CHANGES IN LAW

Change type/cost component, commodity impact and effective date

NY: Consolidated Edison (ConEd), Keyspan: Brooklyn Union Gas (BUG) and Long Island Light Company (LILCO)

If you’re billed by us: You will see the impact from the change in costs as a separate line item labeled "Change in Law 11/01/2025,” beginning with usage from Dec. 1 forward.

If you’re billed by the utility on our behalf: you will see the impact from this change in costs as an adjustment in your unit price on your utility invoice, beginning with any usage from Dec. 1 forward.

New England gas utilities: Berkshire Gas, Colonial Gas, Connecticut Natural Gas, Energy North, Essex Gas, Eversource-NSTAR, Eversource Gas Company of Massachusetts (EGMA), Fall River Gas, Fitchburg Gas Company, Keyspan-Boston, National Grid-Rhode Island Energy, Northern Utilities Maine, Northern Utilities New Hampshire, Southern Connecticut Gas Company

If you're billed by us: you will see this change in costs as a separate line item labeled "Change in Law 11/01/2025,” beginning with any billed usage from Dec. 1, forward.

If you're billed by the utility on our behalf: you will see the impact from this change in costs as an adjustment on your utility invoice near your gas supply charges, beginning with any usage from Dec. 1, forward.

The New York State Public Service Commission (PSC) recently approved National Grid-Niagara Mohawk’s (NGRID-Nimo) Gas Rate Case, 24-G-0323, which include changes to NiMo’s Firm Daily Balanced Retail Access program. Marketers like NRG are now required to contract for annual Primary Point Capacity (PPC) in a quantity sufficient to meet 100% of a firm daily balanced customer’s maximum peak day quantity (MPDQ). To comply with this new MPDQ requirement, NRG must obtain more primary point pipeline capacity, which will increase the cost to serve firm daily balanced customers.

The cost impact of the change to NiMo’s Firm Daily Balanced Retail Access program will be displayed as a separate line item labeled "Change in Law 11/1/2025,” beginning with November 2025 usage (billed in December).

On July 1, the Federal Energy Regulatory Commission (FERC) approved final rates in Columbia Gas’s General Natural Gas Act Section 4 rate case*, which resulted in a pipeline rate decrease. Increases and decreases in pipeline rates can cause changes in pipeline capacity and delivery costs, which we are required to procure from the local distribution companies (LDCs) on behalf of our customers.

The impact from this change in costs will be displayed as a separate line item labeled "Change in Law 09/01/2025,” beginning with September 2025 usage.

* Docket Nos. RP24-1103-000/RP24-1103-001, Doc. Accession #20250701-5199 (July 1, 2025)

The impact of the DDS change in costs will be displayed as a separate line item labeled "Change in Law 5/1/2025,” beginning with June 2025 usage (billed in July).

Change type/cost component, commodity impact and effective date

The Federal Energy Regulatory Commission (FERC) approved a rate increase filed by the Transco Interstate Pipeline Company (Docket No. RP24-1035), which took effect March 1, 2025. Increases in pipeline rates can cause increases in pipeline capacity costs, which we are required to procure from the local distribution companies (LDCs) on behalf of our customers. Because the Transco pipeline supplies gas to the PECO and PGW service areas, there is a corresponding increase in the cost of capacity behind these LDCs, as filed in their capacity release program (CRP) cost updates.

Columbia Gas Transmission, LLC, a subsidiary of TC Energy, filed a General Natural Gas Act Section 4 rate case with the FERC (Docket No. RP24-1103-000) that resulted in a rate increase for pipeline capacity costs. Increases in pipeline rates can cause increases in pipeline capacity and delivery costs, which we are required to procure from the local distribution companies (LDCs) on behalf of our customers. Because the Columbia Gas pipeline supplies gas to the above utilities, there is a corresponding increase in the cost of gas delivery in these service areas.

Each year the New York State Electric & Gas Corporation (NYSEG) files updated cost calculations with the New York Public Service Commission (PSC) for their capacity release program (CRP). This year’s filed rates, which are effective April 1, have increased over last year’s. This increase is due in large part to pipeline rate increases from Algonquin (AGT) and Columbia Gas (TCO) pipeline companies, which supply gas to NYSEG’s service area. Increases in pipeline rates cause increases in pipeline capacity, which we are required to procure on behalf of our customers.

Change type/cost component, commodity impact and effective date

If you're billed by us: you will see the impact from the CRP costs as a separate line item labeled "Change in Law 11012024,” beginning with any usage from Dec. 1 forward. Please note that if you experienced a change in law in the past, you may have more than one change in law line item on your invoice.

