US Power Markets: Inflection
US electricity consumption is forecast at 4,250 BkWh in 2026 (+1.3% YoY) and 4,382 BkWh in 2027 (+3.1%) per the May 2026 EIA Short-Term Energy Outlook. Commercial sector demand — including data centres — will surpass residential consumption for the first time in 2026. BloombergNEF projects US data centre power demand reaching 106 GW by 2035; the IEA’s Lift-Off case sees global data centre demand exceeding 1,700 TWh by 2035.
PJM capacity prices repriced violently in response: from $28.92/MW-day in 2024/25 to $329.17/MW-day for 2026/27 and 2027/28 at the FERC-approved price cap. Hyperscalers have committed over 9 GW of nuclear PPAs at premium economics. The grid is being hardened — covered conductors, undergrounding, dynamic line ratings — at the largest sustained capex pace in modern history. COP30 in Belém failed to agree a fossil fuel transition roadmap; the narrative has shifted from net-zero to energy abundance.
We close Part II with three scenarios for the US grid of 2035 — AI Abundance, Climate-Led Decarbonisation, and the most likely Hybrid Resilience pathway. Part III translates the framework into portfolio positioning.
| 01 | The demand shock — data centres, electrification, manufacturing |
| 02 | PJM capacity escalator & the co-location debate |
| 03 | The new generation stack |
| 04 | ENSO, wildfires & storms — the climate overlay |
| 05 | Grid resilience capex — undergrounding, covered conductors, DLR |
| 06 | From net-zero to energy abundance — the narrative shift |
| 07 | The grid of 2035 — three scenarios |
| G | Glossary additions (cumulative from Part I) |
01 · The demand shock — data centres, electrification, manufacturing
From 2005 to 2022, US electricity demand was essentially flat. Efficiency gains offset population and GDP growth almost perfectly. That equilibrium broke in 2023 and has been shattering ever since. The May 2026 EIA Short-Term Energy Outlook forecasts US electricity consumption of 4,250 BkWh in 2026 (+1.3% YoY) and 4,382 BkWh in 2027 (+3.1%) — a step-change from the prior decade.
Three vectors drive the inflection. Data centres are the largest and fastest-moving. BloombergNEF projects US data centre power demand reaching 106 GW by 2035; the IEA Base Case sees global data centre electricity demand reaching 945 TWh by 2030 and 1,200 TWh by 2035, with the Lift-Off scenario exceeding 1,700 TWh. The EIA forecasts US commercial sector electricity demand growing 2.2% in 2026 and 5.3% in 2027, surpassing residential consumption for the first time. Electrification of transport and heating is a slower but cumulatively large second vector: EV adoption has put incremental load on coastal urban grids; heat pump deployment is adding measurable winter peaks across the Northeast. Re-shored manufacturing — CHIPS Act fabs, battery gigafactories, and chemical plants — is the third, with each large semiconductor fab consuming 100–300 MW of continuous load.
The geography of the shock — uneven by RTO
The demand shock is not evenly distributed. FERC data show MISO experienced 43% annual growth in transmission service requests since 2020. PJM’s data-centre-rich Northern Virginia footprint has absorbed the largest absolute load increase. ERCOT, the Southwest Power Pool, and the Southeast — particularly Georgia’s Atlanta corridor — are seeing rapid growth. CAISO, NYISO, and ISO-NE are growing more slowly, partly reflecting their lower data-centre intensity and partly tighter siting environments.
| Region | Demand driver concentration | Anchor utilities |
|---|---|---|
| PJM (Northern VA) | Data centres: 5,100 MW load growth in 2027/28 auction; 70% of global internet traffic flows through region | Dominion (D), AEP (AEP), Exelon (EXC), Constellation (CEG) |
| ERCOT (Texas) | Data centres + crypto + LNG + manufacturing; 40+ GW pipeline | Vistra (VST), NRG (NRG), Oncor (Sempra), CenterPoint (CNP) |
| SERC (Atlanta) | Data centres + manufacturing reshoring; 50 GW potential pipeline | Southern (SO), Duke (DUK), TVA (federal) |
| MISO | 43% YoY transmission request growth; manufacturing + data | Xcel (XEL), Entergy (ETR), DTE (DTE), Ameren (AEE) |
| WECC | Data centres (Phoenix, Reno); EV electrification | NextEra (NEE) Arizona, PCG, EIX, PNM, IDA |
02 · The PJM capacity price escalator & the co-location debate
PJM Interconnection — the largest wholesale electricity market in North America, serving 67 million people across 13 states — has become the empirical proving ground for the data centre demand shock. The price signal has been violent.
