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December 24, 2024

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Biden Sets New US Emissions-reduction Target of 61-66% by 2035

As he prepares to leave office, President Joe Biden has submitted a new U.S. emissions-reduction target to the U.N., committing the country to cutting its greenhouse gas emissions economywide by 61 to 66% below 2005 levels by 2035.

Knowing that President-elect Donald Trump has pledged to pull the U.S. out of the Paris Agreement again, the Biden administration used the announcement of the new goal on Dec. 19 as a call to action for the states, cities and businesses that continued their efforts to reduce GHG emissions during Trump’s first term.

Biden rejoined the Paris Agreement on his first day in office in 2021. As he has throughout his four years in the White House, he linked action on climate change “to more good-paying jobs, more affordable energy, cleaner air, cleaner water [and] healthier environments for everyone.”

“It is also creating real momentum because we’re unleashing American ingenuity and innovation,” the president said in a statement. “American industry will keep inventing and keep investing. State local, and tribal governments will keep stepping up.”

White House Senior Adviser John Podesta was similarly “confident in America’s ability to rally around this new climate goal because, while the United States federal government may put climate action on the back burner, the work to contain climate change is going to continue in the United States with commitment and passion and belief.”

During a media briefing on Dec. 18, Podesta recalled the surge of subnational climate action that emerged in the wake of Trump’s first withdrawal from the Paris Agreement in 2017. One example was the formation of the U.S. Climate Alliance, a bipartisan coalition of 24 governors committed to enacting state policies to reach net-zero emissions economywide by 2050.

Following Biden’s announcement, the alliance committed its members to the new 2035 goal.

“President Biden’s bold leadership is keeping us on a path to achieve a clean energy economy, and together, the country’s climate-leading governors will carry the torch forward,” said New York Gov. Kathy Hochul (D), co-chair of the alliance. “This new collective goal will serve as our North Star, guiding us in the years to come and keeping America on track toward a cleaner, safer future.”

“The only thing clearer than the science and impacts of climate change is the benefit of taking action ― and we’re not slowing down,” agreed Hochul’s co-chair, New Mexico Gov. Michelle Lujan Grisham (D). “By continuing to stamp out climate pollution together, we’re safeguarding public health, protecting the environment, growing the economy and creating good jobs across the U.S.”

The White House said it will submit the new target to the U.N. Framework Convention on Climate Change secretariat as the U.S.’ nationally determined contribution (NDC) under the Paris Agreement. Signed by 196 nations in December 2015, the agreement commits the nations to cutting emissions to limit the increase in the global average temperature to 1.5 degrees Celsius.

As part of its NDC, the U.S. would also cut its methane emissions by 35% by 2035, which the White House said “is among the fastest ways to reduce near-term warming and is an essential complement to CO2 emissions.”

The White House noted “there are multiple paths to meeting these targets, and U.S. federal, state, local, territorial and tribal governments have numerous tools available to work with civil society and the private sector to mobilize investment in the years ahead.”

A recent study from the University of Maryland, College Park found that with a whole-of-society approach that includes “enhanced ambitions,” the U.S. could achieve a 65% reduction in emissions by 2035. But the report anticipated that without federal support, emission reductions of only 48 to 60% might be achieved, highlighting “the impact that non-federal actors can still have despite uncertainties at the federal level.”

The NDC itself has yet to be released, but the announcement raised questions about the current state of U.S. and global climate action following Trump’s election victory and the contentious 29th U.N. Climate Change Conference of the Parties (COP29) in Baku, Azerbaijan.

While advocates continue to talk about “keeping 1.5 alive,” global emissions and temperatures continue to rise. The National Oceanic and Atmospheric Administration has said 2024 has been the hottest year on record, with 2023 now in second place.

The U.N.’s 2024 Emissions Gap Report called for a global reduction in GHG emissions of 42% by 2030 and 57% by 2035 or “the Paris Agreement’s 1.5-C goal will be gone within a few years.”

Speaking on background, a senior administration official noted that the U.S. is currently on track to reduce its emissions 45% by 2030, falling short of the 50 to 52% target Biden set for the U.S. in his 2021 NDC. But the new NDC would confirm a U.S. commitment to the consensus reached in 2023 at COP28 on a “just, orderly and equitable” transition away from fossil fuels in this decade.

The final agreement at COP29 avoided any action on that consensus, but the official noted that the U.S. NDC acknowledges that the country could take multiple pathways to accelerate decarbonization across the economy, while continuing to increase private sector investments.

The White House also consulted with cities, states and tribes, integrating an analysis of their goals into the NDC, a second senior official said. Echoing Gov. Hochul, the official said the NDC is intended as an impetus to cities, states and others to raise their ambitions on climate policy and action.

