Colocation & the Bypass Economy:Building Next to the Power
When the grid queue runs years long, the fastest data centres stop waiting for the grid and plug straight into the plant. A workaround that is quietly rewriting the rules of who pays for the grid.
Fenrir Research · Jul 2026 · Yggdrasil Ledger / latticelog.in
The mill-owners who waited for the king’s road grew old waiting. The ones who prospered built their wheels where the river already ran — and thought nothing of the villages downstream, who woke one morning to find the water lower than it had ever been.
Original epigraph, in the register of Tolkien’s river- and mill-verses
Section 01
The Bypass Logic
The previous piece ended on a bottleneck: a grid connection now takes four to seven years, while the data centre that needs it can be built in one. When the wait is that lopsided, the rational move is not to wait — it is to build the data centre where the power already is, and skip the grid entirely.
That is colocation. Instead of connecting a data centre to the grid and drawing power across it, you site the facility directly beside a generator — a nuclear plant, a gas plant, a solar-plus-storage complex — and wire it straight in. In the purest form, the load sits “behind the meter”: it never touches the public grid at all, so it never joins the interconnection queue, never waits on new transmission, and can energise in a year or two rather than half a decade. For a hyperscaler racing rivals for compute, that time saving is the entire game.
The Speed Premium — Why Colocation Skips the Queue
Approximate time from decision to energised power, by connection route. Behind-the-meter avoids the interconnection queue entirely; new transmission is the slowest path. Indicative ranges, drawn from LBNL queue data, FERC filings and developer timelines.
The appeal is obvious, and so is the problem hiding inside it. A plant that used to sell its output to the grid, serving everyone, now sells it to a single data centre behind a fence. The electrons haven’t changed — but who they serve has, and that is where a straightforward engineering shortcut turns into one of the most contested questions in US power policy.
Section 02
The Case That Wrote the Rules: Talen, Amazon & Susquehanna
No single deal has shaped this debate more than Amazon’s arrangement with Talen Energy at the Susquehanna nuclear plant in Pennsylvania. Its two-year journey — from quiet acquisition to national test case — is effectively the story of how colocation went from clever workaround to regulated activity.
MARCH 2024
The quiet acquisition
AWS buys a 960 MW data-centre campus on a 1,200-acre site from Talen for $650 million, powered directly by the adjacent 2.5 GW Susquehanna nuclear plant under a behind-the-meter agreement. At the time, it reads as just another data-centre deal.
NOVEMBER 2024
FERC says no
In a 2–1 decision, federal regulators reject the amended interconnection agreement that would have expanded the behind-the-meter draw toward 480 MW. Rival utilities (Exelon, AEP) had challenged it. The core objection: the deal hadn’t shown why colocated load should get a special contract — or how it would pay its fair share of the grid it still leans on for backup.
JUNE 2025
The restructure
Talen and AWS come back with a bigger, differently-shaped deal: a 17-year, $18 billion power-purchase agreement for up to 1,920 MW of nuclear power, ramped over roughly seven years. Crucially, it moves from behind-the-meter to front-of-the-meter — the power now flows through the grid under a retail structure, and pays grid charges.
DECEMBER 2025
The framework
FERC issues a unanimous order directing PJM to write clear rules for colocating large loads at power plants — three new transmission-service options, reformed behind-the-meter rules, and compliance deadlines from January 2026. The workaround now has a rulebook.
Analyst Read — Watch the Meter Line
The single most important detail in that whole arc is the move from behind the meter to front of it. Behind-the-meter is faster and cheaper for the buyer, but it removes capacity from the shared grid and dodges grid charges — which is exactly why regulators balked. Front-of-the-meter keeps the plant connected to everyone, and makes the data centre pay for the network it relies on. The restructured Talen–AWS deal got done because it crossed that line. For any colocation investment, the meter line is the risk line: behind it lies speed and regulatory fragility; in front of it lies durability and cost.
Section 03
The Fight Underneath — and Who Pays
Colocation has quietly split the power industry in two. On one side are the independent power producers — Constellation, Talen and their peers — who own generation and see colocation as the fastest way to sell it at a premium to credit-worthy hyperscalers. On the other are the regulated utilities — Exelon, FirstEnergy, PPL, AEP — who own the grid and argue that behind-the-meter colocation lets data centres free-ride on a network they still depend on for reliability.
The utilities’ strongest argument is physical, not commercial. When a nuclear plant that used to serve the grid is redirected behind the meter to a single data centre, that capacity effectively leaves the shared system. Everyone else’s supply just got tighter — and in a market already short of power, tighter supply means higher prices for every other customer. The data centre gets its electrons; the ratepayer gets the bill.
Extra PJM Bills, Summer 2025
$9.4 bn
Absorbed by PJM’s 67 million customers, largely data-centre-driven
Locked-In for 2026
+$1.4 bn
Further increase already set for summer 2026
Dec 2025 Capacity Shortfall
6,623 MW
PJM auction fell short of its reliability target
Of Which Data Centres
~5,100 MW
The demand surge behind most of the gap
This is what turns a Build-thread topic into a Strain-thread problem in the same breath. The speed that makes colocation attractive is inseparable from the cost-shift that makes it politically radioactive — and the politics is now the primary risk to the economics.
How does it get paid? A colocation deal is a bilateral contract between a generator and a single, usually investment-grade, buyer — closer to a long-dated corporate PPA than to merchant power. That contracted, take-or-pay shape is genuinely attractive. The catch is that its regulatory standing, not its counterparty, is the swing variable: the Talen saga showed that a signed deal can be unwound by a regulator who decides the structure shortchanges the grid.
What stage is it at? Colocating at an existing plant is brownfield on the generation side — the reactor already runs — but greenfield on the load side, and the combination sits in value-add territory. The economics lean heavily on the speed premium, which erodes the moment the regulatory path lengthens.
The Thing That Makes This Deal
Here, the regulator doesn’t influence the return. The regulator is the return.
A colocation deal’s entire value rests on whether FERC and the grid operator permit the structure, at what cost allocation, and on what timeline. The same plant, the same buyer and the same contract are worth wildly different amounts behind the meter versus in front of it — and only a regulatory ruling decides which. This is the primer’s “policy is the return” principle in its purest form: the cash flow is real, but a commission’s vote sets its size.
Section 05
The Investment Map — and the Tail Risk
If the scarce asset is generation sited next to demand, the winners are the owners of that generation — and the losers are whoever gets stuck holding a structure the regulator later rejects.
Independent Power Producers
Holding the prize
Owners of nuclear and firm generation near load centres can sell power at a premium to hyperscalers — demand now exceeds their available capacity.
Nuclear Operators
Uprates & restarts
Existing reactors are the most-wanted colocation hosts; plant uprates and restarts (e.g. the Crane / Three Mile Island revival) are demand-driven.
Gas Generation
Valuations doubled
Gas-plant M&A multiples have roughly doubled since 2024 as firm, fast-to-build power becomes scarce — bullish for owners, a warning on entry price.
Data-Centre Developers
Speed vs. rule risk
The bypass buys years, but a behind-the-meter structure carries the risk of a regulatory unwind mid-project.
Regulated Utilities / T&D
Defending the grid
Wires owners are fighting colocation to protect their rate base — and stand to benefit if regulators force load back in front of the meter.
Ratepayers
Bearing the cost
Not investable, but the political constituency that ultimately sets the rules — and the source of the backlash risk.
The Bull Case
Contracted, long-dated offtake with investment-grade hyperscaler counterparties
Speed premium is real: years faster to power than a grid connection
FERC’s Dec 2025 framework gives colocation a rulebook — reducing (not removing) uncertainty
Owners of firm generation near load hold a genuinely scarce, re-rating asset
The Tail Risk
Regulatory reversal: a signed behind-the-meter deal can be unwound, as Talen–AWS was
Cost-allocation rules still being written — the economics can shift with a compliance filing
Ratepayer backlash ($9.4bn and rising) makes this politically fragile
“Taking generation off the grid” framing invites reliability-based restrictions
Analyst Read — Own the Generation, Not the Structure
The durable value in colocation sits with whoever owns firm power next to demand — that scarcity is real and re-rating regardless of how the rules settle. The fragile value sits in the structure: a specific behind-the-meter arrangement whose economics depend on a regulatory reading that can change. Underwrite the asset, treat the structure as contingent, and assume the meter line moves in front of the load before it moves behind it.
Bottom Line
Colocation is the market routing around a grid that can’t connect fast enough — and in doing so, forcing a fight over the oldest question in utility regulation: who pays for the shared network. The speed is real, the demand is real, and the owners of firm power near load are holding a genuinely scarce asset. But the workaround’s defining feature is that a regulator’s vote, not a contract, sets its value.
Read every colocation deal at the meter line. Behind it: faster, cheaper, and regulatorily fragile. In front of it: slower, costlier, and durable. The Talen saga is the whole lesson in miniature — the deal only got built once it stepped in front of the meter and agreed to pay for the grid it had tried to bypass.
In the end the wisest of the millers did not fight the river or flee it. They paid the villages downstream their due, and were left in peace to turn their wheels — while the ones who took without paying found their dams broken in the night.
Original epigraph, in the register of Tolkien’s river-verses
The Power-Compute Nexus:Compute Is the New Tollbooth
AI’s real bottleneck was never the chips. It was electricity, land, and a grid that cannot connect fast enough — the demand shock underneath the entire infrastructure decade.
Fenrir Research · Jul 2026 · Yggdrasil Ledger / latticelog.in
They built the forge before they had the fire to feed it — a great engine of iron standing cold, waiting on a river of heat that no one had yet learned how to carry. The furnace was never the hard part. The hard part was the fuel, and the road it had to travel.
Original epigraph, in the register of Tolkien’s forge- and fire-verses
Section 01
The Demand Shock
For two decades, electricity demand in the United States was essentially flat. Efficiency gains cancelled out growth, utilities planned around a stable load, and power was the last thing anyone in technology thought about. Artificial intelligence ended that in about eighteen months.
