Snapshot

Natural gas pipelines connect gas wells in basins like the Permian, Appalachia, and Haynesville to end users: power plants, LNG export terminals, industrial facilities, and homes. The five companies here — Kinder Morgan (KMI), Williams Companies (WMB), Energy Transfer (ET), ONEOK (OKE), and Targa Resources (TRGP) — collectively operate over 300,000 miles of pipeline and handle a large share of the ~118.5 Bcf/d the US produced in 2025. US gas consumption hit a record 91.4 Bcf/d in 2025. LNG exports added another 14.2 Bcf/d. An additional 44.9 Bcf/d of new pipeline capacity is planned for 2026-2027, the largest buildout since 2008, driven by LNG terminal feedgas demand and power-sector load growth from AI data centers.

Every molecule of gas burned in a power plant, exported as LNG, or consumed by a factory must travel through a pipeline to get there. Pipeline operators collect a toll on each unit of gas that flows through their system. The upfront cost to build is high, but once the pipe is in the ground, cash flows are largely fee-based and contracted for years. A new interstate pipeline takes 3-5+ years to approve and build.

Sources: EIA "Today in Energy" articles (May 2026, Mar 2025, Feb 2025); EIA STEO (Mar 2025); company Q1 2026 earnings releases.

The product & how money is made

The "product" is pipeline capacity — the right to move gas from point A to point B, measured in Bcf/d (billion cubic feet per day). Midstream companies provide four main services:

• Gathering: collecting raw gas from wellheads via small-diameter pipes and delivering it to processing plants. Fees are typically per-Mcf (thousand cubic feet) gathered.
• Processing: separating NGLs (natural gas liquids — ethane, propane, butane) from raw gas. Revenue comes from processing fees and sometimes a share of the extracted NGLs.
• Transportation: moving processed gas through large-diameter interstate or intrastate pipelines over long distances. Tariffs are set by FERC (Federal Energy Regulatory Commission) for interstate pipelines and are typically contracted under firm capacity agreements lasting 5-25 years.
• Storage: injecting gas into underground formations (depleted reservoirs, salt caverns) when demand is low and withdrawing it when demand peaks. Storage operators earn a fee for the capacity reserved.

Fee-based vs. commodity-exposed

A "fee-based" contract pays the pipeline operator a fixed rate per unit of throughput regardless of gas price. A "commodity-exposed" contract pays the operator a share of the gas itself or a margin linked to gas/NGL prices. KMI, WMB, and OKE earn 90%+ of EBITDA from fee-based contracts. ET and TRGP have more commodity exposure through their NGL processing and marketing operations.

Source: KMI, WMB, OKE 10-K disclosures; OKE Feb 2025 guidance (90-95% fee-based).

How the money comes in — the contract structure

Interstate pipeline tariffs are filed with FERC and function like regulated utility rates. Shippers (producers, utilities, LNG exporters) reserve "firm capacity" — a guaranteed right to move a fixed volume per day. They pay the reservation fee whether or not they use the capacity. If they don't use it, they can release it to other shippers on the secondary market. Williams reported $31.65B in remaining performance obligations (contracted future revenue) as of Q1 2026. KMI's $10.1B project backlog is ~92% natural gas and ~60% tied to power generation and local distribution company demand.

Source: WMB Q1 2026 10-Q (RPO $31.65B); KMI Q1 2026 earnings release (backlog $10.1B).

Demand

Contracted demand — what is locked in

• LNG export terminals under construction or ramping: Golden Pass (three trains, 2025-2026), Corpus Christi Stage 3 (2026), Plaquemines Phase 2 (2026), Rio Grande LNG (2027-2028), Port Arthur Phase 1 (2027-2028). Each requires dedicated pipeline feedgas capacity. EIA forecasts US LNG exports rising from 11.9 Bcf/d in 2024 to 14.2 Bcf/d in 2025 to 16.4 Bcf/d in 2026 — an increase of ~4.5 Bcf/d in two years. contracted
• KMI's project backlog: $10.1B with ~5.6x expected first-full-year EBITDA multiple. Major contracted projects include Trident Pipeline (2 Bcf/d, $1.8B, in-service Q1 2027/Q4 2028), SSE4 on Southern Natural Gas (~1.3 Bcf/d, ~$3.5B total, Q4 2028/Q4 2029), and MSX on Tennessee Gas Pipeline ($1.7B, Q2 2028). contracted
• WMB's contracted pipeline: Southeast Supply Enhancement (1.5 Bcf/d expansion of Transco, proposed for 2027), Power Express (950 MMcf/d, proposed for 2030), plus Regional Energy Access (1.05 Bcf/d, FERC-approved). Total RPO of $31.65B. contracted
• ET's contracted projects: FGT Phase IX (~525 MMcf/d, 15-25 year anchor shipper agreements), Springerville Lateral (~625 MMcf/d, 20-year agreements, in-service Q4 2029, ~$600M). Oklahoma power plant connections totaling ~300 MMcf/d with first in service now. contracted