The new NDC almost certainly will be quickly discounted by Trump and the Republicans who will control both houses of Congress in a matter of weeks, and much uncertainty surrounds the fate of Biden’s signature climate legislation, the Infrastructure Investment and Jobs Act and the Inflation Reduction Act.

Trump campaigned on a pledge to claw back unspent funds from the laws, and some congressional Republicans are already taking aim at specific provisions of the IRA, such as its $7,500 electric vehicle tax credits, to help pay for extending Trump’s 2017 tax cuts, which expire at the end of 2025.

At the same time, those laws have built “a complementary architecture of federal standards that spur demand and generate the regulatory certainty needed to accelerate capital formation and encourage entrepreneurial risk-taking. It is an important combination that has changed the equation” on climate action, National Climate Adviser Ali Zaidi said.

They have also channeled billions in federal dollars and private investment into Republican states and districts, a fact continually raised by Democrats hoping to defend the law’s tax credits and clean energy incentives.

The White House is stressing by-now familiar arguments that the U.S. clean energy transition has hit a tipping point, and its economic and technical momentum will continue, regardless of who’s in the Oval Office. As one of the senior officials said, what will likely change with Trump is the pace and the level of ambition.

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EPA Approves Waiver for California’s Advanced Clean Cars II Rules

Just weeks before President-elect Donald Trump returns to the White House, the Biden administration has given California permission to enforce rules that require all new cars sold in the state to be zero-emission by 2035. 

EPA on Dec. 18 approved a waiver for California’s Advanced Clean Cars II rules, which require an increasing percentage of cars sold in the state to be zero-emission each year until 2035, when all new cars sold must be ZEVs or plug-in hybrids. 

The agency also granted a waiver for California’s heavy-duty omnibus regulation, which sets emission standards for medium- and heavy-duty vehicles. 

Opponents have 60 days to file a petition for review of the decisions. 

“Today’s actions follow through on EPA’s commitment to partner with states to reduce emissions and act on the threat of climate change,” Administrator Michael Regan said in a statement. 

EPA’s decision also means the 11 other states that have adopted Advanced Clean Cars II (ACC II), along with D.C., can proceed with enforcement: Colorado, Delaware, Maryland, Massachusetts, New Jersey, New Mexico, New York, Oregon, Rhode Island, Vermont and Washington.  

The Environmental Defense Fund noted that ACC II jurisdictions account for 33% of the U.S. new vehicle market. 

“EPA’s approval of these standards for California and numerous other states is a welcome action to reduce pollution, including in communities where it’s most needed,” Alice Henderson, EDF director and lead counsel for transportation and clean air policy, said in a statement. 

The California Air Resources Board (CARB) adopted Advanced Clean Cars II in August 2022, updating its previous Advanced Clean Cars regulations. (See California Adopts Rule Banning Gas-powered Car Sales in 2035.) 

ACC II begins with model year 2026, when 35% of new cars delivered for sale in California must be zero-emission. 

In addition to ZEV-transition requirements, the ACC II regulation includes low-emission vehicle (LEV) rules that set emission standards for cars with internal-combustion engines. 

ZEV Progress

California officials celebrated EPA’s approval of the two waivers. 

“Clean cars are here to stay,” Gov. Gavin Newsom said in a statement. “Naysayers like President-elect Trump would prefer to side with the oil industry over consumers and American automakers, but California will continue fostering new innovations in the market.” 

Officials noted that through the end of September, 2.1 million zero-emission cars had been sold in California, and 26.4% of new light-duty vehicles sold in the state in the third quarter of 2024 were ZEVs. 

“Consumers and fleets are increasingly making the choice to drive clean vehicles, and today’s waiver approvals will further that progress,” CARB Chair Liane Randolph said. 

Still, the EPA waivers — and other state climate policies — may face challenges under the new presidential administration.

During Trump’s first term as president, California filed more than 120 lawsuits challenging actions taken by his administration.

In a special session of the state legislature that began Dec. 2, lawmakers will consider funding for the state Department of Justice to quickly challenge actions taken by the Trump administration. Newsom convened the special session “to safeguard California values” — including the fight against climate change. (See Newsom Convening Legislature to Protect California ‘Values,’ Policies.) 

One tool often used to overturn federal agency rules following a change in administration — the Congressional Review Act — doesn’t apply to approved California waivers, Newsom’s office recently told the Los Angeles Times. 

But EPA waivers for other CARB regulations are still pending. Those include waivers for the Advanced Clean Fleets regulation, which requires truck fleets to transition to zero-emission vehicles; the in-use locomotive standards, which ban certain diesel-powered locomotives; and emission standards for small off-road engines, such as those used in landscaping equipment. 

Newsom traveled to D.C. last month to push for federal approval of pending items, including the Clean Air Act waivers, ahead of the incoming administration. 

