What's Happening in Energy highlights the most interesting findings from public utility commission filings.
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What's Happening in Energy highlights the most interesting findings from public utility commission filings.Subscribe below to get these insights delivered straight to your inbox:
What's Happening in Energy — Nov 14
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Starting in Texas, where the Electric Reliability Council of Texas has informed the Texas Commission that it plans to file two Nodal Protocol Revision Requests this month regarding the Dispatchable Reliability Reserve Service (DRRS), which is a proposed new ancillary service (AS). One would establish DRRS as an AS to help reduce uncertainty in supply and demand forecast and decrease the volume of Reliability Unit Commitments. The other request will outline a model of participation for Energy Storage Resources in DRRS.
Additionally, the report included a peak load forecast for ERCOT through 2030, as provided by Aurora. Below, we’ve placed ERCOT’s forecast covered in an earlier Halcyon’s What’s Happening in Energy (WHiE) side-by-side with Aurora’s.
Aurora’s 2030 load forecast is 105 gigawatts, while ERCOT’s forecast is 138 GW, and Texas transmission service providers project a peak load of 208 GW:
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Also in Texas, two sponsors for Texas Energy Fund (TEF) projects, Rockland Capital and Vistra Corp., have requested extensions to the initial disbursement deadline for their projects.
Rockland Capital is seeking an extension of the TEF loan closing date for their New Gulf peaking facility to September 30, 2026.
“The need for the delay is due to the fact that ERCOT market forwards have not kept up with rising costs, and as such, do not support near-to-medium term energy hedging at values that allow Rockland Capital, as the manager of the sponsor, to make a final investment decision.”
Rockland elaborated on the shortcomings of ERCOT forward prices: “The extension timing requested is meant to provide time for either the forward power markets to recognize the fundamental need for new generation resources in ERCOT via prices that support new build and can be hedged, or to allow for the origination of long-term creditworthy offtake.”
Vistra requested an extension for both of its 440 MW projects, Permian Basin I and II, to June 30, 2026.
“As the leading competitive generator in Texas, Vistra Corp. remains committed to these additions to support ERCOT grid reliability. However, as described in its full request submitted through the TEF Portal, market factors have materially impacted the ability to proceed with the current initial disbursement deadline of December 31, 2025. These market factors include extended contract negotiation to support the loan due diligence program.”
Read the letters from Rockland and Vistra below.
- Docket profile
- Rockland Capital request for extension
- Vistra requests for extension: Permian I and II
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In Florida, Duke Energy Florida (DEF) has proposed an adjustment to its Solar Base Rates to recover costs related to four new solar projects expected to be operational in 2026 and 2027: Banner, Jumper Creek, Lonesome Camp, Turnpike. The projects are part of the 2024 Settlement agreement between DEF and the Commission, which permits cost recovery for up to 900 MW of solar.
According to the utility analysis, the projects were evaluated based on four criteria outlined in the Agreement: 1) cost reasonableness; 2) benefit-cost ratios; 3) whether the facilities are 100 percent dedicated to serving DEF load; 4) impact on the revenue requirements. The results of the analysis indicate that the Cumulative Present Value Revenue Requirements (CPVRR) would be lower with these projects in place compared to without them. Additionally, the benefit-cost ratio of the projects through 2061 exceeds the 1.15 ratio stipulated in the Agreement.
All projects are below the 75 MW threshold, which allows them to bypass the certification required by the Power Plant Siting Act. Capital costs range between $1,500 -$1,800/kW-ac.
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Also in Florida, Florida Power & Light (FP&L) has filed a post-hearing brief regarding the Non-Unanimous Settlement Agreement reached with various parties concerning its petition for a four-year rate plan covering the period from 2025-2029. Some key points:
- Compared to the initial filing from FP&L in the rate case, the Settlement Agreement reduces the increase in annual revenues starting next year from $1.545 billion to $945 million, and in 2027 from $927 million to $705 million.
- The Agreement also reduces the ROE from 11.9% to 10.95%
(with an “authorized range” of 9.95% to 11.95%).
Furthermore, the briefing includes details on the storm cost recovery mechanism, procedures to adjust rates based on changes to tax law, EV charging services riders, solar and wind procurements, and the Large Load Contract Service tariff.
