How small oil wells actually make money — and where seller pitches quietly inflate the price

You're offered a small oil well in West Texas for $738,000. The seller hands you a tidy monthly P&L: $30,283 in revenue, $20,507 in profit, and a three-year payback that supposedly settles the math. Should you write the check?

If you've never underwritten an oil well, the answer isn't obvious. The pitch sounds clean. The numbers add up at a glance. But oil well economics have five distinct layers between a barrel of crude and an operator's bank account — and at least three things that almost never make it into a seller's spreadsheet but materially change what the well is worth.

This post walks through both. We'll use a real, modest well in Schleicher County, Texas as the case study: 22 barrels a day, vertical, classic pumpjack. By the end you'll know how to read any small-operator oil P&L line by line, and exactly where the most expensive omissions tend to hide.

Step 1 — How much oil does the well produce?

The case-study well produced 673 barrels of oil in its most recent reported month.

A barrel is 42 US gallons. So 673 barrels is about 28,266 gallons of crude — enough to fill roughly five large fuel-tanker trailers. Spread across 31 days, that's ~21.7 barrels per day; about 22 in round numbers.

In the oil industry, 22 bbl/d is small. Brand-new horizontal shale wells in the Permian can do 1,000+ barrels per day. A 22-bbl/d well is what gets called "low-volume conventional" — and just above what's officially classified as a "stripper well." (The IRS and Texas Comptroller threshold is ≤15 bbl/d averaged over twelve months.)

This single number — 673 barrels — drives every other line of the P&L. Hold it.

Step 2 — Who else owns a piece of every barrel?

In the United States, the company drilling the well and the person who owns the minerals beneath the surface are usually two different parties. The operator signs an oil and gas lease with the mineral rights owner, agreeing to a percentage cut of whatever gets produced.

That cut is called the royalty. It comes off the top, before any other deduction, tax, or cost.

On this well, the royalty is 15%. So for every $100 of crude pumped to surface, the mineral owner is owed $15. The operator keeps the other 85% — and bears 100% of the costs.

For context: most modern Texas leases pay royalties of 18.75% to 25%. A 15% royalty is on the low end and usually means one of two things — either the lease is decades old (signed when 12.5% was the standard), or the mineral owner accepted a lower royalty in exchange for a larger upfront signing bonus.

The operator's 85% is called the working interest. The arithmetic for what they actually earn:

Operator's revenue share = 85% × gross revenue

On this well, the operator's net revenue (their 85% share) is $30,283. From that we can work backwards to gross revenue and an implied wellhead price per barrel:

$30,283 ÷ 85%  = $35,627 gross revenue
$35,627 ÷ 673  = $52.94 per barrel

That $52.94/bbl is the price the operator effectively realized at the wellhead. WTI Midland (the regional benchmark) is around $91/bbl as of late May 2026, so there's a meaningful gap. A handful of things could explain it: the reporting period is from a lower-price era, the crude is heavier and sells at a discount, trucking deductions are eating into the realized price, or all three. Either way, the $52.94 is what's actually on the check — so that's what we work with.

After the mineral owner is paid:

Gross revenue:                         $35,627
Mineral owner's 15%:                  – $5,344
─────────────────────────────────────────────
Operator's net revenue:                $30,283  ← what the operator works with

Step 3 — What does the state take?

Next deduction: state severance tax. It's called "severance" because the state is taxing you for "severing" the resource from the land. In Texas the rate is 4.6% on the market value of crude oil. Natural gas, which is often co-produced from the same wellbore, is taxed separately at 7.5%.

For this well, severance comes in just under $3,000 for the month.

If you do the pure-oil math, the number should look like:

$35,627 × 4.6% = $1,639

So where's the extra $1,361 coming from? In a real-world P&L it almost always reflects two things at once: (1) the well co-produces a small amount of natural gas (these are properly called "oil and gas wells" for a reason) which carries the higher 7.5% rate, and (2) the line item bundles in the Texas Regulatory Fee. The composite roughly reconciles, even when the per-product breakdown isn't shown.

One worth-knowing nuance: Texas does still have a Low-Producing Oil Lease tax credit on the books, but it's price-triggered. The credit only activates when the state's average taxable price drops below $30/bbl (in 2005 dollars). With January 2026's average taxable price at $35.23/bbl (per Texas Comptroller), the credit is currently inactive. The last sustained period it triggered was 2014–2016, when prices crashed.

