US Power Markets: Foundations
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.
| 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.
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.
03 · The 2025 fuel mix and what produces a kilowatt-hour
In 2025, the United States generated a record 4,430 TWh of electricity, up 2.8% year-on-year, ending a decade and a half of essentially flat aggregate demand. The fuel mix has shifted dramatically over fifteen years.
The 2025 mix breaks down to: natural gas 41%, nuclear 18%, coal 17%, wind 11%, utility-scale solar 7%, hydropower 6%, and a residual of biomass, geothermal, petroleum, and other sources (less than 1% combined). Renewables collectively contributed 24% of generation. Power-sector CO₂ emissions rose 4.4% on the year — the second consecutive annual increase after a long decline — driven by the brief coal resurgence on higher gas prices.
The dispatch stack and how a kWh gets priced
In every organised wholesale market, generators offer their output in bid stacks. The system operator dispatches in merit order — cheapest marginal cost first — until forecast demand is met. The bid of the last unit needed (the marginal unit) sets the locational marginal price (LMP) that every dispatched generator receives. This is fundamental to how US power markets work.
Three implications follow immediately. First, because gas is almost always the marginal generator, US wholesale electricity prices are essentially a leveraged play on Henry Hub. Second, zero-marginal-cost generators (wind, solar, nuclear, hydro) earn economic rents — they capture the gas-set clearing price despite paying nothing for fuel. Third, the steepening of the right tail of the curve (when the dispatch stack runs out of cheap generators and must call on oil peakers or scarcity-priced units) is what produced the PJM capacity price explosion we’ll detail in Part II.
04 · The regulatory stack — FERC, NERC, ISOs, state PUCs
No serious investor can underwrite a US utility name without understanding which level of the regulatory stack governs which decision. The American power system is a four-tier pyramid layered onto a tripartite physical machine. The two do not map cleanly. This is the source of most analytical errors.
FERC regulates interstate wholesale electricity sales, transmission service, and the tariffs filed by ISOs and RTOs. It does not set retail rates. Established as the Federal Power Commission in 1935 and renamed in 1977, it answers to Congress and approves market designs proposed by ISOs and RTOs. FERC has five Commissioners; the current chair under the Trump administration has prioritised data centre integration, gas turbine permitting, and dynamic line ratings.
NERC — the North American Electric Reliability Corporation — is the Electric Reliability Organisation. Designated by FERC in 2006 following the Energy Policy Act of 2005, it develops and enforces reliability standards for the bulk power system across the US, Canada, and a sliver of Mexico. Its six regional entities (WECC for the West, SERC for the Southeast, MRO for the Midwest/Plains, NPCC for the Northeast, RF for the mid-Atlantic, Texas RE for ERCOT) audit compliance. NERC penalties for reliability violations can reach millions of dollars per day per violation.
ISOs and RTOs are non-profit grid operators that emerged from FERC Order 888 (1996) and Order 2000 (1999). They run day-ahead and real-time energy markets, dispatch generation by economic merit, manage congestion, and (in four of seven) run forward capacity markets. They serve about two-thirds of US electric load.
State Public Utility Commissions are the most important and least-discussed actors. They set retail rates, approve or deny utility integrated resource plans (IRPs), issue siting permits, and approve every dollar of utility capital expenditure that enters the rate base. In non-RTO regions (most of the Southeast, Southwest, and Northwest), they regulate vertically integrated monopolies directly.
The seven organised markets — at a glance
| 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.
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.