From $28.92/MW-day in 2024/25 to $329.17/MW-day in 2026/27: a tenfold escalation in two years. PJM’s independent market monitor estimates data centres drove 63% of the 2025/26 auction price increase and accounted for 40% of total capacity costs across the last three auctions. NRDC estimates cumulative cost to PJM ratepayers through 2033 at $100–$163 billion. Q1 2026 total wholesale power costs across PJM reached $136.53/MWh, up 76% year-on-year. Capacity costs alone rose 398% in the quarter. Average PJM household bills are projected to rise by approximately $70/month by 2028.
The co-location regulatory debate
Co-location — connecting a large load like a data centre directly to a generator at the same site, bypassing the broader transmission grid — is the most contested regulatory question in US power right now. The advantages are speed (a co-located deal can be operational in 18–24 months vs. 5–7 years for grid interconnection) and reliability. The cost is that the load no longer pays for the shared transmission system that ultimately backstops it.
In December 2025, FERC directed PJM to establish new pathways for co-location and load flexibility that protect reliability and affordability for other consumers. The Amazon–Talen Energy deal at Susquehanna Nuclear Power Station — for 1.92 GW of behind-the-meter nuclear power — was the test case. Microsoft’s revived contract at Three Mile Island (rebranded Crane Clean Energy Center) for 837 MW is the highest-profile example. Meta’s 20-year deals with Constellation (1.1 GW) and Vistra (2.1 GW across three nuclear sites) follow the same architecture.
Hyperscaler PPA deal tracker
| Hyperscaler | Generator counterparty | Asset / type | MW |
|---|---|---|---|
| Microsoft | Constellation (CEG) | Three Mile Island Unit 1 restart (Crane Clean Energy) | 837 |
| Amazon | Talen Energy (TLN) | Susquehanna Nuclear — behind-the-meter | 1,920 |
| Meta | Constellation (CEG) | Clinton Nuclear (Illinois), 20-year PPA | 1,100 |
| Meta | Vistra (VST) | Comanche Peak, Perry, Beaver Valley nuclear; 20-yr | 2,100 |
| NextEra (NEE) | Duane Arnold (Iowa) restart, target 2029 | 615 | |
| Kairos Power | First corporate SMR PPA (advanced reactor) | ~500 | |
| Meta–Oklo | Oklo | Advanced reactor campus, target early 2030s | 1,200 |
| Restart: private | Holtec | Palisades nuclear restart (Michigan) | 837 |
Aggregate disclosed nuclear hyperscaler commitments now exceed 9 GW, with another 3–5 GW of gas and renewables PPAs announced. These contracts are typically 15–20 years at prices well above legacy wholesale economics — converting merchant generators with commoditised wholesale exposure into long-dated infrastructure operators.
Co-location is the most asymmetric structural shift in US power in three decades. The hyperscalers are signing 15–20 year PPAs at prices that lock in nuclear and gas generator economics for two capacity-market cycles. For merchant generators with existing dispatchable fleets (Constellation, Vistra, Talen, PSEG), this transforms commoditised wholesale exposure into long-dated infrastructure contracts. This is the single largest re-rating catalyst in the sector. We position around it explicitly in Part III.
03 · The new generation stack
Six technologies will define the next decade of US generation buildout. Each has a distinct economic profile, deployment timeline, and policy backdrop. We treat each in turn, weighted by realistic 2030 deployment scale.
04 · ENSO, wildfires & storms — the climate overlay
The US grid was built for one climate. It now operates in another. The reliability framework — NERC standards, RTO reserve margins, state IRPs — assumes a stationary distribution of weather events that no longer holds. Readers of our ENSO Primer (Part I of the Climate & Markets series) and ENSO Markets & Portfolio (Part II) will recognise the framework. We extend it here to US power infrastructure.
