Settlement Concerning Pennsylvania Utilities' Default Service Includes Move To Six-Month Fixed Rate (From Three Months Fixed) For Mass Market Customers -- EnergyChoiceMatters.com

Settlement Concerning Pennsylvania Utilities' Default Service Includes Move To Six-Month Fixed Rate (From Three Months Fixed) For Mass Market Customers

Settlement Would Terminate Ability For Customer Assistance Program (CAP) Customers To Shop

Settlement Removes 3- and 6-Month Supply Products From Commercial SOS Portfolio, In Favor Of Longer Contracts

Settlement Includes New Utility-Offered Time Of Use Generation Rate Option For Non-shopping Customers

Termination Date Placed On Current Customer Referral Program

April 22, 2022

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Several parties have filed a settlement concerning the proposed default service plan of the FirstEnergy Pennsylvania utilities ("the Companies") which would govern default service for the period June 1, 2023 and ending May 31, 2027 (DSP VI)

Settling parties include the FirstEnergy EDCs (Met-Ed, Penelec, Penn Power, and West Penn Power), the Pennsylvania PUC's Bureau of Investigation and Enforcement, the Office of Consumer Advocate, the Office of Small Business Advocate, Constellation Energy Corporation, Shipley Energy, and several industrial customer groups, among other parties. The settlement avers that Calpine Retail Holdings, LLC (Calpine), the Retail Energy Supply Association (RESA) and NRG Energy, Inc. (NRG), and John Bevec and Sunrise Energy, LLC (collectively, “Sunrise”), which are parties to the proceeding, have authorized the Joint Petitioners to represent that they do not oppose the Settlement

Default Service Procurement

The settlement does not propose any change in the default service customer classes or cut-off points for each class.

The settlement provides that, except for the long-term solar procurement discussed below, the Companies will procure 100% of the supply required to serve residential and commercial default service customers during the DSP VI Term through a descending clock auction ('DCA') for full requirements service as such is currently constituted at the EDCs (e.g., excluding certain transmission costs noted below)

For the first year of the DSP VI Term, contracts for 76% of the residential class load will have terms of 12 months, and contracts for the remaining 24% will have terms of 24 months. Beginning on June 1, 2024, contracts for 51% of the residential class load will have terms of 12 months, and contracts for the remaining 49% will have terms of 24 months.

During the DSP VI Term, the Companies will also procure – through multi-year, fixed-price power purchase agreements ('PPAs') – the energy and solar photovoltaic alternative energy credits ('SPAECs') generated by one or more new in-state solar photovoltaic projects with total capacity of at least 7 MW and up to 20 MW. The winning project(s) will be selected through a competitive procurement process. The energy generated by the selected project(s) will be paired with spot purchases to satisfy a fixed quantity of residential default service load.

Under the settlement, the full requirements contracts for the commercial class will include a fixed price for 100% of the supply and will be procured through DCAs in the same manner and at the same time as the residential class.

However, the settlement would eliminate both three-month and six-month contracts from the commercial default service supply portfolio

Instead, for the first year of the DSP VI Term, the commercial class full requirements product mix will be comprised of 12-month contracts (74%) and 24-month contracts (26%). For the second year of the DSP VI Term, the commercial class full requirements product mix will be comprised of 12-month contracts (49%) and 24-month contracts (51%). Beginning on June 1, 2025, contracts for 51% of the commercial class load will have terms of 12 months, and contracts for the remaining 49% will have terms of 24 months.

The settlement provides that each of the residential and commercial full requirements products will be procured through semi-annual auctions in April and November each year, and the first auction of the DSP VI Term will be held in November 2022

The settlement would not include a 'hard stop' in terms of procured SOS supply at May 31, 2027 as originally proposed by the Companies. Instead, the settlement calls for overhanging full requirements contracts that cover the period of June 1, 2027 through May 31, 2028 (the first year of the Companies’ seventh default service programs).

Under the settlement, the industrial class product is an hourly-priced service product based upon PJM real-time zonal hourly market prices. Suppliers will bid for the right to serve a portion of the hourly-priced service load for twelve-month terms. Winning suppliers will be paid the winning price bid in the hourly-priced auction, the hourly PJM real time zonal locational marginal price ('LMP'), and a fixed adder of $4/MWh to capture the estimated costs of other supply components, including capacity, ancillary services, AEPS compliance and other costs.

Price To Compare (PTC)

Under the settlement, default service rates established pursuant to the Price to Compare (PTC) Riders for residential and commercial customers will consist of a single per-kWh energy charge, which will change semi-annually instead of quarterly.

These rates will continue to recover: (1) generation costs, transmission costs (excluding NMB charges described below), and ancillary service costs; (2) supply management and administrative costs, as provided in 52 Pa. Code § 69.1808; and (3) applicable taxes.

In addition, the default service rates will include a reconciliation component, or 'E-Factor,' to recoup or refund, as applicable, under or over-collections from prior periods.

The settling parties agree that over/undercollections of default service costs for the residential and commercial classes will be reconciled on a semi-annual instead of a quarterly basis

Time Of Use Generation Rate Option

The settlement includes a new Time of Use generation rate to be offered by the FirstEnergy utilities to non-shopping customers. Currently, the FirstEnergy utilities comply with a statutory requirement for a TOU default service rate by relying on retail suppliers

Specifically, under the settlement, during DSP VI, the Companies will offer new TOU default service rate options for eligible residential and commercial customers to comply with the Companies’ obligations under Act 129 of 2008 ('Act 129') to offer TOU and real-time rates to all default service customers with smart meters.

