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.
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What's Happening in Energy — Aug 22
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Starting in Maine, with a quick look at how developers are managing “good cause” exemptions for participating in the state’s Net Energy Billing (NEB) program for 1-2 megawatt projects. These exemptions are granted to developers that experience delays outside of their control, without which projects would have met the statutory deadline to participate in the NEB program.
Commission staff recommended granting the request from MSD Sanford LLC and Hanson Ridge Solar LLC because of delays in the delivery of switchgear equipment that the Commission deemed were “outside of its control and but for which it would have been able to reach commercial operation by the statutory deadline of December 31, 2024.”
On the other hand, Staff denied the request from Trenton Solar Development, arguing that the delays were not outside of the developer’s control, the need for substation upgrades was anticipated well in advance, and that the delays were within the ““the vicissitudes of the normal interconnection process.”
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In PJM, market operations staff outlined a proposal to allow new large loads above 50 megawatts to voluntarily participate as “Non-Capacity Backed Load” (NCBL). PJM would remove these loads from the capacity market auction (also known as the Reliability Pricing Model, or RPM), thus allowing these loads to opt out of paying their share of capacity market costs in exchange for the RTO directing them to “areas as required to maintain reliability” and triggering curtailment during pre-emergency conditions.
Chart: 2,500 MW of NCBL would push the Variable Resource Requirement (i.e. the demand curve of the PJM capacity market) curve to the left. This means that less supply is needed to meet the RTO Reliability Requirement, which could lower clearing prices.
In an example with 4,000 MW of total NCBL and an RPM clearing price of $325/MW-day, calculations indicate that large loads under the NCBL category could run backup diesel units up to 417 hours/year and still pay less than they would pay under capacity market obligations.
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Also in PJM, staff presented updated “Cost of New Entry” (CONE) values for combustion turbine (CT), combined cycle (CC), and Battery Energy Storage System (BESS) technologies. Values for both Gross and Net (adjusted for energy and ancillary revenues) CONE values decreased across the board. Costs here are “overnight capital costs.”
Primary drivers in reduced Gross CONE include updated technological and operational assumptions related to inlet pressure, wet compression, and “GE operating parameters.” The Brattle report referenced by PJM also considered updated “bonus depreciation from the One Big Beautiful Bill Act.”
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There are many more tables and assumptions in the presentation below.
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In New Jersey, CEP Renewables petitioned the Board of Public Utilities to waive three eligibility requirements for the state’s Community Solar Energy Program (CSEP):
- The five megawatt ceiling for eligible projects;
- The prohibition on “co-located” projects;
- And, the requirement to receive interconnection approval from the utility prior to application for its 190 MW of solar projects.
The developer emphasized the need for these waivers to expedite the interconnection of solar in light of the expiration of federal investment tax credits at the end of 2027, the upcoming expansion of the CSEP program to 3,000 MW, and NJ’s stated goal of redeveloping contaminated sites with renewables.
CEP also recommended extending these waivers “to all contaminated sites and landfills” to create more land eligible for development.
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In Georgia, the Public Service Commission and Georgia Power (the Company) agreed to stipulations regarding the approval of two Company requests: 1) to certify five (5) power purchase agreements for utility-scale solar PV projects totaling 1,068 MW competitively procured through the Company’s CARES 2023 RFP; 2) to approve an additional sum of $4 per kW-year for the term of the PPAs.
Read up on the background of the stipulations in the docket profile below.
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In Florida, the Public Service Commission approved Duke Energy Florida’s (DEF) request for a determination of need to construct a 26.5-mile, 230-kV transmission line that would connect DeLand West substation in Volusia County to the Dona Vista substation in Lake County. Key figures included a table projecting 25% load growth over the next 10 years for the Dona Vista load area, a project map, and a table detailing project costs ($168 million).
Project map:
Load forecast:
Project costs:
Exhibits also included DEF’s response to the Commission’s question regarding deploying generation as a “non-transmission alternative” to achieve similar reliability goals. DEF responded that the costs of simple cycle combustion turbines to serve the need would exceed $500 billion, well above the $165 million price tag for the transmission project, assuming a $1,800/kW cost for simple cycle CT.
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More in the Sunshine State: Florida Power and Light (FPL) submitted an application to the Public Service Commission to issue and sell long-term debt and equities up to $8.6 billion in 2026 and short-term securities up to $5.6 billion in 2026 and 2027.
FPL included a table of expected construction expenditures in 2026 and 2027 to support its application.
The Commission acknowledged receipt and FPL requests taking up the matter for the Agenda Conference on October 7, 2025.
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In SPP, more interconnection queue reform. FERC approved SPP’s proposed Tariff revision that would allow generators to apply for “interim interconnection service” without having an active interconnection request, or waiting until the next Definitive Interconnection System Impact Study (DISIS) cluster opens to apply for interconnection. Such interim service would allow generators to interconnect at less than maximum capacity prior to the completion of full system upgrades, allowing the RTO to interconnect resources faster.
Excerpt from FERC’s approval:
“Thus, we find that SPP’s proposed Tariff revisions will provide additional flexibility for interconnection customers by allowing interconnection customers to submit requests for interim interconnection service when the DISIS queue cluster window is closed, which may enable such interconnection customers to obtain interim interconnection service sooner than possible under the existing Tariff. Accordingly, we find that SPP’s proposed Tariff revisions meet the independent entity variation standard because they are just and reasonable, not unduly discriminatory or preferential, and accomplish the Commission’s purposes of Order No. 845 by making it possible for interconnection customers to obtain interim interconnection service sooner than would otherwise be possible.”
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In Iowa, the Utilities Commission approved a request from Goldinch Solar to amend its Certificate of Public Convenience and Necessity (CPCN). The amendment removes a stipulation requiring that construction of the 200 MW project be complete by November 16, 2025, two years after the issuance of the CPCN. Goldfinch Solar requested this amendment due to “delays with the Midcontinent Independent System Operator interconnection study process and because of other constraints.” In lieu of this deadline, the Commission has ordered the developer to submit status reports every 6 months.
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And finally in Alaska, Chugach Electric Association submitted a request to the Regulatory Commission of Alaska to increase rates by a system average of 3 percent for retail customers. The utility seeks to increase its revenue requirement by $11.1 million. Chugach also proposed a new Economic Development Rate (EDR) “to encourage commercial customers to locate or expand operations within Chugach’s service territory, thereby promoting regional economic growth.”
Customers with a maximum new or incremental manufacturing demand between 1 and 5 MW would be charged at the currently applicable rates, with a new discount on the demand charge, starting at 20% in the first year and decreasing down to 2% over a maximum 10-year contract length.
