CHAPTER 4 BUREAU OF LAND MANAGEMENT RULES AFFECTING ROYALTY REPORTING AND PAYMENT

• Jurisdiction: United States

Federal and Indian Oil & Gas Royalty Valuation and Management
(Oct 2018)
CHAPTER 4
BUREAU OF LAND MANAGEMENT RULES AFFECTING ROYALTY REPORTING AND PAYMENT
Kathleen C. Schroder ¹
Davis Graham & Stubbs LLP
Denver, CO

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KATIE SCHRODER is a partner at Davis Graham & Stubbs LLP in Denver, where her practice focuses on all aspects of energy development on federal lands. Ms. Schroder counsels clients on oil and gas leasing and development on federal lands and agency compliance with the National Environmental Policy Act and the National Historic Preservation Act. She has extensive experience with the Endangered Species Act, including the process for listing species as threatened or endangered, the process for obtaining permits under section 10 of the Act, and the development of conservation agreements for candidate species. She also advises on federal royalty issues. Ms. Schroder is active with the Rocky Mountain Mineral Law Foundation and chairs its Publications Committee. Previously, she has served as a trustee to this organization and authored several papers. She sits on the board of directors of Western Energy Alliance and is a former chair of the Public Land and Resources Committee within the ABA's Section of Environment, Energy, and Resources. Ms. Schroder began her career as an attorney-advisor in the U.S. Department of the Interior's Office of the Solicitor as part of the Solicitor's Honors Program. She then spent 10 years with a boutique law firm in Denver. She holds a B.A. from Rice University and a J.D. from the University of Colorado School of Law. After law school, she clerked for Justice Alex J. Martinez of the Colorado Supreme Court.

I. Introduction

The Bureau of Land Management ("BLM") oversees operations on federal and Indian onshore oil and gas leases² and, as part of these responsibilities, makes determinations that affect the reporting and payment of royalty on these leases, even though the Office of Natural Resources Revenue ("ONRR") is charged with collecting such royalty.³ This paper discusses the two key determinations that impact royalty reporting and payment over which BLM has responsibility: measurement of production and production that is exempt from royalty.

Historically, only one agency--the Conservation Division of the United States Geological Survey ("USGS")--determined royalty on production from onshore oil and gas leases.⁴ In 1982, Secretary of the Interior James G. Watt created the Minerals Management Service ("MMS") to assume the functions of the USGS's Conservation Division.⁵ The following year, Secretary Watt assigned royalty and mineral revenue management functions to MMS and transferred all remaining onshore mineral management functions to BLM.⁶

Despite the seemingly clean division of responsibilities, BLM retained a role in the Department of Interior's responsibility for ensuring the American public and Indian tribes and allottees are fairly compensated for the extraction and sale of their oil and gas resources. First, it determines the measurement points of volumes and qualities of oil and natural gas produced from federal leases on which royalty is due.⁷ Second, it determines when royalty is not due on production, either because the production was used on a federal or Indian lease, unit, or communitized area or because the production was unavoidably lost.⁸

II. Production Measurement

Generally, BLM requires measurement of production leaving a lease or, if a lease is unitized or communitized, production removed from the unit or communitized area. The Mineral Leasing Act of 1920, as amended, ("MLA") provides the statutory basis for measurement of production leaving a lease, unit, or communitized area because the MLA imposes royalty "at a rate of not less than 12.5 percent in

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amount or value of the production removed or sold from the lease.⁹ BLM establishes requirements for and verifies the measurement of royalty-bearing production removed from a lease, unit, or communitized area at a facility measurement point ("FMP"). BLM may, however, allow production to be measured off lease; BLM may also allow production from multiple leases, unit participating areas ("PAs"), and communitized areas to be commingled prior to the point of royalty measurement.

