New ONRR initiative sets presumptive costs of making gas marketable and will require lessees to affirmatively demonstrate costs that differ from ONRR assumptions.
The Department of Interior, Office of Natural Resources Revenue (ONRR),1 is responsible for collecting royalties on gas produced from Federal and Indian lands. In calculating the value of the production on which royalties are assessed, ONRR allows lessees producing gas from Federal and Indian lands (Lessees) to deduct the cost of processing or transporting gas from the value of production, but does not allow Lessees to deduct the cost of placing residue gas and plant products in marketable condition. Until now, Lessees have differentiated between the costs of processing and transporting gas from the costs of making gas or residue gas and plant products marketable (Marketable Condition Costs) on their own. In a new enforcement initiative, ONRR is now promulgating its own calculations for how to “unbundle” these costs, including a much broader and more aggressive definition of the relevant Marketable Condition Costs. ONRR’s enforcement initiative may sharply reduce the amount of fees and expenses that were previously deductible as processing or transportation allowances by reclassifying certain costs as Marketable Condition Costs. In light of ONRR’s new enforcement initiative, Lessees must affirmatively take steps to ensure that they are not required to pay unwarranted additional royalties.
Background: Applicable Law
Lessees Must Pay Royalties on the Value of Production
Under the Mineral Leasing Act of 1920 and its implementing regulations promulgated (Gas Royalty Regulations), Lessees must pay royalties on the “value of production” from these lands.2 For purposes of calculating the value of production, Lessees are required to absorb Marketable Condition Costs.3 If gas, residue gas or gas plant products are sold before they are placed in marketable condition, ONRR may add Marketable Condition Costs to the sales price to determine the value of the production for the purpose of calculating royalties.4
By contrast, Lessees are not required to process gas (separate natural gas liquids from residue gas) or to transport gas from a lease to a point off the lease or from a gas processing plant to a point away from the plant at their own expense. If a Lessee sells gas prior to processing, then royalties are assessed on the unprocessed gas.5 If a Lessee processes the gas, then for purposes of calculating the value of production, the Lessee may deduct a processing allowance to account for the costs of processing.6 Lessees may also deduct transportation allowances for permissible transportation costs.7
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Lessees Must Determine When Gas, Residue Gas and Gas Plant Products Are “Marketable”
The Gas Royalty Regulations for gas produced from Federal lands define “marketable condition” as “lease products which are sufficiently free from impurities and otherwise in a condition that they will be accepted by a purchaser under a sales contract typical for the field or area.”8 The Gas Royalty Regulations for gas produced from Indian lands contain a nearly-identical definition.9
Lessees must answer several questions in order to determine what constitutes “marketable condition” with respect to their particular sales so that they may calculate their Marketable Condition Costs. Lessees must determine what constitutes a “typical” sales contract and what is the “field or area” for which this determination is made.10 In addition, Lessees must differentiate between transportation and processing costs, which are deductible, and Marketable Condition Costs, which are not.
The mere fact that a purchaser is willing to accept gas in its natural state does not render gas “marketable,” because such sales may not be typical of the field or area.11 The D.C. Circuit has held that ONRR may plausibly conclude that a demonstration that contracts for one-fifth of the lease production are not common enough to be “typical.”12 While no decision has clearly demarcated a bright-line threshold for what constitutes “typical,” in Amoco Prod. Co. v. Watson, 410 F.3d 722 (D.C. Cir. 2005), the court held that ONRR may permissibly read “typical” as “the most common use and sale of gas from the area.”13
The D.C. Circuit has also held that the marketable condition rule does not require the physical leasehold to be the relevant geographic market for assessing what constitutes “marketable” gas.14 Rather, ONRR has focused on the area where the gas is ultimately consumed, and the D.C. Circuit has upheld this interpretation.15 Under this rubric, if “the dominant market for gas from the area is for gas that is utilized in distant markets” then the gas must be marketable in those distant markets and the assessment of what contracts are “typical” will be made with respect to the contracts selling gas to those distant markets.16 By this logic, Lessees have been required to pay for the costs of the compression, treatment, and conditioning necessary to meet pipeline specifications for delivery to these distant areas.17 The D.C. Circuit recently restated the requirement as a mandate that Lessees “compress and dehydrate gas to meet the requirements of the pipelines that serve its typical purchasers.”18
Because Lessees must include costs of placing the gas in a “marketable condition” for purposes of calculating the value of production, but may exclude processing and transportation costs, it is important for Lessees to be able to differentiate between these costs. Processes like compression and treatment, which may be necessary in order to transport or process gas, may also be necessary to render gas marketable. Courts have held that if an expense is necessary to make gas marketable, the expense cannot also be deducted as a transportation cost.19
ONRR Marketable Condition Rule Enforcement Initiative
Until now, the determination of the costs that properly may be deducted as processing and transportation allowances and those costs that must be included in the value of production as Marketable Condition Costs has been made only through audits and individual decisions by the Interior Board of Land Appeals and the courts evaluating disputes between Lessees and ONRR. Lessees have determined on their own which costs are attributable to processing and transportation and which costs are necessary for making gas marketable. Lessees have been forced to alter their determinations only when ONRR objected to their cost determinations in an audit. At times, ONRR has issued “Dear Operator” letters approving calculations of royalties by Lessees.
