A complete framework for evaluating an unconventional oil well — from the cost stack through full-cycle returns

Why “well cost” is the wrong question

The headline cost of an oil well is the drilling and completion (D&C) invoice, and it is almost always the largest single check an operator writes to put a well on production. But the D&C number answers only the narrowest question — how much it costs to build the well — and says very little about whether the well is worth building. A complete economic evaluation must carry the analysis from the first land and permitting dollar through facilities, royalties, production taxes, operating costs, decline, abandonment, and the cost of capital.

For a modern U.S. horizontal shale well, three variables dominate the outcome:

• Estimated ultimate recovery (EUR) — how much the well will produce over its life.
• Realized price — what the operator actually nets after differentials, not the benchmark headline.
• Capital efficiency — usually expressed as dollars per lateral foot or dollars per barrel of oil equivalent (BOE).

Everything else in the model is a refinement of those three.

This article walks through the full cost stack and the economic framework that turns it into a go/no-go decision, using a representative 10,000-ft Permian-type oil well as a worked example. The numbers are illustrative; the structure is meant to travel to any basin, lateral length, or working-interest position.

On cost, the market is currently sending two signals at once. The most efficient operators have pushed D&C costs to remarkable lows — Permian Resources, among the lowest-cost operators in the basin, reported D&C costs of roughly $685 per lateral foot in Q1 2026, down from about $700 in late 2025. The same company notes peer averages running from $775 to north of $1,000 per foot, so those best-in-class figures are a floor, not a typical number. At the same time, after roughly two years of efficiency-driven cost deflation, service costs turned higher in 2026: the Dallas Fed’s Q2 2026 Energy Survey showed its input-cost index for oilfield-service firms jumping from 34.9 to 64.4, with companion increases in finding-and-development costs and lease operating expenses. Any 2026 economic model should treat service-cost inflation as a live variable rather than a settled one.

The cost stack: from pre-drill to first oil

A well’s total cost divides into three buckets: capital costs (everything spent to build the well and bring it online), operating costs (everything spent to keep it producing), and fiscal burdens (royalties and taxes). The capital stack itself builds in roughly this order.

Pre-drill. Mineral leasing and bonus payments, title work, geological and geophysical (G&G) evaluation, permitting and regulatory filings, and location construction — pad, roads, containment, and power prep. Leasing and G&G are often excluded from the quoted “well cost” but belong in full-cycle economics.

Drilling. The rig and crew (day rate), fuel and power, drilling fluids, bits and downhole tools (PDC bits, mud motors, rotary steerable systems, MWD/LWD), directional and geosteering services, casing strings (surface, intermediate, production), cementing, formation evaluation, solids control and waste handling, and well control.

Completion. Typically, the single largest line item on an unconventional well: perforating, hydraulic fracturing (pumping horsepower, crews, and chemicals), proppant, water sourcing and handling, frac plugs and drill-out, flowback, production tubing, and the artificial-lift system (ESP, gas lift, rod pump, or plunger lift). Completion design is the dominant driver of cost variability between otherwise similar wells.

Facilities and tie-in. Tank battery, separation, custody-transfer metering (LACT), flowlines, gas-gathering connection, electrical compression where needed, and SCADA. Modest for a single well; material for a multi-well pad — and not to be ignored in full-cycle math.

Four cost definitions that are easy to confuse

Precision about what a cost number includes is half the battle in well economics. Four terms get used loosely and mean very different things.

Term	Includes	Excludes
Drilling cost	Rig, casing, cement, mud, directional services	Frac, facilities, operations
Completion cost	Frac, perforating, plugs, flowback, tubing	Drilling, land, ongoing OPEX
D&C cost	Drilling + completion	Facilities, land, taxes, LOE
Completed-well cost	D&C + artificial lift + facilities + tie-in	Usually land and corporate overhead
Full-cycle cost	Land + G&G + D&C + facilities + OPEX + taxes + abandonment + return on capital	Nothing material

The practical point: D&C cost measures capital efficiency; full-cycle cost measures whether the project creates value. An operator can lead the basin on D&C cost per foot and still drill uneconomic wells if EUR, differentials, or operating costs are wrong.

