Spacing units and pooling in North Dakota, in plain English

What a spacing unit is

A spacing unit is the block of land assigned to a well. The Industrial Commission's rules define it as the area in each pool that is assigned to a well for drilling, producing and proration purposes, in accordance with the Commission's rules or orders.^[1] The statute tells the Commission to set spacing units when that's needed to prevent waste, avoid drilling unnecessary wells, or protect correlative rights. The order has to state the size and shape of each unit.^[2]

Unit sizes vary a lot. DMR publishes a drilling spacing units map service whose layers are sorted by acreage, from 160 acres up to 31,000.^[3] The Commission can also change a unit later. The statute lets it modify an order to increase or decrease the size of units, or to allow additional wells, when that's found necessary for the same purposes.^[2]

Why should you care? Because the unit is the denominator. Your operator is required to send an ownership statement within 120 days after the month of first sale, or after a change in the spacing unit or in your decimal. It has to show the spacing unit, your net mineral acres, the gross mineral acres in the unit, and the decimal interest the operator will apply to the well.^[4] Your net acres divided by the unit's gross acres is the starting point for your decimal. Our division order guide shows the arithmetic with made-up numbers, and you can try your own in the royalty estimator.

What pooling means

Most spacing units hold more than one separately owned tract. The statute says that when that's the case, the owners and royalty owners may pool their interests to develop and operate the unit. If they don't pool voluntarily, the Commission, on the application of any interested person, has to enter an order pooling all interests in the unit.^[2]

Two things in that section matter to a mineral owner. First, every pooling order is made after notice and hearing, and on terms that are “just and reasonable” and give each owner the chance to receive, without unnecessary expense, a just and equitable share. Second, once a unit is pooled, drilling anywhere in it counts as drilling on every tract in it, and each tract's allocated share of production counts as produced from that tract.^[2] That's why a well whose lateral never crosses your tract can still pay you.

A lot of leases already include pooling language, so no hearing is needed. DMR's mineral owner page says it plainly: if all the leases in a unit don't contain voluntary pooling language, a pooling hearing has to be held and the Commission has to issue a pooling order, and that can come before the first royalty check.^[5] Your own lease is the first place to look. If you aren't sure what its pooling clause allows, that's a question for an attorney.

If your minerals are unleased

The statute has a specific rule for unleased interests that get pooled. An unleased interest pooled after July 31, 2009 is entitled to a cost-free royalty equal to the acreage-weighted average royalty of the leased tracts in the unit or, at the operator's election, a cost-free royalty of sixteen percent. The rest of the unleased interest is treated as a lessee or cost-bearing interest.^[2] For interests pooled before August 1, 2009, the statute uses the same weighted average, with a floor of one-eighth.^[2]

In plain terms, an unleased owner in a pooled unit can end up with a royalty on part of the interest and a cost-bearing share on the rest. That's where the risk penalty comes in.

Not joining a well: the risk penalty

If an owner in a unit elects not to participate in the risk and cost of drilling, the owner who pays that share can recover the actual costs plus a risk penalty. The statute sets the penalty at 200 percent of the nonparticipating owner's share of reasonable actual drilling and completion costs when the interest comes from a lease or other development contract. That penalty can be recovered only out of production from the pooled unit, exclusive of any royalty or overriding royalty. For an interest that isn't leased, the penalty is 50 percent of that share, recovered from production exclusive of the royalty described above.^[2]

The paying owner can't just take it. The statute says the owner has to have made an unsuccessful, good-faith attempt to get an unleased owner to sign a lease, or to get a leased owner to join in. Before a penalty can be imposed, the paying owner must notify the nonparticipating owner, with proof of service, that it intends to impose one, and that the nonparticipating owner may object by responding to a petition for the penalty or by asking the Commission for a hearing.^[2]

The Commission's rules add detail on the invitation. It has to be in writing and describe the proposed well and its itemized estimated costs. It must say the election has to be made within thirty days of receiving the invitation, and it has to be served personally, by mail requiring a signed receipt, or by overnight courier requiring a signed receipt.^[1] The operator can also secure its costs with a lien on your share of production, recorded as an affidavit with the county recorder.^[2]

If you get an invitation to participate, read it right away and take it to an attorney or someone who handles oil and gas accounting. We aren't going to tell you how the penalty applies to a particular interest, because it depends on the lease, the order and the notice.

Where the drilling rules fill in

The Commission's rules also have fallback well locations for pools that don't have a spacing order. For a horizontal well projected deeper than the Mission Canyon formation, the default drilling unit is a governmental section or adjacent governmental sections, with the well at least 500 feet from the outside boundary of the tract.^[1] The rules also let the Commission allow an exception location after notice and hearing, and the applicant has to certify that the application went to the lessees and unleased mineral owners of adjoining properties.^[1] Those are fallbacks, though. The order for your section is the document that counts.

