Transmission

How the network and interconnections are represented

Transmission is represented at the zonal level. Inter-zonal flows are bounded by interface limits and solved jointly with unit commitment and dispatch, so congestion separates zonal prices endogenously.

Zonal topology

The footprint is divided into 18 settlement zones connected by transmission interfaces. Each interface is a zone-to-zone path with a transfer limit applied as a constraint in unit commitment and economic dispatch, with flows bidirectional and bounded symmetrically.

Transmission line ends are mapped to zones following the same priority order used to site generation. The sum of line capacities between two zones gives the zone-to-zone capacity, which is then derated by a factor to reflect physical grid constraints. This derating is determined by looking at congestion patterns in the backtest. A small uniform flow penalty of $2/MWh is also applied to all inter-zonal flow. This steers the model away from unnecessary flows when solutions are otherwise equal in cost.

Note that the split of Oklahoma Gas and Electric into OKGE (East) and OKGE (West) (see the Overview) allows the model to capture the sizeable congestion patterns that occur historically within this zone, by separating the wind-rich west from the load-rich east.

Interconnection to SPP West and non-SPP markets

SPP exchanges power with neighboring systems: MISO, ERCOT, WECC, the SPP West footprint, and smaller neighbors. Rather than co-optimizing flows with those external systems, the model represents the exchange as historical interchange netted into the relevant boundary zones:

• MISO: boundary-zone interchange on the eastern boundary
• ERCOT: interchange across the direct-current ties, netted at the southern boundary zone
• WECC and SPP West: interchange on the western boundary
• Associated Electric (AECI), Southwestern Power Administration (SPA), and other neighbors: boundary-zone interchange mapped from external balancing-authority data

External balancing-authority flows are taken from EIA-930 (and SPP tie-flow data where more granular), allocated to SPP boundary zones using fixed weights calibrated to historical interface flow patterns, and subtracted from those zones’ load. In effect the interconnection behaves as a fixed exchange profile at the footprint edge rather than a capacity-limited interface the model optimizes against. Explicit, capacity-constrained boundary interfaces are a planned future enhancement. No wheeling or hurdle charge is applied, either within the footprint or on import and export with external systems. The only per-MWh cost on flow is the small inter-zonal flow penalty described above.

Exports are not fully firm, however. When the footprint is tight, typically during peak hours or a steep net-load ramp, the model can pull its net exports back home rather than continue serving neighbors, but only at an elevated cost. This is a demand-response mechanism on each boundary zone’s net export: as the zone’s internal price rises from $500 to $1,000/MWh, progressively more of the net export is retracted, until at $1,000/MWh the full net export is withheld. Below $500/MWh exports flow normally, so the model only pulls interchange back when keeping the energy at home is worth more than the export.

Transmission expansion

Interface limits evolve over the forecast horizon as planned transmission is added. Two sources drive this:

• SPP transmission planning (STEP / Integrated Transmission Plan): curated SPP-approved projects, including major backbone upgrades, phased in by their planned in-service dates.
• NREL national transmission scenarios: longer-term gross inter-zonal capacity additions, applied to the out-years and to zone pairs the SPP plan does not cover.

Both sources are used together: where they cover the same zone pair, the SPP planning overlay takes precedence, and the NREL scenarios supply the additional longer-term expansion elsewhere. Added capacity raises the corresponding interface limit from its in-service year onward. The SPP-approved projects below are included directly.

The curated SPP overlay is drawn from the 2025 Integrated Transmission Plan. Its backbone projects, largely a 765 kV loop across Oklahoma and the Texas panhandle, are listed below with SPP’s status and whether the base forecast builds them.

“Approved” projects carry a notification to construct (NTC). The base forecast builds the 765 kV projects with an NTC and leaves out those SPP has deferred or still has under study, so the backbone it models is the part SPP has committed to.

• Woodward – Potter County is the one exception. SPP deferred its NTC to the 2026 ITP, but it closes the loop into SPS. Without it, SPS’s import capability is about 2.4 GW and every tie into SPS overloads on peak winter days in the late 2030s, so the base forecast builds it on its planned date.
• The Dakotas – Nebraska uprates are not SPP projects. The 600 MW addition from 2033 is sized to clear the overloads the forecast sees on the NPPD to WAUE corridor as demand in WAUE grows. It sits within NREL’s National Transmission Planning Study, which adds 0.7 to 1.3 GW on this corridor by 2035 in three of its high-demand cases, those targeting 90% to 100% clean power. The 320 MW addition from 2040 takes the corridor’s growth in NREL’s high-demand case, which the modeled demand tracks, where the moderate-demand case adds nothing.
• Belfield – Roundup connects two western zones, so it takes effect only once SPP West is modeled.

Data sources