Fenrir Research · US Power Markets · Bonus · Part IV of IV

US Power Markets: The Other Grids

How the world keeps the lights on — UK, EU, India, China & Japan: five jurisdictions, five answers to the same physics.

01 · The five largest power systems — a side-by-side

Before any comparative analysis, the baseline numbers. The five systems differ by an order of magnitude in scale, but the structural questions each is asking — how to meet demand growth, how to integrate renewables, how to price reliability — are remarkably similar.

Scale matters. China generates more than twice the US, six times the EU-27 collectively, and roughly ten times Japan. India, with a population larger than China’s, generates about 20% of China’s electricity — the per-capita gap is the central feature of its growth story. The UK is shown separately at ~300 TWh; it left the EU in 2020 and now operates an independent market. Together, the five large systems account for roughly two-thirds of global electricity generation.

02 · United Kingdom — REMA, CfDs & the rejected zonal pricing

The Great Britain electricity market — the system covering England, Scotland, and Wales, with Northern Ireland operating separately under the Single Electricity Market with Ireland — is the most centrally planned of the major Western markets. It runs as a single national wholesale price, settled at half-hourly resolution. Generators and suppliers trade bilaterally and through the spot exchange. The Balancing Mechanism, operated by the National Energy System Operator (NESO), resolves the difference between contracted positions and physical flows in real time.

The three legs of the GB stool

The system rests on three interconnected mechanisms:

1. The Wholesale Market. Energy bids and offers clear against a single national price. Marginal pricing (pay-as-clear). Settlement moved from half-hourly to a more granular resolution under the elective Half-Hourly Settlement programme; 15-minute settlement is on the EU-side roadmap but not yet GB.
2. Contracts for Difference (CfD). The dominant route to market for new low-carbon generation since 2014. Developers bid into government-run auctions called Allocation Rounds (AR7 opened summer 2025). Winning bids receive a strike price; CfDs pay the difference between the strike price and a market reference price for a 15-year term. This is functionally a long-dated PPA with the government.
3. The Capacity Market. Annual four-year-ahead auctions procure firm capacity to ensure system reliability through periods of low renewable output. Generators (and increasingly demand-side response and storage) bid £/kW-year for capacity contracts of 1–15 year duration.

REMA — the reform that didn’t happen

The Review of Electricity Market Arrangements (REMA) was launched in 2022 to consider whether the wholesale market should be split into geographic zones (zonal pricing) — similar to the locational marginal pricing in US RTOs. The case for zonal pricing was that curtailment payments approached £700 million in 2025; locational signals would direct generators to build where the grid can absorb power, reducing those payments.

On July 10, 2025, the UK Government published the REMA Summer Update deciding to retain a single national GB-wide wholesale market and pursue “Reformed National Pricing” instead. Three arguments carried: investor uncertainty during transition; the postcode-lottery framing for consumers; concern that the best wind locations in Scotland and the North-east would become uneconomic. The Reformed National Pricing Delivery Plan followed on April 21, 2026 — providing the implementation roadmap.

Reform under this framework includes: sharpening locational signals via Transmission Network Use of System (TNUoS) charges, reforming connection queue management, broadening the Balancing Mechanism to smaller participants, and introducing a Strategic Spatial Energy Plan (SSEP) by end-2026. The CfD scheme will be reformed to better reward dispatchable low-carbon technologies (likely a capacity-based element). The Capacity Market is under separate review.

03 · European Union — federation of 27, marginal pricing, capacity mechanisms

The EU electricity system is not a single market. It is twenty-seven national markets — each with its own transmission system operator (TSO), regulator, generation mix, and policy preferences — federated under common European rules administered by the European Commission, ACER (the Agency for the Cooperation of Energy Regulators), and ENTSO-E (the European Network of Transmission System Operators for Electricity).

The federation in practice

Day-ahead and intraday markets are coupled via the Single Day-Ahead Coupling (SDAC) and Single Intraday Coupling (SIDC) algorithms, producing implicit cross-border auctions across most of the EU plus the UK (which remained coupled post-Brexit through interim arrangements). On September 30, 2025, the EU’s day-ahead market moved from hourly to 15-minute trading intervals — a major reform that allows prices to reflect intra-hour supply-demand variation, critical as renewable penetration grows.

Wholesale pricing across the EU is uniformly marginal (pay-as-clear) — the highest-cost generator dispatched sets the price for all dispatched generators. This is the same mechanism as US RTOs. The political controversy of marginal pricing — that gas often sets the clearing price, allowing zero-marginal-cost renewables and nuclear to capture economic rents — has been one of the dominant policy debates in Europe since the 2022 energy crisis.

Capacity mechanisms — from emergency to structure

In 2024, the EU electricity market design reform repositioned capacity mechanisms from “measure of last resort” to “structural feature” of the electricity market. The 2025 Clean Industrial Deal State Aid Framework (CISAF) consolidated the rules. Eight member states currently operate capacity mechanisms or strategic reserves:

Fuel mix & targets

In 2024, renewables accounted for 47.5% of EU gross electricity consumption — up from 37% in 2020. The Commission projects renewables to exceed 60% of electricity by 2030. Solar and wind capacity grew from 200 GW in 2010 to roughly 850 GW in 2024; hydropower has been stable at around 150 GW. Nuclear capacity is highest in France (~63 GW) with significant fleets in Spain, Belgium, Czechia, Slovakia, and Finland — including the new EPR units at Flamanville (France) and Olkiluoto-3 (Finland).

National policy diverges sharply. France has adopted a Universal Nuclear Payment (progressive levy on EDF redistributed to consumers) and Nuclear Production Allocation Contracts for energy-intensive industries. Germany subsidises industrial electricity prices directly and is building 8–10 GW of “hydrogen-ready” gas plants. The Nordics defend pure marginal pricing. Spain and Portugal lead on corporate PPAs. The bloc as a whole targets net-zero by 2050; the power sector should achieve effective net-zero around 2040 to keep that on track.

04 · India — CERC/SERC, exchanges, the 500 GW question

India is the only large jurisdiction where electricity demand growth is structural — driven by economic development, electrification, and rising per capita consumption — rather than the AI shock that has reset the US picture. The Central Electricity Authority projects total demand at 817 GW by 2030, up from roughly 470 GW today. Meeting that demand while simultaneously hitting the 500 GW non-fossil capacity target by 2030 is the central question of Indian power policy.

