Strategies for Success in CAISO

Preface to the Revised Edition

The market this paper described no longer exists in the same form. The strategies that succeeded in it are worth recording precisely because the conditions were unusual.

The first edition was researched in the fourth quarter of 2024 and published in the first quarter of 2025, in the same weeks in which a new federal administration began to reverse the policy architecture the paper described. It was released with limited distribution.

The IRA was signed on August 16, 2022, and its wind and solar credits were not repealed until the One Big Beautiful Bill Act was signed on July 4, 2025. We nonetheless close the period at the end of the first quarter of 2025, because that is when the market closed it. From January 2025 the question in every investment committee, sell-side process and tax-credit negotiation was not what the law said but what it was about to say; new commitments stopped while existing positions were locked in. The first quarter of 2025 saw $7.9 billion of announced clean-energy projects cancelled, closed or downsized nationally — more than three times the total of the previous thirty months¹ — while, in the same quarter, capital deployment into already-committed projects peaked as developers safe-harbored equipment and sold credits ahead of the change².

A market that simultaneously cancels its future commitments and secures its existing positions is a market in suspension.

This revised edition does three things. It corrects and updates every figure to the close of the first quarter of 2025, which we treat as the end of the IRA era for planning purposes. It reframes the material as a retrospective: what the CAISO market looked like, what a successful entry and investment strategy looked like, and why. And it adds an epilogue recording what changed after March 2025, so that no reader mistakes a period piece for current advice.

The analytical conclusion has not changed. Between 2022 and early 2025, CAISO became the deepest utility-scale battery storage market in the world, and it did so through a specific combination of federal tax credits, state procurement mandates, and a capacity (resource adequacy) framework that rewarded four-hour storage. Developers and investors who organized around that combination did well. Those who organized around offshore wind, speculative queue positions, or solar without storage generally did not.

Executive Summary

What CAISO looked like at the close of the period

By early 2025 the CAISO balancing authority area served roughly 32 million consumers and about 80% of California’s demand across approximately 26,000 circuit-miles of transmission³. Its installed renewable fleet stood at 32,572 MW — 20,739 MW of utility-scale solar (63.6%), 8,346 MW of wind, 1,610 MW of geothermal, 1,147 MW of small hydro and 730 MW of biofuels — and its battery fleet, which had been approximately 500 MW in 2020, had reached roughly 13,000 MW of active capacity by December 2024 (11,454 MW under CAISO’s stricter fully-commercial count as of January 31, 2025)⁴. Resource adequacy net qualifying capacity was 50,852 MW against a 2024 peak of 48,323 MW and an all-time peak of 52,061 MW set on September 6, 2022.

The period had clear bookends. It opened with the Inflation Reduction Act and, three weeks later, the September 2022 heat wave that pushed CAISO to its all-time peak and real-time prices to the $2,000/MWh cap — the event that made the value of dispatchable storage evident to regulators and investors alike. It closed in a single fortnight in January 2025.

What a successful strategy looked like

Seven elements recur in the projects and platforms that created value in CAISO during the period. Each is developed in Chapter 6.

