What's Happening in Energy highlights the most interesting findings from public utility commission filings.
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What's Happening in Energy — Dec 19
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In Virginia, a who’s-who of large load customers filed remarks in the technical conference on data center load flexibility. Data center commenters (Amazon Data Services, Data Center Coalition, Google) repeatedly emphasized that flexibility should be “voluntary” rather than mandated. Utility Dominion reiterated this position and added that much of the Virginia market will be for inference-based services rather than for AI training. Inference, according to the utility, is less flexible than training, as many users rely on low-latency AI inference for their operations. Dominion continues,
Al training facilities may have more flexibility in curtailment capabilities due to the nature of training. Al inference data centers, however, are generally not curtailable because they provide on-demand services to end-users. As mentioned above, the Company’s service territory has not experienced any significant curtailment. Based on industry feedback, the market in Virginia will likely continue to operate that way, suggesting that as additional Al technology is installed, the associated load will be predominantly Al inference load, i.e., not curtailable.
The utility added a table to further highlight the distinction between inference and training.
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ISO-New England (ISO-NE)’s recently-released 2025 Regional System Plan projects net peak demand growth over the next decade–not from data centers, but from electrification. ISO-NE expects its 50/50 winter net peak demand to increase by almost 6 GW (30%) from 2025 to 2034, driven primarily by electrified heating. While the system currently peaks in the summer, ISO-NE projects that the gap between summer and winter peak demand will narrow significantly.
Below are the incremental additions to the net peak in the winter and summer. The electrification of transportation from EVs is a growth driver in both seasons, but the electrification of heating dominates the growth in the winter.
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In California, the Public Utilities Commission approved Pacific Gas & Electric’s (PG&E) Advice Letter outlining how the utility will energize a 90 megawatt Microsoft data center in San Jose. PG&E plans to interconnect the facility at 115 kV through line extensions and substation upgrades financed by an upfront payment from Microsoft. Under normal procedures (the Base Annual Revenue Calculation, or BARC), Microsoft would be eligible for a full refund based on the future revenues PG&E is expected to receive from Microsoft. Given the project’s size and revenue risk, however, the Commission approved a modified refund structure, allowing Microsoft to receive up to 75% of the annual net revenues (i.e. transmission charges paid by Microsoft to PG&E). The Commission justified the change as follows:
Given the factors described above, there should be additional protections to safeguard PG&E ratepayers from assuming the risk of energizing the Microsoft project and potentially being left with the costs if the project’s anticipated load and resulting revenue does not materialize. Refunds should be provided only to the extent that actual net revenues (as defined above) cover both the costs of energization and other costs of providing electric service normally covered by those net revenues (i.e., broader grid upgrades and operations and maintenance, which are normally covered by those portions of the customer bill). In other words, rather than being fully refunded after one year as a customer, based on expected future revenues, the refund for the Microsoft project should be annually provided in parts based on a percentage of the actual net revenues and taking into consideration other costs normally covered through those transmission rates.
Check out the advice letter linked below.
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In South Carolina, utilities Dominion Energy and Santee Cooper filed a Joint Application (JA) for a Certificate of Environmental Compatibility and Necessity to construct Canadys Station–a three-unit 2,180 MW advanced class combined-cycle (vendor not specified) generating plant. The utilities combined forces in this application to achieve economies of scale and procure firm gas deliveries for the plant. If all goes to plan, the plant would come online in 2033, with output split roughly 50/50 between Dominion and Santee Cooper for their respective service territories. The project will be built on the site of the former Canadys Steam Plant, a coal plant operated by Dominion and retired in 2013. Costs are currently estimated at $5 billion for the generating facility and $96 million for a new switchyard.
Check out the conceptual rendering from Sargent & Lundy.
In a supporting testimony, Scott Parker, Manager of Transmission Planning at Dominion, argued that the Canadys Station is necessary to support the load in the Charleston area as critical generators are retired in South Carolina’s Lowcountry over the next decade. The testimony supported this argument with a visual comparing the generation-to-load ratios for Columbia and Charleston. Modeling indicates that in the winter of 2030, Columbia’s ratio is projected at 1.5, while Charleston’s is just 0.4.
Notably, the need for the Canadys Station stemmed from the modeling in both utilities’ integrated resource plans (IRP) dating back to 2023. Santee Cooper modeled a 1,020 MW plant in 2024, and Dominion’s modeling selected either joint ownership of a 662 MW facility or 100% of a 1,325 MW facility. However, in Dominion’s 2025 IRP update, filed on March 31, 2025, it landed on a configuration closer to its 50% stake in the Canadys Station as proposed in the JA.