“EPA continues reviewing additional waiver requests from California and is working to ensure its decisions are durable and grounded by law,” the agency said in a Dec. 18 release. 

Waiver Review

Under the federal Clean Air Act, California may adopt its own vehicle emission standards, but those rules must receive federal approval in the form of a waiver from EPA. Other states may then choose to stick with federal standards or adopt California’s rules. 

The idea is to strike a balance in which car manufacturers don’t face myriad emission standards, while allowing California to innovate on its own standards to combat poor air quality. 

The California standards must be in aggregate at least as stringent as the applicable federal standards. In deciding whether to grant a waiver, EPA considers three “prongs,” Regan explained in his 191-page decision. The burden of proof is on opponents to show that one of the reasons for denial has been met.  

The first is whether California was arbitrary and capricious in determining that its standards are at least as protective of public health and welfare as the federal standards. 

The second prong addresses whether California needs the standards to meet compelling and extraordinary conditions. The third prong looks at whether the standards are consistent with a section of the Clean Air Act that pertains in part to the feasibility of technology in the lead time provided, taking cost into consideration. 

In his decision, Regan addressed many of the comments EPA received arguing for or against the ACC II waiver. Commenters brought up issues such as vehicle affordability, effects on the electric grid and availability of public charging. 

“Although commenters often referred to these topics to support their position that the ZEV standards either are or are not feasible … topics such as these are not within the scope of factors EPA may consider in evaluating consistency with [the Clean Air Act],” he wrote. 

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Oklo, Commonwealth Fusion Unveil Ambitious Nuclear Plans

Two companies developing advanced nuclear technology recently made landmark announcements about their plans. 

Advanced nuclear fission reactor designer Oklo and data center developer Switch said Dec. 18 they had struck a 12-GW power agreement through 2044, saying it was one of the largest corporate clean power agreements ever signed. 

Commonwealth Fusion Systems, which calls itself the largest private-sector company advancing nuclear fusion technology, announced Dec. 17 it would build the first grid-scale commercial fusion plant in the early 2030s. 

Before these plans become reality, this week’s announcements must of course be followed by successful technology development, regulatory approval, siting and permitting processes, favorable public opinion, financing and other milestones. 

Small modular reactors like those Oklo is developing are widely considered to be several years from market-ready, and the running joke about commercially viable nuclear fusion is that it has been only 20 years away for the last half-century. 

But both companies claim a robust list of achievements as they continue on the path to workable and scalable solutions. 

The Oklo-Switch master power agreement is a nonbinding strategic partnership, a framework for collaboration that is expected to yield binding agreements as project milestones are reached. It calls for Oklo to develop and operate power plants to feed Switch facilities across the U.S. through a series of power purchase agreements. 

The master agreement fits with Oklo’s business model of selling power rather than selling power plants. It could accelerate Oklo’s early deployments and position it to scale up to meet the anticipated growth of demand. 

The agreement also serves the priorities of Switch, which says its mission is to build sustainable infrastructure while bolstering the voluntary market for clean and renewable energy. Since January 2016, it has been powering all its data centers with 100% renewable power — nearly 1 billion kWh of it per year. 

Commonwealth’s plan includes a nonfinancial collaboration with Dominion Energy to provide development and technical expertise, as well as leasing rights to a proposed site near Richmond, Va., that is owned by the utility. 

Commonwealth said it conducted a global search for a location to site its first commercial fusion plant. The company plans to independently finance, build, own and operate the facility, which it calls ARC and is expected to be rated about 400 MW. 

If it comes together as planned, ARC is expected to draw significant attention, capital investment and workforce development to that part of Virginia. 

“This is an historic moment for Virginia and the world at large,” Gov. Glenn Youngkin (R) said in a news release. “Commonwealth Fusion Systems is not just building a facility; they are pioneering groundbreaking innovation to generate clean, reliable, safe power, and it’s happening right here in Virginia. We are proud to be home to this pursuit to change the future of energy and power.” 

Both Oklo and Commonwealth have attracted attention among the crowded fields in which SMRs and nuclear fusion are being developed. 

A rendering depicts the design for Oklo’s Aurora powerhouse. | Oklo

Oklo is advancing on multiple fronts with its design of advanced plants that run on nuclear waste. Earlier in 2024, it announced two agreements to supply a combined 850 MW of power to data centers, plus a letter of intent to supply 50 MW to a Permian Basin oil and gas producer. 

Commonwealth is developing SPARC, the fusion demonstration machine that it expects to first produce plasma in 2026. Soon after, it expects SPARC to produce net fusion energy as the first commercially relevant design to generate more power than it consumes. 

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MISO Closing in on New LMR Accreditation

CARMEL, Ind. — MISO said it will finalize an availability-based accreditation for nearly 12 GW of load-modifying resources (LMRs) over the first quarter of 2025 ahead of a filing with FERC.