For detailed information on rate cases around the country and how key metrics evolve from initial filings, check out Halcyon’s recently announced Rate Case Tracker.
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In North Carolina, Duke Energy Progress (DEP) has applied for a Certificate of Public Convenience and Necessity (CPCN) to construct a 240 MW hydrogen-capable, F-class, simple-cycle combustion turbine (CT) at its Smith Energy Center. This new plant will supplement five other CTs at the site, with an anticipated in-service date of 2030. Duke explained that the additional capacity is necessary to meet the 22% reserve margin mandated by the Commission. The project was identified from DEP’s 2025-2026 Carbon Plan and Integrated Resource Plan (2025 CPIRP) Execution Plan and Near-Term Action Plan (NTAP), which projected “annual energy will increase by 19% from 2026 to 2030, requiring system capacity increases of nearly 2 GW.”
In the supporting exhibits, DEP included a map of the Smith Energy Center and its surrounding areas. To the east is the Energy Way Industrial Park, where Amazon has big plans:
Amazon will construct 20 data center buildings of 200,000 to 250,000 square feet each at the site, according to Roger Wehner, Vice President of economic development for the company, during the official announcement in June 2025. Mr. Wehner also said that construction of the data center complex should start within the coming weeks. The Energy Way Industrial Park is directly east of the Proposed Facility, as shown in Figure 1.1-2.
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In Kansas, the Commission approved the Unanimous Settlement Agreement for Evergy’s large load tariff Schedule LLPS. Commission Staff deemed that the tariff serves the public interest for the following reasons:
- The Demand and Energy rates in the LLPS tariff are designed to recover Evergy’s cost to serve LLPS customers, so existing customers are not subsidizing LLPS customers;”
- “Demand and Energy rates were designed to incentivize higher load factors and a more efficient utilization of the grid capacity required to serve these customers, allowing the existing fixed costs of the system to be spread over more energy billing determinants;”
- “The non-rate terms and conditions of the LLPS tariff are designed to protect existing customers from stranded asset cost risk, while not making the LLPS tariff uncompetitive with other existing LLPS tariffs across the nation;”
- “Several optional riders that LLPS customers can use to customize certain elements and characteristics of their electric service without burdening or harming others customers;”
- “Avoids the costly and time consuming process of a fully-litigated hearing.”
See the LLPS monthly pricing for the utility’s Kansas Central and Kansas Metro systems below. Customer charges in Central are half what they are in Metro, but the grid and demand costs are higher in Central than in Metro.
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In Michigan, there is another update on the Trenton Channel Energy Center battery energy storage system (BESS) project for WHiE superfans. The Commission approved DTE’s request to treat $19 million of payments made to Powin under an equipment service agreement (ESA) as a regulatory asset. DTE made these payments prior to Powin filing for bankruptcy in June 2025. Subsequently, DTE entered into a new ESA with another equipment supplier for the Trenton Channel Energy Center BESS project at a cost of $30 million less than the initial ESA. This BESS project was discussed in previous WHiE newsletters (8/28 and 10/31).
In its approval filing, the Commission noted that any claims DTE receives in the bankruptcy proceeding will be credited against the regulatory asset.
... Powin filed for bankruptcy on June 9, 2025, and in its application, the company states that it intends to file a Proof of Claim in Powin’s bankruptcy proceeding that will include all debts owed to DTE Electric from Powin, valued at no less than $19 million. Application p. 2. The company attests that the costs of any unrecovered Powin payments will not be allocated to the Project, that the company will not include the regulatory asset in working capital as part of rate base in any general electric rate case, and that it is not requesting carrying costs. Id., p. 3. DTE Electric acknowledges that it cannot predict the likelihood of recovery in the bankruptcy proceeding but confirms that any proceeds realized from Powin’s bankruptcy proceeding shall be credited against the regulatory asset.
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In Iowa, the Utilities Commission has granted MidAmerican’s application for a CPCN to construct a 518-MW gas peaker plant in Adair County. This plant will feature two combustion turbines that can blend up to 30% hydrogen. MidAmerican argues that this project is necessary to balance intermittent resources and to meet “high projected load growth.” The company estimates that the plants will run 200 to 310 hours per year with expected annual capacity factors ranging from 1-3% (Halcyon note: napkin math on 200-310 hours a year is 2.3-3.5% capacity factor, not 1-3%).