Step 4 — What does it cost to keep the well running?

Lease Operating Expenses — usually abbreviated LOE — is the monthly cash cost of keeping a producing well producing. It excludes the cost of drilling the well in the first place (that's a separate, much larger one-time capital expense), and excludes royalties and taxes.

For this well, LOE runs $5,800 a month. The bucket usually includes:

What's not in this $5,800: workovers. A workover is what happens when something major breaks downhole — the steel sucker rod that drives the pump snaps, or the production tubing develops a hole. When that happens, a workover rig (think small mobile drilling rig) is brought in to pull everything out of the well and replace it. That runs $20,000 to $100,000 per event and happens every two to four years for a typical vertical rod-pumped well like this one.

Workovers are conventionally treated as capital expense, not LOE. That bookkeeping convention is technically correct — and also where buyers get burned. We'll come back to it.

Step 5 — What's the monthly profit?

Add up the layers:

Operator's net revenue (after royalty):     $30,283
  – Severance tax + state fees:            ~$3,000
  – Other deductions (trucking, etc.):     ~$976
  – Lease Operating Expenses (LOE):         $5,800
                                          ─────────
  Net Operating Income (NOI):              $20,507

That's the well's monthly profit — what's left after the mineral owner, the state, and the operating costs are all paid. $20,507 a month.

Quick note on the $976 line: a lot of small-operator P&Ls bundle gathering and trucking costs into LOE without breaking them out. For reference: pipeline gathering in the Permian runs $0.25–$1.50 per barrel; trucking runs $2–$5 per barrel because it's more labor-intensive. A 673-barrel month trucked at ~$3/bbl is around $2,000 — which is broadly where the missing line item usually lives, whether shown on its own or absorbed elsewhere.

Step 6 — How is that worth $738,000?

Valuation in the small-operator world tends to use a simple cash-flow multiple: how many months of current profit are you willing to pay upfront to own the well?

The common Texas heuristic is anywhere from 18 to 36 months of NOI. For this well, the seller's pricing rule is 36 months — three years — of cash flow:

$20,507/month × 36 months = $738,252

That's where the $738,000 figure comes from. Different buyers use different multiples for the same well, with very different implications:

• 18 months — aggressive buyer, expecting trouble or rapid decline. Would pay ~$369K.
• 24 months — typical conservative buyer's view. Would pay ~$492K.
• 36 months — the seller's quote here. Pays ~$738K. Seller-favorable.

The 36-month rule looks clean. But it embeds an assumption that's worth pulling apart.

The math is right. So why is the price wrong?

The walkthrough above is structurally correct. Any oil and gas accountant would build the P&L in the same five steps in the same order. The numbers in each line — gross, royalty, severance, LOE, NOI — are honest individually.

But three things are missing from this kind of pitch P&L almost universally — and they all move the implied value in the same direction. They're the difference between the seller's $738K and what a defensible buyer should actually pay.

Omission #1 — Oil wells decline. Always.

An oil well is not a subscription business. The reservoir pressure depletes, water cut rises, and production drops every year — predictably, modeled by a decline curve. For a conventional vertical well in the Permian, the typical decline is 5–10% per year, settling into a terminal decline of around 6.5%.

The 36-month multiple, applied flat, pretends the well produces 22 bbl/d for the entire three years. It won't.

At a 7% annual decline, here's what actually happens over three years (NOI scaling with production):

The flat $738,252 overstates the actual three-year cash flow by about $50,000 — a 7% haircut just from acknowledging physics. At a steeper 15% decline (closer to what some over-pressured Permian verticals see), the three-year sum drops to about $633,000 — a $105K haircut.

(Method note: this assumes NOI scales linearly with production. That's actually conservative — in reality, LOE is mostly fixed, so a 7% drop in production produces a larger-than-7% drop in NOI. The numbers above are friendly to the seller.)

Omission #2 — Workovers happen, and they're expensive

Recall that workover costs aren't in LOE. They happen anyway — typically every two to four years on a vertical rod-pumped well, at $20K–$100K per event.

A reasonable middle-of-range estimate: $50,000 workover every 3 years. Spread over 36 months, that's about $1,400 a month of real cost the LOE line never showed.

