In oil and gas, a dry hole is a well that cannot produce oil or gas in quantities large enough to justify completing it as a producer. That is the standard the SEC uses word-for-word: a well “incapable of producing either oil or gas in sufficient quantities to justify completion.”1eCFR. 17 CFR 229.1205 – Drilling and Other Exploratory and Development Activities The call usually comes after the operator reaches the target depth set in the drilling contract and runs evaluation tests, such as wireline logs or drill stem tests, to measure reservoir pressure and check for hydrocarbons. Once the well is declared dry, a chain of consequences begins: lease deadlines, tax elections, accounting write-offs, joint operating agreement votes, and mandatory plugging.
What Happens to the Lease
An oil and gas lease has a fixed primary term, often three to five years, followed by a secondary term that lasts as long as the lease keeps producing in commercial quantities. Drill a dry hole in the primary term, stop paying delay rentals, and without a safety valve the lease can terminate the moment the well is abandoned.
The safety valve is the dry hole clause. It gives the lessee a grace period, typically 60 or 90 days, to either resume delay rental payments or begin drilling a new well. Start a second well inside that window and the lease survives as if the dry hole never happened. Courts have generally required actual drilling or reworking activity to qualify as “commencing operations,” not just moving equipment onto the site.2Michigan Law Review. Oil and Gas – Construction of Lease – Dry Hole and Cessation of Production Clause
Miss the window by a few days and the lease can terminate outright, returning all mineral rights to the lessor. Operators who drill a dry hole late in the primary term feel this most sharply, because the grace period may be the only thing keeping the lease alive.
Tax Deductions After a Dry Hole
The tax code softens the blow of a dry hole, but the size of the deduction and its timing depend on the elections the operator has made and whether the company is an independent producer or an integrated oil company.
The IDC Election
Drilling costs split into two categories. Tangible equipment, such as casing, wellheads, and pumps, has salvage value. Intangible drilling costs (IDCs) do not: wages, fuel, repairs, hauling, supplies, and contractor charges for the drilling work itself.3eCFR. 26 CFR 1.612-4 – Charges to Capital and to Expense in Case of Oil and Gas Wells On a typical well, IDCs run 60 to 80 percent of the total.
Under IRC Section 263(c), an operator holding a working interest can elect to deduct IDCs as a current business expense in the year they are paid or incurred, whether the well produces or not.4Office of the Law Revision Counsel. 26 U.S.C. 263 – Capital Expenditures Drill a $1 million well where $750,000 of the cost is IDCs, and that $750,000 is deductible in the year of the dry hole. The election is made by claiming the deduction on the return for the first year eligible costs arise, and for oil and gas wells it is binding for all future years.5Internal Revenue Service. Publication 535 – Business Expenses
If IDCs Were Capitalized
An operator who did not elect to expense IDCs must capitalize them. On a productive well those capitalized costs come back through depletion or depreciation. On a dry hole, the operator can deduct the capitalized IDCs as an ordinary loss in the year the well is completed and abandoned.5Internal Revenue Service. Publication 535 – Business Expenses
A third option under IRC Section 59(e) lets the operator amortize IDCs over 60 months starting from the month each expenditure is paid or incurred.6Office of the Law Revision Counsel. 26 U.S.C. 59 – Other Definitions and Special Rules This middle path spreads the deduction and sidesteps certain alternative minimum tax complications, which can matter for operators with uneven income.
Independent Producers vs. Integrated Companies
Independent producers deduct 100 percent of IDCs in the year incurred. Integrated oil companies, those with substantial refining or retail operations, hit a limit under IRC Section 291: only 70 percent of IDCs can be expensed immediately, with the remaining 30 percent amortized over five years.4Office of the Law Revision Counsel. 26 U.S.C. 263 – Capital Expenditures
The AMT Exclusion for Dry Holes
There is a genuine tax silver lining to a failed well. The AMT preference item for excess IDCs under IRC Section 57(a)(2) applies only to costs “incurred in connection with oil, gas, and geothermal wells (other than costs incurred in drilling a nonproductive well).”7Office of the Law Revision Counsel. 26 U.S.C. 57 – Items of Tax Preference IDCs on a dry hole are not a preference item. An operator who expenses IDCs on a producer may run into AMT if the deduction exceeds 65 percent of net oil and gas income; the same operator drilling a dry hole avoids that issue entirely.
Passive Activity and At-Risk Rules
Dry hole losses could in theory be trapped by the passive activity rules that block passive losses from offsetting wages and other active income. IRC Section 469(c)(3) carves out an exception: a working interest in an oil or gas property is not treated as a passive activity, as long as the taxpayer holds the interest directly or through an entity that does not limit personal liability.8Office of the Law Revision Counsel. 26 U.S.C. 469 – Passive Activity Losses and Credits Limited A general partner in a drilling partnership qualifies; a limited partner typically does not.
The at-risk rules under IRC Section 465 still apply. Oil and gas exploration is one of the listed activities, so the operator can only deduct losses up to the amount actually at risk.9Office of the Law Revision Counsel. 26 U.S.C. 465 – Deductions Limited to Amount at Risk Nonrecourse financing that inflates apparent investment does not lift that ceiling. For an investor in a drilling fund, the at-risk cap often bites harder than the passive activity rules.
How Dry Holes Show Up on the Books
Two accounting methods handle dry holes very differently.
