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DEPARTMENT OF THE INTERIOR
Bureau of Indian Affairs
25 CFR Part 226
[Docket No. BIA–2022–0006; 2231A2100DD/
AAKC001030/A0A501010.999900; OMB
Control Number 1076–0180, 1012–0004,
1012–0006]
RIN 1076–AF59

Mining of the Osage Mineral Estate for
Oil and Gas
Bureau of Indian Affairs,
Interior.
ACTION: Proposed rule.
AGENCY:

The Bureau of Indian Affairs
(BIA) proposes to revise the regulations
governing leasing of the Osage Nation’s
mineral estate (‘‘Osage Mineral Estate’’)
for oil and gas mining. The proposed
rule would allow the BIA to strengthen
management of the Osage Mineral Estate
by updating bonding, royalty payment
and reporting, production valuation and
measurement, site security, and
operational requirements to address
changes in technology and industry
standards that have occurred in the 47
years since the regulations were issued.
The proposed rule would also allow the
BIA to respond to recommendations
made by the Office of Inspector General,
U.S. Department of the Interior (OIG).
DATES: Proposed Regulations: Submit
your comments on the proposed rule to
the BIA on or before March 17, 2023.
Information Collection Requirements:
Submit your comments on the
information collection requirements in
the proposed rule on or before March
17, 2023. Public Meeting: A public
meeting will be held on February 8,
2023, 6:30 p.m. to 9 p.m. central time.
ADDRESSES:
Proposed Regulations: You may
submit your comments on the proposed
rule by any of the methods listed below.
• Federal Rulemaking Portal: https://
www.regulations.gov. Enter ‘‘RIN 1076–
AF59’’ in the search box and click
‘‘Search.’’ Follow the instructions for
sending comments.
• Mail: U.S. Department of the
Interior, Eastern Oklahoma Region,
Bureau of Indian Affairs, Attn: Regional
Director, P.O. Box 8002, Muskogee, OK
74402. All submissions must include
the words ‘‘Bureau of Indian Affairs’’ or
‘‘BIA’’ and ‘‘RIN 1076–AF59.’’
• Hand Delivery/Courier: U.S.
Department of the Interior, Eastern
Oklahoma Region, Bureau of Indian
Affairs, Attn: Regional Director, 3100 W
Peak Boulevard, Muskogee, OK 74402.
Public Meeting: The BIA is holding a
public meeting on the Proposed Rule on

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SUMMARY:

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Wednesday, February 8, 2023, from 6:30
p.m. to 9 p.m. central time at the Osage
Casino and Hotel, 5591 W Rogers
Boulevard, Skiatook, OK 74070. Please
see SUPPLEMENTARY INFORMATION,
Section II, Public Comment Procedures,
for details.
Information Collection Requirements:
Comments on the information collection
requirements in the proposed rule must
be submitted to Steven Mullen,
Information Collection Clearance
Officer, Office of Regulatory Affairs and
Collaborative Action—Indian Affairs,
U.S. Department of the Interior, 1001
Indian School Road NW, Suite 229,
Albuquerque, NM 87104; or by email to
[email protected] with a copy to
[email protected].
All submissions must include the
applicable Office of Management and
Budget (OMB) Control Number(s) for the
BIA or ONRR information collection(s)
you are commenting on:
• OMB Control Number 1076–0180,
Mining of the Osage Mineral Estate for
Oil and Gas.
• OMB Control Number 1012–0004,
Royalty and Production Reporting.
• OMB Control Number 1012–0006,
Suspensions Pending Appeal and
Bonding.
FOR FURTHER INFORMATION CONTACT:
Oliver Whaley, Director, Office of
Regulatory Affairs and Collaborative
Action, Office of the Assistant
Secretary—Indian Affairs, (202) 738–
6065, [email protected].
SUPPLEMENTARY INFORMATION:
I. Executive Summary
II. Public Comment Procedures
III. Background
IV. Incorporation by Reference of Industry
Standards
V. Discussion of Proposed Changes
VI. Procedural Matters

I. Executive Summary
The purpose of this proposed rule is
to amend 25 CFR part 226, Leasing of
Osage Reservation Lands for Oil and Gas
Mining, to strengthen the Bureau of
Indian Affairs’ (BIA) management and
administration of the Osage Mineral
Estate. The last major substantive
revisions to the regulations in 25 CFR
part 226 occurred in 1974, with many
provisions having remained virtually
unchanged since well before then. As a
result, the regulations are outdated,
inconsistent with industry standards,
and do not reflect technological
advancements or modern oil and gas
operations within the Osage Mineral
Estate. The BIA believes that the
proposed rule updating the regulations
makes critical changes that will improve
accounting and production
measurement standards; offer

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consistency in production valuation;
address inadequate bonding; support
the implementation of electronic
reporting systems; enhance
accountability; clarify lessees’
obligations; prevent waste; promote safe
and environmentally sound operations;
and protect resource values. The BIA
also believes that the proposed rule will
allow it to take the necessary actions to
resolve certain recommendations made
by the Office of Inspector General, U.S.
Department of the Interior (OIG).
In 2013, the OIG performed an
assessment of the BIA Osage Agency’s
effectiveness in managing the Osage
Mineral Estate. On October 20, 2014, the
OIG issued its final evaluation report,
titled ‘‘BIA Needs Sweeping Changes to
Manage the Osage Nation’s Energy
Resources.’’ While the OIG
acknowledged the complexity of
managing the Osage Mineral Estate due,
in part, to the number of competing
interests, it documented multiple
deficiencies in the BIA Osage Agency’s
management of the oil and gas program
and called for broad reform.
The OIG report set forth 33
recommendations for improvement of
the BIA Osage Agency’s oil and gas
program. The first issue the OIG report
addressed was deficiencies in the
regulations in 25 CFR part 226.
Specifically, the OIG found that the
existing regulations are vague,
inadequate, and fail to mirror the oil
and gas regulations governing the rest of
Indian country. Accordingly, the OIG
recommended that the BIA ‘‘use its
authority to correct program
deficiencies by modifying 25 CFR part
226 to mirror other Indian Country oil
and gas regulations.’’ The OIG also
identified issues with accounting,
reconciliation, bonding requirements,
royalty and production reporting,
inspections, lease compliance, and
enforcement measures, among other
things. The BIA Osage Agency resolved
26 of the OIG’s recommendations
through the implementation of new and
revised policies and procedures but
determined that the remaining seven
recommendations could not be fully
resolved without revision of the
regulations in 25 CFR part 226.
This proposed rule modernizes the
regulations and brings them in line with
the regulations governing oil and gas
leasing and development throughout the
rest of Indian country consistent with
the OIG’s recommendation. In addition,
the proposed rule will allow the BIA
Osage Agency to respond to the open
OIG recommendations regarding
engagement of the Office of Natural
Resources Revenue (ONRR) to perform
accounting and compliance activities,

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implementation of ONRR’s electronic
reporting systems, reconciliation of
royalty payments, verification of
allowances and arm’s-length sales
transactions, and the implementation of
sampling thresholds. These revisions
are critical to ensure that oil and gas
produced from the Osage Mineral Estate
is properly accounted for and lessees
timely pay the correct and full amount
of royalties due to the Osage Nation.
II. Public Comment Procedures
If you wish to comment on this
proposed rule, you may submit your
comments to the BIA by mail, hand
delivery/courier, or through https://
www.regulations.gov (see ADDRESSES).
Please make your comments on the
proposed rule as specific as possible,
provide a detailed explanation of any
changes you recommend, and include
any relevant supporting documentation.
Where possible, your comments should
reference the specific section or
paragraph of the proposed rule that you
are addressing. The BIA is not obligated
to consider comments received after the
comment period closes (see DATES) or
comments delivered to an address, or
using methods other than, those
identified (see ADDRESSES).
Comments, including the names and
street addresses of respondents, will be
available for public review at the BIA
Eastern Oklahoma Regional Office, 3100
W Peak Boulevard, Muskogee, OK
74402, during regular business hours (8
a.m. to 4:30 p.m.), Monday through
Friday, except holidays. Before
including your address, phone number,
email address, or other personal
identifying information in your
comment, please be advised that your
entire comment—including your
personal identifying information—may
be made publicly available at any time.
While you can ask the BIA to withhold
your personal identifying information
from public review in your comment,
we cannot guarantee that we will be
able to do so. As discussed in detail
below, this proposed rule would
include revisions to information
collection requirements that must be
approved by the Office of Management
and Budget (OMB). If you wish to
comment on the revised information
collection requirements in this proposed
rule, you must send such comments
directly to the OMB (see ADDRESSES).
The BIA is holding a public meeting
on the Proposed Rule on Wednesday,
February 8, 2023, from 6:30 p.m. to 9
p.m. central time at the Osage Casino
and Hotel, 5591 West Rogers Boulevard,
Skiatook, OK 74070. At the meeting,
you may sign up for a two-minute time
slot to provide verbal comments on the

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Proposed Rule. The BIA requests that
groups or organizations wishing to
provide verbal comments elect a single
representative to speak on behalf of the
group or organization.
III. Background
A. Osage Allotment Act
In 1872, the U.S. Congress established
a reservation for the Osage Nation in the
Oklahoma Territory. On June 16, 1906,
Congress passed the Oklahoma Enabling
Act, Public Law 59–234, 34 Stat. 256,
joining the Oklahoma Territory with
Indian Territory to form the state of
Oklahoma. Shortly thereafter, Congress
passed the Act of June 28, 1906, Public
Law 59–321, 34 Stat. 539 (1906 Act),
titled an ‘‘Act for the division of the
lands and funds of the Osage Indians in
Oklahoma Territory.’’ The 1906 Act
provided for the allotment of the Osage
Nation’s lands to individual Tribal
members. Upon statehood in 1907, the
Osage Indian Reservation, comprising
approximately 1,475,000 acres, became
Osage County, Oklahoma.
Section 3 of the 1906 Act, as
amended, severed the surface estate
from the subsurface mineral estate,
reserving all oil, gas, coal, and other
minerals to the Osage Nation in
perpetuity. Accordingly, the United
States holds the subsurface mineral
estate in Osage County, Oklahoma
(‘‘Osage Mineral Estate’’) in trust for the
benefit of the Osage Nation. The 1906
Act authorizes the Osage Nation to lease
the Osage Mineral Estate for oil, gas, and
other mineral development ‘‘with the
approval of the Secretary of the Interior,
and under such rules and regulations as
he may prescribe.’’ The Secretary of the
Interior delegated this authority to the
Superintendent of the BIA Osage
Agency. See 209 Departmental Manual
8.1(A).
Section 4 of the 1906 Act, as
amended, required that the United
States hold the revenues derived from
the Osage Mineral Estate in trust and
distribute the funds to individual Tribal
members on the authorized roll of
membership in a timely (quarterly) and
proper (pro rata with interest) basis.
This prospective right to share in the
royalties, rental, and bonuses derived
from the Osage Mineral Estate is
referred to as a ‘‘headright.’’ See Act of
October 30, 1984, Pub. L. 98–605,
section 11, 98 Stat. 3163.
B. Osage Tribal Trust Settlement and
Negotiated Rulemaking
On October 14, 2011, the United
States and Osage Nation signed the
Osage Tribal Trust Settlement
(Settlement) resolving litigation