A 2026 decision on overlapping units

In 2026 the North Dakota Supreme Court decided Garaas v. North Dakota Industrial Commission, 2026 ND 25. It's worth reading about if your section is part of more than one spacing unit, because it shows how an order can go wrong. We're describing the opinion, and we're not saying what it means for any particular well or owner.

The case involved a four-section, 2,560-acre spacing unit that overlapped a 1,280-acre unit set up years earlier. An operator divided production among the lands in the overlapping unit and then allocated part of it to a section in the older unit. The Commission issued an order approving that allocation. The Court held that the Commission has legal authority to allocate production among spacing units, but that this order didn't regularly pursue that authority. The Court said the order effectively enlarged the unit for the well beyond its existing boundaries, yet nobody had applied to modify the existing orders, which is what the spacing statute contemplates. Without an application, the process went forward without notice to the owners in the affected units, and the Court said proper notice and a chance to take part are necessary. It reversed the district court and vacated the order.^[6]

The opinion also noted that the overlapping unit's pooling order said it didn't modify earlier pooling orders for other spacing units.^[6] If you own in an overlapping or lease-line unit, an attorney who has read the orders for your sections can tell you how that applies to you.

If you think an order is wrong

The statute gives a party adversely affected by a Commission order two routes. One is a written petition for reconsideration under section 28-32-40. The other is an appeal to the district court in the county where the well or the affected property is, under chapter 28-32.^[2] The deadlines come from chapter 28-32, so find out what yours are before you wait on anything.

On appeal, the statute says the district court must sustain the order if the Commission regularly pursued its authority and its findings and conclusions are supported by law and by substantial and credible evidence.^[2] That's a deferential standard, which is one more reason to bring in an attorney early rather than late. Also, DMR says all oil and gas hearings are open to the public, and if you want something on the record you have to attend and sign the witness register.^[5]

How to find your section's order

Start with the map. DMR's mineral owner page walks through it: open the GIS map server, use the Find Section tab, enter your legal description, and zoom to the section.^[5], [7] From there you can see wells and the layers around them. DMR's Find My Well page takes a section, township and range,^[8] and the mineral owner page says a well search by section, township and range returns wells with a matching surface location.^[5] Keep in mind that a long lateral can run under sections other than the one where the well was drilled.

For the orders themselves, DMR keeps an index of hearing dockets by year. Its docket page also links a policy on contested spacing cases and lets you sign up for docket notices.^[9] DMR lists its Field Orders and Case Files, with the order index and scanned case files, under its subscription services. New case files are posted 15 to 30 days after a hearing, and most cases have an audio recording.^[10] If a subscription isn't worth it for one question, the operator's ownership statement is required to name your unit,^[4] and DMR invites mineral owners to call the Oil and Gas Division with questions.^[5]

We follow the Commission's daily activity in our NDIC news section, and we cover the broader picture in our Bakken overview. Our county pages cover the five counties we follow: Williams, McKenzie, Dunn, Mountrail and Divide County. The FAQ covers common mineral owner questions, and the royalty check deductions guide and dormant mineral law guide cover two other things that can change what you're paid.

A note on our interest

Fort Union buys minerals and royalty interests, so we have a commercial interest in this subject. Nothing in this guide depends on selling to us, and each statement comes from a public source listed below. Our editorial standards explain how we source and review our pages. If you ever want to know what we'd pay for your interest, the offer page is the way to reach us.

Sources

These are the sources behind this guide, in the order we first cite them. We read the parts of each one that this guide relies on, on October 25, 2026.

1. N.D.A.C. chapter 43-02-03, Rules of Practice (sections 43-02-03-01, 43-02-03-16.3 and 43-02-03-18) — North Dakota Legislative Branch (Administrative Code), parts read October 25, 2026.
2. N.D.C.C. chapter 38-08, Control of Oil and Gas Resources (sections 38-08-04, 38-08-07, 38-08-08, 38-08-10, 38-08-13 and 38-08-14) — North Dakota Legislative Branch, Century Code, parts read October 25, 2026.
3. DrillingSpacingUnits map service — North Dakota Department of Mineral Resources, viewed October 25, 2026.
4. N.D.A.C. chapter 43-02-06, Royalty Statements — North Dakota Legislative Branch (Administrative Code), read October 25, 2026.
5. Mineral Owner information and frequently asked questions — North Dakota Department of Mineral Resources, Oil and Gas Division, viewed October 25, 2026.
6. Garaas v. North Dakota Industrial Commission, 2026 ND 25 — North Dakota Supreme Court, opinion text as published by Justia, 2026.
7. Oil and Gas GIS map viewer — North Dakota Department of Mineral Resources, viewed October 25, 2026.
8. Find My Well — North Dakota Department of Mineral Resources, Oil and Gas Division, viewed October 25, 2026.
9. Oil and Gas hearing docket index — North Dakota Department of Mineral Resources, Oil and Gas Division, viewed October 25, 2026.
10. Oil and Gas subscription services — North Dakota Department of Mineral Resources, Oil and Gas Division, viewed October 25, 2026.