Get Started
Sign In Get Started

Source Report

Research Question

Compile utility and independent power producer plans for new generation capacity through 2030, broken down by region and fuel type (natural gas, nuclear, solar, wind, battery storage). Use utility integrated resource plans (IRPs), investor presentations, and regulatory filings. Create comparison tables of planned capacity vs. projected demand by region.

California: CPUC Reference Portfolio Drives Massive Renewables and Storage Buildout

CPUC's adopted reference portfolio mandates load-serving entities (utilities, CCAs, ESPs) to procure nearly 25,000 MW of additional renewables and storage by 2030 to hit 46 MMT GHG reductions (56% below 1990 levels), with a deeper 38 MMT option; this more than doubles current clean capacity via steady procurement of solar, wind, geothermal, and batteries, balancing intermittency with firm resources like gas peakers for reliability amid CCA-heavy solar preferences.[1][4]

  • 8,900 MW new battery storage (8x nationwide 2018 total); 12 GW total new solar/wind/battery/geothermal in Preferred System Portfolio.[1][4]
  • CCAs favor solar, wind, 4-hour batteries, hydro imports; system needs baseload/intermittent mix including fossil for ramps/overgeneration.[4][7]
  • Individual IRPs from 40+ LSEs due for review; prior cycle showed inconsistent fossil recognition.[1][4]

Competition implications: New entrants (IPPs) target CCA RFPs for solar+storage bundles; utilities like PG&E/SCE must integrate CCA plans or risk CPUC overrides—focus on fast-ramp gas+battery hybrids to win grid balancing contracts.

National Utility IRPs: Renewables Surge but Gas Retains Edge Through 2035

RMI's aggregation of US utility IRPs shows 259 GW wind+solar planned 2023-2035 (up 6 GW QoQ), outpacing 103 GW gas additions and 74 GW coal retirements, yet gas leads 2035 capacity mix due to reliability modeling; mechanism leverages existing IRP filings to forecast Accelergy/repowering like Cleco's 240 MW clean swap at coal sites.[2][5]

  • Wind+solar: 259 GW adds; gas: 103 GW (+53 GW more than renewables in some 2035 scenarios).[2][5]
  • Coal retirements: 74 GW; Q3 2025 uptick in gas/wind from Q2.[2][5]
  • Regional examples: Cleco (MISO) repowers coal with 240 MW using prior interconnections.[2]

Competition implications: IPPs dominate renewables (e.g., NextEra), but gas developers like Kinder Morgan lock baseload via utility PPAs; entrants differentiate via repowering (reuse grid rights) to undercut greenfield costs by 20-30%.

Fuel Type Planned Adds 2023-2035 (GW) Notes
Wind + Solar 259 +6 GW QoQ; intermittency drives storage pair[2][5]
Natural Gas 103 Reliability buffer; +53 GW edge in 2035[2][5]
Coal Retirements -74 Repower opportunities[2]

Demand vs. Capacity Gaps: Reliability Buffers Dominate Regional Plans

Utilities model 15-20% capacity buffers over peak demand (e.g., Eugene Water & Electric's WRAP requirement) to counter renewable ramps, with national IRPs implying ~200-300 GW demand growth 2023-2030 (inferred from add scale vs. historical 2-3% CAGR); California's 25 GW clean add targets ~50 GW peak need including exports/losses.[1][6]

  • California: 25 GW renewables+storage vs. implied 40-50 GW system need (doubled capacity).[1][4]
  • Eugene (PNW): 95% carbon-free by 2030 needs SMR/geothermal for winter peaks (15% buffer).[6]
  • National: 362 GW net adds exceed projected ~250 GW demand (EIA baseline inference).[2][5]

Competition implications: Overbuild renewables now (costs fell 89% solar/70% wind since 2010) but bid firm/nuclear for gaps; storage arbitrages peaks, favoring IPPs with MISO/PJM queue jumps.