The federal-state matrix

Indian electricity is a concurrent subject — both the Union and state governments have legislative authority. This produces a regulatory matrix with materially different politics in each state:

• Central Electricity Regulatory Commission (CERC) regulates inter-state generation and transmission, sets tariffs for central generating utilities (NTPC, NHPC, Power Grid), and approves inter-state transmission charges.
• State Electricity Regulatory Commissions (SERCs) — one per state — regulate intra-state generation, retail tariffs, and the distribution companies (discoms). This is where most retail electricity policy actually happens.
• Central Electricity Authority (CEA) is the technical planning body responsible for the National Electricity Plan and the National Electricity Policy.
• Distribution companies (discoms) are the retail link. Most are state-owned and chronically loss-making — political tariff suppression, cross-subsidisation of agricultural consumers, and technical/commercial losses have produced repeated bailouts (UDAY 2015, RDSS 2021, the proposed Electricity Amendment Bill 2025).

The exchange-based spot market — IEX

India’s wholesale spot market runs primarily through power exchanges — predominantly the Indian Energy Exchange (IEX), with Hindustan Power Exchange and PXIL also operating. Volumes have grown materially as renewable integration has driven the need for short-term balancing. Key recent developments:

• Real-Time Market (RTM) — half-hourly auctions enabling balancing — has grown rapidly as solar variability has increased.
• Green Term Ahead Market (GTAM) and proposed Green RTM — exclusive renewable energy trading segments to address the May 2025 anomaly where IEX prices repeatedly hit zero during midday solar surplus.
• SHAKTI 2.0 — coal reform allowing generators to sell unrequisitioned surplus (URS) directly on exchanges without PPAs.
• Electricity derivatives — SEBI and CERC approved electricity futures in 2025, giving hedging tools for the first time.
• Market coupling — CERC’s October 2025 decision to introduce market coupling across exchanges has been challenged in the Supreme Court; outcome will materially affect IEX’s competitive position.

Generation mix & the 500 GW target

India installed 41 GW of renewables in the first eleven months of 2025 — a record annual addition. Renewables now account for roughly 40% of installed capacity (though only about 20% of actual generation, reflecting capacity-factor differences). Coal still provides about 70% of generation. The Indian government’s 500 GW non-fossil capacity target for 2030 — up from roughly 220 GW today — requires sustained 40+ GW annual renewable additions, which appears feasible.

UC Berkeley’s India Energy & Climate Center modelling suggests cost-effective coal capacity by 2030 is 242 GW — meaning only ~2 GW of additional coal beyond the 27 GW already under construction is economic. By 2032, cost-optimal non-fossil capacity rises to 590 GW including 372 GW solar, 105 GW onshore wind, 16 GW offshore wind, plus 86 GW of storage. The supply-side investment case is exceptional; the demand-side reform (discom finances, agricultural tariffs, grid stability) is the binding constraint.

As War & Markets developed, India’s energy strategy sits within a broader geopolitical framework — energy import dependence on Russian crude (post-sanctions), Middle Eastern LNG, and Chinese solar modules creates structural exposures that pure power-market analysis misses. A standalone India primer covering this in depth will follow as a separate post.

05 · China — State Grid, spot market pilots & the renewables overtake

China generates more electricity than the next two largest systems (US and EU) combined. The system is centrally planned, dominated by two state-owned grid operators — State Grid Corporation of China (covering ~88% of the country) and China Southern Power Grid — and five state-owned generation conglomerates (the “Big Five”: Huaneng, Datang, Huadian, Guodian-CHN Energy, State Power Investment Corporation). Spot market reform is bolted onto this structure rather than replacing it.

The renewables overtake

In Q1 2025, China’s installed wind and solar capacity reached 1,482 GW — surpassing coal-fired capacity (1,451 GW) for the first time. The country hit its 1,200 GW wind+solar target six years ahead of schedule. The DNV Greater China outlook projects the cumulative wind+solar fleet reaching 3.6 TW by 2035. China added 277 GW of solar and 79 GW of wind in 2024 alone. In H1 2025 alone, China added 210 GW of solar and 50 GW of wind.

But the capacity-vs-generation distinction matters enormously. Coal still operates at higher capacity factors than wind or solar, so coal still supplied roughly 54% of electricity in 2024, gas and oil another 7%, and renewables + nuclear together ~38%. Curtailment of wind and solar — utilisation reductions to maintain grid stability — remains substantial in northern provinces. The structural challenge is not adding more wind and solar capacity; it is integrating it into a grid still dispatched on legacy command-and-control rules.

The spot market reforms

China’s electricity market reform has been gradual and provincial. The 2021 reform allowed coal prices to fluctuate ±20% around benchmarks. In 2024, a two-part pricing mechanism was introduced — capacity payments to ensure reliability plus market-based energy pricing. In April 2025, the NDRC and NEA announced “nationwide coverage” of the electricity spot market by end-2025:

• Hubei province launched regular spot market operations by June 2025; Zhejiang by end of 2025.
• Sixteen additional provinces including Fujian, Sichuan, and Jiangsu commenced trial operation of continuous spot market settlement by end-2025.
• Inter-provincial markets (especially Southern Grid) are scaling simulation efforts.
• In 2025 renewable generators received equal recognition with thermal generators in the spot market — a critical step toward making variable renewables financially viable.

Empirical evidence from China’s pilot spot markets is striking: introducing spot markets reduced coal power by 6.6% and accelerated renewable integration meaningfully. SO₂ emissions fell 15.9%, NOₓ 13.4%, CO₂ 6.7% per year in studied provinces.

06 · Japan — S+3E, nuclear restart & the Kashiwazaki-Kariwa moment

Japan’s electricity system has been defined for fifteen years by a single date: March 11, 2011. The Fukushima Daiichi accident shut down the entire Japanese nuclear fleet — 54 reactors representing roughly 30% of pre-accident generation. The country pivoted to imported LNG, becoming the world’s largest LNG importer and pushing power-sector emissions sharply higher. The fifteen-year story since has been the slow, contested, plant-by-plant restart of the nuclear fleet.

