW of clean power projects as “delayed” in the first quarter and expect a little less than half of that — 29.8 GW — to become operational by the end of this year.
7,773 MW of power purchase agreements were announced in the first quarter, 52% more than in the same quarter of 2023. Utilities were responsible for most of the increase, but corporate PPAs increased as well: Microsoft alone announced 1.4 GW of new PPAs, and Meta, Amazon and UnitedHealth Group also reached sizable PPAs.
Ameren executives have reassured shareholders that Missouri’s capacity shortfall beginning this summer is no cause for panic.
Speaking May 3 on a first-quarter earnings call, CFO Michael Moehn said he doesn’t expect Missouri ratepayers to see “material” bill impacts from MISO’s capacity auction. The utility also doesn’t expect to encounter “any issues with providing reliable electric service throughout the year for our customers,” he said.
MISO’s recent capacity auction returned insufficient capacity for the upcoming fall and spring 2025 in Missouri’s Zone 5, where capacity prices hit the $719.81/MW-day limit on par with building new generation.
Moehn said the cost of new entry prices in MISO Zone 5 are a function of “higher load requirements, changes to the accredited capacity of generation available and reduced import capability.”
He said auction results indicate that Ameren Missouri needs to redouble efforts to “execute the generation plans” laid out in its integrated resource planning. The pairing of new, large loads with new renewable generation means that significant transmission expansion is more necessary than ever to maintain reliability, he said.
“We stand ready to work with stakeholders in our region to address the capacity needs,” Moehn said. He added that the Ameren Illinois and Ameren Missouri service territories are on track to experience mounting load growth, with new projects proposed from the automotive, aerospace manufacturing, data center and agricultural industries.
Ameren’s retiring Rush Island Energy Center — which played a role in the Zone 5 capacity shortfall — also factored into the utility’s earnings picture for the first quarter.
Ameren announced first-quarter earnings of $261 million ($0.98/share) compared to $264 million ($1/share) a year ago. CEO Marty Lyons said unseasonably warm conditions in February and March reduced profits, as did expenses related to mitigation relief stemming from Rush Island’s unresolved air pollution case.
“Despite the year-to-date weather headwinds and the Rush Island charge, our team is taking steps to contain spending, and we remain on track to deliver within our 2024 earnings guidance range of $4.52 per share to $4.72 per share,” Lyons said.
For the rest of 2024, Ameren will implement hiring restrictions, reduce its contractor and consultant workforce and cut back on discretionary spending, Moehn said.
Coal Woes
The company recently filed a plan with the U.S. District Court of Eastern Missouri to remediate 14 years of unlawful air pollution from Rush Island. The $20 million plan involves a surrender of the plant’s sulfur dioxide allowances under EPA’s cap-and-trade program, distributing air filters to disadvantaged households downwind of the pollution and an offer to purchase 20 electric school buses and 40 charging stations for the St. Louis area.
Ameren expects evidentiary hearings on the matter this summer and the court’s decision by the end of the year.
“When you look at the components of the two programs, they are very similar in terms of electric school buses, air filtration program, charging infrastructure. … It really is seemingly not a matter of the program mix, but sort of the extent of them and the cost of them. So, we can’t predict what mitigation the court would ultimately order,” Lyons said.
He added that any penalty will be “nonrecurring and onetime and won’t be something that affects ongoing operations or earnings.”
The district court last year ordered Rush Island to shut down no later than Oct. 15. Ameren opted to close the plant rather than spend several million dollars to install a flue gas desulfurization system to scrub excess emissions. The Justice Department and Ameren have been at an impasse for two years over how to remediate Rush Island’s longstanding environmental harms beyond the plant’s early retirement.
Lyons said Ameren is progressing on its request with the Missouri Public Service Commission to securitize the remaining balance of Rush Island, noting that PSC staff in March recommended the company be allowed to securitize $497 million instead of an original request for $519 million. The PSC is expected to issue a ruling in late June.