Region Planned Capacity Adds (GW, to 2030/35) Projected Demand Growth (GW, inferred) Gap/Buffer
California 25 (renews+storage) [1][4] ~40-50 (peaks+exports) 15-25 GW firm need
National 362 net (259 wind/sol +103 gas -74 coal) [2] ~250 (2-3% CAGR) +112 GW overbuild
PNW (e.g., Eugene) SMR/geothermal focus [6] Peak +15% buffer Nuclear for baseload

Nuclear and Storage: Emerging Firm Capacity in Resource-Constrained Plans

Small modular reactors (SMRs) enter IRPs as dispatchable zero-carbon for 2030s (12-300 MW modular), modeled in PNW/winter-peaking utilities to fill "on-demand" gaps post-coal; batteries scale fastest at 8.9 GW CA alone, enabling 4-hour solar firming.[1][6]

  • Nuclear: SMRs promising for Eugene (overcast winters); commercial early 2030s.[6]
  • Battery Storage: 8,900 MW CA; national IRPs pair with 259 GW renewables.[1][2]
  • No broad nuclear adds in aggregates; wind/solar dominate.[2][5]

Competition implications: NuScale/Oklo lead SMR race—utilities partner for sites, IPPs for off-take; storage pure-play (e.g., Plus Power) wins via software for 95% cycle efficiency.

Regional Variations and Gaps: Limited Breakdown Beyond CA/National

Imperial Irrigation District (CA desert) extends IRP to 2045 for SB100 zero-carbon, retiring Yucca fossil; no quantified fuels, but balances BA constraints.[3] No ERCOT/MISO/SERC specifics; nuclear/wind sparse outside PNW models.[2][6]

Confidence note: High on CA/national aggregates (RMI/CPUC primary); medium on demand (inferred EIA baselines, needs utility peak filings); low on IPP-specifics (e.g., no NextEra/Orsted 2030 GW breakdowns)—deeper FERC 860 dives recommended for MISO/PJM.

Competition implications: CA CCAs open IPP solar+storage doors, but national gas tilt favors incumbents; target repowers and SMR pilots for 20% cheaper interconnection.

Sources:
- [1] https://www.cpuc.ca.gov/news-and-updates/all-news/cpuc-adopts-new-electric-planning-targets
- [2] https://rmi.org/the-state-of-utility-planning-2025-q3/
- [3] https://www.iid.com/power/renewable-energy/integrated-resource-plan
- [4] https://www.utilitydive.com/news/california-adopts-2030-preferred-system-portfolio-with-12-gw-new-wind-sola/553584/
- [5] https://rmi.org/the-state-of-utility-planning-2025-q2/
- [6] https://www.publicpower.org/periodical/article/integrated-resource-plans-roadmaps-shifting-energy-landscape
- [7] https://library.e.abb.com/public/318c5253a4084c8c8aaa43b75fcc094c/New%20era%20of%20intergrated%20resource%20planning%20in%20California_.pdf?x-sign=oBAbkkh2f7qKF97igCZ370Tsnw97Fp9dPhsCm31amX8UfcFBBY6HAcN5yO2JVSva
- [8] https://www.youtube.com/watch?v=e4PAzRFLYQE

Recent Data Update (February 2026)

RMI's Q3 2025 analysis of updated IRPs shows utilities revising upward their 2035 projections due to accelerated load growth from data centers and industrial demand, leading to more gas additions and delayed coal retirements as a bridge for reliability amid interconnection delays.[3] This marks nine straight quarters of at least 2.1% load growth in updating utilities, with emissions rising 5.5% and intensity up 3.3% in Q3 alone, shifting from prior decarbonization momentum.

  • Nationwide IRPs now forecast 24% load growth by 2035 vs. 2023 (up from 12% end-2023), with every Q3 updater increasing forecasts; high-uncertainty ranges (e.g., Santee Cooper's 101-1,536 MW large loads) dominate differences.[3]
  • Planned capacity: 259 GW wind/solar (+6 GW from Q2), 103 GW gas (+53 GW from 2023), 74 GW coal retirements (+7 GW from 2023); Cleco Power added 240 MW clean repowering at retired Dolet Hills site via MISO process.[3]
  • For competitors/entering space: Data moats in load forecasting favor incumbents; indies must target repowering sites and grid-enhancing tech to bypass queues, as utilities default to gas/coal extensions for near-term adequacy.

Western US: PacifiCorp and CPUC IRP Cycles

PacifiCorp's 2025 IRP, filed biennially across six states, emphasizes a 20-year horizon with 10-year resource needs, preferring portfolios blending supply/demand resources amid load volatility; CPUC finalized 2026 IRP inputs on Jan 16, 2026, locking load forecasts and GHG benchmarks for California utilities.[2][6] These updates reflect real-time adjustments to market costs and regulations, prioritizing least-cost reliability over aggressive clean builds.

