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Index for Web Site

Mineral Rights - Introduction

Oil & Gas Exploration & Production Process

Surface Rights and Mineral Rights

Hunt Oil Company v. Kerbaugh

N.D. Industrial Commission Regulatory Role

Considerations for Mineral Owners

Mineral Lease: Introduction & Habendum clause

Mineral Lease: Granting clause

Mineral Lease: Royalty clause

Mineral Lease: Saving clauses

Mineral Lease: Other clauses & Closing Thoughts

North Dakota Sample Mineral Lease

Mineral Lease Clauses: Added Examples

Considerations for Surface Owners

N.D. Ind. Commission Notice to Surface Owner

Added Thoughts for Owners of Mineral & Surface Rights

Oil & Gas Terminology

In return for giving the company the right to exploit oil and gas, the mineral owner typically receives compensation in the form of a bonus when the lease is made and perhaps delay rental payments, discussed above, before the well is drilled. If production is achieved, the mineral owner receives royalties.


Bonus Payment


When the lease is signed, the company pays the mineral owner an initial cash bonus, perhaps as a lump sum or perhaps expressed in dollars per acre (e.g., see paragraph 1 of the State lease). Competition for leases largely determines the amount of bonus offered. The more intense the competition, the larger the bonus. The actual amount paid is generally not shown in the lease. Rather, only a nominal consideration is expressed as "one dollar and other valuable considerations."


Beware that bonus amounts are often offered on the assumption that the mineral owner owns the full mineral interest. For example, if the company offers a $1,000 per acre bonus for a 160-acre tract but the mineral owner owns only 1/4th (25%) of the mineral rights, the actual bonus paid will be $40,000, not $160,000 (see the Lesser Interest Clause discussed previously).


Sight Draft


When the mineral owner signs the lease, the landman may pay the bonus with what is known in the oil and gas business as a “sight draft.” Sight drafts cannot be immediately cashed and are used to give the company time to recheck the ownership of minerals covered by the lease and time to review any changes that have been made in the company’s standard lease form in the course of negotiations.


For example, a 90-day sight draft will not be paid until 90 days after the draft has been presented to the company’s bank for payment. If the mineral owner tries to deposit a sight draft, the mineral owner’s bank will not credit the mineral owner’s account until the company’s bank has actually paid the draft. Moreover, as discussed above, the company will not pay the draft in full if the mineral owner owns less than a 100% mineral interest.


Mineral owners should reject sight drafts, to avoid the danger that the company may record the lease but not pay the draft. On the other hand, the company may be legitimately concerned that the mineral owner’s title is not as represented. The worst-case scenario for the company would be where the mineral owner had already leased the tract to some other company.


If this is a concern to the company, using a local bank, law office, or abstract company as an escrow agent is preferable to allowing a company to pay by sight draft. The escrow agent would hold the signed lease with instructions not to deliver the lease to the company until the company has fully paid the bonus.


Another alternative is a lease option. Under this approach, the mineral owner would give the company an option to lease (e.g., for 10 days) in return for a nonrefundable payment (e.g., 10% of the bonus). During this 10-day option period, the company would have time to check the title, review the negotiated lease, and decide whether it wishes to proceed to lease the property. If it elects to lease, the negotiated balance of the bonus would be paid in full in return for the executed lease.


Knowledgeable legal counsel should be obtained before using either an escrow or an option approach. The key concern is that the mineral owner should not give the company a recordable lease until the mineral owner has been received full and final cash payment of the agreed bonus.


