Midstream contracts and MLP structures

The contract is the asset

A pipeline is a piece of steel in the ground. On its own it generates nothing. What makes it worth something is a set of agreements obligating shippers to use it and pay for it, and the terms of those agreements determine almost everything about how the business behaves.

This is the single most useful sentence to carry into a midstream interview, because it reframes every question. Asked why one midstream company trades at a higher multiple than another, the answer is rarely about the assets themselves and almost always about contract quality: how much revenue is fee-based, how long the contracts run, whether there are minimum volume commitments, and how creditworthy the counterparties are. Two operators can own similar-looking gathering systems in the same basin and carry completely different risk profiles.

The sub-sector spans gathering systems that collect production from individual wells, processing plants that separate natural gas liquids out of the gas stream, fractionators that split those liquids into components like ethane and propane, long-haul transmission pipelines, storage, and terminals. The contract structures vary across those asset types, but the underlying question is always the same: who bears price risk, who bears volume risk, and for how long.

The three contract types

Learn these three cleanly. They generate a large share of the sector's technical questions.

A take-or-pay contract, often structured as a minimum volume commitment, obligates the customer to pay for a contracted quantity of capacity or throughput whether or not it actually ships that volume. If the shipper's production falls short, it pays anyway, sometimes with a deficiency credit it can apply against future overages. For the operator this removes both price and volume risk over the contract term, converting revenue into something that behaves much like a fixed-income stream. This is the highest-quality revenue in the sub-sector and commands the highest multiple.

A fee-based contract charges a set fee per unit actually transported, gathered, or processed. The operator has no direct commodity price exposure, since it earns the same fee whether gas is expensive or cheap, but it does carry volume risk. If producers in the area reduce activity, throughput falls and so does revenue. Most of the sub-sector describes itself as predominantly fee-based, and the follow-up question is always what percentage and over what tenor.

A percent-of-proceeds contract pays the processor a share of the value of the commodities it handles, which gives the operator direct commodity exposure. A keep-whole contract is the more aggressive version: the processor takes the raw gas stream, extracts the liquids and keeps them, and returns to the producer gas of equivalent energy value. That makes the processor long liquids and short gas, so its margin depends on the relationship between the two prices, and it can be genuinely negative when gas is expensive relative to liquids. Candidates who can explain why a keep-whole processor can lose money on volume it successfully handled are demonstrating real understanding.

Volume risk and counterparty risk

Fee-based revenue is not risk-free revenue, and the two ways it fails are worth naming separately.

Volume risk is the slower failure. Gathering systems are tied to specific acreage, so their throughput depends on producers continuing to bring wells online in that area. When prices fall and producers cut budgets, new activity slows first and existing wells decline, so gathering volumes fall with a lag. A long-haul pipeline connecting two liquid markets is more insulated, because it serves a broader supply base. This is why the location and dedication of a gathering system matters as much as its size, and why an operator concentrated behind a single basin's economics is more exposed than the headline fee-based percentage suggests.

Counterparty risk is the faster failure. Contracted revenue is only as good as the counterparty's ability to pay, and midstream counterparties are frequently producers, who are exactly the parties most stressed when prices fall. An investment grade shipper on a fifteen-year take-or-pay is a different asset from a small private operator on the same paper. This risk is not hypothetical, and it interacts with the producer-side dynamics covered in what energy investment bankers actually do, where a sustained downturn pushes producers into restructuring.

So the diligence sequence on a midstream business runs: what percentage of revenue is fee-based or take-or-pay, what is the weighted average remaining contract tenor, who are the counterparties and what is their credit quality, and how concentrated is the acreage dedication behind the system.

The master limited partnership structure

Much of the midstream sub-sector was built inside master limited partnerships, and the structure comes up constantly in interviews even though many companies have moved away from it.

A master limited partnership is a publicly traded partnership that generally avoids entity-level federal income tax, provided a large majority of its gross income comes from qualifying sources. Those qualifying sources include the transportation, processing, storage, and marketing of natural resources, which is why the structure clustered in midstream specifically rather than spreading across the economy.

The appeal is straightforward. Without corporate tax at the entity level, more of the cash a pipeline generates reaches investors. Pair that with long-lived assets producing stable contracted cash flow, and you have a natural vehicle for income-oriented investors: an asset that generates predictable cash, in a structure that passes that cash through efficiently, distributed regularly.

Investors hold units rather than shares and are limited partners. A general partner controls the partnership and manages it, typically holding a small percentage economic interest alongside its control rights. That split between control and economics is where the structural problems started.

Incentive distribution rights and why they became a problem

Many partnerships granted the general partner incentive distribution rights, which entitled it to an escalating share of incremental distributions above defined thresholds. At the top tier, the general partner could receive a very large share of each incremental dollar distributed to unitholders.