The S+3E framework

Japanese energy policy is built around the S+3E framework: Safety first, then the three E’s — Energy security, Economic efficiency, and Environment. The Seventh Strategic Energy Plan, finalised by Cabinet in February 2025, sets the FY2040 energy mix at 40–50% renewables and around 20% nuclear, with the remainder split between thermal sources (transitioning toward hydrogen, ammonia, and CCUS) and emerging technologies. The plan targets a 73% reduction in GHG emissions by 2040.

The Kashiwazaki-Kariwa restart

On February 9, 2026, Japan restarted Unit 6 of the Kashiwazaki-Kariwa Nuclear Power Station — its largest nuclear plant — for the first time since the Fukushima accident. EIA estimates the unit will produce 9,500 GWh annually and displace approximately 1.3 million tons of LNG (62 Bcf of gas) per year. Tokyo Electric Power Company (TEPCO) — operator of the plant and the wider Fukushima-affected region — has delayed Kashiwazaki-Kariwa Unit 7 (also 1,356 MW) restart until 2029–2030.

As of February 2026, Japan has 15 operating nuclear reactors with combined capacity of ~33 GW. The fleet produced 83 TWh in 2024, or 9% of national electricity. The trajectory under the Seventh Strategic Energy Plan would scale this to 20% by 2040 — implying further restarts (Tomari, Hamaoka, Onagawa pending) plus potentially new advanced reactor builds.

Market structure — liberalised, OCCTO, JEPX

Japan’s electricity market has been progressively liberalised since 2016. Key institutions:

• METI (Ministry of Economy, Trade and Industry) sets energy policy. The Agency for Natural Resources and Energy (ANRE) is METI’s energy unit.
• EGC (Electricity and Gas Market Surveillance Commission) formulates retail and trading guidelines; effectively the electricity regulator.
• OCCTO (Organization for Cross-regional Coordination of Transmission Operators) coordinates the ten regional transmission and distribution utilities, manages the capacity market, and handles FIP (Feed-in Premium) payments.
• JEPX (Japan Electric Power Exchange) operates spot wholesale markets, intraday markets, and non-fossil certificate trading.
• NRA (Nuclear Regulation Authority), established post-Fukushima, is the independent nuclear safety regulator.

07 · Net-zero targets & generation mix — convergence and divergence

A direct visual comparison of the five jurisdictions on their current and stated future fuel mixes. The patterns are striking: the EU and UK are most decarbonised today; China is decarbonising fastest in absolute capacity terms but from a higher-coal baseline; India is growing renewables fastest as a share of additions but starting from a low base; the US sits structurally between the two extremes; Japan is the slowest mover among the five.

Net-zero commitments — a side-by-side

The COP30 outcome in Belém — as we discussed in Part II — confirmed that the international climate diplomacy framework can no longer force convergence among these jurisdictions. Net-zero ambition now varies materially. The EU and UK lead. Japan and China are pragmatic. The US has retreated from federal targets entirely. India was always a 2070 country given its development trajectory. The five major systems are now diverging, not converging.

08 · Where the five grids converge — and where they don’t

Despite the institutional, regulatory, and political diversity, the five jurisdictions are converging on several technical realities. They are diverging on others. The pattern matters for global capital allocation.

Where they converge

1. Renewables are economic. In all five jurisdictions, new utility-scale solar and onshore wind are now cheaper than new coal or gas without subsidies. Renewables deployment continues at scale in every market — even those (US, China) where the political framing has moved on from climate priority.
2. Storage is the next priority. Every jurisdiction is building grid-scale batteries. The US has 38 GW; China is doubling annually; India is at 13+ GWh under construction with 86 GW projected cost-optimal by 2032; the EU is scaling fast; Japan is laggard but increasing.
3. Capacity mechanisms or equivalents are spreading. The US has PJM/NYISO/ISO-NE capacity markets, Japan has OCCTO capacity market, the EU is making capacity mechanisms a structural feature, the UK has its Capacity Market, China introduced two-part pricing including capacity payments in 2024. Energy-only is a dying market design.
4. Nuclear is being reconsidered. The US is restarting reactors with hyperscaler PPAs. Japan restarted Kashiwazaki-Kariwa Unit 6 in February 2026. France is investing heavily in EPR-2 new build. The UK is investing in Sizewell C. China continues steady-state construction (around 5 GW/year). Even Germany — having shut its last reactors in 2023 — is debating reopening the question. Only India is not materially expanding nuclear share.
5. Grid hardening matters everywhere. Wildfire mitigation in California, undergrounding in Florida, storm-hardening in the UK and Japan, monsoon-resilience in India, typhoon hardening in southern China and Japan — all five jurisdictions are now in a sustained grid-resilience capex cycle.

Where they diverge

1. Market liberalisation level. The UK, EU, and US run liberalised wholesale markets with merchant generators. India has a hybrid (PPAs + exchange). China remains state-dominated despite spot pilots. Japan is hybrid post-2016. This determines who captures the cash flow from rising prices.
2. Federal vs unitary structure. The US (50 state PUCs), EU (27 national systems), and India (28 SERCs) are federal. The UK, Japan, and China are unitary in power policy. This determines policy coordination speed.
3. Demand growth rate. Highest in India (structural), then China (slowing), US (AI-driven), EU (flat-to-declining), UK (flat), Japan (declining). This determines capex requirement scale.
4. Gas dependence. Highest in Japan (33% of generation), then US (41% — but domestically supplied), UK (25%), EU varies by member state, India lowest (3%), China low (3%). This determines LNG market exposure.
5. Coal trajectory. China and India still building (modestly); US, UK, EU, Japan all retiring (US slower than legislated due to AI demand). This determines transition speed.
6. Net-zero credibility. Highest in EU and UK (institutionalised); medium in Japan, China, India; lowest in US (federal commitment effectively withdrawn). This determines policy risk premium.

Bottom line · what this bonus post established

G · Glossary additions (cumulative from Parts I & II)

New terms introduced in this bonus post. Full glossary including Parts I & II terms is in those posts.

Fenrir Research · US Power Markets · Part III of IV

US Power Markets: Re-rating

The trade in US utilities — from bond proxy to growth engine, and how to position around the most violent sector re-rating in two decades.