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regarding the United States’ alleged
mismanagement of the Osage Mineral
Estate along with other unrelated breach
of trust claims. As part of the
Settlement, the Department of the
Interior (Department) agreed to engage
in negotiated rulemaking with the Osage
Nation pursuant to 5 U.S.C. 561–570a
and revise the regulations in 25 CFR
part 226 to improve management of the
Osage Mineral Estate. The negotiated
rulemaking process began on June 18,
2012, when the Department published a
notice of the intent to establish an Osage
Negotiated Rulemaking Committee
(Committee). See 77 FR 36226.
On July 31, 2012, the Department
announced the establishment of the
Committee, comprised of four Federal
Government representatives and five
members of the Osage Minerals Council
who were selected by Council vote. See
77 FR 45301. The Osage Minerals
Council representatives on the
Committee identified five priority areas
to be discussed during negotiations: (1)
modernization of royalty value and
royalty rate for oil production; (2)
modernization of royalty value, royalty
rate, and royalty calculations for gas
production; (3) strengthening drilling
obligations for oil lessees; (4) requiring
detailed electronic reporting by all
lessees; and (5) strengthening oil
gauging and gas meter inspection,
calibration, and adjustment.
The Committee held the first public
meeting in August 2012 and, except for
December 2012, met monthly until
April 2013. On April 25, 2013, the
Negotiated Rulemaking Committee
submitted its Consensus Report to the
Department on a package of proposed
revisions to the regulations, completing
the negotiated rulemaking process
required by the Settlement. The
Department published the proposed rule
based on the Committee’s
recommendations on August 28, 2013.
See 78 FR 53083. The Department
received, evaluated, and responded to a
significant number of public comments
on the proposed rule and amended the
regulations to make necessary changes
in accordance therewith. On May 11,
2015, the Department published the
final rule, which had an effective date
of July 10, 2015. See 80 FR 26994.
On July 1, 2015, the Osage Minerals
Council and Osage Producers
Association each filed suit in the U.S.
District Court for the Northern District
of Oklahoma (Court), seeking to enjoin
implementation of the final rule. The
arguments advanced in the lawsuits
included, among other things, claims
that the final rule conflicted with the
1906 Act, would impose administrative
costs that would lead to decreased

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production, and the Department failed
to complete the analyses required by the
Regulatory Flexibility and Small
Business Regulatory Enforcement Acts.
The Court consolidated the two lawsuits
and entered an order enjoining
implementation of the final rule
pending resolution of the litigation.
Upon review of the issues raised in
the litigation, the Department
determined that a voluntary remand of
the final rule was appropriate. The
Osage Minerals Council and Osage
Producers Association supported such
action. On November 19, 2015, the
Department filed the Joint Motion for
Voluntary Remand and the Court, in
turn, entered the Judgment of Remand.
As a result of the remand, the 2015 final
rule never went into effect. Accordingly,
the version of 25 CFR part 226 that was
in effect prior to publication of the final
rule remained operative. To ensure that
the correct version of the regulations
appeared in the CFR, the Department
published a final rule formally
confirming that the prior version of 25
CFR part 226 (last updated in 1974)
remained in full force and effect. See 81
FR 39572.

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C. Current Rulemaking
Following remand of the 2015 final
rule, the BIA determined that it was
appropriate to review the regulations in
25 CFR part 226 to consider whether,
and to what extent, the regulations
should be revised to strengthen the
BIA’s management and administration
of the Osage Mineral Estate. On
September 22, 2016, the BIA mailed
letters to the Principal Chief of the
Osage Nation and Chairman of the
Osage Minerals Council requesting
government-to-government consultation
(consultation) regarding the need for
such revisions. On October 25, 2016, the
BIA held a consultation with
representatives from the Osage Nation
Executive and Legislative Branches, the
Osage Minerals Council, and their legal
counsel, in Pawhuska, Oklahoma. The
outcome of the consultation was
agreement by all parties that revision of
the regulations was necessary. See
Section VI, Procedural Matters, for
additional information regarding the
Tribal consultation process for the
proposed rule.
The current effort to revise the
regulations in 25 CFR part 226 is not a
continuation of the negotiated
rulemaking process undertaken
pursuant to the Settlement, nor is it a
republication of the 2015 final rule.

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IV. Incorporation by Reference of
Industry Standards
This proposed rule would incorporate
industry standards and recommended
practices, either in whole or in part,
without republishing the standards in
their entirety in the CFR. This practice
is known as incorporation by reference
(IBR). These standards currently apply
to all federal and Indian lands except
those within Osage County, Oklahoma.
The BIA reviewed these standards and
determined that they achieve the intent
of 25 CFR 226.106 through 226.116 and
25 CFR 226.120 through 226.141 of the
proposed rule. The proposed rule
proposes to incorporate the versions of
the standards listed. Some of the
standards referenced would be
incorporated in their entirety. For other
standards, the BIA would incorporate
only those sections that are relevant to
the rule, meet the intent of 25 CFR
226.0, and do not require further
clarification.
The National Technology Transfer
and Advancement Act (NTTAA), Public
Law 104–113, 15 U.S.C. 3701, et seq.,
states that ‘‘all Federal agencies and
departments shall use technical
standards that are developed by
consensus standards bodies, using such
technical standards as a means to carry
out policy objectives or activities
determined by the agencies or
departments,’’ subject to certain
exceptions. The BIA may incorporate
these standards into its regulations by
reference without republishing the
standards in their entirety in the
regulations. The legal effect of IBR is
that the incorporated standards would
become regulatory requirements. The
incorporated standards, like any other
regulation, have the force and effect of
law. Accordingly, lessees and other
regulated parties would be required to
comply with the standards incorporated
by reference in the regulations.
The Office of the Federal Register
(OFR) regulations governing IBR are set
forth in 1 CFR part 51. The industry
standards for this proposed rule are
eligible for incorporation pursuant to 1
CFR 51.7 because, among other things,
they substantially reduce the volume of
material published in the Federal
Register; are published, bound,
numbered, and organized; and are
readily available to the public free of
charge or through purchase from the
standards organization or through
inspection at the BIA Osage Agency.
The IBR language in § 226.0 meets the
requirements set forth in 1 CFR 51.9.
Where appropriate, the BIA would
incorporate by reference an industry
standard governing a particular process

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and impose requirements that add to, or
modify, the requirements imposed by
that standard (e.g., the BIA sets a
specific value for a variable where the
industry standard proposed a range of
values or options).
All American Petroleum Institute
(API) materials are available for
inspection and purchase at the API, 200
Massachusetts Avenue NW, Suite 1100,
Washington, DC 20001, (202) 682–8000.
API also offers free, read-only access to
the standards in the API IBR Reading
Room at https://publications.api.org. All
American Gas Association (AGA)
standards are available for inspection
and purchase from AGA, 400 North
Capitol Street NW, Suite 450,
Washington, DC 20001, (202) 824–7000,
https://www.aga.org/publication-store.
All Gas Processors Association (GPA)
standards are available for inspection
and purchase from GPA, 6526 E 60th
Street, Tulsa, OK 74145, (918) 493–
3872, https://my.midstream
association.org/publications-store/
publications.
The following industry standards and
recommendations are proposed for
incorporation by reference, in whole or
in part, in subpart J of the proposed
rule:
• API Manual of Petroleum
Measurement Standards (MPMS),
Chapter 2—Tank Calibration, Section
2A, Measurement and Calibration of
Upright Cylindrical Tanks by the
Manual Tank Strapping Method; First
Edition, February 1995; Reaffirmed 2017
(‘‘API 2.2A’’). This standard describes
calibration procedures for upright
cylindrical tanks used for storing oil.
• API MPMS Chapter 2—Tank
Calibration, Section 2B, Calibration of
Upright Cylindrical Tanks Using the
Optical Reference Line Method; First
Edition, March 1989; Reaffirmed April
2019; Addendum 1, October 2019 (‘‘API
2.2B’’). This standard describes
measurement and calibration
procedures for determining the
diameters of upright welded cylindrical
tanks or vertical cylindrical tanks with
a smooth surface and either floating or
fixed roofs.
• API MPMS Chapter 2—Tank
Calibration, Section 2C, Calibration of
Upright Cylindrical Tanks Using the
Optical-triangulation Method; First
Edition, January 2002; Reaffirmed April
2019 (‘‘API 2.2C’’). This standard
describes a calibration procedure for
tanks above 26 feet in diameter with
cylindrical courses that are substantially
vertical.
• API MPMS Chapter 3.1A, Standard
Practice for the Manual Gauging of
Petroleum and Petroleum Products;
Third Edition, August 2013; Reaffirmed

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December 2018 (‘‘API 3.1A’’). This
standard describes the: (a) procedures
for manually gauging the liquid level of
petroleum and petroleum products in
non-pressure fixed roof tanks; (b)
procedures for manually gauging the
level of free water that may be found
with the petroleum or petroleum
products; (c) methods used to verify the
length of gauge tapes under field
conditions and the influence of bob
weights and temperature on the gauge
tape length; and (d) influences that may
affect the position of gauging reference
point (either the datum plate or the
reference gauge point).
• API MPMS Chapter 3—Tank
Gauging, Section 1B—Standard Practice
for Level Measurement of Liquid
Hydrocarbons in Stationary Tanks by
Automatic Tank Gauging; Third Edition,
April 2018 (‘‘API 3.1B’’). This standard
describes the level measurement of
liquid hydrocarbons in stationary, above
ground, atmospheric storage tanks using
ATGs. This standard also discusses
automatic tank gauging in general,
including the accuracy, installation,
commissioning, calibration, and
verification of ATGs that measure either
innage or ullage.
• API MPMS Chapter 3—Tank
Gauging, Section 6, Measurement of
Liquid Hydrocarbons by Hybrid Tank
Measurement Systems; First Edition,
February 2001; Errata September 2005;
Reaffirmed January 2017 (‘‘API 3.6’’).
This standard describes the selection,
installation, commissioning, calibration,
and verification of Hybrid Tank
Measurement Systems. This standard
also provides a method of uncertainty
analysis to enable users to select the
correct components and configurations
to address for the intended application.
• API MPMS Chapter 4—Proving
Systems, Section 1, Introduction; Third
Edition, February 2005; Reaffirmed June
2014 (‘‘API 4.1’’). Section 1 is a general
introduction to the subject of proving
meters.
• API MPMS Chapter 4—Proving
Systems, Section 2—Displacement
Provers; Third Edition, September 2003;
Reaffirmed March 2011; Addendum
February 2015 (‘‘API 4.2’’). This
standard outlines the essential elements
of meter provers that do, and do not,
accumulate a minimum of 10,000 whole
meter pulses between detector switches
and provides design and installation
details for the types of displacement
provers that are currently in use. The
provers discussed in this chapter are
designed for proving measurement
devices under dynamic operating
conditions with single-phase liquid
hydrocarbons.

