The Eastern Interconnection generation stack covers all dispatchable and non-dispatchable capacity across ISO-NE, MISO, NYISO, and PJM. Plant-level data drives short-run marginal costs, capacity factor profiles, and outage derating.
Each region builds an existing fleet from EIA generator inventory data, then merges capacity expansion results from the CEM start year onward, splitting new builds into unit-level generators using node/technology average sizes. Short-run marginal costs are computed per generator from heat rates and fuel costs, using a shared heat-rate hierarchy (plant-specific from emissions-monitoring data, then balancing-authority average, then technology average). Renewable generation uses time-varying capacity factors from weather-year data at the node level, and each region maps its nodes to regional pipeline gas hubs (spot basis plus a firm transport adder, documented on the shared Commodity Prices page).
Existing fleet
The base generator inventory is sourced from EIA-860 (with EIA-860M updates), filtered to operating electric-utility and independent-power-producer units. Each plant carries technology type, fuel, nameplate capacity, heat rate, and operational status. Region-specific refinements and zonal assignments are described in each region below.
CEM capacity integration
From the CEM start year onward, capacity expansion results are merged into the generator inventory. New builds are split into unit-level generators using node/technology average sizes to enable operational modeling. The capacity forecast for each region (total installed capacity by technology across the forecast horizon) reflects queue-anchored near-term additions and CEM build decisions thereafter.
Short-run marginal costs
SRMCs are computed per generator from heat rates and fuel costs, using a shared heat-rate hierarchy:
- Unit-specific — EPA CAMPD reported heat rates derived from continuous emissions monitoring (highest priority)
- Plant-specific — EIA-923 reported heat rates
- BA average — EIA-930 balancing authority mean for the technology
- Technology average — national fallback
Thermal generators are expanded into stepped bid curves with configurable price/volume scaling per technology. Must-run generators (nuclear, certain hydro) can bid at or below zero to reflect system reliability requirements and incentive structures.
Carbon costs
Short-run marginal costs include CO2 allowance costs for generators in RGGI member states. The RGGI cap schedule, CCR triggers, and modeled carbon price path are documented on the Emissions & Policy page. Emissions intensity (tCO2/MWh) is plant-specific from heat rates and fuel CO2 content. Each region’s RGGI membership status is noted below.
Renewable capacity factors and outages
Renewable generation uses time-varying capacity factors from weather-year data at the node level. Nuclear outages are sourced from NRC status data at the plant level. Region-specific outage treatments are described below.
Demand response
Demand response is not currently modeled as a dispatchable resource in the Eastern Interconnection model. Large loads are included in the demand forecast but cannot be curtailed by the solver. This contrasts with the WECC model which includes 7 DR categories as price-responsive supply.
Region Specific Details
ISO-NE
Existing fleet
The ISO-NE existing fleet is sourced from EIA-860, cross-referenced with the ISO-NE 2026 CELT report for capacity consistency.
Forecast
Near-term additions are anchored to the interconnection queue. See Capacity Expansion Model for queue methodology.
Natural gas hub
All ISO-NE zones map to Algonquin Citygate — the dominant pricing point for New England gas, reflecting the peninsula’s constrained pipeline infrastructure.
Carbon costs
All six New England states are RGGI members. Massachusetts generators additionally face EGEL (310 CMR 7.74) carbon costs on top of RGGI. See Emissions & Policy.
Renewable capacity factors and outages
Nuclear outages are sourced from NRC status data at the plant level. Thermal forced outage rates use a market-wide monthly average by prime mover. Renewable capacity factors are at the zonal level.
Data sources
| Source | Description | Link |
|---|---|---|
| ISO-NE CELT 2026 | Existing fleet capacity cross-reference | ISO-NE CELT |
| RGGI | CO2 allowance auction results and CCR trigger prices | RGGI |
| MA DEP EGEL | Massachusetts EGEL covered-facility list and price curve | 310 CMR 7.74 |
MISO
Existing fleet
The MISO existing fleet is filtered to operating electric-utility and independent-power-producer units, and each plant is assigned to an LRZ.
Forecast
The chart below shows total installed capacity by technology across the forecast horizon for MISO.
Near-term additions are anchored to the interconnection queue, detailed on the Capacity Expansion Model page.
Policy drivers
State-level clean-energy mandates and storage targets across the MISO footprint are enforced as model constraints. See Emissions & Policy for the state-by-state policies. MISO is not a RGGI region, so no regional carbon constraint applies.
Short-run marginal costs
Dual-fuel units in MISO are eligible for fuel switching between gas and oil based on relative delivered fuel costs.