Some stakeholders remain skeptical of MISO’s plans to rely on past performance levels to accredit LMRs by the 2028/29 planning year.

During a special Dec. 17 Resource Adequacy Subcommittee teleconference, MISO reiterated that it plans to split LMRs into two categories — those that can respond in 30 minutes or less and those that can’t — and accredit them correspondingly.

The RTO said its faster category would have a maximum response time of 30 minutes and presumed availability for all maximum generation emergency step two events.

On the other hand, the class of LMRs with slower response times would carry a maximum response time of six hours and would be readied earlier under tight conditions, when MISO declares a maximum generation warning. The RTO has long said it needs to be able to access LMRs before emergencies materialize.

MISO said the accreditation will extend to demand response resources participating in the capacity auction. Like the slower LMRs, demand response capacity resources would have a six-hour response requirement and must respond to at least one deployment per season if MISO issues instructions, with reduced accreditation for non-response.

Joshua Schabla, a MISO market design economist, said the RTO doesn’t expect to make major changes to the proposal in the coming months.

“The design is in a good spot. That’s not to mean it’s locked in, or we don’t expect a back and forth,” Schabla said. He added that MISO’s existing LMR accreditation is more than 15 years old and doesn’t reflect performance.

MISO has characterized the two classes of LMRs as “rapid” or “flexible.” However, some stakeholders have said it’s unrealistic to expect load reductions in 30 minutes or less, with many LMRs reasonably being able to respond within two hours. (See “New LMR Accreditation Looks Certain,” MISO Demand Response Under Increasing Scrutiny; IMM Warns of More Potential Schemes and MISO Tries to Win over Stakeholders on New LMR Capacity Accreditation.)

MISO said it will use backward-looking meter data from hours when capacity advisory declarations are in place to gauge availability and accredit resources.

The RTO plans to draw on data from a minimum of 65 historical hours per season over the past year, giving equal weighting to performance during low-margin hours and in hours where capacity advisories escalated into maximum generation events, alerts or warnings. That’s a change from fall, when MISO said it would apply a 20% weighting to low-margin hours and an 80% weighting to capacity advisories and above.

“It’s a very broad framework to capture a very broad set of resources,” Schabla said.

Multiple stakeholders said the accreditation plan still seems too complex and destined to produce unintended consequences.

“We’re seeing accreditation not aligned with what these resources are capable of,” Schabla said. “The stack of resources we can rely on is shrinking.”

Schabla said emergency resources can currently clear the capacity auction “without making themselves available.” MISO said real-time availability data indicates anywhere from 6 to 7 GW of capability from an estimated 9.5 GW participation level, which is “far less” than the auction’s cleared quantity of 12 GW of LMRs.

Schabla said the new accreditation will link availability with accreditation and will motivate demand response operators to give MISO accurate availability data.

MISO said it would also halt its practice of accepting LMRs’ self-conducted testing to verify performance.

Schabla said it’s clear that LMRs’ self-testing is not providing a “good indication” of what the resources can do. He said rolling out MISO-initiated testing will keep cheaper resources that cannot perform from crowding out genuine demand response in the capacity auction.

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MISO Assessment Calls for 17 GW in New Resources Annually

MISO said its members must add an “unprecedented” 17 GW in new resources annually over the next two decades to reliably meet demand and decarbonization goals.

That’s according to the RTO’s finalized Regional Resource Assessment for 2024, which draws on its members’ resource plans to quantify resource expansion needs on a 20-year outlook.

MISO’s Armando Figueroa Acevedo said a 17 GW/year rate would require members to add more than three times their recent average additions of 4.7 GW/year. If members can achieve the more than 340 GW in additions, MISO would boast 515 GW in total installed capacity by 2042.

“Achieving this pace will require several factors, including overcoming supply chain, permitting, labor and interconnection queue delays,” Figueroa Acevedo told stakeholders at a Dec. 18 teleconference to discuss results.

The numbers are in line with results in the draft assessment MISO released in November. (See MISO Prelim Regional Resource Assessment Calls for 343 GW by 2043.)

Members so far have planned to add 163 GW in installed capacity by 2043, less than half of what MISO says is necessary. The RTO filled in a simulated 180 GW of wind, solar and battery storage in its assessment to meet states’ and members’ pollution-cutting goals.

Despite record influxes of renewable energy, Figueroa Acevedo said MISO’s thermal resources are still poised to contribute “the bulk” of accredited capacity by 2043. At that time, MISO expects its lower-accredited wind and solar to account for 62% of installed capacity and have the potential to reach 87% of annual energy.

Between 2029 and 2043, MISO expects 27 GW in thermal retirements and 11 GW in thermal additions, leading to a net loss of 16 GW.

Figueroa Acevedo said MISO’s emerging reliance on solar power is pushing ramping needs from the morning to the evening and will double or triple its average one-hour ramping requirements by the early 2030s.