Lyons cautioned that another Ameren Missouri coal plant, the Labadie Energy Center, faces an uncertain future. While units at the plant aren’t slated to retire until 2036 and 2042, they are vulnerable to EPA’s new rule stipulating that coal plants either close by 2039 or use carbon capture or other technologies to capture 90% of their emissions by 2032. (See EPA Power Plant Rules Squeeze Coal Plants; Existing Gas Plants Exempt.)
Lyons said EPA “expects generators to rely heavily on carbon capture and storage technologies, which are not ready for full-scale economy-wide deployment.” He added that the rule’s application to new gas-fired units with greater than 40% capacity factors will likely complicate Ameren’s plan to add a gas-fired combined cycle plant sometime in the early 2030s to maintain reliability. Litigation by stakeholders is likely, Lyons said.
“While we are still assessing the impact of the rules on our integrated resource plan, these new rules are making it more challenging and costly to maintain existing dispatchable generation or build new dispatchable generation. These challenges come at a time when supply and demand is tight, and the industry has seen significant potential load growth. … These rules, if not modified, would require significant investments beyond what’s in our current 10-year pipeline to meet compliance obligations and maintain a reliable system,” Lyons said.
Transmission Awards
Finally, Lyons called attention to MISO selecting Ameren to build three competitively bid projects from its first, $10 billion long-range transmission portfolio. (See MISO Chooses Ameren for 3rd Long-range Tx Project.) He said the awards provide evidence of the company’s “record of being able to deliver cost-effective, high-value projects to our communities.”
“Ultimately, Ameren was assigned or awarded approximately 25% of total Tranche 1 portfolio projects addressing the MISO Midwest region and 100% of the projects in our service territory,” Lyons said.
Lyons said he expects construction on the projects to “substantially begin in 2026.” He noted also that Ameren representatives have been collaborating with MISO planners in “ultimately approving the most appropriate path forward” on the approximately $20 billion in long-range transmission projects proposed in the RTO’s second portfolio.
In a recent report, a nuclear power expert from George Washington University strongly criticized proponents of nuclear power for presenting what she considered an overly rosy picture of the technology’s potential to meet the world’s energy needs while ignoring its many reliability and security challenges.
The author of “New Nuclear Energy: Assessing the National Security Risks,” Sharon Squassoni, is a research professor of international affairs at GWU whose work focuses on reducing risks from nuclear energy and weapons. In a webinar last month, Squassoni said her goal in writing the report was to explore “what risks might arise given the goals of tripling nuclear energy and deploying small modular reactors to do many things in many places.”
With increasing awareness of the climate effects of burning fossil fuels, some energy experts have touted nuclear energy as a proven technology for meeting baseload energy needs without emitting carbon dioxide and other pollutants. SMRs have emerged as the centerpiece of “an effort to make nuclear energy more affordable, safe and flexible, and thus more attractive to a broader range of uses and users,” the report said.
However, the document pointed out that despite much effort from the nuclear industry and governments “to make nuclear energy relevant again after decades of stagnation,” the actual presence of SMRs on grids “is largely fictional.”
While nuclear boosters have held out visions of cheaply built, moveable reactors powering individual towns and military installations while providing numerous other services, Squassoni said there are currently only two operating facilities that actually merit the SMR label. These reactors — China’s HTR-PM plant, in operation since December 2023, and Russia’s “floating nuclear power plant” Akademik Lomonosov, launched in 2010 — solve few of traditional nuclear plants’ problems and may create new ones, according to the report.
The HTR-PM uses two reactors with a capacity of 100 MWe each, using a “pebble-bed” design incorporating spherical balls of uranium enriched to 8.5% U-235 (compared to the 3 to 5% enrichment typically used in commercial U.S. reactors). It was launched in 2001, based on an existing test reactor, with on-site construction beginning in 2012.
The report noted that the higher enrichment of the reactor’s fuel could make it more attractive for use in a nuclear weapon, while the fuel fabrication, storage of spent fuel and reprocessing “will be more challenging to monitor” than in current reactors. In addition, safeguarding the reactor could be more challenging because it uses on-line refueling, a more complicated process than shutting down the reactor first, and because the spent fuel is stored on site.