Forecast demand — directional, not locked in

• Power-sector gas burn for AI data centers: US electricity demand was flat for 15 years. AI data centers have broken that trend. Utilities in Virginia, Texas, and Ohio are projecting 5-10% annual load growth in their service territories. Natural gas is the only scalable 24/7 fuel available on a 2-3 year timeline (nuclear takes longer, renewables are intermittent). TC Energy planning cases cite a 45 Bcf/d increase in North American gas demand by 2035. est.
• Pipeline exports to Mexico: Mexico's gas production has declined while its demand grows. US pipeline exports to Mexico have been rising and new cross-border capacity is being built (NET Mexico, Sierrita). est.
• Industrial demand: petrochemical plants, fertilizer plants, and other heavy industry consume gas. This segment is relatively stable but grows with GDP and reshoring trends. est.
• EIA projects total US gas consumption to set new records. January 2025 hit an all-time monthly record of 126.8 Bcf/d. The 2025 annual average of 91.4 Bcf/d was a new yearly record, up ~1% from 2024. contracted

Sources: EIA "Today in Energy" (May 2026, Feb 2025); EIA STEO (Mar 2025); KMI Q1 2026 earnings; WMB Q1 2026 10-Q; ET Q1 2026 8-K; Global Energy Monitor (Transco wiki).

Supply

Existing capacity

• KMI: ~65,000 miles of natural gas pipelines, 704 Bcf of storage. Transports ~40% of all US gas consumed. Five major systems ran at 90% average utilization in 2025, up from 74% in 2016. Key systems: Tennessee Gas Pipeline (11,760 mi), El Paso Natural Gas (10,140 mi), NGPL (9,100 mi, 288 Bcf storage), Southern Natural Gas (6,900 mi, 50/50 JV), Florida Gas Transmission (5,400 mi, 50/50 JV with ET). contracted
• WMB: Transco system — 10,200 miles, 16.8 Bcf/d capacity, running from Gulf Coast of Texas to New York City. The single largest pipeline in the US. Transco generated $847M revenue in Q1 2026 (+10% YoY). contracted
• ET: ~140,000 miles of pipeline across 44 states (includes NGL, crude, refined products — not all natural gas). Key gas assets: intrastate system (13,782 BBtu/d transported Q1 2026), interstate system (18,120 BBtu/d), plus 50/50 JV on Florida Gas Transmission with KMI. contracted
• OKE: ~60,000 miles of pipeline. Natural gas pipeline segment earned $339M adjusted EBDA in Q1 2026 (+60% YoY), driven by $92M in optimization from Waha-to-Katy price differentials. 90-95% fee-based. contracted
• TRGP: Primarily a gathering and processing company (8,431 MMcf/d plant inlet in Q1 2026, +12% YoY), with downstream NGL logistics (fractionation, transport, export). Its pipeline capacity is gathering/NGL-focused in the Permian Basin. contracted

New capacity under construction or approved

EIA reported 44.9 Bcf/d of new pipeline capacity planned for 2026-2027, with 31.6 Bcf/d (70%) already under construction as of May 2026. In 2024, 17.8 Bcf/d was added — the second consecutive year of rising additions. The largest share of new capacity (66%) is in Texas, driven by Permian Basin takeaway and LNG terminal connections.

Sources: EIA "Today in Energy" (May 26, 2026); KMI Q1 2026 earnings; WMB press release (May 2026); ET Q1 2026 8-K; Global Energy Monitor.

The bottleneck: permitting

A new interstate natural gas pipeline requires a FERC certificate, federal environmental review (NEPA), and often state-level permits. The Mountain Valley Pipeline took a decade from proposal to completion. KMI's SSE4 project has a FERC Draft Environmental Impact Statement issued January 2026, with a certificate order expected July 2026 — and the pipe won't be in service until Q4 2028 at the earliest. This 3-5+ year lag from conception to first gas is the primary constraint on new supply. WMB's Northeast Supply Enhancement (400 MMcf/d) was cancelled after repeated permit rejections, and several other Transco expansions were abandoned after years of regulatory delays.

The gap

Where demand and supply stand relative to each other

US gas production rose 5.3 Bcf/d in 2025 to a record 118.5 Bcf/d. Domestic consumption set a record at 91.4 Bcf/d. LNG exports are forecast to rise from 14.2 Bcf/d (2025) to 16.4 Bcf/d (2026). Pipeline exports to Mexico are rising. Total call on US gas is increasing from multiple directions simultaneously.