ENSO impacts on US power, by phase
| ENSO phase | US weather signature | Power system impact |
|---|---|---|
| El Niño (warm phase) | Drier Pacific NW, Ohio Valley, SE; wetter Southwest; suppressed Atlantic hurricanes; mild winter NE | Reduced Pacific NW hydro output (BPA); reduced TVA hydro; lower hurricane-driven outages on Gulf/Atlantic; lower winter peak NE |
| La Niña (cool phase) | Wetter Pacific NW, Ohio Valley; drier Southwest/Texas; active Atlantic hurricane season; colder winter NE/Midwest | Higher Pacific NW hydro; Texas drought stress; ERCOT cooling demand pressure; elevated Gulf/Atlantic outage risk; winter peak risk Midwest/NE |
| Neutral | Mixed signals; regional variability dominates | Baseline reliability planning conditions; ENSO signal weak |
The 2025–26 weak El Niño cycle, currently forecast to transition toward neutral or weak La Niña conditions through 2027 per NOAA CPC and IRI/Columbia, sits in the medium-risk band for both Western wildfire and Atlantic storm activity. Two specific exposures matter for US utilities.
Wildfire risk — California, Pacific NW, Rockies
After PG&E’s Camp Fire liability (2018, ~$30 billion) and the January 2025 Los Angeles fires that implicated Southern California Edison, wildfire mitigation has become the defining capex programme for Western utilities. The mechanism is well-understood: utility equipment (sagging conductors, vegetation-touched lines, faulty insulators) sparks ignitions during high-wind, low-humidity events. Climate change has extended fire seasons across the West by roughly two months since 1980. Insurance markets for wildfire-zone homes are restructuring in real time.
Hurricane & storm risk — Gulf Coast, SE, Mid-Atlantic
Atlantic hurricane activity has trended higher since the mid-1990s; warmer sea surface temperatures provide more energy for storm intensification. Hurricane Beryl (July 2024) caused multi-day outages across CenterPoint Energy’s Houston territory affecting 2.2 million customers. Hurricane Helene (September 2024) caused historic flooding across the Carolinas. Hurricane Milton (October 2024) tested NextEra’s Florida hardening investments. The pattern of grid stress from compound climate events is now well-established; reliability standards and utility capex are adapting.
05 · Grid resilience capex — undergrounding, covered conductors, DLR
Utilities have responded to elevated climate risk with the largest sustained resilience capex programmes in their history. The mitigation toolkit has four principal technologies — undergrounding, covered conductors, dynamic line ratings (DLR), and Flexible AC Transmission Systems (FACTS). Each is rate-base eligible. Each translates directly to allowed-revenue growth.
Covered conductors — the workhorse
Covered conductors replace bare overhead wires with insulated equivalents. PG&E has installed over 1,640 miles of system upgrades since its Community Wildfire Safety Program launched after the 2018 Camp Fire. The utility cites a 67% ignition risk reduction per circuit. SCE’s 2026–28 Wildfire Mitigation Plan calls for 440 additional miles of covered conductor. Average cost ~$1 million per circuit-mile.
Undergrounding — the gold standard
Undergrounding eliminates “nearly all” ignition risk on the circuit but costs 4–6× covered conductor — approximately $4–6 million per mile in PG&E’s territory. PG&E plans to underground 1,077 miles between 2026 and 2028, on top of the 1,250 miles already energised since 2021. SCE plans 260 miles. Both utilities have state-level political consensus around the programme; the prudency challenge at the PUC is low. Earnings durability is high.
Dynamic Line Rating (DLR) and FACTS — the capacity unlock
Dynamic Line Ratings measure real-time conductor temperature, ambient conditions, and wind to dynamically adjust the safe current limit on a transmission line — typically increasing usable capacity by 10–40% over static ratings. FERC Order 881 (effective 2025–26) requires transmission owners to implement ambient-adjusted ratings; FERC is now pursuing DLR mandates more broadly. FACTS (Flexible AC Transmission Systems — STATCOM, SVC, series compensators) manage reactive power and voltage stability to enable higher line loadings. Both are low-capex, high-throughput investments that increase grid utilisation without new line construction.
Hurricane & storm hardening — Florida, Texas, Gulf Coast
NextEra Energy’s Florida Power & Light has spent over $5 billion on storm hardening since Hurricane Wilma (2005), including substantial undergrounding of distribution feeders and concrete pole replacement. The result has been notably faster restoration after subsequent hurricanes — a regulatory virtuous cycle that translates to higher allowed ROEs at the Florida PSC. CenterPoint’s post-Beryl resilience plan calls for over $5 billion in distribution hardening across the Houston territory through 2030.
Climate adaptation capex is the most undervalued earnings driver in the US utility complex. It is rate-base eligible, politically supported across both red and blue states, and effectively countercyclical to broader macro stress. For PG&E, SCE, NextEra, CenterPoint, and Dominion, climate resilience programmes alone justify ~2–3% additional annual EPS growth on top of demand-driven capex.