The clearest way to see the scale is through what the hyperscalers are spending. Combined capital expenditure at the four largest — Amazon, Alphabet, Meta and Microsoft — ran near $226 billion in 2024, roughly $410 billion in 2025, and is guided at about $725 billion for 2026, a jump of roughly 77% in a single year. Fold in Oracle and the five-firm total pushes toward $700–900 billion, and analysts already pencil in more than a trillion dollars for 2027. Goldman Sachs puts cumulative hyperscaler capex across compute, data centres and power at something on the order of $7.6 trillion between 2026 and 2031. The Stargate venture alone — OpenAI, SoftBank and Oracle — carries a $500 billion headline. This is, by a wide margin, the largest private construction programme in history.
Hyperscaler Capex Has Tripled in Two Years
Combined capex, four largest US hyperscalers (Amazon, Alphabet, Meta, Microsoft), US$bn. Sources: company guidance; FT / Tom’s Hardware tally; CreditSights. 2026 figure is guidance, up ~77% YoY.
The number that matters for this section, though, is not the dollars — it is where they go. A rising share of every capex dollar now lands not on chips but on the physical shell around them: the buildings, the cooling, the substations, and the power contracts. Memory alone is set to absorb roughly 30% of hyperscaler data-centre spending this year, four times its 2023 share. The AI story, told honestly, is an infrastructure story wearing a software costume.
Section 02
Why Power, Not Chips, Is the Bottleneck
The tell came from Microsoft, which disclosed an Azure order backlog it could not fill — not because it lacked chips, but because the GPUs it already owned sat idle in inventory, waiting for power. When the most valuable company in the world is capacity-constrained by electricity rather than silicon, the binding constraint has moved.
The physics explains why. A traditional server rack draws 5 to 15 kilowatts; an AI training rack draws 30 to more than 100. A single cluster of 100,000 GPUs pulls 70 to 80 megawatts — the continuous draw of a small city — from one connection point. Multiply that across the build-out and the load curve goes vertical:
US Data-Centre Power
31 → 66 GW
2025 to 2027, more than doubling (Goldman Sachs)
Share of US Peak Demand
4.1 → 8.5%
Summer peak, 2025 to 2027 — a national market tightening
Global DC Electricity
~945 TWh
IEA base case by 2030, roughly double 2024 (~415 TWh)
Data-Centre Build Time
~12 mo
vs. 4–7 yrs to connect, 10+ yrs for new transmission
That last comparison is the whole problem in one line. The compute can be built in a year; the power to run it cannot. And the queue to connect has become surreal: at the end of 2024, roughly 2,300 gigawatts of generation and storage sat waiting in US interconnection queues — more than the entire installed US generating fleet of about 1,280 GW. In Texas, the ERCOT large-load queue hit 410 GW by spring 2026, 87% of it data centres, of which under 2% had actually energised.
The Queue Now Exceeds the Grid Itself
US installed generating capacity vs. capacity waiting in interconnection queues (end-2024), and the ERCOT large-load queue (spring 2026). Sources: LBNL “Queued Up: 2025 Edition”; ERCOT. Queued capacity is not all real — much is speculative — but the ratio signals the scale of the access problem.
Analyst Read — The Bottleneck Is the Investment
Most of that queued capacity will never get built; a large share is speculative, duplicative, or filed to hold a place in line. But the queue’s sheer size is the signal: the scarce, valuable thing is no longer the ability to build a data centre — it is the ability to power one. Whoever controls interconnected capacity, firm generation, or a site with secured power holds the real asset. Everyone else holds a waiting ticket. That is the single most important reframe in this entire section.
Section 03
The Workarounds — and Where They Lead
Because the grid cannot connect fast enough, capital is routing around it. Three responses dominate, and each is a full topic in its own right:
Skip the grid entirely. Site the data centre directly at a power source — behind the meter, on-site generation, or straight off a plant — and avoid the interconnection queue altogether. Developers going this route (xAI, Crusoe, Oracle) are energising in one to two years against four-plus on the grid.
Revive firm power. Renewables can’t run a 24/7 training cluster alone, so the build-out is dragging gas turbines (now backordered for years) and nuclear — including the hyperscaler-nuclear deals — back to the centre of the conversation.
Squeeze the existing grid. Reconductoring, grid-enhancing technologies and undergrounding aim to move more power through lines that already exist, faster than new transmission could ever be permitted.
Run this through the primer’s models and the investable shape comes into focus quickly.
How does it get paid? The prize is contracted, investment-grade offtake — a long power-purchase agreement or a take-or-pay lease with a hyperscaler whose credit is impeccable. That is the low-risk, financeable end, and it is why infrastructure and private-credit capital is piling in. The danger zone is merchant exposure: speculative “neocloud” capacity built on the assumption that demand will show up to fill it. Same sector, opposite risk.
What stage is it at? Almost all of this is greenfield — new data centres, new generation, new lines. On the primer’s risk spectrum that lands in value-add and opportunistic territory, not core. Whatever else the AI build-out is, it is not a bond proxy, and pricing it like one is the first mistake.
Where does policy become the cash flow? Everywhere. Power-market rules set what generation earns; interconnection reform decides who connects and when; and the firm-power response leans heavily on tax credits for nuclear, storage and gas. Change any of those and the economics move.
The Fenrir Question
Is the interconnection queue a temporary bottleneck, or a structural moat?
For a developer without power, it’s a bottleneck — a problem to be waited out or engineered around. For an incumbent that already holds interconnected capacity, firm generation, or a permitted site, it is a moat — a multi-year barrier that competitors cannot cross at any price. The durable value in this whole build-out clusters around the second group. Own the scarcity, not the queue.
Section 05
The Investment Map — and the Tail Risk
If the scarce input is power and the connective capacity to deliver it, the beneficiaries are the picks-and-shovels of the electrical system, not the model-builders:
Power Generators / IPPs
Firm capacity re-rated
Independent producers with dispatchable, 24/7 generation near demand centres are suddenly holding the scarcest asset in the system.
Grid Equipment
Multi-year backlogs
Transformers, switchgear and high-voltage kit are supply-constrained worldwide — a hard bottleneck with pricing power.
Gas Turbines
Backordered to 2029+
The fastest firm power available at scale; order books are full, which is bullish for makers and a constraint for everyone else.
Data-Centre Developers / REITs
Power = the moat
Value accrues to those holding secured power and interconnection, not to raw shell capacity.
Nuclear / SMR
Optionality, not yet delivery
The hyperscaler-nuclear deals price in firm, carbon-free baseload — real demand, uncertain timelines.
Infra & Private Credit
Funding the build
The financing stack for the 2025–28 cycle looks like project finance — an ~$800bn private-credit opportunity.
But this is where discipline earns its keep, because the consensus is now very crowded — and 2026 brought the first real cracks in it.
The Bull Case
Two demand shocks stack on the same base: AI compute and broad electrification both need power
Contracted, investment-grade hyperscaler offtake underwrites the strongest projects
The build-time mismatch (12 months of compute vs. years of power) is a durable, ownable scarcity
Inference demand is still early; if agentic AI scales, today’s capex looks small
The Tail Risk
The capex-to-revenue gap is widening; markets are starting to flinch (Meta fell ~9% on raising guidance)
DeepSeek showed training costs can collapse overnight — efficiency is the bear’s friend
Concentration: the whole edifice rests on a handful of hyperscaler counterparties
If demand lags the build, merchant and speculative capacity strands first
Ratepayers are already absorbing the cost — PJM capacity prices jumped ~$9bn, a political backlash risk
Analyst Read — Underwrite the Offtake, Not the Narrative
The single discipline that separates durable exposure from stranded exposure is the contract. Assets with committed, investment-grade offtake — regulated power, contracted hyperscale capacity, take-or-pay firm generation — survive even a sharp demand disappointment. Merchant compute and speculative capacity built on a forecast do not. The AI build-out is real; the question is never whether to have exposure, but which cash flows are contracted. That is the line between owning a tollbooth and owning a bet.
Bottom Line
AI turned a decade of flat electricity demand vertical, and in doing so revealed that the true scarce inputs in computing are physical: power, land, water and the connective capacity of the grid. The chips were never the constraint. The tollbooth is the connection to the electrical system, and it is the thing worth owning.
Read every deal in this build-out through the same lens: where is the power, is the offtake contracted, and is the scarcity a moat or a queue? The bull case — two demand shocks stacking on one physical base — is strong. The tail risk — a debt-funded, concentrated bet on demand that may arrive late — is real. Both are true at once, and the contract is what tells them apart.
The smiths who prospered were not the ones with the finest hammers. They were the ones who had secured the fire — who owned the heat itself, while their rivals stood in line at a forge they did not control.
Original epigraph, in the register of Tolkien’s forge-verses
Bifrost Systems: An Infrastructure Primer — Fenrir Research
Fenrir Research · Bifrost Systems · The Infrastructure Primer
Bifrost Systems:An Infrastructure Primer
Before the deep-dives — the mental models. What infrastructure is, how these assets actually earn and get valued, and why the whole game has changed.
Fenrir Research · Jul 2026 · Yggdrasil Ledger / latticelog.in
A bridge belongs to neither shore. It is built by people who may never cross it, to carry weight they will never see, between a world that exists and a world that does not yet — and everything of consequence, sooner or later, has to pass across.
Original epigraph, in the register of Tolkien’s bridge- and road-verses
Section 01
Infrastructure Moved From the Background to the Foreground
For most of a generation, infrastructure was something you noticed only when it failed — a blackout, a burst main, a closed bridge. It was the dependable substrate underneath the interesting parts of the economy, and being boring was the whole point. That era is over.
Three forces arrived at almost the same moment, and each one turns on the same physical base. The energy transition is not a policy aspiration but a multi-trillion-dollar construction programme — generation, grids, storage, all of it. The AI build-out made electricity and land the scarcest inputs in technology, turning power — not chips — into the true bottleneck. And a wave of geopolitical rewiring — war, protectionism, resource nationalism, reconstruction — put physical control of energy, minerals and trade routes back at the centre of statecraft. Underneath all three, the ageing infrastructure of the developed world needs refinancing at the same time.
