JurisdictionUnited States
Federal & Indian Oil & Gas Royalty Valuation and Management II
(Feb 1998)


Judith M. Matlock
Davis, Graham & Stubbs LLP
Denver, Colorado
Steven P. Williams
Enron Oil and Gas Company
Denver, Colorado

January 1998


On December 16, 1997, the Minerals Management Service ("MMS") issued amendments to its transportation allowance regulations for Federal and Indian leases (the "1997 Amendments").1 The 1997 Amendments are effective February 1, 1998.

The purpose of the 1997 Amendments was to provide specific guidance and certainty as to which transportation cost components resulting from implementing FERC Order 6362 and previous FERC orders3 are deductible in the transportation allowance for purposes of calculating federal royalties. The 1997 Amendments also apply to intrastate pipeline charges to the extent the same types of changes and issues as were raised by FERC Order 636 are relevant to intrastate pipeline transportation service.4

The 1997 Amendments also include amendments to the MMS' gas valuation regulations. The MMS characterizes these amendments as "related to" the transportation amendments.

[Page 6B-2]

The 1997 Amendments divide transportation costs, as that term is understood by industry, into two categories based upon whether such costs are related to transportation (deductible) or related to marketing (not deductible) in the MMS' view.5 The division is as follows:

Deductible Transportation Nondeductible Marketing
Firm demand charges (pipeline charges for the reservation of firm capacity; must be paid whether or not the capacity is used) — deductible only for the actual volumes transported; no adjustment for capacity releases losses or gains; subject to reduction for penalty refunds, rate case refunds or other reasons Firm demand charges to the extent not used for actual volumes
Commodity Charges (pipeline charges for the actual volumes transported) Penalties incurred by shippers including, but not limited to, over-delivery cash-out penalties, scheduling penalties, imbalance penalties, and operational penalties.
Wheeling costs (charges by hub operators for transporting gas from one pipeline to the same or another pipeline through a market center or hub) Intra-hub transfer fees (fees paid to hub operators for administrative services, such as title transfer tracking, necessary to account for the sale of gas within a hub)
Temporary storage service — whether actual or provided as a matter of accounting — limited to 30 days or less Long term storage — fees or costs incurred for storage, including storing production in a storage facility, whether on or off the lease, for more than 30 days
Gas Supply Realignment Costs (FERC-approved costs resulting from a pipeline reforming or terminating supply contracts with producers to implement the restructuring requirements of FERC Orders in 18 CFR part 284)

[Page 6B-3]

Gas Research Institute fees (provided they are mandatory in FERC-approved tariffs) Gas Research Institute fees to the extent they are not mandatory in FERC-approved tariffs
Annual Charge Adjustment fees (fees charged by FERC to pipelines to pay for FERC's operating expenses)
Line loss payments (payments either volumetric or in value for actual or theoretical losses; not applicable to non-arm's length transportation arrangements unless the transportation allowance is based on a FERC or State regulatory approved tariff Line loss payments applicable to non-arm's length transportation arrangements where there is no FERC or State regulatory approved tariff
Supplemental costs for compression, dehydration and treatment—only if such services are required for transportation and exceed the services necessary to place production into marketable condition Aggregator/marketer fees—fees paid to another person, including an affiliate, to market gas including purchasing and reselling the gas or finding or maintaining a market for the gas production.

As to financial transactions, the MMS recognized in the preamble to the 1997 Amendments that, "certain lessee gas transportation arrangements result in financial transactions not directly associated with the gas value" and stated that, "[s]uch transactions may not have royalty consequences."6 Federal lessees may request valuation guidance if they are uncertain about the royalty consequences of their financial transactions.7

The "related" amendments to the gas valuation regulations add the following (underlined) language to the existing provision on the duty to put gas into marketable condition:

(i) The lessee must place gas in marketable condition and market the gas for the mutual benefit of the lessee and the lessor at no cost to the Federal Government. Where the value established under this section is determined by a lessee's gross proceeds, that value will be increased to the extent that the gross proceeds have been reduced because the purchaser, or any other person, is providing certain services the cost of

[Page 6B-4]

which ordinarily is the responsibility of the lessee to place the gas in marketable condition or to market the gas.8

These underlined provisions will be referred to in this paper as the "1997 Marketing Amendments."

The MMS explained the 1997 Marketing Amendments as follows:

The final rule clarifies the principle that lessees cannot deduct from royalty value the costs of marketing production from Federal and Indian leases. The final rule adds specific language [the language underlined above] to paragraph (i) [section references] to expressly state lessees' obligation to incur all marketing costs. ... We believe that the added language contains the concept embodied in the implied covenant to market for the mutual benefit of Federal and Indian oil and gas lessees and lessors. We further believe this imposes no additional marketing burden on the lessee than existing requirements.9

In addition to receiving comments from companies and industry trade associations, the MMS received comments from State representatives, a State/Indian association, two Indian tribes, and one Indian tribal association. The MMS agreed with industry and not the States and Indian commenters on many issues and, given the relative length of the deductible column above as compared to the nondeductible column above, one would think that industry should consider the 1997 Amendments a victory.

In fact, however, many in industry are quite upset with the amendments and their potential interpretation. Industry is concerned that just because FERC Order No. 636 and prior orders have made it possible for producers to sell their production downstream of pipeline mainline receipt points, they will now be required to pay royalties as if they had done so.

It is not just the "obligation to market for the mutual benefit of the lessee and the lessor" language which causes this concern. It is also the fact that the MMS found it necessary to categorize transportation costs at all that raises this concern. The fact is very few producers sell their production downstream of pipeline mainline receipt points. Thus, in only the handful of situations where producers do so should the 1997 Amendments be necessary.

The reason very few producers sell their production downstream of pipeline mainline receipt points is that producers recognize that the marketing of natural gas downstream of interstate and intrastate pipeline receipt points has always been and still is an entirely separate

[Page 6B-5]

business from the business of exploring for and producing natural gas. Producers who have decided to get into that business generally do so through affiliates, not to avoid royalties as royalty owners are so quick to assume, but to avoid putting their oil and gas assets at risk for the liabilities of that separate business. The Courts have always supported this as a valid business purpose.10

For all producers, the 1997 Amendments create uncertainty about their duty to market. For producers engaged in the downstream marketing of gas either directly or through affiliates, the 1997 Amendments ignore the separate nature of that business and impose a penalty for engaging in that business. For producers engaged in that business through affiliates, the 1997 Amendments appear to take lessees further down the Shell v. Babbit11 road which threatens to abrogate the priority scheme of the benchmark valuation regulations for gas not sold pursuant to arm's-length contracts in favor of imputing an affiliate's gross proceeds to the producer.

The purpose of this paper is to provide an historical analysis of the scope of the federal lessee's duty to market and the parameters of the transportation allowance, to summarize and clarify pertinent provisions of FERC Order No. 636, and to analyze whether the 1997 Amendments have expanded or have to potential to expand the royalty payment obligations of lessees beyond what is authorized by the Mineral Leasing Act of 1920, as amended.12

The Physical Delivery of Gas

The physical delivery of natural gas occurs in one continuous process. Unlike oil, natural gas cannot be hauled to market in trucks or railroad cars. Natural gas must be transported, under pressure, through pipelines from the wells where it is produced to the burner tip where it is consumed. At the wellhead, natural gas is delivered into generally small diameter, low pressure gathering lines which eventually connect with larger diameter, higher pressure transmission lines (interstate or intrastate)13 at mainline receipt points. Processing of the

[Page 6B-6]

natural gas to remove impurities (such as hydrogen sulfide or excessive carbon dioxide) and natural gas liquids (such as ethane, propane, butane, and natural gasoline) may occur before or after delivery of the gas into a transmission line...

To continue reading

Request your trial

VLEX uses login cookies to provide you with a better browsing experience. If you click on 'Accept' or continue browsing this site we consider that you accept our cookie policy. ACCEPT