Capacity Expansion Model

How the forward fleet is built

The Capacity Expansion Model (CEM) determines the forward buildout of generation and storage across the SPP footprint. Its outputs define the fleet that the production cost model dispatches in each forecast year.

See the core Capacity Expansion Model for the shared methodology.

At a glance

Buildout logic

The CEM is a least-cost optimization that selects new capacity to meet demand growth and resource adequacy at minimum total system cost (capital cost plus operating cost plus reliability penalties), subject to technology cost trajectories from the NREL Annual Technology Baseline (ATB).

It is solved on a rolling window: each iteration optimizes a single forecast year using the information visible at that point, commits that year’s build decisions, then rolls forward and re-optimizes the next year. Retirements are not a decision of the model: existing units leave the fleet on their exogenous retirement schedule (see Retirements), which the optimization takes as given. Within each year, operations are evaluated on representative days at hourly resolution (selected by clustering the year’s net-load profile) to capture the intraday flexibility and renewable-integration value that drive what gets built.

Build candidates

Nuclear and hydro are not build candidates; existing units are modeled, but new units of these technologies enter only as predetermined additions, not economic choices.

Technology costs and incentives

Capital and fixed operating costs come from the NREL ATB, converted to the model’s 2026 USD base year. Battery storage capital cost is the exception: it is taken from the Modo Energy BESS CapEx Survey (an all-in cost by duration), converted from its real-2023 GBP basis to 2026 USD and marked up for project financing, with fixed operating cost left on the ATB. Federal tax credits are applied on the investment side: the Investment Tax Credit reduces effective capital cost for new solar and storage on a declining schedule, reflecting the current phase-down. New-build economics use a common investment lifetime across technologies in the current version.

New-build gas capital cost follows a Lazard-anchored near-term curve. It starts from the Lazard LCOE+ midpoint in 2026, rises to about 1.5 times that level (a 50% mark-up) by 2030 to reflect the current gas-turbine and skilled-labour supply crunch, then normalizes back toward the long-run NREL ATB level by 2040.

The near-term mark-up is supported by the public record. Combined-cycle projects entering service in 2028–2031 are being filed with regulators at $2,000–2,400/kW, against roughly $1,100–1,400/kW for units completing in 2026–2027 — a 50–80% increase, with SPP-footprint examples such as Evergy’s McNew station (2030, around $2,255/kW). Turbine order books are reported sold out toward 2030 with multi-year lead times, and Lazard’s own 2025 LCOE+ anchor flags steep near-term cost increases for gas. A 50% peak adjustment sits at the conservative end of this range.

Interconnection queue analysis

Near-term additions are anchored to the SPP generator interconnection queue. Queue projects are assigned a completion likelihood from where they sit in SPP’s study process: projects with executed interconnection agreements are treated as near-certain, projects in facility studies as progressively less likely, and early-stage study projects as speculative.

The likelihoods are measured, not assumed. They come from how SPP projects have historically progressed through the study process: composing the observed stage-to-stage conversion rates gives each project a probability of reaching operation from where it sits today.

From these likelihoods the model anchors a near-term set of queue projects into the buildout. Projects are pooled by technology and commercial operation year, and the highest-likelihood projects in each pool are locked in up to its probability-weighted expected capacity. Commercial operation dates are stretched to reflect SPP’s long and lengthening interconnection timelines. Beyond this queue-anchored set, the model is free to add capacity economically.

Resource adequacy

Resource adequacy is enforced through a seasonal Planning Reserve Margin, with separate summer and winter requirements that step up over the horizon. The winter requirement (rising from 36% to 38%) is set materially higher than the summer requirement (16% to 17%), reflecting the cold-weather reliability risk that SPP has prioritized since Winter Storm Uri.

Each technology contributes accredited capacity rather than nameplate:

• Thermal: accredited by its seasonal forced-outage-rate class
• Wind and solar: accredited by effective load carrying capability (ELCC), which declines as penetration rises
• Storage: accredited by ELCC that varies with duration and declines with penetration

The constraint requires accredited capacity from the existing fleet plus new builds to meet the reserve-margin-adjusted seasonal peak in each zone and year.

A resource’s ELCC is not a single number: it falls as more of that resource is added. SPP accredits each resource at its average contribution during the tightest load hours, and places new units on the same average tiers as the existing fleet rather than on a lower marginal value (SPP 2026 ELCC Study Report §3.4; Planning Criteria v4.6 §7.1.6). The model follows this: both the existing fleet and new capacity-expansion builds are credited at the fleet-average ELCC at the prevailing penetration. Because that average still declines as penetration rises, incremental wind, solar, and storage earn progressively less capacity credit as the fleet grows. Longer-duration storage holds its credit best, solar declines fastest, and winter reorders the resources.

The seasonal split is large for the weather-driven resources: solar’s first tranche is accredited near 63% in summer but only about 25% in winter, while wind is credited higher in winter (about 29%) than summer (about 22%).

Folding builds into the production cost model

CEM build decisions are folded back into the production cost model’s generator inventory. Queue-anchored interconnection projects and CEM builds are added to the same fleet that existing units belong to, inheriting heat rates, outage rates, capacity factors, and derates. Thermal builds are split into fleet-representative unit sizes so that minimum-load requirements do not impose unrealistic commitment floors, while renewable and storage builds are carried directly. The production cost model dispatches the queue-anchored projects and existing fleet, and incorporates CEM builds where capacity-expansion outputs are enabled.

Transmission

Planned transmission additions are incorporated so that interface limits evolve over the study horizon. See Transmission.

Policy

State renewable portfolio standards and clean-energy targets are enforced as constraints in the CEM for the SPP states that have them, notably New Mexico, Colorado, Minnesota, and Missouri. Eligible new wind and solar earn renewable energy credits, which can be banked and traded across years against each state’s target trajectory. Federal tax credits enter through investment economics as described above. There is no carbon price in the footprint.

Inputs

Outputs

• Installed capacity by technology and zone, by forecast year
• The resulting fleet feeds the Generation inventory and the production cost model