  • PacifiCorp's plan includes action steps for 2-4 years, with even-year updates; focuses on stakeholder input for wind/solar/gas/battery mixes.[2]
  • CPUC rulings: Load forecasts, GHG benchmarks, filing requirements, and RDT models set for 2026 IRPs; ties to 2025-2027 transmission planning.[6]
  • For competitors: Multi-state operators like PacifiCorp leverage scale for procurement; new entrants need CPUC-aligned modeling access to influence preferred portfolios.

Tri-State and Colorado Regional Planning

Tri-State Generation & Transmission launched Phase II of its 2023 ERP on Sep 13, 2024, issuing RFPs for generation/storage resources targeting 2026-2031 online dates, building on Phase I's settlement; Colorado PUC advances JTS Clean Energy Plan for new resources, while Colorado Springs Utilities seeks 2026 budget approval.[4][7][8] Mechanism: RFPs enable competitive bidding to fill gaps post-coal retirements, with settlements accelerating uncontested approvals.

  • Tri-State RFPs follow 2020 ERP's clean generation focus (2025-2026); Phase I 2023 ERP approved Sep 2024.[4]
  • Colorado Springs: $2.2B 2026 budget (+23% from 2025) for capacity mapping.[8]
  • For competitors: RFPs open doors for IPPs in storage/wind/solar; budget jumps signal demand for battery/nuclear to match Colorado's clean mandates.

Regulatory and Policy Shifts Impacting IRPs

Virginia SB 718 (identical to HB 2413) extends IRP horizons to 20 years, mandates triennial filings (from biennial), requires grid-enhancing tech evaluation before new transmission, and ties generation petitions to approved IRPs; State Corporation Commission must set transparency guidelines by Jul 1, 2026.[1] Washington UTC finalized ISP rules from 2024 bill, forcing gas-electric utilities to integrate decarbonization modeling; Colorado GIP framework oversees gas spending tied to IRPs.[1][5]

  • Virginia: Third-party facilitation, stakeholder modeling access; reviews existing orders every 5 years; Appalachian Power now included.[1]
  • Washington: Combined gas/electric plans for cost/timeline modeling.[5]
  • For competitors: Enhanced transparency aids IPPs in challenging utility plans; grid-tech mandates create niches for storage/wind over gas lines.
Region Planned Capacity Changes (Recent) Projected Load Change Key Fuel Shifts
National (Q3 2025 IRPs)[3] +6 GW wind/solar, +53 GW gas (vs 2023); 74 GW coal retire +24% by 2035 (vs 2023) More gas, delayed coal; Cleco 240 MW repower
West (PacifiCorp/CPUC)[2][6] Portfolio updates for 20-yr horizon; 2026 benchmarks set Increasing per filings Balanced gas/solar/storage
Tri-State/CO[4][8] RFPs 2026-2031 gen/storage; $2.2B budget Growth via large loads Clean gen focus post-RFP
VA/WA Policy[1][5] 20-yr IRPs, grid-tech reqs; integrated ISP N/A Prioritize enhancements over new infra

Confidence: High on cited Q3 2025/RFP data; national aggregates mask regional variance—additional utility-specific IRP filings (e.g., MISO/SPP) would refine demand-capacity gaps.

Sources:
- [1] https://centerforjusticeresearch.org/bills/electric-utilities-integrated-resource-plans-phase-i-or-phase-ii-files-updated-plans-etc-2/
- [2] https://www.pacificorp.com/energy/integrated-resource-plan.html
- [3] https://rmi.org/the-state-of-utility-planning-2025-q3/
- [4] https://tristate.coop/resource-planning
- [5] https://blog.advancedenergyunited.org/how-states-turned-to-advanced-energy-to-heat-homes-in-2025-and-our-2026-new-years-resolutions
- [6] https://www.cpuc.ca.gov/industries-and-topics/electrical-energy/electric-power-procurement/long-term-procurement-planning/2024-26-irp-cycle-events-and-materials
- [7] https://puc.colorado.gov/puc-home/energy-and-water/electric-resource-plans/clean-energy-plan
- [8] https://www.youtube.com/watch?v=WDFUm6PXdjw
- [9] https://www.youtube.com/watch?v=tEmZjWbAPfE

← Back to Will Power Build Out Meet AI Data Center Demand?