In summary, a number of misunderstandings exist concerning the use of sight drafts:


  1. A sight draft is not a check. The draft can only be cashed if the procedure outlined above has been followed.
  2. Because a sight draft is not a check, securing actual payment takes time—more time than is specified by the terms of the daft itself. For example, 90-day sight draft will only be paid, if at all, 90 days after the company’s bank “sees” the check. This does not count the time needed to present the check to the company’s bank, the time needed to send the draft for collection through the banking system, or the time needed to actually transfer payment to the mineral owner’s bank.
  3. When the draft is paid to the mineral owner, the amount received may differ from the amount shown on the sight draft when the lease was signed to reflect the mineral owner’s fractional mineral title.
  4. A sight draft and for that matter, a check is only good for payment if the maker has sufficient funds on deposit and does not stop payment. Thus, a mineral owner should never turn over a signed and notarized lease to a landman without making sure the bonus payment has been actually and finally credited to the mineral owner’s account.



The Royalty Clause


From an economic standpoint, the royalty clause is probably the most important clause to the mineral owner because it allocates to the mineral owner a certain portion of the substances produced or a portion of their value. The standard royalty on oil and gas for many years was a 1/8th share; however, today a 1/6th, 3/16th, 1/5th, and even higher fractions are increasingly common. Whatever the fraction, the fundamental truth for a mineral owner is that the royalty fraction may be the least important part of the royalty clause (e.g., see paragraph 4 of the State lease).


The North Dakota Supreme Court, following Texas case law, and rejecting Oklahoma and Kansas law, has ruled that a company may deduct all post-wellhead costs when calculating royalty under typical company-drafted royalty clauses (see Bice v. Petro-Hunt, L.L.C., 2009 ND 124, 768 N.W.2d 496). This decision will inevitably result in companies sharpening their pencils when calculating royalty payments to maximize their deductions. Unfortunately, mineral owners who have already executed company lease forms will have little recourse to prevent companies from taking maximum advantage of this deduction right. For mineral owners that have not yet leased, it is now imperative that they negotiate more favorable royalty provisions. To avoid this and related royalty valuation problems, mineral owners should insist upon the following royalty terms:


  1. Royalty should be due on a stated fraction or percentage of “gross proceeds but not less than gross market value at an established market location.” By requiring royalty to be paid on “gross proceeds” of an actual sale with the floor being “gross market value,” the mineral owner should be protected from “sweetheart” sales at a low price to an affiliated company; further protection from this possibility would be obtained by providing for royalty on the “gross proceeds received from the first arm’s-length sale of oil or gas but not less than gross market value.”
  2. Any reference that royalty is payable or calculated “at the well,” “at the wellhead,” at the “mouth of the well,” or at any other location, other than the actual point of sale, should be deleted.
  3. If any costs, other than the mineral owner’s share of state production taxes, are to be deducted (this deduction is expressly permitted by statute), they should be expressly identified in detail, including how such deduction is to be calculated. In general, mineral owners should resist such language, except perhaps the deduction of actual transportation charges levied by a “common carrier” pipeline. Because gas may be “processed” for the removal of natural gasoline and other valuable liquids, a company may bargain hard for the right to deduct processing costs. If a mineral owner agrees to the deduction of such costs, it should not include treating or dehydration costs and related compression costs and should only permit the deduction of actual and direct costs of deducting the cost of extracting natural gasoline and other valuable liquids and such deductions should only be made from the sale price of such gasoline and liquids and not from the sale price of the “residue” gas.


Without these changes, a company is certain to burden the royalty owner with maximum costs. Moreover, the mineral owner will be generally unable to determine whether such cost deductions reflect actual and reasonable costs and what cost-components go into this calculation.


These suggested provisions may easily prove to be more valuable than a higher royalty fraction. Remember, royalty fractions do not have to be the same for oil and for gas. For example, a lease could provide for a 1/5th oil royalty, a 1/6th natural gas royalty, and a 1/8th royalty on liquids extracted from gas. By negotiating differing fractions, the parties can build-in certain additional costs incurred by a company in handing natural gas and extracted liquids.


