What's Happening in Energy highlights the most interesting findings from public utility commission filings.
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What's Happening in Energy — Oct 17
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This week in PJM, the Critical Issue Fast Path (CIFP) stakeholder process introduced several innovative ideas aimed at enabling the rapid and reliable interconnection of large new loads. With PJM looking at a ~10 GW shortfall by 2030, Eolian proposed the Bilateral Integration of Generation Portfolios and Load (BIGPAL) as a potential solution.
BIGPAL allows large loads and generators to connect directly, undergo interconnection studies within 90 days, and provide bilateral capacity supported by private risk-sharing. This approach facilitates more flexible and responsive contracting. In one scenario, BIGPAL significantly reduced the requirements for large load shedding — and in another case, it completely eliminated the need for it altogether.
The Governor of Pennsylvania expressed support for BIGPAL in addressing interconnection delays but emphasized “this needs to be paired with broader reforms to incent new entry.”
In contrast, a joint presentation from Amazon, Calpine, Constellation, Google, Microsoft, and Talen called for a “reality check.” They advocated for stricter forecasting criteria for large loads and proposed a revised strategy to address capacity shortfalls. Notably, the group suggested prioritizing time-limited, voluntary demand response from large loads (24-100 hours per year) as an initial step, before considering supply-side solutions (and only when PJM’s capacity market, also known as its Reliability Pricing Model (RPM), clears below 98%).
To access PJM CIFP materials, try Halcyon’s FREE search. Remember that if you want to view the documents (underlined in red below), just you must authenticate (FREE) with your email address.
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Also in PJM, updates to the input assumptions for the informational base scenario were presented, featuring a wealth of interesting charts that outline the RTO’s projections for the next 20 years.
One notable aspect showcased pie charts depicting the future generation mix based on capacity expansion modeling, revealing remarkably similar proportions in 2035 and 2045. Gas and solar will account for the majority of the additional 59 GWs projected for 2045. When broken down by zone within PJM, VEPCO (Dominion) and AEP (American Electric Power) show some of the highest concentrations of resources. See a map of the zones here.
The Load Assumptions tell a similar story on the demand side. Dominion and AEP make up the majority of peak load in 2035 and 2045.
The presentation also included “Build Limits,” which outline the maximum MWs of solar and onshore wind that each zone can accommodate. These limits are based on zoning ordinances, environmental constraints, and national defense concerns. Dominion has nearly 358 GWs of theoretical capacity!
The presentation also features projections for Henry Hub natural gas prices extending through 2045. According to the base scenario, prices steadily rise and exceed $8/MMBtu in the 2040s. Finally, a fascinating visual can be seen in the full presentation, a synoptic view of retirements across PJM, broken down by Zone, state policy, and time.
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In Arkansas, Entergy Arkansas is receiving numerous inquiries about the estimated cost of the Jefferson Power Station (JPS) Project, which is a combined cycle combustion turbine. Currently, the pricing details remain redacted and confidential. In response to a “sub-surrebuttal” testimony to the commission (essentially a rebuttal to a rebuttal), Entergy defended its application by stating that its cost estimates for JPS are reasonable. They argue these estimates are comparable to and lower than those of five similar projects that have recently been approved or are being considered by other commissions across the country.
In Ruiz’s 1,128 page “sub-surrebuttal,” check the filings from the identified projects in the map above, starting on page 14.
If approved, the JPS project would bring 754 MW online in Jefferson County by 2029.
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In Georgia, Georgia Power submitted its second quarterly construction monitoring report for four utility-scale BESS projects: Moody, Robins, McGrau Ford Phase I and II, and Hammond Battery Energy Storage System. The utility reports that all projects are expected to be operational on or ahead of schedule. Cost details have been redacted.
All of the projects are Megapack 2 XL systems from Tesla. Moody and Robins will use local solar resources for charging, while McGrau and Hammond will charge from the grid. Take a look at this aerial photo of the biggest project, McGrau Ford:
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In New Mexico, commission staff provided feedback on PNM’s application for three new Power Purchase Agreements (PPA) and Energy Storage Agreements (ESA) concerning its Special Service Contract (SSC) customer.
“1. The Four-Mile Mesa PPA and ESA (100 MW solar and 100 MW, 4-hour Battery Energy Storage System (BESS)), 20-year agreement;
2. The Star Light PPA and ESA (100 MW solar and 100 MW, 4-hour BESS), 20-year agreement; and
3. The Windy Lane PPA and ESA (90 MW solar and 68 MW, 4-hour BESS), 20-year agreement.”
Staff has concerns regarding the impact of these resources on the PNM system.