Akademik Lomonosov comprises two reactors with a capacity of 35 MWe each and was intended to replace a retired nuclear plant and coal plant in the Chukotka region of eastern Russia. The report noted that placing nuclear plants on a barge does solve the issues of “scarce land for nuclear power plants that require large emergency planning zones,” but the design is far from flawless. Planners must consider the risks of shipping collisions and tsunamis, along with the potential environmental damage of fuel and waste leaks.
Floating plants are also “open to attack either from the surface of the sea or beneath it,” the report said. Pirates and terrorist groups could infiltrate the facilities to steal radioactive material or threaten to damage the plants for financial or political gain.
Additionally, the report warned that “SMRs are unlikely to be built in quantities that will revolutionize nuclear energy” because focusing on large amounts of small reactors means giving up the economies of scale that come with building a single large, centralized plant. The report cited analysis from Princeton University suggesting “700 [small] plants would need to be produced” to outweigh the benefits of large plants, noting that “this is roughly the total number of commercial nuclear … reactors ever built.”
Side Benefits Slow to Emerge
SMR supporters have also proposed that small reactors could provide additional benefits besides electricity, such as residential and industrial heating, desalination, and hydrogen production. The report said that these uses are “neither new nor unique to nuclear energy,” and Squassoni suggested that they would likely not be mentioned if alternatives to nuclear generation for electricity had not recently become available.
“In the past, maybe 10 to 15 years ago, the nuclear power narrative was that nuclear was the only low-carbon baseload generation,” Squassoni said during the webinar. “But what’s happened in the interim is that [renewable energy sources] have captured such a huge part of the market for electricity generation that nuclear now has to tout its ability to multitask.”
This multitasking ability has been touted by the U.S. Department of Energy, and the Electric Power Research Institute floated its NuIDEA plan last year that would see multiple microreactors operate at airports, college campuses, hospitals and other facilities to provide a range of services. But the GWU report said efforts to realize these ambitions will “likely be an uphill climb,” noting that in the U.S., only the Diablo Canyon reactor in California has provided desalination, and none has ever provided district heating.
“Although there are more than 660 district energy systems operating in the United States, few present the right economics for large nuclear cogeneration plants,” the report said. “Smaller plants sprinkled among population centers might overcome the costs of heat transportation, but technical issues like the availability of large dual-purpose turbines to produce electricity and extract steam at suitable temperatures and pressures may continue to persist.”
Military Risks Growing
Finally, the report warned about the possibility for SMRs to become military targets.
Russian forces have occupied both the Chernobyl and Zaporizhzhia power plants at different times since they invaded in 2022 and remain in control of Zaporizhzhia as of early May. The head of the International Atomic Energy Agency (IAEA) recently said that Russia’s “reckless attacks” have brought the danger of nuclear mishaps “dangerously close.” Such an event would have devastating consequences not only for grid reliability but also for the local environment.
“Cooperation among key states essential to minimize the safety, security and proliferation risks of nuclear energy is at an all-time low,” the report said. “The call to triple nuclear energy coincides with the disintegration of cooperation, the unraveling of norms and the loss of credibility of international institutions that are crucial to the safe and secure operation of nuclear power.”
The report called for the U.S., Russia and China to resume their cooperation in nuclear nonproliferation rather than allowing the current environment to spiral into “great power competition.”
“The United States still wields considerable influence in international fora associated with nuclear energy, nonproliferation and nuclear security, and it should use this influence to ensure that any expansion of nuclear energy does not exacerbate national security risks,” the report said. “But first, it will need to get its own policy house in order.”
Pushback from Nuclear Community
Several nuclear experts who spoke to RTO Insider criticized the report, saying it overstated the risks of SMRs without considering the efforts of the international community to address them.
Madeline Lockhart, a doctoral fellow in nuclear engineering at North Carolina State University, acknowledged that growing the nuclear fleet “will naturally lead to an increase in the associated nuclear security risks.” But she argued that the report’s characterization of these dangers is “not well defined,” and that policies should address the risks connected to “specific capabilities, facilities, designs, locations and countries” rather than taking an overly broad view.