06 · From net-zero to energy abundance — the narrative shift
The political frame around US power policy has shifted decisively. The 2020–22 framing was “net-zero by 2050” — energy policy as a subset of climate policy, with decarbonisation as the organising principle. The 2024–26 framing is “energy abundance” — energy policy as a subset of industrial and national security policy, with reliability, affordability, and AI competitiveness as the organising principles. This is not subtle and it has direct consequences for capital allocation. As we discussed in Part I’s coverage of the IRA-to-OBBBA reset, the legislative architecture has already adapted.
COP30 Belém — what didn’t happen
The 30th UN climate conference concluded in Belém, Brazil on November 22, 2025. The headline outcome: the formal text failed to include a roadmap to transition away from fossil fuels, despite 80+ countries advocating for one. Petrostate opposition (notably Russia, Saudi Arabia, India among others) blocked the inclusion. Two new initiatives — the Global Implementation Accelerator and the Belém Mission to 1.5°C — were launched as voluntary, parallel-track mechanisms.
What was achieved at COP30: a tripling of adaptation finance by 2035, a Tropical Forests Forever Fund ($5.5 billion raised, 53 participating countries), a Belém Health Action Plan, and a UNEZA Alliance commitment of $66 billion annually for renewable energy plus $82 billion for transmission and storage from public utilities. What was not achieved: a binding global fossil fuel transition timeline. For the US specifically, COP30 confirmed that international climate diplomacy is no longer a binding constraint on domestic energy policy — the Trump administration disengaged early and the EU was the primary advocate for the failed fossil fuel language.
The trajectory: COP28 → COP29 → COP30
| Summit | Headline outcome | Direction of travel |
|---|---|---|
| COP28 (Dubai, 2023) | UAE Consensus — first explicit call to “transition away from fossil fuels”; triple renewables, double efficiency by 2030 | High ambition |
| COP29 (Baku, 2024) | New Collective Quantified Goal: $300B/year by 2035 for developing countries; $1.3T overall target | Finance-focused; ambition stalls |
| COP30 (Belém, 2025) | Mutirão decision; fossil fuel roadmap omitted; adaptation finance tripled; voluntary tracks created | Ambition retreats |
| COP31 (Türkiye, 2026) | Hosted under Türkiye presidency; Brazilian roadmaps to be reported | Forthcoming |
The geopolitical context matters. As we developed in War & Markets, the post-2022 fragmentation of the global trading system has revalued domestic energy security alongside cost. The COP30 failure to agree fossil fuel transition language is a consequence of the same petrostate-versus-importer divide we mapped in the geopolitical risk framework. Energy policy has become inseparable from national security policy.
What this means for US power
The “energy abundance” framing is not anti-climate; it is a re-prioritisation. Three operational consequences for US power investment:
- Coal retirements are being deferred, not cancelled. PJM reports 17 power plants have postponed retirement since the 2024 auction, retaining roughly 1,100 MW of capacity — mostly coal. The economic logic is straightforward: a coal plant clearing the capacity auction at $329/MW-day generates enough revenue to defer a $300M retirement decision.
- Permitting reform is moving. The administration’s executive orders on critical minerals, nuclear, and gas infrastructure permitting have materially reduced approval timelines for these technologies. Solar and wind permitting has tightened in parallel.
- State-federal divergence is widening. California, New York, Massachusetts, and others continue to enforce aggressive emissions targets; Texas, Florida, Wyoming, and others are explicitly anti-restriction. The same generator can have radically different earnings trajectories across states. State PUC composition becomes a critical equity research variable.
07 · The grid of 2035 — three scenarios
We have laid out the demand shock, the new generation stack, the climate vulnerability, and the political narrative shift. The natural next question — for any investor positioning for 2030 and beyond — is what the system actually looks like in 2035. The answer is genuinely contested.
We construct three scenarios, each internally coherent, each grounded in modelled studies or stated industry forecasts. They differ on two structural axes: the primacy of climate vs growth as the organising principle, and the willingness of capital and permitting systems to enable transmission expansion. Probabilities reflect Fenrir Research’s analytical judgement.
