This forecast covers bundled electricity service for transmission-connected loads in Virginia. It combines energy, fuel, transmission, generation demand, customer service, and riders.
Service overview
| Item | Coverage |
|---|---|
| Service | Virginia · PJM · Dominion GS-5 High Load/Load Factor Service, firm service at 69 kV or above. |
| Rate basis | Proposed scenario: GS-4 rates in 2026, then proposed and estimated GS-5 rates from January 1, 2027. |
| Supply | Bundled utility supply. Optional market-based generation under MBR/SCR is excluded. |
| Billing basis | Hourly imports, seasonal peak windows, and monthly charges. Results are in real 2025 dollars. |
| Contract demand | Maximum grid-import capacity is used as the contracted-demand basis for transmission. |
Charge breakdown
The generation-demand row includes seven demand riders. The calculation below explains each included charge.
| Line item / what it pays for | Tariff Charge Type | How the Charge Is Assessed | Calculation basis |
|---|---|---|---|
| Base electricity supply | Supply | Energy | Imported MWh multiplied by on-peak or off-peak rate; includes base generation and distribution energy charges. |
| Fuel and purchased-power recovery | Supply | Energy | Imported MWh multiplied by Rider A fuel rate. |
| Transmission service, including Rider T1 | Transmission | Fixed | 85% of maximum grid-import capacity multiplied by transmission rate multiplied by in-service days divided by 30. |
| Generation demand and bundled demand riders | Generation | Capacity (demand-based) | Highest monthly on-peak imported MW multiplied by the combined generation and rider rate. |
| Off-peak generation demand | Generation | Capacity (demand-based) | 10% of highest monthly off-peak imported MW multiplied by estimated generation rate multiplied by service days divided by 30. |
| Renewable portfolio standard | Rider | Energy | Imported MWh multiplied by RPS rate. |
| Coal-ash closure | Rider | Energy | Imported MWh multiplied by CCR rate. |
| Energy-efficiency programs | Rider | Energy | Imported MWh multiplied by C4A rate. |
| Peak-shaving programs | Rider | Energy | Imported MWh multiplied by C1A rate. |
| Carbon-allowance recovery scenario | Rider | Energy | Imported MWh multiplied by scenario RGGI rate from March 1, 2027. |
| Deferred fuel-cost bond recovery | Rider | Energy | Imported MWh multiplied by fixed nominal recovery rate through March 2031. |
| Data center electricity consumption tax | Rider | Energy | Imported MWh multiplied by the fixed nominal tax rate from July 2026 through June 2028. |
| Customer service | Distribution | Fixed | Monthly customer amount multiplied by covered days / 30. |
How charges are calculated
Energy and fuel
Energy charges equal imported MWh multiplied by the applicable $/MWh rate. Base supply has separate on-peak and off-peak rates. Fuel recovery and energy riders are added separately.
On-peak hours are weekdays, 10 a.m.–10 p.m. from June through September and 7 a.m.–10 p.m. from October through May, in local time. Holidays are included when they fall on weekdays. All other hours are off-peak.
Transmission
Transmission recovers network costs through a base rate and Rider T1. The forecast assesses 85% of maximum grid-import capacity for days when campus load capacity is in service:
Transmission cost uses 85% of grid-import capacity in MW, multiplied by the rate in $/MW-month. The charge is allocated by in-service days divided by 30.
This charge is fixed for the period. Higher or lower imports do not change it.
On-peak generation demand and riders
Generation demand pays for generation facilities and capacity purchases. It and the included riders use the customer’s highest grid import during the month’s on-peak hours:
The on-peak demand subtotal is calculated by multiplying peak imported MW by the sum of the applicable period rates in $/MW.
Eight underlying charges make up this subtotal. Generation demand is adjusted by covered days divided by 30; riders are adjusted by the covered share of the calendar month.
| Charge | What it pays for |
|---|---|
| Generation demand | Generation cost of service, including net PJM capacity purchases. |
| OSW | Coastal Virginia Offshore Wind. |
| GEN | Generation facilities. |
| SNA | Surry and North Anna nuclear life extension. |
| CE | Clean-energy projects and power purchase agreements. |
| CERC | Chesterfield Energy Reliability Center. |
| E | Environmental projects. |
| SMR | Small modular reactor costs. |
Off-peak demand and customer service
Off-peak generation uses 10% of the month’s highest off-peak grid import. The forecast retains the GS-4 rate, increased with inflation, after the GS-5 transition. Customer service is a fixed monthly charge. Both charges are prorated by service days divided by 30.