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• API MPMS Chapter 4.5, MasterMeter Provers; Fourth Edition, June
2016 (‘‘API 4.5’’). This standard covers
the use of displacement and Coriolis
meters as master meters. The
requirements in this standard are for
single-phase liquid hydrocarbons.
• API MPMS Chapter 4—Proving
Systems, Section 6, Pulse Interpolation;
Second Edition, May 1999; Errata April
2007; Reaffirmed October 2013 (‘‘API
4.6’’). This standard describes how the
double-chronometry method of pulse
interpolation, including system
operating requirements and equipment
testing, is applied to meter proving.
• API MPMS Chapter 4.8, Operation
of Proving Systems; Second Edition,
September 2013 (‘‘API 4.8’’). This
standard provides information for
operating meter provers on single-phase
liquid hydrocarbons.
• API MPMS Chapter 4—Proving
Systems, Section 9—Methods of
Calibration for Displacement and
Volumetric Tank Provers, Part 2—
Determination of the Volume of
Displacement and Tank Provers by the
Waterdraw Method of Calibration; First
Edition, December 2005; Reaffirmed
July 2015 (‘‘API 4.9.2’’). This standard
provides all the procedures required to
determine the field data necessary to
calculate a Base Prover Volume of
Displacement Provers by the Waterdraw
Method of Calibration.
• API MPMS Chapter 5—Metering,
Section 6—Measurement of Liquid
Hydrocarbons by Coriolis Meters; First
Edition, October 2002; Reaffirmed
November 2013 (‘‘API 5.6’’). This
standard applies to custody-transfer
applications for liquid hydrocarbons
and covers the API standards used in
the operation of Coriolis meters, proving
and verification using volume-based
methods, installation, operation, and
maintenance.
• API MPMS Chapter 6, Metering
Assemblies, Section 1—Lease
Automatic Custody Transfer (LACT)
Systems; Second Edition, May 1991;
Reaffirmed May 2012 (‘‘API 6.1’’). This
standard describes the design,
installation, calibration, and operation
of a LACT system.
• API MPMS Chapter 7, Temperature
Determination, Section 1—Liquid-inGlass Thermometers; Second Edition,
August 2017 (‘‘API 7.1’’). This standard
describes how to use various types of
liquid-in-glass thermometers to
accurately determine the temperatures
of hydrocarbon liquids. This standard is
proposed for incorporation for its
standards covering the use of liquid-inglass thermometers for temperature
determination in tank-gauging
operations.

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• API MPMS Chapter 7—
Temperature Determination, Section 2—
Portable Electronic Thermometers;
Third Edition, May 2018 (‘‘API 7.2’’).
This standard describes the methods,
equipment, and procedures for
manually determining the temperature
of liquid petroleum and petroleum
products by use of a portable electronic
thermometer. This standard is proposed
for incorporation for its standards
covering the use of portable electronic
thermometers for temperature
determination in tank gauging
operations.
• API MPMS Chapter 7—
Temperature Determination, Section 4—
Dynamic Temperature Measurement;
Second Edition, January 2018 (‘‘API
7.4’’). This standard describes methods,
equipment, installation, and operating
procedures for the proper determination
of the temperature of hydrocarbon
liquids under dynamic conditions in
custody transfer applications. This
standard is proposed for incorporation
for its standards covering the use of
dynamic temperature determination in
LACT and CMS operations.
• API MPMS Chapter 8.1, Standard
Practice for Manual Sampling of
Petroleum and Petroleum Products;
Fourth Edition, October 2013, (‘‘API
8.1’’). This standard covers procedures
and equipment for manually obtaining
samples of liquid petroleum and
petroleum products from the sample
point into the primary containers.
• API MPMS Chapter 8.2, Standard
Practice for Automatic Sampling of
Petroleum and Petroleum Products;
Fourth Edition, November 2016 (‘‘API
8.2’’). This standard describes general
procedures and equipment for
automatically obtaining samples of
liquid petroleum, petroleum products,
and crude oils from a sample point into
a primary container.
• API MPMS Chapter 8—Sampling,
Section 3—Standard Practice for Mixing
and Handling of Liquid Samples of
Petroleum and Petroleum Products;
First Edition, October 1995; Reaffirmed,
March 2015 (‘‘API 8.3’’). This standard
covers the handling, mixing, and
conditioning procedures required to
ensure that a representative sample of
the liquid petroleum or petroleum
product is delivered from the primary
sample container/receiver into the
analytical test apparatus or into
intermediate containers.
• API MPMS Chapter 9.1, Standard
Test Method for Density, Relative
Density, or API Gravity of Crude
Petroleum and Liquid Petroleum
Products by Hydrometer Method; Third
Edition, December 2012; Reaffirmed,
May 2017 (‘‘API 9.1’’). This standard

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covers the determination of the density,
relative density, or API gravity of crude
petroleum, petroleum products, or
mixtures of petroleum and nonpetroleum products normally handed as
liquids have a Reid vapor pressure of
101.325 Kilopascal (kPa) (14.696 psi) or
less, using a glass hydrometer in
conjunction with a series of
calculations.
• API MPMS Chapter 9.2, Standard
Test Method for Density or Relative
Density of Light Hydrocarbons by
Pressure Hydrometer; Third Edition,
December 2012; Reaffirmed, May 2017
(‘‘API 9.2’’). This standard covers the
determination of the density or relative
density of light hydrocarbons including
liquefied petroleum gases having a Reid
vapor pressure exceeding 101.325 kPa
(14.696 psi).
• API MPMS Chapter 9.3, Standard
Test Method for Density, Relative
Density, and API Gravity of Crude
Petroleum and Liquid Petroleum
Products by Thermohydrometer
Method; Third Edition, December 2012;
Reaffirmed, May 2017 (‘‘API 9.3’’). This
standard covers the determination of the
density, relative density, or API gravity
of crude petroleum, petroleum products,
or mixtures of petroleum and nonpetroleum products normally handed as
liquids and having a Reid vapor
pressure of 101.325 kPa (14.696 psi) or
less, using a glass thermohydrometer in
conjunction with a series of
calculations.
• API MPMS Chapter 10.4,
Determination of Water and/or
Sediment in Crude Oil by the Centrifuge
Method (Field Procedure); Fourth
Edition, October 2013; Errata, March
2015 (‘‘API 10.4’’). This standard
describes the field centrifuge method for
determining both water and sediment,
or sediment only, in crude oil.
• API MPMS Chapter 11—Physical
Properties Data, Section 1—
Temperature and Pressure Volume
Correction Factors for Generalized
Crude Oils, Refined Products and
Lubricating Oils; May 2004; Addendum
1, September 2007, Addendum 2, May
2019; Reaffirmed, August 2012 (‘‘API
11.1’’). This standard provides the
algorithm and implementation
procedure for the correction of
temperature and pressure effects on
density and the volume of liquid
hydrocarbons that fall within the
categories of crude oil.
• API MPMS Chapter 12—Calculation
of Petroleum Quantities, Section 2—
Calculation of Petroleum Quantities
Using Dynamic Measurement Methods
and Volumetric Correction Factors, Part
2—Measurement Tickets; Third Edition,
June 2003; Reaffirmed February 2016

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(‘‘API 12.2.2’’). This standard provides
standardized calculation methods for
the quantification of liquids and
specifies the equations for computing
correction factors, rules for rounding,
calculation sequences, and
discrimination levels to be employed in
the calculations.
• API MPMS Chapter 12—Calculation
of Petroleum Quantities, Section 2—
Calculation of Petroleum Quantities
Using Dynamic Measurement Methods
and Volumetric Correction Factors, Part
3—Proving Report; First Edition,
October 1998; Reaffirmed May 2014
(‘‘API 12.2.3’’). This standard provides
standardized calculation methods for
the determination of meter factors under
defined conditions. The criteria
contained in this standard will allow
entities using various computer
languages on different computer
hardware (or by manual calculations) to
arrive at identical results using the same
standardized input data. This standard
also specifies the equations for
computing correction factors, including
the calculation sequence, discrimination
levels, and rules for rounding to be
employed in the calculations.
• API MPMS Chapter 12—Calculation
of Petroleum Quantities, Section 2—
Calculation of Petroleum Quantities
Using Dynamic Measurement Methods
and Volumetric Correction Factors, Part
4—Calculation of Base Prover Volumes
by the Waterdraw Method; First Edition,
December 1997; Errata July 2009;
Reaffirmed September 2014 (‘‘API
12.2.4’’). This standard provides
standardized calculation methods for
the quantification of liquids and
determination of base prover volumes
under defined conditions. The criteria
contained in this standard allows
individuals, using various computer
languages on different computer
hardware (or manual calculations), to
arrive at identical results using the same
standardized input data. This standard
specifies the equations for computing
correction factors, rules for rounding,
the sequence of the calculations, and the
discrimination levels of all numbers to
be used in these calculations.
• API MPMS Chapter 13.3,
Measurement Uncertainty; Second
Edition, December 2017 (‘‘API 13.3’’).
This standard establishes a methodology
for developing an uncertainty analysis.
• API MPMS Chapter 14, Section 3,
Orifice Metering of Natural Gas and
Other Related Hydrocarbon Fluids—
Concentric, Square-edged Orifice
Meters, Part 1, General Equations and
Uncertainty Guidelines; Fourth Edition,
September 2012; Errata July 2013;
Reaffirmed, September 2017 (‘‘API
14.3.1’’). This standard provides

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reference for engineering equations and
uncertainty estimations.
• API MPMS Chapter 18—Custody
Transfer, Section 1—Measurement
Procedures for Crude Oil Gathered from
Lease Tanks by Truck; Third Edition,
May 2018 (‘‘API 18.1’’). This standard
describes the procedures, organized into
a recommended sequence of steps, for
manually determining the quantity and
quality of crude oil being transferred
under field conditions.
• API MPMS Chapter 21—Flow
Measurement Using Electronic Metering
Systems, Section 2—Electronic Liquid
Volume Measurement Using Positive
Displacement and Turbine Meters; First
Edition, June 1998; Reaffirmed October
2016 (‘‘API 21.2’’). This standard
provides for the effective utilization of
electronic liquid measurement systems
for custody-transfer measurement of
liquid hydrocarbons.
• API Recommended Practice (RP)
12R1, Setting, Maintenance, Inspection,
Operation and Repair of Tanks in
Production Service; Fifth Edition,
August 1997; Reaffirmed April 2008;
Addendum 1, December 2017 (‘‘API RP
12R1’’). This recommended practice is a
guide on new tank installations and the
maintenance of existing tanks. Specific
provisions from this recommended
practice are identified as requirements.
• API RP 2556, Correction Gauge
Tables for Incrustation; Second Edition,
August 1993; Reaffirmed November
2013 (‘‘API RP 2556’’). This
recommended practice provides for
correcting gauge tables for incrustation
applied to tank capacity tables. The
tables in this recommended practice
show the percent of error of
measurement caused by varying
thicknesses of uniform incrustation in
tanks of various sizes.
The following industry standards and
recommendations are proposed for
incorporation by reference, in whole or
in part, in subpart K of the proposed
rule:
• API MPMS Chapter 14—Natural
Gas Fluids Measurement, Section 1—
Collecting and Handling of Natural Gas
Samples for Custody Transfer; Seventh
Edition, May 2016; Addendum, August
2017; Errata, August 2017 (‘‘API 14.1’’).
This standard provides comprehensive
guidelines for properly collecting,
conditioning, and handling
representative samples of natural gas
that are at or above their hydrocarbon
dew point.
• API MPMS, Chapter 14, Section 3,
Orifice Metering of Natural Gas and
Other Related Hydrocarbon Fluids—
Concentric, Square-edged Orifice
Meters, Part 1, General Equations and
Uncertainty Guidelines; Fourth Edition,