“A lot of the accredited capacity we see on the system is retained thermal generation and battery storage” entering the system, MISO Director of Strategic Initiatives and Assessments Jordan Bakke said.

WPPI Energy’s Steve Leovy said MISO should consider adding some long-duration energy storage in its modeling. Other stakeholders said the RTO seemed to underestimate how much storage can help improve reliability.

Bakke said the long-term assessment is meant to reflect members’ planning and said next year’s results could change depending on how many new resources members can scale over the next few years. He said the assessment is meant to “highlight the challenges of what we’re collectively trying to do across the footprint.”

MISO’s resource projections in the assessment began with 2029, skipping the next few years, where the RTO has said it could come up short on capacity.

America’s Power CEO Michelle Bloodworth said MISO should be focusing in particular on the next five years, given the heightened danger to reliability. Staff said the Regional Resource Assessment is intended to examine long-term needs while the annual resource adequacy survey conducted by MISO and the Organization of MISO States concentrates on near-term capacity sufficiency.

MISO fared the worst among all regions in NERC’s 2024 Long-Term Reliability Assessment, being the only region categorized as high risk, with NERC calling attention to possible shortfalls starting in 2025. MISO leadership has also raised the possibility of shortages within a few months and said it’s crucial for the grid operator to devise a fast lane in its interconnection queue for necessary generation projects. (See MISO Tells Board RA Fast Lane in Interconnection Queue is a Must.)

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ISO-NE to Work on State-backed RFP for Northern Maine Transmission

Backed by a new process conducted by the New England states, ISO-NE is moving forward with a request for proposals to build new transmission that would bring wind to market from Northern Maine.

The New England States Committee on Electricity presented its request at the ISO-NE Planning Advisory Committee’s meeting Dec. 18. The RTO plans to develop the RFP and release it by March.

“This is the first time that we’re using this process, and so we wanted to focus on investments that we have a high confidence in, that they’ll provide a lot of value for consumers; this concept of least-regrets transmission,” Jason Marshall, Massachusetts deputy secretary and special counsel for federal and regional energy affairs, said in an interview.

The RFP will be the first use of new rules FERC approved in July that allow states to identify a transmission need and then have the RTO run a solicitation to meet it. (See FERC Approves New Pathway for New England Transmission Projects.)

North-to-south transmission capacity in the region has been lacking, with Marshall saying it has limited the ability of generation to move to load centers to the south.

“As a result, resources have been really curtailed up there, and it’s limited our access to low-cost clean energy generation,” he added.

The RFP would also facilitate the interconnection of new wind resources, which have been held back by the lack of transmission to the resource-rich region, Marshall said.

“Strengthening the connections between northern and southern New England will enhance reliability and market efficiency by resolving known constraints on the transmission system and will also position the region to more efficiently integrate affordable resources in coming years,” NESCOE wrote in a memo to the RTO. “There is broad interest in addressing these longstanding system challenges, and strengthening the transmission system in Maine is a reasonable, measured first step toward the region’s needed transmission investment.”

The RFP targets increasing transfer capacity starting at a substation in Pittsfield, Maine — west of Bangor — and down through the southern part of the state into New Hampshire. Several parties asked in comments for the states to issue multiple RFPs based around the multiple needs for new transmission. (See ISO-NE Stakeholders Respond to Potential Long-term Transmission RFP.)

The states have been discussing the option for the multiple RFPs, and they also brought up that issue with the RTO, NESCOE’s Sheila Keane said at the PAC meeting.

“We understand that multiple RFPs could risk an unintended consequence of inefficient investment and extend the timeline for needed investment,” she added. “So, we certainly take that into mind in our final decision, and at this time, we accept that recommendation that a single, comprehensive RFP scope is the most efficient way forward.”

The tariff requires a complete solution for the needs identified, but Keane said the states are interested in maximizing competition in the process, and that could change in future RFPs.

The RFP is just one of several processes that could increase transmission from Northern Maine, where the grid is operated not by ISO-NE but by the Northern Maine Independent System Administrator and is connected to the Eastern Interconnection through New Brunswick.

The U.S. Department of Energy has offered an investment as an initial off-taker for a major line to the region. (See Long Road Still Ahead for Aroostook Transmission Project.)

The Maine Public Utilities Commission has opened a proceeding looking into better connections for the region, and Massachusetts has the authority to do out-of-state procurements for clean energy, Marshall said.

“I think we would view these activities as complementary,” he added. “They are different processes though, but again, at least for our state, we’re in an early phase.”

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Vistra Extends Baldwin Coal Plant Operations as MISO RA Risk Climbs

Vistra is extending the life of its coal-fired Baldwin Power Plant in Illinois through 2027 amid MISO delivering warnings over a supply crunch in its footprint.

