The Oil & Gas Value Chain, Part 2: Midstream (2026)

Data as of 8 September 2026. The framework — what midstream owns, how a toll is earned and how to screen an owner — is evergreen. Capacities, mileages and throughputs are agency and company figures for their stated reporting year, dated segment by segment because pipeline data lags by about a year; tariffs and spreads are periods or averages, never a single day’s print. The screening example in Section 5.2 is a hypothetical illustration. This report is for information only and was prepared with AI assistance — see the disclaimer at the end.

Every barrel and every cubic foot the world consumes passes through a machine almost nobody looks at: three million miles of American pipe, a few hundred processing plants, a handful of salt caverns and a fleet of refrigerated terminals that chill gas to −162 °C. Midstream infrastructure is the least glamorous and most reliably profitable part of the hydrocarbon business, because it sells a service — moving, cleaning, storing and cooling molecules — rather than the molecules themselves. That distinction is the whole investment case, and it is also the reason midstream behaves nothing like the oil and gas equities most investors already own. For the company-level data behind the charts — every pipeline, terminal and processing owner screened by asset base and scale — go to Metal Pilot’s midstream oil & gas stock screener.

The Oil & Gas Value Chain series. Part 1: Upstream · Part 2: Midstream · Part 3: Downstream · Part 4: Oilfield Services · Companion: World Oil & Gas Basins · Supplement: Oil Sands

TL;DR & Key Takeaways

• What it is: the physical link between the wellhead and the end user — gathering, gas processing, NGL fractionation, long-haul pipelines, storage, marine and LNG terminals, and local distribution. Midstream owns the road, not the traffic.
• How it earns: almost entirely fee-based — large North American operators report 90–98% of cash flow as fee-based, take-or-pay or regulated cost-of-service, so the sector’s earnings are far steadier than the commodity.
• The scale and the gate: 3.04 million miles of reported US pipeline (2025), 4,683 Bcf of gas storage and 18.3 Bcf/d of LNG export capacity — an asset base that takes a decade and a permit fight to replicate, because a FERC certificate is necessary but never sufficient and states hold water-permit vetoes that federal reform has not touched.
• The scarcity signal: a capacity shortage shows up as a basis blowout, not a headline price — Permian gas at the Waha hub traded negative on 46% of trading days in 2024 up to early September.
• The equity behaviour: midstream dampens the commodity instead of amplifying it — from the 2014 peak to the 2016 trough, WTI fell about 76% while the Alerian MLP Index fell 58%.
• The biggest swing factor: the LNG and power build-out — developers plan 44.9 Bcf/d of new US gas pipeline capacity in 2026–27, two-thirds of it starting in Texas.

Figure 1. Midstream infrastructure at a glance

Figure data: PHMSA, U.S. EIA and IGU; see Sections 1.4, 2.3–2.6 and 6.

How to read this guide: new to the sector? Read straight through from Section 1. Here for the investment case? Jump to Section 5 — how to own it, how to screen it, and why the fee stream is not as bulletproof as the marketing suggests. Every technical term is defined in the Vocabulary (Section 8). The commodities that flow through these assets have their own guides: crude oil and natural gas.

1. Midstream & the market basics

1.1 The asset classes

Midstream is the middle third of the hydrocarbon value chain. Upstream finds and produces hydrocarbons; downstream refines and sells them; midstream is everything in between — the assets that take a raw, contaminated, low-value stream at the wellhead and deliver a clean, specification-grade product to a refinery, a power station, a petrochemical cracker or a tanker.

Raw production is not a saleable product. Gas leaves the well mixed with water, carbon dioxide, hydrogen sulphide and natural gas liquids (NGLs) — ethane, propane, butane and natural gasoline. Crude arrives with water and sediment and in dozens of quality grades that must be kept apart or deliberately blended. Turning that into something a buyer will pay for is a physical, capital-intensive process with a fixed sequence:

• Gathering — small-diameter pipe collecting production from individual wells to a central point. This is the most competitive and most volume-sensitive part of midstream, because a gathering system’s value dies with the wells it serves.
• Gas processing — plants that remove water and acid gases (sweetening) and strip NGLs out of the gas stream (deep-cut plants recover more ethane, straddle plants sit on a mainline and skim liquids from gas already in transit). What leaves is dry gas: pipeline-specification methane.
• NGL fractionation — splitting the mixed NGL barrel into purity products (ethane, propane, normal butane, isobutane, natural gasoline), each with its own market. Fractionation is concentrated in a handful of hubs.
• Transmission — the long-haul trunk lines. Separate systems for crude, NGLs and other highly volatile liquids (HVLs), refined products and natural gas, because gas and liquids need different pipe, pumps and operating pressures, and a products line cannot take crude or raw NGLs without contaminating its cargo; within a liquids system, different grades and products move in sequential batches.
• Storage — above-ground tank farms and salt caverns for liquids; depleted reservoirs, aquifers and salt caverns for gas. Storage is the system’s shock absorber and the reason a pipeline network can serve demand that swings with the weather.
• Terminals and LNG — marine terminals that load and discharge tankers; liquefaction trains that chill gas to about −162 °C so it can travel by sea; regasification terminals that turn it back into gas at the destination.
• Distribution — the local distribution company (LDC), a regulated utility that takes gas off the transmission grid and delivers it to homes and businesses through low-pressure mains and service lines.

Where the boundary sits is a real question, not a semantic one. Refineries, renewable-diesel units and lubricants plants convert molecules into different molecules and take a processing margin — they are downstream, and they behave like manufacturers. This guide stops at the refinery gate and the burner tip.

Figure 2. The midstream value chain, wellhead to end user

Source: stage sequence per U.S. EIA infrastructure primers; conceptual diagram.

The asset classes are worth naming precisely, because a midstream company is best understood as a portfolio of them, and each class has its own capacity metric, its own contract style and its own risk profile. Capacity metrics use the industry’s M = thousand, MM = million convention, set out in Section 1.2.

Table 1. Midstream facility classes and their headline capacity metrics

Source: facility-class taxonomy from the Metal Pilot project model; capacity conventions per U.S. EIA and PHMSA reporting definitions.

1.2 Units & measurement conventions

Midstream is the one energy sector where a reader has to hold four unit systems at once, because a single company may report gas in Bcf/d, NGLs in Mbbl/d, LNG in mtpa and storage in Bcf. This report follows the industry’s Roman-numeral convention: M = thousand, MM = million. So MMbbl/d is million barrels per day, Mbbl/d is thousand barrels per day, MMcf/d is million cubic feet per day and Bcf/d is billion cubic feet per day. Where a source uses a different convention its figures are converted, not copied.

The distinction that matters most in this sector is flow versus stock. A pipeline’s capacity is a flow — a rate per day. A storage cavern’s capacity is a stock — a volume held at a point in time. Confusing the two is the fastest way to misread a midstream asset base, because a company with 200 MMbbl of storage and one with 200 Mbbl/d of pipeline capacity own completely different businesses.

Table 2. Units used in this report

Source: unit conventions per U.S. EIA and PHMSA; magnitudes as cited in Sections 2.1–2.6.

One more convention deserves flagging. Pipeline mileage is a poor proxy for economic scale — a 2-inch gathering line and a 42-inch trunk line each count as one mile. Mileage measures reach; capacity, contracted volume and utilisation measure value. Both appear in this report, and they are never used interchangeably.

1.3 Where upstream ends and midstream begins

The line between a producer and its midstream counterparty is not a stage in Figure 2 — it is a meter. On a crude lease it is the lease automatic custody transfer (LACT) unit at the tank battery, which measures and samples each barrel as ownership passes to the purchaser. On a gas lease it is the receipt-point meter where the producer’s lease line ties into a gathering system. Everything before that meter — the wellhead, flowlines, separators, heater-treaters and lease tanks — is the production operation, and the upstream guide covers it asset by asset. Everything after it is a service performed on the producer’s molecules for a fee: gathering, compression, treating, processing, fractionation, transport and storage.

The meter moves custody, not necessarily title. Under a fee-based gathering agreement the gatherer takes custody and control of the gas between the receipt point and the delivery point, while the producer keeps ownership and pays a toll — the fee-based model of Section 1.4. Under percent-of-proceeds or keep-whole contracts the processor takes title to part of the stream, which is exactly why those two structures carry commodity risk (Table 5).