1. Storage first. Four-hour lithium-ion batteries, standalone or co-located with solar, concentrated in the SP15 zone where solar saturation created the widest daily price spreads and the tightest evening capacity need.
2. A resource adequacy contract as the anchor. Long-term RA or tolling agreements with investor-owned utilities and community choice aggregators, procured under the CPUC’s mid-term reliability orders (11,500 MW of net qualifying capacity for 2023–2026, plus 4,000 MW for 2026–2027), with merchant energy and ancillary-service revenue layered on top.
3. A capital stack built on the IRA. The 30% investment tax credit extended for the first time to standalone storage; 10-point adders for domestic content and energy communities; and transferability, which turned tax credits into a $30 billion market in 2024 at 92.5 cents (ITC) and 95 cents (PTC) on the dollar¹⁴.
4. Queue position and zonal alignment. Holding earlier-cluster interconnection positions, siting inside the zones prioritized in CAISO’s transmission plans, and meeting the readiness tests introduced when CAISO reset its process after the 354 GW Cluster 15 window¹⁵.
5. Permitting and community readiness. Using the CEC’s AB 205 opt-in certification where local pathways were uncertain, engaging early with counties and fire authorities, and treating battery safety as a licence-to-operate issue before Moss Landing made it one.
6. Tariff-aware procurement. Managing solar anti-dumping and countervailing duties, the scheduled increase in Section 301 tariffs on Chinese batteries, and the first IEEPA tariffs of February–March 2025 through diversified sourcing, safe-harbor purchases and domestic-content planning.
7. Disciplined exit timing. Selling development pipelines at ready-to-build or shortly after commercial operation, when strategic buyers and infrastructure funds paid premiums for contracted CAISO capacity — a valuation marker set in January 2025 when Constellation agreed to pay 7.9× 2026 EBITDA for Calpine’s dispatchable fleet⁷.

1. Market Trends

1.1 The snapshot at the close of the period

Table 1 sets out the figures used throughout this edition. All are drawn from CAISO’s own statistics as published in February 2025 or from the CAISO Department of Market Monitoring’s 2024 battery report^3,4, so that every figure in the paper reconciles to a single dated source.

1.2 The battery build-out

The defining trend of the period was the speed of storage deployment. CAISO’s active battery capacity grew from about 500 MW in 2020 to 11,200 MW by June 2024 and approximately 13,000 MW by December 2024^4,16, with 2024 alone adding about 4 GW¹⁷ — a record that 2025 would exceed. By the end of 2024 slightly more than half of that capacity was physically paired with solar under CAISO’s co-located or hybrid models, sharing a point of interconnection with generation; the balance was standalone, the segment that would dominate additions from 2025 onward.

Operationally the fleet changed the shape of the grid. In 2024 battery charging represented about 14.7% of CAISO load between hours-ending 10 and 13, up from 8.3% in 2023, absorbing midday solar that would otherwise have been curtailed or exported. In the evening the same fleet displaced gas: in 2023 batteries supplied on average 5.6% of electricity between 5 and 9 p.m.¹⁸, and by the spring of 2024 CAISO was reporting the first evenings on which batteries were the single largest supply resource on the system after sunset. The Department of Market Monitoring found that local market power mitigation had minimal effect on battery dispatch, with only about 363 MW per hour on average subject to bid reductions — evidence that the fleet was competing rather than being constrained.

1.3 Solar saturation, curtailment, and negative prices

Solar remained the largest renewable resource, and its success created the period’s central operating problem. CAISO curtailed 2.4 TWh of wind and solar in 2022 and 2.66 TWh in 2023, and 3.4 TWh in 2024 — a 29% year-on-year increase, 93% of it solar and most of it in the spring, when output is high and heating and cooling loads are low²¹. Trading in the Western Energy Imbalance Market avoided a further 274 GWh of curtailment in 2024, about 8% of the total. Statewide, utility-scale wind and solar capacity nearly tripled over the decade, from 9.7 GW in 2014 to 28.2 GW at the end of 2024.

For developers the implication was direct. Solar-only projects in SP15 faced deepening midday price collapse and rising curtailment exposure, while any project that could shift energy four hours into the evening captured both an energy spread and a capacity payment. The economics of the period pushed capital toward storage, and toward co-location, where a single interconnection could serve both.

1.4 Prices: PPAs rose, not fell

Contrary to the cost-curve narrative that dominated forecasts written in 2022, contracted prices rose through the period. LevelTen Energy’s North American solar P25 index — the most competitive quartile of offers on its marketplace — stood at $56.76/MWh in the fourth quarter of 2024, and CAISO posted the largest increases of any ISO in the index: 8.2% quarter-on-quarter and 24.7% year-on-year²². Higher interest rates from 2022 onward, tariff uncertainty on modules and cells, and interconnection scarcity all pushed in the same direction. Wind PPA offers across North America averaged $67.81/MWh in the same quarter, marking fifteen consecutive quarters in which solar had priced below wind.

