ONRR ROYALTY UPDATE: THE MARKETABLE CONDITION RULE AND UNBUNDLING PENDING RIK IMBALANCE RESOLUTION LITIGATION
| Jurisdiction | United States |
(Jan 2016)
ONRR ROYALTY UPDATE: THE MARKETABLE CONDITION RULE AND UNBUNDLING PENDING RIK IMBALANCE RESOLUTION LITIGATION
Judith M. Matlock
Partner
Davis Graham & Stubbs LLP
Denver, CO
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JUDITH M. MATLOCK is a partner in the Energy Group of the Denver law firm of Davis, Graham & Stubbs LLP. She has practiced in the area of natural resources law for over thirty years. She is involved in all aspects of the gathering, transportation, processing, fractionation and marketing of natural gas, liquids and crude oil and representing producers in connection with the calculation, payment and reporting of royalties and production taxes. She assists clients with federal royalty data mining requests, compliance reviews, audits, and appeals. She also prepares and submits unbundling proposals under the federal marketable condition rule. She received her undergraduate degree (B.A. 1979) from the University of Colorado at Denver and her law degree (J.D. 1982) from the University of Colorado at Boulder. She is a member of Phi Beta Kappa, Order of the Coif, and the Denver, Colorado, and American Bar Associations. She has been named in The Best Lawyers in America® (oil and gas) since 1995. She is an active participant in the Rocky Mountain Mineral Law Foundation and has served on the Executive Committee, as a trustee, and co-chair of the Special Institutes Committee. She has also been the program chair for several RMMLF special institutes and short courses, was the program chair for the 2010 Annual Institute, and is a frequent lecturer and writer on energy topics.
This paper is one of two papers for the "ONRR Royalty Update." This paper covers ONRR's marketable condition rule and the associated unbundling requirement, and the pending litigation concerning resolution of the gas imbalances existing at the time the royalty in kind (RIK) program was terminated.
I. Unbundling of Transportation and Processing Costs to Comply with the Marketable Condition Rule
A. Introduction
In 2015, the Office of Natural Resources Revenue ("ONRR") started doing compliance reviews of onshore and offshore federal lessees to determine whether they were in compliance with the marketable condition requirements of the gas valuation regulations.1 Under the interpretation of the marketable condition rule announced in the Devon Decision,2 gas is not in marketable condition until it is of the quality and at the pressure required for the receiving pipeline(s) that will transport the gas to the markets for which the gas is destined (referred to by the agency as the "mainline pipeline"). In most cases, gas is destined for the interstate market and, therefore, the marketable condition requirement is measured by interstate pipeline quality and pressure requirements. Furthermore, even if gas is in marketable condition for quality and pressure before it reaches a gas processing plant (often the case for offshore production), separation and handling of scrubber condensate and residue gas boosting at the plant are disallowed marketable condition costs. Fuel (gas or electricity) used to perform marketable condition services is also considered a marketable condition cost and royalties must be paid on such fuel.
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Federal lessees may not include in their transportation and processing allowances, any costs incurred to put their gas into marketable condition. If they sell their gas before it is in marketable condition, they must gross up the value to the extent their gross proceeds were reduced by costs to put their gas into marketable condition. The burden of proof is on federal lessees to determine what portion of their transportation and processing costs are disallowed marketable condition costs. This requires federal lessees to "unbundle" their transportation and processing costs into allowed and disallowed costs. ONRR has "unbundled" some transportation systems and processing plants and posted Unbundling Cost Allocations or "UCAs" (allowed and disallowed percentages of transportation and processing costs) which may be used in lieu of a federal lessee doing its own unbundling. However, this does not mean that federal lessees may wait on ONRR before complying with the marketable condition rule. Rather, in that situation, federal lessees must do their own unbundling or take no transportation and processing allowances. Failure to comply with the marketable condition rule can give rise to penalty liability.
B. Definition of marketable condition
The definition of "marketable condition" in the current gas valuation regulations (adopted in 1988) is "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." 30 CFR § 1206.151 . Federal lessees (and lessees of Indian leases not in an Index Zone) are required to put their production into marketable condition at no cost to the lessor.3
On December 8, 1995, the Minerals Management Service (predecessor to the Office of Natural Resources Revenue) issued a Compression Guidance Memorandum which stated:
A lessee's gross proceeds may not be reduced by the cost of compression, whether incurred directly or indirectly, which is performed to meet the delivery requirement for pressure of the
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pipeline immediately downstream of the BLM or MMS approved measurement point. Such compression is deemed to be for placing the gas into marketable condition.