The Irving, Texas-based company said Dec. 17 that it will keep the Baldwin plant running for an additional two years while still meeting EPA retirement and pond closure obligations. Vistra originally announced in 2020 that the 1,185-MW coal plant would close at the end of 2025.

The utility said the extension will buy the region some time to bring new generation online while helping to avoid a capacity shortfall.

“Vistra is committed to the responsible transition of our fleet in Illinois, and in this case, the most reasonable path forward is to continue to operate the plant as a reliable bridge to 2027, as we, and others, bring new generation assets online in the state,” CEO Jim Burke said in a press release. “As many organizations have recently raised concerns over reliability and resource adequacy in central and southern Illinois, we are taking action and delivering solutions that balance the needs of reliability, affordability and sustainability.”

The company has built a 68-MW solar farm and 2-MW/8-MWh energy storage facility at Baldwin; they began operations this month. It said its current coal-solar-storage setup at Baldwin “demonstrates the company’s commitment to evaluating how to best leverage the footprint, infrastructure and transmission connections already at the plant sites to meet the evolving electricity needs of customers.”

Vistra has planned on-site solar and storage at its other downstate coal plants as part of Illinois’ Coal to Solar and Energy Storage Initiative. It has completed a 44-MW solar and 2-MW/8-MWh storage facility at the Coffeen Power Plant and will begin construction of a 52-MW solar and 2-MW/8-MWh storage facility at the Newton Power Plant in 2025.

Vistra also noted it has begun construction on a 405-MW solar farm that will interconnect at its retired Joppa Power Plant.

MISO has said it could contend with a capacity shortfall as soon as the upcoming summer. (See OMS-MISO RA Survey: Potential 14-GW Capacity Deficit by Summer 2029.) While the RTO and the Organization of MISO States’ five-year resource adequacy survey this year did not show the potential for such an immediate shortfall in southern Illinois’ Zone 4, nearby Zone 5 in Missouri was flagged for substantial risk.

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BPA Touts Markets+ in Response to Seattle City Light Opposition

The potential benefits of a single West-wide market footprint must be viewed with “significant skepticism,” the Bonneville Power Administration’s top official told Seattle City Light in a letter reemphasizing the agency’s view that SPP’s Markets+ is preferable to CAISO’s Extended Day-ahead Market (EDAM).  

The letter from BPA Administrator John Hairston, posted by the agency Dec. 17, came in response to a Nov. 14 letter from City Light CEO Dawn Lindell that argued BPA is risking millions of dollars in economic benefits by favoring Markets+ over EDAM. 

Specifically, Lindell pointed to a BPA-commissioned study by Energy and Environmental Economics (E3) showing the agency could gain between $69 million and $221 million per year in economic benefits if it joined CAISO’s EDAM over Markets+. 

In his response, Hairston contended that City Light’s numbers are only accurate under a scenario in which there is only a single West-wide market rather than the more likely scenario that there will be multiple markets in the future. 

“The Western Interconnection appears certain to have multiple day-ahead markets as entities have signed implementation agreements and issued declarations (or intent) for specific day-ahead markets,” the letter stated. “The expected materialization of benefits under a single West-wide market footprint should be viewed with significant skepticism.” 

Hairston similarly shot down City Light’s contention that remaining in the Western Energy Imbalance Market (WEIM) and joining no day-ahead would produce greater benefits than joining Markets+.  

Many WEIM participants have already signed agreements to participate in either Markets+ or EDAM, meaning the benefits of WEIM will likely erode, according to Hairston. 

“As EIM entities move to the [EDAM] proposed by … [CAISO], there is no guarantee WEIM will continue to be offered as a standalone program, which is a risk to the potential benefits and long-term viability of a WEIM-only scenario for Bonneville,” the letter stated. 

The BPA administrator also touted the Markets+ requirement that its members participate in the Western Resource Adequacy Program (WRAP) to ensure system reliability. By contrast, EDAM’s proposal lacks a “common resource adequacy metric,” according to Hairston. 

“Without a market wide mandate for resource adequacy program participation, EDAM does not provide the same assurance for long term benefits of a resource adequacy program that is provided by Markets+,” the letter stated. 

Pathways Skepticism

However, BPA has repeatedly highlighted the governance issue as the main reason it favors SPP’s markets+. While Hairston noted the West-Wide Governance Pathways Initiative has made important strides toward improving EDAM’s governance structure, he argued that more work must be done to ensure that the market is independent of CAISO — and California — influence. 

Hairston singled out three areas of concern: the shared tariff under which EDAM and CAISO would operate, the CAISO board’s authority over market operations and other functions, and that CAISO would remain the counterparty in contracts with market participants, according to the letter. 