What a well costs

The table below frames a realistic range for a single U.S. horizontal oil well. The low and high columns bracket favorable and adverse cost outcomes; the base column is a reasonable all-in, completed-well figure once every category is counted.

Cost category	Low case	Base case	High case
Pre-drill / permitting / location	$0.3 MM	$0.7 MM	$1.5 MM
Drilling	$2.5 MM	$3.5 MM	$5.0 MM
Completion	$3.5 MM	$4.5 MM	$7.0 MM
Facilities / tie-in	$0.5 MM	$1.0 MM	$2.0 MM
Artificial lift / startup	$0.2 MM	$0.4 MM	$0.8 MM
Contingency	$0.5 MM	$0.8 MM	$1.5 MM
Total well cost	$7.5 MM	$10.9 MM	$17.8 MM

For a 10,000-ft lateral, best-in-class D&C of $685–$700/ft implies roughly $6.9–$7.0 million for D&C alone — before facilities, land, overhead, and contingency. On a fully loaded, completed-well basis, most single wells land at or above the base column, which is why D&C cost per foot, while the cleanest execution metric, understates what it actually takes to bring a well online.

Building the economic model

A complete well model runs in eight steps.

Step 1 — Estimate capital.

Total initial capital = land + G&G + permitting + drilling + completion + facilities + artificial lift + contingency

Step 2 — Forecast production. Forecast oil (bbl), gas (Mcf), NGL (bbl), and produced water (bbl) by period. Common decline methods include Arps hyperbolic, modified hyperbolic, exponential-tail, type-curve matching, and reservoir simulation. The production shape — not just the total — drives the economics, because early barrels are worth far more than late ones.

Step 3 — Estimate revenue.

Gross revenue = (oil × realized oil price) + (gas × realized gas price) + (NGL × realized NGL price)

Realized prices must reflect differentials:

Realized oil price = WTI − oil differential

Realized gas price = Henry Hub − basin differential

Step 4 — Deduct royalties and production taxes.

Net revenue interest = working interest × (1 − royalty burden)

Production (severance) taxes apply to taxable revenue, either on gross wellhead value or post-royalty, depending on jurisdiction.

Step 5 — Deduct operating expenses. Lease operating expense (LOE), water handling, gathering/processing/transportation (GPT), workovers, chemicals, power, allocated G&A, artificial-lift maintenance, and insurance/ad valorem tax. State explicitly whether per-BOE operating costs are carried on a gross (8/8ths) or net-revenue-interest basis — the choice materially changes the result.

Step 6 — Calculate cash flow.

Net cash flow = revenue − royalties − production taxes − LOE − GPT − workovers − G&A − sustaining capital

Step 7 — Discount the cash flow.

NPV = Σ [ cash flow_t ÷ (1 + r) ^t] − initial capital

Typical screening rates: 8% for a lower-risk corporate case, 10% as the standard upstream screening rate, and 15%+ for higher-risk private capital, wildcat, or marginal acreage.

Step 8 — Calculate economic indicators. NPV10, IRR, payout, profitability index (NPV ÷ capital), capital cost per BOE (a simple F&D-style metric), operating netback, and breakeven price (the commodity price at which NPV = 0).

A worked base case

The following simplified model is a 10,000-ft horizontal oil well. Commodity prices are stated as illustrative assumptions — at the time of an actual evaluation, substitute current forward (strip) prices and basin-specific differentials.