Four rulebooks each draw the boundary for their own purposes, and they do not sit in quite the same place (Table 3). The accounting line is the SEC’s terminal point, the outlet valve on the lease or field storage tank — yet Rule 4-10 still counts field gathering, treating and processing as producing activity, so a producer’s own gathering can sit on the upstream side of its accounts. The pipeline-safety line is PHMSA’s: gas gathering normally ends no later than the first processing plant, and PHMSA’s 2021 rule, effective May 2022, which brought large-diameter rural (Type C) gathering under safety requirements and every onshore gas gatherer under reporting, is the reason for the step in Table 8. The rate line is FERC’s: the Natural Gas Act exempts gathering, so whether a line is exempt gathering or regulated transmission is settled case by case under FERC’s primary function test. The contract line is the one an investor feels: the gathering agreement fixes the receipt and delivery points, the acreage dedication — the producer’s commitment of everything it produces on defined acreage to that one system — and often a minimum volume commitment.

Table 3. Four lines between upstream and midstream

Source: SEC Regulation S-X Rule 4-10; 49 CFR 192.8 and 49 CFR 195.2; PHMSA gas gathering final rule, November 2021; Natural Gas Act §1(b); primary function test as applied in Williams Gas Processing v. FERC (D.C. Cir. 2003); custody and control between receipt and delivery points per an EQT gas gathering agreement filed with the SEC.

Who owns the steel either side of the meter is a commercial choice, and producers keep changing their minds about it. In a new basin a producer often builds its own gathering because no third party will take the volume risk; once the system is full it is worth more to a midstream buyer than to the producer, and the classic exit was a sponsored partnership that bought the gathering from its parent. Then the pendulum swings back. Antero Resources kept about 31% of Antero Midstream after their 2019 simplification and stopped consolidating it. Diamondback Energy bought out its Rattler Midstream subsidiary in August 2022. EQT re-acquired Equitrans Midstream — spun out of EQT in 2018 — in July 2024, calling the result the only large-scale, vertically integrated US natural gas business. Occidental still holds Western Midstream’s general-partner interest and roughly 40% of its limited-partner units, and Western relies on Occidental for the majority of its revenue. The consequence cuts both ways: a producer that owns its midstream reports lower third-party fees but carries the capital, and a gathering company whose largest shipper is its former parent carries a concentration risk no fee-based percentage reveals (Section 5.5).

Table 4. Which assets sit on which side of the line

Source: physical sequence and ownership pattern consistent with the upstream guide; regulatory classes per the rules cited under Table 3; ownership examples per Antero Resources (March 2019), Diamondback Energy (August 2022), EQT (July 2024) and Western Midstream’s 2025 Form 10-K. Ownership is the common case, not a rule — it varies by basin, contract and vintage.

1.4 Tariffs & contracts

Midstream has no exchange, no benchmark and no traded price. There is no futures contract on a barrel-mile of transport. What exists instead is a tariff — a published or negotiated fee for a service — and a contract that decides who bears which risk. Understanding the contract is the entire analytical job, because two pipelines with identical steel can have completely different earnings profiles.

Four structures dominate, and they sit on a spectrum from pure fee to pure commodity exposure:

Firm transportation is the backbone of long-haul gas and the closest thing midstream has to a bond. A shipper pays a fixed monthly reservation charge for the right to move a set volume, whether or not it ships anything, plus a small commodity charge on volumes actually moved. The pipeline collects the reservation charge in a mild winter and a cold one alike. Interruptible transportation is the opposite: cheaper, volume-only, and the first service curtailed when the line is full.

For scale, Southern Natural Gas — a Kinder Morgan interstate system — lists a firm reservation charge of $10.31 per dekatherm per month for its Zone 3 on its rate sheet effective 1 October 2026, about 34 cents per dekatherm (one MMBtu) if the reserved capacity is used every day, plus a usage charge of between about 0.9 and 3.4 cents per dekatherm depending on the zones crossed (rate sheet; tariffs are refiled, so re-source before use). A toll counted in cents on a commodity priced in dollars is invisible in the gas price and decisive in the pipeline’s earnings.

Take-or-pay and minimum volume commitments (MVCs) perform the same job on gathering and processing systems, where there is no regulated tariff. The producer commits to a floor volume over a term; if it ships less, it pays the shortfall anyway. This is what lets a midstream company underwrite a new gathering system against wells that do not exist yet.

Percent-of-proceeds (POP) and keep-whole contracts are the commodity-exposed exceptions, and they exist because gas processing produces two products. Under POP, the processor keeps an agreed share of the NGLs and residue gas it recovers — so its revenue rises and falls with NGL prices. Under keep-whole, the processor returns the producer’s gas on an energy-equivalent basis and keeps the liquids, capturing the frac spread: the gap between the value of the NGL barrel and the gas consumed to make it. Keep-whole contracts can turn negative when gas is expensive relative to liquids, which is exactly what happened to a generation of processors before the shale era. Both structures have been steadily converted to fees; they are the residual commodity risk in an otherwise fee-based sector.

Cost-of-service and indexed rates apply where a pipeline is a regulated monopoly. Interstate gas pipelines in the United States earn a rate set by the Federal Energy Regulatory Commission (FERC) on a cost-of-service basis — an allowed return on the rate base, the depreciated capital a regulator lets a pipeline earn on. Interstate oil pipelines are common carriers — obliged to serve every shipper on non-discriminatory terms — whose ceiling rates move each year with a FERC-published index — the closest thing the sector has to a benchmark price, and one set slightly below inflation (Section 3.1).

Table 5. Midstream contract and rate structures

Source: contract taxonomy from company filings; index level from FERC, Five-Year Review of the Oil Pipeline Index, April 2026.

Read across Table 5 and the nine structures collapse into three tiers. Regulated cost-of-service cash flow is the most stable: the rate is set on the rate base, and volume risk is largely socialised across the customer group. Contracted fee cash flow — firm transportation, take-or-pay, MVCs, LNG tolling — is stable for the length of the contract and then reprices at whatever the market will bear, which makes weighted-average contract life the single most useful disclosure a midstream company publishes. Commodity-linked cash flow — POP and keep-whole processing, marketing and equity NGL volumes — behaves like a small upstream business bolted onto the side, and the industry has spent a decade converting it into the second tier.

The result is a cash-flow profile that looks nothing like an oil producer’s. Kinder Morgan reports 96% of cash flow backed by take-or-pay, fee-based or hedged contracts (Kinder Morgan); Enbridge reports 98% cost-of-service or contracted (Enbridge); ONEOK describes its business model as about 90% fee-based (ONEOK) and Targa guides to 90%+ (Targa). Those percentages are the sector’s headline claim, and they are broadly true — with two caveats developed in Section 5.5. Fee-based does not mean volume-proof, and a contract is only as good as the producer on the other side of it.

Figure 3. Where midstream contracts sit on the risk spectrum

Source: contract taxonomy from company filings; see Table 5. Bar lengths are the author’s qualitative ranking of commodity exposure, not measured values.

2. The network: capacity, throughput & utilisation

2.1 Systems & hubs

Midstream geography is not geology. Pipelines sit where production meets demand, and the map is a record of where those two things have moved over the past thirty years. Four patterns explain almost all of it.

Basin-to-market corridors carry new production out of a play. The Permian Basin in West Texas is the clearest case: it produces more associated gas than it can use, and every incremental molecule needs a route to the Gulf Coast. Producing-region-to-coast corridors feed export terminals — the entire Louisiana and Texas Gulf Coast is now organised around LNG liquefaction and NGL docks. Import-era legacy systems run the other way: North America’s oldest trunk lines were built to move Gulf Coast supply north and east, and several have been reversed as shale changed the direction of flow.

A fourth pattern is politically re-routed systems, and Europe is where it reads most clearly. Between 2022 and 2025 the continent’s gas map was redrawn with no change in the geology at all: Nord Stream went from Europe’s largest single import route to an idle asset, Russian transit through Ukraine stopped at the start of 2025, and the displaced volumes were taken up by Norwegian pipeline gas, newer links such as Baltic Pipe and the Southern Gas Corridor, and LNG. Policy can strand a midstream asset as completely as a depleted basin, and it can make a modest new line strategically indispensable.

Asset-level detail matters here more than in any other part of the energy complex, because midstream value is concentrated in a small number of irreplaceable systems and hubs. A handful of names carry a disproportionate share of North American and global throughput.