As of the end of 2024, MidAmerican owned 1,258 MW of natural gas facilities. This new project would increase the company’s natural gas capacity by 40%.
Additionally, the Commission waived certain procedural requirements for the application, concluding that “the public interest will not be adversely affected by waiving the scheduling and hearing requirements.”
See below a list of the project’s “major structures and components”.
Check out the docket profile with Exhibits and the Final Order below.
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In Indiana, Duke Energy Indiana (Duke again!) has filed testimony supporting its 2024 Integrated Resource Plan (IRP), which includes various intriguing charts, figures, and technical details behind the modeling. One interesting projection in the document concerns the historical and future system load factor. Duke anticipates that its system load factor will increase, as energy consumption is expected to grow at a faster rate than peak demand. This is primarily driven by “strong growth in the industrial and commercial sectors relative to the residential sector.”
From 2013-2023, load factor declined.
However, Duke projects an increasing system load factor from this year through 2044: +6.75% from 63.26% to 70.02%.
Also of note, a table listing “Generic Capital Costs” for the generation resources used in various model scenarios. Duke modeled everything from combined cycle plants at $1,450-$1,550/kW to Small Modular Reactors at $11,150/kW. According to the table, the earliest availability for a gas plant is 2030. On the other hand, a $12,300/kW 300 MW Advanced Reactor with 150 MW of Thermal Storage isn’t available until 2039.
- Docket profile
- Direct Testimony (see Appendix D for load forecast details and Appendix F for supply-side resources)
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In California, both Pacific Gas & Electric (PG&E) and Southern California Edison (SCE) have submitted draft reports for Part 2 of their Electrification Impact Study (EIS). Part 1 (published May 9, 2023; searchable in Halcyon) focused on primary investments in substations, feeders, and lines. In contrast, part 2 includes information on secondary investments in transformers and secondary lines.
PG&E’s Part 2 draft study indicated that increased electrification could exert “downward pressure on distribution rates of as much as ~25% by 2040” due to lower revenue requirements. Of the projected cumulative distribution costs, which range from $23 billion to $31 billion, $15B–$18B is expected to be associated with secondary infrastructure, while the remaining costs will be related to the primary system.
For Southern California Edison, the secondary system costs in the Base Scenario differ significantly from those of PG&E. Out of $13.179 billion in costs, only 6.7% ($884 million) are attributed to the secondary system.
SCE also provided charts that illustrate the total loading of distribution substations for future peak days, specifically September 6, 2030, and September 6, 2040, measured in GW across all four scenarios. For both peak days, the “Alternate D-Flex Case” shows a relatively large reduction in loading compared to the other scenarios. This case serves as “a theoretical upper bound to assess the maximum potential of demand flexibility for energy storage and electric vehicles in mitigating infrastructure needs across SCE’s distribution system.”
One other finding of importance: the City of Long Beach, through its Board of Harbor Commissioners (Port of Long Beach), has requested approval for the amended distribution Upgrade Projects Report And Known Loads Tracking Dataset Of 2025 Grid Needs Assessment. The total load growth for the Port is projected to be 313% between 2024 and 2033.
- Docket profile
- PG&E Electrification Impacts Study Part 2 Draft report
- SCE Electrification Impacts Study Part 2 report
- Port of Long Beach Request to Modify Load
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Bonus! In Iowa, the ~615 MW restart of the Duane Arnold Energy Center (DAEC) is progressing. NextEra Energy Duane Arnold, LLC (NEDA) is seeking a CPCN along with multiple waivers to recommission the nuclear reactor.
Currently, NEDA holds 70% of DAEC, while Central Iowa Power Cooperative (CIPCO) holds 20%, and Corn Belt Power Cooperative owns the remaining 10%. NEDA plans to purchase the additional interests from CIPCO and Corn Belt in the coming months, pending regulatory approval. The facility’s restart is not for NEDA’s own use; it is designated for exclusive use by CIPCO and Google Energy LLC through wholesale purchase power agreements.
NEDA is requesting a series of waivers. Some of these waivers are intended to initiate the physical security modification scope and others to demo existing structures, including cooling tower basins and a former sewer treatment center (as shown below).
