This article was featured in the July/August 2024 edition of the AAPL Landman Magazine.

In Foundation Minerals, LLC v. Montgomery,[1] the New Mexico Court of Appeals considered whether a Mineral Estate Purchase Agreement (the “PSA”) was enforceable. The dispute centered around the meaning of “Net Royalty Acres,” which was the formula used to determine the final Purchase Price. Montgomery (the “Seller”) argued that the term Net Royalty Acres was ambiguous enough to void the contract completely.

The trial court agreed with the Seller and held that the PSA was unenforceable because the parties never reached a mutual assent or “meeting of the minds” about the Purchase Price. In applying Texas law in accordance with the PSA,[2] the New Mexico Court of Appeals noted that one element of an enforceable contract is a meeting of the minds on all essential terms – such as the purchase price. You can’t infer a meeting of the minds without sufficiently definite contract terms.[3]

I. Background and the PSA

Under the PSA, Foundation Minerals, LLC (the “Buyer”) contracted with the Seller for the sale of 257.48 Net Royalty Acres (“NRAs”) at $15,535.19 per NRA under twenty-five (25) tracts of land. The total Purchase Price was thus estimated to be $4,000,000.00. The PSA defined an NRA as “the equivalent of 1 Net Mineral Acre (“NMA”) being leased at a 1/8th royalty. For Example: 1 NMA leased at a [25% royalty] is equal to 2 NRAs.” In other words, for every NMA that was leased at a 25% royalty, the Buyer would purchase 2 NRAs for a total of $31,070.38. Exhibit “A” to the PSA listed a total of 128.74 NMAs, and assumed that each NMA was leased at 25%, totaling said 257.48 NRAs.[4] However, the final amount of NRAs and thus the total Purchase Price were to be determined by title examination prior to closing.

Disagreements subsequently arose between the Buyer and Seller as to the treatment of nonparticipating royalty interests (“NPRIs”) and unleased mineral interests (“UMIs”). The PSA addressed NPRIs to a degree, stating that “adjustments to the price will only be made if the NRAs increase or decrease based on title examination which shall include confirmation of the assumed 25% lease royalty on all leases.” Per the Buyer, this meant that NPRIs were intended to be valued “in the same manner as a royalty interest.”[5] It appears that that PSA was silent on UMIs, but the Seller testified that UMIs are commonly sold at an assumed 25% royalty, “because more value is placed on [UMIs] since the purchaser [is] then able to negotiate and enter into its own lease at a [25%] royalty, [and] negotiate and receive lease bonuses.”[6]

II.  The Seller’s Argument

The Seller was unhappy with certain title defects that were asserted by the Buyer prior to closing and the corresponding reductions to the Purchase Price. The Seller thus attacked the enforceability of the PSA, stating that there was no mutual assent as to price because the Seller “intended to sell [its] mineral estate for $4,000,000.00, and nothing less.” [7] As part of its argument, the Seller argued that the NRA formula, as set forth in the PSA, could not be applied to UMIs (which clearly have no lease) or NPRIs (which represent only the right to receive a payment under a lease and not to participate in the lease itself).  Because the PSA did not separately identify a different Purchase Price for either, the Seller argued that there could not have been a meeting of the minds.[8] The trial court agreed and negated the PSA on summary judgment,[9] and the Buyer appealed.

III.  Decision on Appeal

The New Mexico Court of Appeals first held that for a PSA to be enforceable it must set forth a Purchase Price with a “reasonable degree of certainty.” The court then held that the PSA was reasonably certain because it allowed the Buyer to pay an adjusted Purchase Price after title examination had been conducted to confirm the 257.48 Net Royalty Acres. The PSA expressly included a mechanism to adjust the final valuation and reflected a “strong presumption that the parties intended a reasonable price.” The parties’ course of dealing during the due diligence period further supported this reasoning. For example, the Seller had attempted to cure title issues and had even entered into new leases covering some of the UMIs.[10]

The court then addressed the Seller’s argument that the PSA should be canceled because it failed to adequately define a Purchase Price for UMIs and NPRIs. It agreed with the Buyer that based on common trade usage and the course of dealing between the parties, an assumed 25% royalty rate could be implied in the purchase and sale of these interests. Further, the PSA itself stated that NPRIs would be purchased assuming a 25% royalty on all leases – subject to confirmation by title examination.[11]