“Government organizations, National Laboratories and stakeholders are actively engaged with reactor vendors and buyers to address and minimize national security risks before any reactor will be connected to the grid. Often, robust and complex regulations and guidelines contribute to the extended timelines for reactor deployment — but the goal is always the deployment of safe and reliable energy production,” Lockhart said. “While the national security risks must be addressed, the risk associated with the failure to meet a growing global demand for electricity will be devastating.”
Mehdi Sarram, who served as safeguards director of the Atomic Energy Organization of Iran from 1974 to 1979 and later served in DOE and the IAEA, called the report “biased toward a negative view of nuclear energy.” He disputed Squassoni’s claim about the vulnerability of Chernobyl and Zaporizhzhia, saying that the IAEA “has worked with Russia to avoid a possible attack on Ukrainian nuclear plants.”
The report also discounts the boost that technological advances bring to nonproliferation work, according to Angela Di Fulvio, associate professor of nuclear, plasma and radiological engineering at the University of Illinois Urbana-Champaign. Di Fulvio noted that advances in radiation detection systems and other technologies helped the IAEA track the development of China’s nuclear weapons capabilities.
With regard to SMRs, Di Fulvio admitted that deploying such resources may require “a paradigm shift in material accountancy” and close collaboration between designers and the IAEA to develop proper safeguards against diversion of nuclear material, particularly in regions of political instability. But she insisted that these risks “can be mitigated effectively” and should not prevent the deployment of needed energy resources.
Paul Dickman, chair of the American Nuclear Society’s External Affairs Committee and formerly with DOE’s National Nuclear Security Administration, focused on the challenge of building large fleets of SMRs, noting that the U.S. lacks manufacturing capacity to produce reactor components on a large scale. He said that rather than looking to SMRs to replace large plants as baseload energy suppliers, they should be used to “fill in gaps where grids are small or to replace smaller coal and oil-based generating stations.”
The biggest obstacle to New Jersey’s adoption of clean energy is the state’s inadequate grid and a reluctance to make the kind of investments needed for the grid to handle a surge in solar and wind power, a state senator said at a clean energy conference.
Sen. Bob Smith (D), chairman of the Senate Environment and Energy Committee, which initiates much of the state’s clean energy legislation, said that despite New Jersey’s aggressive agenda, the state is far short of creating a grid that can accept numerous clean energy connections.
Smith spoke at the Clean and Sustainable Energy Summit 2024 on May 2 at Montclair University. Transmission issues were prominent, but some speakers differed with Smith’s analysis, praising initiatives such as the state’s aggressive solicitation of projects to develop onshore and offshore transmission links to connect offshore wind (OSW) projects with the grid.
Smith said his committee got some “relatively modest” climate change initiatives passed but has struggled with major initiatives to prepare the grid for the task of handling the state’s shift to an energy system focused almost entirely on electricity.
“We’re in trouble, and we’re not moving fast enough to solve the problem,” said Smith, the conference’s morning keynote speaker. He called for a “wartime mobilization for global climate change.”
“We have this 19th-century view that you should not spend an extra one-tenth of a cent in trying to upgrade your grid,” he said. The attitude is “build what you basically need and maybe only for the short term. We don’t have long-term thinking, either at the federal level, FERC, or the regional entity PJM or in New Jersey. So we now have a grid that is held together by duct tape, and not very good duct tape.”
Smith noted that Gov. Phil Murphy (D) marked Earth Week by citing his administration’s clean energy initiatives, including the allocation in his 2024/25 budget of $40 million for grid upgrades, to use a federal match. But Smith called it “literal spit in the bucket of what we need to do to make our grid work.”
In an interview with NetZero Insider after his speech, Smith said he’s uncertain whether a bill he co-sponsored, S258, which would allocate $300 million to grid upgrades to use $200 million more in federal funds, will advance in the near future. Introduced in January, the bill in March passed out of the Senate Environment and Energy Committee but has yet to move in the Senate Budget and Appropriations Committee or the Assembly.
Smith said educating legislators is not too dissimilar from educating the citizenry, in the sense they often get motivated only by a hurricane, flood or other crisis.
“People have to understand how serious this is,” he said. “We have got to get their attention.”