Table 6. Major midstream systems, hubs and terminals

Sources: CER oil pipeline throughput snapshot, 2025 (Enbridge Mainline); Williams (Transco); CME Group OpenMarkets, 2026 (Mont Belvieu); U.S. EIA Working and Net Available Shell Storage Capacity, March 2024, the last survey before it was discontinued (Cushing); U.S. EIA liquefaction capacity workbook, 2Q 2026 (Sabine Pass and Plaquemines capacity), with first cargoes per U.S. EIA (Sabine Pass) and U.S. EIA (Plaquemines); QatarEnergy (Ras Laffan, 77 mtpa to 142 mtpa by the end of 2030). European systems per Gassco for the Norwegian network, with 2025 export volume per Gassco key figures; Nord Stream AG with capacity, line status and Nord Stream 2’s missing operating permit per Pipeline & Gas Journal, March 2025; TurkStream, with its sole-route status per Bruegel, October 2024 (TurkStream as the only other active route) and the IEA, Q1 2025 (the halt of transit via Ukraine on 1 January 2025); GAZ-SYSTEM (Baltic Pipe); TAP AG and its first capacity-expansion step; Global Energy Monitor (Druzhba); Port of Rotterdam (Rotterdam / ARA). Capacities are nameplate or design figures and are approximate; Rotterdam crude is throughput, converted at 7.33 bbl per tonne.

2.2 Demand for capacity

Demand for midstream capacity is derived demand: it is set by how many molecules need to move, not by how much anyone wants a pipeline. That makes the sector’s demand side unusually easy to observe, because the volumes are all published.

The United States is the largest single market and the clearest illustration. Marketed natural gas production reached a record average of 118.5 Bcf/d in 2025, up 5.3 Bcf/d on the year (U.S. EIA); crude production ran at roughly 13.6 MMbbl/d (U.S. EIA); and 15.0 Bcf/d of gas left the country as LNG (U.S. EIA). Every one of those numbers is a claim on midstream capacity, and they are all rising at once.

Two demand drivers are genuinely new. The first is export pull: LNG terminals are enormous, inflexible, coastal customers that need firm pipeline capacity contracted years before first cargo, which is why so much new pipe originates in Texas and terminates in Louisiana. The second is electricity. Data centres accounted for 50% of US electricity demand growth in 2025 (IEA) — a demand source that did not exist in the last build cycle and that arrives at specific, grid-constrained locations rather than spread evenly across a market (the projections are in Section 6).

The third driver is the least visible and the most reliable: decline. Shale wells lose 60–70% of their first-year rate (the decline curve is walked in the upstream guide), so a basin has to be continuously re-drilled just to hold flat, and each new pad needs to be gathered and processed. Gathering systems therefore have a maintenance-capital treadmill that long-haul pipelines do not.

2.3 Capacity by segment

Against that demand sits an installed base that is easy to underestimate. The United States alone reports just over three million miles of pipeline to PHMSA, and the great majority of it is not the long-haul trunk line most people picture — it is the low-pressure distribution grid that reaches individual buildings.

Table 7. Installed US pipeline network by segment

Source: PHMSA annual report mileage — gas transmission & gathering, hazardous liquid or carbon dioxide systems and gas distribution systems, all for report year 2025 (pages revised 8 September 2026). Every segment is the same vintage, so the total is a single-year sum of the rows; PHMSA’s hazardous-liquid total also counts 22 miles of fuel-grade ethanol line, not shown. PHMSA’s wider onshore network estimate of roughly 3.3 million miles also captures gathering lines outside the regulated reporting set.

Figure 4. US pipeline network by segment

Source: data in Table 7.

Mileage is only part of the base. The three capacity stocks that matter as much as pipe are gas processing (510 active plants in the Lower 48 with 80.8 Bcf/d of capacity at the last full EIA-757 survey), NGL fractionation (over 4 MMbbl/d across 36 units among the four largest Gulf Coast operators) and storage (Section 2.6).

The base is still growing — pipeline projects completed in 2025 added about 6.3 Bcf/d of US gas capacity (U.S. EIA), and the 2026–27 programme is the subject of Section 6.

Table 8. US natural gas transmission and gathering mileage, 2000–2025

Source: PHMSA annual report mileage — natural gas transmission & gathering systems, 2000–2025, as revised 8 September 2026. The step-change in gathering between 2021 and 2022 is a definitional break, not construction: PHMSA extended reporting to Type C onshore gathering lines, bringing roughly 95,000 previously unreported miles into the data set. Transmission mileage is directly comparable across the whole series.

That table carries the single most important structural fact about the sector, and it is easy to miss. US gas transmission mileage has not grown in twenty-five years. It was 298,957 miles in 2000 and 300,214 in 2025 — flat, while gas production roughly doubled. The network absorbed that growth through compression, looping (laying a parallel line inside the existing right-of-way), bidirectional flow and reversals rather than new right-of-way, because new long-haul right-of-way in populated corridors has become extraordinarily hard to obtain. The barrier to entry in midstream is not capital; it is permission.

Figure 5. US gas transmission and gathering mileage, selected years 2000–2025

Source: data in Table 8, shown for eight of its sixteen years and rounded to thousand miles. The 2021–22 jump in gathering is PHMSA’s reporting-scope change for Type C lines, not construction.

Liquids tell the opposite story. Crude pipeline mileage grew from 49,264 miles in 2004 to 82,168 in 2025 — a 67% expansion — and NGL/HVL mileage grew 46% over the same period, because shale created liquids volumes in places (the Bakken, the Permian, Appalachia) that had no pipe at all. Refined-product mileage, serving mature demand, barely moved.

Table 9. US hazardous-liquid pipeline mileage by product, 2004–2025

Source: PHMSA annual report mileage — hazardous liquid or carbon dioxide systems, 2004–2025, as revised 8 September 2026. Rows are five-year steps from 2004 to 2019, then 2025, the latest report year. The Total column is PHMSA’s published figure and also carries fuel-grade ethanol (under 25 miles throughout), so the four product columns sum to within a mile or two of it rather than exactly.

Figure 6. US hazardous-liquid pipeline mileage by product, 2004–2025

Source: data in Table 9, rounded to thousand miles; total mileage rose from 166,669 in 2004 to 228,207 in 2025.

2.4 Capacity vs throughput

A commodity market clears through price. A midstream network clears through utilisation, and the equivalent of a supply-demand balance is the gap between installed capacity and actual throughput. When that gap closes, the asset owner has pricing power and the producer behind it has a problem. When it widens, tolls compress and new projects get cancelled.

Table 10. Capacity, throughput and utilisation across the chain

Sources: CER (Mainline); U.S. EIA (2025 LNG exports) and U.S. EIA (18.3 Bcf/d peak export capacity); U.S. EIA Form EIA-757 (processing — the survey is triennial and 2017 is the last full published year, so treat this as a structural rather than current figure). The Cushing row is a single July 2026 inventory snapshot, not an average, set against working capacity from the U.S. EIA survey of March 2024, the last before it was discontinued — re-source at time of use.

Figure 7. Utilisation across the midstream chain

Source: data in Table 10.

The utilisation spread in that table is the sector in one picture. Long-haul crude out of Canada runs almost flat out because there is no alternative route; LNG terminals run near their engineering ceiling because their offtake is contracted decades ahead; gas processing runs at two-thirds because plants are built ahead of the wells and sized for peak rich-gas volumes; and storage sits deliberately empty most of the time, because its job is to have room when the market needs it.

Where the shortage shows up. A midstream bottleneck does not raise the global price of anything. It creates a basis differential — a local discount to the benchmark, equal to the cost of not being able to get out. Two recent episodes make the mechanism concrete, and both are settled history.

In the Permian, gas takeaway capacity fell behind associated-gas growth so badly that producers began paying buyers to take the molecules. Spot gas at the Waha hub traded below zero on 46% of trading days in 2024 up to early September — every day from 26 July — hitting −$6.41/MMBtu on 29 August 2024 (U.S. EIA) — the market’s way of saying the pipe was full. In Western Canada, the reverse happened. Heavy crude sold at a punishing discount for a decade because there was one export route; since the Trans Mountain expansion entered service in May 2024, the WCS–WTI differential — Western Canadian Select, the heavy Canadian benchmark, against West Texas Intermediate, the US light one — has averaged about US$13/bbl, roughly US$3/bbl narrower than from January 2014 to April 2024, on estimates by the Canadian Association of Petroleum Producers (CAPP). One pipeline moved that US$3/bbl of value from the buyer to the producer — worth an additional $4–5 billion a year of industry revenue at December 2025 production.

