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November 15, 2024

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Amazon Moves to Accelerate SMR Development

Amazon is stepping further into the nuclear energy market, announcing multiple agreements surrounding advanced reactor technology that could provide carbon-free electricity for its operations.

The Oct. 16 announcements are the latest display of nuclear interest by energy-intensive data crunchers. Just two days earlier, Google announced a pioneering agreement to support Kairos Power’s development of its small modular reactor (SMR) and then buy power from the first few units built. (See Google, Kairos Sign 500-MW Nuclear PPA.)

Amazon itself agreed earlier this year to operate a data center co-located with Talen Energy’s existing nuclear plant in Pennsylvania. The move made news, and waves. (See Talen Energy Deal with Data Center Leads to Cost Shifting Debate at FERC.)

“One of the fastest ways to address climate change is by transitioning our society to carbon-free energy sources, and nuclear energy is both carbon-free and able to scale — which is why it’s an important area of investment for Amazon,” Matt Garman, CEO of Amazon Web Services, said in a news release. “Our agreements will encourage the construction of new nuclear technologies that will generate energy for decades to come.”

Amazon’s latest plans involve three other entities: X-energy Reactor Co., Energy Northwest and Dominion Energy Virginia.

X-energy

Amazon and others will invest $500 million in X-energy to help it complete design and licensing of its Xe-100 SMR and build a fuel fabrication facility.

The reactor’s design will be shippable via highways; it is intended to accelerate construction timelines and create more predictable and manageable construction costs.

Amazon and X-energy hope to bring more than 5 GW of SMRs online in the United States by 2039.

As part of the deal, X-energy and Amazon will develop a standardized deployment and financing model for future projects with infrastructure and utility partners.

“To fully realize the opportunities available through artificial intelligence, we must bring clean, safe and reliable electrons onto the grid with proven technologies that can scale and grow with demand,” X-energy CEO J. Clay Sell said in a news release. “We deeply appreciate our earliest funders and collaborators … we are now uniquely suited to deliver on this transformative vision for the future of energy and tech.”

Energy Northwest

Amazon will partner with Energy Northwest to fund efforts to develop the Xe-100 SMR and deploy it near the public power agency’s Columbia Generating nuclear power station in Washington.

The deal gives Amazon the right to purchase electricity from the first phase (four modules totaling 320 MW) and gives Energy Northwest the option to add up to eight more modules (640 MW).

Energy Northwest said as the owner and operator of the only nuclear facility in the Pacific Northwest, and as a developer of clean energy and storage resources, it is well-suited for this new partnership.

“We’ve been working for years to develop this project at the urging of our members, and have found that taking this first, bold step is difficult for utilities, especially those that provide electricity to ratepayers at the cost of production,” Energy Northwest’s Vice President for Energy Services and Development Greg Cullen said in a news release. “We applaud Amazon for being willing to use their financial strength, need for power and know-how to lead the way to a reliable, carbon-free power future for the region.”

Dominion

The memorandum of understanding between Amazon and Dominion Energy Virginia commits them to exploring commercial and financing structures for SMR development in Virginia.

In July, parent company Dominion Energy sought proposals from SMR developers to evaluate the feasibility of adding an SMR at the company’s North Anna nuclear generating station in Virginia.

An objective of the Amazon MOU is to mitigate potential cost and development risks for customers’ capital providers. Large nuclear reactors have proved extremely expensive to develop in the United States in recent decades, and while SMRs hold the promise of eventual cost reduction through standardization, they are still in development and early projects are expected to be expensive.

The SMRs in development now must still clear numerous technical and regulatory hurdles. And any future scenario in which scores or hundreds of new reactors with smaller safety zones dot the American landscape could be expected to prompt extensive debate and litigation.

But Dominion said SMRs could play a pivotal role in the energy mix in the 2030s. “This collaboration gives us a potential path to advance SMRs with minimal rate impacts for our residential customers and substantially reduced development risk,” CEO Robert Blue said in a news release.

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California Hits Milestones for Batteries, DR Grid Support

California’s battery energy storage capacity has hit 13,391 MW, an increase of 3,012 MW in just six months and a milestone that Gov. Gavin Newsom’s office called “a major victory on the state’s path to 100% clean energy.”