Regulated vs merchant — a fundamental distinction
| Attribute | Regulated utility | Merchant IPP |
|---|---|---|
| Revenue source | Cost-of-service tariff approved by PUC | Wholesale market or bilateral PPA |
| Earnings driver | Rate base × allowed ROE | Spark spread, capacity revenue, ancillary services |
| Risk profile | Regulatory risk dominant; weather upside capped | Commodity-linked; high operational leverage |
| Typical EPS growth | 5–10% with rate-base growth | Highly variable; 15%+ in tight markets |
| Dividend yield | 2.5–4.5% typical | 0–2% (buybacks preferred) |
| Anchor names | NEE, D, SO, DUK, XEL, AEP, PCG | CEG, VST, TLN, NRG, AES |
Many large utilities are hybrid: NextEra Energy (NEE) is the parent of regulated Florida Power & Light and merchant NextEra Energy Resources. Public Service Enterprise Group (PEG) operates regulated PSEG New Jersey alongside merchant nuclear at PSEG Power. Vistra is mostly merchant but owns regulated retail at TXU. Understanding the regulated/merchant split in any utility name is the single most important valuation step.
07 · Three choke points reshaping the build-out
Capital is not the binding constraint on US power expansion. Three more prosaic problems are: solar module tariffs, the transformer supply chain, and the interconnection queue. Each deserves its own dedicated framing.
Choke point 1 — Solar AD/CVD tariffs and the US–China dimension
The US has been imposing trade remedies on solar imports since 2012, when the original Commerce Department investigation found Chinese manufacturers were dumping crystalline silicon modules in the US market. Subsequent investigations targeted the workaround through Southeast Asia. On April 21, 2025, the Department of Commerce announced its final affirmative determinations in AD/CVD investigations of crystalline solar cells from Cambodia, Malaysia, Thailand, and Vietnam. The country-wide rates are extreme:
| 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.
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
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.
G · Glossary — abbreviations and technical terms
This glossary is cumulative across the Power & Markets series. Terms introduced in later parts will be appended in those posts.
| REGULATORY & MARKET BODIES | |
| AD / CVD | Antidumping Duty / Countervailing Duty — trade remedies imposed by US Department of Commerce. |
| CAISO | California Independent System Operator. Runs California’s wholesale market. |
| ERCOT | Electric Reliability Council of Texas. Single-state ISO, outside FERC jurisdiction. |
| FERC | Federal Energy Regulatory Commission. Regulates interstate wholesale power, transmission tariffs. |
| ISO / RTO | Independent System Operator / Regional Transmission Organisation. Non-profit grid operators. |
| MISO | Midcontinent Independent System Operator. 15 states across Midwest/South. |
| NERC | North American Electric Reliability Corporation. Sets mandatory reliability standards. |
| NYISO | New York Independent System Operator. |
| PJM | PJM Interconnection. Largest US RTO; 13 states + DC; named for Pennsylvania-NJ-Maryland origin. |
| PUC / PSC | Public Utility / Service Commission. State body that regulates retail utility rates. |
| SPP | Southwest Power Pool. 14 states across central plains. |
| MARKETS & PRICING | |
| BRA | Base Residual Auction. PJM’s primary forward capacity auction. |
| Capacity market | Forward auction procuring firm capacity to meet future peak demand plus reserve margin. |
| Day-ahead market | Wholesale market clearing one day before delivery, hourly granularity. |
| FCM | Forward Capacity Market (ISO-NE’s capacity construct). |
| Heat rate | Energy input per unit electricity output, typically Btu/kWh. Lower = more efficient. |
| Henry Hub | US benchmark natural gas pricing point, located in Louisiana. |
| ICAP / UCAP | Installed Capacity / Unforced Capacity. Installed nameplate vs. performance-adjusted. |
| LMP | Locational Marginal Price. Wholesale electricity price at a specific grid node. |
