Lease operating expense (LOE) is the recurring, production-phase cost to operate producing wells, often called the lifting or production cost, and the figure professionals should track above all others is LOE per barrel of oil equivalent (BOE). LOE sits apart from drilling and completion capital, and recent EIA data put average production expenses near $26 per BOE after the 2021-2022 inflation spike eased.
TL;DR:
- Keep drilling and completion capital, gathering and transport, royalties, and taxes outside LOE, and use the same denominator, such as BOE or Mcf, for comparisons.
- Classify repairs that restore prior operating condition as expenses, capitalize work that adds capability or extends asset life, and retain dated work orders as support.
- BCG found a $5 to $8 per BOE gap between quartiles within Permian geology; adjust for well age, lift method, and water costs.
- Report field LOE monthly, reconcile totals quarterly, and use a rolling twelve month view while checking denominator consistency and workover reclassifications.
- Pilot cost reductions on a small group of wells, track production alongside savings, and scale only after both remain steady for a full quarter.
Table of Contents
- What lease operating expenses include and why precise scope matters
- Typical LOE component categories and sample line items
- How to structure a lease operating statement for clean reconciliation
- Distinguishing operating expense from capital costs
- What drives LOE and how to benchmark it correctly
- Operational levers that actually reduce LOE
- The KPIs and reporting cadence that keep LOE under control
- What I’d tell any operator chasing a lower LOE number
- Where investors can review operator economics alongside LOE
- FAQ
- Sources
What lease operating expenses include and why precise scope matters
LOE covers the recurring costs of keeping a producing well flowing: labor, chemicals, power, water handling, workovers and the routine upkeep that production depends on. It excludes the capital spent to drill or complete a well, which falls under CapEx, and it excludes gathering and transportation fees, royalty payments and production or ad valorem taxes, all of which appear as separate line items on a lease operating statement.
Mixing these categories together is the single most common reason two companies’ LOE figures look incomparable. An operator that buries workover costs inside LOE will report a higher number than one that capitalizes the same spending, even on identical wells.
Getting the scope right matters just as much as getting the number right:
- LOE covers routine labor, chemicals, power, water handling, and workovers tied to keeping wells producing.
- CapEx covers drilling, completions, and major equipment installs, not routine operation.
- Gathering, transportation, royalties, and production taxes sit outside LOE as their own reporting lines.
- The denominator (BOE, Mcf, or well-month) must stay consistent across any comparison or the ratio becomes meaningless.
Choosing a denominator depends on the asset mix. Oil-weighted leases typically normalize to BOE, gas-weighted leases often use Mcf, and leases with highly variable well counts benefit from a well-month basis that smooths out timing effects from new connections or temporary shut-ins.
Typical LOE component categories and sample line items
A lease operating statement breaks LOE into granular line items, and operators who track them separately spot cost drivers faster than those who report a single lump sum. The categories below cover most of what shows up on a monthly field schedule.
- Labor: pumper and field technician wages, including overtime for unscheduled call-outs.
- Fuel and power: electricity or natural gas consumed by pumps, compressors, and heaters.
- Chemicals: corrosion inhibitors, scale treatment, and paraffin control.
- Water handling and disposal: trucking, pipeline disposal fees, and saltwater disposal well costs.
- Workovers: well interventions to restore or improve production, distinct from a full re-completion.
- Artificial lift costs: rod pump, gas lift, or electric submersible pump maintenance and replacement parts.
- Trucking and logistics: hauling fluids, equipment, and personnel to remote lease sites.
- Surface maintenance: tank, separator, and flowline repairs.
Some of these costs are fixed regardless of production volume, like a pumper’s base salary or a compressor lease payment, while others are variable and scale with output, like chemical dosing or water hauling. Treating a fixed cost as variable in forecasting understates risk during a production decline, since the fixed portion does not shrink when volumes drop.
