A joint operating agreement is the contract that governs how two or more companies co-own and co-develop an oil and gas tract or unit, setting out who operates the property, how costs and production are split, what votes are needed for new wells, and what happens when a partner defaults or wants out. The current industry baseline is the AAPL Form 610-2015 Model Form Operating Agreement, used across onshore operations in the United States as a starting template that parties then customize through exhibits. Because a single project can involve tens of millions of dollars in capital and decades of production, the terms discussed below are the ones that most often determine whether the venture runs smoothly or ends in litigation.
What the Agreement Covers
The contract area is the geographic footprint of the deal. Every lease, tract, and unit falling under the JOA is identified by legal description, usually drawn from county land records and confirmed against a title opinion. Each party’s ownership percentage inside that footprint drives cost sharing, voting power, and revenue allocation, and the agreement stays in force as long as the underlying leases remain active or wells continue producing in paying quantities.
The scope of operations limits what activities the parties can conduct under the agreement. A well-drafted scope runs from seismic exploration through drilling, completing, producing, and eventually plugging wells. Activities outside that scope cannot be charged to the joint account, so vague language here invites arguments later about whether a given expenditure was authorized.
Area of Mutual Interest
Many JOAs add an area of mutual interest (AMI) clause that reaches beyond the contract area itself. If a party acquires new leases or mineral interests inside the AMI boundary, it must give the other parties written notice of the acquisition terms and a set period to buy in at their proportionate share. The AMI exists to stop a partner from using geological information gained through joint operations to quietly lease up surrounding acreage and keep the upside.
Operator and Non-Operator Roles
One party is designated as operator and runs day-to-day field activities for the group. The operator controls the site, hires contractors, handles regulatory compliance, and makes the routine decisions that keep production moving. Under the AAPL Form 610, the operator must conduct operations as a reasonably prudent operator, using good oilfield practices and complying with applicable law.
With that role comes a significant liability shield. The operator is not liable to the other parties for losses sustained during authorized operations unless the losses result from gross negligence or willful misconduct. Courts applying that standard look at the operator’s state of mind: whether the operator knew about the danger and acted with indifference to the consequences. Ordinary mistakes or poor judgment do not meet the threshold.
Non-operators play a more passive role but keep meaningful oversight. They can visit the site at reasonable times, and they can inspect and audit the joint account books. Those audit rights are the primary check on how the operator spends money. If the operator fails to perform, non-operators can vote to remove and replace it. Under the 2015 AAPL Form, removal requires an affirmative vote of one or more parties holding a majority interest. If the operator holds no working interest in the contract area, it can be removed at any time, with or without cause, by a majority-in-interest vote. If the operator itself is the defaulting party, non-operators can appoint a successor immediately without waiting out a cure period.
How Operations Get Paid For
Before the operator spends significant money, it issues an Authority for Expenditure (AFE) estimating costs for a proposed operation. Each party reviews the AFE and decides whether to approve its financial participation. Once an operation is approved, the operator issues cash calls to collect each party’s share based on ownership percentages. Under the 2015 AAPL Form, non-operators have 30 days from receipt of the demand to pay.
Accounting and Overhead
The accounting procedure attached to the JOA governs how the operator tracks and bills joint account expenses. Most agreements incorporate model forms published by the Council of Petroleum Accountants Societies (COPAS).1Council of Petroleum Accountants Societies. Economic Factors and Accounting Procedures Overhead compensates the operator for accounting, regulatory reporting, and other administrative functions that cannot be charged directly to the joint account. The current structure separates drilling overhead, prorated by drilling days so that deeper and longer wells generate more, from production overhead, which is a flat rate because a shallow producing well requires about the same administrative effort as a deep one. The rates are negotiable and often traded off against other commercial terms.
The 24-Month Audit Deadline
Non-operators who suspect billing errors face a hard deadline. Under COPAS standards, all bills and statements rendered during a calendar year are conclusively presumed correct 24 months after that calendar year ends. To preserve a challenge, the non-operator must file a specific, detailed written exception and make a claim for adjustment inside that window. Starting an audit does not extend the deadline. A non-operator who begins an audit 20 months in but fails to file a written exception before month 24 loses the right to dispute those charges. This is the trap most partners fall into: they assume launching the audit is enough.