The EIA projects 44.9 Bcf/d of new pipeline capacity for 2026-2027, but most of this capacity serves specific routes (Permian takeaway, LNG terminal feedgas) and does not create fungible nationwide capacity. KMI's five major systems went from 74% utilization (2016) to 90% (2025). The Waha Hub in West Texas traded at deep discounts to Henry Hub through much of 2024-2025 because pipeline takeaway capacity out of the Permian was insufficient. OKE earned $92M in Q1 2026 from Waha-to-Katy price differentials — that spread exists because the pipes are full.

AI data centers need 24/7 power, and gas-fired generation is the only scalable source on a 2-3 year timeline. ET has signed a long-term firm gas transport agreement for an AI hyperscale campus with on-site gas generation ("Nexus Hubbard Campus"). KMI reports that 60% of its $10.1B backlog is tied to power generation and local distribution company demand.

Tariff dynamics

Pipeline tariffs are not set by the commodity market — they are negotiated between shippers and operators (for new capacity) or regulated by FERC (for existing rates). KMI's $10.1B backlog carries an expected 5.6x investment-to-EBITDA multiple — meaning for every dollar of capex, they expect about $0.18 of annual EBITDA. FERC rate cases adjust existing tariffs for inflation and cost of capital on a periodic basis.

Sources: EIA (production, consumption, pipeline capacity data); KMI Q1 2026 earnings (utilization, backlog); OKE Q1 2026 earnings (Waha spread); ET Q1 2026 8-K (Nexus Hubbard).

The players

Structural note: ET is a master limited partnership (MLP) and issues K-1 tax forms rather than 1099s. Distributions are largely return of capital but add tax-filing complexity. The other four are C-corporations with standard 1099-DIV dividends.

Adjusted EBITDA: earnings before interest, taxes, depreciation, and amortization, adjusted for one-time items and non-cash charges. The ratio of enterprise value (market cap + net debt) to EBITDA tells you how many years of current cash profit you are paying for the entire business.

Sources: KMI Q1 2026 earnings release; WMB Q1 2026 10-Q and May 2026 press release; ET Q1 2026 8-K; OKE Q1 2026 earnings and Feb 2025 guidance; TRGP Q1 2026 8-K. Prices from stockanalysis.com and barchart.com (Jun 3, 2026). EV/EBITDA calculated as (market cap + net debt) / 2026E EBITDA midpoint. WMB and OKE net debt estimated from balance sheet data.

The price of exposure

What you get for your money — per $1,000 invested

"Share of 2026E EBITDA" = 2026E EBITDA midpoint / market cap x $1,000. "Share of net debt you assume" = net debt / market cap x $1,000.

Valuation ranges — what the market has paid

Dividend coverage: KMI's Q1 2026 FCF of $687M covered its $654M dividend with $33M to spare. WMB's AFFO guidance of $6.2B covers its ~$2.6B annual dividend at 2.4x. TRGP pays $5.00/yr annualized while generating ~$5.8B EBITDA est.. ET's $2.7B Q1 2026 DCF (annualized ~$10.8B est.) covers its ~$4.6B annual distribution at over 2x est..

Sources: Dividend and EBITDA data from Q1 2026 filings. 52-week ranges approximate from stockanalysis.com and barchart.com.

What to deep-dive next

• FERC rate case risk: interstate pipeline tariffs are subject to periodic FERC review. Understand the rate case schedule for KMI's Tennessee Gas Pipeline and WMB's Transco — when are they next up for review?
• Permian basis differentials: track whether Blackcomb, Hugh Brinson, and Trident collapse the Waha-to-Henry Hub spread when they come online in 2026-2027, or whether production growth keeps pipes full.
• LNG feedgas contracts: which of these five companies hold the long-term feedgas delivery contracts for Golden Pass, Corpus Christi Stage 3, Plaquemines, Rio Grande, and Port Arthur?
• ET's structural complexity: ET is an MLP that consolidates Sunoco LP and USA Compression Partners (USAC). Strip out Sunoco and USAC to understand ET's "pure midstream" EBITDA and leverage.
• WMB's growth capex: $7.0-7.6B in 2026 is nearly the company's entire annual EBITDA. What is the expected return on this capital? How much is Transco expansion vs. new acquisition?
• TRGP's commodity exposure: TRGP's Q1 2026 natural gas realized price was $0.57/MMBtu (down 75% YoY) and NGL prices fell 22%. How much of TRGP's EBITDA growth came from volume vs. price?
• Counterparty concentration: WMB's Transco has a single customer responsible for 83% of accounts receivable. Who is it?
• Tax structure for ET: the K-1 creates UBTI issues for tax-exempt accounts like IRAs. Quantify whether the yield advantage over C-corps survives after tax-structure friction.

Sources & confidence