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Litigation between oil and gas producers and royalty owners continues to keep the courts busy. Leases of mineral interests by private landowners, the federal government and state governments typically provide for one-eighth of the value of the production to be paid to the royalty owners (the lessors) as royalties. Disputes over the calculation of the volume and value of the oil and gas production frequently results in litigation. A recent well-publicized example was the $11.9 billion verdict in State of Alabama v. Exxon Mobil Corp., No. CV-99-2368 (Montgomery Co., Ala., Cir. Ct. Nov. 14, 2003). Changes in oil and gas trading and marketing have created a litigation explosion in the royalty area. Valuing oil and gas was relatively simple when most oil and gas was sold outright by producers at the wellhead in arm’s-length transactions. But the development since the early 1990s of vibrant trading markets for oil and gas at downstream hubs and on the New York Mercantile Exchange have made prices at downstream locations more transparent and public. Royalty owners, seeing higher prices downstream at market trading centers than prevail at the wellhead in the field, have sued seeking royalties on downstream prices rather than the wellhead value and without deducting all of the costs associated with the downstream sales. For private-royalty-owner litigation, the terms of the oil and gas lease itself are determinative of valuation and usually require a valuation “at the well.” Royalties on state lands and federal lands are likewise determined by the language of the lease contract, but are also often determined by state and federal regulations dictating how the royalties will be calculated. These and other issues, such as disclosure of calculation methods on royalty check stubs, implied covenants to market oil and gas, and class certification, have filled court dockets. Class actions in the royalty area have become more frequent, seeking national, statewide or fieldwide classes of royalty owners. But recent decisions have cast doubt on the viability of royalty class actions, in part because differences in the contracts (leases) of many royalty owners destroy commonality. The Texas Supreme Court issued its first opinion on royalty class actions on July 3, 2003, in Union Pacific Resources Group Inc. v. Hankins, 111 S.W.3d 69 (Texas 2003). In reversing a class certification, it raised the bar significantly for royalty owners. The trial court had certified a class of gas royalty owners who claimed that producers (lessees) had breached an implied duty to obtain the best current price reasonably attainable. Within the proposed class were royalty owners with at least two different types of lease contracts: Some leases provided for a royalty based on an amount realized (or proceeds) basis, and the others on current market value. In Hankins, the Texas Supreme Court applied the rule it announced in Yzaguirre v. KCS Resources Inc., 53 S.W.3d 368 (Texas 2001), that there is no implied covenant to obtain the best price reasonably attainable in market-value leases. In market-value leases, the royalty payments are based upon fair market value, regardless of what price the lessee actually obtains for the gas. A plaintiff’s claim for this type of lease is limited to merely breach of the express agreement to pay royalties based on market value. In contrast, the court found that in proceeds leases, the implied marketing duty focuses on the behavior of the lessee rather than on evidence of other comparable sales, on whether the lessee acted as a reasonably prudent operator. So the court found that the Hankins royalty owners failed to show common questions of law or fact to support class certification because the two types of leases defined the responsibilities of the lessee differently and the “implied duty” in proceeds leases did not apply to market-value leases. Hankins follows the increasingly frequent denial of class certifications in royalty suits by state and federal courts in recent years. While states such as Oklahoma and Kansas have been more accommodating to royalty class actions, the Texas Hankins decision indicates that the trend will be to deny class certification in most of these cases. The death knell of multistate royalty classes was sounded in Stirman v. Exxon Corp., 280 F.3d 554 (5th Cir. 2002), which reversed a 15-state class because of differences in each state’s law on implied marketing duties in leases. The underlying issue in Hankins was a claim by the royalty owners that the lessee had sold gas to affiliated companies at preferential price indexes and had