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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 21
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Let’s begin with South Dakota, where there is tug-of-war over which company can provide electrical service to a proposed rock crushing plant.
To find the answer, read the competing utilities arguments (click the link and try Halcyon’s recently released search + query sharing – note you need a free auth code sent to email and sometimes in spam).
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In Arizona, a proposed 159.5‑acre private natural‑gas power plant, along with an associated data‑center and backup generation development (two 500,000‑sf buildings, on‑site substation and 18 gas turbines totaling ~700 MW) called the Takanock Project Baccara, is scheduled for a hearing on December 1st. The project is located in an industrial area north of Luke Air Force Base (AFB). In October, Luke AFB submitted a compatibility review letter reviewing the proposed project. Although they are not the approval authority, Luke AFB highlighted actual and/or potential mission risks and hazards in their review. This letter was uploaded this week with a rejected stamp (see below).
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In the Southwest Power Pool (SPP), an acronym soup of a proceeding examines the wind and solar components of expected underprovision of energy. Get ready for it: it’s a presentation before the Supply Adequacy Working Group (SAWG), focusing on the system’s Loss of Load Expectation (LOLE) for the years 2030 and 2032. The analysis shows evolving system risk during specific times of day when low wind and solar collide with high load. In 2032, nearly 30% of the hours with Expected Unserved Energy (EUE) are expected to occur at 7 PM on hot summer days.
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In Texas, congestion, shade, and confusion. ENGIE has filed comments outlining concerns with Lone Star Transmission’s proposed 345-kilovolt (kV) transmission line in Jones County. This line is intended to connect the Phantom Hill substation with the 255 megawatt (MW) Tiger Solar (Vaca del Sol, LLC) project. Both assets are owned by NextEra.
ENGIE has expressed worries that its Anson solar projects, located along the route of the transmission line, would be impacted due to shading and congestion. Additionally, ENGIE contends that NextEra did not follow proper procedures when requesting ENGIE’s consent for the easements required to build the line. Another point of contention is the proposed $1 million compensation from Vaca del Sol to ENGIE.
“In this connection, Lone Star and NextEra provided us for review an “Impact Agreement,” whereby Vaca del Sol would compensate us $1,000,000 for the impact of its project, and an “Consent and Non-Disturbance Agreement,” which specified the terms of the easement desired by Lone Star. Our primary concern … was that Lone Star proposed that Anson waive its rights to the easement area and all damages arising from their use of the easement area; in response, Anson proposed a co-location clause whereby Anson could still access and utilize any of Anson’s improvements existing in the easement area, and a mutual non-disturbance agreement whereby each party would agree to not interfere with the activities of the other. The negotiations stopped when it became clear Lone Star would not agree to include such language in the easement agreement.”
In another filing from ENGIE, the developer expressed its concerns between Lone Star and its parent company.
“Yes, I think one thing that has been concerning is in our communications regarding this project, we do not know who we are communicating with, is it NextEra or Lone Star. As can be seen on many of the emails referenced in testimony, there appear to be people on the e-mail chain with Lone Star and NextEra email addresses. Even the testimony filed in this docket is from NextEra employees. This brings a general concern of what of ENGIE’s confidential engineering, and other information, is being shared with a competitive affiliate. Even the fact that Lone Star was negotiating for ENGIE’s consent to this line is unusual as normally these actions would be handled by the generator.”
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In Massachusetts, Berkshire Gas (BG) is seeking approval for a multi-year rate plan from 2026 to 2031, which includes a return on equity (ROE) of 10.35%. In support of this requested ROE, the Brattle Group explained that the multi-year plan would provide more certainty in recovering Berkshire’s projected capital expenditures. Capital recovery, according to the testimony, has been a major reason why it has been unable to achieve its ROE targets over the past few years.
The utility plans to forecast its annual capital expenditures at the start of each year, hold costs fixed during the year, and recover actuals at the beginning of the next year when the new forecast is submitted.
The testimony supporting the requested ROE included a quote from S&P regarding the industry’s broader struggles with capital cost recovery.
“We expect rising capital spending and increasing cash flow deficits that are not sufficiently funded in a credit-supportive manner will continue to pressure the industry's financial performance. Its average funds from operations (FFO) to debt was about 15% in 2021 and has gradually fallen to about 13.5%, primarily reflecting rising leverage (see chart 20). Given our expectations for continued increasing capital spending over the next decade, we expect financial performance and credit quality will continue to be pressured.”
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And for more ROE, Texas-New Mexico Power Company (TNMP) has filed its rate case requesting a 10.4% ROE and a rate base of $2.8 billion. The rate base increase is attributed to large capital additions that reflect significant investment needs (see direct testimony and table below).
And what is driving growth in TNMP’s capital budget? New customers, expanding existing customer load, and replacing facilities that are approaching the end of rated / useful life. TNMP states, “A significant driver of growth in capital budgets has been the dramatic load growth in the Permian and Delaware Basin regions of West Texas. This load growth resulted from many factors, including new oil and gas technology, discovery of new shale plays with low breakeven price points for developers, geopolitical events, and numerous other factors.”
How do "geopolitical events” impact load growth? Unclear. TNMP continues:
Looking at capital expenses (see Exhibit JNW-7) during the period 2025 to 2029, TNMP's capital budget increases from $609,106 to $1,007,780, or an average of 13.4% per year.