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Recently, however, ONRR has begun a campaign to more rigorously enforce the marketable condition requirement. Significantly, ONRR has adopted the aggressive stance that some of the costs of processing gas may constitute Marketable Condition Costs.20 The Agency is proceeding by establishing presumptive costs of placing gas in a marketable condition for cases where a Lessee transports and processes gas under arm’s-length agreements (so-called Unbundling Cost Allocations or UCAs).21 ONRR is establishing UCAs on a region-by-region basis and has developed a priority queue for the order of regions for which the Agency plans to calculate UCAs.22 For regions without UCAs, ONRR has directed Lessees to calculate their own unbundling costs.23 ONRR is requiring Lessees to use available cost data to calculate such costs.24 For situations where data is not available, ONRR is developing a method that uses engineering estimates.25
ONRR has successfully maintained that “Dear Operator” letters are not binding on it, and the burden of proving that gas in an area is typically sold without compression, treatment or conditioning is on the Lessee.26 Similarly, courts have held that where ONRR has made findings to support its determination of what costs must be included as necessary to make gas marketable, courts and the Interior Board of Land Appeals have placed the burden on Lessees to establish compression, treatment and conditioning costs that differ from those set by ONRR.27
The ONRR calculated UCAs reportedly have sharply decreased the amount of fees and expenses which were previously deductible as processing or transportation allowances.28 In a series of presentations to industry stakeholders, staff members from ONRR (acting outside of their official capacity) have stated that ONRR plans to interpret the marketable condition rule aggressively.29 These presentations suggest that ONRR may push the boundaries of recent court decisions interpreting the Mineral Leasing Act of 1920 and the Gas Royalty Regulations.
Furthermore, ONRR staff has cautioned the industry that the Agency will pursue stringent penalties against producers who fail to abide by its regulations, stating that “ONRR refers cases it believes constitute ‘false claims’ under the False Claims Act to the Office of Inspector General and Department of Justice.”30 ONRR staff has noted that “[a]ny incorrect Form ONRR-2014 that has a royalty consequence may constitute a ‘false claim.’”31 According to an industry group, ONRR is assessing reporting penalties for reporting errors even where the amount of royalties paid is correct.32 ONRR and the United States Department of Justice have shown a willingness to pursue qui tam actions based on allegedly improper deductions of marketing fees in the past. In one case alleging various forms of royalty fraud, including the improper deduction of marketing fees, settlements to date exceed $280 million.33
How Lessees Can Avoid Unwarranted Additional Royalties
Lessees can take several steps to avoid paying royalties in excess of those prescribed by the Mineral Leasing Act of 1920 and the Gas Royalty Regulations.
First, Lessees should endeavor to quantify and maximize processing costs. Processing includes an operation designed to separate raw gas into separate marketable products, including natural gas liquids, as well as marketable chemicals, such as sulphur — provided that the chemicals are actually turned into marketable products.34 Lessees may also benefit from separately identifying and minimizing compression, treatment and/or conditioning costs necessary to render gas marketable and not include such costs as part of their processing and transportation costs. Where compression, treatment and/or conditioning are bundled with processing or transportation costs in processing and/or transportation agreements, Lessees could develop the separate costs of compression, treatment and/or conditioning necessary to meet
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marketability requirements. Unbundling costs could benefit Lessees who sell unprocessed gas to an affiliate, or Lessees who sell processed gas.