Participating in New Operations
JOAs separate initial operations from subsequent operations. Initial operations are the first activities to prove up the contract area, typically the first well, and every party that signed the agreement has already committed to fund them at its ownership percentage.
Subsequent operations work differently. When the operator proposes a new well, a deepening, a sidetrack, or a recompletion, each party chooses whether to participate. A party that declines becomes a non-consenting party, and the financial consequences are steep. The consenting parties cover the non-consenter’s share of costs, then recover that investment plus a penalty out of the non-consenter’s share of production before the non-consenter sees any revenue. The penalty commonly ranges from 100% to 300% depending on the risk level of the operation. At a 300% penalty, the consenting parties recover four times the non-consenter’s costs (its original share plus 300%) before any production revenue flows back. On a productive well, non-consenting can cost far more than participating would have.
Gas Balancing
Co-owners of a gas well do not always take their share of production at the same rate. One party may have a ready buyer while another lacks pipeline capacity or market contracts. Over time, one party ends up overproduced and another underproduced relative to ownership. A gas balancing provision, sometimes a separate gas balancing agreement, lets the underproduced party catch up in-kind by taking a larger share of future production. If the well depletes before the imbalance clears, the overproduced party typically owes a cash payment to the underproduced party.
Default and Remedies
When a party fails to pay a cash call or meet another financial obligation, the consequences escalate quickly. The operator sends written notice of default, and the defaulting party has 30 days to cure. If the default is not cured, the non-defaulting parties can suspend the defaulting party’s rights under the agreement:
- The operator can withhold the defaulting party’s share of revenue from any producing well and apply it against the outstanding balance plus interest.
- The defaulting party loses the right to receive operational information about activities conducted during the default period.
- The defaulting party can no longer elect to participate in proposed operations, even if it had previously agreed to participate.
- If the default involves drilling a new well or a significant downhole operation, the defaulting party is automatically treated as non-consenting, triggering the full non-consent penalty on top of the original debt.
JOAs also create cross-liens on each party’s working interest, produced hydrocarbons, and sale proceeds to secure payment of operating costs. If the defaulting party still does not pay, the operator can foreclose on those liens in the same manner as mechanics’ and materialmen’s liens. If the foreclosure proceeds do not cover the full debt, the defaulting party remains personally liable for the shortfall. Under the 2015 AAPL Form, the right to offset production proceeds against unpaid obligations extends beyond the operator to any party that may have been mistakenly paid common account funds.
Transfers, Preferential Rights, and Uniform Interest
Selling a working interest under a JOA is rarely as simple as finding a buyer. Most agreements include a preferential right to purchase, giving existing partners the first chance to buy any interest before it goes to an outsider. The seller must send written notice to all other parties with full details of the proposed sale: the buyer’s name, purchase price, legal description, and all material terms. Under the standard AAPL form, the other parties have 10 days after receiving notice to match the offer on the same terms. If they exercise the right, they take the interest proportionally. Under the 2015 form, a transfer does not become effective until 30 days after the operator receives the transfer documents.
A separate but related provision, the maintenance of uniform interest clause, prevents parties from carving up their ownership well-by-well. It requires that any transfer cover either a party’s entire interest in the contract area or an equal undivided percentage of its interest across all assets. Without that restriction, an operator could face a fractured ownership pattern with different percentages in different wells, forcing separate notices, accounting, metering, and cost allocations for every project. Courts have enforced these clauses strictly, holding that horizontally subdividing a working interest by retaining certain wells and selling others breaches the clause.