Long-run cost curves still pointed down. NREL’s 2024 Annual Technology Baseline projected that overnight capital cost for utility-scale PV-plus-battery would fall from roughly $2,100/kW in 2024 to roughly $1,060/kW by 2050, and that PV-plus-storage levelized cost would decline from the high-$70s to the mid-$50s per MWh (conservative) or low-$30s (advanced)²³.

The cost curves were not wrong. The period demonstrated that in a capacity-short market with rising rates and tariffs, the equilibrium contract price is set by scarcity rather than by the cost curve.

1.5 Load growth arrived late in the period

For most of the period California’s load story was flat-to-declining demand offset by electrification. That changed at the end. The CEC’s 2025 forecast projected CAISO’s 1-in-2 peak rising 15% from 46,094 MW in 2025 to 52,940 MW in 2030, and annual energy from 217,686 GWh to 271,992 GWh over the same window²⁴. CAISO’s own transmission planning, drafted in the spring of 2025, raised its assumed year-on-year rate of peak growth from 0.99% to 1.53%, and to 2.14% in the Greater Bay Area, on the strength of transportation and building electrification and data-center interconnection requests²⁵. The last quarter of the IRA era was therefore also the first quarter in which CAISO participants began to plan for a growing, rather than a static, system.

1.6 Policy drivers and constraints, as they stood at March 31, 2025

2. Market Structure and Operations

2.1 The balancing authority and the Western markets

CAISO operates the day-ahead and real-time markets for its balancing authority area and, since 2014, the Western Energy Imbalance Market (WEIM), a real-time market that by the end of 2024 had 22 active participants across 11 states with two more preparing to join, and had produced $6.62 billion in gross benefits since launch. For a CAISO developer the WEIM’s practical value was as an outlet for surplus midday solar and as a source of imports during evening ramps; its value was indirect rather than a distinct revenue stream.

The period also settled the structure of the West’s day-ahead markets. FERC accepted CAISO’s Extended Day-Ahead Market (EDAM) tariff in December 2023²⁹. By the end of the period PacifiCorp (implementation agreement April 2024; go-live May 1, 2026), Portland General Electric (June 2024), the Balancing Authority of Northern California (November 2024) and the Los Angeles Department of Water and Power (January 13, 2025) had signed implementation agreements, with NV Energy, Idaho Power, BHE Montana and PNM publicly leaning toward EDAM³⁰. The competing Southwest Power Pool Markets+ received conditional FERC approval on January 16, 2025, with Bonneville’s choice — the largest single swing factor — still pending at the close of the period. The West was heading toward two day-ahead markets with a long seam between them.

2.2 Resource adequacy: the anchor of the revenue stack

California does not run a centralized capacity market. Instead the CPUC requires each load-serving entity (LSE) — investor-owned utility, community choice aggregator, or electric service provider — to demonstrate system, local and flexible resource adequacy (RA) against its forecast load plus a planning reserve margin, and CAISO backstops any shortfall. The planning reserve margin was 17% for the 2024 and 2025 compliance years, with an “effective” procurement target of roughly 22.5% for the summer months, and the CPUC’s new Slice-of-Day framework — under which each LSE must show sufficient capacity in every hour of the month’s worst day — took effect for the 2025 compliance year^32,33.

Two features of this framework built the battery fleet. First, RA is contracted bilaterally, so a developer with a signed long-term RA or tolling agreement from an IOU or CCA had bankable revenue years before commercial operation, and the CPUC’s mid-term reliability orders obliged those buyers to sign. Second, Slice-of-Day explicitly rewards resources that can cover the post-sunset hours — that is, four-hour storage. Scarcity pricing reinforced the effect. By the end of the period the market had begun to loosen as the 2024 additions came online, but RA remained the revenue line on which every CAISO storage financing was underwritten.

