The Promote Is the Most Expensive Capital an Operator Uses: Keeping the Well With Strategic Leverage

By MercConsulting · Published 2026-10-20

Small and mid-sized operators give investors most of every well because they do not have the capital, or do not know lender capital exists for drilling. One well compared both ways, in shares of its cash flow, and what changes for the operator who finances instead.

The investor promote is the most expensive capital most small and mid-sized oil and gas operators will ever use, and most of them have never priced it. The structure is universal: investors fund the cost of a well in exchange for 50% to 70% of it, the operator is carried for the rest, and the investors' share never ends. Lender capital for drilling exists, it is repaid once out of the well's own cash flow, and after that the production belongs to the operator. On one illustrative well the capital costs about 24% of ten years of cash flow under the promote and about 3% under a loan. That is strategic leverage to enhance returns and further mitigate and further minimize risk, and it is a decision about capital structure, not geology.

This guide is for the owner of an operating company, or the business owner who is about to become one. It covers how the promote actually prices, the same well funded both ways in shares of its cash flow, what changes for the operator who keeps the well, the structures lenders use, and how we help an owner decide. It is education, not a pitch. MercConsulting does not lend, and does not sell interests in wells or in anything else.

"I thought of the investors as partners. It took a spreadsheet to see that I had been paying them the most expensive interest rate in the county, forever."

How the promote actually prices

Take a well whose cost the operator cannot fund alone. Accredited investors put up all of it for 60% of the working interest; the operator is carried for 40%. Each investor owns a pro rata slice of the investors' 60%. Nobody is ever repaid in the ordinary sense; the well pays everyone out of production for as long as it produces, and the investors' 60% lasts as long as the well does.

The promote has real virtues. It funds wells that would otherwise sit undrilled, and it places drilling risk on people who chose to take it. The problem is the price. A lender is paid interest until principal is returned, then nothing. The promote is paid a majority of the production, after the investors' capital has already come back, for twenty years. Operators accept it for one of two reasons: they lack the capital, or nobody has shown them that commercial financing exists for what they do. The second is fixable in a conversation; the first is usually more fixable than the operator thinks, because each well kept creates the proved production the next loan is underwritten on.

One well, two ways

Run one illustrative well both ways and look only at the ten-year net cash flow it produces, which is the same in both cases. The capital that drilled it is returned out of that cash flow either way: to the investors inside their 60%, or to the lender as principal. What differs is the price of the capital and who keeps the rest.

On this well the promote costs roughly 9 times what the loan costs, and the operator's share of ten years of cash flow rises by about half. Multiply that by a program of ten or a hundred wells and the promote stops looking like a partnership and starts looking like what it is: a permanent sale of most of the business, one well at a time.

What changes when the operator keeps the well

• The operator keeps the well. A loan is repaid once; a promote pays out for the life of the well.
• Each well kept funds the next. Proved producing reserves are what energy lenders advance against. A program that keeps its wells builds a borrowing base; a program that gives them away builds someone else's.
• Tax efficiency stays with the operator. Deductions for intangible drilling costs and depletion follow the working interest, so the operator who keeps the well keeps them, and interest paid is generally deductible. Eligibility and limits depend on the operator's circumstances; your CPA confirms the treatment. The mechanics are in how oil and gas is taxed.
• Fewer investor obligations. No private placement, no investor reporting, no partners to manage on every well, no fundraising calendar between the lease and the rig. That is also fewer securities-law obligations, which deserve a licensed securities attorney whenever investors are involved.
• Investors where the operator chooses them. A facility sized to what a lender will advance, with a smaller raise on selected wells, keeps far more of the program than a promote on every well.

The structures lenders use

None of this is exotic. Energy credit has a standard toolkit, placed by commercial banks and private energy lenders, and small operators are simply rarely shown it.

An operator with producing wells is a reserve story: the lender advances against what is already producing, and the program is funded as the base grows. An operator with little production is a development story: the lender underwrites the program, the offset results and the operator's history, and advances on each well as its AFE is approved. Knowing which story you are telling before the first conversation saves weeks, and the file is the same either way: the program or AFE, production history and lease operating statements, a reserve report if one exists, the operator's record on offset wells including actual costs against AFEs, hedging, a sources-and-uses budget, and entity and personal financials.

Where the owner's decision sits

The decision is not whether lender capital is cheaper than a promote; on any producing well it is, by a wide margin. The decision is how much of the program the owner is prepared to share, how much a lender will advance against what exists today, and how to sequence wells so that each one kept moves the next one further toward the lender. That is a capital-structure plan, and it belongs beside the owner's reserve targets, tax planning and entity structure rather than in a rig-side conversation under deadline. The same discipline applies to the other side of the table: an owner being offered a working interest should read evaluating sponsors and operators and the plain-English primer before committing anything, and an investor weighing financing of their own units will find that case in strategic leverage in a working interest portfolio.

We help operators and owners make that decision with written criteria, coordinated diligence, and capital-placement support through the commercial funding relationships we work with, inside Multiply Profits. We do not lend, and we do not sell interests in wells.

Frequently Asked Questions

What does an investor promote cost an oil and gas operator?

Whatever share of the well the investors receive above the return of their capital, for the life of the well. On an illustrative well where investors fund the cost for 60%, that is about a quarter of ten years of net cash flow above the capital returned, against a few percent of it for interest on a loan. The figures are hypothetical; the shape of the comparison holds on any producing well.

Can a small operator borrow to drill instead of raising from investors?

Often, and more often than small operators assume. An operator with producing reserves can usually fund drilling from a reserve-based facility as the borrowing base grows. An operator with little production is underwritten as a development program on offset results and history, and may be offered a facility that funds part of each well, with equity covering the balance. Every request is subject to a lender's underwriting and approval.

What is strategic leverage for an operator?

Using lender capital, repaid once from the well's own cash flow, in place of investor capital that takes a permanent share of production. It enhances returns because the operator keeps the well, and it reduces risk to the program because each well kept adds proved production to borrow against with fewer investor obligations to carry. The loan remains an obligation that must be repaid whether or not the well produces, so it has to fit the program's cash flow.

Does keeping the well change the tax treatment?

The deductions for intangible drilling costs and depletion follow the working interest, so an operator who keeps the whole well keeps the deductions a promote would have passed to investors, and interest paid is generally deductible. Eligibility, limits and timing depend on the operator's circumstances and current law; confirm with your CPA.

Can an operator use both a lender and investors?

Yes, and many do. A facility sized to what the lender will advance, with a smaller raise on selected wells, keeps far more of the program than a promote on every well. The mix depends on existing production, the lender's advance rate and how much of the program the operator wants to share.

This article is general education, not legal, tax, or investment advice, and nothing in it is an offer to lend, an offer or solicitation to buy any interest in any venture, or a commitment of any kind. The well example is hypothetical and illustrative only; actual results vary widely and may be materially lower, and borrowed funds must be repaid regardless of well performance. MercConsulting does not lend and does not sell interests; it coordinates diligence, structuring, capital placement and tax questions with licensed securities attorneys, CPAs, lenders and other professionals where the work requires it.