The result is that infrastructure has become the binding constraint on almost everything the world is trying to do at once. This primer is the foundation for Bifrost Systems — Fenrir Research’s standing coverage of that shift. It won’t list every topic (a short roadmap sits at the end); it will give you the mental models you need to read any of them. In the old stories, Bifrost was the bridge between worlds, the structure that made everything else reachable. That is what infrastructure is to a modern economy.
The Scale of the Convergence — Annual Capital Demand
Sources: IEA World Energy Investment 2025 (clean energy, generation, grids, fossil); Dell’Oro / Morgan Stanley (data-centre construction, annualised). Figures indicative, US$/year. Note how little flows to grids relative to generation — the bottleneck in one bar.
Section 02
What Infrastructure Actually Is
Infrastructure is defined less by what the assets are than by how their cash flows behave. A toll road, a power grid, a fibre network and a hospital look nothing alike, but strip away the concrete and a common economic signature remains — and it is that signature, not the physical form, that makes something investable as infrastructure:
Essential services. Water, power, roads, data — demand is inelastic and largely indifferent to the economic cycle.
High barriers, often a monopoly. These assets are capital-intensive, usually regulated or concession-based, and hard to replicate. Competition is limited by design.
Long-lived. Useful lives of 25 to 99-plus years, matched by concessions or contracts of similar length.
Predictable cash flows. Revenue is regulated, contracted or availability-based — it doesn’t depend on selling a product at a volatile price.
Inflation-linked. Tariffs and regulated returns are frequently indexed, passing inflation through to revenue.
The One Mental Model to Keep
Infrastructure charges a toll on a flow.
Electrons, water, vehicles, data, freight — an infrastructure asset sits on a flow that has to happen anyway and collects a toll on it, under a long, protected contract. That is the whole thing. Real estate rents space. Commodities own the flow itself and its price. Infrastructure owns the toll booth. Once you see an asset that way, its risk and its value both become far easier to read.
Dimension
Infrastructure
Real Estate
Commodities
Gets paid by
A toll on an essential flow, under contract or regulation
Rent on space; occupancy-driven
The spot price of the thing itself
Duration
Very long (decades)
Medium (lease cycles)
Short, price-cyclical
Inflation
Explicitly linked
Partial (rent reviews)
Volatile, unlinked
Correlation to GDP
Low (at the core end)
Moderate-to-high
High
Because the cash flows are long, contracted and inflation-linked, core infrastructure behaves like a long inflation-linked bond with a little equity upside — which is exactly why pensions and insurers, whose liabilities have the same shape, are its natural owners. But hold that thought loosely: as the next section shows, only part of the universe behaves that way, and the label “infrastructure” on its own tells you almost nothing about the risk you’re taking.
Section 03
How to Read Any Infrastructure Asset
Two questions decide almost everything about an infrastructure asset’s risk. First, how does it get paid? Second, what stage is it at? Answer those two and you can place any asset on the risk spectrum — and price it roughly — before you know anything else about it.
Question one: how does it get paid?
There are only three answers, and they sit in ascending order of risk:
Revenue model
How the money arrives
What you’re exposed to
Example
Regulated (RAB)
A regulator sets an allowed return on a defined asset base
Regulatory risk, not market risk
Electricity & water networks
Contracted / availability
Fixed payments for making the asset available
Counterparty credit risk
PFI hospital, contracted wind farm
Merchant / demand
Revenue rises and falls with how much the asset is used
Volume, price & GDP risk
Toll road, airport, merchant power plant
Question two: what stage is it at?
A brownfield asset is already built and operating, with a cash-flow history you can underwrite. A greenfield asset still has to be constructed — carrying permitting, construction and ramp-up risk before it earns a cent. Greenfield sits a full rung higher than brownfield on everything.
Combine the two questions and the entire universe sorts onto one spectrum — from bond-like at the left to equity-like at the right:
Core
Brownfield, regulated or contracted, mature. Yield-led, low leverage.
~6–9%
Core-plus
Some growth or contract-renewal risk, light expansion capex.
~9–12%
Value-add
Repositioning, platform build-out, more leverage.
~12–16%
Opportunistic
Greenfield, merchant, or emerging-market. Equity-like risk.
~16%+
← lower risk · incomehigher risk · capital growth →
Why This Matters More Than Ever
A decade ago, “infrastructure” mostly meant the left of that spectrum — core, regulated, brownfield yield. But the energy transition and the AI build-out are inherently greenfield and value-add: you are constructing new capacity, not buying a settled toll road. The centre of gravity has drifted right. So when someone describes a strategy simply as “infrastructure,” the useful question is never whether it’s infrastructure — it’s where on this spectrum it sits, because a regulated grid and a merchant hydrogen plant share a label and almost nothing else.
Section 04
How It Earns, and How It’s Valued
Infrastructure returns come mostly from yield — the cash the asset distributes each year — plus modest capital growth, the reverse of the buyout world where the gain is almost all at exit. That yield-led shape, and the sheer length of the cash flows, drives how these assets are valued, and it produces two quirks worth understanding.
The first is duration sensitivity. Infrastructure is valued by discounting decades of future cash flow back to today. When the cash flows stretch that far out, small changes in the discount rate move the valuation a great deal — which is why rising interest rates hit infrastructure valuations harder than their stable cash flows alone would suggest, and why the asset class is more rate-sensitive than its “defensive” reputation implies.
The second is the regulated-asset-base anchor. For a regulated network, value is roughly the regulated asset base multiplied by the allowed return — a valuation floor and ceiling handed to you by the regulator. No other real asset has anything like it; it is the closest thing in equities to a set of published rules for what the asset is worth.
The Thing That Makes Infrastructure Unique
In infrastructure, policy doesn’t just influence the return. Very often, policy is the return.
A production tax credit, a capacity payment, a regulated allowed return, a carbon price, an availability contract with a government — in this asset class, a policy decision frequently doesn’t nudge the cash flow, it creates it. That is why so much of Bifrost Systems comes back to policy: a change in a subsidy or a price signal can turn a project from uninvestable to compelling overnight, and back again. Reading infrastructure well means reading the policy that manufactures its cash flows — not as background, but as the asset.
One caveat to carry throughout. Because private infrastructure is valued by appraisal rather than by a live market price, its reported values move far less than listed equivalents. This smoothing flatters volatility and correlation statistics — the diversification benefit is real, but partly an artefact of how infrequently the assets are re-priced. Treat the “low volatility” of private infrastructure as partly genuine and partly a measurement effect.
Section 05
The Tension That Organises Everything: Build vs. Strain
Here is the single most important shift, and the reason this section is structured the way it is. For most of modern infrastructure history, the binding constraint was capital — the hard part was raising the money. That is no longer true. Institutions are under-allocated to infrastructure against rising targets, private managers sit on record dry powder, and private credit is queuing to lend. There is a wall of money.
What is scarce now is everything physical: grid-connection capacity, permits, transformers, skilled labour, water, copper and critical minerals — and power itself. The bottleneck has moved from the balance sheet to the physical world. The question is no longer “can we finance it?” but “can we actually build it, and what will it run into?”
The Frame for the Whole Section
Build is the enormous, accelerating construction of new capacity — and the ingenuity being deployed to do it faster: colocation, second-life assets, hybrid renewables, small modular reactors, grid-enhancing tech.
Strain is what the build runs into — resource limits, physical climate risk, permitting walls and geopolitical friction.
The returns, and the mispricings, live in the gap between the two.
Section 06
The Lens: What Fenrir Research Actually Asks
There is no shortage of engineering writing on these subjects, and no shortage of advocacy. Bifrost Systems asks a narrower, less-crowded question: what should a long-horizon investor make of this? Three sub-questions do most of the work, and they’ll recur in every piece:
Where is a physical risk mispriced? Markets are good at pricing financial risk and clumsy at pricing physical risk — heat derating a grid, a basin running short of water, a mineral supply chain with one choke point. The gap between the two is where the opportunity usually sits.
Is this a structural moat or a temporary bottleneck? A four-year interconnection queue is either a durable barrier protecting incumbents or a problem about to be solved. Which one it is decides whether you want to own the scarcity or bet on its relief.
Where does a policy signal become a cash flow? Following Section 04 — when a subsidy, price or mandate turns into a contracted return, and how durable that return is to the next election.
The register is markets, not morality. The aim is to see the system clearly enough to position around it.
Section 07
Where This Goes: The Roadmap
With the models in place, the rest of the section applies them. The coverage runs across seven threads — three about building, three about the pressures the build runs into, and one about the markets where those conclusions change shape. This is the map; each piece is a full application of the frameworks above.
A note on the links. Bifrost Systems is published one piece at a time. Titles shown as live links are published; every other title is forthcoming and its link will stay inactive until that piece appears. Titles marked soon are drafted or in progress. Where a piece has a counterpart that reaches the opposite conclusion outside the OECD, both carry a ↔ mirrored by note.
01 — BuildThe Machines Getting Built
What’s being constructed, and the ingenuity used to build it faster.
An identical project, multiples of the financing cost. Currency risk, guarantees and blended finance as the real constraint.
The Offtaker Problemsoon
Distribution utility insolvency — where the buyer, not the wire, is the bottleneck.
Connection Is Not Supply
Electrification declared complete on paper, while reliability remains the metric that matters.
The Informal Utility
Tankers, borewells and diesel gensets — the shadow infrastructure serving where the network does not reach.
Why Cities Can’t Fund Themselves
Municipal own-revenue a fraction of OECD levels — the fiscal root of urban infrastructure failure.
Land as the Binding Constraint
Acquisition timelines that set the pace of every network project, regardless of funding.
The Import Bill
Electrification as current-account strategy rather than climate policy.
Where to Start
For the demand story behind the urgency, start with the Power-Compute Nexus. For the constraints that will decide who wins, read the Interconnection Queue and Resource Adequacy: Power. For the finance, start with Infrastructure in Modern Portfolios and the four-part asset-class series. For the single most contrarian argument against the whole consensus, read The Demand Counterweight — then read its mirror, The Demand Multiplier, which argues the reverse for most of the world’s population. Reading a mirrored pair together is the fastest way to see why the same framework produces opposite answers in different markets.