01 · S5UTIL — the sector has already started running

The S&P 500 Utilities sector index (S5UTIL) is the cleanest read on how the market is pricing the structural shift we’ve documented. The trajectory has been violent. After fifteen years of compounding at roughly the rate of inflation — appropriate for a defensive bond-proxy sector — the index re-rated sharply from late 2024 onwards.

Three observations matter. First, the sector tracked roughly at the broad market through 2019–24 — appropriate for its historic role as a bond proxy with low beta. Second, beginning in late 2024 the sector decoupled materially, outperforming the S&P 500 over an extended period. This is not a momentary flash. It is the market re-rating utility earnings growth in response to the data centre demand shock, hyperscaler PPAs, and capacity market reset documented in Part II. Third, the dispersion within the sector has widened sharply: merchant generators (Constellation, Vistra, Talen) have outperformed regulated names by 2–3× — a pattern that informs portfolio construction.

Forward P/E — the multiple expansion story

The S5UTIL forward P/E has expanded from roughly 16–17× during the 2015–22 era to 20–21× today. That move alone represents roughly 25% of the index appreciation; the balance comes from earnings upgrades. Selected name-level forward multiples illustrate the dispersion:

Note: Forward P/E figures are approximate as of May 2026 and based on analyst consensus EPS estimates. Multiples shown for illustrative purposes; investors should verify current valuations before any position.

02 · The investment thesis shift — bond proxy to growth engine

For three decades, US utilities were owned for three reasons: 3–5% dividend yield, defensive characteristics in market drawdowns, and inflation-linked rate-base growth of 4–6% per year. The total return narrative was bond-like: low single-digit EPS growth plus the dividend. This framing is now obsolete.

What changed — five structural drivers

1. Demand growth is back, structurally. The flat-demand consensus that defined 2005–22 has broken. EIA forecasts 3.1% YoY growth in 2027. The vector mix — data centres, electrification, manufacturing reshoring — is durable across multiple administrations. We covered this in detail in Part II.
2. Rate-base growth has accelerated. Regulated utility capex is running 60–80% above the pre-2023 baseline. Climate adaptation (covered conductors, undergrounding), data centre transmission build-out, and aging grid replacement combine to produce 8–10% rate-base growth at the most exposed names — versus 4–5% historic norm.
3. Merchant generator economics have repriced. PJM capacity prices at $329/MW-day. Hyperscaler PPAs at premium prices for 15–20 years. Coal-plant retirements deferred. Nuclear restart economics transformed. Constellation guidance: 20%+ annual EPS growth 2026–29.
4. Earnings revisions have turned positive. Q3 2025 Utilities sector posted +14% YoY EPS growth — the fastest among defensive sectors and ahead of materials, energy, and consumer staples. This is the empirical evidence of the structural shift.
5. Inflation Reduction Act tailwind, OBBBA selective preservation. Nuclear PTC (§45U), battery storage ITC (§48E), geothermal credits, and CCUS §45Q all preserved or enhanced under OBBBA. Wind and solar compressed but operational projects retained credits. As we mapped in Part I, the OBBBA framework is brutal for new wind/solar but supportive of nuclear and storage operators.

The new mental model — three earnings drivers

For regulated utility names, the earnings algorithm is now:

For merchant generators, the algorithm runs differently:

Both algorithms now produce 8–20% annual EPS growth at the most exposed names. That is fundamentally not a bond proxy any longer. The required return investors should expect from the sector — and the multiples the market is willing to pay — have re-rated accordingly.

03 · Five positioning tracks — anchor stocks & the rationale

We construct exposure across five distinct tracks. Each captures a different aspect of the structural thesis. Together they provide diversified exposure to the convergent outcomes we identified in Part II’s three-scenario framework — firm zero-carbon capacity, multi-horizon storage, transmission expansion, climate resilience, and demand-side flexibility.

Track 1 — Nuclear-anchored merchant IPPs (the pure-play growth trade)

Names: Constellation Energy (CEG), Vistra (VST), Talen Energy (TLN), Public Service Enterprise Group (PEG).

These are the cleanest hyperscaler beneficiaries. Long-dated PPAs convert merchant exposure into infrastructure-grade contracted cash flows. The §45U Zero-Emission Nuclear PTC, preserved under OBBBA, provides a price floor; data centre PPAs provide an explicit price ceiling well above legacy wholesale economics.

Constellation owns the largest US nuclear fleet (~23 GW), signed the Microsoft–Three Mile Island restart, has 1.1 GW Meta PPA at Clinton, and is guiding 20%+ annual EPS growth 2026–29 after the Calpine acquisition. Vistra closed a $4.7 billion Cogentrix gas deal and has signed 3.8 GW of 20-year hyperscaler PPAs across Comanche Peak, Perry, and Beaver Valley. Q1 2026 revenue at Constellation was up 64% YoY. Talen Energy is the Susquehanna nuclear story — Amazon’s 1.92 GW behind-the-meter deal. PSEG operates regulated PSEG New Jersey alongside merchant nuclear at PSEG Power; the hybrid structure provides a more conservative entry into the same thesis.

The risk: valuations already reflect a meaningful portion of the AI thesis. The opportunity: if 20% earnings growth proves durable, multiples can hold or re-rate further. Conviction: very high. Position size: 25–30% of sector sleeve.

Track 2 — Regulated utilities with data centre footprint (the defensive growth trade)

Names: Dominion Energy (D), Southern Company (SO), NextEra Energy (NEE), Duke Energy (DUK), Xcel Energy (XEL), Entergy (ETR).

These are the rate-base growth stories. Dominion serves Northern Virginia, where roughly 70% of global internet traffic flows; it is in contract talks for 40–47 GW of new data centre capacity. Southern has 50 GW of potential large-load growth in its Georgia pipeline, with ~40 GW concentrated around Atlanta. NextEra has a 33 GW renewables backlog plus a 60 GW data centre hub in development with 10 GW of approved new gas. Duke, Xcel, and Entergy cover similar territory in the Carolinas, Upper Midwest, and Gulf Coast respectively.

These names trade at lower multiples than the merchant IPPs (typically 18–22× forward EPS), pay higher dividends (3–4% yields), and offer regulated rate-base growth in the 6–10% range. The earnings outcome is more predictable; the catalyst path is slower. This is the sweet spot for a balanced equity portfolio. Conviction: high. Position size: 30–35% of sector sleeve.