If you're billed by the utility on our behalf: you will see the impact from the change in CRP costs as an adjustment in your unit price on your utility invoice, beginning with any usage from Dec. 1 forward.

The impact from the change in CRP requirements will be displayed as a separate line item labeled "Change in Law 11012024,” beginning with December usage. Although the CRP changes were effective on Nov. 1, 2024, we will not be billing retroactive cost changes.

If you're billed by us: you will see the impact from this program cost change (a charge or credit) as a separate line item labeled "Change in Law 110124,” beginning with any usage from Nov. 1 forward. Please note that if you experienced a change in law in the past, you may have more than one change in law line item on your invoice.

If you're billed by the utility on our behalf: you will see the impact from this program cost change as an adjustment in your unit price on your utility invoice, beginning with any usage from Nov. 1 forward.

NATURAL GAS: ConEd peaking demand rate increase

Effective date of change: April 1, 2024

ConEd implemented out-of-cycle changes to its peaking demand rates, which are part of natural gas daily delivery service (DDS) and which we are required to purchase from ConEd to serve our natural gas customers. Normally ConEd updates these rates annually and the changes are effective November 1—and they remain in place through the winter season. These out-of-cycle rate changes resulted in a net increase over the original annual rate change that was effective in November.

If you're billed by us: you will see the impact from this increase in demand rate as a separate line item labeled "Change in Law 04012024,” beginning with any usage from April 1 forward. Please note that if you experienced a change in law in the past, you may have more than one change in law line item on your invoice.

If you're billed by ConEd on our behalf: you will see the impact from this increase in demand rate as an adjustment in your unit price on your ConEd invoice, beginning with any usage from April 1 forward.

ELECTRICITY: ERCOT System Admin Fee increase

Effective date of change: Feb. 1, 2024

This charge will appear in the prior period pass-thru section of the invoice, labeled as “TX-ERCOT Admin Fees – CIL” for any invoices that containing billing dates from Feb. 1, forward.

In November, the New England utilities reset the program requirements for the annual Capacity Release Program (CRP),² which impacts the natural gas supply costs associated with Transportation, Capacity, Storage, and Peaking, which we are required to procure on behalf of our customers. Changes to the CRP parameters can increase or decrease the costs associated with procuring these components, which are assigned based on your individual usage profile. All customers, regardless of who supplies your natural gas (the utility or a retail supplier), are subject to these costs.

As a result of the annual update to the CRP requirements, we will be passing through the associated change in costs on your invoice starting with your February 2024 usage.

If you're billed by us: you will see the impact from the CRP change (a charge or credit) as a separate line item labeled "Change in Law 02012024,” beginning with any billed usage from Feb. 1, forward. Please note that if you experienced a change in law/change to purchase price in the past, you may have more than one change in law line item on your invoice.

If you're billed by the utility on our behalf: you will see the impact from the CRP change (a charge or credit) as an adjustment on your utility invoice near your gas supply charges, beginning with any usage from Feb. 1, forward.

² Sample program change documentation from Berkshire Gas for reference purposes.

Change type/cost component, commodity impact and effective date

Since 2018, ISO-NE has taken several steps to plan for adequate generation resources and fuel supply for those generators during the winter months to ensure reliable electricity production during periods of extreme cold weather. One such step was to create the Inventoried Energy Program (IEP) in 2019, which is similar to the Winter Reliability Program of years' past. The IEP is a temporary program that pays certain generators for maintaining energy inventories during the winters of 2023/24 and 2024/25. This—along with keeping certain generators, like Mystic, online beyond their retirement—is part of the ISO's overall fuel security planning approach. 

The costs associate with the IEP program will be passed through to customers from December to February 23/24 and 24/25.

ConEd, BUG, LILCO, and O&R each implemented its annual update of costs for its Daily Delivery Service (DDS) program/Core Daily Balancing (CDB) program, which went into effect on Nov. 1, 2023. DDS/CDB is a natural gas delivery and storage service that we are required to purchase from the local utility to serve our natural gas customers. As a result of the annual cost update, we will be passing through the change in costs on your invoice, which could be a charge or a credit, starting with your November 2023 usage.

If you're billed by us: you will see the impact from this program cost change (a charge or credit) as a separate line item labeled "Change in Law 110123,” beginning with any usage from Nov. 1 forward. Please note that if you experienced a change in law in the past, you may have more than one change in law line item on your invoice.

