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Affecting Petroleum Land Practices

February, 1999

Habendum Clause and Royalty Issues – plus some extras

By Professor Marla E. Mansfield

The University of Tulsa, College of Law

The courts in the past few months have been busy on several fronts. Some of these cases present "all new episodes" in our discussions in this column and two provide perhaps anti-climatic ends to running series. The new cases come out of Texas and deal with habendum clause interpretations. Return appearances are made by HECI Exploration Co. v. Neel and a case interpreting the duties of the United States as a lessor under an Outer Continental Shelf lease. Finally, Colorado has provided an episode that refines in its interpretation of what post-production costs are to be shared by a lessor.

The first new case out of Texas is Sun Operating Limited Partnership v. Holt, 1998 WL 758433 (Tex. App. Amarillo No. 07-0010-CV) (October 29, 1998). It dealt with both a cessation of production clause in a lease's habendum clause and the lease's force majeure clause. It is useful for its careful exposition of when each of these clauses, as well as the shut-in royalty clause, applies. The habendum clause of the lease stated:

subject to other provisions herein contained, this lease shall remain in force ... for so long thereafter as oil, gas or other mineral is produced from said land, or as long thereafter as Lessee shall conduct drilling or re-working operations thereon with no cessation of more than sixty consecutive days until production results, and if production results, so long as any such mineral is produced.

The force majeure clause of the lease provided that:

When drilling or other operations are delayed or interrupted by lack of water, labor or materials, or by fire, storm, flood, war, rebellion, insurrection, riot, strike, differences with workmen, or failure of carriers to transport or furnish facilities for transportation, or as a result of some order, requisition or necessity of the government, or as the result of any cause whatsoever beyond the control of the Lessee, the time of such delay or interruption shall not be counted against lessee, anything to in the lease to the contrary notwithstanding.

The facts reveal that Sun operated a lease on which five wells produced gas. All were hooked up to one purchaser's pipeline. When the pipeline was being repaired, there was no production from the leasehold for more than sixty-days, although the wells were capable of production. Production resumed as soon as the repairs were completed. The trial court found that the leases had expired, after instructing the jury that, to use force majeure, the lessee must prove that it "exercised due diligence and had taken all reasonable steps to remove and overcome the effect of `force majeure'."

The court of appeals disagreed with this interpretation of the force majeure clause. It held that determining what constitutes force majeure requires contract interpretation, not the use of general principles. This particular clause did not require the lessee to have attempted to avoid the problem. The failure to exercise due diligence could become a breach of the implied covenant to market or properly administer the lease, but is not required to invoke force majeure under this clause. The clause did, however, apply to the requirement of production because it refers to "other operations" that might have to be excused. The lack of pipeline facilities would fall within the clause as a possible excusing event because the clause refers to a "failure of carriers to transport." However, the wording of the clause does require the purported force majeure event (pipeline shut-down for repairs) to have been beyond the control of the lessee and to have been the sole cause of the cessation of production. The case would therefore be remanded.

The case also addressed the cessation of production clause in the habendum clause and whether it governed the case. The court held that the cessation of production clause, requiring drilling or re-working operations within 60 days does apply to situations where the well is capable of production and is neither depleted nor inoperable because of mechanical failure. Drilling or re-working another well is an option for continuing the lease in the absence of production. The habendum clause, however, was subject to the other provisions of the lease, which include the force majeure clause. It states that the time during which force majeure prevents an "operation" shall not "be counted against the lessee." Therefore, the lease did not automatically end after the end of 60 days. Finally, the case examined the relevancy of the shut-in royalty clause and found that payment of royalties was not the sole way to maintain a lease with a well capable of production. It could have been used, but perhaps was not needed if force majeure excused performance. The particular clause required payment of $50 per well that was shut-in. One assignee of the lessee, which obtained one well, could not automatically preserve its interest by paying $50 because the shut-in royalty payment was indivisible.

The second Texas case examined whether "illegal" production could suffice to meet a the equivalent of a habendum clause's requirements. Duncan Land & Exploration Co. v. Littlepage, 1998 WL 894601 (Tex.App. - Fort Worth No. 2-97-172-CV). The origin of the conflict was the interest in a well Duncan received pursuant to a farmout, which provided that the assigned interest would terminate if there was no commercial production of oil or gas from the tract for a period in excess of 90 days. The termination would be effective upon the assignor filing an affidavit of record.