Marian Abdou, a commissioner of the New Jersey Board of Public Utilities (BPU), was more measured in her assessment of the state’s position. She said that “with an increase in demand for electricity and expanding our renewable energy resources, we need to ensure the grid can handle this influx.”
Standing in for BPU President Christine Guhl-Sadovy, who was unable to attend, Abdou noted the board on April 30 approved a package of grid modernization rules that could help streamline the interconnection process.
“Stable infrastructure is a critical piece of building a clean energy future, and for New Jersey, it centers on modernizing our electric grid,” she said.
Balancing New and Declining Energy Sources
Matthew Bernstein, senior policy advisory, governmental services at PJM, addressing a panel on energy security, said the RTO faces a series of the challenges but already has recognized, and responded to, the need for “proactive transmission planning,” and an improved connection process.
The RTO is working with stakeholders on a long-term framework that would allow it to get ahead of anticipated generator deactivations and load growth and focus beyond a “five-year regional transmission expansion planning process,” he said.
The RTO is addressing the ongoing backlog of new projects awaiting connection through reforms that would allow the company to “expeditiously move these projects through the interconnection queue,” Bernstein said.
“We implemented stronger guardrails around speculative projects to show that the projects that are entering the queue really do have the potential to be built,” he said. “We’re already seeing a lot of projects make their way through the queue in a much more timely manner.”
By the middle of 2025, PJM expects to have studied and processed projects with a combined capacity of about 72,000 MW, he said. And over the next three years, all 230,000 MWs of proposed projects will be studied by PJM and the response delivered to their developers, he added. Still, about 40,000 MW of generation that was passed out of the PJM connection process has not been developed due to obstacles such as supply chain issues, inflation and financial pressures, he said.
PJM electricity demand growth | PJM
The RTO also is working to balance the retirement and closure of fossil fuel generators with the arrival of clean energy generators, to create a steady power flow that matches demand, Bernstein said. Load growth has increased dramatically, driven by “significant electrification of the transportation sector, heating equipment and other dwelling units, as well as the proliferation of data centers throughout the region.”
In its annual forecast, PJM predicted from 2014 to 2024 that load growth would decline slightly, Bernstein said. But the RTO this year predicted summer peak load will grow by about 1.7%. That dynamic has raised questions about whether the RTO has “sufficient generation available to meet our demand today, and in the future, not just the actual demand, but also have sufficient reserves in place for contingencies,” Bernstein said.
“If the load continues to grow at the rate that we are expecting, and we are seeing resources retire, this will become a problem,” he said “It’s not a problem that we’re seeing this moment today. But over the coming decade, this will become a problem if these (new) resources aren’t coming into the system in a timely manner.”
Linking OSW to the Grid
Damian Bednarz, managing director for Attentive Energy Two, which is developing a 1,342-MW OSW project off the Jersey Shore, agreed with Smith that long-term planning will be “critical” to the sector. The state has shown foresight in its “prebuild” solicitation seeking proposals for transmission infrastructure that will link OSW projects with the grid on land, Bednarz said.
If completed, Attentive Energy Two and a second project, Leading Light Wind, together would bring about 3,742 MW of capacity through Sea Girt, in Monmouth County. The projects would connect to the grid at the Larrabee Collector Station, an entry gateway the BPU instigated in a solicitation held under the FERC State Agreement Approach.
Bednarz, referring to Smith’s comment that the state needs a “wartime mobilization,” said he believes “offshore wind is that counterattack.” He added that “if we’re going to have a counterattack in this effort to combat climate change, it takes a deep level of investment into not just the generation, but all aspects, to make this reality.”
Attentive Energy was the developer of one of three projects canceled by the New York State Energy Research and Development Authority (NYSERDA) after they had been approved in the state’s third solicitation, on Nov. 17. NYSERDA said the designated developers could not finalize their agreements due to changes in several factors, in particular a decision by GE Vernova to halt development of an 18-MW variant of its Haliade-X turbine and to remain making smaller, less efficient turbines.
Bednarz called the cancellations “incredibly frustrating” for many stakeholders, but he said the sudden, dramatic project meltdowns may be dissipating. Attentive Energy’s New York project suffered from the change in technology due to GE Vernova’s decision, rather than routine supply chain price hikes, he said.