calculated royalty payments based on the sale to the affiliates. The plaintiffs also alleged that the royalties were reduced because the lessee paid excessive rates to its marketing affiliates to market, gather, compress, treat and transport the gas. In turn, the marketing affiliate sold the gas to third parties at higher prices. There is a growing trend in royalty litigation to challenge sales by producers to affiliated companies, such as marketing affiliates, gas-gathering systems, processing plants and pipelines affiliated with producing companies. All have been named as defendants in royalty cases, based on allegations of self-dealing. Downstream considerations Whenever natural gas is valued at downstream locations for royalty purposes, a major source of litigation brought by private royalty owners is what post-production costs may be deducted. Some state courts have held that the producer has an implied duty to the royalty owner to put the gas in “marketable condition” and that the royalty owner should not share in costs incurred by the producer up to that point. Because of the shift in judicial interpretations of “marketable condition,” which varies from state to state, the deductibility of costs such as transportation, processing, treatment, compression, dehydration and marketing have all been the subject of extensive royalty litigation. See, e.g., Heritage Resources Inc. v. NationsBank, 939 S.W.2d 118 (Texas 1996); Mittelstaedt v. Santa Fe Minerals Inc., 954 P.2d 1203 (Okla. 1998); Sternberger v. Marathon Oil Co., 894 P.2d 788 (Kan. 1995); Rogers v. Westerman Farm Co., 29 P.3d 887 (Colo. 2001). For royalties on federal lands, a tapestry of interpretations has resulted from decisions by federal courts, the Interior Board of Land Appeals (IBLA) and the Minerals Management Service (MMS), which manages federal royalties under the Department of the Interior’s authority. For valuation purposes, dispositions of production are deemed either “arm’s-length contracts” with third parties, or “nonarm’s-length transactions” with an affiliate of the producer. For arm’s-length contracts, MMS regulations specify royalty valuation on “gross proceeds” less allowances. Valuing nonarm’s-length transactions, however, requires value to be imputed by reference to various measures (e.g., comparable sales, spot prices, other indices) that can vary by location and region. An MMS rule requires the producer to put the oil or gas into “marketable condition” without cost to the lessor. This means “sufficiently free from impurities and otherwise in a condition a purchaser will accept under a sales contract typical for the field or area.” 30 C.F.R. 206.101 (oil), 206.151 (gas). A litigated issue is whether marketable condition has come to include gathering, compression and dehydration. Costs for transportation and processing, however, are indisputably deductible from federal royalties. The 1996-2003 period was particularly busy, as various decisions from IBLA and the federal courts countered one another with regard to royalty valuation and the deductibility of downstream costs from royalties. In several cases, the type of affiliate that had purchased the gas from the producing company was a key issue. Two decisions, in particular, have served to clarify some of these issues: Independent Petroleum Assoc’n of America [IPAA] v. Dewitt, 279 F.3d 1036 (D.C. Cir. 2002) and Fina Oil and Chemical Co. v. Norton, 332 F.3d 672 (D.C. Cir. 2003). IPAA v. Dewitt is relevant to both gas and crude oil production and stemmed from the IPAA and the American Petroleum Institute consolidated challenge of the 1996 MMS gas transportation rule. At issue was MMS’ denial of deductions from royalties for all downstream costs, except transportation costs. Reversing a district court opinion, the U.S. Circuit Court for the District of Columbia upheld MMS’ denial of deductions for marketing costs, whether at the lease or downstream, but held that firm-demand charges are not marketing costs but rather deductible transportation charges. Separate from the Dewitt litigation, MMS transportation allowances have evolved to include deductions for some costs of offshore platforms allocable to the support of platform transportation equipment, including gas-compression equipment and, in some cases, on-lease gathering lines in deepwater fields. Fina v. Norton focused on affiliate sales. The D.C. Circuit held on June 27, 2003, that when gas is sold, the valuation for royalty payments on federal lands should be based on the initial sales by the producer, not resales by nonmarketing affiliates. Fina, at 673. The D.C. Circuit’s decision reversed a district court opinion that had upheld the U.S. Department of the Interior’s interpretation of federal gas-valuation regulations using its “gross proceeds” rule to require gas sold to any affiliate to be valued based on the affiliate’s downstream resale price (i.e., the selling price occurring at the point where the gas leaves the corporate family of companies). 