For these reasons, the court held that the Purchase Price in the PSA was sufficiently definite, even if the final total was left open. The PSA in no way supported the Seller’s claim of a “flat” $4,000,000 regardless of the results of title examination in the due diligence period. The PSA thus did not guarantee the Seller a particular dollar amount, instead setting forth that: “(1) a decipherable calculation would yield the total purchase price after title examination verified Seller’s mineral and royalty interests; and (2) should Seller fail to correct any title issues, Buyer could grant Seller more time, negotiate a reduction in price acceptable to all parties, waive the title issue, or refuse to accept title to the Mineral Estate and cancel the agreement.” The Seller could not repudiate the PSA based on an indefinite Purchase Price.

IV. Foundation Takeaway

Although commonly employed in purchase and sale agreements and in the oil and gas industry at large, terms such as Net Royalty Acres, Net Royalty Interest Acres, Overriding Royalty Acres, and Net Revenue Acres are not legal terms of art. This means that these monikers have no universally accepted legal definition.

Royalty acres were originally conceptualized on the basis of the standard 1/8^th royalty, with eight Net Royalty Acres contained in one Net Mineral Acre. Thus, a 1/8^th lease would entitle you to one of the eight royalty acres. In other words, a 1/8^th lease would grant you 1 NRA, a 3/16^th lease would grant you 1.5 NRA, and a 1/4 lease would grant you 2 NRA (as in the Foundation PSA).

Over time, the idea of a Net Royalty Acre has become disconnected from the actual lease royalty and a single Net Royalty Acre has come to generically mean a 1/8^th royalty on the full mineral interest in one acre of land. An oft-cited legal treatise argues that a “royalty acre” should continue to reflect a full lease royalty. In other words, if a landowner is subject to a 1/4th royalty on 1 acre of land and sells 1 royalty acre, then such grant would include the full lessor’s royalty interest. Conversely, if 1 mineral acre equals 8 royalty acres, a 1/4th lessor’s royalty on 1-acre tract would yield 2 royalty acres and the sale of 1 royalty acre would only transfer 1/2 of the grantor’s royalty.[12]

Further complications may arise when a PSA does not address how to treat unleased mineral interests and/or nonparticipating royalty interests. It benefits both parties and assures a “meeting of the minds” if terms such as Net Royalty Acre, and the treatment of NPRIs and UMIs, are carefully defined in the PSA. This also prevents the possibility of a court later imposing its own definitions, leading to unpredictable results.

Understanding the nuances of “dirt law” is crucial when negotiating a PSA for mineral, royalty, nonexecutive, and leasehold interests. These nuances can have a tremendous impact on your defects and price adjustments at closing and may even negate the deal completely (as the Foundation Seller attempted to do here). It is therefore advisable to have a trusted oil and gas attorney, licensed in the state where the assets are located, look over the definitions, defect mechanisms, and due diligence provisions in your PSA prior to signing.

For more tips on drafting and negotiating a PSA from an oil and gas perspective, take a look at our practical Acquisition and Due Diligence Checklist, available for download here.

[1] 2023 N.M. App. LEXIS 78 (2023).

[2] The court notes that Texas law governs the interpretation of the contract, but that “Texas and New Mexico law are in harmony on the relevant principals. Id. at 10.

[3] Id. at 11.

[4] Id. at 13.

[5] Id. at 15.

[6] Id.

[7] Id. at 17.

[8] Id. at 17-18.

[9] Note that summary judgment is doled out with much less frequency in New Mexico than in other states, as New Mexico Courts “disfavor” summary judgment and prefer trial on the merits. Id. at 9 (citing Romero v. Philip Morris Inc., 242 P.3d 280 (N.M. 2010).  Therefore, the trial court must have strongly felt that there was no enforceable contract.

[10] Id. at 21.

[11] Id. at 21-22.

[12] See 1 Patrick H. Martin and Bruce M. Kramer, Williams & Meyers, Oil and Gas Law, § 320.3 (LexisNexis 2022)