If you're billed by the utility on our behalf: you will see the impact from this program cost change as an adjustment in your unit price on your utility invoice, beginning with any usage from Nov. 1 forward.

Change type/cost component, commodity impact and effective date

In 2021 and 2022, the Public Utility Commission of Texas (PUCT) and the Electric Reliability Council of Texas (ERCOT) approved several regulatory changes that increase or add energy supply costs in Texas, including:

Firm Fuel Supply Service (FFSS):This service was developed consistent with directives from the Texas Legislature and the Public Utility Commission of Texas's (PUCT's) order for ERCOT to develop and procure a firm-fuel product as part of the Commission's Phase I Market Design efforts and in response to Texas Senate Bill 3. This firm fuel supply service (FFSS) product provides additional grid reliability and resiliency during extreme cold weather and compensates generation resources that meet a higher resiliency standard. FFSS will be procured for the obligation period of November 15 through March 15 each year.

When the owners of the Mystic Generating Station announced that they were going to retire several units in 2022, the ISO-NE, after studying and identifying the resulting adverse consequences for New England's energy security, moved to retain the Mystic units for an additional two years, in an effort to give the region time to implement reliability solutions before the units' eventual retirement in 2024.

As a result, all customers in New England will be subject to Reliability Must Run (RMR) charges, effective June 1, 2022, which cover the costs to keep generation units running beyond their scheduled retirement.

In 2021 and 2022, the Public Utility Commission of Texas (PUCT) and the Electric Reliability Council of Texas (ERCOT) approved several regulatory changes that increased or added energy supply costs in Texas, including:

Ancillary Services obligation increase: To help ensure there is enough capacity to serve customers through periods of emergency, ERCOT significantly increased the ancillary services obligations (specifically Non-Spin Reserves) that LSEs like us must procure for our customers.

• July 2021: ERCOT Market Notice "Adjustment to 2021 Minimum Monthly Ancillary Service Requirements and Implementation Details of OBDRR031"
• August 2021: W-A081221-01 Adjustment to minimum Monthly Ancillary Service Requirements for September through December 2021
• December 2021: ERCOT Board Endorsement, December 10, 2021, authorizing changes from December 2021 forward.

The ancillary services increases were passed through as follows:

Ancillary Services 2022 increase started April 2022 and is labeled as "Ancillary Service Obligation Adj." on your invoice. It covers billing dates from Mar. 1, 2022 forward.

Ancillary Services 2021 increase started in June 2022 and is labeled "AncillaryServiceObligationAdj: 7/21-2/22" on your invoice. It covers billing dates from July 2021 thru February 2022.

In 2021 and 2022, the Public Utility Commission of Texas (PUCT) and the Electric Reliability Council of Texas (ERCOT) approved several regulatory changes that increased or added energy supply costs in Texas, including:

Securitization charges: The PUCT issued Orders¹ that allow ERCOT to obtain approximately $3 billion in funds to help stabilize the wholesale electricity market. ERCOT will assess these charges, which will impact load serving entities (LSEs), including retail electric providers (REPs) like NRG, who can then pass these charges on to their customers. Securitization charges are comprised of:

• Default Securitization Charge²: a non-bypassable charge that is effective in January 2022.


• Uplift Securitization Charge³: a non-bypassable charge, which will be effective in early Q2 2022.

Securitization credit: NRG customers (including transmission-level customers who did not opt-out) that were charged ancillary services costs over $9,000 MWh and reliability deployment price adder (RDPA) charges for usage during Winter Storm Uri, received a credit to offset those charges in an amount proportional to NRG's recovery of its exposure.

• ¹ Docket Nos. 52321 (Default Securitization) and 52322 (Uplift Securitization)
• ² PUCT Docket No. 52321
• ³ PUCT Docket No. 52322

The securitization charges/credit was/were passed through at different points in time during 2022 as follows:

Default Securitization (current): was passed thru on invoices starting in August 2022 and labeled as "Market Securitization (Debt) Financing: Default" (covers July 2022 forward)

Securitization Credit: appeared on August 2022 invoices labeled as "Market Securitization Subchapter N – Credit"

Uplift Securitization: was passed thru on invoices starting in September 2022 and labeled as "Market Securitization (Debt) Financing: Uplift" Note: Uplift Securitization Charges will not be assessed to transmission-voltage level ESIDs that have opted out of the uplift portion of securitization.

Default Securitization (back bill): was passed thru on invoices starting in November 2022 and labeled as "Market Securitization: Default 1/1/22- 6/30/22." (covers the back-billing of costs back to the effective date)