In 1992, there was a downhole problem and the well began producing sour gas. A neighbor complained and the Railroad Commission on May 21 ordered the well shut-in pending testing of the SO₂ concentrations. The well passed the first test in May but the well remained shut-in until another test in July, which was passed. Nevertheless, a third test was ordered and the well was to remain shut-in. It was tested in October, the results were received in November, and Duncan received notice that the shut-in order was lifted on December 2, 1992. Despite the shut-in order, Duncan periodically operated the well by natural flow in order to continue to produce in commercial quantities. There was some production throughout 1992. Littlepage learned of the problems and, after being told there was a little production, filed an affidavit of termination. He had not talked to Duncan, had not personally sought to ascertain production figures, and had not inquired as to Duncan's cost figures. The jury found there had been production in commercial quantities without a lapse of 90 days. The court rendered a judgment finding that there was no evidence to support the jury's verdict. It did so in response to Littlepage's argument that production in violation of the shut-in order was against public policy and should preclude it being used to show commercial quantities.

The court of appeals court reversed and reinstated the jury's verdict. The court found that in this particular situation, production contrary to the Railroad Commission order could be considered as evidence of commercial production. First, the commission order did not in itself amend the lease because the Commission does not adjudicate private rights. Second, although the court does not condone Duncan's actions, the well in question was peremptorily shut-in for six months when it was not in fact in violation of the regulations. Additionally, Littlepage is using the order as an offensive tool and he had knowledge that some production was occurring. The court also found sufficient evidence that Littlepage committed slander of title by filing the affidavit.

To shift our type of programming a bit, we look at a continuation of Colorado's exposition  of when a lessor shares post-production costs.  In Garman v. Conoco, Inc., 886 P.2d 652 (Colo. 1994), the Colorado supreme court held that, absent a lease provision to the contrary, the implied duty to market precluded the lessee from deducting any costs incurred to make the product marketable. The present case defines "marketable" and considers the impact of the provision that royalty should be determined "at the wellhead." In  Rogers v. Westerman Farm Co., Inc., 1998 WL 895887 (Colo. App. No. 97CA0293) Dec. 24, 1998), a lessee was selling gas that was sweet and dry. Some sales were at the wellhead. Others were at the inlet to the interstate pipeline, which sales required the lessee to transport, dehydrate and compress the gas to meet pipeline standards. The lessee paid royalty on the wellhead sales based on gross proceeds and for the other sales based on a work-back method, subtracting the post-production costs from the proceeds. The leases involved stated that royalty was to be computed at the wellhead. The lessors claimed that 1)  the transportation, dehydration, and compression costs should not have been deducted from the downstream sales; and 2) the sales made at the wellhead (to an affiliate) should have been made downstream to capture the increased value.

The court of appeals held that the phrase "at the wellhead" does not provide any express input on how to allocate post-production costs other than transportation. Therefore, the leases are "silent" and the Garman rule provides that the lessee cannot deduct costs that make the gas marketable because of the lessee's implied duty to market. The submitted instruction at trial which dealt with marketability included having the jury look at the good faith of the lessee. The sole question for marketability, however, is whether the product is sufficiently free from impurities that is will be taken by a purchaser. Good faith is not applicable to this issue, but may be considered if generally looking at the implied covenant to market or to the reasonableness of deductions made to make a product marketable. The court found that the gas was marketable at the wellhead as a matter of law and the question should not have been submitted to the jury. All the costs after that were costs of transportation to market and should have been deemed deductible. This answered the first allegation of the plaintiffs.  On the second issue, the jury also had found that, for the sales made at the wellhead, the gas was in a marketable condition at the wellhead. The crux of this complaint is a violation of the duty to reasonably market. Therefore, the questioned definition of marketability did not prejudice anyone on this issue; the jury found the sales to be reasonable and in good faith.

[As an aside, a Colorado court of appeals, in a case of first impression for Colorado at least, concurred with majority opinion and found a reservation of all "minerals" to include oil and gas. McCormick v. Union Pacific Railroad Co., 1998 WL 856995 (Colo. App. No 97CA1625) (Dec. 10, 1998).]