That is the sector’s economic signature. Midstream capacity does not create value out of nothing; it transfers value from whoever is captive to whoever owns the exit. Which is precisely why regulators care so much about how its rates are set (Section 3.1).

Physically, a full line rations. An oil pipeline apportions — cuts every shipper’s nominations pro rata — and a gas pipeline curtails interruptible service first. The remedy is an open season: a bidding window in which shippers commit to firm capacity on an expansion before its final investment decision (FID), which is why new pipe is contracted before it is built.

2.5 Trade flows & chokepoints

Midstream’s chokepoints come in two kinds, and only one of them is a strait.

Physical maritime chokepoints matter to the seaborne end of the chain. LNG from Qatar leaves through the Strait of Hormuz; Atlantic-basin cargoes bound for Asia route through the Panama Canal or, when the canal is drought-constrained, around the Cape of Good Hope at a cost of two extra weeks; Suez and Bab el-Mandeb carry both crude and LNG. These are the same chokepoints that constrain the commodities themselves, treated in full in the oil guide.

A live event, dated 8 September 2026. Shipping through the Strait of Hormuz has been largely shut since early March 2026. QatarEnergy stopped LNG production at Ras Laffan that month and suspended deliveries to its buyers (Gulf News); missile damage to two trains is expected to keep 12.8 mtpa of nameplate (design) capacity offline for three to five years (IGU). A Qatari tanker was struck near Hormuz in July, and Qatar shipped 18 LNG cargoes in the conflict’s first six months against 509 in the same period a year earlier (Euronews). The event is unresolved; Qatari figures in this guide are 2025 or nameplate baselines that predate it.

Infrastructure chokepoints are the midstream-specific kind, and they are more consequential for the sector’s economics. A basin with one export route, a fractionation complex concentrated in a single Gulf Coast town, a delivery hub that sets a global benchmark price — these are single points of failure that no maritime map shows. Mont Belvieu is the clearest example: the world’s NGL purity-product prices are set at one Texas hub with roughly 4 MMbbl/d of fractionation, and a hurricane track through Chambers County is a global petrochemical event.

Table 11. Chokepoints that constrain midstream flows

Sources: maritime chokepoints per U.S. EIA energy disruptions; Permian egress and Waha pricing per U.S. EIA, September 2024; Qatar’s 2025 rank per IGU World LNG Report 2026; Trans Mountain differential per CAPP, Understanding the WCS–WTI Differential, April 2026.

At the global level, the trade map is being redrawn by LNG. Trade reached a record 437 Mt in 2025, up 6.3% — the strongest growth since 2022. The United States exported 110.7 Mt (25% of the global total), ahead of Qatar at 81.5 Mt; together with Australia the top three took 62% of world exports (IGU). Russian LNG exports fell 8% on EU sanctions — the largest volumetric decline of any exporter — and Canada entered the market for the first time when LNG Canada started up in June 2025 (U.S. EIA). Where that trade goes next is the subject of Section 6.

Figure 8. Global LNG exports by source, 2025

Chart source: IGU World LNG Report 2026 for the US and Qatari figures (110.74 Mt and 81.51 Mt) and the global total (436.98 Mt, shown as 437). “Rest of world” is the residual (437 − 110.7 − 81.5) and includes Australia, the third-largest exporter.

2.6 Storage & system resilience

Every energy system needs a shock absorber, and midstream owns it. Where oil markets have the strategic petroleum reserves covered in the oil guide, the gas system’s resilience is commercial and physical rather than governmental.

Underground storage is the largest piece: 4,683 Bcf of working-gas design capacity across 375 active fields in the Lower 48 as of November 2025, up 26 Bcf on the year. Against average US gas demand of about 90 Bcf/d in 2024, that is roughly 52 days of cover — an author calculation, not a published statistic. Storage exists because gas demand swings violently with weather while production is nearly constant, so the system injects through the summer and withdraws through the winter. Three reservoir types do the work, and they are not interchangeable — depleted gas reservoirs are cheap and large but slow to cycle; aquifers are rarer and costlier; salt caverns are small but can be filled and emptied several times a season, which makes them the ones that actually respond to a price spike.

Two smaller mechanisms complete the picture. Line pack — the gas physically compressed inside the pipeline itself — is a few hours of buffer that lets the network absorb intraday swings without curtailment. LNG peak-shaving plants, small liquefaction and storage facilities owned mostly by utilities, hold liquid gas near demand centres for the coldest days of the year. On the liquids side, tank farms and salt caverns at Cushing and along the Gulf Coast play the same role for crude and products.

The investment-relevant point is that storage economics are counter-cyclical to the rest of midstream. Transport earns most when volumes are high and steady; storage earns most when volatility is high and the forward curve is in contango — when future prices exceed today’s, paying a holder to keep barrels or molecules in tank. A midstream company with meaningful storage has a partial hedge against the flat, low-volatility markets that squeeze everything else it owns.

3. Regulation & permitting

3.1 Rate-setting

Midstream has no OPEC. What performs the same function — setting the terms on which capacity earns — is economic regulation, and it differs by asset class and jurisdiction — the part of the sector most investors get wrong, because they assume “regulated” means one thing (Table 12). Two features matter most. An interstate gas pipeline cannot be built without a FERC certificate and earns a return set on its rate base. An interstate oil pipeline is a common carrier whose ceiling rate moves each year with the Producer Price Index for Finished Goods (PPI-FG) minus 0.55%, the index FERC set for July 2026 to June 2031 and one that governs 86% of FERC-regulated oil pipelines. A large slice of the industry’s tolls can therefore rise only slightly below inflation, while gathering is largely exempt and negotiated commercially.

Table 12. Who regulates what in North American midstream

Source: FERC oil pipeline index, 2026; PHMSA; Canada Energy Regulator.

3.2 Permitting

Section 2.3 showed that US gas transmission mileage has not grown in twenty-five years, and Section 3.1 that regulation caps what incumbents can charge. Permitting is the other half of that bargain: the process that decides whether a competitor’s pipe ever gets built. It is also the least uniform part of the sector. Which authority holds the pen depends on what the pipe carries and which borders it crosses, and no single approval is ever enough.

Interstate gas pipelines: one federal certificate, and many permits it does not include. A new interstate gas line needs a certificate of public convenience and necessity from FERC under Section 7 of the Natural Gas Act (Figure 9). Large projects usually start with a voluntary pre-filing review in which FERC staff scope the environmental analysis before any application is filed; for an LNG terminal pre-filing is mandatory and runs at least 180 days. FERC then prepares an environmental assessment — or a full environmental impact statement for a major pipeline on new right-of-way — under the National Environmental Policy Act (NEPA), and issues a certificate order with conditions. Construction can begin only once FERC issues a notice to proceed, which in practice waits for the permits FERC does not grant itself. The certificate carries the most powerful tool in the sector: federal eminent domain over the right-of-way, which the Supreme Court confirmed in PennEast v. New Jersey (June 2021) reaches even state-owned land. The GAO’s review of certificates approved in 2010–12 found an average of 558 days from the start of pre-filing to the certificate.

Figure 9. The FERC certificate path for an interstate gas pipeline

Source: 18 CFR 157.21 (pre-filing), 18 CFR 380.6 (assessment versus impact statement), Natural Gas Act §7 (certificate and eminent domain) and Allegheny Defense Project v. FERC (D.C. Cir. en banc, 2020); conceptual sequence — durations vary widely by project.

What the certificate does not include is where projects actually die. Under Section 401 of the Clean Water Act, each state a pipeline crosses must certify that it meets the state’s water-quality standards, and FERC cannot override a timely denial, although a state that fails to act within a year can be found to have waived its say. New York used that power against the Constitution Pipeline — certification denied in April 2016, project shelved in February 2020 even after FERC found in 2019 that the state had waived, and revived by Williams in December 2025 over New York’s objection. Stream and wetland crossings also need Army Corps of Engineers permits under Section 404, usually through Nationwide Permit 12 (reissued in March 2026), and federal-land and endangered-species approvals are each litigated on their own record. The Atlantic Coast Pipeline won 7–2 at the Supreme Court over its Appalachian Trail crossing in June 2020 and was cancelled three weeks later anyway, its cost estimate up to about $8 billion from $4.5–5.0 billion after years of challenges to its other permits.