As the growth in battery capacity is accelerating, the new milestone is one-quarter of the way to the state’s projected need of 52 GW of battery storage capacity by 2045.

Industry experts cited the growth of battery storage as a key factor in the Western grid having an “uneventful” summer — despite enduring the hottest weather on record. (See Batteries, Energy Transfers Support ‘Uneventful’ Summer in West.)

Batteries are also key to capturing solar energy that’s produced during the day so it can be used when the sun isn’t shining, Newsom’s office said. Battery discharge to the grid increased from 6,000 MW this spring to more than 8,000 MW over the summer.

“These are the essential resources that we’ll continue needing more of as the climate crisis makes heat waves hotter and longer,” Newsom said in a statement.

According to a CAISO special report on battery storage, battery charging accounted for about 8.3% of load in the CAISO balancing area during peak solar hours in 2023.

“During these hours, batteries help reduce the need to curtail or export surplus solar energy at very low prices,” the report said.

Most of the state’s current battery storage capacity comes from 187 utility scale installations totaling 11,462 MW.

Residential battery storage adds 1,354 MW of capacity in 193,070 installations across the state, according to a California Energy Commission (CEC) dashboard. The remaining 576 MW of capacity is from 3,211 commercial installations.

Broken down by region, the 93501 and 92225 ZIP codes have the most battery storage capacity: 1,450 MW and 1,051 MW, respectively. Both areas are in the Southern California desert.

Grid Support Program

California’s battery storage milestone comes as the state is seeing growth in a program aimed at maintaining grid reliability during extreme weather events.

The CEC’s Demand Side Grid Support (DSGS) program pays participants to reduce electricity use or send energy to the grid to reduce the risk of rolling blackouts. The program runs from May through October.

Since its launch in August 2022, the DSGS program has grown to 265,000 participants and 515 MW of capacity, the CEC announced Oct. 15.

The program includes what the CEC describes as one of the largest storage virtual power plants in the world, with a capacity of more than 200 MW. The VPPs are a network of customer-owned battery storage systems — usually paired with solar — that send power to the grid.

In addition to storage VPPs, the program has two other ways to participate. Participants may provide non-combustion resources, such as traditional demand response. It’s also open to demand response aggregators participating in the CAISO market.

So far in 2024, the virtual power plant has been activated 16 times and demand response was activated once, “helping to avoid a grid crisis during four separate heat waves from July through the beginning of October,” the CEC said.

The DSGS program also played a role in the September 2022 heat wave, when it reduced electricity demand by 3,000 MWh during the 10-day event.

DSGS is part of the state’s Strategic Reliability Reserve, created in 2022 through Assembly Bill 205. The reserve is intended to expand the resources available to manage or reduce net-peak demand during extreme events.

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FERC Grills Grid Stakeholders on Reliability

Speaking to FERC’s annual Reliability Technical Conference on Oct. 16, NERC CEO Jim Robb told commissioners the challenges of ensuring reliability across the North American power grid are only growing. 

“We have a very simple math problem: the trend lines for electricity supply and demand are moving in the wrong direction to sustain reliability,” Robb said in his opening remarks. He went on to highlight a few of the emerging pressures on supply, including the replacement of conventional generation with renewable resources like wind and solar that rely on inverters to connect to the grid. 

“Replacement generation lacks the abundant reliability characteristics of the retiring resources,” he said. “And as we’ve seen over the past few years, the weather conditions the system operates under are increasingly severe, whether they’re long-duration, wide-area extreme cold or heat events, space-weather driving [geomagnetic disturbance] events … or tropical systems like the devastating hurricanes of Helene and Milton.” 

NERC CEO Jim Robb | FERC

However, despite the increasingly “turbulent” environment, Robb also emphasized that “the state of reliability remains a great story of progress,” with the severity and duration of outages declining and system restoration times shortening. 

Robb was part of the first panel of the day, along with representatives of a range of ERO stakeholders including ISO-NE, MISO, Duke Energy, the American Public Power Association and American Clean Power. The discussion touched on multiple reliability issues, with a large share of attention on generation retirements. 