Track 3 — Equipment manufacturers (the picks-and-shovels)

Names: GE Vernova (GEV), Eaton (ETN), Quanta Services (PWR), MasTec (MTZ), Vertiv (VRT), Generac (GNRC).

The gas turbine, transformer, and transmission build-out has a finite list of beneficiaries. GE Vernova reported $2.4 billion in Q1 2026 data centre-related orders — exceeding all of 2025. Management has guided 16–18% organic revenue growth for the power division in 2026, with electrification revenues up 20%. Free cash flow is targeted at $4.5–5 billion. The risk: cyclical execution and gas turbine supply chain bottlenecks could swing margin guidance.

Eaton, Quanta, and MasTec are the transmission and substation buildout proxies — Quanta’s backlog stretches well into 2028, and the firm has built deep capacity in HVDC engineering relevant to all three Part II scenarios. Vertiv (data centre cooling and power management) is the most direct data centre play but trades at the most expensive multiple in the basket (35× forward). Generac provides residential and small-commercial backup power — secondary play with elevated cyclical sensitivity.

Conviction: high. Position size: 15–20% of sector sleeve. Important caveat: this track has more cyclical risk than Track 1 or 2 — order books can compress quickly if construction slows.

Track 4 — Climate resilience and grid hardening (the rate-base compounders)

Names: PG&E Corporation (PCG), Edison International (EIX), CenterPoint Energy (CNP), Avangrid (AGR).

PG&E remains the most contentious name in US utilities — the wildfire liability tail is genuinely difficult to size, and the political risk in California is non-trivial. But the rate-base growth trajectory is exceptional: ~10% annual compounding on the back of $12+ billion of undergrounding and covered-conductor deployment, all rate-base eligible. SCE’s parent EIX is similar with somewhat lower volatility. CenterPoint is the Houston-focused version of the same thesis — post-Hurricane Beryl, the company committed over $5 billion to distribution hardening across the Houston territory through 2030. Avangrid (Iberdrola’s US subsidiary, recently re-taken private) offers similar exposure across Northeast.

These names trade at meaningful discounts to peers (PCG at 14× forward vs sector 20×) and offer the highest risk-adjusted rate-base growth in the sector. The market is pricing the wildfire liability tail; we believe the political consensus around resilience and the ongoing capex programmes have materially reduced that tail risk versus 2019. Conviction: medium-to-high (asymmetric). Position size: 10–15% of sector sleeve.

Track 5 — SMRs and advanced nuclear (the option value)

Names: NuScale Power (SMR), BWX Technologies (BWXT), Cameco (CCJ), Centrus Energy (LEU), Oklo (OKLO).

Position size matters here. SMRs are a 2030+ deployment story with significant execution risk. NuScale’s 6 GW TVA partnership and ENTRA1 relationship represent the largest committed pipeline but no module has yet been built. BWX Technologies is the most defensive way to play the theme — it has the existing fabrication capacity for SMR pressure vessels and a $1.5 billion NNSA defence enrichment contract. Cameco owns 49% of Westinghouse, making it the cleanest broad nuclear exposure. Centrus Energy is the most direct play on HALEU (High-Assay Low-Enriched Uranium) supply for advanced reactors. Oklo is the highest-beta SMR story.

Conviction: medium (binary outcome). Position size: 5% of sector sleeve. Treat the segment as venture-style optionality within an income-oriented utility book. If SMRs deploy at scale by 2030, this segment 3–5×; if they slip to 2033+, the names compress materially.

04 · Scenario sensitivity — how each track performs across A/B/C

The five tracks have different sensitivities to the three scenarios we constructed in Part II. This is what makes the portfolio construction robust — the convergent enabling systems means most tracks perform across most scenarios. The table below scores each track across the three scenarios with a directional rating.

* Track 3 equipment OEMs see mixed outcome in Climate-Led Scenario B because gas turbine demand compresses while transmission/HVDC build accelerates — net depends on company mix. GE Vernova is more balanced; pure-play gas turbine names would suffer.

The portfolio implication: Tracks 1, 2, and 4 perform across all three scenarios. Track 3 is robust on the dominant A and C scenarios. Track 5 has optionality biased toward Scenario B but with sufficient base-case demand in A and C to sustain the names. The scenario-agnostic nature of Tracks 1, 2, and 4 is what justifies the heavier weights in those buckets.

05 · Portfolio blueprint — conviction-weighted allocation

The portfolio blueprint below assumes a dedicated utility / energy infrastructure sleeve within a broader equity book. For investors managing the sector as a single line item within a diversified equity portfolio, sleeve weight should be 8–12% of total equity — meaningfully above the S&P 500 utilities weighting (~2.5%) to reflect the structural overweight thesis.

Within-track guidance

Within each track, position-level sizing should follow the within-track diversification rule — no single name above 40% of track weight. For Track 1, that implies CEG and VST at 30–40% each, TLN at 15–20%, PEG as the conservative hedge at 10–15%. For Track 2, the natural anchor weights are NEE (largest, most diversified) at 20–25%, with the others equally split. For Track 3, GE Vernova is the dominant exposure (35–40%) given its leveraged play on the gas turbine bottleneck.

06 · Five risks that could compress the trade

No thesis survives complete certainty. The five risks below could materially compress the trade. We assign probabilities and direction of impact to each.

Risk 1 — Capacity market reform

State-level political pressure on PJM is intense. A re-engineered auction with lower price caps, demand-response priority, or load-shifting mandates could compress the wholesale tail meaningfully. Watch Pennsylvania, Maryland, and Virginia legislatures through 2026–27. The most likely outcome is incremental tightening — for example, a graduated price cap reduction over 3–5 years — rather than a fundamental redesign. But the political risk premium is real. A 30–40% capacity price reduction would compress Track 1 EPS by ~10–15% versus current consensus.

Risk 2 — Hyperscaler capex slowdown

The AI capex cycle is correlated to hyperscaler earnings. A meaningful enterprise-software demand pause would cascade to power. The 2030 deployment forecasts assume continuous compute scaling; this is not guaranteed. The 2025 enterprise IT spending environment has been resilient but recall the cloud capex pause in 2019–20. A 12-month pause in hyperscaler builds would not break the thesis but would substantially compress Track 1 and 3 valuations — both rerate to historic ranges in such a scenario.