Oil and NGL pipelines: no federal siting certificate. FERC regulates oil-pipeline rates (Section 3.1) but not where the pipe goes; federal agencies approve only its border, federal-land and water crossings. Siting is a state matter, and so is eminent domain — in Texas it depends on a line genuinely serving the public as a common carrier, and in Denbury Green (2012) the Texas Supreme Court held that a Railroad Commission permit alone does not prove it. A liquids pipeline crossing into Canada or Mexico also needs a Presidential permit, and since a 2019 executive order that decision rests with the President personally. Keystone XL is the cautionary case: granted a permit in March 2019, it lost it on 20 January 2021 and was terminated that June.

LNG: siting and exporting are separate approvals. FERC has exclusive authority to site an LNG terminal under Section 3 of the Natural Gas Act, but exporting the gas needs a Department of Energy authorisation. Exports to countries with a US free-trade agreement are deemed in the public interest by statute; exports to everyone else — including the European Union, Japan and China — require a public-interest review. That second gate is where politics enters: DOE paused new non-FTA approvals in January 2024, ended the pause in January 2025 and finalised its updated export study in May 2025.

Table 13. The US permit stack for new midstream infrastructure

Source: Clean Water Act §401 and EPA certification rules; 2026 nationwide permits; PennEast Pipeline Co. v. New Jersey, 2021, and its cancellation; Constitution Pipeline denial and shelving, the 2019 FERC waiver ruling and the project’s revival; US Forest Service v. Cowpasture River Preservation Assn., 2020, and Dominion Energy and Duke Energy on the cancellation; Minnesota PUC and Enbridge on Line 3; Texas Rice Land Partners v. Denbury Green, 2012; Executive Order 13867 and TC Energy on Keystone XL; Natural Gas Act §3; DOE on ending the LNG pause and finalising the export study, 2025; average certificate timeline per GAO-13-221.

Delay is how permitting destroys value, because a pipeline’s cost is spent up front and its revenue starts only when the line enters service. Four of the most contested North American projects of the past decade finished — or were abandoned — at between roughly 1.7 and 6.3 times their estimates at filing or construction decision (Figure 10). Permitting was not the only cause: three of the four ran years late on approvals and litigation, while Coastal GasLink finished on its 2023 schedule and still more than doubled in cost amid blockades, compliance orders and the pandemic.

Figure 10. What contested permitting costs — final cost against first estimate

Chart source: Trans Mountain — Kinder Morgan application estimate (C$5.4 billion, 2013) against Trans Mountain Corporation’s final cost as reported by the Parliamentary Budget Officer (C$34.2 billion, 2024); Mountain Valley — $3.5 billion at ground-breaking in 2018 against $9.6 billion in a November 2024 FERC cost filing, as reported by VPM; Coastal GasLink — TC Energy construction decision (C$6.2 billion, 2018) against its 2023 update (about C$14.5 billion); Atlantic Coast — Dominion Energy (up to $8 billion against $4.5–5.0 billion, midpoint used). Each multiple is nominal and in the project’s own currency; Trans Mountain’s earliest public figure, before the design grew to 890,000 bbl/d, was lower still. The Atlantic Coast bar is its last estimate before cancellation.

3.3 Permitting reform since 2023

Congress, the courts and the agencies have spent three years shortening the federal half of the permitting process in Section 3.2. The Fiscal Responsibility Act of June 2023 gave NEPA reviews deadlines — two years for an impact statement, one for an assessment — and ratified every outstanding approval for the Mountain Valley Pipeline, a one-project fix rather than a process. In Seven County Infrastructure Coalition v. Eagle County (May 2025) the Supreme Court told lower courts to defer to agencies on a review’s scope and held that NEPA does not require studying separate upstream or downstream projects outside the agency’s authority — a holding likely to narrow challenges over the wells that fill a line and the plants that burn its gas. The Council on Environmental Quality has removed its NEPA regulations altogether (final rule, January 2026), and FERC has withdrawn its 2022 draft policies on emissions and need, kept its 1999 certificate policy, and since November 2025 lets construction start while rehearing requests are pending.

None of that touches the gates that have stopped the most projects — state water certifications, state siting of oil lines, and a Presidential permit a successor can revoke. And speed cuts both ways for an investor. The difficulty of building new pipe is the incumbent’s moat; a regime that approves competitors faster erodes the scarcity that lets existing lines recontract at good rates, while a regime that swings with each administration — the Keystone XL permit, the LNG export pause — lengthens the payback a developer must demand before committing capital. That is why the industry’s preferred growth is brownfield: compression, looping and expansions inside existing rights-of-way, contracted with shippers before the final investment decision.

In Canada, federally regulated lines are approved through the Canada Energy Regulator, with the 2019 Impact Assessment Act layered on top for major projects — a scheme whose main project-review provisions the Supreme Court of Canada found unconstitutional in October 2023 and Parliament amended in June 2024. The cost of that system is Trans Mountain: estimated at C$5.4 billion when the expansion was filed in 2013, bought by the federal government for C$4.4 billion in 2018 after its private owner threatened to abandon it, and completed in May 2024 at C$34.2 billion — the 6.3× bar in Figure 10. Ottawa’s response, a national-interest track for designated projects, is still being built (Section 6).

4. The companies & the value chain

4.1 The largest midstream companies

Midstream is more concentrated than upstream and far more concentrated than downstream, because networks are natural monopolies over the corridors they occupy. In North America roughly a dozen companies own most of the interstate system, and their reach is best understood asset by asset rather than by any single financial measure.

Table 14. Major listed midstream companies and their signature assets

Sources: company disclosures and websites, 2025–26 — Kinder Morgan, Williams; Mainline throughput per CER; Targa CBF interest per RBN Energy. Listing gives the primary exchange and ticker; Transneft’s preference shares trade in Moscow but are effectively inaccessible to Western investors under sanctions, and PipeChina is wholly state-owned. No market-capitalisation figures are shown by design.

Figure 11. Company-stated pipeline network, largest North American operators

Chart source: company disclosures and websites, 2025–26 — Energy Transfer, Kinder Morgan, ONEOK and Enterprise Products. Figures are company-stated and use differing definitions — some include gathering and equity-method joint ventures, others do not — so they indicate reach rather than a like-for-like ranking. Mileage is not a measure of earnings power (see Section 1.2).

Two things the table does not show deserve attention. First, joint ventures are everywhere: large Gulf Coast fractionators, LNG trains and export docks are typically owned in partnership, so a company’s consolidated financials may capture only part of the assets it operates — or may consolidate assets it only partly owns. Second, the non-North-American picture is state-dominated. Outside North America and a handful of European regulated grids, most midstream is owned by national champions and is not investable, which is why the listed midstream universe is so heavily weighted to the United States and Canada.

4.2 Company archetypes & structures

Midstream companies differ along two independent axes, and confusing them is the most common analytical error in the sector. The first axis is what they own; the second is how they are structured for tax.

On assets, six archetypes cover the field. Gathering and processing (G&P) companies sit closest to the wellhead: highest volume risk, shortest contract life, most residual commodity exposure, and the fastest growth when a basin is running. Long-haul gas transmission is the opposite end — regulated, firm-contracted, decades-long, and effectively a bond with a maintenance budget. Liquids logistics (crude and NGL pipelines, fractionation, storage, docks) sits in between and is where most of the industry’s genuine commodity optionality lives. LNG developers and operators are a different animal again: enormous single-asset construction risk before first cargo, then a 20-year tolling annuity after it. Regulated distribution utilities are rate-base compounders whose growth is set by an approved capital programme, not by drilling. Diversified midstream combines several of these and trades the resulting stability against the fact that no single part of it is a pure play.

On structure, the split is master limited partnership (MLP) versus C-corporation: an MLP is a tax pass-through that distributes most of its cash, while a C-corp pays entity-level tax and issues shareholders an ordinary 1099 tax form. Many of the largest names converted to C-corps in the late 2010s to widen their investor base — what the choice means for a holder is Section 5.1 — and regulated utilities are a third structure again, valued on rate base and allowed return rather than on distributable cash flow.