Under the successful efforts method, only costs tied to productive wells are capitalized. Dry hole expenses are charged against income immediately, cutting reported earnings in the year the well fails.10Federal Trade Commission. Successful Efforts and Full Cost Accounting as Measures of the Internal Rate of Return for Petroleum Companies Drill five wells with one producer and four dry holes hit the income statement as expenses.
Under the full cost method, every cost of finding and developing reserves is capitalized, dry holes included, on the theory that they are a necessary part of exploration. The capitalized pool is then amortized against production over time.10Federal Trade Commission. Successful Efforts and Full Cost Accounting as Measures of the Internal Rate of Return for Petroleum Companies Smaller exploration companies tend to prefer full cost because it smooths earnings; larger majors generally use successful efforts.
Either way, public companies have to disclose their dry hole track record. SEC Regulation S-K Item 1205 requires disclosure for each of the last three fiscal years, broken down by geographic area, of the number of net productive and dry exploratory wells drilled, and the number of net productive and dry development wells drilled.1eCFR. 17 CFR 229.1205 – Drilling and Other Exploratory and Development Activities A well counts as drilled in the year it is completed, and for a dry hole “completion” means reporting abandonment to the appropriate authority.
Dry Holes Under a Joint Operating Agreement
When multiple working interest owners share a lease, the joint operating agreement (JOA) controls what happens when a well comes up dry. The AAPL Model Form 610, the template for most U.S. JOAs, has specific dry hole provisions.
A dry hole cannot be plugged and abandoned without the consent of all parties to the JOA. Once the operator proposes abandonment, each non-operating party has 48 hours (excluding weekends and holidays) to respond. Any party that fails to respond within that window is deemed to have consented.11American Association of Petroleum Landmen. A.A.P.L. Form 610 – 1989 Model Form Operating Agreement The tight clock exists because an open dry hole burns money every day.
A party that objects can take the well over, but has to give the operator satisfactory proof of financial capability to continue operations. If the dissenting party fails to produce that proof or fails to actually perform the work, the operator can plug and abandon.11American Association of Petroleum Landmen. A.A.P.L. Form 610 – 1989 Model Form Operating Agreement
Non-consent elections work differently on dry holes than on producers. When one party proposes drilling and another declines, the consenting parties can typically recoup a multiple of costs, often 300 percent, from the non-consenting party’s share of production if the well succeeds.12University of Oklahoma College of Law. Old Faves and New Raves – How Case Law Has Affected Form Joint Operating Agreements If the well is dry, there is no production to recoup from. The non-consenting party generally owes nothing, and the full loss falls on the consenting parties. That asymmetry is the core gamble of non-consent: no downside on a dry hole, but most of the upside gone on a producer.
Plugging, Abandonment, and Bonding
Declaring a well dry does not end the operator’s obligations; it triggers them. Every producing state requires operators to plug abandoned wells and restore the surface, whether the well produced for twenty years or never flowed at all.
The Plugging Process
State rules vary in detail but share a framework: the wellbore is sealed with cement plugs at specified intervals to keep fluids from migrating between underground formations, so that saltwater and residual hydrocarbons cannot contaminate freshwater aquifers.13National Petroleum Council. Plugging and Abandoning Oil and Gas Wells Regulations typically prescribe cement zones above and through producing formations, inside casing below freshwater zones, and at set distances from the surface. The operator must also clear the site, remove equipment, and restore the land surface close to its original condition.
What It Costs
Plugging and abandonment costs vary widely by well depth, age, location, and whether surface restoration is included. Studies across multiple states show costs ranging from under $20,000 for simple shallow wells to over $300,000 for deep or complicated ones, with a typical combined cost for plugging and surface reclamation around $76,000. Deeper wells run roughly 20 percent more for each additional thousand feet, natural gas wells tend to cost slightly more than oil wells, and operators who contract multiple wells at once can negotiate lower per-well rates.
These costs land on top of the already-lost drilling investment. Operators who fail to plug abandoned wells face daily fines from state regulators and can forfeit their drilling bonds or lose the ability to obtain future permits.
Federal Bonding on Public Lands
For wells on federal land, the Bureau of Land Management requires operators to post bonds before drilling. Under rules finalized in 2024, the minimum individual lease bond is $150,000 and the minimum statewide bond is $500,000.14Bureau of Land Management. Oil and Gas Leasing – Bonding Those figures replaced longstanding minimums of $10,000 and $25,000 that had been widely regarded as too low to cover actual plugging costs. Existing bonds below the new minimums must be increased by June 22, 2027.15Federal Register. Federal Onshore Oil and Gas Statewide Bonds Extension of Phase-In Deadline The BLM will adjust the minimums for inflation every ten years going forward.
Dry Hole Contribution Agreements
A dry hole contribution agreement, sometimes called a dry hole letter, is a separate contract, not a lease provision. A nearby acreage holder agrees to pay the operator a set amount if the well comes up dry, and in return receives all geological and geophysical data gathered during drilling: formation logs, core samples, and pressure test results. If the well is a producer, the contributor owes nothing, because the operator’s reward is the well itself.
The payment is typically a fixed dollar amount per foot drilled, negotiated before spud, and the agreement sets a minimum depth the operator must reach for the payment obligation to trigger. The contributor does not acquire any working interest in the well, which is what separates these arrangements from farmouts, where acreage interests actually change hands.