2.3 The procurement mandates

The CPUC’s integrated resource planning proceeding converted state policy into purchase orders. Decision 19-11-016 required 3,300 MW of new capacity for 2021–2023. Decision 21-06-035 (June 2021) required 11,500 MW of new net qualifying capacity from zero-emitting or RPS-eligible resources between 2023 and 2026 — at the time the largest single procurement order in the state’s history — and Decision 23-02-040 (February 2023) added 4,000 MW for 2026–2027. These orders, allocated across the IOUs and CCAs by load share, are the demand side of every RA contract signed in the period. In parallel, AB 1373 (2023) authorized the Department of Water Resources to procure centrally on behalf of LSEs for resources with long lead times — long-duration storage, geothermal and offshore wind — a channel that was still in design at the close of the period³⁵.

2.4 Interconnection: the queue and the reset

Interconnection was the binding constraint of the period. CAISO’s Cluster 14 window (2021) drew 151 GW of requests; Cluster 15, in April 2023, drew 541 requests totaling roughly 354 GW, against an informal survey that had anticipated about 300 requests in total. With approximately 188 GW of earlier-cluster projects still active, the queue exceeded 500 GW — more than ten times the system’s peak load.

CAISO’s response, the Interconnection Process Enhancements (IPE) 2023 initiative, reset the rules for every project in the queue. Track 2, approved by FERC in the Appendix KK “Resource Interconnection Standards” tariff (Docket ER24-2671) in 2024³⁶, introduced a zonal approach tied to the CPUC and CEC resource portfolios; a scoring system weighting project viability (site control, engineering progress), system need (including local RA), and commercial interest from LSEs and non-LSEs; and a cap on the capacity studied per zone at 150% of available transmission capability. Cluster 15 requests were required to be resubmitted through a window that ran from October 1 to December 2, 2024, and were being scored as the period closed. FERC’s Order 2023 (July 2023) provided the federal backdrop, though CAISO obtained regional variations for most of its reforms.

For developers the reset changed the definition of a good queue position. Positions in earlier clusters became scarcer and more valuable; new positions were worth little without site control, LSE interest and a location inside a portfolio zone. The IPE scoring also elevated the strategic value of surplus interconnection capacity at existing points of interconnection, which is one reason co-location and repowering at existing solar sites gained ground.

2.5 Transmission planning

CAISO’s 20-Year Transmission Outlook (May 2022) estimated $30.5 billion of transmission would be needed to integrate the state’s 2040 portfolio, and its annual plans began to deliver it. The 2022-2023 plan approved 45 projects at $7.3 billion. The 2023-2024 plan, approved May 23, 2024, added 26 projects at $6.1 billion, of which $4.59 billion was for three lines to bring North Coast (Humboldt) offshore wind to the Bay Area — a new Humboldt 500 kV substation with an HVDC line to Collinsville and a 500 kV AC line to Fern Road, both opened to competitive solicitation⁴⁰. CAISO’s chief executive framed the planning task as adding roughly 7,000 MW of new resources every year to meet state goals. At the close of the period the draft 2024-2025 plan was weeks from publication; it would shift emphasis from policy-driven offshore lines toward reliability-driven upgrades and reconductoring for load growth.

3. Competitive Landscape

3.1 Buyers

3.2 Builders

The CAISO storage ecosystem at the close of the period comprised roughly 75 active owner-developers and nearly 500 battery projects under construction or in development totaling well over 100 GW¹⁸. The most prolific by project count included EIG-backed platforms, NextEra Energy Resources, Arevon, Hecate Energy and Cultivate Power; the largest operating sites included Vistra’s Moss Landing complex, the Edwards and Sanborn solar-plus-storage project in Kern County, and a series of standalone SP15 batteries built by AES, Calpine (Nova Power Bank), Terra-Gen, REV Renewables, esVolta and others.

