How to Value an Oil Well

The core equation

For each month of the well's remaining life:

Add up every monthly cash flow across the remaining life, discount future dollars back to today, and compare the result to what you have to pay to get in. Four numbers carry the decision:

A well can show positive undiscounted profit and still be a bad deal if the cash arrives too slowly. That is why NPV and IRR matter more than a single monthly number.

1. Start with ownership

You cannot model profitability until you know exactly what percentage you own and what burdens sit ahead of you.

• Working interest (WI): your share of costs and operating responsibility — capex, LOE, workovers, plugging.
• Royalty burdens: landowner royalty, ORRI and NPRI receive revenue but normally pay no operating cost.
• Net revenue interest (NRI): your share of revenue after those burdens.

Buy 25% WI in a lease carrying a 25% combined burden and you hold 18.75% NRI. You pay a quarter of the costs and receive less than a fifth of the revenue. First underwriting rule: never assume WI equals NRI. Every listing on the Heartland marketplace requires both, plus the percentage of ownership actually being conveyed.

2. Forecast future production

Production is the engine of the model. You need monthly oil, gas, NGL and water volumes from the acquisition date until economic limit. For an existing producer, start with actual history — 24 to 60 months — including downtime, shut-ins, compression constraints, disposal issues and mechanical history. Then fit a decline curve and sanity check it against analog wells.

Decline curve styles

• Exponential: a constant percentage decline; the workhorse for mature conventional wells.
• Hyperbolic: steep early decline that flattens; typical for unconventional wells.
• Harmonic: a very slow flattening decline — usually too optimistic unless the data strongly supports it.

EUR (estimated ultimate recovery) is observed production plus the forecast tail. For a stripper or conventional lease the question is rarely “how big was the IP?” — it is what is the sustainable base decline, and at what rate does this lease go cash-flow negative?

3. Convert volumes into realized revenue

Do not treat headline WTI or Henry Hub as your revenue. Model the price at the wellhead.

A $70 WTI environment may net only $63/bbl after a $4 basis differential and $3/bbl of trucking and marketing. Gas needs its own treatment: local index, basin basis, gathering and compression, processing fees, fuel shrink, and the residue/liquids split. If NGLs already sit inside your processor settlement, do not count them twice. Our regional price calculator carries Texas, Oklahoma and Kansas netbacks so you are not guessing at basis.

4. Deduct the costs

Lease operating expense

Pumper labor, electricity and fuel, chemical, routine maintenance, well servicing, tank battery upkeep, compression, saltwater hauling and disposal, compliance, insurance, SCADA and telemetry, and lease road and site maintenance.

That split matters. When production falls, the fixed piece stays — which is why old wells hit economic limit sooner than a simple per-barrel cost suggests. This is also where continuous monitoring pays: our predictive maintenance stack exists to keep the fixed cost of a downed well from eating the margin.

Production taxes

State oil and gas severance, conservation and regulatory assessments, ad valorem property tax, and local levies. Each has its own tax base — gross value, net taxable value, exemptions and reduced rates differ materially between Kansas, Oklahoma and Texas.

Revenue deductions

Crude hauling, pipeline tariff, gathering, compression, treating and processing, marketing fees, fuel loss, quality penalties, BS&W and purchaser charges. Use actual check-stub deductions. Realized revenue per barrel over the last 6–12 months beats any generic market assumption.

Capital expenditures

Capex is not monthly cost — it is money spent to acquire, repair, upgrade or extend the well: purchase price and closing costs, title curative, facilities and hookup, artificial lift, workovers and recompletions, rod/tubing/pump replacements, water-handling upgrades, compressor replacement, casing and corrosion repair, remediation, plugging and abandonment, and surface restoration. For an acquisition, build a known capex list from operator records plus a separate contingency reserve.

5. Account for timing

Then run monthly: revenue at your NRI, less your share of LOE, capex and workovers, less taxes and deductions. Use cash timing, not production timing. January production may pay in March. JIBs trail operations. A large repair bill often lands before the production benefit. The purchase price is due immediately, and the plugging bill arrives at the end when revenue is lowest.

6. Economic limit and plugging liability

The practical decision compares two paths: keep producing and earn future net operating cash, or shut in and pay the P&A obligation. A marginally positive well can still be a poor asset if it carries heavy failure exposure and a real plugging bill. Include expected P&A cost, probability-weighted early failure, surface remediation, tank and flowline removal, disposal and reclamation, bonding, and any realistic salvage value. Treat P&A as a genuine future negative cash flow — never leave it off because it is years away.

7. Discount future cash flows

A dollar today is worth more than a dollar in five years. Cash flow at t = 0 is normally negative because that is the acquisition. Your discount rate should track deal risk: steady PDP production warrants a lower hurdle than a development bet; single-well concentration, high water cut, unstable differentials, weak operator performance or uncertain title justify a higher one. PV-10 is the common reference, but the right rate is your required return.

A simple worked example

You acquire 100% WI in a conventional oil well with 75% NRI after burdens. Month one:

• 300 bbl sold at a realized $60/bbl = $18,000 gross oil revenue
• Gas and NGL revenue: $1,500 — total gross $19,500
• At 75% NRI your revenue is $14,625
• Less LOE $7,000, production taxes and deductions $1,300, routine capex $500

That tells you what the well made — not whether the acquisition is good. If you paid $120,000 and remaining undiscounted cash flow is $135,000, a likely $25,000 workover and $20,000 plugging cost turn an apparently profitable well into a losing deal.

The inputs that matter most

• Actual production and decline rate — a 10% difference in remaining volume can dominate the answer.
• Realized commodity price — deck, basis, transport, quality and purchaser deductions.
• NRI and title burden — royalty, ORRI, NPRI, non-consent penalties and back-in rights.
• Fixed LOE and water handling — decisive on older Kansas, Oklahoma and Texas conventional wells.
• Workover probability and cost — pumps, rods, tubing, scale, corrosion, casing, SWD.
• P&A obligation — a debt-like liability embedded in the asset.
• Purchase price and deal structure — effective date, adjustments, retained liabilities, indemnities.

Stress-test the deal

Never underwrite one forecast. Build three cases:

For a mature acquisition, bid on whether the downside case avoids a material loss while the base case still clears your NPV and payout requirements. Our cash flow simulator runs thousands of randomized price paths so you see the full band instead of three hand-built cases.

Due diligence checklist

• 24–60 months of monthly production by commodity
• Oil and gas purchaser statements and check stubs
• JIBs, LOE detail, AP ledger and vendor costs
• Current working interest and NRI decks
• Lease, assignment, royalty and title documents
• Tax bills and severance tax history
• Well files, workover history, pulling tickets and failure history
• Artificial lift configuration plus power and fuel costs
• Water volumes, disposal source, contract price and capacity
• P&A estimate and bond or surety requirements
• Environmental reports, spills, remediation and surface obligations
• Operating agreement, non-op rights and future capital obligations
• Shut-in, curtailment, line-pressure or purchaser constraints

The cleanest practical approach is a monthly 5–15 year cash-flow model with separate inputs for production, pricing, ownership, LOE, capex and workovers, taxes, P&A and sensitivities. For a mature well you can run the forecast only to economic limit — but still carry the plugging liability as a discounted negative cash flow.

Run it against a real package

Every concept above is wired into the Heartland tools. Start with a listing on the marketplace, or type in your own numbers:

Go deeper on two things

Two pieces of this guide carry most of the weight in a valuation and deserve their own pages:

Educational content only. Not investment, tax, legal or engineering advice. Verify every assumption against your own records and advisors.