Three scenarios at a glance
| Dimension | A · AI Abundance | B · Climate-Led Decarb | C · Hybrid Resilience |
|---|---|---|---|
| 2035 generation | ~5,500 BkWh; gas + nuclear-led | ~5,200 BkWh; 100% clean | ~5,300 BkWh; ~55% clean |
| Gas share | 42% (modest decline) | <5% (CCUS or retirement) | 28% (declining bridge fuel) |
| Nuclear share | 20% (restarts + SMRs + new build) | 15–20% (doubled in constrained NREL case) | 22% (restarts + SMRs prioritised) |
| Wind+solar share | 22% (constrained by OBBBA) | 60–80% (NREL least-cost) | 35% (deploy where economic) |
| Geothermal/hydro | 8% (EGS unlocked) | 8–10% (24/7 firming) | 10% (anchor for 24/7 demand) |
| Storage capacity | ~200 GW | ~400 GW + LDES | ~280 GW |
| Transmission build | 1.3× current | 1.3–2.9× current (NREL) | 1.6× current |
| Incremental cost | $1.2T (capex + fuel) | +$330–740B over reference | $1.6T (capex + transition) |
| Power-sector CO₂ | ~50% below 2005 | 100% reduction (net-zero) | ~70% below 2005 |
| Probability | ~40% | ~15% | ~45% (base) |
2035 generation mix — three scenarios visualised
The five enabling systems any 2035 grid must build
All three scenarios require — at different scales — the same five enabling systems. These are the actual deliverables behind the headline generation mix:
- Firm 24/7 zero-carbon capacity. Existing nuclear extensions, restarts, SMR rollout, enhanced geothermal, expanded pumped hydro. Required across all scenarios. Strongest scaling in B and C.
- Storage at three time horizons. Sub-hourly (frequency regulation, voltage support) via batteries; 4–8 hour (daily arbitrage and solar firming) via lithium-ion BESS; multi-day to seasonal (long-duration energy storage) via flow batteries, compressed air, iron-air chemistry, hydrogen, pumped hydro. B requires materially more LDES; C requires moderate LDES; A requires minimal LDES.
- Transmission expansion at 1.3×–2.9× current capacity. Long-distance HVDC links for moving wind from Plains to coastal load (especially in B); intra-regional reinforcement (all scenarios); offshore wind interconnection (limited in A and C). Permitting is the binding constraint.
- Resilience and adaptation. Undergrounding, covered conductors, dynamic line ratings, FACTS deployment, microgrid integration, advanced inverter capabilities. Rate-base eligible in every scenario; particularly intensive in California, Texas, Florida, the Carolinas.
- Demand-side flexibility. Time-of-use rates, demand response, virtual power plants (VPPs), data centre load shifting, EV smart charging. Increasingly cost-competitive with new generation; underweighted in current planning.
The scenarios differ on the surface mix but converge on the underlying enabling systems. Firm zero-carbon capacity, multi-horizon storage, transmission expansion, climate resilience, and demand-side flexibility are required in every plausible 2035 grid. The investable companies are those exposed to multiple of these enabling systems regardless of which generation-mix scenario plays out. This insight is the central thesis of Part III’s portfolio positioning.
Bottom line · what Part II established
The structural drivers from Part I have crossed into operational reality. Demand is rising at rates not seen since the 1970s. The PJM capacity market has repriced tenfold in two years. Hyperscalers have committed over 9 GW of nuclear PPAs at premium economics. Wildfire and storm risks have driven the largest sustained grid hardening capex programmes in modern history. COP30 confirmed that international climate diplomacy is no longer a binding constraint on US energy decisions. The narrative has shifted from net-zero to energy abundance.
Our three scenarios for 2035 give analytical structure to the next decade. AI Abundance (~40%) sees gas, nuclear restarts, and SMRs lead the buildout with modest decarbonisation. Climate-Led Decarbonisation (~15%) requires a political pivot in 2028 and 100% clean by 2035 per NREL’s modelling. Hybrid Resilience (~45%) — our base case — sees firm low-carbon capacity, geothermal scaling, and gas-with-CCUS converging at ~55% clean, ~70% emissions reduction. All three require the same five enabling systems: firm 24/7 zero-carbon capacity, multi-horizon storage, transmission expansion, climate resilience capex, and demand-side flexibility.
The market has begun to price this. The utility sector has been one of the strongest performers in the S&P 500 over the past 18 months. The merchant generators have re-rated more violently than any other sector. Part III takes this analysis and translates it into specific portfolio positioning across all three scenarios — the S5UTIL trajectory, the P/E expansion, the move from defensive bond proxies to growth narratives, and named anchor stocks across five distinct tracks. We also map the risks that could compress the trade.