Asked by FERC Chair Willie Phillips about the “record pace” of retirements and the wind and solar resources coming online to replace traditional generation, Carrie Zalewski of American Clean Power emphasized that the growth of renewable energy does not need to be seen as an inherent risk. Recalling the failure of natural gas generators in Texas during the winter storm of December 2022, she urged commissioners that “resource diversity is the linchpin of reliability.”  

FERC Chairman Willie Phillips | FERC

“No resource is immune to risks or weaknesses, whether it’s weather dependency, limited energy availability, correlated system outages … insufficient fuel supply or environmental limitations,” Zalewski said. “It’s dangerous to run a grid that focuses on one type of resource alone, and we … have all kinds of facts … out of Winter Storm Elliott [about] the over-reliance on a [single] resource.” 

In the second panel of the day, Phillips noted that NERC’s written comments before the conference called for “close, intense collaboration” between regulators and state governments to build a reliable electric system. NERC Chief Engineer Mark Lauby said the ERO has focused on building a shared vision of how the grid will function with the new resources coming online. 

“The partnership has got to be around getting to a point of understanding what is the design basis of this system of the future?” Lauby said. “We’ve been so very comfortable about” the one-day-in-10 years loss-of-load expectation, “and it’s really held [up] well. Very rarely did you see generation lower than demand. And we’re starting to see that now, as we integrate weather-related or weather-dependent resources, as we have an interconnected gas and electric system, and how they work together.” 

Andrew French, chair of the Kansas Corporation Commission, endorsed Lauby’s vision of collaboration, describing some of the ways his organization’s coordination with NERC and FERC have borne fruit. 

“I think the primary area where we have coordinated very well there is in things like setting accreditation policies and setting those ultimate resource adequacy requirements, things like planning reserve margins,” French said. “These are fuel-neutral policies, they are data-driven policies that tell us what an appropriate level of reliability might be and how we might value different resources based on the attributes they provide to the system, but it ultimately leaves to the state what resources they will implement to achieve those resource adequacy requirements.” 

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SCOTUS Upholds EPA Rule on Power Plant Emissions ― for Now

The Supreme Court on Oct. 16 turned down industry and state efforts to slap a stay on the U.S. Environmental Protection Agency’s new rules aimed at cutting carbon emissions at U.S. power plants burning fossil fuels. But the court left the door open for a second attempt pending a decision on the cases from the Court of Appeals for the D.C. Circuit. 

Under the final rule EPA released April 24, existing coal-fired power plants nationwide will have to either close by 2039 or use carbon capture and storage or other technologies to capture 90% of their emissions by 2032. New natural gas plants will have until 2035 to similarly cut their emissions through efficient design, carbon capture or a combination of both. (See EPA Power Plant Rules Squeeze Coal Plants; Existing Gas Plants Exempt.) 

The brief decision from Justice Brett Kavanaugh responded to a slate of eight cases against the EPA now before the D.C. Circuit, including two separate state challenges: one led by West Virginia, one led by Ohio. Suits also have been filed by the National Rural Electric Cooperative Association, the National Mining Association, NACCO Natural Resources Corp., the Midwest Ozone Group, Electric Generators for a Sensible Transition and the Edison Electric Institute. 

With Justice Neil Gorsuch concurring, Kavanaugh said that while the plaintiffs “have shown a strong likelihood of success on the merits as to at least some of their challenges” to the EPA rule, work on complying with the rule would not have to begin until June 2025. 

The plaintiffs “are unlikely to suffer irreparable harm before the Court of Appeals for the D.C. Circuit decides the merits,” Kavanaugh said. “Given that the D.C. Circuit is proceeding with dispatch, it should resolve the case it its current term.” 

Either the plaintiffs or EPA then could appeal to the Supreme Court, he said. 

The decision notes that Justice Clarence Thomas would have granted a stay, while Justice Samuel Alito “took no part in the consideration or decision of these applications.”  

The mixed decision got a quick reaction from Michelle Bloodworth, CEO of America’s Power, the coal industry’s trade association, who expressed disappointment that the court did not stay the rule, but also pointed to Kavanaugh’s belief that at least some of the state and industry arguments had merit.  