30 C.F.R. 206.151. The decision focused, in part, on the definition of the term “lessee” as used in the gross proceeds rule, which required gas, at a minimum, to be valued based on the gross proceeds received by the “lessee.” Fina, at 676-677. The court determined that the term “lessee” was specifically defined in the regulations and the underlying statute, the Federal Oil and Gas Royalty Management Act, to refer only to proceeds accruing to the corporate entity that holds a lease, not to affiliates. According to the court, the regulation, as written, permits lessees to pay federal royalties on gas before its value is increased by the transportation services of affiliates, except for a narrowly defined marketing affiliate, namely, a party that sold the lessee’s production exclusively. Fina, at 677. Another area of interest are qui tam suits that claim knowing underpayment by producers and their affiliates of royalties on production from federal lands, which have increased significantly in the past 10 years. The False Claims Act qui tam provision allows individuals claiming knowledge of underpayment to the government to bring lawsuits (as “relators”) on the federal government’s behalf for treble damages plus attorney fees. The relator can receive a bounty of 15% to 30% of any damages recovered for the government from a successful action (whether litigated or settled). Qui tam royalty allegations The qui tam allegations in royalty cases fall into two broad categories: under-measurement of gas and oil volumes at the wellhead, and undervaluation of oil and gas. A qui tam jury verdict related to oil measurement was obtained in Oklahoma in 1999 against an oil purchaser and later settled for $25 million. United States ex rel. Koch v. Koch Indus. Inc., No. 91-CV-763 (N.D. Okla.). In 2000, a major qui tam suit against 18 major oil producers was settled for more than $400 million. United States ex. rel. Johnson v. Shell Oil Co., No. 9:96-CV-66 (E.D. Texas). Currently, a large consolidated case involving gas measurement is pending: In re Natural Gas Royalties Qui Tam Litigation, MDL No. 1293 (D. Wyo.). Another qui tam suit against a large number of gas producers alleges undervaluation of natural gas. United States ex rel. Wright v. AGIP Petroleum Co., No. 03-CV-264 (E.D. Texas). The outcome of these suits may clarify whether the False Claims Act is an appropriate vehicle for enforcement of complex federal regulations on royalties. An alternative to paying royalties based on the value of production (which has generated so much litigation) is royalty-in-kind, which has been getting close scrutiny from the MMS, in addition to enthusiastic industry support. When royalties are paid in kind, the producer simply delivers the royalty share (typically one-sixth or one-eighth) in actual oil or gas, which the royalty owner then markets on its own for the best price it can obtain. The Outer Continental Shelf Lands Act has always allowed the secretary of the interior to take royalties-in-kind rather than in-value. Since the mid-1990s, royalties-in-kind use has grown significantly as a way to satisfy federal royalty obligations. Presidential directives to use federal royalty oil to fill the Strategic Petroleum Reserve have been a boon to the royalty-in-kind concept. As of January 2003, the MMS reported that royalties-in-kind accounted for 70% of the nation’s outer continental shelf (OCS) royalty crude oil, a significant portion of the onshore federal royalty crude, and 15% of OCS royalty gas. While royalties-in-kind cannot be expected to replace royalties-in-value completely, their obvious benefit is in avoiding complex valuation issues and the many disputes they spawn. Provisions allowing the agency to optimize the use of royalties-in-kind have been an important part of recent Department of the Interior appropriation bills and are included in the pending (as of this writing) national energy legislation. If passed, the royalties-in-kind provisions would help to clear away some of the fog of litigation surrounding federal oil and gas royalty issues. Daniel M. McClure is a partner in the home office of Houston-based Fulbright & Jaworski. L. Poe Leggette is a partner, and David T. Deal is senior counsel, at the firm’s Washington office.

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