The cost of compression, whether incurred directly or indirectly, which is performed after meeting the delivery requirement for pressure of the pipeline immediately downstream of the BLM or MMS approved measurement point, is an allowable deduction from royalty as part of the lessee's cost of transportation. [Emphasis added.] 4
Additionally, on April 22, 1996, the MMS issued a Dear Payor Letter which stated:
Costs for compression downstream of the royalty measurement point, to the extent necessary for transportation, can be included in the transportation allowance.
Costs of dehydration occurring after metering at the royalty measurement point can be taken in the transportation allowance.
In October 2003, the Assistant Secretary of the United States Department of the Interior issued a valuation determination to Devon Energy Corporation concerning coalbed methane production from the Kitty, Spotted Horse and Rough Draw Fields in the Powder River Basin, Wyoming (the "Devon Decision"). The valuation determination did not include any mandatory ordering language. On March 19, 2004, the Acting Assistant Secretary ordered Devon to perform a restructured accounting and pay additional royalties due to Devon's transportation deductions on certain compression costs. Because the decisions were issued by an Assistant Secretary of the Interior, it was the final action of the Department of the Interior and was not appealable to the Board of Land Appeals. Instead, it was immediately appealable to the courts. The Devon Decision was affirmed on appeal.5
The Devon Decision involved federal oil and gas leases located in a producing area in northern Wyoming known as the Powder River Basin. Coalbed methane gas was produced from wells located on the leases. The production occurred in three producing areas known as the Kitty, Spotted Horse, and Rough Draw Fields. As is typical of coalbed methane production, the gas flowed from the wells at very low pressures and also contained an impurity, carbon dioxide, which had to be removed from the gas.
Thunder Creek Gas Services LLC constructed a 126-mile pipeline from an area north-northwest of Gillette, Wyoming, in the Powder River Basin, almost due south. The Thunder Creek Pipeline began at what was called the Landeck Header and ended at the Buckshot Plant, a carbon dioxide treating facility located between Glenrock and Douglas, Wyoming. The "tailgate" or outlet of the plant was interconnected with two interstate pipeline companies, the CIG Powder River Lateral pipeline and the Wyoming Interstate Medicine Bow Lateral.
Devon's gas was compressed at four locations between the wellhead and the tailgate of the Buckshot Plant. Devon's coalbed methane gas flowed from the wells at a pressure of about 2 pounds
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per square inch ("psi"). The gas was compressed near the wellhead (within a few hundred feet to approximately 2.25 miles) in rotary screw compressors with a discharge pressure in the range of 80 to 100 psi. Then the gas was transported in small diameter pipelines a distance of between approximately 0.1 mile and 5.7 miles where it entered field boosters (reciprocating compressors) with a discharge pressure of 550 psi for gas from the Kitty and South Kitty Fields, 600 psi for gas from the Rough Draw Field, and 800 psi for gas from the Spotted Horse Field.
From the outlet of the reciprocating compressors, the gas was transported to pipeline interconnects at or a few miles south of the Landeck header on the Thunder Creek Pipeline.6 Before the gas from the Rough Draw Field reached the Landeck Header, Devon sold some of it to WBI at a pressure of 550 psi. The remaining gas entered the 126-mile long Thunder Creek Pipeline.
At a point approximately 28 miles south of the Landeck Header on the Thunder Creek Pipeline, the gas entered a large compressor called the MTG Booster. The MTG Booster compressed the gas to raise the pressure from an inlet pressure of 450-500 psi (the gas having lost some pressure due to friction by this point) to a discharge pressure of 1,200 psi. The gas then traveled the remaining approximately 90 miles to the Buckshot Plant. At the Buckshot Plant, carbon dioxide was removed, the gas was dehydrated, and the gas was compressed from an inlet pressure of approximately 800 psi to a discharge pressure of 1,100 psi. Devon sold some gas at the tailgate of the Buckshot Plant but the balance of the gas was...
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