Primer — Bottom Line
Infrastructure spent decades as the least interesting thing in the economy precisely because it worked. It is interesting now because it has become the constraint — on the energy transition, on AI, on national security, on growth itself. Everything the world wants to do next has to cross the same overloaded bridge, and the bridge is not yet built to carry the weight.
Hold the four models and you can read any of it: infrastructure is a toll on a flow; its risk is set by how it gets paid and what stage it’s at; its value is long-duration and often policy-made; and the binding constraint has moved from capital to physical capacity. Everything in Bifrost Systems is an application of those four. The rest is detail — and the detail is where the work is.
They did not ask whether the far shore was worth reaching. They asked only whether the span would hold — and then they laid the first stone, and trusted the ones who came after to lay the next.
Original epigraph, in the register of Tolkien’s bridge-verses
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.
BOTTOM LINE UP FRONT
The world’s five largest power systems — China (9,400 TWh), US (4,430 TWh), EU (2,650 TWh), India (1,900 TWh), and Japan (940 TWh) — together account for roughly two-thirds of global electricity. Each is grappling with the same trilemma: meet rising demand, decarbonise the supply, maintain reliability. The choices they have made about market design and fuel mix could not be more different.
China has crossed 1,482 GW of installed wind+solar, overtaking coal in capacity. The UK has rejected zonal pricing and is reforming national pricing instead. The EU has reformed its market design and moved to 15-minute settlement intervals. India targets 500 GW of renewables by 2030 against an 817 GW total demand projection. Japan is restarting nuclear after fourteen years — Kashiwazaki-Kariwa Unit 6 came back online in February 2026.
This bonus post sits between Part II and Part III of the Power & Markets series. It is the contextual primer that frames the US system as one of many — and sets up forthcoming standalone deep dives on UK and India power markets.
BONUS POST · CONTENTS
01
The five largest power systems — a side-by-side
02
United Kingdom — REMA, CfDs & the rejected zonal pricing
03
European Union — federation of 27, marginal pricing, capacity mechanisms
04
India — CERC/SERC, exchanges, the 500 GW question
05
China — State Grid, spot market pilots & the renewables overtake
06
Japan — S+3E, nuclear restart & the Kashiwazaki-Kariwa moment
07
Net-zero targets & generation mix — convergence and divergence
08
Where the five grids converge — and where they don’t
G
Glossary additions (cumulative from Parts I & II)
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.
Jurisdiction
Generation (TWh)
Capacity (GW)
Market type
Headline target
China
9,400
~3,550
Centralised + provincial spot pilots
3.6 TW wind+solar by 2035; net-zero 2060
US
4,430
~1,300
7 ISO/RTO + bilateral utility
Energy abundance; no binding net-zero
EU-27
2,650
~1,100
Federation of 27 national markets
60% renewables by 2030; net-zero 2050
India
1,900
~470
Federal CERC + 28 state SERCs
500 GW non-fossil by 2030; net-zero 2070
Japan
940
~300
Liberalised retail + JEPX wholesale
40–50% RE + 20% nuclear by 2040; -73% GHG
UK (separate)
300
~110
Single national + CfD + Capacity Market
Clean Power 2030; net-zero 2050
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
“Genius is no guarantee of wisdom.”
— ISIDOR RABI · OPPENHEIMER
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:
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.
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.
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.
UK system feature
Detail
System operator
National Energy System Operator (NESO) — public ownership since Oct 2024
Regulator
Ofgem (independent national regulatory authority)
Peak demand
~60 GW (winter)
Generation mix 2024
Wind ~30%, gas ~25%, nuclear ~14%, solar ~5%, biomass ~5%, hydro ~2%, imports ~14%
Net-zero target
Power sector: Clean Power 2030 (95% low-carbon); economy: net-zero 2050
The UK’s rejection of zonal pricing is the most consequential market-design decision of 2025 outside the US. It locks in the CfD as the primary investment tool, which means the government underwrites generator revenue risk. For investors, this is a feature, not a bug — it produces bond-like cash flows on long-dated renewables. The structural risk is fiscal: as CfD strike prices fall below market prices, generators pay back to the Low Carbon Contracts Company; as they rise above, taxpayers fund the gap. The Treasury exposure has grown materially.
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:
Country
Capacity mechanism type
Generation feature
France
Market-wide capacity market
Nuclear-dominant (~65% of generation); Universal Nuclear Payment regime under EDF restructuring
Germany
Strategic reserve; new market-wide mechanism in design
80% renewables by 2030 target; 8–10 GW “hydrogen-ready” gas plant programme
Italy
Market-wide capacity market
Gas-heavy; ambitious solar buildout; LNG import dependence
Spain
Capacity mechanism in development
Renewables leader; massive PPA volume; Iberian peninsula often price-decoupled
Belgium / Ireland / Poland
Market-wide capacity markets
Smaller systems; Poland coal-heavy but transitioning; Ireland wind-rich
Finland / Sweden
Strategic reserves
Hydro + nuclear dominant; among lowest-carbon grids globally
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.
FENRIR VIEW
The EU has the most institutionally complex electricity system in the world. The federation works tolerably well in normal times but fragmented disastrously during the 2022 energy crisis — Europe’s gas-set marginal pricing transmitted Russian-invasion gas shocks directly into every household electricity bill. The 2024–25 reforms attempt to inoculate the system from another such shock: more capacity mechanisms, faster CfD-equivalent contracts for renewables, 15-minute settlement. The investable thesis remains: French nuclear (Engie, EDF if it relists), Iberian renewables developers (Iberdrola, EDP), German grid (E.ON, RWE on the merchant side), Nordic hydro (Fortum, Statkraft if accessible).
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.
India feature
Detail
System operator
POSOCO (Power System Operation Corporation) — recently renamed Grid Controller of India
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
“Power stays in the shadows.”
— LEWIS STRAUSS · OPPENHEIMER
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.
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.
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.
China feature
Detail
System operators
State Grid Corporation of China (88%) + China Southern Power Grid (12%)
Regulator/Planner
National Development and Reform Commission (NDRC) + National Energy Administration (NEA)
Total capacity 2025
~3,550 GW (renewables now 59% of installed capacity at mid-2025)
Generation mix 2024
Coal ~54%, hydro ~13%, wind ~10%, solar ~8%, gas ~3%, nuclear ~5%, other ~7%
Net-zero target
Peak emissions ~2030; carbon neutrality by 2060
Capacity targets
3.6 TW wind+solar by 2035 (DNV outlook); ~150 GW battery storage by 2030
Investable angles
Limited direct access; ETFs (KWEB), HK-listed (China Yangtze Power, Huaneng Power, CGN Power, Longi Green Energy, CATL via lithium), Chinese ADRs
FENRIR VIEW
China’s energy transition is unique among large economies: it is happening at scale, on policy command, with state capital, despite a still-dominant coal fleet. The contradiction is well-captured by Ember analyst Daan Walter’s framing: “The best word to describe China’s grid might be whiplash.” For investors outside China, the most accessible plays are: (a) the supply chain — battery materials (Albemarle, SQM globally; CATL, BYD if accessible); (b) the technology suppliers (Longi, JinkoSolar, Trina); (c) the indirect plays through US/EU customers of Chinese solar and storage; (d) the grid-equipment beneficiaries of HVDC export from China. As we discussed in War & Markets, the geopolitical risk on direct China exposure is now material.
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.
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.
Japan feature
Detail
System operators
10 regional T&D utilities; OCCTO coordinates
Regulators
METI/ANRE/EGC for electricity; NRA for nuclear safety
Peak demand
~165 GW (summer)
Generation mix 2024
Gas ~33%, coal ~30%, solar ~10%, hydro ~8%, nuclear ~9%, biomass + other ~7%, oil ~3%
TEPCO, Kansai Electric (KEPCO), Chubu Electric, JERA (LNG & thermal), Mitsubishi Heavy (nuclear, gas turbines), INPEX
FENRIR VIEW
Japan is the cleanest read-across to the US hyperscaler-nuclear story we covered in Part II. Both countries have substantial existing nuclear fleets that are now strategic assets after years of underappreciation. Both have lost decarbonisation credibility — the US through OBBBA, Japan through the slow restart pace and the Seventh Strategic Energy Plan’s heavy reliance on hydrogen/ammonia co-firing that critics call “fantasy.” Both have powerful gas-import lobbies. The investable thesis on Japanese utilities is essentially the same as on US merchant nuclear: re-rating as nuclear restarts compound and LNG imports decline. TEPCO and Kansai Electric are the cleanest expressions.
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
Jurisdiction
Net-zero year
Power-sector milestone
Credibility
UK
2050
Clean Power 2030 (95% low-carbon)
High — institutionalised
EU-27
2050
60% renewables by 2030; effective power-sector net-zero ~2040
High — Fit for 55 legislated
US
No federal target post-OBBBA
State-level only (CA, NY, MA); national framing is “energy abundance”
Low — state-divergent
Japan
2050
-73% GHG by 2040; 40–50% RE + 20% nuclear by 2040
Medium — nuclear restart contingent
China
2060
Peak emissions by 2030; 3.6 TW wind+solar by 2035
Medium — capacity yes, generation lags
India
2070
500 GW non-fossil by 2030 (against 817 GW total demand)
Medium — supply-side OK, demand-side risk
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
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.
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.
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.
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.
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
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.
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.
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.
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.
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.
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.
FENRIR VIEW
The single most important investable observation from this comparison: the physics converges; the politics diverges. Every grid needs the same five enabling systems we identified in Part II — firm zero-carbon capacity, multi-horizon storage, transmission expansion, climate resilience, demand-side flexibility. But which companies capture that capex flow depends entirely on the market structure they operate in. The US merchant nuclear story (Constellation, Vistra) has no equivalent in the UK (where National Grid and centralised CfDs do the work) or France (where EDF holds the assets). The Indian renewables developer story (Adani Green, Tata Power, ReNew) has no equivalent in China (where the Big Five and state-owned enterprises dominate). Global power investing requires understanding which financial structure converts the physical capex into investor cash flow in each jurisdiction.