"The difference is the magnitude of the power input from the SSC resources, and the fact that the combined generating capacity of those resources far exceeds the connected load (peak load) of the SSC Customer... the SSC Customer resources routinely input more power into the system than the SSC Customer’s peak load, potentially imposing a daily burden on PNM’s operations and driving potentially premature investments in new transmission and distribution that may not be fairly allocated in the future.”
According to staff, adding these resources would complicate system balance. This is mainly due to significant excess generation that PNM would need to manage in addition to the existing 450 MW of “must take” generation from the Palo Verde, Four Corners, and Luna power plants.____
At the North Carolina commission-initiated Large Load Technical Conference, Tyler H. Norris presented findings from his team’s research. A few key charts in the presentation underscore a central insight: greater capacity can be unlocked to support large load integration when load flexibility is introduced.
Norris outlined the projected ~50 GW supply-side gap in new gas-fired capacity needed to meet peak demand growth and reserve margin requirements through 2030. His analysis revealed that there is significant underutilization of system headroom outside of peak hours. On average, 10% of the system’s capacity is dedicated to handling only about 35 hours per year of extreme peak demand.
In North Carolina specifically, the balancing authorities of Duke Energy Carolinas (DEC) and Duke Energy Progress (DEP) operate with load factors of 55.6% and 48.4%, respectively. This load factor indicates how much of the system is being used. By unlocking just 0.5% of that load through curtailment, an additional 4.1 GW of available capacity across DEC and DEP.
When applied at a national scale, the implications are striking. Norris’s analysis shows that if new large loads could reduce their maximum uptime by just 1%, up to 126 GW could be interconnected. This presents a powerful and low-impact way to accelerate the integration of demand without relying on traditional supply-side buildout.
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In the Western Power Pool, the Western Transmission Expansion Coalition (WestTEC) recently shared updates on its 10- and 20-year transmission expansion plans. The coalition aims to finalize the 10-year report by the end of 2025 and then use those findings to develop a scenario analysis for a 20-year Horizon report, which is expected to be completed by September 2026.
The working draft of the 10-year report includes transmission buildout based on projects that are already scheduled to be operational by 2035 or earlier (an estimated $40 billion of investment). It also includes additional projects designed to address system reliability concerns arising from “stressed yet credible conditions,” as well as initiatives to facilitate “evolving but credible” interregional transfers, especially across the Cascades into the Pacific Northwest. The areas marked by orange circles on the map below indicate potential projects aimed at alleviating congestion.
Over a 20-year period, WestTEC provided the outputs of its capacity expansion model by region for three different scenarios. Below are the modeling results organized by region:
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In Oregon, a rare occurrence is taking place: Idaho Power has requested a rate decrease, set to take effect in 2026.
“More specifically, the Company [Idaho Power] requests to update customer rates to reflect (1) a decrease in rates due to the removal of coal-related costs at North Valmy Generating Station (“Valmy”) Unit 2, (2) a decrease in rates to return an outstanding regulatory liability related to the Boardman coal plant (“Boardman”), and (3) an increase in rates to recover the amortization of deferred 2023 wildfire mitigation costs. Combined, this yields a net revenue requirement decrease of $588,295, which equates to an overall decrease of 0.90 percent.”
This emergency backup generating facility, with a capacity of up to 92 MW, is designed to ensure uninterrupted power supply for the data center’s tenants.
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Back in North Carolina, plans to install new hydrogen-capable natural gas generation continue to advance. Duke Energy Carolinas and Duke Energy Progress (DEP) are moving ahead with preparations to file applications for a Certificate of Public Convenience and Necessity (CPCN). Last year, the Commission approved a joint application for the Person County Energy Complex combined cycle gas turbine. This project includes a 1,360-megawatt (MW) advanced-class combined cycle unit with selective catalytic reduction. It will be constructed at the site of the existing Roxboro Steam Plant in Semora, North Carolina. Once completed, the facility will house two gas turbine generators and one steam turbine generator.
This initiative is part of Duke Energy’s Biennial Consolidated Carbon Plan and Integrated Resource Plans. For more details on hydrogen integration and project execution, see Chapter 4. Execution Plan.