“We have long stated that … EPA’s carbon rule is an illegal overreach of the agency’s authority and would undermine the reliability of our nation’s electrical grid,” Bloodworth said. “By forcing the premature retirement of coal plants, the EPA would reduce needed sources of electricity at the same time electricity demand is exploding. Coal-based electricity is essential to ensuring the United States can develop and deploy artificial intelligence and not fall behind other nations like China.” 

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CEC Unlocks Nearly $43M in Funds for OSW Infrastructure Projects

The California Energy Commission is offering $43 million in grants to fund waterfront facility improvements to support the development and operation of floating offshore wind energy off the state’s coast.  

Eli Harland, energy policy expert and planner at CEC, gave an overview of the solicitation and how to apply during an Oct. 16 workshop. 

“The purpose of the GFO [grant funding opportunity] is to fund projects that will plan for offshore wind energy infrastructure improvements that can advance the capabilities of California waterfront facilities, ports or harbors to support the development and operation of floating offshore wind projects,” Harland said.  

The solicitation implements provisions of Assembly Bill 209, otherwise known as the Energy and Climate Change Budget bill, that requires the commission to implement a variety of clean energy programs, including the Offshore Wind Waterfront Facility Improvement Program. CEC will obtain the funds in June 2025 and make them available to selected grant applicants by June 2029.  

The Waterfront Facility Improvement Program was established in recognition that ports will be crucial to all aspects of the development and operation of floating offshore wind projects, including manufacture of parts such as blades, assembly and transport of turbines, and the operations and maintenance of final products. 

The solicitation required by AB 209 works in tandem with several other policy efforts aimed at advancing West Coast wind projects, including AB 525, which directed the CEC to develop a strategic plan outlining offshore wind development. The report was approved in July and includes a chapter covering efforts to improve ports and waterfront facilities.  

According to the plan, California’s existing port infrastructure is insufficient to support the offshore wind industry. Individual wind turbines are likely to be anywhere from 12 MW to 25 MW each and can only be transported over water, making staging and integration port sites where turbines are assembled essential.  

It also emphasizes that “no single port site in California can support all the needs of the offshore wind energy. Instead, multiple ports will be needed and … [upward] of 16 large and 10 small port sites [could be needed] to support offshore wind development over the next decade or more.”  

The CEC will fund offshore wind infrastructure improvements at waterfront facilities in two investment categories. Category 1 covers activities that support developing individual or regional retrofit concepts and investment plans. Category 2 includes activities that support final design, engineering, environmental studies and review, and construction of retrofits.  

Up to $6.75 million will be available for grants for Category 1, with projects eligible to receive a minimum of $750,000 and a maximum of $2 million. Up to $36 million is available in Category 2, with a project minimum of $9 million for each project and a maximum of $27 million. Eligible applicants include port authorities, operators and commissioners and California waterfront facilities and partners. Applicants in both categories must demonstrate site control.  

Funding, Site Control Concerns

While commenters during the call largely expressed approval of the program, some industry experts weren’t happy with the way the funding was split between categories.  

“We would like to see some additional funding allocated to Category 1 activities, in addition to increasing the overall award size for category one activities from the $2 million cap. That’s really not a lot of money,” said Artie Mandel, director of strategic initiatives at the Port of Los Angeles. “This program is a really unique opportunity for all of the California ports to support the statewide strategy and build out a California supply chain, and we really need to make sure that there’s enough resources there to support all of the ports in undergoing their planning efforts.”  

Other meeting participants echoed the request for increasing Category 1 funding.  

Jason Cotrell, founder and CEO of Sperra, a company that designs and manufactures offshore wind infrastructure, expressed concern about the Category 1 site control requirement.  

“The site control really puts the cart before the horse. I think one thing that we can agree on is that floating offshore wind is very early in terms of supply chain and technology developments, and it will consistently change over the next decade before it’s deployed in California,” Cotrell said. “We really think that site control in Category 1 is an unnecessary requirement that potentially restricts and will discourage participants from participating in Category 1.”  

The deadline to submit applications is Nov. 22, and the notice of proposed awards will be announced in December. The anticipated start time for the project agreements is April 2025.  