The intent was alignment: the general partner earns more as it grows distributions. The effect over time was the opposite. Because the general partner captured a disproportionate share of incremental cash, the partnership's effective cost of capital rose as it grew, which meant acquisitions and projects had to clear a progressively higher return hurdle to be accretive to limited partners. It also created a conflict, since the general partner benefited from growth in distributions even when the growth was funded on terms that were poor for limited partners.

Layered on top was a structural dependence on capital markets. Because the partnership distributed most of its cash flow rather than retaining it, growth had to be funded externally with new units and new debt. That worked while markets were receptive and became acutely painful when they closed, since a partnership could find itself unable to fund committed projects while also unable to cut its distribution without destroying its unit price.

There were investor-level frictions too. Unitholders received a partnership tax form rather than a standard dividend statement, which brought complications that deterred many institutional investors and irritated retail holders. Certain tax-exempt and foreign investors faced additional issues holding partnership interests.

The result was a wave of simplifications: partnerships eliminating incentive distribution rights, general partners rolling up their interests, and in many cases conversion back to corporate form. A candidate who can explain both why the structure made sense and why the sector moved away from it is giving a genuinely informed answer, which is more than the question usually gets.

Distributable cash flow and the coverage ratio

The sub-sector's headline metric is distributable cash flow, meaning the cash actually available to pay distributions. It generally starts from EBITDA, subtracts cash interest expense, cash taxes, and maintenance capital expenditures, and adjusts for a handful of other items. The coverage ratio is distributable cash flow divided by distributions paid, and a ratio below one means the partnership is paying out more than it generated, which it must fund with debt or new units.

The soft spot is maintenance capital. There is no rigid line separating maintenance capital from growth capital, so management judgment determines how much gets subtracted. A company that classifies aggressively can report healthy distributable cash flow and a comfortable coverage ratio while underinvesting in its asset base. The analytical response is to compare maintenance capital against depreciation, watch whether the split has drifted over time, and cross-check with free cash flow after all capital spending.

This is structurally the same instinct required elsewhere in the sector: reported metrics need translation before they mean anything, whether it is exploration accounting at a producer, as in energy accounting: successful efforts versus full cost, or maintenance capital here.

Valuation follows conventionally. EV to EBITDA against comparables, a discounted cash flow on contracted volumes, and a distribution or distributable cash flow yield analysis reflecting how income-focused investors actually price the security. The multiple work is covered alongside the rest of the sector in how energy companies are valued, and the closely related contracted-infrastructure logic that governs export projects is in LNG and export infrastructure.

What interviewers ask

The most common question is the contract comparison: what happens to a gathering and processing company with percent-of-proceeds contracts versus one with fixed fees when gas prices collapse. The complete answer has two halves. The percent-of-proceeds operator is hurt immediately and directly, because its revenue is a share of a falling commodity value. The fee-based operator has no direct exposure, but is hurt with a lag as producers cut activity and volumes decline, and faces rising counterparty risk as its customers come under stress. Minimum volume commitments would protect it against the volume decline for the contract term, which is exactly why that provision commands a premium.

The second is why midstream is less volatile than upstream, which is the fee-versus-price point, with the qualification that not all midstream contracts are equally insulated.

The third is the MLP question, which usually arrives as "what is an MLP and why did companies convert away from it." Incentive distribution rights and capital markets dependence are the two answers that matter most.

Practice question

Two gathering and processing companies have the same EBITDA. Why might one trade at a meaningfully higher multiple?

Almost certainly contract quality, because in midstream the contract is really the asset. The first thing I'd look at is revenue mix. If one company's revenue is largely take-or-pay or minimum volume commitment, the customer pays for contracted capacity whether or not it ships, so that revenue behaves close to a fixed-income stream and deserves a premium multiple. If the other is heavily percent-of-proceeds or keep-whole, it has direct commodity exposure, and a keep-whole processor can actually post a negative margin if gas gets expensive relative to the liquids it keeps, so that revenue is worth much less per dollar of EBITDA. Second, weighted average contract tenor. Ten years of remaining contract life is worth more than two, because the shorter book has to be renegotiated at whatever the market offers. Third, counterparty credit, since contracted revenue is only as good as the payer, and midstream counterparties are often producers, who are exactly the parties under stress when prices fall. Fourth, acreage concentration behind the system, because a gatherer dedicated to one basin carries volume risk that a long-haul line between two liquid markets doesn't. I'd also check whether the reported maintenance capital looks realistic against depreciation, since distributable cash flow can be flattered by classifying maintenance spending as growth.

What the interviewer is listening for: That you go to contract structure rather than to the assets, and that you can name the three contract types and say who bears which risk under each. Raising counterparty credit and the maintenance capital discretion in distributable cash flow are the two additions that mark a candidate who has actually looked at these businesses.