What's Happening in Energy highlights the most interesting findings from public utility commission filings.
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What's Happening in Energy — Jan 23
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In Pennsylvania, the Public Utility Commission approved a Settlement Agreement to establish a revenue increase of $1,391,327 for Citizens’ Electric Company of Lewisburg. Although the Settlement was non-unanimous, the approved increase was below the utility’s initial request of $1,794,525 (22% and 15% decrease from the initial and revised request respectively).
A Halcyon query provided the following key changes between the original and approved increases:
The settlement captured many adjustments the Office of Small Business Advocate (OSBA) and other parties advanced (including reductions to requested return on equity, size factor adjustment, corporate net income tax rate, generation-related costs, general inflation factor, and rate case expense), which were largely reflected in the negotiated revenue increase.
Review (and revise) the Halcyon query to learn more!____
In Oklahoma, Public Service Company of Oklahoma (PSO), owned by American Electric Power (AEP), responded to the state Attorney General’s proposal to cap costs at $540 million for its proposed 450 megawatt (MW) natural gas simple cycle project Northeast 5 and 6 (NE 5&6). PSO stated,
As with all major power generation projects, … potential unknown risks … could increase … a cost estimate, such as market disruption events associated with supply chain, labor availability, hyperinflation, and changes in law. Although a $44 million dollar contingency is included … it does not account for all of them nor does it account for extreme circumstances[…]. [T]he Company must be granted flexibility to prudently manage its investment in NE 5&6 in order to provide reliable, economic, compliant, and safe service to its customers.
PSO also plans to build battery energy storage systems (BESS) Northeast 1 and 2 alongside the gas turbines. However, in November 2025, Rogers County Board of Adjustment denied PSO’s request for a zoning change to accommodate the projects. AEP has appealed and the project is in legal limbo: “PSO does not plan to commence construction at the Northeastern site until after the conclusion of pending relevant legal matters. PSO has filed a Notice of Appeal with the Rogers County Court Clerk, the Clerk of the Board of Adjustments, and the County Clerk to preserve its rights and options.”
Dig through the trove of rebuttals and exhibits in the docket profile below.
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In MISO, stakeholders are discussing the concept of a “Zero-Injection Generator Interconnection Agreement” (ZGIA) for large loads. This type of agreement would allow large loads to co-locate with resources that offset load without injecting power into the grid. Such an arrangement could mitigate the need for network upgrades identified through the MISO Transmission Expansion Plan (MTEP) study process. Check out the graphic produced by MISO below outlining the two paths a large load could follow with or without a ZGIA.
Next procedural steps include discussion regarding the extension of ZGIAs across multiple points of interconnection, contractual arrangements between loads and resources, and other modeling implications.
Halcyon note: we are idly wondering exactly how “ZGIA” will be voiced: as an acronym (like NASA) or as initialism (like LGIA). Our preference: an acronym, said as either “Ziggy-Ahh” or “Zzzz-Ghia” 🤔
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Continuing with large load interconnection, in Texas, Public Utility Commission Staff released a set of questions (attachment B) and a 2nd Discussion Draft (attachment C) with an interconnection timeline (see below). Following a January 9th workshop, stakeholders are submitting comments on these materials. Run this Halcyon query to identify areas of agreement with staff recommendations, proposed alternatives/modifications, and objections.
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In Vermont, Green Mountain Power’s (GMP) submitted extensive exhibits this week for its four-year regulation plan (FY27–FY30). One notable proposal is the Integrated Energy Storage Pilot: a $7.2 million program installing 300 whole-home backup energy storage systems as a resiliency alternative on remote areas of the grid. The pilot has an overall benefit cost ratio (BCR) of 1.11, indicating that benefits outweigh the costs.
The battery pilot and other resilience proposals respond to GMP’s rising storm restoration costs, which spiked in 2023 and 2024 (Figure 14 below). Over the past decade, average annual storm costs were $24.3M, and increased $2.6M per year using the slope of the linear trend line.