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New England Generators Protest ISO-NE Financial Assurance Changes

A recently filed proposal by ISO-NE to increase the collateral requirements for generators with capacity supply obligations (CSOs) has received strong pushback from the New England Power Generators Association (NEPGA), which argued to FERC on Oct. 9 that the proposal would violate the filed rate doctrine (ER24-3071).

The policy changes are intended to reduce risks to the market of generators defaulting on pay-for-performance changes, which are accrued if a generator can’t meet its obligations during a capacity scarcity event.

ISO-NE initiated the updates in the wake of PJM’s struggles with generator defaults following Winter Storm Elliott. (See PJM: Elliott Nonperformance Penalties Total More Than $1.8B.)

“There is a significant risk to the New England Markets caused by the fact that many [forward capacity market] participants do not have adequate corporate liquidity to satisfy their contractual, financial obligations related to the CSOs they were awarded,” ISO-NE said.

The RTO filed three updates to the policy last year, which were all accepted by FERC. However, the last set of changes have proven controversial and faced significant pushback in the NEPOOL stakeholder process. Neither ISO-NE’s proposal, nor two amendments proposed by NEPGA, passed the two-thirds approval threshold required for NEPOOL support. (See NEPOOL Participants Committee Votes to Support Hourly GIS Tracking.)

ISO-NE is proposing to introduce a new corporate liquidity assessment that would assign each participant a risk level to determine the collateral requirements. The RTO projects the changes would increase market-wide financial assurance costs by $72 million to $90 million for the 2025/2026 capacity commitment period (CCP).

In response, NEPGA protested the effective date of the proposal but not the underlying changes. The association argued that the changes should not apply to existing capacity commitments and should instead take effect for the 2028/2029 CCP. The auction for this CCP will likely take place in early 2028, depending on the results of ISO-NE’s ongoing capacity auction reform project.

“The [financial assurance policy] changes, if applied beginning on June 1, 2025, as ISO-NE requests, would alter the legal requirements associated with capacity supply obligations assumed years ago in violation of the filed rate doctrine,” NEPGA wrote.

The filed rate doctrine prohibits retroactive changes to rates that have been approved. NEPGA argued that ISO-NE’s proposal would add costs for generators with capacity commitments which were not accounted for in the auction bids.

“Denying the opportunity to reflect the full cost of providing capacity by post facto changing the rules governing the costs of holding a CSO, is not just wrong from a policy standpoint, but could contribute to accelerated retirements,” NEPGA said.

“With announced retirements in New England already outpacing new entry over the coming years, exacerbating this mismatch undermines confidence in the market and consequently risks reliability and the resource adequacy of the region,” the group added.

NEPGA requested that if FERC accepts the changes, it should either direct ISO-NE to adopt a June 1, 2028, effective date or schedule a hearing to determine an adequate effective date.

ISO-NE argued its proposal “does not constitute a retroactive rate change” because the changes would not affect auction prices or capacity supply obligations.

It added that the changes are prospective, not retroactive, because they would take effect in June 2025 and would “not alter prior credit reviews or supplant previously calculated inputs into the formula for the [forward capacity market] delivery financial assurance requirement.”

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Report Explores State Options for Short-term Transmission Planning

ARLINGTON, Va. ― FERC Order 1920 eventually may provide a structure for long-term, interregional transmission planning, but the anticipated yearslong implementation of the rule could mean states will have to lead in planning for their nearer-term transmission needs, according to a new report from the American Council on Renewable Energy and The Brattle Group.  

Rolled out at ACORE’s recent Grid Forum, the report focuses primarily on PJM’s Mid-Atlantic states, which are developing transmission for offshore wind and other renewables. New Jersey’s state agreement approach (SAA) ― in which the state’s Board of Public Utilities has partnered with PJM on project solicitations ― is seen as a model that could cut costs and interconnection times. 

Brattle’s Joe DeLosa III laid out seven options states might pursue, ranging from following New Jersey’s lead with a single-state SAA with a single “driver” ― such as meeting state goals for offshore wind deployment ― to waiting for implementation of 1920.  