Additionally, it’s uncertain whether California lawmakers will provide the legislative support required to establish a “regional organization” and grant it power to set market policy for EDAM, Hairston wrote. 

“We appreciate Pathways Launch Committee’s optimism for a positive legislative outcome, but such efforts have repeatedly failed to secure the California Legislature’s approval,” Hairston wrote. “It also remains to be determined what legislative conditions and constraints may be introduced that would impede an independent governance structure.” 

Pathways supporters have said they foresee few challenges in passing the needed legislation during the 2025 session, given that the bill will be sponsored by the staunchest opponents of previous efforts to “regionalize” CAISO. 

In an email to RTO Insider, Seattle City Light — which operates its own balancing authority area and has signaled its intent to join EDAM despite BPA’s leaning — noted that in addition to the E3 study, a report by the Brattle Group showed the agency would realize $65 million in annual benefits in EDAM versus $83 million in losses in Markets+. 

“A two-market solution in the Pacific Northwest is simply not efficient,” City Light wrote. “Both the recent BPA E3 and PNCG/NIPPC/RNW Brattle studies confirm this assertion. 

City Light added that it agreed with concerns U.S. senators from Oregon and Washington expressed in a Dec. 13 letter to BPA asking the agency for more details justifying its leaning in favor of Markets+ and its decision to pay its $25 million share of the cost to fund the Phase 2 implementation stage of the market.  

The utility said “BPA’s continued leaning towards an inferior economic option is worrisome especially in light of their proposed 10% increase in power rates and nearly 30% rate increase in point-to-point transmission rates. According to the Brattle study, the impact of this decision will leave upwards of $430 million a year in benefits behind.” 

“We look forward to seeing a detailed and thorough response from BPA,” City Light said. 

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Cost Overruns on Project in 1st LRTP Prompt MISO Analysis

THE WOODLANDS, Texas — MISO will examine one of the long-range transmission projects from its first portfolio following a cost increase of more than two and a half.  

MISO announced that it will conduct a variance analysis on the planned 345-kV Morrison Ditch-Reynolds-Burr Oak-Leesburg-Hiple line in Illinois and Indiana, which has climbed from an estimated $261 million to $675 million. The project was approved in 2022 under MISO’s first long-range transmission plan (LRTP) portfolio.  

Northern Indiana Public Service Co. is handling the upgrade of existing 138-kV lines with about 37 miles of 345-kV lines.  

During MISO Board Week on Dec. 10, Executive Director of Transmission Planning Laura Rauch confirmed the cost increase triggered the study process. She said MISO will share more details once it finishes the analysis. 

MISO performs variance analyses on transmission projects when they encounter schedule overruns or significant design changes or experience a cost increase of at least 25% from original estimates. After completing the analysis, MISO can either let projects stand, cancel them or assign them to different developers, if possible. 

Rauch said other projects from the first LRTP portfolio remain on budget, with overall portfolio costs holding steady around the originally estimated $10.3 billion. 

MISO’s End-Use Customer sector has requested that the RTO and stakeholders discuss transmission cost-containment measures in planning meetings over 2025. 

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Virginia SCC Probes Data Centers, Demand Growth

Data centers are already a major source of demand in Virginia, but their growth in the coming 15 years is the main reason Dominion Energy expects its load to grow by 64%. 

The State Corporation Commission held a technical conference looking into the issue Dec. 16. Data center load growth accounts for 87% of the utility’s load growth and that does not even count the fact that 60% of data center load growth is in the territory of rural electric cooperatives, Trailhead Energy Consulting’s Marc Chupka, on behalf of Clean Virginia, told the commission. 

The state’s Joint Legislative Audit and Review Commission (JLARC) released a similar forecast just a week prior to the SCC meeting. (See Virginia Legislature Report Tackles How to Meet Surging Demand from Data Centers.) 

“Other forecasts are actually closely clustered to the Dominion forecast — the JLARC report, PJM’s and others — but consensus does not imply accuracy,” Chupka said. “Often, forecasts of this nature are clustered, not because everyone is in agreement about how the future is going to unfold, but rather, they’re working from the same data, or very similar data, using very similar methodologies.” 

Those assumptions could be off significantly, Chupka said, noting that Google just announced its quantum-based Willow chip. That advance and others could lead to much more efficient hardware in data centers, or artificial intelligence software could get more efficient, either of which would mean much lower demand from the sector going forward. 

The industry is growing because consumers are more online than ever, with an average of 21 connected devices in every home, said Aaron Tinjum, the Data Center Coalition’s director of energy policy and regulatory affairs. 

“Consumers and businesses will generate twice as much data in the next five years as they did in the past decade, so twice the amount of data in half the time,” Tinjum said. “This growth is driven by the widespread adoption of cloud services, the proliferation of connected devices and the rapid scaling of advanced technologies like generative AI, which alone could create between $2.6 trillion and $4.4 trillion in economic value globally by 2030.” 

