Take-or-Pay Contracts and Pipeline Revenue Quality

Take-or-Pay Moves the Risk, It Does Not Remove It

A take-or-pay clause obliges a shipper to pay for booked pipeline capacity whether or not it ships anything. Nothing about that makes the revenue safe. It makes the revenue independent of volume, and dependent on two other things instead: whether the shipper can still pay, and how many years the contract has left to run.

That trade sits behind every “96% contracted” slide in the sector. Volume risk goes to the producer who signed. The pipeline takes on that producer’s credit, and the risk of what the contract renews at when it expires. Minimum-volume commitments, or MVCs, do the same job in gathering and processing contracts under a different name: the producer commits to a quantity and pays a shortfall fee if it falls short.

So a contract-mix percentage answers one question: which slice of earnings would still arrive if volumes fell. It says nothing about who owes the money, or for how long.

”Fee-Based” Is a Much Wider Word Than “Take-or-Pay”

This is where most screens go wrong. A fee-based contract charges a fixed rate per unit moved instead of taking a share of the commodity itself. That removes commodity price risk. It does not remove volume risk. A gathering fee of a few cents per thousand cubic feet earns exactly nothing on a well that has stopped flowing.

Take-or-pay is the narrower subset of fee-based business where the payment survives volume going to zero. Every take-or-pay contract is fee-based; most fee-based revenue is not take-or-pay.

Hedged earnings are a third category, weaker still: commodity-exposed volumes with the price locked for a period. When the hedge expires, the exposure comes back at whatever the market is then.

A company quoting one blended number for all three is not telling you the take-or-pay figure. Kinder Morgan publishes the split, which makes it the useful case.

Worked Example: KMI’s 2026 Budget Mix

Kinder Morgan’s 1Q 2026 investor presentation breaks down its 2026 budgeted total adjusted segment EBDA, its measure of segment earnings before depreciation and amortisation:

Category	Share of budgeted EBDA
Take-or-pay	65%
Fee-based, no volume commitment	26%
Hedged	5%
Unhedged, commodity-exposed	4%
Take-or-pay, fee or hedged combined	96%

The headline is 96%. The figure for earnings that survive a volume collapse is 65%. Those 31 points are the gap that matters: the 26% fee-based slice still needs molecules to move, and so does the 5% hedged slice, with the price fixed for a while.

Even 65% is not a floor. It holds only for as long as the shippers behind it stay solvent and the contracts stay in force. Both can fail.

The Contract Ends: Recontracting Is the Real Exposure

Pipeline contracts have terms. When one expires, the pipeline renegotiates at whatever the market will bear, against the competing capacity built meanwhile. A drilled-out basin, or a route a rival line now serves more cheaply, produces a renewal at a lower toll or no renewal at all. None of that shows in the contracted percentage until the expiry lands.

So hunt for the contract term alongside the percentage. Companies with long ones tend to say so, usually as a weighted-average remaining contract life, per asset or per segment, in the investor deck and not in the accounts. A system 90% contracted for nine more years and one 90% contracted for two are not the same business, and the percentage cannot tell them apart. Silence on term tells you something too.

Term also decides how much of the valuation the contracts can carry. Discounting ten years of cash flow on the strength of a contract with three years to run means seven of those years are a bet on renewal, not on the contract.

The Shipper Fails: Credit Risk Was Always the Point

Because take-or-pay converts volume risk into a promise to pay, the revenue is only as good as the party promising. Concentration matters for the same reason: a network with one shipper behind a third of its capacity holds that shipper’s credit rating, whatever its contract mix says.

Bankruptcy is where this stops being theoretical. A company in Chapter 11 can ask the court to reject contracts it no longer wants, and midstream contracts have been rejected. Sabine Oil & Gas is the case everyone cites. In 2016 the bankruptcy court held that the dedication covenants in its gathering agreements did not run with the land under Texas law. That made them ordinary contracts the debtor could throw off, and the Second Circuit upheld the rejection. Later cases in other states went the other way on the same question, so the answer turns on the drafting and the jurisdiction, not on anything visible in a percentage.

Interstate pipelines regulated by the Federal Energy Regulatory Commission sit on contested ground of their own. When Chesapeake Energy moved to reject transportation agreements in 2020, FERC declared it held jurisdiction over the outcome alongside the bankruptcy court, reasoning that rejecting a contract cannot by itself change a regulated rate.