Plugging and Decommissioning Obligations
Every well eventually reaches the end of its productive life, and someone pays to plug it and restore the surface. On federal leases, the operator must promptly plug and abandon any well that no longer produces in paying quantities, following a plan approved by the authorized officer.2eCFR. 43 CFR 3162.3-4 – Well Abandonment A well can be temporarily abandoned for up to 30 days without prior approval; anything longer requires authorization, and the operator must demonstrate the well’s mechanical integrity. After four years of temporary abandonment, the operator must either permanently abandon, resume production, or present a detailed plan for future beneficial use.
Between the working interest owners, cost allocation for plugging is a matter of contract, and the JOA’s cost-sharing provisions generally apply. But the federal government does not care about the internal split. All current and prior record title owners and operating rights owners are jointly and severally liable for decommissioning obligations. If one party cannot pay, the others must cover the full cost and pursue reimbursement afterward. Assigning an interest to a third party does not automatically release the assignor unless the contract contains specific release language. Parties sometimes discover too late that exiting a JOA is not as clean as it looked on paper.
Tax Treatment and the Section 761 Election
A JOA creates an arrangement the IRS could treat as a partnership, which would require filing a partnership return and allocating income through Schedule K-1s. Most oil and gas co-owners prefer to avoid that treatment because it adds complexity and limits each party’s ability to compute income independently. Under 26 U.S.C. ยง 761(a), all members of an unincorporated organization formed for the joint production or extraction of property, but not for selling the product, can elect to exclude the organization from Subchapter K.3Office of the Law Revision Counsel. 26 USC 761 – Terms Defined The election is available only when each member can adequately compute its income without calculating partnership taxable income.
Each member must be able to determine its own tax liability independently, which works cleanly when working interest owners each take their proportionate share of production and sell it separately. If the organization never formally makes the election but the members clearly intended to operate outside Subchapter K from the outset, the IRS may treat the election as having been made.4eCFR. 26 CFR 1.761-2 – Exclusion of Certain Unincorporated Organizations From the Application of All or Part of Subchapter K of Chapter 1 of the Internal Revenue Code Once effective, the election is irrevocable as long as the organization remains qualified. Most JOAs include a tax partnership election exhibit addressing the choice directly.
Force Majeure
Force majeure provisions suspend a party’s obligations when performance becomes impossible due to events beyond its control. The affected party must promptly notify the others in writing with full details of the event and its impact. Obligations stay suspended only while the condition continues, and the affected party must use reasonable diligence to resolve the situation. One limit matters more than the rest: force majeure never excuses the obligation to pay money. A party owing cash call payments or operating costs cannot invoke a hurricane or regulatory delay to avoid writing the check.
Signing, Filing, and Federal Land
All participating parties sign multiple original copies of the agreement, and signatures are typically notarized to meet the formalities for property-related contracts. Rather than recording the full JOA, the parties file a memorandum of operating agreement with the local county clerk or land office. The memorandum identifies the parties, describes the contract area, and confirms that an agreement exists without disclosing commercial terms like overhead rates, non-consent penalties, or individual ownership percentages. Recording it gives constructive notice to future buyers, lenders, and creditors that the working interests are subject to an operating agreement.
Most parties start from the AAPL Form 610-2015 Model Form and customize it through exhibits.5American Association of Professional Landmen. Joint Operating Agreements Exhibit A carries the legal descriptions of all tracts and units along with each party’s ownership percentage, and other exhibits handle the accounting procedure, insurance, gas balancing, the AMI boundary, and the tax partnership election. Getting the percentages right matters disproportionately, because a one-percent error in Exhibit A means that party pays the wrong share of every cash call, receives the wrong share of every barrel, and casts the wrong voting weight on every proposal for the life of the agreement.
For operations on federal land, the Bureau of Land Management imposes additional requirements. Submitting a transfer of operating rights on BLM Form 3000-3a is a certification that the party is qualified to hold the lease interest and complies with the Mineral Leasing Act.6Bureau of Land Management. H-3102-1 – Qualifications of Lessees The BLM can request documentation proving a party’s ability to hold a federal lease and gives at least 30 days to respond. Leases committed to an approved federal unit or communitization agreement are excluded from acreage limitation calculations, which can affect a party’s ability to acquire additional federal acreage.