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September 2012; Errata, July 2013 (‘‘API
14.3.1’’). This standard provides
engineering equations and uncertainty
estimations for the calculation of flow
rate through concentric, square-edge,
flange-tapped orifice meters.
• API MPMS Chapter 14, Section 3,
Orifice Metering of Natural Gas and
Other Related Hydrocarbon Fluids—
Concentric, Square-edged Orifice
Meters, Part 2, Specification and
Installation Requirements; Fifth Edition,
March 2016; Errata 1, March 2017;
Errata 2, January 2019) (‘‘API 14.3.2’’).
This standard provides construction and
installation requirements, and
standardized implementation
recommendations, for the calculation of
flow rate through concentric, squareedge, flange-tapped orifice meters.
• API MPMS Chapter 14, Section 3,
Orifice Metering of Natural Gas and
Other Related Hydrocarbon Fluids—
Concentric, Square-edged Orifice
Meters, Part 3, Natural Gas
Applications; Fourth Edition, November
2013 (‘‘API 14.3.3’’). This standard is an
application guide for the calculation of
natural gas flow through a flangetapped, concentric orifice meter.
• API MPMS, Chapter 14.5,
Calculation of Gross Heating Value,
Relative Density, Compressibility and
Theoretical Hydrocarbon Liquid
Content for Natural Gas Mixtures for
Custody Transfer; Third Edition,
January 2009; Reaffirmed November
2020 (‘‘API 14.5’’). This standard
presents procedures for calculating the
following properties of natural gas
mixtures at base conditions from
composition: gross heating value,

relative density (real and ideal),
compressibility factor, and theoretical
hydrocarbon liquid content.
• API MPMS Chapter 21.1, Flow
Measurement Using Electronic Metering
Systems—Electronic Gas Measurement;
Second Edition, February 2013 (‘‘API
21.1’’). This standard describes the
minimum specifications for electronic
gas measurement systems (EGMs) used
in the measurement and recording of
flow parameters of gaseous phase
hydrocarbon and other related fluids for
custody transfer applications utilizing
industry recognized primary
measurement devices.
• AGA Report No. 3, Orifice Metering
of Natural Gas and Other Related
Hydrocarbon Fluids; Second Edition,
September 1985 (‘‘AGA Report No. 3’’).
This report provides construction and
installation requirements, and
standardized implementation
recommendations, for the calculation of
flow rate through concentric, squareedged, flange-tapped orifice meters.
• AGA Transmission Measurement
Committee Report No. 8,
Compressibility Factors of Natural Gas
and Other Related Hydrocarbon Gases;
Second Edition, November 1992 (‘‘AGA
Report No. 8’’). This report presents
detailed information for precise
computations of compressibility factors
and densities of natural gas and other
hydrocarbon gases, calculation
uncertainty estimations, and FORTRAN
computer program listings.
• GPA Midstream Standard 2166–17,
Obtaining Natural Gas Samples for
Analysis by Gas Chromatography,
Reaffirmed 2017 (‘‘GPA 2166–17’’). This

2435

standard recommends procedures for
obtaining samples from flowing natural
gas streams that represent the
compositions of the vapor phase portion
of the system being analyzed.
• GPA Standard Midstream 2261–19,
Analysis for Natural Gas and Similar
Gaseous Mixtures by Gas
Chromatography; Revised 2019 (‘‘GPA
2261–19’’). This standard establishes a
method to determine the chemical
composition of natural gas and similar
gaseous mixtures within set ranges
using a gas chromatograph (CG).
• GPA Midstream Standard 2198–16,
Selection, Preparation, Validation, Care
and Storage of Natural Gas and Natural
Gas Liquids Reference Standard Blends;
Revised 2016 (‘‘GPA 2198–16’’). This
standard establishes procedures for
selecting the proper natural gas and
natural gas liquids reference standards,
preparing the reference standards for
use, verifying the accuracy of
composition as reported by the
manufacturer, and the proper care and
storage of those reference standards to
ensure their integrity while they are in
use.
V. Discussion of Proposed Changes
This proposed rule adds new sections
and redesignates or revises current
sections as set forth in the table below.
The proposed rule removes all
references to the ‘‘Osage Tribal
Council,’’ and replaces them with
‘‘Osage Nation’’ or ‘‘Osage Minerals
Council,’’ as applicable, because the
Osage Tribal Council ceased to exist
upon ratification of the Constitution of
the Osage Nation in 2006.

New section

Current section

Proposed changes

226.0 ....................................

N/A .....................................

226.1 ....................................

226.1 ..................................

226.2 (new) ..........................

N/A .....................................

226.3 (new) ..........................

N/A .....................................

226.4 (new) ..........................

N/A .....................................

226.5 ....................................

226.45 ................................

226.6 ....................................

226.31 ................................

226.7 ....................................
226.8 ....................................

226.7 ..................................
226.4 ..................................

The proposed rule identifies the API standards incorporated by reference in subpart
J, Oil Measurement, and the API, AGA, and GPA standards incorporated by reference in subpart K, Gas Measurement.
The proposed rule defines new key terms, updates existing definitions, and removes definitions of terms that are no longer used in the regulations.
The proposed rule identifies the legal authorities that govern oil and gas leasing
and development activities within the Osage Mineral Estate.
The proposed rule describes the Superintendent’s authority and responsibility to
administer oil and gas leasing and development of the Osage Mineral Estate.
The proposed rule describes ONRR’s authority and responsibility to administer the
Osage royalty management program.
The proposed rule clarifies the Superintendent’s authority to issue orders and notices and adds a provision specifying ONRR’s authority to issue orders and notices.
The proposed rule removes the provision requiring lessees who reside outside the
state of Oklahoma to designate in-state process agents for the purpose of serving notice. The proposed rule also removes the provision providing for the Superintendent to serve notice on employees present on the lease if the designated
process agent is incapacitated or absent from the state of Oklahoma. The proposed rule adds provisions setting forth the procedures the Superintendent and
ONRR will use to serve official correspondence.
No substantive change.
The proposed rule removes the language allowing cash payments and updates the
accepted forms of payment to include electronic funds transfer (EFT), certified
check, cashier’s check, money order, or commercial or personal check drawn on
a solvent bank.

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Proposed changes

226.9 ....................................

226.2(c) ..............................

226.10 ..................................

226.46 ................................

226.11 (new) ........................

N/A .....................................

226.12 ..................................

226.2(f) ...............................

226.13 ..................................

226.2(f) ...............................

226.14 ..................................

226.2(a) ..............................

226.15 ..................................

226.2(b) ..............................

226.16 ..................................

226.2(b), 226.6(a) ..............

226.17 ..................................
226.18 ..................................

226.2(b) ..............................
226.2(f) ...............................

226.19 ..................................

226.6(a) ..............................

226.20 ..................................

226.2(d) ..............................

226.21 ..................................

226.9(b), 226.10 .................

226.22 ..................................
226.23 ..................................

226.5 ..................................
226.2(e) ..............................

226.24 ..................................

226.15(a) ............................

226.25
226.26
226.27
226.28
226.29

..................................
..................................
..................................
(new) ........................
(new) ........................

226.15(a) ............................
226.15(b) ............................
226.15(b) ............................
N/A .....................................
N/A .....................................

226.30 (new) ........................

N/A .....................................

226.31 ..................................
226.32 ..................................

226.15(c) ............................
226.15(d) ............................

226.33 ..................................
226.34 ..................................

226.3 ..................................
226.9(a), 226.29(a) ............

226.35 ..................................

226.9(a) ..............................

The proposed rule clarifies the Superintendent’s obligations to conduct environmental reviews and cultural surveys prior to approving leases and operations involving new or additional ground-disturbance.
The proposed rule updates this section to reflect amendments to the Paperwork
Reduction Act promulgated after the section was last revised requiring the BIA to
obtain OMB approval for the information collections in 25 CFR part 226. The proposed rule also adds language identifying the applicable OMB Control Numbers.
The proposed rule informs submitters of information that the BIA and ONRR will
make records available to the public without prior notification, subject to exceptions for trade secrets, confidential commercial or financial information, and information protected by the Privacy Act.
The proposed rule clarifies that the OMC must submit requests for the Superintendent to negotiate leases in writing and provide a resolution authorizing such
negotiation. This change reflects the BIA’s and OMC’s existing practices for the
submission of leasing requests.
The proposed rule clarifies that the OMC must submit requests for the Superintendent to advertise lease sales in writing and provide a resolution authorizing
such advertising. This change reflects the BIA’s and OMC’s existing practices for
the submission of lease sale requests.
The proposed rule removes the nomination fee for lease sales and clarifies the
content and submission requirements for lease sale nominations. These clarifications reflect the BIA’s existing requirements for lease sale nominations.
The proposed rule specifies that the Superintendent will publish the Notice of
Lease Sale at least 30 calendar days prior to the date of the sale. This change
reflects the BIA’s and OMC’s existing practices for publishing such notices.
The proposed rule specifies that successful bidders must submit 25 percent of the
bonus by 4:30 p.m. central standard time on the day of the sale. The proposed
rule also removes the language allowing cash payments and updates the accepted forms of payment to electronic funds transfer (EFT), cashier’s check, or
money order.
No substantive change.
The proposed rule specifies what information offerors must include in non-competitive lease offers submitted to the OMC.
The proposed rule requires successful offerors of non-competitive leases to submit
the bonus and required documentation to the Superintendent within 20 calendar
days of the OMC’s acceptance of the offer. This change reflects the BIA’s and
OMC’s existing requirements for non-competitive leases and is consistent with
the requirements for competitive leases in the new § 226.16.
The proposed rule removes oil-only and gas-only leases and requires all leases executed after the effective date of the final rule to be combination oil and gas
leases.
The proposed rule combines the regulations regarding extension of the primary
term and the term of the lease into one section. The proposed rule specifies the
actions that constitute ‘‘actual drilling operations’’ for purposes of obtaining an extension of the primary term.
No substantive change.
The proposed rule clarifies the prohibition on U.S. Government employees acquiring interests in leases of the Osage Mineral Estate.
The proposed rule specifies that lessees must submit cooperative agreements to
the Superintendent for approval at least 90 calendar days prior to expiration of
the leases covered by the agreements.
No substantive change.
No substantive change.
No substantive change.
The proposed rule specifies the effective date of the transfer for lease assignments.
The proposed rule specifies that assignors are liable for lease obligations and compliance issues that accrue prior to approval of the assignment.
The proposed rule specifies that assignees are liable for lease obligations and
compliance issues that accrue after approval of the assignment.
No substantive change.
The proposed rule removes the provision authorizing the Superintendent to approve drilling contracts because it is contrary to law and clarifies that lessees are
simply required to file copies of drilling contracts with the Superintendent.
No substantive change.
The proposed rule combines the regulations regarding lease termination and lessees’ obligations upon termination into one section. The proposed rule adds a
provision specifying that leases in the extended term terminate by operation of
law as of the date production in paying quantities ceases. The provision regarding termination in the extended term reflects the BIA’s existing practices.
The proposed rule increases the rental rate for leases approved after the effective
date of the final rule. The proposed rule also requires lessees to pay advance
annual rental for the full primary term within 15 calendar days of the Superintendent’s approval of the lease.

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New section

Current section

Proposed changes

226.36 ..................................

226.11(a)(1) ........................

226.37 ..................................

226.11(a)(2) ........................

226.38 (new) ........................

N/A .....................................

226.39 ..................................

226.11(b) ............................

226.40 ..................................

226.11(b) ............................

226.41 ..................................

226.11(c) ............................

226.42 ..................................

226.11(a)(3) ........................

226.43 ..................................

226.13(a) and (c) ...............

226.44 ..................................

226.14 ................................

226.45 ..................................

226.13(b) ............................

226.46 ..................................

226.30 ................................

226.47 ..................................

226.12 ................................

226.48 (new) ........................

N/A .....................................

226.49 (new) ........................

N/A .....................................

226.50 ..................................

226.6 ..................................

226.51 ..................................

226.6(a) and (c) .................

226.52 ..................................

226.6(a) and (b) .................

226.53 ..................................

226.6(d) ..............................

226.54 (new) ........................

N/A .....................................

226.55 (new) ........................

N/A .....................................

226.56 (new) ........................

N/A .....................................

226.57 (new) ........................

N/A .....................................