3.3 CAISO versus ERCOT: the two storage markets

The only inter-ISO comparison that carried analytical weight in the period was with Texas. At mid-2024 CAISO had 9.87 GW of operating batteries to ERCOT’s 7.74 GW⁵¹; by the end of 2024 the figures were approximately 13 GW and 10 GW. The two markets reached similar scale by opposite routes. CAISO’s fleet was built on bilateral RA contracts with LSEs under CPUC mandates, supported by the IRA’s storage ITC; ERCOT’s was built merchant, on energy and ancillary-service revenue in an energy-only market with a $5,000/MWh cap. CAISO offered bankable contracted cash flows and slower, more expensive development; ERCOT offered faster interconnection and higher but more volatile returns. ERCOT would overtake CAISO in installed capacity in the second quarter of 2025⁵², but not in contracted capacity.

3.4 The M&A marker: Constellation–Calpine

On January 10, 2025, Constellation Energy agreed to acquire Calpine from Energy Capital Partners, CPP Investments and Access Industries for an equity price of approximately $16.4 billion (50 million Constellation shares plus $4.5 billion in cash) and the assumption of about $12.7 billion of net debt — a net purchase price of $26.6 billion after expected interim cash generation and tax attributes, or 7.9× 2026 EV/EBITDA⁷. For CAISO participants the transaction was the period’s clearest statement of what dispatchable, capacity-earning assets in a tightening Western market were worth to a strategic buyer, and it set the reference multiple against which contracted storage platforms were marked in the following months.

3.5 SWOT, restated

4. Regulatory and Policy Framework

5. Site Selection

5.1 Resource availability

California’s resource endowment did not change during the period, but its ranking did. Direct normal irradiation in the Mojave and Colorado Desert reaches the highest values in the continental United States (7–8.5 kWh/m²/day on the World Bank/Solargis Global Solar Atlas), which is why the Riverside East Solar Energy Zone and the corridors along I-10 and State Route 177 remained the core of utility-scale solar development. Offshore, NREL’s 2022 assessment of the Morro Bay and Humboldt wind energy areas found annual mean wind speeds at hub height in the 8–10 m/s range, with Humboldt the stronger of the two⁷⁰ — a resource of the first rank that could not, in the period, be developed at acceptable cost.

5.2 Riverside County: solar-plus-storage on public land

The Riverside East Solar Energy Zone, designated by the Bureau of Land Management under the Western Solar Plan and refined by the DRECP to protect the approaches to Joshua Tree National Park, offered flat basins, sparse vegetation, proximity to the I-10 corridor and existing SCE and IID transmission, and a county Eligible Renewable Energy Resource Development policy that explicitly supported solar paired with storage. CAISO’s 20-Year Outlook assumed roughly 12,266 MW of new solar in the SDG&E area and 4,001 MW in the IID area — 16,267 MW in the region — and prioritized the transmission to deliver it. The trade-offs were known: significant wildfire and extreme-heat exposure, a 2–3 GW seasonal surplus that deepened curtailment, and BLM leasing timelines. The archetype worked. Solar-plus-storage and standalone storage in the eastern SCE and IID footprint were the most heavily contracted assets of the period.

5.3 Morro Bay: floating offshore wind on federal water

The Morro Bay Wind Energy Area covers about 240,898 acres roughly 20 miles off the central coast. In the December 2022 BOEM auction — the first for floating wind in the United States, raising $757 million across five California leases — the three Morro Bay leases went to Equinor, Golden State Wind and Invenergy (Even Keel Wind)⁷³. The state’s AB 525 planning goals and CAISO’s 20-Year Outlook allowance of 5,400 MW for Morro Bay made it the most policy-supported wind site in the state. The 2023-2024 transmission plan nonetheless directed its $4.59 billion of offshore-wind investment to Humboldt, not Morro Bay, and AB 1373’s central procurement mechanism — the only realistic buyer for a $3,000/kW-plus resource — was still in design.