Risk 3 — Cost-of-capital sensitivity

Utility names with 60–65% debt-to-cap ratios are highly sensitive to long-end yields. A 100 bps move in 10-year Treasuries compresses regulated utility multiples by ~10–15%. The Federal Reserve’s path through 2026–27 is the dominant macro input here. Our base case anticipates the curve roughly stable through 2026 with measured cuts; a hawkish surprise could compress Tracks 2 and 4 materially. Track 1 is partially insulated because hyperscaler PPAs are largely contracted at fixed prices and capacity payments are not directly rate-sensitive.

Risk 4 — Regulatory backlash on rate increases

Average residential bills are rising. Multiple states (Virginia, Oregon, New Jersey) have introduced or are considering data-centre-specific rate classes that shift costs from households to large-load customers. This is rational and arguably overdue, but it could compress merchant generator margins on new contracts and slow rate-base growth at affected utilities. Specifically, Virginia legislation could materially affect Dominion’s data centre tariff structure. Track 2 names with the largest data centre concentration are most exposed.

Risk 5 — Gas turbine supply chain

The single largest execution risk. If GE Vernova, Siemens Energy, or Mitsubishi Power cannot scale production, gas-heavy build plans slip and merchant nuclear holds pricing power longer — but the broader sector earnings trajectory disappoints. This is genuinely binary for Track 3. If supply chain resolves on schedule, GE Vernova is a 2–3× return story by 2028. If it slips further (gas turbine lead times rising from 60 months to 72+ months), the names compress materially. Currently rated as 50/50 in our base case.

07 · Catalysts watch & what to monitor

The trade is now well-mapped. From here, the question is execution. Below is the calendar of catalysts we monitor through 2026–27.

Bottom line · what Part III concluded

G · Glossary additions (cumulative from Parts I, II, and Bonus)

New terms introduced in Part III. Full glossary spans across all four posts.

Fenrir Research · US Power Markets · Part II of IV

US Power Markets: Inflection

Demand, resilience & the grid of 2035 — the flat-demand consensus is dead, the grid is hardening against an unstable climate, and the next decade will be defined by which scenario wins.

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.

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

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.

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

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.

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

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:

1. 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.
2. 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.
3. 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

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:

1. 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.
2. 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.
3. 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.
4. 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.
5. 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.

Bottom line · what Part II established

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.

Fenrir Research · US Power Markets · Part I of IV

US Power Markets: Foundations

How the American grid works — a primer on generation physics, market architecture, and the supply-chain choke points reshaping US power.

01 · A timeline of US electric power, 1882–2026

Every structural feature of US electricity in 2026 is a fossil of a specific historical decision. The shape of the regulatory pyramid, the existence of seven different wholesale markets, the legal status of nuclear plants, the divide between vertically integrated utilities and merchant generators — none of these are technically optimal. They are political settlements layered on top of older political settlements. We organise the chronology around five inflection points.

Formation (1882–1935). Thomas Edison’s Pearl Street Station in Manhattan, commissioned September 4, 1882, was the first commercial electric utility. The current War — Edison’s DC versus Westinghouse and Tesla’s AC — ended with AC’s victory by the 1890s, fundamentally because AC could be transformed to high voltages for long-distance transmission. State public utility commissions began in 1907 (Wisconsin and New York simultaneously), establishing the principle that electricity was a “natural monopoly” requiring price regulation. The industry consolidated rapidly into pyramidal holding companies whose financial speculation contributed to the 1929 crash.

The regulated era (1935–1978). Roosevelt’s Public Utility Holding Company Act (PUHCA, 1935) broke the holding companies. The Federal Power Act (also 1935) created the Federal Power Commission (renamed FERC in 1977) to regulate interstate wholesale sales and transmission. The 1965 Northeast blackout — 30 million people, nine hours — drove the formation of the North American Electric Reliability Council (NERC’s predecessor). Through this entire period, the dominant business model was the vertically integrated, state-regulated, cost-of-service utility. Nuclear plants were built on this model from 1965 to 1985; after Three Mile Island (1979), new construction effectively halted for thirty years.

Deregulation (1978–2008). The Public Utility Regulatory Policies Act (PURPA, 1978), passed in response to the 1973 oil shock, required utilities to purchase power from “qualifying facilities” — small renewable and cogeneration plants. This opened the door for independent power producers. The Energy Policy Act of 1992 expanded wholesale competition. FERC Order 888 (1996) mandated open, non-discriminatory access to transmission systems. FERC Order 2000 (1999) encouraged the formation of Regional Transmission Organisations. The Energy Policy Act of 2005, following the 2003 Northeast blackout (50 million people, four days), made NERC’s reliability standards mandatory and enforceable. By 2008, seven ISOs/RTOs were operational, serving roughly two-thirds of US load.

Decarbonisation and the shock (2008–present). The shale gas revolution after 2008 collapsed Henry Hub prices and made combined-cycle gas the marginal generator across the eastern interconnection, displacing coal. Wind and solar costs fell 70% over the 2010s. The Inflation Reduction Act of August 2022 was the largest climate spending package in US history. The One Big Beautiful Bill Act of July 4, 2025 rewrote much of it. Layered on top: the AI data centre demand shock that broke the flat-demand consensus and rewrote utility valuations.

02 · The physics of generation — how electrons get made

Six technologies produce the vast majority of US electricity. Each operates on different physical principles, has different cost structures, different ramp characteristics, and different regulatory treatment. Understanding the physics is not optional — it determines which technologies can scale, which can be dispatched on demand, and which compete on cost versus reliability.

03 · The 2025 fuel mix and what produces a kilowatt-hour

In 2025, the United States generated a record 4,430 TWh of electricity, up 2.8% year-on-year, ending a decade and a half of essentially flat aggregate demand. The fuel mix has shifted dramatically over fifteen years.

The 2025 mix breaks down to: natural gas 41%, nuclear 18%, coal 17%, wind 11%, utility-scale solar 7%, hydropower 6%, and a residual of biomass, geothermal, petroleum, and other sources (less than 1% combined). Renewables collectively contributed 24% of generation. Power-sector CO₂ emissions rose 4.4% on the year — the second consecutive annual increase after a long decline — driven by the brief coal resurgence on higher gas prices.