Table 15. Midstream archetypes and their economics

Source: archetype taxonomy from company filings and the Metal Pilot project model; examples are illustrative, not a recommendation.

Figure 12. Midstream archetypes by volume risk and commodity exposure

Source: data in Table 15, with its ratings mapped to a 1–5 scale (very low = 1, low = 2, low–medium = 2.5, medium = 3, high = 4; no commodity exposure = 1 and very low = 1.5); positions are the author’s qualitative assessment, not measured values.

4.3 Assets on the balance sheet

A midstream balance sheet looks nothing like a producer’s. There are no reserves, no depletion, no reserve-life ratio. What sits there instead is property, plant and equipment at historical cost less accumulated depreciation — steel in the ground, valued at what it cost to put there decades ago, which for a long-lived network means book value can bear almost no relationship to replacement cost or economic worth.

Five other line items carry most of the information:

• Rate base — for regulated assets, the depreciated capital on which a regulator allows a return. Rate-base growth, not volume growth, is what compounds a utility-like midstream business.
• Equity-method investments — the joint ventures. These hold real assets and real debt that never appear in consolidated revenue or, often, in consolidated leverage. Read them on ownership percentage and proportionate EBITDA: checking the proportionate picture rather than the consolidated one is essential in this sector.
• Right-of-way and easements — usually a small book number and an enormous economic one, because they are the thing a competitor cannot buy at any price.
• Contracted backlog — not a balance-sheet item but disclosed alongside it: the secured growth capital programme and the revenue it is expected to support.
• Goodwill — midstream has consolidated aggressively, and large goodwill balances are a live impairment risk when a basin disappoints.

5. Investing in midstream

5.1 Exposure vehicles

Midstream is unusual among energy exposures in that there is no commodity to buy. You cannot own a barrel-mile of transport, there is no futures contract on pipeline capacity, and the physical asset is unavailable to anyone without a few billion dollars and a decade. Every route into this sector is an equity or a fund, which changes the nature of the structural trap investors need to watch for.

The vehicle spectrum runs from most direct to most wrapped. Individual MLP units give the purest exposure and the best tax treatment for a US taxable investor — no entity-level tax, high distributions — at the cost of a Schedule K-1 partnership tax form instead of a 1099, potential unrelated business taxable income (UBTI) inside retirement accounts, and state filing obligations. Midstream C-corporation shares give up the pass-through efficiency in exchange for a 1099, index eligibility and a far wider investor base; this is why several large partnerships converted. Regulated utility shares with a midstream arm are the lowest-beta way in. LNG developer equity is the highest-beta: pre-first-cargo it is construction risk, post-first-cargo it is an annuity, and the transition between those two states is where most of the return is made or lost.

Then come the funds, and this is where the structural caveat lives.

The tax-drag caveat — the midstream equivalent of contango. In most commodity sectors the classic retail trap is a futures-based ETF bleeding value as it rolls contracts in a contango market (the oil guide walks it). Midstream has no futures, so its analogous trap is structural taxation. A fund holding more than 25% MLPs cannot qualify as a regulated investment company (RIC) and must be taxed as a C-corporation, accruing deferred tax liability on the appreciation of its holdings at the corporate rate plus state tax. That accrual comes straight out of net asset value. The effect is not theoretical: over the ten years to 30 June 2026, the largest MLP ETF returned 6.39% a year at NAV against 8.56% for its index, the Alerian MLP Infrastructure Index (ALPS) — roughly 2.2 percentage points a year, a gap that combines the fund’s fees and its deferred-tax accrual. RIC-structured energy-infrastructure funds cap MLP holdings at 25% precisely to avoid this, at the cost of holding more C-corps and fewer partnerships. Any investor choosing a midstream fund needs to know which structure they are buying; it is the single most expensive detail in the sector.

Table 16. Ways to take midstream exposure

Source: fund structures per issuer documentation; ten-year NAV versus index comparison per the ALPS Alerian MLP ETF fact sheet, 30 June 2026; the 25% RIC limit per VettaFi. Structural attributes only — no fees, yields or prices are quoted.

5.2 How to value & screen midstream

Producers are screened on reserves and cost. Midstream has neither, so the screen is built from contracts, capital and leverage. Seven measures do most of the work — Table 17 adds two cross-checks — and they are all in the filings.

Start where a filing’s information actually sits. Not the income statement, but the asset table in the property section — capacity by system — then the contract disclosure (firm share, weighted-average life, counterparty concentration), then the equity-method note (Section 4.3). Those three, in that order, determine almost everything the financials will do over the next five years.

Fee-based share of cash flow is the first filter, but read it precisely: what matters is the reservation-based share — the money that arrives whether or not a molecule moves — not the broader “fee-based” bucket, which each company defines for itself and which often includes throughput-linked fees. Weighted-average contract life is midstream’s answer to reserve life: it tells you how many years of the current fee stream are locked before recontracting risk begins. Counterparty quality decides whether those contracts are worth anything in a downturn — a take-or-pay obligation from a bankrupt producer is a claim, not cash flow (Section 5.5).

On capital, maintenance versus growth capex separates the money that keeps the network running from the money that expands it, and only the second should be judged on returns. Return on invested capital versus cost of capital on growth projects is the discipline test — the previous cycle’s great sin was building projects at returns below the cost of the capital raised to fund them (Section 5.4). Leverage (net debt to EBITDA) matters more here than in almost any other sector because the whole model is debt-financed long-lived assets; post-2016 deleveraging is why the industry survived 2020 intact (Section 5.4). Finally, distribution or dividend coverage — cash generated against cash paid out — tells you whether the payout is funded by operations or by issuance.

Valuation itself is done on cash-flow multiples and, for regulated assets, on rate base and allowed return. Those ratios are the screening machinery rather than facts to print in an evergreen guide, which is why this report names them without quoting levels — you can screen the midstream universe on Metal Pilot and, because a pipeline’s fortunes are only as good as the wells behind it, cross-check the producers that fill those systems at the same time.

Table 17. Screening metrics for midstream companies

Source: metric taxonomy from midstream company filings and non-GAAP reconciliations; leverage targets per Targa (August 2026) and ONEOK (June 2026); the Metal Pilot project model captures the asset-side inputs — facility class, capacity, ownership interest — that sit behind several of these.

A hypothetical illustration of the screen. Take two invented owners — not real companies. Gatherer A runs a single Permian system: 60% of its cash flow is reservation-based, its weighted-average contract life is four years, one sub-investment-grade producer ships most of its volume, and net debt is 4.5× EBITDA. Pipeline B owns a long-haul gas line: 95% firm, a twelve-year contract life, investment-grade utility shippers, 3.5× leverage and brownfield expansions announced at disclosed build multiples. Read down Table 17 and A fails the counterparty, contract-life and leverage rows at once — the combination the 2015–16 bust punished — while B fails none. A is not therefore uninvestable; the screen tells you what its valuation has to compensate for.

5.3 Macro regimes, rates & correlations

Midstream’s macro profile is genuinely different from the commodity it carries, and the difference is the reason to own it.

Interest rates are the dominant macro variable — more so than the oil price. Midstream is a long-duration, capital-intensive, high-payout asset class, which makes it behave partly like a corporate bond with growth. Rising real rates hurt through three channels at once: a higher discount rate on distant cash flows, a higher refinancing cost on a debt-heavy balance sheet, and competition from risk-free yield for the income buyer. Cutting cycles reverse all three. The offset is that a meaningful share of the fee stream is contractually inflation-linked — the FERC oil index moves with PPI-FG minus 0.55%, and many negotiated gas and gathering tariffs carry explicit escalators — so midstream has a partial, contractual inflation hedge that most bond-like assets lack. High inflation with low real rates is, on paper, the sector’s best regime.

The oil correlation is real but unstable, and it rises exactly when you would rather it did not. In calm markets, fee-based cash flow decouples midstream from the commodity. In a downturn it re-couples: the weekly correlation between the Alerian MLP Infrastructure Index and WTI jumped to 0.62 during the 2014–16 collapse, and the broader Alerian Midstream Energy Index reached 0.65 in the same window. The mechanism is not the fee stream — it is the market pricing in producer bankruptcies, volume declines and contract rejection. Correlations quoted here are weekly, over the stated window, and are not stable across regimes.

