What's Happening in Energy highlights the most interesting findings from public utility commission filings.
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What's Happening in Energy — Nov 7
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Let’s begin with some direct language regarding a situation in Oregon. Amazon Data Services (ADS) has filed a complaint with the Public Utility Commission against PacifiCorp. The complaint states that PacifiCorp has failed to provide adequate service to the four data center campuses that ADS has developed since 2021: Specialized, Litespeed, Pivot, and Gray.
According to ADS, “PacifiCorp is supplying significantly less power than promised to the first Data Center Campus (known as ‘Specialized’), has delivered no power to the second (‘Litespeed’), and has refused to even complete its own standard contracting process for the third and fourth Data Center Campuses (‘Pivot’ and ‘Gray’).”
In addition to these accusations, ADS claims that PacifiCorp’s 32.6 percent “gross-up charge” on top of Actual Costs, as defined in the Master Electric Service and Facilities Improvements Agreements (MESAs) for Litespeed and Specialized are “grossly inflated.”
ADS lists two potential pathways forward:
Read the heavily redacted complaint below.
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In Kentucky, the Public Service Commission has approved East Kentucky Power Cooperative’s Rate Data Center Power (DCP) tariff for data centers greater than 15 megawatts (MW). A unique feature of the tariff is the “Dedicated Resource Rider,” which the utility will use to allocate supply costs to the data center customer. For data centers with loads greater than 250 MW, the tariff would require “one or more dedicated resources” to supply the customer.
Rate DCP includes a requirement for EKPC to work with data centers to develop and implement a power supply plan to support the customer’s load with the following: Dedicated Resources supplied by EKPC or the data center; bilateral power and capacity purchases; or a combination of these resources. In the case of data center loads exceeding 250 MWs, one or more dedicated resources will be required as part of the power supply plan and the Dedicated Resource Rider will apply. EKPC stated that the 250 MW threshold was selected because that is intended to be the approximate value of a dedicated CT unit, and EKPC believes that any load exceeding that amount should be served with Dedicated Resources to help minimize risk to non-data center loads.
The utility has 20 days from the Order’s date of service to file its revised tariff sheets for Rate DCP and the Dedicated Resource Rider.
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In Virginia, the main character of Halcyon’s What’s Happening in Energy, Rappahannock Electric Cooperative (REC), is back in the spotlight! REC, along with its affiliates– Hyperscale Energy Services, LLC; Hyperscale Energy 1, LLC; Hyperscale Energy 2, LLC– has requested approval to provide credit support to its dedicated service affiliates (DSAs).
However, the Commission Staff found that the Applicants did not demonstrate that the proposed credit support serves the public interest. They concluded that it is unreasonable and unnecessarily risky to require the Cooperative’s mostly residential members to provide cash collateral for a large-load customer.
Comments from Retail Energy Advancement League (REAL)
... if REC, as a parent company to a DSA, were to underwrite a DSA’s collateral obligation associated with 1,000 MW, the “value” of the parent guaranty provided to PJM by REC to support its Affiliated Generation Companies could be $20-$30 million.
REAL continues this proceeding, “is related to REC’s ongoing efforts to create affiliated generation companies that can act as intermediaries and procure capacity and energy from PJM for its large load customers.” Two related proceedings:
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In South Carolina, Duke Energy, North Carolina Electric Membership Corporation, and Central Electric Cooperative have submitted an application for a Certificate of Environmental Compatibility and Public Convenience and Necessity. This application is for the construction of a hydrogen-capable combined-cycle power plant with a capacity of 1,365 MW, in Anderson County, SC. The applicants justify this request by highlighting the need to maintain a 22% winter planning reserve margin, as identified in the 2023 IRP, and an increase in “annual energy need of 25,735,000 MWh between 2024 and 2031.”
“With respect to natural gas combined cycle generation, the 2023 Integrated Resource Plan (IRP) initially identified the need for 4,080 MW of new natural gas combined cycle generation (equivalent of 3 Advanced Class 2x1 combined cycles) by 2031. The January 31, 2024 supplement to the 2023 IRP confirmed the initial selection of—and selected additional—natural gas combined cycle generation in the Companies’ IRP, adding an additional 2,720 MW of natural gas combined cycle generation (equivalent of another 2 Advanced Class 2x1 combined cycles) to be placed in operation by 2033.”
The application included a timeline of the “Year of Need Identified for Combined Cycle Generation, by Unit”:
The application also includes proposals to “fold in/out the existing Chickasaw B/W 230 kV lines” into a new 230 kV switching station in order to accommodate the Anderson County CC plant.
Check out the application and associated exhibits in the docket profile below. For granular details on gas power plants all across the country, check out Halcyon’s Gas Power Plant Tracker.____
In Minnesota, utilities submitted cost estimates in response to a Commission order that aimed to identify “system specific leakage rates” across their pipeline systems. The current GHG reporting follows EPA methodology based on pipeline type and footage, while system-specific rates use actual infrastructure data.