Accurate accounting of these costs will allow Lessees to identify the amount at issue in any dispute about the applicable Marketable Condition Costs or, if the point is not disputed as suggested above, to more accurately claim processing and transportation allowances. This accurate accounting would also provide Lessees with evidence necessary to rebut any presumptive costs that ONRR may assess using unbundling assumptions that overstate the costs of making gas marketable or understate processing or transportation costs.
However, maintaining accurate accounting records may require modifying existing accounting processes to capture relevant data. For example, companies currently may capture data in an aggregate manner that does not facilitate separating out Marketable Condition Costs. To capture data in a manner that will allow defensible unbundling of recoverable from unrecoverable costs, Lessees may need to change accounting methods to separately capture these costs. If this is not possible, Lessees should develop a methodology that allocates costs on a reasonable basis. Implementing the processes to capture or develop the necessary information as part of the ordinary course of business prior to any dispute will increase a Lessee’s probability of success in safeguarding all deductions to which a Lessee is properly entitled.
Develop Evidence Regarding Gas Quality and Pressure
Second, if possible, Lessees should develop convincing evidence regarding the quality and pressure at which gas from the field or area in which the Lessee produces gas is typically marketed to the destination markets into which the gas is typically sold prior to compression, treatment and/or conditioning. Once ONRR sets a UCA for a region into which a Lessee’s gas is sold, the burden will fall to the Lessee to provide information demonstrating a Lessee’s costs in order to claim any royalty that provides for Marketable Condition Costs that differ from those set in ONRR’s UCA. Where gas from an area is typically marketed before compression treatment and/or conditioning, Lessees should be able to satisfy this burden by developing convincing evidence showing that this is the case. Further, instances may arise in which some compression, treatment and/or conditioning is required to make gas marketable, but a Lessee provides more than is required. By demonstrating the quality and pressure at which gas in an area is typically sold, a Lessee can ensure that such “extra” costs are not used to increase royalty payments and are not part of the value of production on which royalty payments are calculated.
Collaborate with ONRR on Regional Estimates
Third, Lessees may work with ONRR to develop regional estimates of the costs necessary to meet marketability requirements. By supplying ONRR with accurate information regarding these costs, Lessees can reduce the likelihood that these costs will be overstated in UCAs calculated by ONRR.
Comprehensively Analyze ONRR’s Methods
Fourth, each Lessee should carry out a comprehensive analysis of ONRR’s methods of determining the Lessee’s costs of making gas marketable, to assess whether ONRR has used inaccurate simplifying assumptions which overstate those costs.
While there are many potential inaccuracies in ONRR’s approach, one example is that ONRR assumes that the cost of compression is linear (e.g., where pipeline specifications require 1200 psi, if a Lessee has compressed gas to 1600 psi, ONRR may allow deduction of ¼ of the costs of compression).35 In this example, if a Lessee’s costs of compressing the gas beyond pipeline specifications are actually greater on a unit basis than the costs of compressing the gas to pipeline specifications, then by identifying
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ONRR’s inaccurate assumption and clearly demonstrating its costs, a Lessee may avoid being assessed unwarranted additional royalties.
Challenge ONRR’s Interpretation of the Gas Royalty Regulations
Fifth, Lessees selling processed gas or Lessees selling unprocessed gas to an affiliate who will then process the gas may seek to challenge ONRR’s interpretation that the costs of processing gas constitute costs of making gas marketable. Based on the text of the Gas Royalty Regulations, Lessees could argue that costs necessary to turn gas into residue gas and gas plant products (i.e., to process gas) by definition do not constitute marketing costs.36 Arguably, ONRR’s new unbundling initiative conflates placing unprocessed gas in marketable condition with placing residue gas and plant products in marketable condition. ONRR is supporting its expanded interpretation of Marketable Condition Costs by relying on cases in which Lessees have not been allowed to deduct compression and treatment costs of coalbed methane gas, which is not necessarily a comparable situation.37
Royalties for coalbed methane are determined under 30 C.F.R. § 1206.152, which is the general regulation for the assessment of royalties on unprocessed gas on Federal lands. These regulations require the Lessee to place “gas” in a marketable condition. By contrast, the regulations covering processed gas extracted from Federal lands are in 30 C.F.R. § 1206.153. These regulations require Lessees to place “residue gas and gas plant products” in marketable condition.38 Because residue gas and gas plant products have already been processed, Lessees may argue that — except as specifically provided in the regulations covering processing allowances — any costs that are inherent to processing the gas do not constitute Marketable Condition Costs. However, the Gas Royalty Regulations covering processing allowances also specify that except for certain extraordinary costs approved by ONRR “no processing cost deduction shall be allowed for the costs of placing lease products in marketable condition, including dehydration, separation, compression, or storage.”39 Accordingly, ONRR could argue that “lease products” include raw gas. Lessees might respond that the lease products at issue are residue gas and gas plant products and therefore the marketing costs referenced in the processing regulations refer only to the costs of dehydrating, separating, compressing and storing those products.40
The regulations for gas produced from Indian lands require a Lessee to place “gas, residue gas, and gas plant products in marketable condition.”41 Unlike the regulations for gas produced from Federal lands, the regulations for gas produced from Indian lands do not regulate unprocessed gas and processed gas under different provisions. But a similar textual argument may be advanced for gas produced on Indian lands because gas, residue gas, and gas plant products are each separately required to be placed in marketable condition. This language implies that where a Lessee sells processed gas, the marketable condition rule applies to the “residue gas and gas plant products” that are being marketed and sold, suggesting that the marketable condition requirement for processed gas produced from Indian lands may only bar the deduction of costs that are not necessary to turn the gas into residue gas and gas plant products.