The proposed rule removes the language requiring a royalty rate of not less than
20 percent when the quantity of oil from all wells in a quarter-section or fraction
thereof during any calendar month averages 100 bbl or greater per well, per day.
The proposed rule adds language authorizing the Superintendent to approve an
oil royalty rate that is below the minimum royalty rate in the regulations if it is determined to be in the best interest of the Osage Nation.
The proposed rule requires the value of oil to be calculated using the NYMEX Calendar Month Average Price of oil at Cushing, Oklahoma instead of the highest
posted price by a major purchaser in Osage County, Oklahoma.
The proposed rule specifies how to calculate the gravity adjustment of the NYMEX
Calendar Month Average Price of oil.
The proposed rule adds language authorizing the Superintendent to approve a gas
royalty rate that is below the minimum royalty rate in the regulations if it is determined to be in the best interest of the Osage Nation.
The proposed rule requires the value of gas to be calculated using the ONRR
Monthly Index Zone Price for Oklahoma Zone 1 instead of the market value of
the gas and products extracted therefrom.
The proposed rule requires lessees to submit minimum royalty payments to ONRR
instead of the Superintendent.
The proposed rule revises the royalty-in-kind provision to allow the OMC to take
both oil and gas royalty-in-kind and adds a provision setting forth notice requirements for the OMC initiating and terminating royalty-in-kind status.
The proposed rule requires lessees and purchasers to submit royalty payments to
ONRR instead of the Superintendent and establishes a new due date for royalty
payments. The proposed rule also adds a provision specifying the procedure for
payors to recoup overpayments.
The proposed rule removes the language requiring the Superintendent’s approval
of royalty payment contracts and division orders and clarifies that lessees are
simply required to file such contracts and division orders with the Superintendent
prior to removing production from the lease.
The proposed rule requires lessees to submit royalty reports to ONRR electronically, subject to certain exceptions, and establishes a new due date for reporting.
The proposed rule requires lessees to retain rental, royalty, and payment records
for a minimum of six years unless the Superintendent or ONRR direct otherwise.
The proposed rule also adds a provision requiring lessees to make such records
available to ONRR upon request.
The proposed rule updates this section by requiring the U.S. Government to purchase oil produced from the Osage Mineral Estate at the price set forth in
§ 226.37.
The proposed rule authorizes ONRR to conduct audits and reviews of compliance
with rental, royalty, and other payment and reporting requirements.
The proposed rule exempts existing lease (quarter-section) and collective bonds
from certain changes to the bonding requirements.
The proposed rule adds a provision identifying the accepted types of performance
bonds.
The proposed rule replaces the $5,000 lease bond for each quarter-section or fraction thereof covered by the lease with an individual well bond of $6 per foot of
measured or projected well depth.
The proposed rule combines the collective and nationwide bond provisions into one
section. The proposed rule changes the collective bond (covering all leases up to
10,240 acres) to a countywide bond covering only those operations in Osage
County up to 10,240 acres and increases the bond amount from $50,000 to
$75,000.
The proposed rule clarifies the conditions that justify the Superintendent increasing
the required bond amount and adds a provision placing a limit on the amount of
any such increase.
The proposed rule specifies that the Superintendent has authority to call for the forfeiture of performance bonds and clarifies lessees’ obligations upon default. This
change reflects the Superintendent’s existing authority, as all bonds are payable
to the Superintendent. The proposed rule adds a provision specifying that the
United States or OMC may take action to recover from lessees all costs in excess of the amount collected under the bond if an obligation in default exceeds
the face amount of the bond.
The proposed rule specifies that the period of liability under a performance bond
will not terminate, and the bond will not be released, until all lease obligations
have been satisfied. This reflects the BIA’s existing practices for the release of
bonds.
The proposed rule requires bonding for geophysical exploration activities, subject to
certain exceptions for existing lessees.
The proposed rule specifies that the Superintendent has authority to call for the forfeiture of geophysical exploration bonds. This is consistent with the Superintendent’s authority for performance bonds for all other oil and gas operations within
the Osage Mineral Estate.

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Proposed changes

226.58 (new) ........................

N/A .....................................

226.59 ..................................

226.19(a) ............................

226.60 ..................................

226.30 ................................

226.61 ..................................

226.16(a) ............................

226.62 ..................................
226.63 ..................................

226.17 ................................
226.18 ................................

226.64 ..................................

226.19(b) through (d) .........

226.65 ..................................

226.19(a), 226.24 ...............

226.66 ..................................

226.16(b)(1) and (c);
226.33.

226.67 ..................................

226.36 ................................

226.68 ..................................
226.69 ..................................

226.40 ................................
226.16(b)(1) and (2), (c); ....

226.70 (new) ........................

N/A .....................................

226.71 ..................................

226.32(b), (d) .....................

226.72 ..................................

226.28(a) ............................

226.73 ..................................

226.28(a) and (b);
226.29(c) and (d).

226.74 ..................................

226.32(a), (c), and (e) ........

226.75 ..................................

226.34 ................................

226.76 ..................................

226.22(a), 226.35 ...............

The proposed rule specifies that the period of liability under a geophysical exploration bond will not terminate, and the bond will not be released, until all permit
obligations have been satisfied. This is consistent with the BIA’s existing practices for the release of performance bonds for all other oil and gas operations
within the Osage Mineral Estate.
The proposed rule adds a provision requiring lessees and permittees to properly
maintain installations and equipment and comply with the National Electrical
Code.
The proposed rule clarifies the Superintendent’s authority to inspect and investigate
operations.
The proposed rule clarifies the language regarding the commencement of operations, expressly stating that operations may not commence until the Superintendent approves a lease or geophysical exploration permit, as applicable.
No substantive change.
The proposed rule adds a provision requiring lessees and permittees to send meeting requests to surface owners by certified mail. The proposed rule also adds a
provision authorizing the Superintendent to approve the commencement of operations if a meeting request cannot be delivered to the surface owner’s last known
address or the surface owner fails to accept the request within 30 calendar days
of receiving it.
The proposed rule combines the regulations regarding commencement money for
operations and tank siting fees into one section. The proposed rule increases the
amount of commencement money for drilling and reentering wells and siting
tanks and adds a provision requiring lessees and permittees to pay commencement money for the acreage occupied during seismic surveys using vibroseis.
The proposed rule also adds a provision stating that commencement money that
cannot be delivered to the surface owner’s last known address or that the surface owner refuses is deemed forfeited.
The proposed rule combines the regulations regarding the use of surface lands and
water into one section. No substantive changes.
The proposed rule combines the regulations regarding drilling operations and line
drilling requirements into one section. The proposed rule specifies that lessees
must provide the Superintendent with five calendar days’ notice of drilling operations. The proposed rule adds a line drilling requirement imposing a setback
from certain water sources. This setback is consistent with the BIA’s existing permit conditions under the Osage County Oil and Gas Final Environmental Impact
Statement (2020).
The proposed rule requires lessees to obtain the Superintendent’s prior approval to
drill wells that deviate significantly from the vertical and conduct directional surveys if deviation occurs without prior approval.
No substantive change.
The proposed rule specifies that lessees must provide the Superintendent with at
least five calendar days’ notice of workover operations. The proposed rule adds
a provision clarifying that prior approval and a subsequent report of operations
are not required for certain well maintenance activities. This change reflects the
BIA’s existing practices with respect to well maintenance activities.
The proposed rule establishes testing, training, operational, and safety requirements for drilling and workover operations in Hydrogen Sulfide (H2S) areas.
The proposed rule adds a provision requiring lessees to conduct reasonable tests
of the mechanical integrity of downhole equipment.
The proposed rule clarifies the language regarding temporary abandonment, more
clearly stating that lessees must obtain the Superintendent’s approval to temporarily abandon a well for more than 30 calendar days.
The proposed rule combines the regulations regarding permanent abandonment
and plugging obligations into one section. The proposed rule removes the plugging application fee and requirement that oil-only and gas-only lessees offer
wells to one another prior to abandonment. The proposed rule specifies that lessees must provide the Superintendent with five calendar days’ notice of plugging
operations.
The proposed rule requires lessees to submit certain information together with the
subsequent report of hydraulic fracturing operations and adds a provision specifying the procedure for lessees to withhold confidential information regarding
such operations. The proposed rule also clarifies that lessees must retain well
records and reports for a minimum of six years unless the Superintendent directs
otherwise.
The proposed rule adds a provision requiring lessees to mark wells that are permanently plugged and abandoned.
The proposed rule combines the regulations regarding the prevention of pollution
and protection of formations into one section. The proposed rule specifies that
lessees and permittees must conduct surveys and tests of the measures taken to
protect fresh water and mineral bearing formations and provide the results to the
Superintendent upon request.

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2439

New section

Current section

Proposed changes

226.77 ..................................

226.22(b) through (e) .........

226.78 (new) ........................

N/A .....................................

226.79 (new) ........................

N/A .....................................

226.80 (new) ........................

N/A .....................................

226.81 (new) ........................

N/A .....................................

226.82 ..................................
226.83 ..................................
226.84 ..................................

226.20 ................................
226.21 ................................
226.9(a) ..............................

226.85 ..................................

226.13(b) ............................

226.86 (new) ........................

N/A .....................................

226.87 (new) ........................

N/A .....................................

226.88 (new) ........................

N/A .....................................

226.89 ..................................
226.90 ..................................
226.91 (new) ........................

226.23 ................................
226.37 ................................
N/A .....................................

226.92 (new) ........................

N/A .....................................

226.93 (new) ........................

N/A .....................................

226.94 (new) ........................

N/A .....................................

226.95 (new) ........................

N/A .....................................

226.96 (new) ........................

N/A .....................................

226.97 (new) ........................

N/A .....................................

226.98 (new) ........................

N/A .....................................

226.99 (new) ........................

N/A .....................................

226.100 (new) ......................
226.101 (new) ......................

N/A .....................................
N/A .....................................

226.102 ................................

226.41 ................................

226.103 (new) ......................

N/A .....................................

226.104 (new) ......................

N/A .....................................

226.105 ................................

N/A .....................................