If a company balks at agreeing to such terms, a mineral owner should first consider finding another company who will accept these terms. As a fallback position, a mineral owner might demand a so-called “federal floor,” which would amend the royalty clause to specify that “notwithstanding anything to the contrary, the royalty payable shall never be less than what would be payable to the federal government if the oil and gas under lease were owned by the federal government, if the federal government were taking its royalty in cash, and if the federal government had retained the same royalty fraction or percentage specified in this lease.” While this provision would allow for some deductions for transportation and for certain gas processing costs, it would provide the mineral owner with a royalty that is on the same basis as federal royalty, albeit for possibly a higher fraction or percentage, as federal leases, which typically carry a 1/8 royalty burden. If federal minerals are in the vicinity, an additional advantage to this provision would be that the mineral owner could periodically check with the federal government as to whether any royalty audits had occurred that indicated that royalties had been improperly calculated by the company. A disadvantage to this approach is that royalty calculations under federal leases are fairly complex. Nevertheless, companies regularly secure federal oil and gas leases, so they should be willing to pay private mineral owners on the same basis.


Of course, the ultimate fallback position would be to refuse to lease. While a mineral owner might be pooled through a regulatory compulsory pooling process, the mineral owner will still secure a statutory royalty, as well as a net-profits interest in production attributable to the mineral owner’s interest. However, the mineral owner would not receive a bonus, and the mineral owner’s net-profits interest would be subject to a “statutory risk penalty” before any net profits would be payable. The statutory risk penalty allows the company to recover an additional sum of money over and above the pooled party’s actual share of costs out of production before having to account for net profits. A mineral owner who is compulsory pooled may avoid the risk penalty by electing to directly participate in the drilling of the well; however, this election exposes the mineral owner to significant financial risk. A mineral owner who seriously considers refusing to lease should thoroughly discuss the matter with knowledgeable legal counsel.


In Kind Royalty


Some oil and gas leases “reserve” royalty oil in kind to the mineral owner. For example, if the mineral owner reserved a 1/6 oil royalty, one out of every six barrels of produced oil would be owned by the royalty owner. Leases seldom reserve royalty gas in kind, and most mineral owners should avoid doing so to avoid the practical problems associated with handling, processing, transporting, and marketing natural gas.


Reserving royalty oil in kind does provide a slight advantage to the mineral owner in terms of legal remedies. If a company fails to make royalty oil available to the mineral owner, the company commits the tort of conversion. If royalty is payable only in cash, the company has simply breached a promise to pay a debt. If royalty oil is reserved in kind and if the company goes bankrupt, the mineral owner can argue that the company has no title to the royalty oil, which may help a mineral owner who is competing with other creditors to satisfy the debts of an insolvent company. The principal disadvantage is that the mineral owner must sell the royalty oil to realize value—perhaps at a lower price than the company received for its share. On balance, reserving the option to take oil and perhaps gas in kind is a good idea, but not as a tradeoff for the suggested value provisions.


Parts of a Royalty Clause


The royalty clause offered by a company may have several parts—an oil royalty provision, a gas royalty provision, a royalty provision for casinghead gas (gas produced from an oil well), and even a royalty provision for processed gas (gas from which gasoline and other hydrocarbon liquids may be extracted). Regardless of its parts, the basic royalty obligation should be to pay on gross proceeds but not less than gross market value.


Cancellation of Lease for Nonpayment of Royalties


North Dakota is one of two states that have a specific statute allowing the mineral owner to cancel the lease for nonpayment of royalties. The statute allows cancellation, "if the equities of the case require it."


As a practical matter, the statute is not that useful. If the company missed a royalty payment or made an error in calculating royalty, but later acknowledged the fact and paid the royalty plus interest, a court would most likely rule that the equities do not require cancellation. However, the statute is useful where a company is found to have acted fraudulently or in bad faith.




The following factors should be considered when negotiating a royalty clause.