A. Facility Measurement Points

The physical location where BLM requires measurement of production removed from a lease, unit, or communitized area is a decision "entrusted solely" to BLM.¹⁰ Until 2016, BLM did not formally define the point of production measurement for royalty purposes. Rather, agency guidance identified the point of royalty measurement as the place where "production is last measured before leaving the leasehold," unless BLM had approved off-lease measurement.¹¹

In 2010, the Government Accountability Office ("GAO") criticized BLM for not tracking onshore production measurement points, explaining that the lack of this information "creates uncertainty about the location of the official point of measurement and complicates production verification work."¹² The GAO later reiterated these concerns, and the Department of the Interior's Office of Inspector General made similar observations.¹³ The GAO recommended that BLM track onshore meters, including meter locations and owners, and assign an identification number to meters, similar to how the Bureau of Safety and Environmental Environment tracks offshore measurement points.¹⁴ The GAO also recommended that onshore operators report meter identification numbers in monthly production reports.¹⁵

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In 2016, BLM updated its existing Onshore Oil and Gas Order No. 3, Site Security, ("Onshore Order 3") which had been in effect since 1989.¹⁶ This update, which BLM incorporated into the Code of Federal Regulations at 43 C.F.R. subpart 3173, established "a formal nationwide process for designating and approving the point at which oil or gas must be measured for the purpose of determining royalty."¹⁷ BLM regulations now require operators of federal and Indian onshore oil and gas leases to obtain BLM approval of FMPs to determine the volume and quality of production for purposes of determining royalty due.¹⁸ This requirement applies both to new and existing facilities.¹⁹

Notably, the Department of the Interior has announced it intends to propose revisions to its regulations at 43 C.F.R. subpart 3173 in 2019.²⁰ Therefore, the requirements outlined below may change.²¹

What is an FMP?

BLM defines an FMP as a "BLM-approved point where oil or gas produced from a Federal or Indian lease, unit PA, or [communitization agreement] is measured and the measurement affects the calculation of the volume or quality of production on which royalty is owed."²² FMPs include (1) approved points of royalty measurement; (2) measurement points that determine the allocation of production to federal and Indian leases, unit PAs, and communitization agreements ("CAs") for commingling approvals granted before July 9, 2013 or on; and (3) meters or measurement facilities used in the determination of the volume or quality of royalty-bearing oil and gas produced before BLM approves an FMP.²³ Allocation facilities that are part of a commingling and allocation approval ("CAA")

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approved after July 9, 2013 are not considered FMPs.²⁴ BLM will not approve a gas processing plant tailgate meter that is located off a lease, unit, or communitized area as an FMP.²⁵

What is a point of royalty measurement and how is it related to an FMP?

BLM defines a "point of royalty measurement" (also known as a "point of royalty settlement") as "a BLM-approved FMP at which the volume and quality of oil or gas which is subject to royalty is measured."²⁶ Points of royalty measurement do not include allocation meters.²⁷ FMPs can, however, include both points of royalty measurement and certain allocation meters.²⁸ Thus, all points of royalty measurement are FMPs, but not all FMPs are points of royalty measurement.

Where must an operator locate an FMP?

Operators must locate their FMPs within the boundaries of a lease, unit, or communitized area from which the production originated, unless BLM approves otherwise.²⁹ The FMP can be located "anywhere within the boundary of a lease, a unit, or a CA from which the production originates."³⁰

What equipment requires an approved FMP?

Only permanent measurement facilities, which are defined as "equipment constructed or installed and used on-site for 6 months or longer," require an approved FMP.³¹ Temporary equipment used during well testing operations, including temporary tanks to store oil, do not require an FMP.³²

An approved FMP is required for "each oil measurement facility where the measurement affects the calculation of the volume or quality of production on which royalty is owed," such as an "oil tank used for tank gauging, [lease automatic custody transfer] system, [Coriolis measurement system], or other approved metering device."³³ Meters used for allocation under a CAA issued under 43 C.F.R. § 3174.2(h) do not require an approved FMP.³⁴

When an operator removes oil or gas downstream of an FMP and uses that oil or gas royalty free, then the operator must apply for an FMP approval to measure the oil or gas that is removed for royalty-free use.³⁵

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What production can an FMP measure?

FMPs may only measure production from the lease, unit PA, or communitized area on which the FMP is located, unless BLM approves otherwise.³⁶

How does an operator apply for FMP approval?

Operators apply for FMP approvals by submitting the following:

A Form 3160-5, Sundry Notices and Reports on Wells ("Sundry Notice") requiring approval of each FMP;

The applicable Measurement Type Code specified in the Well Information System;

A legal description of the land on which the FMP will be located;

The API well numbers, if production from more than one well will flow to the FMP;

For FMPs for gas, the

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