If you bake a workover reserve into NOI, the well isn't really making $20,507 a month — it's making more like $19,100. Apply the 36-month rule to that, and acquisition value drops by another $50K.

Omission #3 — When the well dies, you have to plug it

Texas and federal law require that when a well permanently stops producing, the operator must plug and abandon it — fill the wellbore with cement, remove the surface equipment, and restore the surface. This is called P&A liability.

For a typical Texas vertical well, P&A runs $25,000 to $75,000.

The previous owner could have done it but didn't — when you buy the well, you inherit the debt. Smart buyers treat P&A as a liability that carves down acquisition value, not as a future cost to be ignored.

The buyer's real underwriting math

Putting all three omissions together, here's what a careful buyer should pay:

That's a 25% gap between what the seller asks and what the math supports — on the same well, with the same production, the same costs, the same everything. The gap is entirely a question of framing.

A more conservative buyer using 24 months (rather than 36) net of those reserves lands closer to $370,000 — about 50% of the original quote:

24 months of NOI with 7% decline:    $474,942
  – Workover reserve (2/3 share):    –$33,333
  – P&A reserve:                     –$50,000
  – G&A overhead (3% × 24 mo):       –$21,804
                                    ─────────
Conservative buyer value:            $369,805

None of this means a seller offering at $738K is dishonest. They're doing what every seller in every industry does: anchoring the conversation at the most favorable defensible number. The buyer's job is to walk that number back to something that survives reality.

A few terms worth knowing

Stripper well

The legal threshold is ≤15 bbl/d averaged over twelve months. This case-study well at ~22 bbl/d is just above that line — officially a "low-volume conventional vertical," not a stripper. The distinction matters because federal depletion-percentage deductions and some state regulatory treatments differ between the two classifications. National context: the average US stripper well produces only ~1.8 bbl/d (per IOGCC's survey of 409,000+ wells), so a 22-bbl/d Permian well is comparatively rich for its class.

Central tank battery

A facility where crude from multiple nearby wells is separated (oil from water from gas), measured, and stored in 1,000-bbl steel tanks before being trucked or piped to market. Low-volume wells that don't justify a dedicated gathering pipeline get trucked instead — which costs significantly more per barrel and gets bundled into LOE without being broken out.

Pumpjack failure modes

The pumpjack drives a long steel sucker rod up and down inside the well's tubing — picture a long, thin pipe going down thousands of feet. At the bottom, a downhole plunger pump lifts the oil up. The two most common ways this stops working: (1) the sucker rod snaps from fatigue or corrosion ("rod parts"), or (2) the tubing develops a leak ("hole in tubing"). Both require a workover rig to pull the rods and tubing and replace them — the failure modes that drive Omission #2 above.

The takeaway

Oil well economics aren't complicated. There are five layers between a barrel of crude and the operator's bank account — production, royalty, severance, LOE, NOI — and one final step that turns monthly NOI into asset value via a cash-flow multiple. Any small-operator P&L can be read in those terms.

The trap is the multiple. Sellers anchor on 36 months because it gives the highest defensible number. Buyers should anchor on 24 months net of three specific reserves — decline-adjusted cash flow, amortized workovers, and end-of-life plugging — because those are the things that show up in reality but rarely on a pitch P&L.

Run those adjustments on any small-well acquisition and the seller's quoted price typically turns out to be 25–50% above what the math supports. That isn't deception. It's standard seller-side framing — the same dynamic that shows up in any small business sale. The buyer's job is to add the missing layers back before signing.

The math is honest. The sequence is right. The omissions are systematic.

Sources

• Texas Comptroller — Crude Oil Production Tax (4.6% rate)
• Texas Comptroller — Low-Producing Oil Lease Tax Credit (price triggers)
• Texas Comptroller — Natural Gas Production Tax
• RRC Texas — Permian Basin Overview
• RRC Texas — Severance Tax Incentives
• Stripper Well — Wikipedia
• National Stripper Well Association
• Baker Tilly — Marginal & Stripper Wells: Tax Breaks
• Kingdom Exploration — Oil Well Decline Curve & Investment Returns
• Greasebook — Decline Curve Analysis Guide
• Payne Institute (Colorado School of Mines) — Terminal Decline Rates
• Oilprice.com — WTI Midland Futures
• RBN Energy — Understanding Lease Operating Expenses

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