Fuel prices are footprint-wide inputs that set each generator’s short-run marginal cost. Natural gas, coal, oil, and minor fuels are each built from historical data over the backtest window and a forward forecast, expressed in real US dollars per MMBtu at the model’s currency base year. Natural gas is priced at the node level; the other fuels are priced at the balancing-authority or basin level.
Natural gas
Natural gas sets the marginal price across most of the footprint, so it is modeled at the node level. Each node is mapped to a pipeline trading hub, and the number of hubs per ISO reflects its internal pricing diversity. Zone-to-hub assignments are anchored to each ISO’s Net Cost of New Entry (Net CONE) studies and cross-validated against EIA Form 923 monthly fuel-receipt data to ensure the mapping aligns with observed delivered-fuel costs, with additional reference to published pipeline supply studies (PJM Gas Futures Zonal Mapping, Analysis Group, Monitoring Analytics, ICF).
| ISO | Pipeline hubs | Hubs |
|---|---|---|
| NYISO | Tennessee Zone 4 200L, Iroquois Zone 2, Tennessee Zone 6, Transco Zone 6 NY | 4 |
| PJM | Transco Zone 6 NY, Transco Zone 6 non-NY, Transco Zone 5, TETCO M3, Transco Leidy, Chicago Citygate | 6 |
| MISO | Chicago Citygate (LRZ1 to LRZ7), Henry Hub (LRZ8 to LRZ10) | 2 |
| ISO-NE (planned) | Algonquin Citygate | 1 |
Forecast methodology
The forward gas curve is built in two layers. The Henry Hub reference uses CME natural gas futures for the first four forecast years, taking the market-implied price level and monthly seasonality from the last 90 days of traded contracts. Beyond four years it switches to the EIA Annual Energy Outlook annual price level, with the CME-derived seasonal shape applied on top.
Each hub price is then the Henry Hub reference plus a monthly additive basis: the median hub-to-Henry-Hub spread by calendar month over 2019 to 2025, from daily spot data. A firm gas transportation adder is layered on each hub to approximate the delivered cost at the generator busbar.
Historical prices
Over the backtest window, NYISO nodes use actual daily pipeline hub spot prices, and the other ISOs use daily spot or proxy hubs. A five-day trailing moving average is applied, reflecting the lag between gas spot price and generator bid behavior.
Data sources
| Source | Description | Link |
|---|---|---|
| CME (Databento) | Natural gas futures, forward curve and seasonality | CME |
| EIA AEO | Long-run Henry Hub price level | EIA AEO |
| EIA Henry Hub spot | Historical Henry Hub reference | EIA NG |
| Daily pipeline hub spot | Hub basis vs Henry Hub | EIA NG prices |
| EIA Form 923 | Monthly delivered fuel-receipt data — cross-validates generator-to-hub mapping | EIA 923 |
| ISO Net CONE studies | Generator-to-hub assignment basis | PJM / MISO / NYISO Net CONE Reports |
Coal
Coal is priced by supply basin, then delivered to each plant with a transport cost. Five basins are represented: Central Appalachia (the reference basin), Northern Appalachia, Illinois Basin, Powder River Basin, and Uinta Basin. Each modeled coal plant is mapped to the basin that supplies it.
Forecast methodology
Historical prices come from EIA weekly basin spot data. The forward baseline uses the EIA AEO Central Appalachia proxy (the AEO PJM/West region), with historical monthly seasonality applied. Each other basin is then derived from a multiplicative basis ratio: the median basin-to-Central-Appalachia price ratio by calendar month over 2019 to 2025.
The delivered price adds a transport cost to the basin price. Transport costs are sourced from the EIA Form 923 transport table (averaged 2008 to 2023), converted from dollars per ton to dollars per MMBtu using each basin’s heat content, and mapped to the plant’s state.
The series above are basin prices before the plant-level transport adder described above.
Data sources
| Source | Description | Link |
|---|---|---|
| EIA Coal Markets | Weekly basin spot prices | EIA Coal |
| EIA AEO | Forward coal price baseline (PJM/West proxy) | EIA AEO |
| EIA Form 923 | Basin-to-state transport costs | EIA 923 |
Distillate and residual fuel oil
Distillate fuel oil (DFO) and residual fuel oil (RFO) are forecast from EIA AEO projections per balancing authority. The AEO utility-sector distribution markup is stripped from the DFO series to recover the wholesale refinery price that power plants actually pay. Over the backtest window, oil prices come from EIA-923 fuel-receipt volume-weighted averages per balancing authority. Jet fuel and kerosene track the DFO series, as they have no price series of their own.
Minor fuels
Municipal solid waste, landfill gas, and other captured gases are set to $0/MMBtu: waste-to-energy plants receive tipping fees and landfill gas is captured on-site, so no fuel is purchased. Wood and biomass waste is held flat at the EIA SEDS electric-power-sector average. Nuclear carries a flat fuel cost. Petroleum coke, used only by one MISO IGCC unit, is priced from an Illinois Basin coal proxy.