Forecast methodology
| Charge | How its rate changes |
|---|---|
| Base supply and customer service | GS-4 rates and proposed GS-5 rates apply on the dates stated for this scenario. Each rate stays at face value for its first year, then increases annually with assumed inflation. |
| Fuel | The interim Rider A rate applies through 2027. From 2028, the entire fuel charge changes by the same percentage as the Transco Zone 5 gas-price index. |
| Transmission | The base rate stays fixed in nominal dollars. Rider T1 follows transmission revenue requirements divided by DOM-zone network peak load. Forecast investment follows the regional transmission expansion plan, then extends with load growth. |
| Generation demand | The estimated 2027 rate is split between cost of service and capacity purchases. The assumed share used to buy capacity follows annual DOM-zone PJM capacity prices. That share determines how much the total rate changes when capacity prices change. |
| OSW | Coastal Virginia Offshore Wind. Follows the company’s revenue-requirement forecast, adjusted for load growth. The rate is floored at zero; potential credits are excluded. |
| CE | Clean Energy Projects and Power Purchase Agreements. Extends the historical rate-growth trend through 2035, then holds the rate constant in real 2025 dollars. |
| GEN, SNA, CERC, E, and SMR |
Rates increase with inflation. |
| Off-peak generation | Uses the GS-4 rate, increased with inflation. |
| RPS | Renewable Energy Portfolio Standard. Grows with the renewable portfolio requirement from a projected-cost baseline. Renewable energy certificate prices stay fixed in nominal dollars; future true-ups are assumed zero. |
| CCR, C4A, and C1A |
Rates continue with inflation from their effective dates. |
| RGGI | Regional Greenhouse Gas Initiative. Zero before March 2027, then the proposed standard-recovery rate with inflation. This scenario includes catch-up recovery that can exceed the ongoing cost. |
| Deferred fuel-cost recovery | The latest nominal rate continues through March 2031, assuming unchanged sales. |
| Data center consumption tax | A fixed nominal rate applies from July 2026 through June 2028, then ends. July is the assumed usage start; collection began in September. |
Nominal charges are converted to real 2025 dollars at each billing-month start. Rate changes follow each charge’s effective date and annual update schedule.
Assumptions and limitations
| Assumption | Effect on results |
|---|---|
| Demand minimums | The forecast uses fixed transmission demand and current generation peaks. Tariff minimums based on earlier peaks and contracted demand can produce higher bills, especially when load falls. |
| Off-peak demand | The forecast uses 10% of the off-peak peak. The tariff charges the amount by which the off-peak peak exceeds 90% of the on-peak peak. These quantities match when both peaks are equal. |
| Meter interval | Hourly imports can miss the tariff’s 30-minute demand maximum. |
| Partial months | A partial-month demand measurement can miss the full-month peak when imports vary. |
| Self-supplied electricity | The consumption-tax estimate uses grid imports. Tax on electricity supplied onsite is not included in that amount. |
| Excluded charges and options | Reactive-power demand, ordinary consumption tax, sales/use-tax surcharge, site-specific connection costs, and other pending recovery are excluded. MBR/SCR and clean-energy-buyer exemptions are not applied. Distribution demand is zero at the selected voltage. |
Public tariffs and regulatory filings
| Source | Coverage |
|---|---|
| Dominion filed tariff and rider schedules | GS-4 and rider schedules. Live documents may include updates after this methodology version. |
| PUR-2025-00058 Final Order | November 25, 2025; pp. 23–26, GS-5 terms and minimum charges. Approved GS-5 service terms. |
| PUR-2025-00058 public case record | Stuller Exhibit 27, proposed GS-5 schedule, PDF pp. 24–28. Proposed rates used in this forecast. |
Methodology version: October 2026. Results use real 2025 dollars.