The Companies will source both the standard and TOU default service for residential and commercial customers from the same supply portfolio for each procurement class. The Companies will use the standard default service price as calculated in the PTC Riders as the reference price by class for their TOU rate calculations.

The TOU default service rates for each Company will be determined by multiplying the PTC Rider rate by the multiplier for the applicable customer class and TOU pricing period.

The TOU rate will be three parts (on-peak, off-peak, and super-off peak). While varying by utility and customer class, generally the multiplier to the PTC rate to arrive at the TOU rate is 2x for on-peak, ~0.75 for off-peak, and ~0.55 for super off-peak.

The TOU periods will be fixed year-round. On-Peak would be 2 p.m. – 9 p.m., Monday through Friday, year-round

More specifics on the TOU time periods and multiplier rates can be found in this section of the settlement (click here)

The Companies will recover the costs to implement their revised TOU Riders from customers through the PTC Riders.

Customer Referral Program (CRP)

Under the settlement, each Company’s CRP, as it is currently operated, will terminate as of May 31, 2027.

In their default service filing for the period commencing June 1, 2027, the Companies will address whether a successor CRP program should be implemented and is necessary and provide the reasons for their proposal.

The Companies will provide the option for customers to enroll in the CRP through the Companies’ website no later than June 1, 2023.

The CRP enrollment fee to be paid by EGSs will remain at $30 per customer enrollment for those enrollments completed by the Companies’ third-party service provider. There will be no EGS fee for those customers who elect to utilize the Companies’ web enrollment program to participate in the CRP without using the third-party service provider.

Within 90 days following entry of the Commission’s final order at these dockets, the Companies agree to convene an initial stakeholder collaborative open to the signatories of this Settlement to explore the compilation of metrics related to the Companies’ CRPs. Thirty days prior to the initial CRP collaborative meeting, the Companies will provide potential fields for data collection to begin at the start of the DSP VI Term on June 1, 2023.

POR Clawback Charge

The settlement provides that, as of June 1, 2023, the clawback charge will no longer be a pilot provision of the Companies’ POR programs.

Under the settlement, the Companies will continue to use a two-prong test to determine the clawback charge. The first, as described in testimony, will identify those EGSs whose average percentage of write-offs as a percentage of revenues over the twelve-month period ending August 31 each year exceeds 200% of the average percentage of total EGS write-offs as a percentage of revenues per operating company. The second prong of the test will identify, of those EGSs identified in the first test, EGSs whose average price charged over the same twelve-month period exceeds 150% of the average price-to-compare for the period. For those EGSs identified by both prongs of the test, the annual clawback charge assessed each September would be the difference between that EGS’s actual write-offs and 200% of the average percentage of write-offs per operating company.

CAP Customer Shopping

The settlement provides that, effective June 1, 2023, all customers enrolled in the Companies’ CAP are required to be enrolled in default service at the applicable PTC.

Currently, CAP customers may shop and take service from a competitive retail supplier, subject to a price cap

The settlement provides that the Companies will develop a letter to be sent to all CAP customers enrolled with an EGS notifying those customers of the pending change to the program rules and their options related thereto. The letter will be available in English and Spanish, and will inform CAP shopping customers of the following:

• All CAP shopping customers are required to return to default service by June 1, 2023 in order to remain enrolled in the Companies’ CAP.
• CAP shopping customers have the choice to voluntarily withdraw from CAP by June 1, 2023, if they wish to remain with their current EGS.
• CAP shopping customers who take no action by June 1, 2023 will be automatically returned to default service and will remain enrolled in CAP without interruption.
• CAP shopping customers will not incur any early cancellation, termination, or other fees if they choose to return to default service and remain in CAP.

The settlement provides that no EGSs will be permitted to charge early cancellation, termination or other fees to any shopping customer transitioning into one of the Companies’ CAP programs. The Companies’ Supplier Tariffs will be updated to reflect this restriction.

All administrative and programming costs incurred by the Companies to implement the aforementioned CAP shopping restriction will be collected from residential customers through the Companies’ PTC Riders.

Full Requirement Service

As is currently the case, the full requirements products described above will exclude certain transmission charges. These excluded transmission requirements are the Regional Transmission Expansion Plan ('RTEP') charges, Expansion Cost Recovery Charges; Reliability Must Run/generation deactivation charges associated with generating plans for which specific RMR charges begin after July 24, 2014; historical out-of-market tie line, generation, and retail customer meter adjustments; unaccounted for energy; or any Federal Energy Regulatory Commission ('FERC') approved reallocation of PJM RTEP charges related to Docket No. EL05-121-009 (collectively, referred to as 'non-market based charges' or 'NMB charges').

The Companies will continue to assume these NMB charges for both default service suppliers and EGSs that serve load in the Companies’ service areas, and the associated costs will be recovered from customers in a competitively neutral manner through the Companies’ non-bypassable Default Service Support ('DSS') Riders.

Other Issues

In the SOS procurement, the Companies will employ a 50% load cap for fixed-price product auctions and a 75% load cap for hourly-pricing product auctions.

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