Assumption	Value
D&C cost	$8.5 MM
Facilities / tie-in / startup	$1.0 MM
Total initial capital	$9.5 MM
EUR	1.2 MMBOE
Oil / NGL / gas mix	70% / 15% / 15% (BOE)
WTI price (assumption)	$84.67 / bbl
Oil differential	−$2 / bbl
Gas price (assumption)	$2.80 / MMBtu
Gas differential	−$0.75 / Mcf
NGL price	$24 / bbl
Royalty	25%
Production tax	7.5%
LOE	$8 / BOE
GPT (gathering / processing / transport)	$3 / BOE
G&A	$1.50 / BOE
Discount rate	10%
Economic life	20 years

Result

Metric	Result
Initial capital	$9.5 MM
Capital cost per BOE	$7.92 / BOE
NPV10	~$14.1 MM
IRR	~47%
Payout	~1.5 years
WTI NPV10 breakeven	~$46 / bbl

Two cautions on reading these outputs. First, they describe a deliberately strong, Tier 1, oil-weighted well at 1.2 MMBOE — not a basin average. Drop the EUR, raise the cost, widen the gas differential, or let the water cut climb, and the economics deteriorate quickly. Second, IRR, payout, and breakeven are highly sensitive to the shape of the production forecast; a flatter type curve or a slower first-year ramp moves all three. Treat the figures as what a representative type curve produces under these inputs, not as precise constants.

Sensitivity analysis

Sensitivity to oil price

WTI price	Economic impact
$50 / bbl	Marginal to moderate, depending on EUR and cost
$60 / bbl	Often workable for high-quality inventory
$70 / bbl	Solid payout and NPV
$80 / bbl	Attractive for Tier 1 oil-weighted wells
$90+ / bbl	Strong returns — though sustained high prices tend to pull service costs up with them

Because commodity prices move constantly, run the model on current forward prices at the time of evaluation; the table shows the shape of price sensitivity, not a forecast.

Sensitivity to D&C cost

D&C cost change	Impact
−10%	Improves NPV, lowers breakeven
Base case	Normal development case
+10%	Can materially reduce IRR
+20%	May push marginal wells below the investment threshold

This is especially relevant in 2026: after two years of falling costs, the Dallas Fed’s Q2 2026 survey showed service input costs, finding-and-development costs, and lease operating expenses all rising. Cost inflation has re-emerged as a swing factor in well returns.

Sensitivity to EUR

EUR outcome	Economic interpretation
0.6 MMBOE	Marginal unless costs are low or prices are high
0.8 MMBOE	Moderate economics
1.0 MMBOE	Good well if capital cost is controlled
1.2+ MMBOE	Strong Tier 1 inventory
1.5+ MMBOE	Exceptional, assuming no major parent-child degradation

EUR is usually the single most important variable, because it drives both revenue and capital cost per barrel.

Expressing economic cost per barrel

There are several complementary ways to state a well’s economic cost.

Capital cost per BOE (simple F&D metric):

$9.5 MM ÷ 1.2 MMBOE = $7.92 / BOE

Cash operating cost:

LOE + GPT + G&A = $8 + $3 + $1.50 = $12.50 / BOE (before production taxes)

Full-cycle breakeven layers in capital recovery, royalties, production taxes, LOE, transportation, G&A, abandonment, and a required return on capital.

The key distinction: a well can show a D&C cost under $10/BOE and still carry a full-cycle breakeven of $40–$60/bbl once royalties, taxes, operating costs, differentials, and a required return are included. The gap between those two numbers is exactly why D&C cost per foot — the headline figure — is not the same thing as economic viability.

Key risks in well economics

Risk	Economic effect
Cost inflation	Higher D&C cost, lower IRR
Lower EUR	Higher cost per barrel, lower NPV
Parent-child interference	Reduced productivity in infill wells
Gas takeaway constraints	Wider gas differentials
Water-cut growth	Higher LOE
Service availability	Higher completion cost, longer cycle time
Commodity price volatility	Revenue uncertainty
Regulatory change	Permitting delays or compliance cost
Mechanical failure	Workover cost and deferred production
Abandonment liability	End-of-life cash outflow

 

The bottom line

A well should not be judged on drilling and completion cost alone. The right question is not, “How much does it cost to drill and complete the well?” It is:

After paying drilling, completion, facilities, royalties, taxes, operating cost, transportation, overhead, and capital recovery, does the well earn an acceptable risk-adjusted return?

