POST-PRODUCTION DEDUCTIONS FROM ROYALTY
| Jurisdiction | United States |
(2001)
POST-PRODUCTION DEDUCTIONS FROM ROYALTY
Phelps Dunbar, LLP
New Orleans, Louisiana
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I. INTRODUCTION
The nature of traditional royalty clauses—short, all-encompassing, and vague—has caused conflict between lessors and lessees as long as mineral leases have existed. While litigation relating to royalties encompasses an extremely wide range of issues, expenses incurred by the lessee after production passes through the wellhead are a focal point for friction. Two theories of the lessee's duty to the lessor to shoulder these costs now exist. These theories lay at opposite ends of a continuum that elevates the language of the royalty clause at one end and the lessee's duty to market the production of its lessor on the other. States following both theories agree that a lessee is responsible for the cost of exploration and production. The lessor is not responsible for any cost incurred by the lessee to develop production in paying quantities from the lease. The point at which production ends, however, is disputed by the two rules, and the lessee's costs to make production "marketable" are in some states treated as an element of production that the lessee must shoulder alone.
II. A TALE OF TWO RULES
A. A Brief History of the Duty to Market
The lessee's implied duty to market is recognized in every major oil-producing state. In its original formulation, the duty provided that a lessee must diligently seek a market for shut-in gas reserves. See Owen L. Anderson, Royalty Valuation: Should Royalty Obligations Be Determined Instinctively, Theoretically or Realistically?, Parts 1 & 2, 37 Nat. Resources J. (Parts 1 & 2, 1997). Along with that duty, of course, came its costs, and the type of costs that the duty obligates the lessee to bear came into dispute at an early date. Disagreement regarding the scope of the duty stretches back as far as 1940, when Maurice H. Merrill argued that the lessee's duty to market production necessarily required the lessee to bear the cost of marketing the production and preparing it for sale. See Tooley, supra, at 21-15 to 21-16.
Today, courts impose upon the lessee the duty to market gas produced from a well and to obtain the best price and terms possible for the sale of production. See Watts v. Atlantic Richfield Co., 115 F.3d 785, 794 (10th Cir. 1997); Cabot Corp. v. Brown, 754 S.W.2d 104, 106 (Tex. 1987) (implied duty to market rises from covenant to manage and administer the lease and requires the lessee to market the production with due diligence and obtain the best price reasonably possible). The duty has been applied to matters ranging from settlements between lessees and gas purchasers to take-or-pay payments. See Watts v. Atlantic Richfield Co., 115 F.3d 785, 795 (10th Cir. 1997); Frey v. Amoco Production Co., 603 So.2d 166 (La. 1992). However, the duty is based on the lessee's obligation to act at all times as a prudent operator. See, e.g., Parker v. TXO Production Corp., 716 S.W.2d 644 (Tex.App.—Corpus Christi 1986). Frey v. Amoco Production Co., 603 So.2d 166 (La. 1992). The expansion of the duty to these extremes, of course, comes down to money. Specifically, the duty defines the conditions under which the lessor may receive a share of production under a lease without risk or obligation.
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As an amorphous, expanding doctrine, then, the duty to market is a natural ground for the argument that lessors' royalty should be calculated on the value of gas without deduction for costs associated with, but not a part of, the production process.
B. The Basics
1. "Post-Production...
Post-production costs reflect amounts expended by the lessee that add value to production in its raw state at the location of the wellhead prior to a final sale. Generally, costs incurred by a lessee prior to its final sale may be categorized into gathering, compression, treatment, processing, transportation, and dehydration costs. See Tooley, supra, at 21-2 fn.4. No consensus exists among the courts of the various states regarding the allocation of post-production costs between the lessee, the lessor, and other non-working interests. Heritage Resources, Inc. v. NationsBank, 939 S.W.2d 118, 129 (Tex. 1995) (Owen, J., concurring); see also Robert S. Raynes, Jr., A Royalty Pain in the Gas: What Costs may be Properly Deducted From a Gas Royalty Interest?, 98 W. Va. L. Rev. 1199, 1205-1206 (Summer 1996).
2. ...deductions...
The term "deductions" refers to amounts subtracted from the value of production. These amounts are not actually subtracted from royalty. Rather, the lessor's royalty is calculated on the value of production, following the subtraction of the lessor's pro rata share of reasonable, chargeable post-production costs. See, e.g., Rogers v. Westerman Farm Co., 1998 WL 895887, at *6 (Colo.App. Dec. 24, 1998).