The dispatch stack and how a kWh gets priced

In every organised wholesale market, generators offer their output in bid stacks. The system operator dispatches in merit order — cheapest marginal cost first — until forecast demand is met. The bid of the last unit needed (the marginal unit) sets the locational marginal price (LMP) that every dispatched generator receives. This is fundamental to how US power markets work.

Three implications follow immediately. First, because gas is almost always the marginal generator, US wholesale electricity prices are essentially a leveraged play on Henry Hub. Second, zero-marginal-cost generators (wind, solar, nuclear, hydro) earn economic rents — they capture the gas-set clearing price despite paying nothing for fuel. Third, the steepening of the right tail of the curve (when the dispatch stack runs out of cheap generators and must call on oil peakers or scarcity-priced units) is what produced the PJM capacity price explosion we’ll detail in Part II.

04 · The regulatory stack — FERC, NERC, ISOs, state PUCs

No serious investor can underwrite a US utility name without understanding which level of the regulatory stack governs which decision. The American power system is a four-tier pyramid layered onto a tripartite physical machine. The two do not map cleanly. This is the source of most analytical errors.

FERC regulates interstate wholesale electricity sales, transmission service, and the tariffs filed by ISOs and RTOs. It does not set retail rates. Established as the Federal Power Commission in 1935 and renamed in 1977, it answers to Congress and approves market designs proposed by ISOs and RTOs. FERC has five Commissioners; the current chair under the Trump administration has prioritised data centre integration, gas turbine permitting, and dynamic line ratings.

NERC — the North American Electric Reliability Corporation — is the Electric Reliability Organisation. Designated by FERC in 2006 following the Energy Policy Act of 2005, it develops and enforces reliability standards for the bulk power system across the US, Canada, and a sliver of Mexico. Its six regional entities (WECC for the West, SERC for the Southeast, MRO for the Midwest/Plains, NPCC for the Northeast, RF for the mid-Atlantic, Texas RE for ERCOT) audit compliance. NERC penalties for reliability violations can reach millions of dollars per day per violation.

ISOs and RTOs are non-profit grid operators that emerged from FERC Order 888 (1996) and Order 2000 (1999). They run day-ahead and real-time energy markets, dispatch generation by economic merit, manage congestion, and (in four of seven) run forward capacity markets. They serve about two-thirds of US electric load.

State Public Utility Commissions are the most important and least-discussed actors. They set retail rates, approve or deny utility integrated resource plans (IRPs), issue siting permits, and approve every dollar of utility capital expenditure that enters the rate base. In non-RTO regions (most of the Southeast, Southwest, and Northwest), they regulate vertically integrated monopolies directly.

The seven organised markets — at a glance

Day-ahead, real-time, and capacity — three markets in one

Each RTO runs two energy markets and (in four cases) a third capacity market. The day-ahead market clears at noon the day before delivery: generators submit hourly bids for the next 24 hours, the RTO clears the market against a forecast load curve, and binding financial schedules are issued. The real-time market clears every 5–15 minutes against actual load, with deviations from day-ahead positions settled at the real-time price. Capacity markets (PJM’s Base Residual Auction, NYISO ICAP, ISO-NE Forward Capacity Market, MISO Planning Resource Auction) procure firm capacity 1–3 years forward to ensure system adequacy.

ERCOT is the major exception: it operates as energy-only, relying on scarcity pricing (capped at $5,000/MWh through 2025, with proposals to raise) to incentivise new capacity. This design works during normal years but failed catastrophically during Winter Storm Uri in February 2021, contributing to a multi-day blackout and at least 246 deaths.

05 · Generation, transmission, distribution & the three interconnections

The physical chain runs in three segments. Electricity must be generated, transmitted, and consumed within milliseconds — it cannot be meaningfully stored at grid scale (battery storage is changing this but is still under 1% of grid energy). Each segment is regulated differently.

The three interconnections

North America’s bulk power system is divided into three asynchronous AC interconnections, each operating as a single synchronous machine at 60 Hz: the Eastern Interconnection (east of the Rockies, plus a bit of Texas), the Western Interconnection (west of the Rockies, extending to British Columbia and Baja California), and the Texas Interconnection (most of ERCOT’s footprint). Power flows freely within each interconnection but cannot flow directly between them — they would tear themselves apart if synchronised. Limited transfer between interconnections happens through DC ties, which can move several hundred MW each.

This three-grid architecture is the binding constraint on the long-discussed “macro-grid” — a national HVDC overlay that could move excess wind from the Plains to coastal demand centres. The DOE’s National Transmission Planning Study (2024) modelled scenarios requiring 2–3× transmission expansion by 2035. Whether any of this gets built is now an active question; the IIJA provided some transmission funding, and FERC Order 1920 (May 2024) mandated long-term transmission planning, but the political and siting hurdles remain extreme.

AC, DC, and the new HVDC opportunity

US transmission is overwhelmingly alternating current (AC) at 345 kV, 500 kV, or 765 kV. AC has dominated since the 1890s because it can be transformed easily between voltages. But at distances above roughly 500 miles, high-voltage direct current (HVDC) becomes economically competitive: it suffers no reactive losses, no skin effect, and can be controlled point-to-point. Modern HVDC links use voltage-source converters and operate at ±525 to ±800 kV.

The US has only about 8 GW of operational HVDC — Pacific DC Intertie (3.1 GW, Oregon to LA, since 1970), TransWest Express (planned), SunZia (under construction), and several merchant DC ties. By comparison, China has built over 400 GW of HVDC since 2010. The case for US HVDC expansion is strongest for offshore-wind-to-coastal-load and for moving Plains wind to PJM. The political case is much harder.

06 · The rate-base business model

For investor-owned utilities in regulated jurisdictions, returns are not market-driven. They are determined by a deterministic formula approved by the state Public Utility Commission. This is the most important equation in US utility equity investing.

The rate base is the depreciated book value of utility assets — generators, transmission lines, distribution poles, substations, software, vegetation management equipment, wildfire mitigation infrastructure — that the state PUC has determined are “used and useful”. The allowed ROE typically ranges between 9.0% and 10.5% across US jurisdictions, set through periodic rate cases. Most jurisdictions use a hypothetical capital structure (typically 50–55% equity) for ROE calculation.