- Docket profile
- Application Petition and Statement and table of contents Volume 1
- Application Volume 3
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In Georgia, Commission Staff recommended that Commissioners approve, conditionally approve, and reject resources that Georgia Power has requested to certify as part of its 2029-2031 All-Source Request for Proposal (RFP). Regular Georgia observers will recognize a familiar, and expansive, redaction pattern.
Georgia Power’s Proposed Resources include:
- Company-Owned Projects (COP): include 15 proposed projects for 7,065 MW at a cost of $ billion comprising 3,692 MW of Combined Cycle (CC), 3,023 MW of Battery Energy Storage System (BESS), and 350 MW of Solar + BESS.
- Power Purchase Agreements (PPAs): include 11 PPAs for 2,821 MW comprising 1,150 MW of Combustion Turbine (CT), 975 MW of CC, 646 MW of BESS, and 50 MW of System.
Staff calculated the impacts on the revenue requirement if the above projects are certified. Projections indicate that the revenue requirement would increase by up to $3.4 billion.
Staff’s comment on the load growth assumptions behind the revenue requirements was stark: “Non-large load customers could experience significant harm if the Company were to commit to acquire the resources, and the new load and additional incremental revenues do not materialize.”
Staff recommended that the Commission approve two tranches of projects. The first would be fully certified to meet the load growth identified in the utility’s B2026 Load Forecast, based on contracts that have been signed as of October 8, 2026. This is referred to as the “Contracts-Only Large Load Recommendation.” The projects recommended for approval under this scenario include 3,125 MW with commercial operation date (COD) from June 2028 through December 2030:
For other loads in the B2026 forecast that execute contracts before March 16, 2026, Staff recommended “Conditional Approval” for the following projects worth 4,298 MW with a COD from November 2028 to November 2030:
Otherwise, according to Staff, “Should new large load contracts be executed after March 16, 2026, Staff would work with the Company on an expedited process to certify additional resources selected from the conditional approval list, or the Company could identify new resources in its 2032/2033 RFP.”
Dig into the filing below for more details on Staff’s modeling and the B2026 forecast.
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In PJM, the Pennsylvania Consumer Advocate (OCA) has proposed that PJM require large loads to “Bring Your Own Capacity” (BYOC). This would involve supplying generation, reserves, or demand response to cover their demand. While recognizing the economic development benefits associated with large loads, OCA argued that a BYOC mechanism would help prevent catastrophic grid failures and price spikes. Check out the disaster-maxxing introduction:
The number of examples of large-scale, catastrophic but preventable failures is long: the Hindenburg, the Titanic, the Challenger space shuttle explosion, the Deepwater Horizon oil rig failure, the Bhopal chemical disaster, the Chernobyl nuclear accident, the 2021 rolling blackouts in ERCOT, the Hyatt Regency Hotel walkway collapse in 1981, and many more. [emphasis added] After these failures occurred, causes such as political pressure and competitive haste were clear. Learning that these failures’ resulting injuries had been preventable only exacerbated the devastation felt by those affected and the public.
The equivalent type of failure need not occur in PJM…. The solution to mitigate this risk is clear: by adopting a mandatory bring your own capacity (BYOC) backstop, PJM can significantly reduce the risk of rolling blackouts and runaway wholesale electricity prices.
Read the full OCA proposal below and for a panoptic view of large load tariffs across the country, check out Halcyon’s Large Load Tariff Tracker.
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In California, Longroad Development Company, LLC is proposing to build and operate the Rosa Storage Project, a 1000 MW Battery Energy Storage System Generating Facility located in Moorpark. Queue Cluster 14 Interconnection Studies have been completed (use Halcyon Search to view), and as a result of those studies, the project has been assigned a share of Reliability Network Upgrades (RNU, where IRNU is interconnection and GRNU is general) of $18.8 million due this month. Per the transmittal letter, “It is SCE’s understanding that Interconnection Customer [Longroad] disputes the project payment schedule and requirement to post collateral to secure funding for its portion of the shared RNUs.”
In the transmittal letter from Southern California Edison (SCE) to FERC, there is some nonconforming language including:
- An UNEXECUTED Design, Engineering, Procurement, and Construction Letter Agreement with Longroad was submitted
- Future annual reassessments may identify additional upgrades.
- Termination impacts: Because of the project’s stage in the interconnection process, there are potential additional implications associated with the termination of the Letter Agreement than was contemplated in SCE’s pro forma agreement. In particular, pursuant to Section 11.3.2.6 of CAISO’s Appendix DD (GIDAP), termination of the Letter Agreement may result in Longroad’s Interconnection Request being deemed withdrawn.
- Shared Network Upgrade refunds are only provided if CAISO and SCE determine the upgrades are no longer required.
- Longroad cannot take delivery of materials purchased under the agreement, since the work involves shared upgrades essential to multiple projects.
More details below.
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In Arizona, the Administrative Law Judge has filed a Recommended Opinion and Order to approve the Settlement Agreement in Sulphur Springs Valley Electric Cooperative’s rate case. This agreement would increase its revenue requirement by $10.4 million to $144 million, with a 7.89% rate of return. A key update in the Agreement includes a freeze to the NM-1 net-metering tariff for non-commercial customers. Current customers would be grandfathered in under the old rates until either 20 years after the installation date or November 17, 2037. From here on out, all net-metering customers would be served under the new Distributed Generation Export Energy rate (DGEE).
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