For more (much more!), check out Halcyon’s Gas Power Plant Tracker.____
In MISO, the final version of the system operator’s 2025 transmission expansion plan (MTEP) is out, and it's big! The MTEP25 portfolio consists of 432 projects totaling nearly $12.3 billion in investment from 33 Transmission Owners across MISO’s footprint. In the top three spots for estimated investment are Entergy Louisiana at $3.4 B (thanks in part to Meta), followed by American Transmission Company at $1.9B, and Wabash Valley Power Association at $850M, Inc. See the full table here.
Who wins out in the investment type? Substations at $5 billion (41%), followed by New Lines $3 billion (26%), and then Line Upgrades $2.5 billion (21%). You can see the regional variation below.
More than 70% of facilities are projected to be in service within the next three years, with the majority coming online in 2027.
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In Nevada, PR Power I–LLC (an outcropping of Tract), responsible for the Peru Ridge hyperscale data center campus, has applied for a permit to construct a 345-kV to 34.5-kV substation. The company is also requesting the permit to construct four 345 kV lines to connect the new substation with NV Energy’s existing Gosling Switching Station.
In support of its application, PR Power submitted several exhibits, including the following diagram of the proposed single circuit lines connecting the Gosling Switching Station to the new substation. You may have to tilt your head for this one.
However, the image quality of the other exhibits may not have been up to Commission standards. The Commission rejected the original application for failing to conform to the electronic formatting specified in the users’ guide, to which PR Power responded, “CONTACT FILER REGARDING IMAGE QUALITY.”
And a heartwarming aside, the environmental assessment includes a plan for helping trapped critters:
“At the end of each workday, any open trenches, holes, or pipes will be covered to prevent wildlife entering them and becoming entrapped…. at the beginning of a workday, it will be checked thoroughly for the presence of wildlife prior to the commencement of construction activities.”
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In PJM, Duke Energy Kentucky & Ohio has updated its transmission planning “Supplemental Projects”. The deck is concise but packed with eye-catching tidbits on the state of the grid in this region. The first project described is a $39 million retirement of a 93-year old, 47-mile long, transmission line between Miami Fort and Clifty Creek in Northern Kentucky. Another interesting detail from the deck is on slide 9, which documents a request for transmission service from a new customer that would ramp from 15 MW in 2025 to 500 MW in 2028 Check out the deck linked below.
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In Maine, loads are ramping down, not up. A large customer is sharply reducing load in Madison Electric Works (MEW) territory amid already declining operating revenues (down about 10.6% year over year). In late October—just three days before MEW’s planned rate case filing—the customer notified the utility that operational changes would cut its usage by roughly 90%. The resulting loss is projected to reduce annual revenues by about $458,000, or 24% of MEW’s total sales revenue, beginning with the February 2026 billing cycle. As a result, MEW is requesting a February 1, 2026, effective date for new rates.
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In Maryland, multiple intervenors filed comments arguing that the Commission should reject the Certificate of Public Convenience and Necessity (CPCN) application for Chaberton Solar Sugarloaf’s four megawatt project. Intervenors from citizen, countryside, and agricultural associations argued that the project threatens the Montgomery County Agricultural Reserve, violates zoning laws that limit solar development on lower quality soils, and provides minimal reliability benefit to the community:
“Maintaining the Reserve’s integrity has not been easy. Development pressures have been continuous and persistent. The homebuilding industry, bridge builders, firearm shooting ranges, “glamorous camping” proponents, large scale entertainment venues, and others have persistently sought to monetize the Reserve’s farmlands. Almost every one repeats the same soothing mantra: “We love the Reserve, and ours will only be a tiny bite.” Chaberton says the same: the Intervenors and the County exaggerate the threat to the Reserve because the Sugarloaf project will occupy only a small portion of the Reserve’s farmland – only a tiny bite that won’t matter.”
The intervenors further argue that, should the Commission grant the CPCN, it must impose strict requirements for “agrivoltaics.” However, they contend that Chaberton was never serious about its RFP for agrivoltaics–in this case, the proposed leasing of land for sheep grazing.
“One explanation for why Chaberton hasn’t released the RFP is … lease conditions that are so over-the-top unattainable that it would be a stunning surprise if even a single sheep farmer ever attempted to meet its requirements. It is 26 single-spaced pages containing, among other daunting content, a “Farmer Qualifications” section and a “Proposal Requirements” section that are so onerous that they look like they were deliberately designed to deter interest.”
If you want to follow along, the Discovery/Tech Conference has been extended from December through January 26, 2026.
Halcyon Team Queries of the Week: