CAUTION: New Federal Oil And Gas Royalty Regulations Take Effect January 1, 2017

The U.S. Department of Interior recently announced new regulations (effective January 1, 2017) governing how federal royalties on oil and gas produced from federal leases are to be calculated. These regulations make some significant changes on how lessees are to value the production of natural gas from federal leases for the purposes of determining federal royalties. Some notable changes, with a focus on natural gas, are briefly addressed below, but the regulations should be viewed in their entirety in light of the specific marketing, transportation and processing circumstances involved.

● Valuation of Unprocessed Gas

For non-arm’s length sales of unprocessed gas, the Office of Natural Resources Revenue (ONRR) is eliminating the valuation “benchmarks.” Instead, where a lessee’s sale of natural gas is to an affiliate, the new regulations require the lessee to (1) pay royalties based on the gross proceeds received in the first arm’s-length sale by the lessee’s affiliate or, (2) at the option of the lessee, pay royalties based on an index pricing methodology. For arm’s length sales, the lessee must value unprocessed gas based on its gross proceeds and may not use the index pricing method.

The optional index pricing method for non-arm’s length sales looks to where a lessee’s gas could physically flow. If the gas stream could flow to several index pricing points, the index price method requires the lessee to use “the highest reported monthly bidweek price for the index pricing points to which your gas could be transported for the production month, whether or not there are constraints for that production month.” 30 C.F.R. 1206.41(c)(1)(ii). If a lessee can only transport gas to one index pricing point published in an ONRR-approved publication, value is to be determined by the highest reported monthly bidweek price for that index. 30 C.F.R. 1206.14(cc)(1)(i). For onshore production, the index price value is reduced by 10 percent (but not less than 10 cents per MMBtu or more than 30 cents per MMBtu), to account for transportation and no separate transportation allowance is allowed. Once a lessee selects an ONRR approved publication the lessee may not select a different publication more often than once every two years.

● Valuation of Processed Gas

Under the new regulations, where a lessee sells gas under an arm’s length “keepwhole” or “percentage of proceeds” contract, the lessee must calculate royalties for the gas as “processed gas.” 30 C.F.R. 1206.142(a). For example, where a lessee enters into an arm’s length sales contract for the sale of gas prior to processing, but the contract provides for payment to be determined on the basis of the value of any products resulting from processing, including residue gas or natural gas liquids, the gas must be valued as processed gas – namely, based on 100% of the value of residue gas, 100% of the value of gas plant products, plus the value of any condensate recovered downstream of the point of royalty settlement prior to processing, less applicable transportation and processing allowances. The lessee may not deduct, directly or indirectly, costs for boosting residue gas at a processing plant or for fuel associated therewith. The new regulations place increased burdens on lessees who sell gas in an arm’s length contract under a keepwhole or percentage of proceeds agreement to “unbundle” costs and value natural gas liquids and residue gas recovered from processing in order to properly calculate federal royalties.

For non-arm’s length sales of processed gas, the regulations also eliminated the “benchmarks” and require the lessee to value residue gas and gas plant products by using the gross proceeds received under the first arm’s-length sales price or an optional index price method. Again, the index method for processed gas is only available where the lessee did not sell production under an arm’s length contract. The optional Index price methodology includes approved index pricing for natural gas liquids (NGLs) with a stated deduction from the index pricing points to account for processing costs (based on a minimum rather than average processing rate as determined by the ONRR) and a reduction for transportation and fractionation (T&F), also at a stated amount. No separate transportation or processing allowance may be claimed if this option is used.

● Firm Cap on Transportation and Processing Allowances and Elimination of Transportation Factors

The new regulations make the 50% value cap on transportation and the 66 and 2/3rd value cap on processing allowances firm. The ONRR no longer has the discretion to permit larger allowances for extraordinary circumstances. ONRR has also eliminated transportation factors (netting of transportation costs as part of sale’s price) and now requires transportation factors to be stated in an equivalent monetary amount and claimed as a transportation allowance.

● Marketable Condition

 The new regulations continue to employ the ever expanding “marketable product” rule by providing, among other things, that transportation allowances may not include costs attributable to transporting non-royalty bearing substances commingled in the wellhead gas stream, by requiring royalty to be paid on gas used as fuel, lost or unaccounted for (FL&U) (except FL&U in an arm’s length contract based on a FERC or State approved tariff), and by disallowing deductions for the costs of boosting residue gas during processing, including any fuel used for boosting. In its comments for requiring wet gas sold at the well under percentage of proceeds (POP) contracts to be valued as “processed gas,” for example, Department of Interior asserted:

[P]ast regulations did place the responsibility on lessees who sell their gas at the wellhead under POP-type contracts to place the residue gas and gas plant products into marketable condition at no cost to the Federal Government. Simply selling the gas at the wellhead does not mean the gas is in marketable condition –one must look to the requirements of the main sales pipeline. . . . “Whether gas is marketable depends on the requirements of the dominant end-user, and not those of intermediate processors.” 81 Fed. Reg. 43348 (unreported case citation omitted).

● Default Provisions

The new regulations also contain “default” provisions that allow the ONRR to reject a lessee’s valuation or allowances and determine valuation and allowances by looking to other market indicia of value and allowances, and these default provisions will apply if: (1) there is no written sales contract, transportation agreement or processing agreement signed by all parties to the contract, or (2) the ONRR determines the lessee has failed to comply with applicable regulations because of, among other things, (a) misconduct by or between the contracting parties, (b) the lessee breached its duty to market the gas, (c) ONRR determines the value of gas, residue gas or gas plant product is unreasonably low (ONRR may consider a sales price unreasonably low if it is 10 percent less than the lowest reasonable measures of market price, including index prices and prices reported to ONRR for like-quality gas, residue gas or gas plant products) or (d) the lessee fails to provide adequate supporting documentation.

The new federal royalty regulations for natural gas produced from federal leases may require lessees to make significant changes in how they report and pay federal royalties, particularly where a lessee sells gas under percentage of proceeds or keepwhole sales contracts. Application of these new regulations should be carefully reviewed in light of the lessee’s sale, transportation and processing arrangements to avoid potential interest and penalties.