G · Glossary additions (cumulative from Part I)
New terms introduced in Part II. Full glossary including Part I terms is at the end of Part I — Foundations.
| MARKETS & DEMAND | |
| AEO | Annual Energy Outlook. EIA’s long-term US energy forecast, published annually. |
| BkWh | Billion kilowatt-hours. EIA’s preferred unit for national consumption (= TWh). |
| BNEF | BloombergNEF. Energy research and forecasting unit of Bloomberg. |
| Co-location | Direct connection of large load to generator at same site, bypassing grid interconnection. |
| STEO | Short-Term Energy Outlook. EIA’s monthly two-year forecast. |
| VPP | Virtual Power Plant. Aggregation of distributed resources providing grid services. |
| TECHNOLOGY & INFRASTRUCTURE | |
| BPA | Bonneville Power Administration. Federal Pacific Northwest hydro operator. |
| DLR | Dynamic Line Rating. Real-time conductor capacity assessment using temperature, weather. |
| EGS | Enhanced Geothermal System. Engineered reservoirs in hot dry rock. |
| FACTS | Flexible AC Transmission Systems. Power electronics for reactive power/voltage management. |
| FEOC / PFE | Foreign Entity of Concern / Prohibited Foreign Entity. OBBBA restrictions on China, Russia, Iran, DPRK. |
| LDES | Long-Duration Energy Storage. Multi-hour to seasonal storage (flow batteries, compressed air, hydrogen, iron-air). |
| NREL | National Renewable Energy Laboratory. US DOE research institution; produces ReEDS capacity expansion modelling. |
| ReEDS | Regional Energy Deployment System. NREL’s flagship capacity expansion model. |
| RTC+B | Real-Time Co-optimisation with Batteries. ERCOT’s storage-aware market design. |
| STATCOM / SVC | Static Synchronous Compensator / Static VAR Compensator. FACTS device categories. |
| TVA | Tennessee Valley Authority. Federal utility serving 10 million people in 7 SE states. |
| POLICY & INTERNATIONAL | |
| COP | Conference of the Parties. Annual UN climate summit under UNFCCC. |
| NCQG | New Collective Quantified Goal. COP29 finance target: $300B/year by 2035 from developed countries. |
| NDC | Nationally Determined Contribution. Country-level climate plan under Paris Agreement. |
| UAE Consensus | COP28 Dubai final text. First explicit call to “transition away from fossil fuels”. |
| UNFCCC | United Nations Framework Convention on Climate Change. Treaty body convening COPs. |
US Energy Information Administration (EIA) — Short-Term Energy Outlook (May 12, 2026); Annual Energy Outlook 2026 (April 8, 2026); Electricity Data Browser. BloombergNEF — US data centre demand outlook (Dec 2025). International Energy Agency (IEA) — Energy and AI report 2025 (Base, Lift-Off, and Headwinds cases). Brookings Institution — Global energy demands within the AI regulatory landscape (April 2026). FERC — quarterly transmission monitoring data; Orders 881, 1920, 2023. PJM Interconnection — BRA results 2024/25 through 2027/28. Monitoring Analytics LLC — independent market monitor reports. Inside Lines (PJM), Utility Dive, Canary Media, IEEFA, NRDC — capacity market and data centre demand analysis. National Renewable Energy Laboratory (NREL) — “Examining Supply-Side Options to Achieve 100% Clean Electricity by 2035” (2022); National Transmission Planning Study (2024). US Department of Energy — Enhanced Geothermal Shot, SMR Tier 1 and Tier 2 funding announcements. NuScale Power Corporation — SEC Form 8-K filings (FY2026 Q1). UN Climate Change (UNFCCC) — COP30 outcomes and Mutirão decision text. World Resources Institute, IISD, European Commission Climate Action — COP30 outcome analyses (November–December 2025). Pacific Gas & Electric Company — 2026–28 Wildfire Mitigation Plan. Southern California Edison — 2026–28 Wildfire Mitigation Plan. S&P Global Commodity Insights — US battery storage capacity reports (Q2/Q3 2025). NBC News, PBS NewsHour, Offshore Wind, Utility Dive — offshore wind regulatory actions (Dec 2025–Jan 2026). NOAA CPC, IRI/Columbia, ECMWF — ENSO outlooks. Fenrir Research prior publications: Power & Markets Part I — Foundations, ENSO Primer, ENSO Markets & Portfolio, War & Markets.
This analysis is for informational purposes only. Not investment advice. All scenario probabilities and forward-looking judgements are analytical synthesis based on cited sources. Stock-specific references are illustrative and not buy or sell recommendations. The author and Fenrir Research may hold positions in securities mentioned.
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