What's Happening in Energy highlights the most interesting findings from public utility commission filings.
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This week:
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What's Happening in Energy — July 24
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Large Load // Proposed Tariff // Public Service Company of Oklahoma
The Public Service Company of Oklahoma (PSO) submitted a proposed Large Load Power (LLP) tariff to the Oklahoma Corporation Commission. The tariff includes minimum contract capacity of 75 MW, minimum contract length of 10 years with a ramp period of up to five years, a System Contribution Charge, and collateral and exit fee requirements.
In late June, Google, the Public Utility Division, and the Petroleum Alliance of Oklahoma presented an alternative tariff proposal in a Joint Stipulation and Settlement Agreement. The Agreement Tariff would have allowed customers to fully or partially self-supply its own generation service and exempted them from a System Contribution Charge unless approved by the Commission. The Agreement Tariff was questioned by PSO as to “whether there can be a purported ‘settlement agreement’ that does not include the Applicant in the case.” Curious about the differences between the Agreement and Proposed Tariff? Response here.
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Large Load // Ex parte Signal // Google and Pacific Gas and Electric
The California Public Utility Commission granted Pacific Gas and Electric (PG&E) an ex parte meeting with representatives from Google. This was filed in the docket concerning PG&E’s application for approval of Rule 30, which would govern transmission-level interconnection of high-demand customers.
Halcyon angle: Here’s a five-minute research angle we took to follow up on this filing. We navigated to the docket and asked Halcyon to describe “any comments or procedural actions taken by Google in this proceeding.” From the response, we learned that Google had expressed concerns about “Type 4” payments under Rule 30 in another ex parte filing. So, we asked Halcyon “What are Type 4 payments?” Check out the response.
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NYC Peak Needs // Proposed Solutions // Consolidated Edison
Consolidated Edison (ConEd) will need 125 MW of capacity in the New York City area (NYISO Zone J) by 2033. That reliability need will rise to 675 MW in 2036, per ConEd’s ten-year planning file in its Reliability Contingency Plan.
One of the proposals the utility is putting forth to procure this capacity is the Reliability Asset Dispatch Rights (RADR) program. Under the framework of this program, existing resources on the Value of Distributed Energy Resources (VDER) tariff could transfer to the RADR program through a competitive process. According to the utility, the RADR program would reliably provide more dispatchable resources to meet its reliability needs and…
“Participating developers will execute 15-year RADR contracts with the Company, relinquishing their VDER rights and obligations in exchange for predictable, performance-dependent payments. This transition can benefit customers by repurposing batteries seeking to operate under VDER into a reliability-driven RADR framework that can more reliably help address transmission security needs and provide additional economic value that customers do not receive under VDER.”
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Upcoming Capacity Market Inputs // Shifting Seasonal Peaks // PJM
Although PJM is still unpacking the results of the most recent capacity market, a presentation filed ahead of the RTO’s upcoming meeting of the Markets and Reliability Committee on July 28th sheds important light on the inputs to the next capacity market (the Base Residual Auction (BRA)) in 2029/2030. The load scenarios underpinning the auction contained an interesting dynamic: summer extreme loads are lower in 2029/30 (blue dots) than 2028/29 (red dots), and winter extreme loads are higher. Why? Data centers and heating electrification increase load in the winter, while rooftop solar decreases summer peaks.
On the left is the percentile of modeled summer peaks in both service years. On the right, is the same plot but for the winter. Note that the auction years switch places.
This increasing risk in the winter leads to a decrease in Effective Load Carrying Capability (ELCC) Class Ratings for the resources that perform worse during the winter hours. Many resources have decreased ELCC ratings in the 2029/30 BRA relative to 2028/29.
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Integrated Distribution System Planning // Connecticut PURA
The Connecticut Public Utilities Regulatory Authority filed a Proposed Final Decision outlining the structure of Integrated Distribution System Plans (IDSPs). If approved, Connecticut utilities would have to file IDSPs every four years or three to six months prior to filing a rate case. The regulator would then hold the utilities accountable to their IDSPs for the purposes of their performance-based ratemaking.
Halcyon angle: Use Halcyon to ask targeted questions about this filing. For example, 1) to learn about the proposed filing frequency, 2) the forecasting requirements, 3) the stakeholder process, and 4) the structure of the plans.
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New Combined Cycle Plant // Rockport Energy Center // Indiana Michigan & Power
Indiana Michigan & Power (I&M) applied for a Certificate of Public Convenience and Necessity to construct a 1,520 MW combined cycle plant called the Rockport Energy Center at the site of an existing coal plant in Spencer County, Indiana (docket profile). The plant will consist of “four General Electric Vernova (GEV) 7F.05 combustion turbines (CTs), two GEV D-600 steam turbine generators, and four heat recovery system generators (HRSGs) with integrated selective catalytic reduction (SCR).”