The worked episode — midstream dampens, it does not amplify. Rule of thumb in commodity equities: the stocks amplify the commodity. Midstream is the exception, and the 2014–16 bear market is the cleanest concluded test. WTI fell from roughly $107/bbl in June 2014 to $26.21 on 11 February 2016 — about −76%. Over almost exactly the same window, the Alerian MLP Index fell 58.2% on a total-return basis, peak (29 August 2014) to trough (11 February 2016) — deeper than its 50.1% fall in 2007–08, and still an 18-percentage-point cushion against the barrel. That is what a toll road looks like in a bust: badly hurt, but structurally less hurt than the thing it carries.

The cushion is not a floor, and the second episode says so. On 9 March 2020, at the start of the Saudi–Russian price war, WTI fell 24.6% in a single session and the Alerian MLP Infrastructure Index fell 27.7% — the equity fell more than the commodity that day. In a liquidity event, leverage and forced selling overwhelm contract structure. Midstream dampens a slow grind; it does not protect against a crash.

Figure 13. Midstream versus the barrel — the 2014–16 bear market and 9 March 2020

Chart source: WTI spot per U.S. EIA; the 2014–16 index decline per Alerian/VettaFi, Calling the MLP Bottom and the 9 March 2020 moves per Alerian/VettaFi, Reexamining MLP & Midstream Oil Correlations. Past performance is not indicative of future results.

Table 18. Midstream across macro regimes

Source: regime responses substantiated by the episodes cited in the right-hand column; index data per Alerian/VettaFi, Calling the MLP Bottom (2014–16) and Reexamining MLP & Midstream Oil Correlations (2020), WTI per U.S. EIA. Historical, not predictive. Cross-commodity regime behaviour is covered in the macro regime guide.

Figure 14. Midstream response by macro regime

		Channel (1 = most adverse, 5 = most favourable)
		Tariff escalation	Volume	Cost of capital	Sentiment
Macro regime	Rising inflation, low real rates	5	4	4	4
	Rising real rates	4	3	1	2
	Falling rates / easing	3	3	5	5
	Strong growth, high volumes	4	5	3	4
	Commodity bust	3	2	2	1
	Liquidity crisis	3	2	1	1
	Deflation / demand destruction	1	1	3	1

Source: the author’s qualitative scoring of each regime in Table 18 on four channels, from 1 (most adverse) to 5 (most favourable); the episodes behind each regime are cited in that table.

5.4 Value drivers & cycles

Five forces move midstream economics, and none of them is the daily oil price.

Basin volume growth sets gathering and processing earnings directly. Egress scarcity sets the value of long-haul capacity: the wider the basis differential, the more a pipeline can charge to close it, which is why the Permian’s negative Waha prints in 2024 were simultaneously a producer disaster and a midstream opportunity. Export capacity pulls molecules to the coast and creates decades-long firm contracts on the way. Interest rates set both the discount rate and the cost of the next project. And permitting determines whether a project that clears all four gets built at all (Section 3.2).

The cycle the sector has just lived through is the most useful case study, and it is fully concluded. Between roughly 2012 and 2015 midstream over-built into the shale boom, funding growth with equity issuance and leverage on the assumption that volumes would keep arriving. When the oil price collapsed, that funding model broke: capital markets closed, distributions were cut, incentive distribution rights — the sponsor’s escalating share of a partnership’s payouts — were bought in and the whole industry deleveraged. By the late 2010s the model had changed from “issue equity to grow” to self-funded growth — capital programmes covered by retained cash flow. That discipline is precisely why the sector took the 2020 demand collapse without a wave of failures, and it is the single most important thing that distinguishes today’s midstream from the 2014 version.

Table 19. Midstream value drivers

Source: drivers derived from the concluded episodes cited in Sections 2.4 and 5.3 and from company capital-allocation disclosures, 2015–2026.

5.5 Risks, controversies & ESG

Midstream’s marketing emphasises the durability of the fee stream. The risks are real, and most of them are not commodity risks.

Recontracting is the sector’s quiet risk. A twenty-year firm contract signed when a basin was tight reprices at whatever the market will bear when it expires. Long-haul lines out of declining basins have repriced downward before and will again; contract life is the disclosure that tells you when.

Counterparty risk turns fees into claims. In 2015–16 producer bankruptcies forced courts to rule on whether gathering contracts could be rejected — and some were. A fee-based contract is only as strong as the shipper’s balance sheet, which is why counterparty concentration deserves as much attention as the fee percentage.

Permitting is both the moat and the mortal risk. Section 3.2 sets out the gates and Figure 10 what they cost: four of the most contested North American projects of the past decade finished, or were abandoned, at roughly 1.7–6.3 times their estimate at filing or construction decision, and Keystone XL was terminated outright after its permit was revoked. The same difficulty that protects existing lines from competition destroys the economics of new ones.

Safety, methane and cyber are the operational trio. Pipeline integrity spending is non-discretionary and set by PHMSA. Methane leakage across gathering, processing and transmission is the sector’s central ESG exposure, and it is the reason gas’s “bridge fuel” case is contested — the argument for and against is set out in the natural gas guide. Cyber risk became concrete in May 2021 when a ransomware attack shut the Colonial Pipeline — about 5,500 miles carrying the bulk of the US East Coast’s fuel — for roughly six days, causing regional shortages and prompting the first federal pipeline cyber-security directives.

Stranded-asset risk is the long-horizon controversy, and it is genuinely two-sided. The bear case is that a 40-year asset built for hydrocarbons faces a demand peak inside its depreciation schedule, so today’s contracted cash flow understates terminal risk. The bull case is that decarbonisation is proving slower and more electricity-hungry than assumed, that gas networks are being repurposed for RNG and hydrogen blending, and that a pipeline’s economics are recovered over its contract life rather than its physical life. Both positions rest on assumptions about 2040s demand that no one can currently verify.

Table 20. Midstream risk register

Source: risks derived from the concluded episodes cited above — the 2015–16 contract-rejection rulings, the Keystone XL, Atlantic Coast and Mountain Valley outcomes, and the May 2021 Colonial Pipeline shutdown. Likelihood and impact are the author’s qualitative assessment, not a modelled probability.

Figure 15. Midstream risk map

Source: data in Table 20, scored high = 4, medium = 3 and low = 2 on each axis; each point prints likelihood × impact. The uncertain likelihood of stranded assets is plotted at mid-scale, and tied points are spaced apart within their cell. The shaded high-likelihood, high-impact quadrant is empty — no midstream risk on this register is both likely and severe.

6. Future outlook & catalysts

Three build-outs are running at once, and for the first time since the shale boom they reinforce rather than compete with each other.

The export wave is the largest. US peak LNG export capacity stands at 18.3 Bcf/d against 15.0 Bcf/d of exports in 2025, and the gap closes fast — EIA’s April 2026 forecast has exports reaching about 18.5 Bcf/d in 2027 as Corpus Christi Stage 3 and Golden Pass start up (U.S. EIA; Table 21). Globally, liquefaction capacity rose from 494.4 mtpa at end-2024 to 524.5 mtpa at end-2025 (IGU 2025; IGU 2026), and Qatar’s pre-disruption plan takes it from 77 mtpa of nameplate capacity to 142 mtpa by around 2030 (Section 2.5). Every one of those trains needs firm upstream pipeline capacity contracted years ahead.

The power build-out is the newest. US gas consumption is projected to rise from 90.8 Bcf/d in 2025 to 108 Bcf/d by 2050 in the EIA’s AEO2026 counterfactual baseline case (U.S. EIA), and data centres — 50% of 2025 US electricity demand growth, and roughly 6.1 Bcf/d of direct gas burn by 2030 in an RBC Capital Markets projection — are the marginal driver. What makes this different from ordinary demand growth is location: data centres cluster where fibre, land and interconnection allow, not where pipelines already run, so they create new corridor needs rather than filling existing ones.

The pipe itself is the constraint and the opportunity. Developers plan 44.9 Bcf/d of new US gas pipeline capacity across 2026–27, with 31.6 Bcf/d already under construction; 29.7 Bcf/d of it originates in Texas and 8.4 Bcf/d in Louisiana. That is one of the largest concentrated build programmes in the network’s history, and it is being executed inside the same permitting regime that killed Keystone XL and the Atlantic Coast Pipeline — faster at the federal level since 2023, unchanged at the state level (Section 3.2).