Bottom line · what this bonus post established
The American system that Parts I and II mapped is one of five large jurisdictions accounting for two-thirds of global electricity. Each system has answered the same physics with different politics, different market structures, and different fuel mixes. The UK rejected zonal pricing in favour of Reformed National Pricing with CfD-led decarbonisation. The EU runs a federation of twenty-seven national markets unified by the SDAC algorithm and standardised by the 2024 Electricity Market Design reform. India operates a federal-state matrix with an exchange-based spot market driving its 500 GW renewable buildout. China combines centralised state planning with provincial spot market pilots and has already overtaken coal in installed wind+solar capacity. Japan is rebuilding its nuclear fleet plant-by-plant under the S+3E framework, with the Kashiwazaki-Kariwa Unit 6 restart in February 2026 marking the most significant single restart since Fukushima.
The five systems are converging on technical realities — renewables economics, storage deployment, capacity mechanism adoption, nuclear reconsideration, grid hardening. They are diverging on market liberalisation, federal structure, demand growth, gas dependence, coal trajectory, and net-zero credibility. The physics converges; the politics diverges. The investable consequence: global power capital allocation requires jurisdiction-by-jurisdiction market structure analysis. The same physical capex flow produces fundamentally different investor cash flows in liberalised merchant markets (US, UK, Nordics), single-counterparty CfD markets (UK, France), federal cost-of-service markets (most of US), state-owned monopolies (China), and hybrid structures (India, Japan, Germany).
Standalone deep dives on UK and India will follow as separate posts. Part III returns to the US — translating the framework from Parts I and II into specific portfolio positioning, the S5UTIL re-rating, the five positioning tracks, and the named risks.
DATA SOURCES & REFERENCES
US Energy Information Administration (EIA) — Electricity Data Browser; “Today in Energy” Japan nuclear restart analysis (March 2026); International Energy Statistics. Eurostat — EU electricity statistics 2024. European Commission — Electricity Market Design reform documentation; Clean Industrial Deal State Aid Framework (CISAF). ACER — European Resource Adequacy Assessment (ERAA). UK Government / DESNZ — Review of Electricity Market Arrangements Summer Update (July 10, 2025); Reformed National Pricing Delivery Plan (April 21, 2026); Clean Power 2030 Action Plan (December 2024). Ofgem — Locational Charges and Regulatory Siting Levers Call for Input (Q1 2026). Norton Rose Fulbright, Slaughter and May, Herbert Smith Freehills Kramer, Squire Patton Boggs, Energy UK — REMA legal and policy analyses (July 2025–April 2026). Bruegel — capacity mechanism analysis (2025). Eurelectric — capacity mechanism positions. Clean Air Task Force — EU electricity reliability comparative analysis (March 2026). Central Electricity Authority (India) — Growth of electricity sector in India 1947–2024; National Electricity Plan. Central Electricity Regulatory Commission (CERC) — Short-term power market reports; Real-Time Market regulations; market coupling order (October 2025). India Energy & Climate Center (UC Berkeley) — Strategic Pathways for Energy Storage in India through 2032 (August 2025). Centre for Research on Energy and Clean Air — India power sector review 2025 (January 2026). Indian Energy Exchange Ltd — quarterly investor materials FY26 Q4. Climate & Sustainability Initiative — Evolution of India’s Renewable Energy Trading (June 2025). National Development and Reform Commission (NDRC) / National Energy Administration (NEA) — Notice on Accelerating Electricity Spot Market Development (April 2025). DNV — Greater China Energy Transition Outlook 2025. Ember — China Energy Transition Review 2025. Wood Mackenzie — China renewables investment analysis (October 2025). Carbon Brief — China power sector analysis 2025. CKGSB Knowledge — China Power Grid Challenges (January 2026). METI / Agency for Natural Resources and Energy (ANRE) — Seventh Strategic Energy Plan (February 2025); Energy White Paper 2025. NPR — Japan nuclear restart coverage (December 2025). Global Legal Insights — Energy Laws and Regulations Japan 2026. Sino-German Cooperation on Climate Change — China power market reform analysis (July 2025). Eecc Energy — China market deregulation analysis (May 2025). Fenrir Research prior publications: Power & Markets Part I — Foundations, Power & Markets Part II — Inflection, ENSO Primer, ENSO Markets & Portfolio, War & Markets.
DISCLAIMER
This analysis is for informational purposes only. Not investment advice. All probability estimates 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.
FENRIR RESEARCH · YGGDRASIL LEDGER
POWER & MARKETS · BONUS POST · LATTICELOG.IN · MAY 2026
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.
BOTTOM LINE UP FRONT
The S&P 500 Utilities sector (S5UTIL) has delivered ~25% total return in 2025 and ~32% cumulative over 18 months — its strongest run since the early 2000s. Forward P/E has expanded from the 16–17× range that defined the 2015–22 era to roughly 20–21× today. The merchant nuclear names have re-rated most violently — Constellation Energy now trades at ~26× forward earnings versus a five-year average around 14×. This is not a bubble. It is the market repricing utility earnings growth from 4–5% per year (the bond-proxy era) to 8–10% per year (the AI-infrastructure era).
Our base case from Part II (Hybrid Resilience, ~45% probability) and the AI Abundance scenario (~40%) collectively make up 85% of probability-weighted outcomes — both supportive of the trade. We construct portfolio exposure across five tracks: nuclear-anchored merchants, regulated rate-base growth, equipment manufacturers, climate resilience compounders, and SMR optionality. The thesis is not subtle and it is not over.
The single most important framing: utilities are no longer a defensive bond proxy. They are a growth trade. The portfolio construction, conviction-weighted allocation, and risk framework follow.
PART III · CONTENTS
01
S5UTIL — the sector has already started running
02
The investment thesis shift — bond proxy to growth engine
03
Five positioning tracks — anchor stocks & the rationale
04
Scenario sensitivity — how each track performs across A/B/C
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:
Name
Type
Fwd P/E now
5-yr avg
Premium / discount
Constellation Energy (CEG)
Merchant nuclear
~26×
~14×
+86%
Vistra (VST)
Merchant gas + nuclear
~22×
~10×
+120%
Talen Energy (TLN)
Merchant nuclear
~24×
n/a (recent IPO)
premium re-listed
NextEra Energy (NEE)
Hybrid (regulated + merchant)
~22×
~22×
in line
Dominion Energy (D)
Regulated, data centre
~19×
~17×
+12%
Southern Company (SO)
Regulated, Atlanta load
~20×
~18×
+11%
GE Vernova (GEV)
Gas turbine OEM
~38×
n/a (2024 spin)
growth multiple
PG&E Corp (PCG)
Regulated, wildfire risk
~14×
~13×
in line
S5UTIL (sector avg)
Sector
~20–21×
~16–17×
+25%
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
“You’re the man who gave them the power to destroy themselves.”
— ALBERT EINSTEIN · OPPENHEIMER
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
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.
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.
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.
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.
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:
EPS growth = Rate base growth (8–10%) + Equity issuance dilution (-1 to -2%) + ROE adjustments (±0.5%)
For merchant generators, the algorithm runs differently:
EPS growth = Capacity market repricing + Energy margin × volume + PPA premium + Tax credit value
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.
FENRIR VIEW
The most consequential analytical error in US power equities right now is using historic valuation frameworks to assess current multiples. Constellation at 26× looks expensive against the 14× five-year average; it looks reasonable against 20%+ EPS growth guidance. The same logic applies to the regulated names. Anchoring to 2015–22 multiples is the single largest mistake on this trade.
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)
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
A · AI Abundance (40%)
B · Climate-Led (15%)
C · Hybrid Resilience (45%)
Prob-weighted
1 · Nuclear merchants
Strong
Strong
Strong
Very strong
2 · Regulated rate-base
Strong
Strong
Strong
Strong
3 · Equipment OEMs
Strong
Mixed*
Strong
Strong
4 · Climate resilience
Strong
Strong
Very strong
Strong
5 · SMR optionality
Medium
Strong
Medium
Medium
* 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.
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.
Track
Weight
Profile
Anchor names
1 · Nuclear merchants
25–30%
Growth, AI tail, premium multiples
CEG, VST, TLN, PEG
2 · Regulated rate-base
30–35%
Defensive growth, dividends, lower volatility
NEE, D, SO, DUK, XEL, ETR
3 · Equipment OEMs
15–20%
Cyclical growth, picks-and-shovels
GEV, ETN, PWR, MTZ, VRT
4 · Climate resilience
10–15%
Asymmetric value, rate-base compounders
PCG, EIX, CNP, AGR
5 · SMR optionality
5%
Venture-style optionality, binary outcome
BWXT, CCJ, SMR, OKLO, LEU
Cash / dry powder
5%
For drawdowns and adding to convictions
Treasury bills, short duration
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.
FENRIR VIEW
The portfolio is constructed for the central tendency of our Part II scenario framework — predominantly Hybrid Resilience (45%) and AI Abundance (40%) outcomes. It is robust to Climate-Led Decarbonisation (15%) through Track 5’s optionality and Track 2’s regulated diversification. The most acute risk is a fast capacity-market reform in PJM that compresses Track 1 economics; we discuss this and four other risks in Section 06.
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
Probability
Most affected tracks
Capacity market reform
High
Track 1 (merchant nuclear most exposed)
Hyperscaler capex slowdown
Medium
Tracks 1, 3 directly; 2 indirectly
Cost of capital shock
Medium
Tracks 2, 4 most sensitive; 1 partially insulated
Regulatory backlash on rates
Medium
All tracks; Track 4 most resilient
Gas turbine supply chain
Medium
Track 3 (binary upside or downside)
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.