At the close of the period the leases were intact, no construction and operations plans had been approved, and the January 20, 2025 memorandum had frozen new federal approvals and ordered a review of existing leases. The reasonable assessment in March 2025 was that Morro Bay had moved from a 2030s project to an option on a change in federal policy. The epilogue records what became of that option.

5.4 The lesson of the two archetypes

Sites that won in the period shared four attributes: existing or planned transmission within the CAISO plan, a resource that could be firmed with four-hour storage on the same interconnection, a permitting path with a state backstop (AB 205 or BLM/DRECP), and no dependence on a federal approval that a change of administration could withdraw. Riverside East had all four. Morro Bay had two.

6. What a Successful Strategy Looked Like

6.1 The seven pillars

6.2 Three archetypes

6.3 Approaches that did not succeed

• Solar without storage in SP15. Rising curtailment (3.4 TWh in 2024), negative midday prices and Slice-of-Day counting rules concentrated solar-only RA value in the daytime slices where the system was already long.
• Queue speculation. Filing many Cluster 15 positions without site control or LSE interest, expecting to trade them; the IPE reforms and the December 2024 resubmission window eliminated the strategy.
• Offshore-dependent strategies. Any plan whose critical path ran through a federal wind approval was exposed to a single executive action, which arrived on January 20, 2025.
• Indoor, high-density battery buildings on constrained sites. The design lineage of Moss Landing Phase 1 became difficult to insure or to permit within weeks of the fire.
• Treating tariffs and tax rules as static. Sponsors who did not safe-harbor equipment or document prevailing wage and apprenticeship compliance found their 2025 economics repriced.
• Corporate PPA as the anchor. In CAISO a corporate offtake agreement delivered no RA revenue; projects underwritten on it alone could not be financed as storage.

6.4 Offtake channels and stakeholder communications, as practiced

Several offtake channels were available to a utility-scale developer in the period. In order of importance: (1) IOU and CCA resource-adequacy and hybrid PPA solicitations driven by the CPUC’s orders; (2) the CPUC’s central procurement entities for local RA; (3) DWR central procurement under AB 1373 for long-lead resources (still in design at the close); (4) corporate and public-agency PPAs as energy and REC complements; and (5) merchant participation in CAISO’s energy and ancillary-service markets and, prospectively, EDAM. Advisory support was most valuable at the point of monetization — the packaging of queue position, contract and permit into an asset that a strategic buyer would pay for.

Stakeholder communication in the period converged on four messages that regulators, counties and communities responded to: reliability, safety, local benefit, and alignment with the state’s targets. Messages about corporate sustainability or “innovation” carried little weight with the audiences that actually decided permits and contracts.

7. Risk Management

8. The Interregnum

The IRA era ended in practice in the first quarter of 2025 and in law on July 4. This chapter covers the ninety-five days in between, so that the reader knows what the market was waiting for and what it did while it waited.

Conclusion

The IRA era in CAISO lasted roughly thirty-one months in practice and thirty-four in law. In that time the market built the world’s largest contracted battery fleet, reset its interconnection process, launched a Western day-ahead market, and discovered that a decade of flat load was ending. The strategies that succeeded were not novel. They were storage-first siting in the zone with the deepest need, a capacity contract as the first dollar of revenue, a capital stack that used the federal credits as designed, a queue strategy built on readiness rather than volume, permitting and safety treated as commercial imperatives, procurement that assumed the tariff regime would move, and a willingness to sell when the buyer was paying for what the developer had actually created.

Epilogue: After July 4, 2025

Federal tax credits

The One Big Beautiful Bill Act, signed July 4, 2025, ended the technology-neutral §45Y and §48E credits for wind and solar facilities placed in service after December 31, 2027, with an exception for facilities that began construction by July 4, 2026 (which then have the usual four-year continuity window). Energy storage kept the original IRA schedule — full credit for projects beginning construction before 2033, phasing down thereafter.