3. ...From Royalty...
A royalty on oil or gas production is an expense-free share of production distributed to the lessor over the life of a lease. It is free of all costs of development and production. Martin v. Glass, 571 F.Supp. 1406, 1407 (N.D.Tex. 1983); see also Howard R. Williams & Charles J. Meyers, Manual of Oil & Gas Terms, Matthew Bender & Co., Inc. (10th ed. 1997). Costs that are incurred by the lessee subsequent to production may be allocated between the lessor and lessee. Martin v. Glass, 571 F.Supp. at 1407.
Royalty on oil production is generally payable in cash or in kind. Id. at 1407. Royalty on gas production is generally paid in cash, although leases increasingly allow the lessor the option of receiving such a royalty in kind. See id. at 1407.
An "overriding royalty," as opposed to an ordinary royalty, is a royalty paid out of a lessee's or operator's interest in an oil and gas lease in addition to the lessor's royalty. Martin v. Glass, 571 F.Supp. at 1407. It is usually free of all costs relating to development, production, and operation. Garman v. Conoco, Inc., 886 P.2d 652 (Colo. 1994). An overriding royalty interest is limited to the life of the lease through which it is created. See Martin v. Glass, 571 F.Supp. at 1407. Various states have applied different rules regarding an overriding royalty owner's ability to benefit from the express and implied duties of the lessee to the lessor. See, e.g., Rogers v. Westerman Farm Co., 1998 WL 895887, at *6 (Colo.App. Dec. 24, 1998). The
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concept of overriding royalties has therefore at times complicated the courts' treatment of post-production cost issues.1
4. ...On Oil and Gas Production"
Production of oil, of course, differs from production of gas in the costs that must be incurred following the arrival of production at the wellhead. The costs incurred to prepare each type of production for sale, however, are often analogous. Gas, for example, may have to be dehydrated prior to its purchase, since gas that contains water is corrosive to the pipelines through which it must travel. Frederick R. Parker, Jr., Costs Deductible by the Lessee in Accounting to Royalty Owners for Production of Oil or Gas, 46 La. L. Rev. 895, 908 (1986). Oil also must be dehydrated, although the water will normally separate as the oil sits in storage. Id. Both oil and gas must sometimes be treated to remove impurities. Id. at 903.
Disputes as to how to divide post-production costs thus arise with regard to both oil and gas production. Cases involving royalty on gas, however, more often are litigated to appeal. The reason for this is not entirely clear. However, a lessor who dislikes the manner in which its lessee accounts for oil royalty is typically entitled by his lease to take the oil in kind and market it. Gas royalty is rarely taken in kind, due to restrictive royalty clause language and the impracticality of such an endeavor. Nevertheless, the principles regarding deductions from gas valuation track the principles of oil royalty valuation. See, e.g., id. (discussing deduction of post-production costs from oil and gas royalty valuations simultaneously); see also Bruce M. Kramer, Royalty Interest in the United States: Not Cut From the Same Cloth, 29 Tulsa L. J. 449 (Spring/Summer 1994) (same). While this presentation concentrates on costs assessed against gas production, then, it may be used as a guide for the various states' positions in the oil royalty context. This rule often referred to as the "at the well" rule.
C. The Majority Rule: A Deal Is A Deal
The majority of oil-producing jurisdictions hold that the lessee's implied duty to market production does not oblige the lessee to bear the costs of marketing production alone. Under this rule, known as the "at the well" rule, any costs incurred by the lessee after the production reaches the wellhead, whether to improve the quality of the production or to transport it to a market where it may be sold, may be shared proportionally by the lessee and lessor.
As a result, the language of the royalty clause determines the lessee's financial responsibilities to the lessor following the end of production. Lessors that agree to use certain language in the royalty clause, and in particular the phrase "at the well," agree to value production by reference to the value of the raw production at the wellhead, at the time title vests in the producer. "At the well" states have applied this general rule for post-production expenses with the following results:
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1. Transportation costs
Transportation costs to a purchaser's pipeline, whether on or off a lease, are post-production costs which may be shared with a lessor through a deduction from the value of production. Lessees do not have a duty to transport production to markets off the lease when no market exists for the production at the well.
2. Gathering and dehydration costs
Gathering costs reflect the cost to collect gas from various wells in a field subsequent to...
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