Timing
Catalyst
Impact
Q3 2026
PJM 2028/29 Base Residual Auction
Confirms (or breaks) the $329 capacity price plateau
Q4 2026
Three Mile Island restart commercial date
First major restart proof point; CEG validates
2027
First NuScale module commercial operation
SMR thesis validation; TVA/ENTRA1 pipeline
2027–28
PJM capacity market reform decisions
Track 1 multiple expansion/compression
2028
US presidential election
Scenario B trigger; Climate-Led Decarbonisation
2029
Duane Arnold restart commercial date
Second major restart proof point
Ongoing
Hyperscaler PPA flow; quarterly earnings
Track all five tracks for execution
Bottom line · what Part III concluded
The American utility sector is undergoing the most violent re-rating it has experienced in two decades. Part I established the foundations — how the machine works, what choke points constrain expansion. Part II documented the inflection — demand shock, capacity repricing, climate vulnerability, narrative shift, and the three scenarios for 2035. The bonus post on Other Grids placed the US system in international context. Part III translates everything into actionable portfolio positioning.
The five-track framework — nuclear merchants, regulated rate-base, equipment OEMs, climate resilience, SMR optionality — provides scenario-robust exposure across the three Part II outcomes. The portfolio blueprint allocates 25–30% to nuclear merchants for AI-tail growth, 30–35% to regulated names for defensive growth, 15–20% to equipment OEMs as picks-and-shovels, 10–15% to climate resilience as asymmetric value, and 5% to SMR optionality. The portfolio is constructed for the central tendency of our Part II framework — predominantly Hybrid Resilience and AI Abundance outcomes — while preserving exposure to a Climate-Led pivot through Track 5 and Track 2 diversification.
The five risks — capacity market reform, hyperscaler capex slowdown, cost-of-capital shock, regulatory backlash on rates, gas turbine supply chain — could compress the trade but do not break the thesis. The catalysts to monitor through 2026–28 include PJM auction outcomes, first restart proof points, the 2028 election, and ongoing hyperscaler PPA flow.
The trade is not subtle. It is not over. Position accordingly. Diversify across the five tracks. Watch the regulatory dockets. Monitor the catalysts. Stay disciplined on entry — utility re-ratings are violent but episodic.
SERIES COMPLETION
Power & Markets — the full trilogy
The Power & Markets series has covered the American electricity system from physics to portfolio. Part I established the foundations. Part II mapped the inflection. The bonus post placed the US in international context. Part III translated everything into positioning. The series is now complete; ongoing coverage will appear as standalone Learning Series posts and quarterly updates.
Forthcoming standalone primers: UK Power Markets (deep dive); India Power Markets (deep dive); and continued ENSO & Climate Markets coverage through Part III of that series.
DATA SOURCES & REFERENCES
S&P Dow Jones Indices — S&P 500 Utilities sector index data. FactSet — sector EPS estimates Q3 2025; analyst consensus. MacroMicro — sector forward P/E series. Deutsche Bank Wealth Management — S&P 500 EPS Tracker Q3 2025 (November 2025). Constellation Energy Corporation — earnings releases and management guidance FY2026. Vistra Corp — earnings releases and Cogentrix acquisition disclosures. Talen Energy Corporation — Amazon Susquehanna deal disclosures. NextEra Energy — Duane Arnold restart announcement; data centre PPA disclosures. Public Service Enterprise Group — nuclear segment disclosures. Dominion Energy — Northern Virginia data centre pipeline disclosures. Southern Company — Georgia large-load pipeline disclosures. Duke Energy, Xcel Energy, Entergy — investor materials. GE Vernova — Q1 2026 earnings release; data centre order backlog. Eaton, Quanta Services, MasTec, Vertiv, Generac — investor materials. Pacific Gas & Electric Company — 2026–28 Wildfire Mitigation Plan; rate-base growth disclosures. Edison International (SCE), CenterPoint Energy — resilience capex programmes. NuScale Power, BWX Technologies, Cameco, Centrus Energy, Oklo — investor materials. PJM Interconnection — Base Residual Auction results. Monitoring Analytics LLC — independent market monitor reports. Fenrir Research prior publications: Power & Markets Part I — Foundations, Power & Markets Part II — Inflection, Power & Markets Bonus — The Other Grids, ENSO Primer, ENSO Markets & Portfolio, War & Markets.
DISCLAIMER
This analysis is for informational purposes only. Not investment advice. All probability estimates, conviction ratings, and forward-looking judgements are analytical synthesis based on cited sources. Stock-specific references and portfolio allocations are illustrative of the investment framework discussed and are not buy or sell recommendations. Forward P/E figures and other valuation metrics are approximate as of May 2026 and subject to change. The author and Fenrir Research may hold positions in securities mentioned. Investors should conduct their own due diligence and consult qualified professionals before making investment decisions.
FENRIR RESEARCH · YGGDRASIL LEDGER
POWER & MARKETS · PART III · LATTICELOG.IN · MAY 2026
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.
BOTTOM LINE UP FRONT
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.
PART II · CONTENTS
01
The demand shock — data centres, electrification, manufacturing
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
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
Google
NextEra (NEE)
Duane Arnold (Iowa) restart, target 2029
615
Google
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.
FENRIR VIEW
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.
Combined-cycle gas turbines remain the marginal unit in most US dispatch hours. NextEra has approved 10 GW of new gas builds. Vistra closed a $4.7 billion Cogentrix gas deal. GE Vernova has reportedly secured over 90% of its gas turbine production capacity through 2030. The structural constraint is the OEM oligopoly — GE Vernova, Siemens Energy, and Mitsubishi Power. New combined-cycle delivery timelines have extended from 24 months to 48–60 months. This is the binding constraint on data centre buildout.
Realistic 2030 deployment: 60–80 GW new gas capacity. The OEMs are the picks-and-shovels play — GE Vernova reported $2.4 billion in Q1 2026 data centre-related orders alone, exceeding all of 2025.
The existing fleet (94 reactors, ~95 GW) has gone from stranded asset to strategic prize in 36 months. 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.
Restarts. Three Mile Island (Constellation, 837 MW, target 2028). Duane Arnold (NextEra, 615 MW, target 2029). Palisades (Holtec, 837 MW). Cumulative: ~2.3 GW of legacy nuclear coming back online with hyperscaler backing.
Small Modular Reactors. NuScale’s 77 MWe NRC-certified design is the only fully approved SMR. Its partner ENTRA1 Energy is progressing planning for up to 6 GW of NuScale capacity with the Tennessee Valley Authority — potentially the largest nuclear deployment programme in US history. Kairos Power signed the first corporate SMR PPA with Google in August 2025. The DOE awarded $94 million in May 2026 across eight companies for Tier 2 site permits and supply chain. Realistic first-deployment timeline: 2029–2030 for NuScale; 2030–2032 for non-NuScale designs.
Total nuclear capacity 2030 forecast: existing fleet ~95 GW + ~2 GW restarts + ~1 GW first SMR units = ~98 GW vs current 95 GW. Modest in MW terms; transformational in earnings power.
US grid-scale battery storage capacity reached 38.1 GW by end-Q2 2025, up 63% YoY. ERCOT briefly overtook CAISO as the largest deployment market, ending 2025 at ~16 GW vs CAISO’s ~17 GW. On June 19, 2025, batteries supplied roughly 26% of CAISO’s evening peak — overtaking gas for that hour.
Two business models have emerged. CAISO storage earns through resource adequacy contracts and arbitrage against the solar duck curve. ERCOT storage operates as pure merchant — ancillary services and energy arbitrage. ERCOT’s RTC+B (Real-Time Co-Optimisation with Batteries) market design, live since December 2025, co-optimises batteries across energy and ancillary services. Rabobank projects ERCOT installed storage could exceed 70 GW by 2028.
The OBBBA preserves the §48E ITC for storage through 2034 but layers FEOC restrictions on Chinese content. Since global lithium cell supply remains China-dominated, compliance is a material near-term constraint. Realistic 2030 deployment: 150–200 GW of grid-scale storage.
Conventional hydrothermal geothermal is a 70-year-old industry concentrated in the western US (3.7 GW operating, mostly California and Nevada). The new story is enhanced geothermal systems (EGS) — applying oil-and-gas drilling techniques to engineer geothermal reservoirs in dry hot rock. The DOE’s Enhanced Geothermal Shot targets $45/MWh by 2035.
Fervo Energy’s Cape Station project in Utah (400 MW Phase 1) is the leading commercial deployment. Google signed a 24/7 carbon-free EGS PPA with Fervo for its Nevada operations in 2023, with multi-site expansion since. Eavor Technologies (closed-loop geothermal) and Sage Geosystems are scaling demonstration projects. Importantly: geothermal retained full §45Y/§48E PTC and ITC under the OBBBA, with the phase-out beginning only in 2034.
Realistic 2030 deployment: 10–15 GW. Below gas and storage in scale but the highest-quality renewable option for 24/7 firm power — ideally suited for data centre PPAs that demand round-the-clock zero-carbon supply.
Wind and solar combined produced more US electricity than coal in 2024 and 2025. Texas installed 7.4 GW of solar in the first nine months of 2025 — nearly double California’s additions. Most of the H1 2025 surge was policy-driven: developers rushing to begin construction before OBBBA deadlines bit.
The construction-start deadline (July 4, 2026) and placed-in-service deadline (December 31, 2027) for full §45Y/§48E credits create a binary: developers either move into the ground now or accept reduced or zero credit. Onshore wind faces the additional headwind that §45X domestic content credits (which support GE Vernova, Vestas’s US plants, TPI Composites) terminate after 2027.
Offshore wind is a separate, harsher story. In December 2025, Interior suspended leases for all five large-scale projects under construction: Empire Wind 1 (Equinor, >60% complete), Revolution Wind (Ørsted, >80% complete), Sunrise Wind, Vineyard Wind 1, Coastal Virginia Offshore Wind. All four developers have federal court challenges pending. US offshore wind is effectively closed for new business through 2028.
Carbon capture, utilisation, and storage (CCUS) is the most underdiscussed beneficiary of the OBBBA. The §45Q credit was raised from $60 to $85 per ton for carbon used in enhanced oil recovery (matching the rate for permanent sequestration). This is a political compromise: a clean-energy credit that flows to oil and gas operators.
Occidental Petroleum’s STRATOS direct-air capture facility (Texas) is the most prominent. Exxon’s Baytown blue hydrogen project depends on §45Q economics. For power, CCUS retrofits create a viable compliance path for gas plants in states with carbon constraints. Realistic 2030 deployment for power CCUS: 2–4 GW of retrofitted gas capacity — modest but tax-credit-rich.