Here’s a summary of the estimated capital and operations and maintenance (O&M) costs from three utilities:
Current practice for leak identification involves CenterPoint Energy using the Picarro brand advanced mobile leak detection for our compliance surveys using a 3-year cycle per federal guidance in 49 CFR Part 192. Any areas that aren’t covered by Picarro are manually covered by technicians walking the area with handheld leak detection equipment. Any leak indication survey areas identified by Picarro are also walked by technicians with handheld leak detection equipment. The costs of the leak detection activities can be found below in Table 1.
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In Utah, Rocky Mountain Power (RMP) has submitted its semi-annual forecast for expenditures related to its demand-side management (DSM) program for the year 2026. The report includes a forecast of the expected irrigation load control available during peak months from May through August. Out of a total of 14 megawatts (or see chart below: MegaWatts) available, RMP expects a maximum load reduction of roughly 5 MW in the late summer.
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In Kansas, Evergy submitted its annual report on historical and projected generation and capacity data to the Kansas Corporation Commission. The report reveals a stark distinction between two of its main systems: Evergy Central and Evergy Metro, particularly regarding the future System Capacity Responsibility needed to meet Southwest Power Pool’s (SPP) planning reserve margins.
By the end of the decade, Evergy Central’s (image below to the left) total system capacity is projected to fall short by 543 MW of its total system responsibility. By 2044, its peak responsibility is projected to reach 7,214 MW, resulting in a deficit of 4,104 MW. This suggests a combination of future load growth and a decline in accredited capacity.
In contrast, Evergy Metro’s has shown similar historical load growth but less dramatic future projections. Its total system peak has fluctuated, reaching as high as 4.25% in 2020 and dropping as low as -5.15% in 2023. While its system capacity meets its responsibilities throughout the rest of the decade, it begins to lag in the 2030s, ultimately leading to an 879 MW deficit by 2044.
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In Texas, the Data Center Coalition has filed comments on the rules regarding “net metering arrangements between existing ERCOT-registered generation and new large-load customers.” This is a crucial aspect of the recently passed large load interconnection bill, SB6. The DCC urged the Commission to consider the impacts of diesel backup generation from large load curtailment.
Large load customers, such as data centers, site backup generators as an emergency resource to ensure continuity of operations during grid outages - not as a callable resource. If large load customers are required to operate on-site diesel backup generators for extended periods, the Commission should consider the potential implications.… backup diesel generators are subject to strict emissions limits under state and federal law that cap their annual usage. DCC emphasizes that these generators are not a simple on/off solution for sustained grid support. Large load customers should not face regulatory penalties for switching to backup generation in response to emergency grid conditions….DCC recommends that a formal process be established through which ERCOT, the Commission, the Texas Commission on Environmental Quality (TCEQ), and the Environmental Protection Agency (EPA) coordinate to provide enforcement discretion. This would help ensure that large loads remain compliant while aligning with the legislative intent of Senate Bill 2321 (89th Regular Session).
In another comment, developer Eolian stressed that energy storage resources (ESRs) should be acknowledged for their dispatchability and eligibility to participate in net metering arrangements with large loads, in addition to generation resources (GRs).
“Co-location of GRs/ESRs with LLs should be recognized and supported by the Commission and ERCOT as a means of enhancing system reliability, operational flexibility, and voltage stability, provided that such configurations preserve clear jurisdictional boundaries and maintain metering and settlement arrangements consistent with ERCOT's wholesale market framework and Wholesale Storage Load (WSL) treatment.”
Dig into the comments from Vistra, Calipine, Enchanted Rock, Texas-New Mexico Power, Oncor, and more Texas stakeholders in the docket profile below.
The report outlines the details behind the IRP modeling process, which includes multiple scenarios of load forecasts.
In the review on load forecasting, the report presented the “annual peak demand additions” in the updated IRP, which models several large load scenarios through 2040. According to the report, “the timing of load additions, including in the near term, is still uncertain. Ameren Missouri will be closely monitoring its load assumptions and will include any changes in future filings.”
The difficult-to-interpret table below presents five large-load scenarios ranging from 500 MW to 3,500 MW—a 600% swing by 2040 (and a 1,067% jump from the smallest 2026 scenario).
Due to significant uncertainty (see table above), the IRP compares three load forecast scenarios at the request of the Commission. Ameren intends to pursue the MEEIA scenario (blue bar), which shows the lowest energy usage throughout the modeling horizon. Ameren’s preferred selection, entails energy increases by 79% (Figure 3.3) and peak by 46% (Figure 3.4) from 2025 to 2043.
The report compared various load forecast scenarios, including one without demand-site rates (ToU rates), in terms of MWs instead of MWhs. Once again, the utility’s preferred plan is the lowest load forecast.
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And one more in Missouri, Evergy is seeking expedited approval of a large-load power service rate plan for data centers and other large customers in the Show-Me State. Evergy, along with Google and the Data Center Coalition, have requested that the Commission approve the Non-Unanimous Global Stipulation and Agreement. Other parties, including the Commission staff and the Office of the People’s Counsel, have also filed briefs with other perspectives on the subject.
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And a Federal bonus round! FERC has opened a docket for Interconnection of Large Loads to the Interstate Transmission System and motions/notices to intervene are flowing in.