The New Marketable Condition Rule: Is It Really New or Has it Been this Way All Along? John F. Shepherd February 13, 2019

The Marketable Condition Rule Lessee bears all costs of putting oil, gas, and other products into “marketable condition.” Lessee cannot deduct those costs. If purchaser pays the cost, lessee must pay royalty on that amount.

Gas Typically Sold at Wellhead 1930s-1980s Gas Typically Sold at Wellhead

No definition of “marketable condition” Early Regulations “It is an obligation of the lessee to put into marketable condition all products produced from the leased land and pay royalty thereon, without recourse to the lessor for deductions on account of cost of treatment or of costs of shipping.” [1936 Operating Regulations] No definition of “marketable condition”

The Texas Co. (DOI 1957) Early Cases Sales contract required delivery of gas in field at 1,000 psi. Gas not marketable until it met terms of sales contract. Emphasizes no transportation or manufacturing involved.

California Co. v. Udall (D.C. Cir. 1961) Early Cases California Co. v. Udall (D.C. Cir. 1961) Sales contract required gas suitable for PL – a “short distance” from wells. Treating and compression costs not deductible. Emphasizes no transportation or manufacturing involved. Marketing vs. “merely selling.”

USGS Manual Marketable condition means “gas of sufficient pressure to enter the marketing facilities for the field or area.” “Field or area” means “that geographic subdivision which can be considered as representing a common source of production or marketing facilities.”

Continue marketable condition rule Define terms 1988 Regulations Continue marketable condition rule Define terms Definition based in part on California Co. v. Udall and USGS Manual.

Definition in 1988 Regulations Marketable condition “means 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 C.F.R. 1206.151]

Definitions of Field and Area Field defined as “a geographic region situated over one or more subsurface oil and gas reservoirs encompassing the outermost boundaries of all oil and gas accumulations known to be within those reservoirs vertically projected to the land surface.” Area defined as “a geographic region at least as large as the defined limits of an oil and/or gas field, in which oil and/or gas lease products have similar quality, economic, and legal characteristics.”

Purpose of costs important Relevant market is at or near lease MCR Principles 1989-2000 No per se rules Purpose of costs important Relevant market is at or near lease Not a distant market Need sufficient pressure to enter buyer’s PL in field Evidence gas marketable at lease? Own sales contract probably not enough Competitive offers from multiple buyers

Market of concern not the one “50 miles away from the leasehold.” The Beartooth Case MCR “does not require the lessee to condition the gas so that it is suitable for secondary or retail markets.” Market of concern not the one “50 miles away from the leasehold.” Remanded case because record did “not contain evidence of what is typical for the field from which Beartooth produces.”

The Xeno Case Lessee sold gas at wellhead to affiliated gathering entity, which resold gas to Montana Power Co. Lessee had multiple offers to purchase gas at wellhead without gathering or compression. Board held that costs of compression and gathering were deductible as transportation costs.

Xeno, cont’d “While the cost of gathering gas from the wellhead and moving it to a nearby delivery point in the field has been disallowed as a cost required to place the production in marketable condition where the lessee is obligated to do so under the sales contract, the evidence shows that in this case the gas is in marketable condition at the wellhead.”

1996 CBM “Dear Payor” Letter In 1996, MMS issues “Dear Payor” letter on valuing CBM. Costs of removing CO2 not deductible. Costs of dehydration and compression after royalty measurement point are deductible as transportation allowance.

The Amoco Decision (D.C. Cir. 2005) Wellhead sales of untreated CBM did not establish marketable condition. Resales on mainline PLs were “most common” sale. MCR “does not contain a geographic limit.” While producer position plausible, MMS view just as plausible.

In 2003, Assistant Secretary issues “royalty value determination.” The Devon Decision In 2003, Assistant Secretary issues “royalty value determination.” Disavows 1996 Dear Payor Letter. Requires Devon to bear all costs of compression & dehydration to meet pipeline specs. Decision notes no sales of CBM at or near wellhead.

The Devon Decision (cont’d) Upholds agency interpretation. Agrees “Dear Payor” letters not binding.

2010 “Dear Reporter” Letter Oct. 6, 2010, ONRR extends rationale of Devon to conventional gas. Unbundles fees paid under transportation and processing contracts. “Non-deductible marketable conditioning costs” include: Compression/dehydration necessary for pipeline CO2 removal Boosting residue gas

Cases After Amoco and Devon Burlington (IBLA 2013), aff’d (N.D. Okla. 2014) IBLA said wellhead contracts for sale of wet gas did not = marketable condition. Gas not marketable until ready for sale to “ultimate purchaser.” District court upholds “dominant end-use” test for marketable condition.

Cases After Amoco and Devon Encana (IBLA 2014), appeal pending Under MCR, gas must meet pressure and quality specs to enter PL where “the gas is actually sold.” For gas produced in Colorado and transported to better markets in New Mexico, “it is the New Mexico market” that determines marketability. Pending appeal deals with application of Devon to compression costs (incl. residue boosting)

Interplay Between MCR & Boosting Rule Unbundling of Fees Current Issues Interplay Between MCR & Boosting Rule Unbundling of Fees Compression to plant for NGLs

MMS/ONRR interpretation has evolved Conclusions MCR itself not new MMS/ONRR interpretation has evolved Interpretation has led to other issues