SPP Capacity Expansion Planning

Ward-Reduced Network Model & Scenario Analysis

Ali Jahanbani Ardakani, Charlie Philips, James McCalley
Iowa State University — April 1, 2026

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Why This Work?

The Challenge

The Eastern Interconnection model: 96,328 buses, 80,000+ branches
Direct capacity expansion on this scale is computationally infeasible
Need a reduced equivalent that preserves electrical fidelity
Must support DC optimal power flow formulation

SPP Load Growth Context

From SPP's published ITP studies:

FERC 714 SPP 2024 peak: 54 GW
SPP 2025 ITP: 70–83 GW by 2034
SPP 2026 ITP: 91–110 GW by 2035
Driven by data centers, electrification, reshoring

Our model: 2024 ITP base case + FERC 714 → 2049

Data Sources

Network, Generation & Load

PSS/E 2024 ITP: Full Eastern Interconnection study case — buses, branches, transformers, and 596 generators with capacity and fuel type
Generator technologies: Mapped from PSS/E fuel codes to 7 categories (Coal, CC Gas, Gas CT, Wind, Solar, Nuclear, Hydro)
FERC 714: 8,760 hourly SPP system load (2024)
Bus locations: 90,455 buses geocoded (OSM + HIFLD)

Cost & Fuel

NREL ATB 2024: OCC, FOM, VOM, heat rates by technology (Moderate scenario)
EIA AEO 2025: Fuel price projections (Reference case)

Renewable Resources

NREL 2024 supply curves: Wind + Solar sites mapped to buses
9,942 wind sites → 1,004 buses
10,604 solar sites → 1,057 buses

Weather-Derived Capacity Factors

HRRR reanalysis: Location-specific wind and solar output
Wind avg CF: 0.415
Solar avg CF: 0.25 (including nighttime)

Pipeline

PSS/E RAW
96K buses

→

Ward Reduction
1,763 buses

→

Load Analysis
FERC 714

→

Equivalent Line
Capacities
7,134 lines

→

CEP Model
DCOPF

→

Results

Key Steps

Ward reduction: Preserves electrical coupling at the SPP boundary
Equivalent line capacities: 7,134 thermal limits estimated for reduced network lines
HRRR capacity factors: Location-specific wind and solar from weather reanalysis

Runtime (per scenario)

Stage	Time
Network reduction	5 min
Line capacity estimation	25 min
CEP model solve	~60 min
Total	~90 min

Ward Network Reduction

Method

Partition the admittance matrix into retained and eliminated buses:

        Yeq = Yrr - Yre · Yee-1 · Yer
      

98.2% reduction: 96,328 → 1,763 buses
Perfect load conservation at retained buses
External boundary buses provide realistic coupling

Retained Network

Metric	Value
Retained buses	1,763
SPP internal	~1,020
Transit corridors	~110
External boundary	~630
Equivalent lines	7,134
Generators	596
SPP+Transit load	85,627 MW

Capacity Expansion Model

Formulation

Linear program minimizing total discounted cost
DC optimal power flow with angle coupling
6 planning years × 17 time blocks
15% planning reserve margin
Carbon reduction: 2%/year → 50% by 2049

Cost Components

Generation investment
Transmission expansion
Fixed & variable O&M
Fuel cost

Technologies

Technology	Can Build?	Can Retire?	Capacity Credit
CC Gas	Yes	Yes	1.00
Gas CT	Yes	Yes	1.00
Wind	Yes	Yes	0.20
Solar	Yes	Yes	0.35
Coal	No	Yes	1.00
Nuclear	No	Yes	0.90
Hydro	No	Yes	0.50

Capacity credit = how much each GW counts toward the 15% reserve margin.

Load Growth Scenarios

1.5%

Low Growth — historical trend

2034: 96 GW | 2049: 116 GW

4.0%

Reference — data centers + electrification

2034: 118 GW | 2049: 197 GW

7.0%

High Growth — aggressive electrification

2034: 150 GW | 2049: 382 GW

Alignment with SPP ITP Projections

SPP 2025 ITP projects 70–83 GW by 2034 (our low scenario: 96 GW in 2034).
SPP 2026 ITP projects 91–110 GW by 2035 (between our low and reference scenarios).
Our reference (4%) and high (7%) represent accelerated growth scenarios driven by large load interconnection.

Results — Total SPP System Cost

All scenarios DCOPF optimal, zero unserved energy

	Low	Ref	High
Total (B$)	$117	$207	$431
Gen Investment	$30	$83	$205
Line Investment	$4	$5	$13
Fixed O&M	$67	$90	$142
Fuel	$13	$24	$59

Cost Breakdown — Reference

FOM

$90B

43%

GenInv

$83B

40%

Fuel

$24B

11%

LineInv

$5B

3%

Gen investment increases 7x from low ($30B) to high ($205B). Transmission investment remains relatively stable.

Generation Investment by Scenario

New capacity built through 2049

Low (1.5%) — 48 GW new

GasCT

31 GW

65%

Wind

11 GW

22%

Solar

5 GW

11%

CC

1 GW

2%

Reference (4%) — 182 GW new

Wind

75 GW

41%

GasCT

72 GW

40%

Solar

20 GW

11%

CC

15 GW

8%

High (7%) — 543 GW new

Wind

252 GW

46%

GasCT

149 GW

27%

Solar

102 GW

19%

CC

40 GW

7%

Key Insight

At low growth, Gas CT dominates (65%) — firm capacity is the priority. As growth increases, wind takes the lead (41-46%) due to its high capacity factor (0.415 avg). Gas CT remains essential for firm capacity because wind's capacity credit is only 0.20 — requiring ~5 GW of gas peaking for every 1 GW of effective firm capacity from wind.

Limitations & Future Work

Current Limitations

Single weather year — 2024 HRRR data only
Uniform load profile — All buses follow same FERC 714 shape
No storage cycling constraints
No forced retirement schedule — Economic retirement only
Ward load leakage — ~4% of SPP load redistributes to external buses

Planned Improvements

Adaptive Capacity Expansion (ACEP) — Multi-stage stochastic formulation with uncertainty in load, fuel prices, and policy
Storage constraints — SOC limits, charge/discharge, round-trip efficiency
Sensitivity analysis — Carbon policy, discount rate, technology costs
Multi-year weather validation
Improved network reduction — Target ~1,500 buses for faster solves

Sensitivity: What If SPP Is Islanded?

Remove external buses — SPP must self-supply entirely

With Eastern Interconnection (1,763 buses)

	Low	Ref	High
Total (B$)	$117	$207	$431
Unserved Energy	0	0	0

SPP Island — no external (1,193 buses)

	Low	Ref	High
Total (B$)	$155	$267	$524
Unserved Energy	~0	270 GWh	4,055 GWh

Costs exclude load shedding penalty.

Key Insight

At 1.5% growth, SPP can nearly self-supply — cost increases 33% without interconnection
At 4%+ growth, external transmission paths are essential — transit corridors cannot serve growing load without external routing
The value of interconnection increases dramatically with load growth

Summary

96K → 1.8K

buses (98.2% reduction)

$117–431B

SPP system cost (25-year NPV)

Wind #1

75 GW new wind in reference case

Key Takeaways

Ward reduction produces a tractable, electrically faithful equivalent
Load growth drives $117B to $431B in total SPP system cost
Wind dominates new investment at higher growth rates (HRRR CF = 0.415)
Gas CT is essential for firm capacity due to low wind capacity credit
As growth increases, investment shifts from firm gas → renewables + gas

Questions?