The proposed rule adds provisions prohibiting lessees from constructing pits in certain sensitive locations consistent with the BIA’s existing permit conditions under
the Osage County Oil and Gas Final Environmental Impact Statement (2020).
The proposed rule also adds a provision requiring the Superintendent’s prior approval for the land application of drilling fluids.
The proposed rule requires lessees to remove fire hazards from well sites and facilities and safely dispose of waste oil. These requirements are consistent with
the BIA’s existing permit conditions under the Osage County Oil and Gas Final
Environmental Impact Statement (2020).
The proposed rule requires a geophysical exploration permit to conduct geophysical exploration operations on both leased and unleased lands.
The proposed rule specifies that lessees and permittees must provide the Superintendent with five calendar days’ notice of geophysical exploration operations.
The proposed rule requires lessees and permittees to submit subsequent reports of
geophysical exploration operations to the Superintendent.
No substantive change.
No substantive change.
The proposed rule specifies that lessees must place oil and gas into marketable
condition at no cost to the lessor. This change is consistent with current industry
practices within the Osage Mineral Estate.
The proposed rule requires lessees to submit production reports to ONRR electronically, subject to certain exceptions, and establishes a new due date for production reports.
The proposed rule requires lessees to submit site facility diagrams to the Superintendent and specifies the format and content of such diagrams.
The proposed rule requires lessees to use FMP numbers when reporting production to ONRR.
The proposed rule specifies what information production records must contain and
requires lessees to maintain such records for a minimum of six years unless the
Superintendent or ONRR direct otherwise. The proposed rule also requires lessees, purchasers, and transporters to provide production records to ONRR upon
request.
No substantive change.
No substantive change.
The proposed rule requires lessees to pay compensatory royalty for avoidably lost
or wasted production. This change reflects the BIA’s existing requirement to pay
royalty for lost and wasted production. The proposed rule specifies when production is considered avoidably and unavoidably lost or wasted.
The proposed rule sets forth lessees’ responsibilities for protecting oil and gas resources from drainage.
The proposed rule requires lessees to pay compensatory royalty for drainage if protective action is not taken within a reasonable time and specifies how compensatory royalty will be calculated.
The proposed rule requires the use of seals on appropriate valves at oil storage
and sales facilities and prohibits tampering with such valves.
The proposed rule requires the use of seals on oil measurement system components.
The proposed rule requires transporters removing oil from storage tanks to possess
run tickets, trip logs, and manifests.
The proposed rule requires any person transporting oil or gas to possess documentation indicating the first purchaser and authorizes the Superintendent and
law enforcement to conduct vehicle inspections.
The proposed rule requires lessees, purchasers, and transporters to record certain
information when water is drained from tanks holding oil.
The proposed rule requires lessees to record certain information when oil is removed from storage and used on the lease or unit for hot oiling, clean up, and
completion operations. The proposed rule also requires lessees to report all production removed from storage and used on a different lease to ONRR.
The proposed rule specifies the records that lessees must maintain for each seal.
The proposed rule requires lessees to obtain the Superintendent’s approval for offlease measurement of production.
The proposed rule specifies that lessees must report spills, thefts, mishandling of
production, accidents, and fires to both the Superintendent and surface owners
immediately upon discovery and requires lessees to submit incident reports with
proposed contingency or remediation plans to the Superintendent. This change
reflects the BIA’s current requirements for reporting of such incidents. The proposed rule adds a provision requiring lessees to provide surface owners with
both emergency and written notification of such incidents.
The proposed rule prohibits bypasses of meters and tampering with oil measurement devices, the components of such devices, and the measurement process
and imposes the maximum penalty for such violations.
The proposed rule establishes the timeframe for complying with the new requirements for oil measurement equipment and procedures.
[Reserved]

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New section

Current section

Proposed changes

226.106 (new) ......................

N/A .....................................

226.107 ................................

226.38 ................................

226.108 ................................
226.109 ................................

226.38 ................................
226.38 ................................

226.110 ................................

226.38 ................................

226.111 ................................

226.38 ................................

226.112 ................................
226.113 (new) ......................
226.114 (new) ......................

226.38 ................................
N/A .....................................
N/A .....................................

226.115 ................................

226.38 ................................

226.116 (new) ......................

N/A .....................................

226.117 (new) ......................

N/A .....................................

226.118 (new) ......................

N/A .....................................

226.119 ................................
226.120 (new) ......................

N/A .....................................
N/A .....................................

226.121 ................................

226.39 ................................

226.122 ................................
226.123 (new) ......................

226.39 ................................
N/A .....................................

226.124 (new) ......................

N/A .....................................

226.125 ................................

226.39 ................................

226.126 (new) ......................

N/A .....................................

226.127 (new) ......................

N/A .....................................

226.128 (new) ......................

N/A .....................................

226.129 (new) ......................

N/A .....................................

226.130 (new) ......................

N/A .....................................

226.131 (new) ......................
226.132 (new) ......................
226.133 (new) ......................

N/A .....................................
N/A .....................................
N/A .....................................

226.134 (new) ......................
226.135 (new) ......................

N/A .....................................
N/A .....................................

226.136 (new) ......................

N/A .....................................

226.137 (new) ......................

N/A .....................................

226.138 (new) ......................
226.139 (new) ......................
226.140 (new) ......................

N/A .....................................
N/A .....................................
N/A .....................................

226.141 (new) ......................

N/A .....................................

226.142 ................................

226.27(b) ............................

226.143 ................................

226.27(b) ............................

The proposed rule establishes requirements for oil volume uncertainty levels,
measurement bias, and equipment verification.
The proposed rule specifies that tank gauging may be used to measure oil and updates requirements for the use and calibration of oil storage tanks.
The proposed rule specifies the required tank gauging procedures.
The proposed rule specifies that Lease Automatic Custody Transfer (LACT) systems may be used to measure oil and sets forth general requirements for LACT
systems.
The proposed rule identifies required LACT system equipment and sets forth standards for operating LACT system components.
The proposed rule specifies that Coriolis Measurement Systems (CMS) may be
used to measure oil and sets forth general requirements for CMS and CMS components.
The proposed rule establishes Coriolis meter operating requirements.
The proposed rule sets forth requirements for volumetric meter proving.
The proposed rule requires the completion and submission of run tickets for tank
gauging, LACT systems, and CMS. This change codifies the BIA’s existing requirements with respect to run tickets.
The proposed rule specifies that the Superintendent’s approval is required to use
methods of oil measurement other than tank gauging, LACT system, or CMS.
The proposed rule prohibits the sale and disposal of waste oil without the Superintendent’s approval. This change codifies the BIA’s existing requirement.
The proposed rule prohibits bypasses of meters. The proposed rule also prohibits
tampering with any measurement device, component of a measurement device,
or the measurement process. The proposed rule imposes the maximum penalty
for such violations.
The proposed rule establishes the timeframe for complying with the new requirements for gas measurement equipment and procedures.
[Reserved]
The proposed rule establishes requirements for gas flow rate and heating value uncertainty, measurement bias, and equipment verification.
The proposed rule specifies the standards for orifice plates and meter tubes and
sets forth inspection requirements.
The proposed rule establishes standards for the use of mechanical recorders.
The proposed rule establishes requirements for the verification and calibration of
mechanical recorders, correction of reported gas volumes, and certification of
test equipment.
The proposed rule specifies what information integration statements must contain
and requires lessees to retain integration statements.
The proposed rule establishes standards for the use of electronic gas measurement (EGM) systems.
The proposed rule establishes requirements for the verification and calibration of
transducers, correction of reported gas volumes, and certification of test equipment.
The proposed rule provides the gas flow rate, volume, and average value calculations.
The proposed rule requires lessees to retain certain logs and records and make
them available to the Superintendent upon request.
The proposed rule specifies the methods of gas sampling and analysis that may be
used.
The proposed rule establishes standards for the location, design, and type of sampling probes and sample tubing size.
The proposed rule establishes the general requirements for taking spot samples.
The proposed rule specifies the methods of spot sampling that may be used.
The proposed rule specifies the frequency with which lessees must take and analyze spot samples.
The proposed rule establishes specifications for composite sampling methods.
The proposed rule establishes requirements for the installation, operation,
verification, and calibration of on-line gas chromatographs.
The proposed rule establishes requirements for the installation, operation,
verification, and calibration of gas chromatographs.
The proposed rule identifies the components of gas that must be analyzed and the
frequency with which component analysis must occur.
The proposed rule specifies what information gas analysis reports must contain.
The proposed rule specifies the effective date of a spot or composite gas sample.
The proposed rule establishes requirements for calculating the heating value, average heating value, and volume of a gas sample.
The proposed rule establishes requirements for reporting gross and real heating
values and volumes.
The proposed rule updates the provision by requiring the Osage Nation and Tribal
members to pay for gas at the price set forth in § 226.40.
The proposed rule updates the provision by requiring the lessee to pay royalty on
all gas furnished to the Osage Nation and Tribal members at the rate set forth in
§ 226.39.

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2441

New section

Current section

Proposed changes

226.144 ................................
226.145 (new) ......................

226.11(a)(1) and (b)(2) ......
N/A .....................................

226.146 (new) ......................

N/A .....................................

226.147 (new) ......................

N/A .....................................

226.148 (new) ......................

N/A .....................................

226.149 (new) ......................

N/A .....................................

226.150 (new) ......................

N/A .....................................

226.151 (new) ......................

N/A .....................................

226.152 ................................

226.37 ................................

226.153 (new) ......................

N/A .....................................

226.154 (new) ......................

N/A .....................................

226.155 (new) ......................

N/A .....................................

226.156 (new) ......................

N/A .....................................

226.157 (new) ......................

N/A .....................................

226.158 ................................

226.42 ................................

226.159 ................................

226.43 ................................

226.160 (new) ......................

N/A .....................................

226.161 (new) ......................

N/A .....................................

226.162 (new) ......................

N/A .....................................

226.163 (new) ......................

N/A .....................................

226.164 ................................

226.28(c) ............................

226.165 ................................

226.29(b); 226.42 ...............

226.166 ................................

226.42 ................................

226.167 (new) ......................

N/A .....................................

226.168 (new) ......................

N/A .....................................

226.169 (new) ......................

N/A .....................................

226.170 (new) ......................

N/A .....................................

226.171 (new) ......................

N/A .....................................

226.172 (new) ......................

N/A .....................................

226.173 (new) ......................

N/A .....................................

No substantive change.
The proposed rule identifies the uses of production on a lease or unit that do not
require the Superintendent’s prior approval for royalty-free treatment.
The proposed rule identifies the uses of production on a lease or unit that require
the Superintendent’s prior approval for royalty-free treatment.
The proposed rule identifies the uses of production off the lease or unit that do not
require the Superintendent’s prior approval of royalty-free treatment.
The proposed rule identifies the uses of production off the lease or unit that require
the Superintendent’s prior approval of royalty-free treatment.
The proposed rule sets forth requirements for the measurement and reporting of
royalty-free volumes of oil and gas used.
The proposed rule specifies that lessees do not need to own or lease the equipment or facility that uses royalty-free oil and gas.
The proposed rule sets forth procedures for requesting royalty-free use of oil and
gas.
The proposed rule adds a provision prohibiting the venting and flaring of gas without the Superintendent’s prior approval. The proposed rule also requires all flares
and combustible devices to be equipped with an automatic ignition system. This
reflects the BIA’s existing requirements for venting and flaring and is consistent
with the BIA’s existing permit conditions under the Osage County Oil and Gas
Final Environmental Impact Statement (2020).
The proposed rule adds a provision prohibiting the venting and flaring of gas-well
gas unless it is unavoidably lost.
The proposed rule authorizes the venting and flaring of oil-well gas in accordance
with §§ 226.155, 226.156, and 226.157.
The proposed rule requires gas to be flared, rather than vented, subject to certain
exceptions.
The proposed rule authorizes the venting and flaring of gas during certain tests,
well maintenance activities, and emergencies.
The proposed rule sets forth the requirements for measuring and reporting the volumes of gas vented and flared.
The proposed rule identifies the remedies the Superintendent may utilize to address violations of lease or permit terms and conditions, the regulations, and orders or notices.
The proposed rule updates the list of lease operation violations that will result in
immediate assessments.
The proposed rule authorizes the Superintendent to issue assessments if a lessee
fails to commence or perform an operation within five calendar days of an order
to do so if the Superintendent performs the operation or must retain a third-party
to perform the operation.
The proposed rule sets forth the procedure the Superintendent will use to notify
lessees of lease violations that have a period to correct prior to the assessment
of penalties and the penalty amounts imposed if violations are not timely corrected.
The proposed rule sets forth the procedure the Superintendent will use to notify
lessees of lease violations that do not have a period to correct prior to the assessment of penalties and the penalty amounts imposed for such violations.
The proposed rule specifies the factors the Superintendent will consider in determining that amount of the penalty to assess.
The proposed rule clarifies the circumstances under which the Superintendent may
take shut-in action.
The proposed rule specifies the circumstances under which the Superintendent
may cancel a lease or permit and the procedure for cancelling a lease or permit.
The proposed rule specifies that interest on unpaid and underpaid civil penalties
and assessments will be charged at the IRS underpayment rate or such other
rate as the Superintendent may prescribe.
The proposed rule identifies the remedies ONRR may utilize to address violations
of lease or permit terms and conditions, the regulations, and orders or notices.
The proposed rule authorizes ONRR to issue assessments for incorrect or late royalty and production reporting and specifies the amount of such assessments.
The proposed rule authorizes ONRR to issue assessments for failing to submit the
correct payment amount or providing inadequate or erroneous information and
specifies the amounts of such assessments.
The proposed rule sets forth the procedure ONRR will use to notify reporters and
payors of violations that have a period to correct prior to the assessment of penalties and the penalty amounts imposed if violations are not timely corrected.
The proposed rule sets forth the procedure ONRR will use to notify reporters and
payors of violations that do not have a period to correct prior to the assessment
of penalties and the penalty amounts imposed.
The proposed rule specifies the factors ONRR will consider in determining the
amount of the penalty to assess.
The proposed rule specifies the due date for remitting payment of penalties and assessments to ONRR and that interest on unpaid and underpaid penalty and assessment amounts will be charged at the rate set forth in § 226.166(b).