“You also have a lot of states looking at the solicitations differently, I think, through some hard trial and error,” he said. “In key aspects of the solicitations, you have an inflation adjuster additive that could potentially push back on some of the supply chain risks, and then increased costs that can vary being factored in.“
“And I believe New Jersey, going forward, as well is going to have a lot of those things built into solicitations that prevent some of that increase in costs,” he said.
FERC on May 6 granted NYISO’s waiver request to update its installed capacity requirement for New York City in the 2024/25 capability year, which began May 1 (ER24-1800).
The amount of capacity the market is set to procure for Zone J (i.e., the city) was off because NYISO originally used the wrong historical data to calculate the transmission security limit (TSL) floor for the zone, from 2017-2021 instead of 2018-2022. The TSL floor is an input for the locational capacity requirement (LCR) and essentially acts as the minimum LCR.
The correct inputs lead to a TSL floor value (and LCR) of 80.4% instead of 81.7%. NYISO told FERC in its request that the waiver would save load-serving entities in the city about $15 million to $20 million per month in capacity costs.
NYISO discovered the issue late and only filed its request on April 18, but it immediately reported the issue to FERC’s Office of Enforcement and the ISO’s Market Monitoring Unit, Potomac Economics, on April 10, as required by its tariff. The grid operator said it acted swiftly to analyze the error and determine its impact and potential remedial impacts. It is also trying to understand how it happened and avoid it going forward, it said.
The waiver is the narrowest feasible solution to the problem created by the error, NYISO said. Only Zone J needs to be fixed, and the correction would not cause any reliability issues or changes to the reserve margin set for the New York Control Area.
The waiver also addresses a concrete problem by avoiding overcharging consumers in New York City, and it would not have undesirable consequences, such as harming third parties, the ISO said.
“NYISO argues that although the correction may result in lower capacity prices in Load Zone J, which may be contrary to the economic interests of some market participants, no stakeholder has a legitimate interest in preventing an error from being corrected for that reason,” FERC said. “NYISO asserts that all market participants will benefit from capacity auction prices that accurately reflect NYISO’s methodology for computing transmission security limit floor values for LCRs.”
The LCR is also the basis for several downstream processes related to the capacity market, such as the determination of capacity accreditation factors and the availability of capacity import rights, but NYISO said it did not need to fix those issues yet because the financial impacts of doing so would be limited. However, the ISO said it would continue to work with stakeholders to assess the feasibility, implications, timelines and required actions to pursue any corrective actions going forward.
The Independent Power Producers of New York and New York City both said NYISO should work expeditiously to complete the assessment of how other downstream parts of the capacity market might be impacted.
FERC found that the waiver request met its requirements, including solving the concrete problem of avoiding overcharging for capacity.
While some parties argued for additional requirements that NYISO fully address the downstream impacts of its error, FERC said such arguments were beyond the scope of the proceeding. The commission encouraged NYISO to expeditiously complete its assessment of the error’s impact and continue working with stakeholders on a solution.
The Public Service Commission of Wisconsin said it’s missing several details from We Energies regarding its multiyear plan to substitute gas for coal at its Oak Creek Power Plant south of Milwaukee.
In a May 3 letter, the commission said it and the Wisconsin Department of Natural Resources reviewed We Energies’ application for a certificate of public convenience and necessity to build the gas plant and deemed it incomplete. The PSC told the utility it could not make a decision and to re-file an application including the overlooked specifics (6630-CE-317).
We Energies intends to retire two of its 60-year-old Oak Creek coal units this month and the remaining two units by December 2025. It has requested to replace the capacity on-site with $1.4 billion in five gas-fired combustion turbines that would generate up to 1.1 GW. The utility applied for the certificate at the beginning of April and expected to have commission approval this month.
The Wisconsin PSC compiled a three-and-a-half-page list of missing or incomplete elements in the application. The agency asked for modeling data supporting the case for the plant, drawings of proposed and alternate layouts, an estimated maintenance schedule, a description of all major construction activities and a breakdown of capital costs. The commission asked We Energies to detail how hydrogen “may be used for any potential future fueling of the proposed combustion turbines.”