Company testimony included an analysis of the expected impact on customers’ bills. The expectation is that as “industrial loads become a much larger share of overall system usage, both the allocation of costs and the associated revenue responsibility shift toward the Industrial class. This shift reduces the portion of the revenue requirement that must be recovered from Residential and Commercial customers...”
Here’s the table for the cost of service in the first couple of years after the facility is placed into service in 2030.
The company projects that residential and commercial bills, however, will decrease throughout the decade and even in the first couple of years after Rockport is placed into service. Here’s a table of the class allocation factors over the same time span.
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Xcel’s Short-term Resource Adequacy // Procedural Steps and PUC Requests
The Colorado PUC set intervening parties and directed Xcel to file a procedural schedule for its application to approve its preferred resource adequacy portfolio.
Xcel’s Preferred Portfolio includes:
The Commission also requested that Xcel explain why its June 2026 large load forecast diverged so much from the forecast it provided in response to the Just Transition Solicitation (JTS), “compared to the large load forecasts ... put forth in its rebuttal testimony in the JTS and the monthly large load report from June 2026, the projected additions from large loads appear to be approximately 700 MW lower for 2026 and 1,400 MW lower for 2027.”
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Batch Zero // Study Assumptions // ERCOT
ERCOT released a presentation with a consolidated summary of the deliverables, study assumptions, and stability screenings for its Batch Zero Interconnection Study. Here’s a list of the load forecasts that ERCOT will use in the study:
See here for all the gory details.
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System Outlook Report // ISO-NE
While New England may not be the hottest market for data centers, it is not immune to electrification. Over the next ten years, winter peak demand is expected to converge with the summer peak primarily because of heating electrification. Check out this recent presentation for more charts on the ISO’s outlook.
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Winter Icing // Route Permit Amendment // Xcel Energy // Minnesota
Xcel requested an amendment to its route permit for the Sherco Solar East Block High Voltage Transmission Line (HVTL). Why? “The icing on the Sherco Solar East Block HVTL results from water vapor plumes from the nearby Unit 1 cooling towers blowing onto the lines and freezing when westerly winds combine with temperatures below 20 degrees Fahrenheit…”
Here’s a field worker’s hand held up for scale to show the ice.
The line would return to the normal route after Sherco Unit 1 ceases operations. Unit 1 was originally slated to shut down in December 2026. However, “...observed circumstances at the federal level could result in the Unit being required to continue to operate beyond that date.”
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Rate Case // Arizona Public Service
Arizona Public Service (APS) recently submitted a stack of testimonies for its latest rate case. Its last rate case was based on a test year ending June 30, 2022…which was before ChatGPT was released. Citing new load growth and external cost pressures, APS is asking for a 13.99% increase in its rate base to cover new infrastructure. This includes new generation, such as expanding the Sundance peaker plant with two new GE Vernova LM6000 turbines and improving the cooling capacity of the Redhawk combined-cycle gas turbine to improve year-round operation.
APS CEO Theodore Geisler calls out Microsoft by name in testimony, defending APS’s internal cost recovery methodology and rejecting Microsoft’s claim that APS must reform its interconnection process for load. He argues that APS’s bottleneck is capacity, not transmission, and that because FERC is also looking at large load rulemaking courtesy of its October 2025 ANOPR (which has now turned into show-cause orders for RTOs), there’s no point changing tack until FERC gives a clear answer.
Catch up on the docket here.
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New Dockets of the Week
At the FERC, the docket for what could be the country’s largest electric utility has been opened: the NextEra-Dominion merger. Interventions are coming in, and application materials have been submitted. Set an alert on this one by clicking “Create Alert” in the top right corner.
Public Comment Excerpt(s) of the Week
In Ohio, the PUC’s Office of the Federal Energy Advocate filed comments on PJM’s governance challenges ahead of the July 23 technical meeting. It’s a great read on how states feel about the control that transmission owners have on the RTO’s stakeholder process. Here’s an interesting excerpt:
“The Ohio FEA strongly supports the ability of the PJM Board to act independently when necessary and encourages the Commission to position the PJM Board similarly to other RTO/ISOs across the country in this regard...components of PJM governance such as the energy and ancillary services markets, emergency procedures, and regional transmission planning are contained in PJM’s Operating Agreement (OA) where filing rights under section 205 of the FPA are held by the PJM Members. As a result, the PJM Board cannot act independently to change components of the OA without a threshold of 2/3 support from the PJM Members…Although the Members provide valuable input in the stakeholder process, the PJM Board should be able to render independent decisions on the matters before it, as is the case in other RTO/ISOs.”
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