The asset class that defined the period survived. The asset classes around it did not.

The act also imposed “foreign entity of concern” restrictions, including material-assistance cost-ratio tests, on projects beginning construction after December 31, 2025; removed five-year MACRS for post-2024 starts (while making 100% bonus depreciation permanent); terminated the §25D residential solar credit after December 31, 2025; and, for wind, ended the §45X credit for components sold after 2027^87,88. A July 7, 2025 executive order directed Treasury to tighten begin-construction rules, which it did on August 15, 2025, eliminating the 5% safe harbor for larger wind and solar projects in favor of a physical-work test.

Offshore wind

On December 8, 2025 a federal district court vacated the agencies’ pause on wind approvals as a violation of the Administrative Procedure Act; on December 22, 2025 the administration suspended the leases of five large East Coast projects on national-security grounds. In California the outcome was settlement rather than litigation. In April 2026 Golden State Wind surrendered its Morro Bay lease in exchange for the return of roughly $120 million; in June 2026 Invenergy surrendered Even Keel Wind at Morro Bay together with three Atlantic leases, redirecting $765 million to gas-fired and geothermal projects. Equinor is the sole remaining Morro Bay leaseholder. On June 23, 2026 the California Energy Commission and the Attorney General issued notices of intent to sue the Department of the Interior over the settlements. The Morro Bay archetype described in Chapter 5 has, for practical purposes, ended.

Storage, safety and the market

The CAISO battery fleet reached 15.7 GW at December 31, 2025, adding a record 4.7 GW during the year with standalone systems now 59% of the fleet and 93% of fourth-quarter additions¹⁷; on April 21, 2025 batteries met 36.6% of CAISO load between 5 and 9 p.m., discharging 42.6 GWh. The CEC counted 15,763 MW statewide by April 2025. ERCOT overtook CAISO in installed capacity in the second quarter of 2025 and stood at 15,981 MW in December 2025 — but still without a contracted capacity framework. SB 283 and AB 303 carried the Moss Landing response through the legislature, and EPA-supervised battery removal continued through 2025 and 2026 under the General Order 167-C regime adopted in March 2025.

Interconnection, transmission and Western markets

Following the Cluster 15 scoring, CAISO issued the IPE 5.0 draft final proposal in October 2025; the Cluster 16 window is scheduled to open in October 2026. The 2024-2025 Transmission Plan approved in May 2025 (31 projects, $4.8 billion) is now in execution, with load-growth-driven reliability projects and advanced-conductor reconductoring displacing the policy-driven offshore-wind lines that dominated the 2023-24 plan. EDAM went live on May 1, 2026 with PacifiCorp; Portland General Electric is scheduled for October 2026, LADWP, BANC, PNM and Turlock Irrigation District for 2027, and Imperial Irrigation District for 2028, at which point EDAM is expected to serve about 42% of Western demand. Bonneville adopted a policy to pursue SPP Markets+ in May 2025, and Markets+ is targeting an October 2027 launch. The two-market West is now a fact.

Other markers

• The NRC approved Diablo Canyon’s 20-year license renewal on April 2, 2026; operation beyond 2029/2030 still requires state action.
• LevelTen’s North American solar P25 index reached $61.67/MWh in the fourth quarter of 2025, up 9% year-on-year, with wind at $73.77/MWh — policy and tariff costs continuing to flow into contract prices.
• California extended its cap-and-trade program beyond 2030 in September 2025 legislation, renaming it cap-and-invest.
• Constellation completed the Calpine acquisition on January 7, 2026, following FERC approval on July 24, 2025 and a December 4, 2025 settlement with the Department of Justice requiring divestitures in PJM and ERCOT; no California assets were divested.

Appendix: Q1 2025 Data Snapshot

References