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
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.
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.
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.
FENRIR VIEW
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
“They won’t fear it until they understand it. And they won’t understand it until they’ve used it.”
— J. ROBERT OPPENHEIMER · OPPENHEIMER
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
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
“The reaction may proceed catastrophically.”
— EDWARD TELLER · OPPENHEIMER
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)
Premise. The “energy abundance” narrative wins decisively. Federal policy prioritises hyperscaler power needs, manufacturing reshoring, and national-security-driven AI competitiveness. State-level emissions policies become a heterogeneous patchwork. The OBBBA framework persists or is reinforced. Coal retirements continue to be deferred. New gas combined-cycle gets fast-tracked permitting. SMRs and nuclear restarts receive sustained policy and capital support. Wind and solar continue to deploy where economic but face structural headwinds.
2035 system features. Total generation ~5,500 BkWh — meeting all demand growth. Gas combined-cycle remains the dominant generator at 42% share. Nuclear expands to 20% via restarts (~2 GW), the existing fleet, first SMR deployments (~5 GW), and possibly large-scale new build at TVA. Wind+solar plateau at 22% (vs current 18%) — deployed but constrained. Enhanced geothermal scales to 5–8% of generation. Storage at ~200 GW absorbs variable renewable output and provides firming.
Emissions outcome. Power-sector CO₂ falls ~50% below 2005 levels — meaningful but well short of net-zero. Gas displaces residual coal; nuclear and renewables displace some gas; but absolute fossil generation rises in MWh terms as the system scales.
Equity implications. Strongest scenario for merchant gas IPPs (Vistra, NRG), gas turbine OEMs (GE Vernova, Siemens Energy), regulated utilities with data centre footprints (Dominion, Southern). Weakest for pure-play renewables developers (Sunrun, residential solar) and offshore wind. Nuclear merchants (Constellation, Talen) remain strong. Probability ~40%.
Premise. A change in administration in 2028 reinstates aggressive federal climate policy. State coalitions (California, NY, MA, IL, NJ, Colorado, others) drive coordinated regional planning. The Biden-era target of 100% clean electricity by 2035 is revived with binding interim milestones. Permitting reform unlocks transmission build at the scale modelled by NREL’s 2022 study. Capital flows back into wind, solar, and storage. Gas combined-cycle without CCUS is retired or curtailed.
2035 system features. Total generation ~5,200 BkWh (demand growth somewhat moderated by efficiency and demand-side flexibility). Wind and solar combined provide 60–80% of generation — per NREL’s least-cost modelling. Storage capacity scales to ~400 GW, with material long-duration energy storage (LDES) deployment. Nuclear expands modestly to 15–20% in the constrained NREL case (where new transmission is harder) or holds at 12–15% (where transmission expansion is easier). Conventional and enhanced geothermal hold at 8–10%. Gas without CCUS is <5% of generation; remaining gas plants run as peaking-only or with carbon capture.
Transmission build. 1.3× to 2.9× current US transmission capacity — requiring 1,400 to 10,100 miles of new high-capacity lines per year. This is the binding constraint. Without it, costs balloon and the constrained-transmission scenario dominates.
Cost. NREL modelled $330–$740 billion in additional power-system costs vs reference case over 2023–2035, with the higher end reflecting siting and transmission constraints. Health and climate benefits exceed costs in all modelled scenarios.
Equity implications. Strongest for renewables developers (NextEra Energy Resources, Avangrid), storage manufacturers (Fluence, Tesla, Sungrow alternatives), HVDC transmission EPC (Quanta, Mastec, Hitachi Energy), and clean firm power (geothermal, nuclear restarts). Weakest for gas IPPs without CCUS, coal-heavy generators, and gas turbine OEMs (though they would pivot to grid services and HVDC). Probability ~15% — the timeline is exceptionally tight even with full political alignment; the 2028 election outcome is the binary trigger.
Premise. Neither extreme prevails. Federal policy under successive administrations zigzags, but the underlying economic and physical drivers force convergence. Demand growth is real and persistent — utilities, RTOs, and state PUCs cannot afford to wait for political resolution. Climate adaptation capex (covered conductors, undergrounding, hardening) continues regardless of decarbonisation politics — it is rate-base eligible in every jurisdiction. Capital flows toward firm, dispatchable, low-carbon generation: nuclear restarts and SMRs, enhanced geothermal, pumped hydro, gas with CCUS retrofit, hybrid solar+storage with high storage ratios. Pure intermittent renewables continue to grow where economic but cease to be the policy darling.
2035 system features. Total generation ~5,300 BkWh. Generation mix: gas 28% (declining bridge fuel, increasing CCUS share), nuclear 22% (existing + restarts + early SMRs), wind+solar 35% (deployed where economic, especially Texas and the West), geothermal+hydro 10% (with EGS scaling materially), CCUS-equipped 2–4%, coal residual 1%, oil/other <1%. Storage capacity ~280 GW.
System characteristics. ~55% clean by 2035 (carbon-free generation including nuclear, hydro, geothermal, wind, solar). Power-sector CO₂ ~70% below 2005 levels — short of net-zero but materially lower than today. Reliability improves materially as the system shifts toward firm low-carbon resources. Transmission grows ~1.6× current capacity. Costs ~$1.6 trillion cumulative (capex + transition costs through 2035), distributed across rate-base recovery, merchant capacity payments, and hyperscaler PPAs.
Why this is the base case. Three structural forces converge: (1) capital is already flowing into firm low-carbon assets — hyperscaler PPAs are doing the policy work; (2) climate adaptation capex is non-political and well-supported; (3) the technology cost curves for storage, geothermal, and SMRs are improving fast enough that the economics dominate without policy push. State-federal divergence persists but the equilibrium clusters around mid-path system design.
Equity implications. Strongest for diversified utility names with all-of-above capex (NextEra, Dominion, Duke, Southern), nuclear-anchored merchants (Constellation, Vistra, Talen), grid equipment manufacturers (GE Vernova, Eaton, Quanta), and climate resilience plays (PG&E, SCE, CenterPoint). Cleaner-than-A but more dispatchable-friendly than B. Probability ~45% — this is our base case for Part III positioning.
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.
FENRIR VIEW
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.
How the American grid works — a primer on generation physics, market architecture, and the supply-chain choke points reshaping US power.
BOTTOM LINE UP FRONT
The US power sector is the most complex regulated industrial system in the world. Four jurisdictional tiers, seven organised wholesale markets, three asynchronous interconnections, fifty state commissions, roughly 3,300 utilities, and a 2,300 GW interconnection queue all sit on top of a physical machine that must balance supply and demand in milliseconds.
For two decades this complexity was hidden by flat demand. With the data centre boom, the rules of the machine now matter for equity returns. Part I lays the foundations: the timeline, the physics, the regulatory architecture, the fuel mix, the rate-base model, and the three supply-chain choke points — solar AD/CVD tariffs, the grain-oriented electrical steel monopoly, and the interconnection queue — that are now binding constraints on every project in development.
Part II addresses the demand shock, the new generation stack, and grid resilience. Part III translates the framework into portfolio positioning — the utility re-rating, the S5UTIL trajectory, and named positioning tracks.
PART I · CONTENTS
01
A timeline of US electric power, 1882–2026
02
The physics of generation — how electrons get made
03
The 2025 fuel mix and what produces a kilowatt-hour
04
The regulatory stack — FERC, NERC, ISOs, state PUCs
05
Generation, transmission, distribution & the three interconnections
06
The rate-base business model
07
Three choke points — solar AD/CVD, transformers, the queue
G
Glossary — abbreviations and technical terms
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.
FENRIR VIEW
Three patterns recur across the timeline. First, every major regulatory restructuring follows a blackout. Second, every consumer subsidy regime gets reversed within 10–15 years (PURPA → 1990s deregulation; IRA 2022 → OBBBA 2025). Third, the deepest structural reforms (PUHCA, Order 888, EPAct 2005) preserved the rate-of-return business model intact. The architecture has been remarkably durable; only the prices and the politics change.
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.
A CCGT is two thermodynamic cycles bolted together. First, a Brayton cycle: natural gas is compressed, mixed with air, combusted at ~1,500°C, and expanded through a gas turbine that spins a generator. The hot exhaust — still around 600°C — would normally be wasted. Instead, it passes through a heat recovery steam generator (HRSG) that boils water into high-pressure steam. The steam drives a second turbine (a Rankine cycle), producing additional electricity. The combined system reaches 60–63% thermal efficiency in modern H-class units — nearly double a coal plant’s ~35%.
Operating characteristics: Capex ~$800–1,100/kW. Construction time 24–48 months historically, now extending to 60+ months due to turbine supply chain. Ramp rate ~50 MW/minute from spinning reserve. Heat rate around 6,400 Btu/kWh. At Henry Hub $3.50/MMBtu, a CCGT’s marginal fuel cost is about $22/MWh; at $7/MMBtu, $45/MWh. The gas price is the single biggest driver of US wholesale power.
Why this matters: CCGTs are the marginal generator in almost every US RTO, almost every hour. They set the wholesale clearing price. Their abundance over the 2010s collapsed coal generation; their relative scarcity now is one reason PJM capacity prices have exploded. The OEM oligopoly (GE Vernova, Siemens Energy, Mitsubishi Power) is the binding supply constraint on new build.
A US nuclear plant is fundamentally a giant kettle. Enriched uranium-235 (3–5% U-235) sustains a fission chain reaction in a pressurised reactor vessel. The heat boils water (or, in pressurised water reactors, heats a primary loop that boils water in a secondary loop). The steam drives a conventional steam turbine. The entire fission process produces no CO₂ at the point of generation.
The US fleet is 94 reactors totalling roughly 95 GW of capacity, mostly pressurised water reactors (PWRs) of the Westinghouse three- and four-loop designs or General Electric BWRs. Capacity factors are exceptional: the fleet averaged over 92% capacity factor in 2024 — well above any other generation technology. Marginal operating costs are about $30/MWh, dominated by fuel and labour; the rest of the cost is sunk capital.