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New section

Current section

Proposed changes

226.174 (new) ......................

N/A .....................................

226.175 (new) ......................

N/A .....................................

226.176 ................................
226.177 ................................

226.43(j) .............................
226.44 ................................

226.178 (new) ......................

N/A .....................................

226.179 (new) ......................

N/A .....................................

226.180 (new) ......................

N/A .....................................

226.181 (new) ......................

N/A .....................................

226.182 (new) ......................

N/A .....................................

226.183 (new) ......................

N/A .....................................

226.184 (new) ......................
226.185 (new) ......................

N/A .....................................
N/A .....................................

Appendix A ...........................

N/A .....................................

The proposed rule specifies the actions ONRR may take to collect unpaid civil penalties.
The proposed rule specifies that ONRR will refer past due debts to the U.S. Treasury for collection or tax refund offset and may assess administrative costs.
No substantive change.
The proposed rule clarifies the procedures for filing administrative appeals of decisions the Superintendent and Regional Director issue.
The proposed rule sets forth the procedures for filing administrative appeals of orders that ONRR issues.
The proposed rule specifies the conditions for suspension of compliance with an
ONRR order during an administrative appeal.
The proposed rule sets forth the requirements for posting an appeal bond or other
surety on an appellant’s behalf for administrative appeals of ONRR orders.
The proposed rule specifies when an obligation to comply with an ONRR order is
suspended due to judicial review.
The proposed rule specifies when ONRR will collect bonds and other surety instruments posted for administrative appeals.
The proposed rule specifies that the ONRR bond-approving officer’s determination
of the required surety amount is not subject to appeal.
The proposed rule sets forth the standards for ONRR-specified surety instruments.
The proposed rule explains how ONRR will determine the bond or surety instrument amount.
Table of Atmospheric Pressures to be used with §§ 226.123(a)(7) and (c)(10),
226.124(c), 226.126(a)(3), and 226.127(b).

VI. Procedural Matters

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A. Regulatory Planning and Review
(Executive Orders 12866 and 13563)
Executive Order 12866 provides that
the Office of Information and Regulatory
Affairs (OIRA) at the Office of
Management and Budget (OMB) will
review all significant rules. OIRA
determined that this proposed rule is
not significant.
Executive Order 13563 reaffirms the
principles of Executive Order 12866,
while calling for improvements in the
Nation’s regulatory system to promote
predictability, to reduce uncertainty,
and to use the best, most innovative,
and least burdensome tools for
achieving regulatory ends. The
Executive Order directs agencies to
consider regulatory approaches that
reduce burdens and maintain flexibility
and freedom of choice for the public
where these approaches are relevant,
feasible, and consistent with regulatory
objectives. Executive Order 13563
further emphasizes that regulations
must be based on the best available
science and that the rulemaking process
must allow for public participation and
an open exchange of ideas. We
developed this proposed rule in a
manner consistent with these
requirements.
B. Regulatory Flexibility Act
The Regulatory Flexibility Act (5
U.S.C. 601, et seq.) (RFA) requires
Federal agencies to prepare a regulatory
flexibility analysis for rules subject to
notice-and-comment rulemaking
requirements under the Administrative
Procedure Act (5 U.S.C. 500, et seq.) to

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determine whether a regulation would
have a significant economic impact on
a substantial number of small entities.
The BIA does not believe the proposed
rule would have a significant economic
impact on a substantial number of small
entities. Accordingly, a regulatory
flexibility analysis is not required by the
RFA. Although such analysis is not
required, BIA performed an initial
regulatory flexibility analysis pursuant
to section 603 of the RFA as part of its
Regulatory Impact Analysis (RIA). The
IFRA, included as Appendix B to the
RIA, analyzes impacts on small entities
that may be affected by the proposed
rule and is available upon request (see
ADDRESSES). The IFRA for the proposed
rule uses the best available information
to identify potential impacts on small
entities.
Small entities include small
businesses, small governmental
jurisdictions, and small organizations,
as defined by section 601 of the RFA. A
small entity is one that is independently
owned and operated and is not
dominant in its field of operation. The
small entities most likely to be impacted
by the proposed rule are small
businesses in the mining sector; impacts
to small governmental jurisdictions and
small organizations are not anticipated.
The Small Business Administration
(SBA) defines small businesses in the
crude petroleum and natural gas
extraction industry as those with 1,250
employees or less. For subsector mining
support activities, the SBA defines
small businesses as drilling contractors
with 1,000 employees or less and
service companies with less than $41.5

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million per year in revenues. Under
these size standards, most oil and gas
lessees and supporting entities within
the Osage Mineral Estate would be
classified as small businesses.
Accordingly, the proposed rule would
likely impact a substantial number of
small entities within the Osage Mineral
Estate.
Using the best available data for the
past three years of production (2018–
2020), there were an average of 223
lessees actively and exclusively
producing oil from the Osage Mineral
Estate, 5 lessees actively and exclusively
producing gas from the Osage Mineral
Estate, and 59 lessees actively
producing both oil and gas from the
Osage Mineral Estate, for a combined
average of 286 lessees actively
producing oil and gas. The volume of
production varies substantially across
lessees, with a substantial number of
smaller lessees producing marginal
volumes of oil and gas and several larger
lessees producing the majority of annual
production from the Osage Mineral
Estate. For example, two lessees
produced over 250,000 barrels of oil
annually between 2018 and 2020,
comprising 41 percent of all oil
production from the Osage Mineral
Estate during that period. In contrast,
approximately 100 lessees during the
same period produced less than 1,000
barrels of oil annually. The allocation of
production for gas is similarly skewed.
To estimate the economic impacts on
small entities, the IFRA estimates costs
of the proposed rule for ‘‘average’’
lessees (286 active lessees) by assuming
that lessees produce an average volume

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Federal Register / Vol. 88, No. 9 / Friday, January 13, 2023 / Proposed Rules
of oil and gas, that costs are shared
equally across lessees, and that small
entities would bear all costs of the
proposed rule. The estimated costs of
the proposed rule (including
compliance costs, reporting and
recordkeeping costs, and other
payments) are $18,000 to $26,000 per
year for ‘‘average’’ lessees, which could
represent between 15 to 65 percent of
annual profits depending on the lessee.
As the IFRA assumes that costs are
shared equally across lessees, however,
the estimated per entity costs are higher
than would be expected for lessees with
small production volumes and lower
than would be expected for lessees with
large production volumes. For example,
a lessee producing marginal oil volumes
will have lower impacts from a change
in the valuation of oil for royalty
purposes than a lessee producing the
‘‘average’’ volume of oil.
The BIA does not believe the
proposed rule would conflict with,
duplicate, or overlap any relevant
Federal rules in a way that would
unnecessarily add cumulative
regulatory burdens on small entities
without any gain in regulatory benefits.
BIA invites public comments
identifying any Federal rules that may
conflict with, duplicate, or overlap the
proposed rule.
C. Small Business Regulatory
Enforcement Fairness Act
This proposed rule is not a major rule
under the Small Business Regulatory
Enforcement Fairness Act, 5 U.S.C.
804(2). This proposed rule would not
have an annual effect on the economy
of $100 million or more; would not
cause a major increase in the costs or
prices for consumers, individual
industries, Federal, State, local
government agencies, or geographic
regions; and would not have significant
adverse effects on competition,
employment, investment, productivity,
innovation, or the ability of U.S.-based
enterprises to compete with foreignbased enterprises.

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D. Unfunded Mandates Reform Act
This proposed rule would not impose
an unfunded mandate on State, local, or
Tribal governments or the private sector
of $100 million or more per year. The
proposed rule would not have a
significant or unique effect on State,
local, or Tribal governments or the
private sector. A statement containing
the information required by the
Unfunded Mandates Reform Act, 2
U.S.C. 1531, et seq., is not required for
this proposed rule.

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E. Takings (Executive Order 12630)
This proposed rule would not
constitute a taking of private property or
otherwise have takings implications
under Executive Order 12630. The
proposed rule would revise certain
operational and administrative
requirements for existing lessees. All
such operations are subject to lease
terms and conditions and a current
regulation expressly requiring
compliance with amendments to the
regulations except that the term of the
lease, acreage, rental rate, and royalty
rate may not be changed absent
agreement by both parties to the lease.
The proposed rule conforms to those
requirements. A takings implication
assessment is not required.
F. Federalism (Executive Order 13132)
Under the criteria in Executive Order
13132, this proposed rule would not
have a substantial direct effect on the
States, the relationship between the
Federal Government and the States, or
the distribution of power and
responsibilities among the various
levels of government. A federalism
impact statement is not required.
G. Civil Justice Reform (Executive Order
12988)
This proposed rule complies with the
requirements of Executive Order 12988.
Specifically, this proposed rule was
reviewed to eliminate errors and
ambiguity and written to minimize
litigation. In addition, this proposed
rule was written in clear language and
contains clear legal standards.
H. Consultation With Indian Tribal
Governments (Executive Order 13175)
The BIA evaluated this proposed rule
under the criteria set forth in Executive
Order 13175 and in accordance with
Departmental policy to identify possible
effects on federally recognized Indian
Tribes and Indian trust assets. This
proposed rule applies to oil and gas
leasing and development activities
within the Osage Mineral Estate in
Osage County, Oklahoma. As the Osage
Mineral Estate is held in trust by the
United States for the benefit of the
Osage Nation, this proposed rule has the
potential to affect the Osage Nation.
On September 22, 2016, the BIA sent
letters to the Osage Nation and Osage
Minerals Council inviting their
participation in government-togovernment consultation to discuss
potential revision of the regulations in
this part. Both the Osage Nation and
Osage Minerals Council expressed an
interest in such consultation. On
October 25, 2016, the BIA held a
consultation with the Osage Nation,