Figure 16. US LNG exports, selected years

Chart source: U.S. EIA, Ten years after first Sabine Pass cargo, 2026, and U.S. natural gas exports to grow nearly 30% by 2027, April 2026. The 2027 figure is an EIA forecast, not an observed value: 17.0 Bcf/d forecast for 2026 plus a further 1.5 Bcf/d in 2027.

The structural shift underneath all of this is that midstream’s growth is moving from land to coast. Long-distance piped gas trade is expected to fall by almost 55 bcm between 2024 and 2030, mainly on lower deliveries to Europe, while global LNG supply rises by roughly 250 bcm (IEA). Pipelines will still carry the molecules to the water — but the value is migrating toward liquefaction, marine terminals and the corridors that feed them.

Canada is testing a faster track of its own. The Building Canada Act of June 2025 lets Ottawa designate projects of national interest, reviewed through a single Major Projects Office opened that August; its early referrals include LNG Canada’s second phase and Ksi Lisims LNG with its Prince Rupert Gas Transmission feed line, and on 2 July 2026 Alberta submitted a proposed West Coast oil pipeline, naming Trans Mountain Corporation and Pembina as its intended development partners.

Table 21. What to watch

Source: LNG start-ups and export forecasts per U.S. EIA, 2026; pipeline programme per U.S. EIA planned capacity additions, 2026; index per FERC, 2026; permitting items per Section 9.1 and the Canada–Alberta implementation agreement, May 2026. Timings are announced schedules and slip routinely.

7. Summary

Midstream infrastructure is the physical link between the wellhead and the end user — gathering, processing, fractionation, pipelines, storage, terminals, LNG and local distribution — and it earns by selling a service rather than a molecule. The service starts at a meter, the custody-transfer point at the edge of the lease, and because the revenue is a tariff rather than a price, 90–98% of the large operators’ cash flow is fee-based, take-or-pay or regulated.

The asset base is enormous and effectively unrepeatable: just over three million miles of reported US pipeline, 4,683 Bcf of working-gas storage and 18.3 Bcf/d of peak LNG export capacity. US gas transmission mileage has not grown since 2000 — the network absorbed a doubling of production through compression and reversals — and when capacity runs short, the shortage shows up as a basis differential, not a headline price.

Regulation, not a cartel, sets the terms: FERC’s oil index runs at PPI-FG − 0.55% through mid-2031. Permitting, not capital, is the moat — a FERC certificate is necessary but never sufficient, states hold vetoes that federal reform has not touched, and contested projects have finished at up to six times their estimate.

The listed universe is a dozen North American networks spread across six asset archetypes, from wellhead gathering, which carries the most volume risk, to regulated distribution, which carries almost none, and two tax structures, partnership and C-corp. Every route in is an equity or a fund, and a fund’s structure is the sector’s most expensive detail: the largest C-corp-taxed MLP fund returned about 2.2 points a year less than its index over the decade to June 2026, fees and deferred tax together.

Rates, not oil, are the dominant macro variable, and the sector dampens the commodity rather than amplifying it: from 2014 to 2016 WTI fell about 76% while the Alerian MLP Index fell 58%. The forward case rests on LNG and electricity — 44.9 Bcf/d of planned US pipe and a 437 Mt global LNG market — and the forward risks are recontracting, counterparty credit and the same permitting regime that protects the incumbents.

To move from this map of the network to the companies that own it — screening every pipeline, terminal, processing and storage owner by asset base, facility class and capacity — explore Metal Pilot’s midstream oil & gas stock screener.

Next in the series → Part 3: Downstream — how the barrel and the molecule are turned into fuels and petrochemicals once they reach the refinery gate.

8. Vocabulary

Table 22. Midstream terminology

Source: definitions compiled from U.S. EIA, FERC and PHMSA glossaries, company filings and standard industry usage.

9. Sources, methodology & disclaimer

9.1 Sources, methodology & data vintage

Agencies and regulators. PHMSA annual report mileage — natural gas transmission & gathering, hazardous liquid or carbon dioxide systems and gas distribution systems (report year 2025, revised 8 September 2026); U.S. EIA for LNG exports and capacity, the liquefaction capacity workbook, crude storage capacity, natural gas storage capacity, processing plant survey Form EIA-757, planned pipeline capacity additions and global LNG trade; FERC oil pipeline index (April 2026 final rule); Canada Energy Regulator oil pipeline throughput snapshot (2026).

Industry bodies and market data. IGU World LNG Report 2026; CAPP, Understanding the WCS–WTI Differential (April 2026); CME Group OpenMarkets on Mont Belvieu (2026); Alerian/VettaFi for index correlations and the 2014–16 drawdown. European systems in Table 6 per Gassco, Nord Stream AG, TurkStream, GAZ-SYSTEM, TAP AG, Global Energy Monitor and the Port of Rotterdam, with TurkStream’s status as the last Russian pipeline route to the EU per Bruegel (October 2024) and the IEA (Q1 2025). The dated 2026 Hormuz aside in Section 2.5 is sourced where it appears.

Boundary and permitting. SEC Regulation S-X Rule 4-10; PHMSA 49 CFR 192.8, 49 CFR 195.2 and the 2021 gas gathering rule; the Natural Gas Act; FERC’s pre-filing and NEPA regulations; GAO-13-221 (2013) on certificate timelines; US reform per the Fiscal Responsibility Act (2023), Seven County Infrastructure Coalition v. Eagle County (2025), CEQ’s final rule removing its NEPA regulations (January 2026), FERC Order No. 915, FERC’s withdrawal of its 2022 draft certificate policy (September 2025) and CNBC on the House’s SPEED Act vote (December 2025); Canadian reform per the Supreme Court of Canada reference as summarised by Fasken (2023), the Building Canada Act royal assent (June 2025), the Major Projects Office’s first and second referrals (September and November 2025) and Alberta’s West Coast oil pipeline submission (July 2026); Trans Mountain’s federal purchase per CDEV. Court decisions, agency actions and project disclosures behind Table 3, Table 4, Table 13 and Figure 10 are linked beneath them.

Company sources. Kinder Morgan, Williams, Enbridge, ONEOK, Energy Transfer, Enterprise Products, Targa and Cheniere disclosures and websites, 2025–26, for network scale, signature assets and fee-based cash-flow percentages. The firm-transportation tariff example in Section 1.4 is from the Southern Natural Gas rate sheet effective 1 October 2026.

Methodology. Pipeline mileage is taken from PHMSA operator annual reports for 2025, the latest year PHMSA now publishes for every segment, so the segment table in Section 2.3 is a single-year sum. The 2021–22 discontinuity in gas gathering mileage is a reporting-scope change (Type C gathering), not construction, and is flagged wherever the series appears. Company network figures are company-stated and use differing definitions, so they indicate reach rather than a like-for-like ranking. Utilisation figures divide throughput by the capacity basis stated in the same row; days of storage cover is an author calculation (design capacity ÷ average daily demand) and is labelled as derived. Correlations are weekly over the stated window. Cost multiples in Section 3.2 divide each project’s final or last-reported cost by its estimate at filing or construction decision, nominal and in the project’s own currency; the baseline differs by project (application, construction decision or ground-breaking) and is named in the figure source. Forecasts — the 2027 LNG export figure, the 2030 gas-burn and Qatari capacity figures, and the 2026–27 pipeline programme — are agency or company projections and are labelled as such wherever they appear; none is presented as a measured value. No market capitalisations, share prices or enterprise values appear anywhere in this report, by design.

Data as of 8 September 2026. Intended update cadence: annually, after the PHMSA annual report mileage refresh and the IGU World LNG Report.

9.2 Disclaimer & disclosure

This report is for informational purposes only and is not investment advice, a recommendation, or an offer to buy or sell any security. Midstream companies carry leverage, regulatory, counterparty and commodity risks, and capacity, throughput and contract figures are estimates as of the stated date that change with each reporting cycle. Historical index and price behaviour is presented as settled history; past performance is not indicative of future results, and the correlations and regime patterns described here are sample-dependent and can break down, particularly in a crisis. Readers should do their own research and consider consulting a licensed financial adviser before acting. This report was prepared with the assistance of AI, consistent with the ai = true flag in its front matter; figures were sourced from the references above and reviewed, but readers should verify any figure they intend to rely on. The author holds no position in any company named in this report.