Outages
Thermal outages are derived from MISO’s Multi-day Operating Margin (MOM) forecast, resolved by subregion (North/Central vs South) and thermal technology (combined cycle, combustion turbine, steam). Nuclear outages are sourced separately from NRC per-unit status data.
Renewable capacity factors
Renewable generation uses time-varying capacity factors from weather-year data at the node level.
Natural gas hubs
MISO nodes are mapped to two pipeline gas hubs: a Midwest hub (Chicago Citygate) for the North/Central zones (LRZ1–LRZ7) and a Gulf hub (Henry Hub) for the South zones (LRZ8–LRZ10).
Assumptions and caveats
Data sources
These MISO-specific sources supplement the shared sources below.
| Source | Description |
|---|---|
| MISO MOM forecast | Thermal outage rates by subregion |
NYISO
Existing fleet
For NYISO, the existing fleet is further refined using the NYISO 2025 Gold Book generator inventory, which provides unit-level capacity and operational data that supplements and takes precedence over EIA-860 where the two sources overlap.
Forecast
The chart below shows total installed capacity by technology across the forecast horizon for NYISO.
Near-term additions are anchored to the interconnection queue, detailed on the Capacity Expansion Model page.
Policy drivers
New York’s CLCPA shifts the buildout toward renewables and storage. See Emissions & Policy for the RGGI carbon budget.
Carbon costs
New York is a RGGI member, so short-run marginal costs include CO2 allowance costs for its generators. See Emissions & Policy for the RGGI cap schedule and carbon price path.
Natural gas hubs
Each NYISO zone is mapped to a regional pipeline gas hub based on physical infrastructure analysis. Four hubs capture the geographic variation in gas pricing across the state, as set out in the table below.
| NYISO zones | Pipeline gas hub |
|---|---|
| Western, Central, Mohawk Valley (A, B, C, E) | Tennessee Z4 200L |
| Northern, Capital, Hudson Valley, Long Island (D, F, G, K) | Iroquois Z2 |
| Millwood & Dunwoodie (H, I) | Tennessee Z6 |
| New York City (J) | Transco Z6 NY |
Renewable capacity factors and outages
Nuclear outages are sourced from NRC status data at the plant level. Technology-level forced outage rates are a placeholder (not currently modeled beyond nuclear).
Assumptions and caveats
- Each thermal plant uses a 2-level bid step rather than a multi-step offer curve.
- Renewable and thermal load factors use the 2022 base weather year (see Demand for the weather-year rationale).
- Hydro is not price responsive, output follows fixed historical profiles.
Data sources
| Source | Description | Link |
|---|---|---|
| NYISO Gold Book | Existing and planned generation capacity | NYISO Gold Book |
| RGGI | CO2 allowance auction results and CCR trigger prices | RGGI |
PJM
Existing fleet
The PJM existing fleet is sourced from EIA-860M, filtered to operating electric-utility and independent-power-producer units. Generators are assigned to a PJM transmission zone, first from a per-generator override table and otherwise via a county-to-zone mapping.
Outages
Generation outages for PJM are informed by actual and forecasted outages as reported by PJM with technology-specific outage allocations driven by other PJM-published reports.
Interconnection queue and retirements
Near-term additions are anchored to PJM’s serial and cycle interconnection queues, detailed on the Capacity Expansion Model page. Retirements are drawn from public data and tiered by the level of confidence in each announced closure.
Forecast
The chart below shows total installed capacity by technology across the forecast horizon for PJM.
Policy drivers
The RGGI carbon budget applies to PJM’s NJ, MD, DE, and VA load. See Emissions & Policy for details.
Natural gas hubs
PJM nodes are mapped to several pipeline gas hubs reflecting the footprint’s geographic spread (for example Transco Zone 6, Transco Zone 5, TETCO M3, Transco Leidy, and Chicago Citygate).
Data sources
| Source | Description | Link |
|---|---|---|
| PJM IC Queue | Interconnection queue data with technology mapping | PJM |
Data sources
The following sources are common across all regions.
| Source | Description | Link |
|---|---|---|
| EIA-860 / 860M | Generator inventory, fuel types, operational status | EIA-860 |
| EIA-923 | Plant-level fuel receipts and heat rates (fallback) | EIA-923 |
| EIA-930 | BA-level generation averages for heat rate fallback | EIA-930 |
| EPA CAMPD | Unit-specific heat rates from continuous emissions monitoring | EPA CAMPD |
| EIA AEO | Long-run gas price escalation | EIA AEO |
| NREL ATB | CAPEX/OPEX assumptions for CEM investment decisions | NREL ATB |
| NRC | Nuclear power plant status and outage data | NRC |