Other SAA options include a single state agreement covering multiple drivers ― say, reliability and a renewable energy target ― and multiple states with single or multiple drivers. Outside of SAAs or 1920, the report looks at “voluntary solicitations” involving either single or multiple PJM states or interregional, multistate efforts, for example, bringing in New York or New England states. 

“Building offshore wind at scale in the next decade is essential to meeting electricity demand in a clean and reliable manner, but transmission planning must start today,” said Evan Vaughan, executive director of MAREC Action, in an ACORE press release announcing the report. States must “set their own direction on transmission planning to address multiple needs — reliability, economic growth, clean energy deployment, extreme weather resilience — in the most efficient way possible.” 

MAREC Action is an advocacy group representing utility-scale renewable energy developers in the Mid-Atlantic and Appalachia.  

ACORE CEO Ray Long agreed that “time is of the essence, and our report lays out the opportunities for states to maximize the benefits of proactive planning, particularly for offshore wind.” 

RTO Insider did offer PJM the opportunity to comment on the report, but a spokesperson said the RTO still was reviewing it and would “defer comment at this time.” 

The SAA Options

The report sees state leadership as filling a critical gap in PJM’s planning processes.  

“Despite recent stakeholder efforts, PJM’s transmission planning process has not yet evolved to the point where it is cost-effectively meeting multiple system needs, including the public policy goals of PJM states. This would require a more proactive and holistic planning approach,” the report says. 

Brattle’s analysis of benefits of each approach comes down squarely on going with an SAA, which DeLosa said provides more flexibility. “We just recommend that if a state or states within PJM seek to lead transmission procurement, it makes a lot more sense for them to use the tariff structure and the experience of New Jersey and go with the SAA.” 

To date, New Jersey has completed one solicitation under its SAA with PJM, awarding onshore transmission projects, but put a second solicitation on hold this year, according to a recent update from PJM. 

Maryland’s Promoting Offshore Wind Energy Resources Act (SB 781), passed in 2023, required the state’s Public Service Commission (PSC) to ask PJM for an analysis of the transmission upgrades that might be needed for offshore and onshore wind. Meetings between PJM, the PSC and other state agencies are ongoing.   

At the same time, the PSC has been talking with New Jersey and Delaware about the possibility of regional collaboration on transmission planning. But according to a recent report from the commission, each of the three states is at a different stage of analyzing and considering their options, making collaboration unfeasible. 

DeLosa also sees potential for interregional planning between PJM and non-PJM states. “We believe it could be well utilized for targeted procurements, even over a broad geographic scope,” he said. “We envision so-called ‘low-hanging fruit’ projects … that are either well-known or somewhat advanced in their development that would kind of evidently provide benefits.  

“If sufficiently targeted, we also believe a cost-allocation approach, which could be a key underlying element of this, could be developed [and] limited to particular projects and the associated benefits case.” 

A major caveat for any of these approaches is the “leadership role that is required of the states, the ongoing project management responsibilities for the projects that have been selected,” he said. “They persist over a long period of time, and they don’t go away. … There needs to be some method of supporting the states so that they can actually meet the needs, the leadership needs … under some of these frameworks.” 

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FERC Gets Mixed Advice on How Quickly to Move on DLR Requirements

FERC received dozens of comments on its advanced notice of proposed rulemaking (ANOPR) that would require broad use of dynamic line ratings across the U.S. transmission grid.

The ANOPR (RM24-6) proposes to require utilities to monitor hourly solar and wind conditions and a requirement to enhance data around transmission congestion outside of organized markets to see where DLRs might be cost effective. (See FERC ANOPR Seeks to Move the Ball Forward on Dynamic Line Ratings.)

Many utilities urged FERC to be cautious in mandating specific and additional requirements around DLRs, as the industry is still working to implement Order 881 on ambient adjusted ratings (AARs), which Edison Electric Institute noted comes with a July 2025 deadline. FERC also recently required transmission planners to consider DLRs as part of their compliance with Order 1920.

“EEI members are committed to deploying DLRs and other grid-enhancing technologies (GETs) where they are proven to be cost-effective and produce identifiable benefits for customers,” the investor-owned utility trade group said. “Where EEI members have implemented DLRs, they have been deliberate in their analysis and careful to ensure that costs do not outweigh benefits.”