We now proceed to the final episodes of some continuing series.  HECI Exploration Co. v. Neel had a long run as the court of appeals kept vacating and replacing its own decisions. To refresh memories on the facts, AOP had violated Railroad Commission rules and thus damaged the reservoir. The overproduction ended in December of 1988. HECI filed suit against AOP in 1988 and received actual and punitive damages for damage to the formation. The lessors did not learn of the suit until 1993 and then filed suit. This was more than four years after a release of judgment against AOP was filed of record. They sought a royalty of 1/6 of the damage award and also alleged negligent misrepresentation because of HECI's failure to disclose information about the illegal production or the suit, breach of an implied covenant against drainage that allegedly included an obligation to sue AOP on behalf of the lessors, and unjust enrichment because HECI retained compensation from AOP that was based on the lessor's interest. The Court of Appeals rejected the royalty claim because damages were based on damage to the formation, not production. It did, however, acknowledge the viability of the remaining claims. It found an implied covenant to notify the lessors of two things: 1) the need for a suit, and 2) the lessee's intention to sue. These covenants existed because the lessee was not impliedly authorized to sue on behalf of the lessors. Moreover, it held that the discovery rule applied and thus tolled the four-year and two-year statutes of limitations applicable to breaches of covenants and misrepresentations, respectively.

In HECI Exploration Co. v. Neel, 1998 WL 750917 (Tex. No. 97-0403) (October 29, 1998), the Supreme Court reversed and rendered a take-nothing judgment for the lessors. The court found the causes of action to have been time-barred or substantively lacking. On the issue of failure to notify the lessor of the need for a suit, the court found the discovery rule did not apply because the type of injury was not inherently undiscoverable. The lessors should have known of the failure to notify when it knew or should have known that a cause of action accrued. In this instance, that was when the damage to the formation occurred, which was in 1988. As owners of the mineral estate, the lessors had some obligation to exercise reasonable diligence to protect their interests.  One source of information on the reservoir would be the lessees; these lessees never failed to give information when requested to do so.. Additionally, information on a common reservoir and operations on it is available at the Railroad Commission. Although the public records about illegal operations do not provide constructive notice to royalty owners of their content so as to create an irrebuttable presumption of knowledge, they are available and thus the cause of action would not be inherently undiscoverable. When the underlying cause of action was or should have been discovered, then the failure to notify of that cause of action would also be known. Therefore, to the extent the lessors' cause of action relies on the existence of an implied covenant that the lessee will notify the lessor that an adjoining landowner has injured the formation, the court found the action time-barred. It did not need to address whether such an implied covenant existed.

The Supreme Court did, however, reject any implied covenant to notify the lessor of the lessee's intention to sue another. The court did not find such a duty to be so clearly within the intention of the parties that they did not have to express it in the lease; the duty was not fundamental to the purpose of the lease. Finally, unjust enrichment would not be a proper remedy in this instance because the lessors were not foreclosed from suing AOP by HECI's suit. Even if HECI arguably recovered more than its share from AOP, that would not have prevented a timely suit by the lessors.

Finally, in Marathon Oil Co. v. United States, 158 F.3rd 1253 (1998), the Federal Circuit Court of Appeals reversed the Court of Federal Claims, which had found that the United States breached an Outer Continental Shelf oil and gas lease when Congress passed the Outer Banks Protection Act. This Act had placed a moratorium on approving Plans of Exploration in the area. The Court of Federal Claims had ruled that the leases were not subject to future statutes and the failure to fairly review a POE constituted a breach of the contract. Conoco Inc. v. United States, 35 Fed.Cl. 309 (1996). The Appeals Court, however, found that the passage of the Outer Banks Protection Act was not the cause of the delay in approving the POE. North Carolina had not certified that the proposed exploration was consistent with its Coastal Zone Management Act. The Outer Continental Shelf Lands Act, under which the leases were issued, provided that exploration could not proceed if a state found inconsistencies and the Secretary of Commerce did not override this finding. Because Marathon did not prevail in appealing the denial of consistency to the Secretary, it was this, rather than the subsequent legislation, which precluded approval of the POE.

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