What's Happening in Energy highlights the most interesting findings from public utility commission filings.
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What's Happening in Energy — Aug 29
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In Texas, Oncor filed an August 2025 investor presentation in its ongoing rate case. The deck included a breakdown of its five-year capital plan and interconnection request received from Large Commercial and Industrial (LC&I) customers. Most expenditures stem from investments in transmission and distribution projects to satisfy “significant service territory growth” and reliability investments through the $3 billion System Resiliency Plan (SRP).
Oncor has…a lot of large load requests. 457 of them represent 137 gigawatts (GWs) in total, of which 228 requests and 119GWs are data centers.
Importantly: even the non-data center load requests total 18GWs, and Oncor’s current peak demand is 31GWs. In other words — even without data centers, Oncor has received requests totaling roughly 60% of its peak demand from LC&I customers.
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The California Energy Commission presented its “Retail Electricity Rate Forecast” as part of the ongoing 2025 Integrated Energy Policy Report. Pacific Gas & Electric sees more than three gigawatts of cumulative data center load by 2045, with nearly 3GW by 2035. The result is an increase in its incremental revenue requirement from data centers to roughly $400 million in the early 2030s followed by a decrease to $250 million in 2045
Of note: the net effect of the data center projections in the PG&E planning area is a 1.25 cent per kilowatt-hour decrease in the system average rate. However, according to the presentation: “Actual sector level impacts will depend on interconnection rules and rate design for large transmission-level customers, currently being addressed in CPUC Rule 30 proceeding (A.24-11-007).”
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Not necessarily data center related, but noteworthy in California: statewide forecasts of residential rates for the six largest utilities. Sorry, Los Angeles…LADWP rates are soaring “to support system investment and implement LA100 plans.”
More tables and a deep dive into the CEC’s forecasting methodology in the presentation below (note: same presentation as in 2. above).
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In Virginia, the State Corporation Commission refiled part of Staff testimony that had been erroneously designated as confidential in the docket for the 2025 biennial review of Dominion Energy’s rates, terms, and conditions. The refiled testimony reveals that Staff removed $853 million in “speculative” data center expenditures to recalculate the revenue requirement, resulting in a reduction of 2026 and 2027 revenue requirements by $21.9 million and $58.6 million, respectively.
The reasoning behind their removal is key. The projects removed are in the “Pre-ELOA” or “ELOA” stages which only require interconnecting load customers to pay for an engineering study or make a $250,000 deposit, as opposed to the “CLOA” stage that requires customer payment incurred transmission and distribution costs even if they do not proceed.
According to the refiling,
Given the minimal obligation from customers prior to the CLOA stage, Staff maintains that projects in the Pre-ELOA and ELOA stages are speculative and are not reasonably predicted to occur during the Rate Years. As such, Staff has removed the associated costs of these projects from its ratemaking adjustments in this proceeding.
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In North Carolina, the Southern Environmental Law Center filed a report prepared by London Economics International entitled “Uncertainty and Upward Bias are Inherent in Data Center Electricity Demand Projections” as part of the large load tariff docket proceeding before the NC Utilities Commission. The report compares projected US data center demand growth with global chip manufacturing capacity from 2025 to 2030, finding that US demand would account for 90% of global chip demand over the six year period.
A key finding in the report:
It is not realistic to expect that the United States will be able to acquire 90% of the global supply of chips over the next six years. Global chip manufacturing capacity will be sought after by customers around the globe, not just in the United States, and not just in the US jurisdictions surveyed.
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In Michigan, DTE Energy submitted updated cost forecasts for its Trenton Channel BESS project, a four-hour 220 MW (880 MWh) system, after its previous battery supplier filed for bankruptcy. The updated project costs fell from $409.6 million to $378.5 million after DTE executed a contract with another battery supplier. DTE indicated that the Commercial Operations Date (COD) of the Trenton Channel BESS project is still December 2026 as expected. Commission Staff requested more information from the utility on the “revenue deficiency impacts” of the updated costs–i.e. impacts of the newly executed contract on the ongoing rate case. Quote:
Given the signed battery supply contract which preserves an anticipated COD in the test year and the updated forecasted project capital expenditures being $31.1 million lower than what was requested in the instant case, Staff recommends the Company provide all of the revenue deficiency impacts in rebuttal, so parties and the Commission may understand how this update in costs would impact the Company’s requested relief.
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In South Carolina, the Southern Electric Reliability Coordinator (SERC) briefed the Public Service Commission on extreme weather impacts and grid hardening measures. Slides 11-16 included details on the impacts of Winter Storm Elliott in December 2022, which incurred $5.4 billion in losses, caused the “Largest controlled firm load shed in the history of the Eastern Interconnection,” reduced dry natural gas production in the Marcellus and Utica shale formations by up to 54%, and forced numerous unplanned resource outages. SERC presented a pie chart of the 3,565 outages and derates by cause. The majority were from freezing issues (31%) and mechanical/electrical issues (41%).
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In PJM, the Reserve Certainty Senior Task Force (RCSTF) presented its proposal to manage day-ahead sources of uncertainty from intermittent resources, generator performance, gas fuel security/availability, load, weather, and behind-the-meter solar.
PJM used machine learning to forecast the net uncertainty of each energy source, and then developed a methodology to schedule reserves based on low, medium, and high risk scenarios.
PJM gives an example displaying reserve levels at different risk percentiles on a high-load day. Generator performance and load uncertainty have the largest impact on the absolute amount of reserves. However, reserves from renewable uncertainty are higher relative to their forecasted megawatts.
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In New York, Montgomery County filed a visual impact analysis of the proposed 300-MW Flat Creek Solar project. The analysis included a rating of the project’s “visual contrast” from three “key observation points” (KOPs). Visual contrast criteria were evaluated using panoramic photographic simulations of the short (0-5 years) and long-term (5-30 years) impacts of the project. The report concluded that the “Project creates a visual change to the existing landscape character that would be considered NOT COMPATIBLE or UNREASONABLE” primarily from impacts on the “rural identity” and “agricultural aesthetic.”
Check out the graphic below showing the viewscape represented via a “panoramic photo simulation in curved frame.”
The findings on each of the key observation points:
KOP 1: Canajoharie High School
Contrast level: “Moderately strong”
Conclusion: “NOT COMPATIBLE”
KOP 2: Conway Road at Pieberry Farm Stables
Contrast level: “Moderately strong
”Conclusion: “NOT COMPATIBLE”
KOP 3: Flat Creek Road
Contrast level: “strong”
Conclusion: “NOT COMPATIBLE”
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Bonus: In Hawaii, a resident submitted a letter with concerns regarding the application of Hawaii Electric Light Company (HELCO) to amend and restate its PPA with Puna Geothermal Venture. The project application, if approved, would expand the PPA to 46 MW.
The resident’s concern? The project is in breach of an order because it did not file an additional 1,475 pages of appendices to its 130 page Final Environmental Impact Statement.