The value of DLRs will depend on the accuracy and transparency of the line ratings used in AARs, but the industry lacks that benchmark since Order 881 has yet to go into effect, EEI said. FERC should allow some time for the industry to be comfortable with AARs because complying with two mandates at once would create overlapping deadlines, bottlenecks with limited vendors in the space, and tax utility employees working in the space, EEI said.

While the use of DLRs on the American grid has been largely at a pilot level, other commenters noted that the pilots have so far tended to show promise, and many European grids use the technology much more widely already. A group of clean energy trade associations — the Working for Advanced Transmission Technologies (WATT) Coalition, American Clean Power Association, Advanced Energy United and others — say that DLRs can help the industry deal with its most pressing problems.

“It is imperative that FERC act quickly to proceed to a Notice of Proposed Rulemaking (NOPR) and then a final rule requiring DLR under appropriate circumstances,” they said. “The urgent need for more transmission capacity is even clearer now than when FERC opened its Notice of Inquiry into the Implementation of Dynamic Line Ratings in 2022.”

DLRs would help to address lengthening interconnection queues, growing demand and the need to expand the transmission grid. Expanding the grid means shutting down parts of it as new transmission comes online, and DLRs can mitigate side effects there, the clean energy trade groups said.

“Utilities should use all cost-effective approaches to reduce the impacts of unforced and forced outages on ratepayers and markets,” they said. “Congestion and curtailment due to transmission outages should be straightforward to predict and calculate in production cost modeling (which should also be performed outside of RTOs), so an evaluation of GETs to address those outages should also be straightforward.”

A more exhaustive review of the 60-plus comments in the docket will be published in the coming days.

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Dominion Releases ‘All of the Above’ Integrated Resource Plan for 2024

Dominion Energy’s 2024 Integrated Resource Plan, filed Oct. 15 with Virginia and North Carolina regulators, calls for major expansions of offshore wind, solar power and natural gas to meet surging demand in its territory. 

The document lays out multiple portfolios to meet that rising demand through significant investments in new power generation, upgrades to the power grid, energy storage and efficiency. It does not seek approval for specific projects, but offers a long-term plan based on current technology, market information and load projections. 

“We are experiencing the largest growth in power demand since the years following World War II,” Dominion Energy Virginia President Ed Baine said in a statement. “No single energy source, grid solution or energy efficiency program will reliably serve the growing needs of our customers. We need an ‘all-of-the-above’ approach, and we are developing innovative solutions to ensure we deliver for our customers.” 

The IRP included bill forecasts for Dominion’s residential customers in Virginia, who now spend $142.77 a month for 1,000 kWh and could see their bills grow by between $72.85 and $161.13 by 2035. 

Power demand is expected to grow 5.5% annually for the next 10 years and to double by 2039, according to a forecast by PJM, Dominion said. 

Just under 80% of the plan’s proposed new generation over the next 15 years is carbon-free, including 3,400 MW of new offshore wind on top of the 2,600-MW Coastal Virginia Offshore Wind (CVOW), 12,000 MW of new solar, 4,500 MW of new battery storage and small modular reactors starting in the mid-2030s. 

The CVOW project is proceeding on time and on budget, and Dominion has secured offshore leases nearby to build additional power plants. Those include 176,505 acres off Virginia Beach that could support 2.1 GW to 4 GW of wind power and an additional 38,964 acres off North Carolina that could support up to 800 MW. 

The utility asked the Virginia State Corporation Commission in a separate filing to approve 1,000 MW of additional solar, which would bring its fleet to 5,750 MW in the state. 

The remaining 20% of the plan’s power generation would come from natural gas, which Dominion said was a “critically important source of back-up power” to keep the lights on when wind and solar plants are not producing energy. 

“Winter Storm Elliott showed the need for every generating unit in the company’s fleet to be dispatched to meet the system peak early in the morning when renewable resources were not producing energy,” the IRP said. “This type of extreme weather event threatens reliability and requires resources to ensure the company can meet customer demands.” 

The company is modeling additional combustion turbines, which would function as quick-dispatch, balancing resources and combined cycle units that would operate more often, the IRP said. 

The proposal to expand coal, which could mean nearly 6 GW of new fossil-fired power plants, drew opposition from some clean energy interests and environmentalists. Advanced Energy United noted that the Virginia Clean Economy Act requires the state to move to renewable energy and a fully clean grid by 2050. 

“Dominion Energy’s latest IRP is a step in the wrong direction,” AEU’s Shawn Kelly said in a statement. “Instead of harnessing the potential of advanced energy to more reliably and cost-effectively meet Virginia’s growing energy needs and clean energy goals, this plan threatens to keep the state dependent on fossil fuels for decades. Dominion is missing a critical opportunity to lead Virginia’s clean energy transition, protect households and businesses from rising costs, and provide more resilient clean energy solutions for all Virginians.” 

All four of the plans filed with the SCC would increase emissions, said the group Clean Virginia, which called for the IRP to be rejected. 

“Dominion’s latest energy plan blatantly disregards the financial well-being and health of Virginia families,” Clean Virginia Deputy Director of Energy and Operations Kate Asquith said in a statement. “By continuing to invest in gas-burning facilities, Dominion is not just raising bills — it’s locking Virginians into a future of higher costs and greater pollution. This is unacceptable at a time when we need to be transitioning to clean, affordable energy.” 

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US Utility-scale Solar Buildout Set Record in 2023

Utility-scale solar construction reached record levels across the United States in 2023 and its cost continued to decline, the Berkeley Lab announced in this year’s edition of its annual report on the sector. 

A total of 18.5 GWAC of large-scale solar was brought online last year, bringing total installed capacity to 80.2 GWAC in 47 states, the report says, while capacity-weighted average installed costs decreased 8% to $1.43 per watt AC. 

The levelized cost of electricity from these utility-scale photovoltaic systems rose slightly to $46/MWh, not counting tax credits, but decreased slightly to $31/MWh once the federal incentives were factored in. 

For the first time ever, more than half of new grid capacity nationwide was solar — 17% distributed and 35% utility-scale. 

The report predicts that 2024 will be another record year, with more than 35 GW of utility-scale solar and distributed commercial or residential solar installed. 

A whopping 1.09 TW of utility-scale solar is stacked up in the nation’s interconnection queues, but historically, only 10% of requests ever advance to construction, the Lawrence Berkeley National Laboratory noted as it announced the new report Oct. 15. 

Capital costs of building utility-scale solar generation have steadily decreased over the past decade, as measured by cost per output. | Lawrence Berkeley National Laboratory

The 2023 report and its executive summary drill down on the state of the utility-scale solar sector. Among the details, data points and conclusions: 

    • Average energy and capacity value nationwide was $45/MWh; average market value ranged from $27 MWh in CAISO, where solar has the largest market share, to $67/MWh in ERCOT, where summer heat waves and record electricity demand were seen during peak solar production hours. 
    • Only 4% of utility-scale PV capacity added in 2023 was installed on a fixed-tilt mount; the rest used single-axis tracking. Fixed-tilt is relegated mainly to challenging sites and least sunny regions of the Northeast; tracking mounts add 20 cents per watt to the cost on average but can boost capacity significantly in sunny regions. 
    • Projects larger than 50 MW cost 13% less per megawatt on average than their counterparts rated at 5 MW to 50 MW. 
    • Plant output still declines with age, but more recent projects are showing a slower decline than earlier projects did at the same points in their lifespans. 
    • Projects in the regions with the lowest solar insolation have the highest levelized cost of electricity — ISO-NE and NYISO were $76 and $78/MWh, respectively — while the sun-rich ERCOT, CAISO and non-ISO West ranged from $37 to $42. (Project costs and size contributed to this disparity.) 
    • Solar power purchase agreements have largely closed the gap with onshore wind PPAs — both were much more expensive 15 years ago, but solar PPA prices have declined more sharply than wind. Lower natural gas prices, meanwhile, have given existing combined-cycle gas-fired generators a near-term cost advantage over solar. 
    • Concentrating solar thermal power has been lagging, with no U.S. installations since 2015. The newest of the existing installations have underperformed expectations.