For U.S. shale, D&C cost remains the largest controllable capital item and the cleanest measure of execution — but full-cycle performance depends just as much on well productivity, decline behavior, realized pricing, and operating discipline. In 2026, it depends on one more thing that had faded into the background: service-cost inflation, which has re-emerged as a swing factor after two years of falling costs. Operators and investors who track only the per-foot D&C number will miss half of what determines whether a well actually makes money.

Sources

• Permian Resources Corp., Q1 2026 and Q4 2025 results — drilling and completion cost per lateral foot.
  https://permianres.com/permian-resources-announces-strong-first-quarter-2026-results-and-increased-full-year-guidance/
  https://permianres.com/permian-resources-announces-strong-fourth-quarter-2025-results-and-provides-full-year-2026-plan-with-improved-capital-efficiency-and-increased-base-dividend/
• Federal Reserve Bank of Dallas, Dallas Fed Energy Survey, Q2 2026 — oilfield-service cost diffusion indexes.
  https://www.dallasfed.org/research/surveys/des/2026/2602
• U.S. Energy Information Administration, Short-Term Energy Outlook and Drilling Productivity Report — price and new-well productivity context.
  https://www.eia.gov/outlooks/steo/report/natgas.php
  https://www.eia.gov/petroleum/drilling/

Contributors

Ajay Gundlapalli’s reflections

One specific thing I learned is that the rig isn’t the primary driver of well cost. A 10,000-foot horizontal well needs all the equipment, material, and labor to drill vertically and turn into a lateral. Before any completion even starts, the operator must pay for directional drilling, casing, cement, mud, bits, crews, supervision, etc. Then, after drilling, the well is completed with frac, water, sand, perforating, flowback, and artificial lift. And that’s before the operator even pays to build separators, tank batteries, flowlines, metering, electrical, and prepare the site. The base case is that the drilling is $3.5 million, the completion is $4.5 million, and the total completed-well cost is about $10.9 million. Why are horizontal wells so expensive? It’s the specialized equipment and work involved in drilling vertically, then turning to go several thousand feet horizontally inside a rock layer that’s full of oil. But if you drill horizontal wells, you touch much more of the reservoir, and you’ll likely produce much more oil and gas as a result. The cost of these added steps can be justified as such.

Finally, one thing that surprised me the most was that even though everything engineers work on might go right, the operator still won’t drill the well if they think the expected production wouldn’t pay back its initial investment and leave an acceptable return after royalties, production taxes, operating expenditures, deductions for transportation costs, and future abandonment expenses. Production isn’t constant; while a shale well may have a high initial output, it will decrease rapidly. This means that not just the amount of oil produced matters; it’s when the oil is produced, too. Oil and gas commodity prices may vary during the life of the well, and service prices may increase as operators increase the number of wells being drilled. Therefore, they evaluate factors such as estimated ultimate recovery, realized commodity price, NPV, IRR, payout time, and breakeven price to determine which wells they should drill. I was under the impression that operators were looking primarily at how much oil was in the ground; however, it seems they’re trying to determine whether they can drill it cheaply and quickly enough to earn a risk-adjusted return on investment.

Piya Reddy’s reflections

During my journey of learning about building an oil well, I learned a great deal about the specific costs that go into it. I was interested to learn

that the completion stage, which includes hydraulic fracturing, installing production tubing, and setting up artificial lift systems, is often the most expensive part of the project. I also learned that the quoted “well cost” usually leaves out expenses such as leasing land and geophysical evaluation.

What surprised me most was how much economics dictates whether a well gets drilled. I learned that companies must consider expected production, oil prices, operating costs, taxes, and whether the project will earn a satisfactory return on investment. A well can often be possible to drill but not worth it. This has shown me that in oil production, the business decisions are just as important as engineering decisions.