Shared costs, often handled under COPAS accounting procedures, get allocated across working interest owners by percentage. An operator running artificial lift on a mature well might reference guidance like EcoLift Energy’s overview of artificial lift options when weighing deployment costs against expected production gains.
How to structure a lease operating statement for clean reconciliation
A lease operating statement works best when it follows the same order investors see in audited disclosures: production and revenue first, then LOE, then the other costs that sit below it. SEC filings typically show gathering and transportation, production and ad valorem taxes, and depreciation, depletion and amortization listed separately from LOE, never folded into it.
A monthly field-level schedule should include these fields in sequence:
- Gross production volumes and realized prices by product.
- Fixed LOE and variable LOE, reported separately.
- Workover costs, broken out from routine maintenance.
- Total LOE and the resulting LOE per BOE.
- Gathering, transportation, and compression fees.
- Production and ad valorem taxes.
- Net operating cash flow and owner working-interest splits.
Internal field schedules usually run at a finer grain than quarterly SEC disclosures, which aggregate many leases into a single reporting unit. A representative SEC filing example shows lease operating expenses reported alongside workover and other sub-lines with specific dollar figures, giving a useful template for investor-facing reporting. Reconciling the two means tying each month’s field totals into the quarterly rollup before taxes and DD&A get layered on top, so finance and operations never argue over which number is correct.
Distinguishing operating expense from capital costs
Classification follows the nature and purpose of the spending, not its size. A repair that restores a well to its prior operating condition is generally an expense, while work that materially improves, extends the life of, or adapts an asset to a new use tends toward capitalization. Industry guidance on CapEx versus OpEx warns that misclassifying either direction inflates or deflates LOE per BOE and distorts the metrics teams use to compare assets.
Practical tests operators apply:
- Does the work restore the well to its prior condition, or does it add new capability?
- Is the expenditure routine and recurring, or a one-time structural change?
- Does the cost extend the economic life of the asset beyond its original expectation?
IRS and Treasury guidance under rules tied to IRC Sections 162 and 263 provides the framework federal filers rely on when drawing this line, and documentation matters as much as the judgment call itself. Readers evaluating how capitalized costs get recovered over time can also review depreciation methods for oil and gas assets.
Pro Tip: Keep a dated work order and job description for every workover or repair; that paper trail is what supports the expense classification if a filing is ever questioned.
What drives LOE and how to benchmark it correctly
LOE varies by well type, artificial lift method, water cut, well age, geography, and local power and labor costs, which is why a single benchmark number rarely applies across a portfolio. Produced water handling, maintenance frequency, disposal capacity, and power costs tend to be the largest swing factors on mature assets.
LOE averaged around the mid-$20s per BOE according to EIA’s production expense analysis, after supply-chain-driven inflation pushed costs sharply higher in 2021 and 2022 before easing. That figure is a contemporary reference point, not a target every lease should hit, since well mix and basin geology shift the number considerably.
Benchmarking well means normalizing by BOE or Mcf consistently, adjusting for artificial-lift mix, and accounting for well age before comparing two assets side by side. BCG’s 2026 analysis of shale LOE found top-quartile and bottom-quartile operators in the same Permian geology can differ by more than $5 to $8 per BOE, which means geology alone does not explain performance gaps.
Key points to carry into any benchmarking exercise:
- Produced water volume and disposal capacity often drive the widest cost swings on mature wells.
- Maintenance frequency and artificial lift type shape both labor and parts spending.
- Power costs vary by region and by whether an operator runs on-grid or on-site generation.
- Quartile spreads within the same basin show operational execution matters as much as geology.
Operational levers that actually reduce LOE
Cost reduction that holds up over multiple quarters comes from targeted operational changes, not blanket cuts that risk production. BCG’s research identifies exception-based maintenance and remote monitoring as high-impact levers, since they cut unscheduled truck rolls by flagging only the wells that actually need attention.