Why this matters: Nuclear is dispatchable, zero-carbon, and continuous — exactly what hyperscalers want for 24/7 data centre load. Existing US reactors are the most valuable underpriced assets in the US power complex. Microsoft–Constellation revived Three Mile Island for this reason. NextEra–Google is restarting Duane Arnold. Meta has signed 20-year PPAs with Constellation and Vistra totalling 3.2 GW of nuclear capacity. We address Small Modular Reactors (SMRs) — a different physical architecture — in Part II.
Solar PV exploits the photoelectric effect Einstein described in 1905. A photon of sufficient energy strikes a semiconductor (typically silicon doped with phosphorus and boron to create a p-n junction), liberates an electron from the valence band into the conduction band, and the resulting potential drives current through an external circuit. No moving parts; no thermodynamic cycle. The DC output is inverted to AC for grid synchronisation.
Modern utility-scale silicon PV achieves about 22–24% module efficiency. Capex has fallen below $900/kW for utility-scale fixed-tilt systems. There is no fuel cost — marginal cost is essentially zero. Capacity factor is the binding constraint: a fixed-tilt installation in Arizona produces around 30% capacity factor; in the Pacific Northwest, closer to 18%. Output is also highly correlated across geographic regions, producing the so-called “duck curve” of negative-priced midday hours in CAISO.
Why this matters: Solar’s near-zero marginal cost makes it always-dispatched-first when the sun shines, but its output is uncorrelated with peak demand (evening) and zero overnight. This is what drove storage adoption. First Solar’s cadmium telluride thin-film modules are the only major US-manufactured PV technology and the dominant beneficiary of post-OBBBA domestic content rules.
A wind turbine converts the kinetic energy of moving air into rotational mechanical energy, then into electricity via a generator. Power available in wind scales with the cube of wind speed (P ∝ v³) — doubling wind speed produces eight times the power. This explains why turbine economics are dominated by site selection. The Betz limit (1919) caps maximum extraction at 59.3% of incoming wind energy; modern utility turbines reach 45–50%.
US onshore wind is dominated by the Great Plains corridor (Texas, Oklahoma, Kansas, Iowa) where capacity factors reach 40–45% — among the highest globally. Offshore wind, almost exclusively along the Northeast Atlantic coast, can achieve 45–55% capacity factors but at 2–3× the capex of onshore. As we discuss in Part II, US offshore wind is currently in regulatory crisis.
Why this matters: Wind is the largest non-hydro renewable source in the US (11% of 2025 generation). Its diurnal pattern is opposite to solar — windier at night in most regions — making wind-plus-solar a complementary mix. The post-OBBBA tax credit construction-start deadline of July 4, 2026 is forcing a developer scramble. Wind component domestic content credits (§45X) terminate after 2027, threatening US wind manufacturing.
Conventional hydro extracts gravitational potential energy from water falling through a turbine. Output is determined by head (vertical drop) and flow rate. Modern francis and kaplan turbines achieve 90%+ mechanical efficiency. The US has about 80 GW of conventional hydro, concentrated in the Pacific Northwest (Bonneville Power Administration) and the Southeast (Tennessee Valley Authority).
Pumped storage hydropower (PSH) is the original utility-scale battery: pump water uphill when power is cheap, release through a turbine when prices are high. The US has about 22 GW of PSH, almost all built in the 1960s–80s to load-follow nuclear plants. Round-trip efficiency is 75–80%. New PSH projects face decade-long permitting timelines, but interest is reviving — Rye Development is partnering with Kentucky utilities on a 266 MW / 2,128 MWh PSH project.
Why this matters: Hydro is one of two zero-carbon dispatchable resources (the other being nuclear). Its long-duration storage capability is essentially impossible to replicate with batteries at current technology. As we discussed in the ENSO Primer, US hydro output is highly correlated with ENSO state — El Niño typically reduces Pacific Northwest hydro, La Niña enhances it.
Hydrogen is not itself a primary energy source — it is an energy carrier. The dominant US production route is steam methane reforming (SMR): natural gas is reacted with steam at ~800°C over a nickel catalyst to produce hydrogen and CO₂ (CH₄ + H₂O → CO + 3H₂, followed by a water-gas shift). About 95% of US hydrogen comes from SMR — colloquially “grey hydrogen”. Combining SMR with carbon capture produces “blue hydrogen.”
Electrolysis — splitting water with electricity (2H₂O → 2H₂ + O₂) — produces “green hydrogen” if the electricity is renewable. Polymer electrolyte membrane (PEM) and alkaline electrolysers dominate. The fundamental challenge is energy: about 50 kWh of electricity to produce 1 kg of hydrogen, which contains ~33 kWh of energy. Round-trip efficiency through a fuel cell is around 35–40%.
Why this matters for power: Hydrogen is being positioned as the long-duration storage solution and the decarbonisation pathway for hard-to-abate industrial sectors. The IRA’s §45V production tax credit (up to $3/kg for green hydrogen) was the largest single subsidy in the bill; the OBBBA has compressed it. Practical deployment timeline for hydrogen in US power generation: 2030+. Note: “SMR” here means steam methane reforming. The other “SMR” — Small Modular Reactor — is a different technology covered in Part II.
A coal plant is a pure Rankine cycle: pulverised coal is combusted in a boiler at ~1,200°C, the heat boils water into superheated steam, the steam drives a turbine generator. Most US plants are subcritical (~35% efficient); newer supercritical and ultra-supercritical units reach 40–45%. Average capacity factor for the US coal fleet has fallen from over 70% in the 2000s to about 42% today as plants run mid-merit rather than baseload.
US coal generation peaked at 2,016 TWh in 2007 (49% of generation). By 2025 it was about 750 TWh (17%) — a 63% decline driven by cheap gas, environmental regulation (MATS rule 2012, Clean Power Plan / replacement), and renewables economics. The 2025 uptick (+12% YoY) was a temporary gas-price-driven reversal that the EIA expects to unwind in 2026.
Why this matters: Many coal plants scheduled for retirement have been deferred to meet rising demand. PJM reports 17 power plants postponed retirement since the 2024 auction, retaining 1,100 MW of capacity — mostly coal. The political question of forced coal-plant retention is now active. Equity-wise, the few remaining coal-heavy IPPs (NRG, Vistra’s legacy coal fleet) are hedges, not theses.
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
“You don’t get to commit the sin and then ask all of us to feel sorry for you when there are consequences.”
— LEWIS STRAUSS · OPPENHEIMER
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
RTO / ISO
Footprint
Peak load
Capacity mkt?
PJM
13 states + DC; data centre alley (Northern Virginia)
~155 GW
Yes (BRA)
MISO
15 states across Midwest and South
~127 GW
Yes (seasonal)
ERCOT
Texas (~90%); outside FERC jurisdiction
~86 GW
No (energy-only)
CAISO
California + slivers of Nevada
~52 GW
No (RA-based)
SPP
14 states across central plains
~57 GW
No (energy + AS)
NYISO
New York State
~32 GW
Yes (ICAP)
ISO-NE
Six New England states
~25 GW
Yes (FCM)
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.
FENRIR VIEW
The single most underappreciated structural fact in US power: roughly a third of the country — the Southeast (TVA, Duke, Southern Company), the Pacific Northwest (Bonneville Power Administration), most of the Mountain West — has no organised wholesale market at all. These are bilateral, vertically integrated utility territories where investor returns are set by regulated rate-of-return formulas, not by capacity auctions. The data centre boom is now forcing this part of the country into bilateral PPAs and resource adequacy debates it has never had to run before. This is where the longest-duration utility re-rating sits.
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
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.
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.
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.
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
“It’s a long way from theory to a working bomb.”
— LESLIE GROVES · OPPENHEIMER
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:
Country
Antidumping rate
Countervailing rate
Notes
Cambodia
125.4%
3,403.96%
Country-wide adverse facts
Vietnam
271.3%
542.6%
Country-wide adverse facts
Thailand
111.5%
263.7%
Country-wide adverse facts
Malaysia
81.2%
168.8%
Lower than peers; some company-specific rates exist
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.
FENRIR VIEW
The three choke points share a common analytical implication: incumbency is worth a premium. Generators with existing grid connections, transformer fleets, and operating PPAs have an option that new entrants cannot replicate inside this decade. This is why nuclear restarts (Three Mile Island, Duane Arnold, Palisades) command 20-year PPAs at premium prices — they offer immediate, dispatchable, zero-carbon capacity that no greenfield project can match. It is also why co-located behind-the-meter deals are commanding premium economics. Part III translates this into specific equity positioning.
Bottom line · what Part I established
“Now I am become death, the destroyer of worlds.”
— J. ROBERT OPPENHEIMER · BHAGAVAD GITA, AS QUOTED IN OPPENHEIMER
We have laid the foundations. The US electricity system is the product of 144 years of layered political settlements operating on top of immutable physics. Six generation technologies produce 99% of US electrons. Four regulatory tiers govern who gets paid what. Seven organised wholesale markets, plus a third of the country still running on bilateral utility tariffs, set the prices. The rate-base business model translates capex into earnings through a deterministic formula. Three supply-chain choke points — solar AD/CVD tariffs at up to 3,400%, transformer lead times of nearly three years, and a 2,300 GW interconnection queue with a 14% historical completion rate — bind the speed of any response to changing demand.
Part II addresses the demand shock: data centre and electrification forecasts, the new generation stack (gas turbines, nuclear restarts, SMRs, storage, CCUS, geothermal), the IRA-to-OBBBA policy reset, the offshore wind freeze, the shift from net-zero rhetoric to “energy abundance” policy framing, and grid resilience capex including covered conductors and undergrounding. We will reference our existing ENSO Primer and ENSO Markets piece for the climate overlay on wildfire and storm activity.
Part III translates everything into portfolio positioning: the S5UTIL index trajectory, the P/E re-rating, the shift from defensive bond-proxy framing to growth narrative, five named positioning tracks with anchor stocks, and the risks that could compress the trade.