Three implications for equity

1. Earnings grow with capex. A utility that doubles its rate base doubles its earnings power, holding ROE constant. This is why utility EPS growth tracks rate-base growth, not GDP or industrial demand. A utility growing rate base at 7% per year typically grows EPS at 6–8% per year.
2. Capex must be approved. Imprudent or duplicative spending can be disallowed by the PUC, sitting on the balance sheet earning nothing. PG&E’s bankruptcy from wildfire liability illustrated this in the negative; the systematic approval of large data centre transmission build in Virginia (Dominion) and Georgia (Southern) illustrates it in the positive. Regulatory risk is the dominant risk in this business model.
3. Returns are bond-like — until they are not. A regulated utility growing rate base 3% per year is a bond proxy. One growing rate base 8–10% per year on the back of data centre build-out, electrification, and climate resilience capex is something else entirely. This is the heart of the 2024–26 utility re-rating, which we address in detail in Part III.

Regulated vs merchant — a fundamental distinction

Many large utilities are hybrid: NextEra Energy (NEE) is the parent of regulated Florida Power & Light and merchant NextEra Energy Resources. Public Service Enterprise Group (PEG) operates regulated PSEG New Jersey alongside merchant nuclear at PSEG Power. Vistra is mostly merchant but owns regulated retail at TXU. Understanding the regulated/merchant split in any utility name is the single most important valuation step.

07 · Three choke points reshaping the build-out

Capital is not the binding constraint on US power expansion. Three more prosaic problems are: solar module tariffs, the transformer supply chain, and the interconnection queue. Each deserves its own dedicated framing.

Choke point 1 — Solar AD/CVD tariffs and the US–China dimension

The US has been imposing trade remedies on solar imports since 2012, when the original Commerce Department investigation found Chinese manufacturers were dumping crystalline silicon modules in the US market. Subsequent investigations targeted the workaround through Southeast Asia. On April 21, 2025, the Department of Commerce announced its final affirmative determinations in AD/CVD investigations of crystalline solar cells from Cambodia, Malaysia, Thailand, and Vietnam. The country-wide rates are extreme:

These rates stack on top of pre-existing Section 201 tariffs (~14%) and the new “reciprocal” tariffs that took effect April 2025 (10–49% depending on country). Anti-circumvention duties from earlier Auxin investigations apply where applicable. The petitioners — the American Alliance for Solar Manufacturing Trade Committee — include Korean-owned Qcells and Mission Solar, Swiss Meyer Burger, and US-based First Solar.

The effect on US solar economics is severe. Roughly 80% of US solar modules historically came from these four Southeast Asian countries. Domestic cell and wafer manufacturing capacity is ramping (Qcells in Georgia, First Solar in Ohio/Alabama/Louisiana) but cannot fully fill the gap until 2027–28. The OBBBA’s domestic content thresholds compound the pressure. Net result: utility-scale solar capex in the US has risen materially since 2024 and will remain elevated through the rest of the decade.

Choke point 2 — The transformer supply chain and grain-oriented electrical steel

A transformer’s core is made of grain-oriented electrical steel (GOES), a highly engineered silicon-iron alloy with anisotropic magnetic properties that minimise hysteresis losses. The United States has exactly one domestic GOES producer: Cleveland-Cliffs, operating plants in Butler, Pennsylvania and Zanesville, Ohio. Every domestic transformer manufacturer draws GOES from this single source.

Demand for power transformers has exploded. Wood Mackenzie data show generator step-up (GSU) transformer demand up 274% from 2019 to 2025; high-voltage power transformer demand up 116%; substation demand up 91%. Supply has not scaled proportionally:

As of Q2 2025, large power transformers averaged 128 weeks (2.5 years) for delivery; GSUs averaged 144 weeks (2.75 years). Some classes of distribution transformer have risen 95% in price since 2019. GOES prices have roughly doubled since 2020; copper prices are up over 50%. Roughly 80% of large US power transformers are imported, primarily from Mexico, South Korea, and China — exposing the supply chain to trade policy and global demand.

The structural response is in motion. ArcelorMittal announced a $1.2 billion non-grain-oriented electrical steel (NOES) plant in Alabama (first production 2027). GE Vernova completed its acquisition of Prolec GE in February 2026, consolidating North American transformer capacity. Hitachi Energy, Hyundai Electric, and HICO have all announced US capacity expansions. Wood Mackenzie forecasts the supply deficit for large power transformers narrowing from 30% in 2025 to roughly 5% by 2030 — but only if announced investments materialise on schedule.

Choke point 3 — The interconnection queue

A generator cannot connect to the grid without an interconnection agreement. The process — system impact study, facilities study, generator interconnection agreement — is operated by the relevant RTO or transmission owner. It has become the single largest bottleneck on US power expansion.

According to the Lawrence Berkeley National Laboratory’s “Queued Up: 2025 Edition” report, approximately 2,290 GW of generation and storage capacity was actively seeking interconnection at the end of 2024 — roughly 1.8× the entire installed US generation fleet. The composition: solar 956 GW, storage 890 GW, wind 271 GW, natural gas 136 GW (up 72% YoY). 408 GW already has a draft or executed interconnection agreement but has not yet reached commercial operations.

Two facts about the queue matter for equity investors. First, completion rates are low: historically, only about 14% of capacity that entered queues between 2000 and 2019 reached commercial operation by end-2024. The rest is withdrawn, fails studies, or is indefinitely delayed. Second, wait times have doubled: median duration from interconnection request to commercial operation date has risen from under two years (for projects built 2000–2007) to over four years (for projects built 2018–2024).

FERC Order 2023 (effective 2024) is attempting to fix this by moving from “first-come, first-served” to “first-ready, first-served” cluster studies with stricter financial commitments. Early indications are that the queue is rationalising — total active capacity decreased 12% YoY in 2024 as historic withdrawal waves cleared speculative projects. But the binding constraint remains: a US project applying for grid connection today cannot reasonably expect to be operational before 2030 in most jurisdictions.

Bottom line · what Part I established

G · Glossary — abbreviations and technical terms

This glossary is cumulative across the Power & Markets series. Terms introduced in later parts will be appended in those posts.