- Exception-based maintenance and remote monitoring reduce labor hours and unplanned site visits.
- Produced-water routing and haul optimization cut disposal fees and trucking miles on water-heavy leases.
- Energy optimization, including peak-demand shifting and on-site generation contracts, lowers power spend.
- Procurement consolidation across chemicals and parts reduces per-unit costs at scale.
Water logistics deserve particular attention on mature shale portfolios, where disposal infrastructure constraints increasingly decide whether a lease stays economic. Operators running mobile compression or well support equipment in their own fleets sometimes turn to day-rate providers like EcoLift Energy rather than committing to fixed contracts during a pilot phase.
Pro Tip: Pilot any cost-reduction tactic on a small well set first, track production impact alongside cost savings, and only scale once both metrics hold steady for a full quarter.
The KPIs and reporting cadence that keep LOE under control
A short, consistent KPI set beats a long dashboard nobody reads. Track LOE per BOE, LOE per well-month, workover cost per intervention, produced-water cost per barrel, and well uptime.
- Report field-level LOE monthly, then reconcile into finance on a quarterly cycle.
- Use a rolling twelve-month view to smooth out seasonal and one-time items.
- Watch for mismatched denominators between field schedules and corporate financials, a common reconciliation error.
- Flag any workover reclassified as capital spending before it hits the quarterly rollup.
What I’d tell any operator chasing a lower LOE number
The biggest mistake I see is treating LOE reduction as a cost exercise instead of a production-preservation exercise. The operators who hold their gains document every classification decision, keep their denominator consistent quarter over quarter, and resist the urge to cut maintenance that protects uptime. Every lease is different enough that a benchmark number only means something once the scope behind it matches yours. Readers focused on the tax side of asset ownership may also find value in reviewing how depreciation methods apply to oil and gas investments.
— Sharif
Where investors can review operator economics alongside LOE
Investors evaluating operator cash flow often want to see how LOE disclosures affect the economics of a specific project before committing capital. We built a marketplace where accredited investors can review vetted U.S. energy projects, including producing assets, development projects, and energy infrastructure, with the underlying operator materials presented for comparison.
- Our tax deduction calculator estimates first-year deductions tied to a specific investment.
- Our guide to analyzing projected ROI walks through how LOE and other costs factor into return expectations.
- Our overview of U.S. oil investments explains the project types available on our platform.
Explore the Fieldvest marketplace to review current vetted projects and see how operator disclosures translate into investment terms.
FAQ
What are the operating expenses in a lease?
Lease operating expenses cover the recurring costs of running a producing well: labor, chemicals, power, water handling, workovers, and artificial lift upkeep. They exclude drilling and completion capital, gathering and transportation fees, and production taxes, which appear as separate line items on a lease operating statement.
How much do oil companies pay for leases?
Lease costs vary widely by well type, artificial lift method, water cut, age, and location, so there is no single figure that applies broadly. Recent EIA data put average production expenses near $26 per BOE after the 2021-2022 inflation spike eased, though that number should be treated as a reference point rather than a universal rate.
Can you provide an example of a lease operating statement in the oil and gas industry?
A typical lease operating statement lists gross production and realized prices first, then fixed and variable LOE, workovers, and total LOE with the resulting LOE per BOE, followed by gathering and transportation fees, production taxes, and net cash flow to owners. SEC filings follow this same ordering in their disclosure formats, which makes them a useful template for internal reporting.
What is OpEx in oil and gas?
OpEx, or operating expense, refers to the recurring costs of running producing wells, as opposed to CapEx, which covers drilling and completion spending. Industry guidance notes that routine maintenance and workovers are generally OpEx, while structural improvements or new drilling fall under CapEx.
Sources
- EIA — Production expenses and BOE trends
- BCG — How AI cuts shale lease operating costs in 2026
- SEC filing (example lease operating statement structure)
- Quorum — CapEx vs OpEx in oil and gas (2026)
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