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In California, Southern California Edison (SCE) filed comments arguing its case against the Commission’s Decision authorizing a “one-part post-test year ratemaking (PTYR) mechanism” to establish SCE’s revenue requirement. The utility argued that this mechanism inappropriately treats capital and operation and maintenance (O&M) expenditures the same, resulting in significant under-recovery of capital expenditures. SCE provided the following tables quantifying the underrecovery for a $100M capital expenditure.
The utility added another table showing the compounding underrecovery from making $100M capital expenditures each year from 2025 through 2028. The revenue shortfall in 2028 reaches almost $40M.
Read the full arguments from SCE in the filing below.
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In Kansas, Liberty-Empire (Liberty), a power utility (but water, sewer, and other utility services in other jurisdictions), applied for approval of its Annual Cost Adjustment (ACA) to recover costs associated with fuel and power costs in Kansas. Supporting testimony included the following table showing the utility’s energy costs during the 2024-2025 ACA period. Notably, the same energy source showed the greatest price variation—Wind and Hydro delivered the lowest average cost while Wind (in PPA form) commanded the highest.
Digging in even more, for the “Energy Cost” column, the utility added the following footnote to clarify what the dollar per megawatt-hour figure represents: “This is the cost of Liberty’s resource generation for November 2024 through October 2025 and excludes: the cost of fixed gas transportation, resettlements and adjustments, purchased power agreement (PPA”) demand charges, environmental costs, the cost of consumables, SPP IM costs and revenues and generation plant O&M (except the PPA’s)”
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In Illinois, a filing stating Ameren is rejecting 90-95% of clean energy interconnection applications on Ameren’s distribution system using a metric that community solar and storage developers say is technically inappropriate. The utility policy in question prohibits the interconnection of distributed energy resources (DER) with a “Weighted Short Circuit Ratio” (WSCR) under 10. The developers argue the WSCR metric is a transmission-level standard originally designed for ERCOT wind farms, not distribution systems. They continue that the threshold of 10 is arbitrary and excessive, violating 83 Ill. Adm. Code Part 466, sections of the Public Utilities Act, and impeding progress towards the state’s 100% clean energy by 2050 goal.
“The WSCR is not suited for distribution-level DER projects. Unlike transmission systems, where synchronous generation and short-circuit strength dominate stability concerns, distribution systems are primarily influenced by local loads and line configurations. Additionally, distribution-level solar projects use different equipment and have points of interconnect that are electrically distant and dispersed throughout the distribution grid. Ameren has not drawn boundaries for study and instead adopted a uniform standard for the entire Ameren distribution grid covering most of central and southern Illinois.”
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In PJM, a wonky discussion to correct incentives where demand response (DR) resources can profit regardless of performance–a flaw that undermines grid reliability. To address this, PJM proposed penalizing DR that do not perform as expected during Non-Performance Assessment Intervals (Non-PAI) at 50% of the standard rate. However, the Independent Market Monitor (IMM), Monitoring Analytics, argues this penalty is too weak to change behavior and “will not provide effective performance incentive” because even with “zero performance…it is profitable to sell load management.” As the IMM’s table shows (below), even a 100 MW resource with zero performance would face penalties of only 12.2% of the revenues from the PJM capacity market (RPM revenues), still leaving load management profitable despite non-performance.
Voltus, a virtual power plant operator, also weighed in with its own proposal for PJM to set a percentage of the PAI penalty for the Non-PAI penalties based on the expected number of non-PAI hours and a “discount factor” selected by PJM. This discount factor, Voltus argued, would reduce the penalty based on the RTO’s judgement of the relative “reliability impact” of non-PAI to PAI hours since the full penalty is supposed to recover the theoretical cost of reliable replacement capacity (Net Cost of New Entry or Net CONE). See the hypothetical matrix of percentages below provided by Voltus.
Dig into the full proposals from each stakeholder below. And check out the Halcyon query that explains the distinctions between the two approaches more deeply.
The chart below shows projected reliability performance: the yellow line represents the As-filed Scenario and the almost indistinguishable purple and pink for Flat SAIDI and Reverse the Trend Scenario (the line closer to the X-axis), respectively.
Contributing to reliability challenges is Ameren's aging wood pole infrastructure (Figure 4)—an increasing number of assets are entering vulnerable age cohorts each year.