Take Antitrust Issues Into Account
Lessees should be mindful of antitrust issues in developing the relevant information regarding the quality and pressure of gas typical of the destination markets into which its gas is sold. Lessees should utilize legal counsel and outside experts to develop and sanitize data when data from multiple producers is required.
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If you have questions about this Client Alert, please contact one of the authors listed below or the Latham lawyer with whom you normally consult:
Kenneth M. Simon
Miles B. Farmer
The authors thank Michael J. Webb, Ph.D., a Director of the Regulatory Economics Group, LLC in Herndon, Virginia for identifying issues addressed in this Client Alert and for suggesting some of the methods that lessees may use to avoid excessive royalties.
Client Alert is published by Latham & Watkins as a news reporting service to clients and other friends. The information contained in this publication should not be construed as legal advice. Should further analysis or explanation of the subject matter be required, please contact the lawyer with whom you normally consult. A complete list of Latham’s Client Alerts can be found at www.lw.com. If you wish to update your contact details or customize the information you receive from Latham & Watkins, visit http://events.lw.com/reaction/subscriptionpage.html to subscribe to the firm’s global client mailings program.
1 Until 2010, an agency within the Department of Interior, the Minerals Management Service (MMS), promulgated and administered regulations establishing procedures for the collecting royalties, setting royalty rates, and determining the value of production under Federal and Indian leases for the purpose of calculating federal royalty payments. Following a reorganization in 2010, responsibility for assessing royalties lay briefly with the Bureau of Ocean Energy Management, Regulation and Enforcement (BOEMRE), and since October 1, 2010, has rested with ONRR. For the sake of simplicity, references to ONRR in this article refer to BOEMRE and/or MMS as appropriate.
2 See 30 C.F.R. Part 1206, Sub-part D (Federal gas), Sub-part E (Indian gas).
3 30 C.F.R. §§ 1206.152(i), 1206.153(i) (Federal gas), § 1206.174(h) (Indian gas).
4 See 30 C.F.R. §§ 1206.152(i), 1206.153(i) (Federal gas), § 1206.174(h) (Indian gas) (the value on which royalties are calculated “must be increased to the extent that the gross proceeds have been reduced because the purchaser, or any other person, is providing certain services to place the gas, residue gas, or gas plant products in marketable condition or to market the gas”).
5 30 C.F.R. § 1206.152 (Federal gas); Part 1206, Sub-part E (Indian gas).
6 30 C.F.R. § 1206.158 (Federal gas), § 1206.179 (Indian gas).
7 30 C.F.R. § 1206.157 (Federal gas), § 1206.177-78.
8 30 C.F.R. § 1206.151.
9 The Gas Royalty Regulations for valuation of Indian gas define “marketable condition” in a nearly identical manner, as “a condition in which lease products are sufficiently free from impurities and otherwise so conditioned that a purchaser will accept them under a sales contract typical for the field or area.” 30 C.F.R. § 1206.171
10 See Energy Corp. v. Kempthorne, 551 F.3d 1030, 1037 (D.C. Cir. 2008) (Devon) (producers contested an MMS royalty order, advancing different interpretations of “typical” and “field or area” than the agency); Amoco Prod. Co. v. Watson, 410 F.3d 722, 729 (D.C. Cir. 2005) (Amoco) (same).