| MW / GW / TWh | Megawatt / Gigawatt (capacity); Terawatt-hour (energy = capacity × time). |
| PPA | Power Purchase Agreement. Long-term bilateral contract between generator and buyer. |
| Real-time market | Wholesale market clearing every 5–15 minutes against actual demand. |
| Reserve margin | Capacity above forecast peak load to handle outages and forecast error; NERC targets ~15–20%. |
| Spark spread | Gross margin of a gas plant: power price − (gas price × heat rate). |
| TECHNOLOGY & PHYSICAL | |
| BESS | Battery Energy Storage System. Almost always lithium-ion at utility scale today. |
| BWR / PWR | Boiling Water Reactor / Pressurised Water Reactor. Two dominant US nuclear designs. |
| CCGT | Combined-Cycle Gas Turbine. Brayton + Rankine cycles; 60%+ efficiency. |
| CCUS | Carbon Capture, Utilisation, and Storage. |
| Capacity factor | Actual generation ÷ theoretical maximum at nameplate. Nuclear ~92%; wind 35–45%; solar 18–30%. |
| EHV | Extra-High Voltage. Transmission at 345 kV and above. |
| GOES | Grain-Oriented Electrical Steel. Silicon-iron alloy used in transformer cores. |
| GSU | Generator Step-Up transformer. Steps generator output voltage up for transmission. |
| HVDC | High-Voltage Direct Current. Used for long-distance transmission >500 miles. |
| IPP | Independent Power Producer. Merchant generator selling into wholesale market. |
| PV | Photovoltaic. Solar electricity from the photoelectric effect. |
| SMR (1) | Small Modular Reactor. Nuclear reactor <300 MWe, factory-fabricated. |
| SMR (2) | Steam Methane Reforming. Industrial route to grey/blue hydrogen. |
| T&D | Transmission and Distribution. |
| POLICY & FINANCE | |
| IIJA | Infrastructure Investment and Jobs Act 2021. Bipartisan infrastructure spending. |
| IRA | Inflation Reduction Act 2022. Largest US climate spending package. |
| IRP | Integrated Resource Plan. Long-term utility planning document, filed with state PUC. |
| ITC | Investment Tax Credit (§48 / §48E). Tax credit on capital cost of clean energy. |
| OBBBA | One Big Beautiful Bill Act 2025. Reset of IRA tax credits. |
| PTC | Production Tax Credit (§45 / §45Y). Tax credit per kWh of qualifying generation. |
| PUHCA | Public Utility Holding Company Act 1935. Broke up utility holding pyramids. |
| PURPA | Public Utility Regulatory Policies Act 1978. Required utility purchase from qualifying facilities. |
| Rate base | Depreciated book value of utility assets approved by PUC for cost-of-service recovery. |
| ROE | Return on Equity. Allowed by PUC, typically 9.0–10.5%. |
US Energy Information Administration (EIA) — Electricity Data Browser, Monthly Energy Review, “Today in Energy” (March 2026). Federal Energy Regulatory Commission (FERC) — Electric Power Markets overview, Orders 888 / 2000 / 1920 / 2023. North American Electric Reliability Corporation (NERC). PJM Interconnection — Auction results and stakeholder materials. Lawrence Berkeley National Laboratory — “Queued Up: 2025 Edition, Characteristics of Power Plants Seeking Transmission Interconnection As of the End of 2024” (Rand, Manderlink, Zhang et al., 2025). US Department of Commerce, International Trade Administration — Final affirmative determinations in AD/CVD investigations of crystalline photovoltaic cells (April 21, 2025). Wood Mackenzie — Supply Chain Analytics, transformer lead-time surveys Q2 2025. ArcelorMittal — SEC Form 6-K, FY2025 Q2. Cleveland-Cliffs investor disclosures. Norton Rose Fulbright, Project Finance Newswire — Updated Solar Import Tariffs (April 2025). InfoLink Consulting, PV Tech, Solar Power World — AD/CVD market analysis. Industrial Sage, Electrical Trader, PowerMag — transformer supply chain reporting. Resources for the Future — “US Electricity Markets 101”. PCI Energy Solutions — FERC/NERC role explainer. Time2Market, DigitalEnergyBy5 — RTO/ISO structural overviews. Fenrir Research prior publications: ENSO Primer, ENSO Markets & Portfolio, War & Markets.
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.
Leave a Reply