In the electric industry generally, 20-year forecasts can be directionally helpful, but beyond that, their value is questionable, Google’s Brian George said. 

“I do think as we start to inch back towards that sort of 12-, 10-, eight-year mark, we need to start ratcheting up the confidence we have, and that is simply because of the long lead times it requires to build new infrastructure,” said George, the U.S. federal lead for Google’s Global Energy Market Development and Policy program. “But … we actually think there’s a lot of room right now for PJM to be more aggressive in addressing the load forecast adjustments that come up from its” transmission owners. 

Dominion does a good job on the forecasts that it feeds to PJM that are then turned into regional forecasts, but that is not the case with all of the region’s TOs, he added. Google works to have the most efficient data centers in the world, and it has a financial incentive to continue that because energy is one of the biggest costs they incur, George said. 

Data centers are focused on the state’s electric co-ops, especially around Data Center Alley in Northern Virginia, because they offer ample land that is also near transmission corridors, Rappahannock Electric Cooperative (REC) CEO John Hewa said. 

“We’ve engaged with a wave of new data center members and emerging direct-serve projects with an inbound load ramp projection that climbs in excess of 16,700 MW by the year 2040,” Hewa said. “Commissioners, what I’m characterizing here is that a once-quiet and still-rural electric cooperative has an inbound load ramp that exceeds the summer peak of the New York City power control zone, actually substantially. In REC’s case, much of this load ramp is scheduled to mature quickly within the next five years.” 

The co-op has set up an affiliate to serve the major group of new customers separately from the homes and smaller businesses that make up the rest of its customer base, with the affiliate serving them with market-based rates under FERC’s regulation, he added. That helps insulate other customers from any potential billing disputes, which can quickly add up to millions of dollars with hyperscale data centers, especially if the wholesale markets are impacted by an event like Winter Storm Elliott. 

“I simply do not think it is right for the other members, such as residential, to have to backstop the scenario for a Virginia-based data center operating with global reach,” Hewa said. “These large-use members must provide the financial liquidity, not only for their own great infrastructure and operations, but also for backing their presence in the wholesale market and the wholesale market purchases that go with that.” 

When done right, using market-based rates would protect other member consumers from subsidizing the energy demands of data centers, he added. 

In Dominion’s territory, the recent growth in data center-led demand has actually contributed to lower transmission and distribution costs for residential customers, who paid 59% of the overall costs in 2020 and now pay 10% less, said Vice President of Regulatory Affairs Scott Gaskill. 

“The growth in the GS3 and GS4 load classes, or rate classes, has increased over that time, which just naturally is going to reallocate costs to that load class, and you see a residential decline and that class go up,” he said, referring to Dominion’s rate schedules for business customers with a peak demand of at least 500 kW. 

But past performance is no guarantee of future results, and the large infrastructure investments needed to meet growing demand from data centers, some of which is already inevitable, will lead to higher costs as seen in PJM’s capacity market already. 

“I view that as probably the single largest driver to rate increases, say over the next three to five years,” Gaskill said. “Again, from the infrastructure build perspective, I think our current cost allocation methodology largely [takes] care of that, and the fact that the GS3 [and] GS4 classes are going to continue to be allocated more and more of those costs. But when we talk about the impact of energy prices — just the supply and demand in the whole PJM region — that’s going to be socialized across our system.” 

The other members of the GS3 and GS4 rate classes are often the Virginia Manufacturing Association’s members, which include 4,511 factories that were historically the largest electricity customers, attorney Cliona Robb said on behalf of the group. 

“It is the GS3 and GS4 rate classes that are being assigned a greater proportion of costs related to generation and transmission associated with meeting data center load,” she said. 

VMA does not believe any drastic changes are needed to the way rates are handled now, Robb said. While its members are facing a greater share of costs from new load, that is just how the system works, and all customers benefit from building more generators and expanding the transmission system. 

Demand from data centers is already driving most of the growth in demand, and eventually, it could get to the point where it threatens to make other large business less affordable in Virginia, which could have a bigger impact on the economy, Wilson Energy Economics Principal James Wilson said. 

“We’ve heard that data centers represent economic development, but when you look on it on a per-megawatt basis, the amount of economic development from, say, an electrified manufacturing facility is much, much higher than a data center,” Wilson said. 

Data centers can move to another part of the country easily, and that would have a much smaller economic impact than losing a manufacturing operation, he added. 

“So, you might push the data centers around a little bit, but you probably wouldn’t want to do that to the manufacturing,” Wilson said. 

So far, though, the way costs are allocated has worked, and the addition of new infrastructure has benefited the entire system, Google’s George said. 

“We have never tied the provision of retail electric service to jobs-per-megawatt created,” George said. “And so again, it’s unclear what benefit that adds.”