11 See California Co. v. Udall, 296 F.2d 384, 387-88 (D.C. Cir. 1961) (explaining the distinction between “marketing” and “selling” gas).
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12 Amoco at 730 (emphasis in original).
14 Devon at 1037; Amoco at 728.
15 See Amoco at 729-31.
16 Devon at 1037 ; Amoco at 729-31.
17 Devon at 1035.
18 Id. at 1037.
19 See Devon; Amoco at 731.
20 See Inderbitzin, The Marketable Condition Rule (presented to the Petroleum Accountants Society of Oklahoma, Feb. 6, 2013), at 23 (Inderbitzin I); Inderbitzin, The Marketable Condition Rule (presented at the ONRR Unbundling Workshop, June 24-25, 2013), at 24 (Inderbitzin II).
21 ONRR states in a disclaimer on the website for its unbundling initiative that the UCAs do not apply to situations where a Lessee transports and processes gas under non-arm’s-length agreements. See http://onrr.gov/Unbundling/default.htm (last accessed Feb. 11, 2014).
22 For a list “tentative” list showing of the regions that ONRR has selected to evaluate in 2013, and a “tentative” list of regions ONRR has selected to evaluate in 2014 and 2015 and designated priority of each, see Inderbitzin, Office of Enforcement & Appeals Federal Royalty Unbundling Information (presented at the National Oil and Gas Royalty Conference, October 21-22, 2013), at 7-9 (Inderbitzin III). Note that the relative priority of various plants has changed. See Ginley and Shishido-Sheahan, IPANM Unbundling Session Cost Allocation (presented at the ONRR Unbundling Workshop, June 24-25, 2013), at 9-11 (“Ginley”), available at http://www.ipanm.org/images/library/File/Govnmt%20presentations(1).pdf.
23 See Inderbitzin III at 10.
24 See Id. at 25.
25 Id. at 29-31.
26 See Devon at 1035, 1039.
27 See Devon at 1037-38; Burlington Resources Oil & Gas Co., 183 I.B.L.A. 333, 352 (2013).
28 Independent Petroleum Ass’n of New Mexico, The Marketable Condition Rule: Federal and NM, at 5 (IPANM Annual Meeting 2013) (IPANM).
29 See, e.g., Inderbitzin I; Inderbitzin II; Inderbitzin III, Ginley.
30 See Inderbitzin II at 25
32 IPANM at 13.
33 See Press Release, Department of Justice, Total Companies to Pay U.S. $15 Million to Resolve Allegations of Royalty Underpayments from Federal and Indian Lands (Feb. 22, 2012), available at http://www.justice.gov/opa/pr/2012/February/12-civ-240.html; Third Amended Complaint, United States ex rel. Wright. v. Chevron USA Inc., No. 5:03-cv-00264-MHS-CMC (E.D. Tex. 2000), ECF No. 104.
34 The Gas Royalty Regulations specify that where gas is sweetened “no processing cost deduction shall be allowed for such costs unless the acid gases removed are further processed into a gas plant product.” 30 C.F.R. § 1206.158(d).
35 See Inderbitzin I at 26.
36 Brad Welsh introduced this argument in a presentation to the Independent Petroleum Association of New Mexico. See Welsh, Comments on the Federal Marketable Condition Rules (Presented at the ONRR Unbundling Workshop, June 24-25, 2013), at 4-8.
37 See Inderbitzin I at 23; Inderbitzin II at 24.
38 30 C.F.R. § 1206.153(i).
39 30 C.F.R. § 1206.158(d). Identical language is contained in the regulations covering gas produced from Indian Lands. See 30 C.F.R. § 1206.179(d).
40 Note that this argument may not apply to Lessees who sell unprocessed gas at arm’s length, because the value of production in such cases is determined under 30 C.F.R. § 1206.152 and not 30 C.F.R. § 1206.153. For example, Lessees selling unprocessed gas pursuant to Percentage-of-the-Proceeds contracts may be required to include treatment and compression costs determined to be Marketable Condition Costs in the value of production. See Citation Oil & Gas Corp. v. U.S. Dep’t of Interior, 448 Fed. Appx. 441 (5th Cir. 2011).
41 30 C.F.R. § 1206.174(h).