The agency also zeroed in on how the plant could be affected if the utility’s proposed, 33-mile Rochester Lateral gas pipeline is rejected, and asked how the pipeline stands to affect the plant’s construction schedule. We Energies filed for permission to build the pipeline — which would supply firm natural gas service to Oak Creek — on the same day it requested commission approval to the build the plant.
The PSC asked We Energies to calculate the amount of firm natural gas supply needed to run all five turbines continuously at maximum output and asked if its proposed upgrades to its natural gas infrastructure — alongside ANR Pipeline Co.’s planned capacity expansion in the area by late 2027 — would be enough to support those kinds of operations. It also asked how much a proposed, on-site liquified natural gas storage tank would hold and how long the tank could support the new turbines running at full speed.
The commission said it wanted to know if We Energies anticipates or has factored in additional costs to convert the Oak Creek substation since the new gas plant must connect to the MISO system at different voltages than the existing coal plant. Transmission owner American Transmission Co. is phasing out its 230-kV system in the area and will use only 138-kV and 345-kV voltages, affecting Oak Creek’s point of interconnection.
The PSC asked whether We Energies has contacted MISO to perform retirement studies to figure out if the system can operate reliably as the coal units cease production and after Oak Creek’s interconnection point is calibrated to different voltages. It said it wanted to know if powering down the four coal units can “proceed as planned without reliability concerns.” It also asked whether Oak Creek’s generator replacement studies consider only the two immediate coal unit retirements or all four of them.
Finally, the PSC said We Energies submitted an incomplete construction-noise study with its application.
In its application to build the plant, We Energies called Oak Creek’s shift to natural gas a “key component” in providing reliability amid its fleet transition, conforming to MISO’s stricter resource adequacy rules, meeting growing load and complying with proposed EPA requirements.
EPA issued a final rule May 6 meant to strengthen, expand and update methane emissions reporting requirements for oil and natural gas systems, as required by the Inflation Reduction Act.
Oil and natural gas facilities are the largest industrial source of methane, which is a stronger greenhouse gas than carbon dioxide — though shorter lived — and estimated to be responsible for about a third of the increase in global average temperatures.
The IRA’s Methane Emissions Reduction Program is meant to help states, industry and communities implement recently finalized standards under the Clean Air Act and slash emissions from the oil and gas sector. The Biden administration also is mobilizing $1 billion to accelerate the transition to no- and low-emitting oil and gas technologies as part of a broader effort to cut methane emissions.
“EPA is applying the latest tools, cutting-edge technology and expertise to track and measure methane emissions from the oil and gas industry,” EPA Administrator Michael Regan said in a statement. “Together, a combination of strong standards, good monitoring and reporting, and historic investments to cut methane pollution will ensure the U.S. leads in the global transition to a clean energy economy.”
EPA said studies have shown that actual emissions from the oil and gas industry are much greater than what they have reported to the agency. The new rule is meant to address that gap by making it easier to use satellite data to identify superemitters and quantify large emission events, and by requiring direct monitoring of key emission sources.
EPA also is finalizing new methods allowing empirical data for quantifying emissions to be used. The changes are meant to improve transparency and give owners and operators more options to submit empirical data to show their efforts to cut methane emissions.
The rule covers about 8,000 facilities around the U.S., which have to report their emissions data annually; EPA publishes the results every October. Owners and operators of oil and natural gas systems that emit 25,000 metric tons or more of equivalent carbon dioxide emissions annually are required to report their emissions.
Aaron Padilla, vice president of corporate policy for the American Petroleum Institute, said in a statement that the final rule raises serious concerns, including the use of “flawed methodologies” that could lead to inaccurate reporting of higher GHG emissions.
“We are reviewing the final rule and will work with Congress and the administration as we continue to reduce GHG emissions while producing the energy the world needs,” he said.
The Environmental Defense Fund, which launched its own satellite earlier this year to track methane emissions, welcomed the new rules.