  1. Incorporate the royalty provisions that were discussed above.
  2. Detail the time, place and frequency royalty payments are to be made. Outline the consequences for royalty payments being missed.
  3. Discuss and resolve whether royalties should be paid for wastes due to leakage, fire or other reasons which can be attributed to the company's negligence.
  4. Reserve the option to take royalty in kind upon 30 days’ notice to company.
  5. Determine if the mineral owner should have access to free gas. Related to royalty are provisions that allow the mineral owner free gas—usually for domestic household purposes but potentially for commercial or irrigation purposes. Occasionally, the mineral owner will not get free gas, but will have the right to buy gas at a low established price. Because of a host of potential practical problems with taking gas from wells, this benefit should not be pursued at the expense of most other matters addressed in this publication, except perhaps in very unique circumstances. Do not trade off what may be only a phantom benefit for the high-priority matters discussed in this bulletin.
  6. Limit the company’s free use of oil and gas to operations conducted on the leased tract and directly related only to production attributable to the leased tract and specify that such free gas is limited to the mineral owner’s proportionate interest in the oil and gas produced. (See further discussion below under Resource Use).
  7. As outlined earlier, include royalty percentages for substances other than oil and gas that might be included in the granting clause; but ordinarily the granting clause should be limited to the leasing of oil and gas, as discussed above.
  8. Require that royalties be paid on gross proceeds but never less than gross market value and delete all references to location of payment (e.g., at the well, etc.).
  9. Most importantly, the decision to lease or not to lease and the drafting of royalty provision should not be attempted without knowledgeable legal counsel.


Other Royalty Matters:

Overriding Royalty Interest

In its most common but not exclusive usage, an overriding royalty is a royalty carved from a company’s interest in a lease. For example, a company may assign the lease to another company and reserve an overriding royalty. Or a company may convey an overriding royalty to a geologist or other party as compensation for work performed. The fraction or percentage of an overriding royalty may vary considerably. By checking courthouse records for overriding royalties in lease assignments or in outright conveyances, a mineral owner might get a general idea of the royalty burden that a company is willing to bear. For example, if leases providing for a mineral owner royalty of 1/8th (i.e., 12.5%) are being regularly burdened with a 10% overriding royalty, this suggests that mineral owners should have negotiated a higher lease royalty.


An overriding royalty may also be created when the company leasing land elects to “farmout” the lease, rather than develop the lease by itself. In such a circumstance, the company will typically retain an overriding royalty; however, this overriding royalty may also be convertible, at the company’s election, to a participating working interest upon “payout” (i.e. achieving profitability) of any well drilled on the property. In contrast to paying quantities, discussed above, payout means a profit after drilling, completion, and day-to-day operating costs up to payout have been recovered. Payout is the “break even” point for a producing well.  Farming out, rather than leasing, may in an option for some mineral owners, but a farmout agreement must be custom drafted by knowledgeable legal counsel.


Division Order


A division order is ordinarily prepared by a lawyer for the company or for the purchaser of production. The order advises the company or purchaser of how production revenues are to be allocated among various mineral owners and companies holding interests in property that is attributed to a well. When signed and returned by a mineral owner or company, the signer acknowledges that the interest is correct as summarized in the division order.


Division orders should only be signed upon advice of knowledgeable legal counsel. In general, mineral owners do not have to execute division orders to be entitled to receive royalties. Division orders should only be signed if the mineral owner is certain of his or her interest, if such interest is correctly stated in the division order, if the division order does not purport to amend the lease in any way, and if the division order does not purport to ratify any oil or gas sales contract.


Time Limit on Royalty Payments


A bill passed by the 1981 North Dakota Legislature requires that interest of 18 percent be paid on royalties not paid within 150 days of the sale of gas or oil produced. See N.D.C.C. §47-16-39.1.  Oil companies can normally pay royalties within 90 days after they have sold their first oil from a well, although it may take somewhat longer with the first well in a particular field.


Next Pages

Mineral Lease -- Introduction and Habendum clause

Mineral Lease -- Granting clause

Mineral Lease -- Royalty clause

Mineral Lease -- Saving clauses

Mineral Lease -- Other clauses and Closing Thoughts


Last updated July 26, 2010


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