After a successful rejection the pipeline is left with an unsecured damages claim, queuing with the bondholders. A take-or-pay obligation is a contract, not collateral.

The Percentages Do Not Compare Across Companies

Each filer builds its number on a different base. Ranking them is the trap.

Company	What it discloses	Measured on	Period
KMI	96% take-or-pay, fee or hedged (65% take-or-pay)	Budgeted total adjusted segment EBDA	2026 budget
ENB	98% from low-risk businesses	EBITDA	Sep 2023 filing
WMB	More than 90% fee-based	Fee-based earnings	2024 mix, Oct 2025 fact sheet
ET	About 90% fee-based	Adjusted EBITDA	Q3 2025 deck
EPD	82% fee-based	Gross operating margin	FY2025
MPLX	No consolidated figure published	n/a	FY2025

Three faults show in that table. The years differ: Kinder Morgan’s forward budget sits beside Enterprise Products’ completed year. The denominators differ: gross operating margin, EBITDA and segment EBDA are three different lines, and a margin measure that strips out certain pass-through costs behaves unlike a consolidated EBITDA. The definitions differ too, since Enbridge’s “low-risk” labels a category of business, not a count of contracts.

A fourth fault hides one level down. Williams’ more than 90% fee-based earnings is a consolidated figure. The 93% of NGL processing volumes under fee-based contracts, from the same company, is one segment measured in volumes instead of earnings. Segment statistics get quoted as though they described the whole company.

No third-party aggregate for the sector exists, so there is no average to rank against. The only honest comparison sets them side by side with each footnote written next to its number.

MPLX publishes no consolidated fee-based share at all. What it gives instead is more useful: Marathon Petroleum owns 63.7% of the units and the whole general partner, and is also the partnership’s main customer. That answers the counterparty question directly, with no percentage in the way.

Worked Example: Enbridge’s 98% and Its Largest Asset

Enbridge reports 98% of EBITDA from low-risk businesses. FY2025 adjusted EBITDA of C$19,952M splits as:

Segment	EBITDA (C$M)	Share
Liquids	9,710	49%
Gas transmission	5,397	27%
Gas distribution	4,139	21%
Renewables	672	3%

Gas distribution is a rate-regulated utility, and low-risk describes it well. Liquids, the largest segment, is mostly the Canadian Mainline, and the Mainline is not take-or-pay. It runs as a common carrier: shippers nominate volumes month by month and pay tolls on what they actually move. Enbridge applied to put most of that capacity under firm contracts of eight to twenty years. The Canada Energy Regulator refused in November 2021, partly because reserving only a tenth of capacity for uncommitted shippers sat badly with the common-carriage obligation.

So half of a portfolio labelled 98% low-risk carries volume risk fairly directly. It has held up because the line is full, not because anyone is obliged to fill it: Mainline throughput averaged 3.1 million barrels a day in FY2025 against nameplate capacity of about 3.22 million, roughly 96% utilisation. Scarce capacity is real protection, and it lasts exactly as long as demand for the line exceeds the line.

What This Changes in a Valuation

EV/EBITDA multiples and distribution coverage both assume the EBITDA or the distributable cash flow underneath them is durable. Contract quality decides whether that assumption holds. It is why a heavily contracted gas transmission network capitalises at a higher multiple than a gatherer taking a share of processing margin, at the same leverage.

But the percentage alone will not size the gap. A gatherer disclosing 90% fee-based EBITDA can be the weaker business than a pipeline citing 82% fee-based gross operating margin, if the gatherer’s fees are per-unit with no minimum commitment and the pipeline’s are not. Three things do the work: how much is take-or-pay rather than merely fee-based, how many years it has left, and who is on the other side.

Operating netback is the upstream mirror image, where the producer keeps the price exposure the pipeline shed. Midstream should not be screened on netback at all. The equivalent question for a pipeline is what share of EBITDA is a toll owed regardless of price and volume, and for how long.

When a deck cites a contracted percentage, take the footnote with it: the denominator, the year, and the segment scope. Then ask what the percentage cannot answer: how long do the contracts run, and what happens to that revenue if the largest shipper stops paying? File the answers next to DCF and leverage before ranking anything on revenue quality.