“By directing EPA to update and strengthen methane emissions reporting, Congress recognized the vital importance of measurement-based, accurate and scientifically robust data to establish the true volume of pollution created by the oil and gas industry,” EDF Senior Scientist Daniel Zavala-Araiza said in a statement. “Updated methane reporting, along with continued integration of new measurement data, will allow us to better understand emission sources and mitigation opportunities and track changes in emissions over time.”
BALTIMORE, Md. — The PJM Members Committee on May 6 rejected endorsement of revisions to the RTO’s Operating Agreement and tariff shifting filing rights over the Regional Transmission Expansion Plan (RTEP) from the committee to the Board of Managers.
The language received 25% sector-weighted support during PJM’s Annual Meeting, held this year at the Baltimore Marriott Waterfront hotel.
The proposal was brought to the MC by the PJM Board of Managers in response to similar revisions to the Consolidated Transmission Owners Agreement (CTOA) brought to the Transmission Owners Agreement-Administrative Committee (TOA-AC). The TOA-AC also is set to consider revising the CTOA on May 14. Should the CTOA be modified, modifications to the PJM OA and Tariff would be necessary to avoid inconsistency.
The vote does not necessarily prohibit the board from unilaterally filing a proposal with FERC. PJM Director of Stakeholder Affairs Dave Anders said the board sought the input of stakeholders on the changes prior to considering whether to agree to any CTOA amendments that the TOA-AC may request.
During the April 25 Markets and Reliability Committee meeting, PJM General Counsel Chris O’Hara said the board has not ruled out making a Federal Power Act Section 206 filing asking FERC to grant it filing rights over the RTEP protocol if TOA-AC approves the CTOA revisions and the MC does not endorse the companion OA and Tariff revisions.
. At the Annual Meeting, board Chair Mark Takahashi stressed that no decisions had been made and that the board values the stakeholder process. There may be some cases, however, where the membership reaches a stalemate and the process cannot yield a solution to an issue that needs resolving, he said.
Several stakeholders argued they had only weeks to consider the changes, leaving insufficient time to vet the language for unintended consequences or to provide thoughtful comments.
Paul Sotkiewicz, president of E-cubed Policy Associates, said transferring the planning to the Tariff from the OA, in the context of the planning reforms in the table, would lead back to integrated resource plans.
Susan Bruce, of the PJM Industrial Customers Coalition, said the key difference with the RTO holding filing rights is that overriding an MC vote currently requires a filing under FPA Section 206, which must demonstrate that the existing governing document language is unjust and unreasonable.
“We strongly believe in the stakeholder process. The PJM stakeholder process has been important in balancing parties’ rights in this industry that has gone through a lot of transitions,” she said, adding that stakeholders have not had adequate time to think through the proposal.
LS Power’s Sharon Segner argued that any MC votes to amend the OA must immediately result in a FERC filing, but the drafted CTOA language includes a mediation process for any instances where a TO objects to an MC vote that it feels is contrary to the agreement. She said the interactions between that provision and the proposed OA and tariff language are not understood.
The status quo governing document language strikes a balance between granting TOs filing authority over local planning decisions, while PJM membership holds filing authority over regional planning.
Exelon’s Alex Stern said the PJM Members Committee is not a FERC jurisdictional public utility. It is a body created for consultation and does not have regional planning authority — that burden lies with PJM, which should hold final say over planning decisions. Stern asserted that “the Planning Protocol was directed to be placed in the OA by FERC nearly two decades ago to afford PJM independence. Unfortunately, as things have evolved, that intention has been thwarted to the point that people now actually incorrectly believe the Members Committee and not PJM has the regional planning authority.”
He said TOs, as PJM members, also are giving up stakeholder process veto rights over the planning protocols, but supporters of the CTOA revisions believe changes are needed to ensure reliability through the clean energy transition and to meet rising load, noting the growing reliability challenges facing PJM, highlighted by last week’s announcement that the summer outlook PJM presented to the Operating Committee on May 2 stated there’s a smaller generation pool available this summer than past years while forecast peak loads are increasing. (See related story, “PJM Confident on Summer Reserves; Stakeholders Concerned About Long Term,”PJM Operating Committee Briefs: May 2, 2024.)