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2443

Osage Minerals Council, and their legal
counsel in Pawhuska, Oklahoma and
the parties agreed that revision of the
regulations was appropriate. As part of
the rulemaking effort, the BIA proposed
that the process include an opportunity
for the Osage Nation and Osage
Minerals Council to provide input on
proposed revisions to the regulations
prior to the BIA preparing the proposed
rule for publication in the Federal
Register. The parties agreed that the BIA
would prepare a discussion draft
revising the regulations, provide it to
the Osage Nation and Osage Minerals
Council for review and comment, and
hold a second government-togovernment consultation to discuss
Tribal representatives’ feedback.
Thereafter, the BIA would begin
preparation of the proposed rule.
On August 18, 2020, the BIA provided
the Osage Nation and Osage Minerals
Council with the discussion draft
revising the regulations in 25 CFR part
226. The BIA proposed that the parties
conduct the second government-togovernment consultation to receive the
Tribe’s feedback on the discussion draft
in November 2020. On October 7, 2020,
the Osage Minerals Council requested
that the review period for the discussion
draft be extended to February 1, 2021.
The BIA agreed to the extension. On
December 16, 2020, the Osage Minerals
Council requested an additional
government-to-government consultation
prior to providing feedback on the
discussion draft. The BIA agreed to
conduct an additional consultation, but
the Osage Nation and Osage Minerals
Council did not respond to
communications attempting to schedule
the consultation.
On February 11, 2021, the Director of
the Bureau of Indian Affairs, exercising
the delegated authority of the Assistant
Secretary—Indian Affairs, sent a letter
to the Osage Nation and Osage Minerals
Council advising of the deadline for
scheduling the additional consultation
requested and providing feedback on
the discussion draft. On February 25,
2021, the Osage Minerals Council
responded and declined the BIA’s
invitation to provide written feedback
on the discussion draft and participate
in government-to-government
consultations relating thereto. The BIA
advised the Osage Nation and Osage
Minerals Council that they would still
have the opportunity to provide
feedback following publication of the
proposed rule in the Federal Register.
On February 22, 2022, the Osage
Minerals Council sent a letter to the
Assistant Secretary—Indian Affairs
requesting that the BIA not publish a
proposed rule based on the discussion

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2444

Federal Register / Vol. 88, No. 9 / Friday, January 13, 2023 / Proposed Rules

draft the Council received in 2020 and,
instead, work with the Council to
prepare a new set of regulations. The
Assistant Secretary—Indian Affairs
spoke with the Chairman of the Osage
Minerals Council by phone and
explained that the proposed rule had
already been prepared and the BIA was
in the process of completing the
procedural requirements for
publication. The Assistant Secretary—
Indian Affairs advised that the BIA
remained open to consulting with the
Osage Nation and Osage Minerals
Council following publication of the
proposed rule in the Federal Register
and noted that written feedback can also

I. Paperwork Reduction Act
All information collections require
approval under the Paperwork
Reduction Act of 1995 (PRA), 44 U.S.C.
3501, et seq. We may not conduct or
sponsor, and you are not required to
respond to, a collection of information
unless it displays a currently valid
Office of Management and Budget
(OMB) Control Number. There are BIA
and ONRR information collection
requirements in this proposed rule. The
BIA is proposing to renew its
information collection with revisions
(OMB Control No. 1076–0180) and

ONRR is proposing to renew two
information collections with revisions
(OMB Control Nos. 1012–0004 and
1012–0006).
1. OMB Control Number 1076–0180
(BIA)
The OMB has reviewed and approved
information collections for the existing
regulations in 25 CFR part 226, which
are assigned OMB Control No. 1076–
0180. The BIA is proposing to renew
information collection 1076–0180 with
revisions. The following BIA revisions
to reporting and recordkeeping
requirements in the proposed rule
require OMB’s approval:

Section(s)

Proposed revision(s) to OMB 1076–0180

226.6(b) ................................

Lessees must provide the name and address for a designated point of contact
upon whom the Superintendent can serve official correspondence regarding the
lease and operations thereon.
Lessees may submit a draft environmental assessment (EA) for proposed drilling
operations and any other proposed ground-disturbing activities occurring outside
the existing well pad. This requirement is the same as the requirement in existing
§ 226.2(c).
Lessees must submit a Cultural Resources Survey for proposed drilling operations
and any other proposed ground-disturbing activities occurring outside the existing
well pad if the location of the operations or activities is not covered by a prior
survey. This requirement is the same as the requirement in existing § 226.2(c).
The Osage Minerals Council (OMC) may request that the Superintendent negotiate
a non-competitive lease with a prospective lessee on its behalf by submitting a
Resolution authorizing the Superintendent to undertake such action. This requirement is the same as the requirement in existing § 226.2(f).
The OMC may request that the Superintendent advertise a competitive lease sale
by submitting a Resolution that specifies the proposed location, date, and time of
the lease sale as well as the minimum acceptable bid. This requirement is the
same as the requirement in existing § 226.2(f).
An individual who wants to nominate a tract for a competitive lease sale must submit a nomination letter that includes their name and address as well as the legal
description of the tract they are nominating. This requirement is the same as the
requirement in existing § 226.2(a).
The successful bidder at a competitive lease sale must submit an executed lease
form, evidence of authority to execute papers form, and certificate of good standing from the Oklahoma Secretary of State. This requirement is the same as the
requirement in existing § 226.2(b).

226.9(a) ................................

226.9(b) ................................

226.12(b) ..............................

226.13(a) ..............................

226.14(a) ..............................

226.17(a)(2) through (4) ......

OMB 1076–0180 form(s)

226.19(a)(2) through (4) ......

A prospective lessee who negotiates a non-competitive lease with the OMC must
submit an executed lease form, evidence of authority to execute papers form,
and certificate of good standing from the Oklahoma Secretary of State. This requirement is the same as the requirement in existing § 226.2(f).

226.21(b) ..............................

Lessees may submit a lease amendment form evidencing an agreement between
the lessee and OMC to extend the primary term of the lease. This requirement is
the same as the requirement in existing § 226.9(b).
The lessee or OMC may submit a proposed cooperative agreement whereby the
parties agree to unitize or merge one or more leases of the Osage Mineral Estate to promote development. This requirement is the same as the requirement in
existing § 226.15(a).
The lessee or OMC may submit an agreement whereby the parties agree to modify, amend, or terminate an approved cooperative agreement. This requirement is
the same as the requirement in existing § 226.15(a).
A lessee (assignor) may submit a lease assignment form transferring record title in
an approved lease to another existing or prospective lessee (assignee). This requirement is the same as the requirement in existing § 226.15(b).
Lessees must submit a request to surrender all or part of an approved lease. This
requirement is the same as the requirement in existing § 226.3.
Lessees must submit a copy of any agreement with a surface owner where the
parties agree that the lessee can remove permanent improvements from the
lease following termination. This requirement is the same as the requirement in
existing § 226.29(a).

226.24(b) ..............................

226.24(c) ..............................

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be provided as part of the public
comment process.

226.26(c) ..............................

226.33(a) ..............................
226.34(d) ..............................

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Osage Form A—Lease
Contact of Record.
None.

None.

None.

None.

None.

Osage Form B—Evidence
of Authority to Execute
Papers.
Osage Form C—Oil and/or
Gas Mining Lease.
Osage Form B—Evidence
of Authority to Execute
Papers.
Osage Form C—Oil and/or
Gas Mining Lease.
Osage Form D—Lease
Amendment.
None.

None.

Osage Form E—Assignment of Record Title Interest.
None.
None.

Federal Register / Vol. 88, No. 9 / Friday, January 13, 2023 / Proposed Rules
Section(s)

Proposed revision(s) to OMB 1076–0180

226.36 ..................................

The OMC must submit a Resolution approving a royalty rate for oil that is below
the regulatory minimum of 121⁄2 percent. This requirement is the same as the requirement in existing § 226.11(a).
The OMC must submit a Resolution approving a royalty rate for gas that is below
the regulatory minimum of 121⁄2 percent. This requirement is the same as the requirement in existing § 226.11(b).
The OMC must submit a Resolution providing notice of its intention to take oil and/
or gas royalty in kind. This requirement is the same as the requirement in existing § 226.11(a), except that the new provision allows the OMC to take both oil
and gas royalty in kind, instead of allowing the OMC to only take oil royalty in
kind.
Lessees must submit contracts or division orders with purchasers of oil and gas.
This requirement is the same as the requirement in existing § 226.14, except that
the Superintendent’s approval of contracts and division orders is no longer required.
Lessees must make, retain, and preserve royalty, rental, and payment records for
six years from the date upon which the relevant transaction was recorded or
such longer period as the Superintendent or ONRR may require. This requirement is the same as the requirement in existing § 226.30, except that it reduces
the burden by providing a specific timeframe for record retention and clarifies that
both the Superintendent ONRR may request the subject records.
Lessees must file an individual well bond for each well the lessee proposes to drill,
reenter, recomplete, or accept responsibility for through assignment; a countywide bond covering all leases of the Osage Mineral Estate (10,240 acres maximum); or a nationwide bond covering all leases within the United States to which
the lessee is a party. This requirement is the same as the requirement in existing
§ 226.6(a).
Lessees and permittees must file an Oil and Gas Exploration Bond Form for geophysical exploration operations. An existing lessee with a countywide or nationwide Oil and Gas Lease Bond may file a bond rider covering geophysical exploration operations in lieu of filing an Oil and Gas Exploration Bond. There is no
form for bond riders because they are prepared by the surety.
Lessees must submit a request to expand an approved drilling site beyond the
acreage set forth in the approved EA. This requirement is the same as the requirement in existing § 226.19(b).
Lessees must submit an application for a permit to drill or reenter a well. This requirement is the same as the requirement in existing § 226.16(b), but the burden
on respondents is reduced because Osage Form 139 is now a fillable form that
can be completed and submitted electronically.
Lessees must notify the Superintendent of planned drilling and reentry operations
five days prior to the commencement thereof. Notice may be provided by phone
or email. This requirement is the same as the requirement in existing § 226.16(c),
except that the new provision specifies that the timeframe for providing notice is
five days as opposed to ‘‘a reasonable time in advance.’’.
Lessees must submit a request to drill a well within 300 feet of the lease boundary
or locate a well or tank within 200 feet of roads or highways maintained for public
use, water sources, and residences, granaries, and barns. This requirement is
the same as the requirement in existing § 226.33.
Lessees must submit a request to drill a well that deviates significantly from the
vertical and report the drilling of any well that deviates significantly from the
vertical without prior approval.
Lessees must submit an application for a permit to workover a well. This requirement is the same the requirement in existing § 226.16(b), but the burden hours
are reduced because Osage Form 139 is now a fillable form that can be completed and submitted electronically.
Lessees must notify the Superintendent of planned workover operations five days
prior to the commencement thereof. Notice may be provided by phone or email.
This requirement is the same as the requirement in existing § 226.16(c), except
that the new provision specifies that the timeframe for providing notice is five
days as opposed to ‘‘a reasonable time in advance.’’.
Lessees must submit the results of H2S concentration tests upon request and submit radius of exposure calculations for any well or production facility with an H2S
concentration of 100 ppm or more.
Lessees must report any release of a potentially hazardous volume of H2S as soon
as practicable, but not later than 24 hours following identification of the release.
Notice must be provided by phone. A lessee must submit a Public Protection
Plan for the potential release of a hazardous volume of H2S if:
1. The 100 ppm radius of exposure is greater than 50 feet and includes any
part of a residence, school, church, park, place of business, or other area
the general public can reasonably be expected to frequent;
2. The 500 ppm radius of exposure is greater than 50 feet and includes any
part of a federal, state, county, or municipal road or highway that is owned
and maintained for public use; or

226.39 ..................................
226.42(b) ..............................

226.44(a) ..............................

226.46(b) ..............................

226.51(c), 226.52(a) and (b)

226.56(a) and (c) .................

226.65(b) ..............................
226.66(a) ..............................

226.66(c) ..............................

226.66(d) ..............................

226.67(b) ..............................
226.69(a) ..............................

226.69(c) ..............................

226.70(a) ..............................

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226.70(b)(1) and (2) .............

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OMB 1076–0180 form(s)

13JAP3

None.
None.
None.

None.

None.

Osage Form F—Oil and
Gas Lease Bond.

Osage Form G—Oil and
Gas Geophysical Exploration Bond.
None.
Osage Form 139—Application for Permit to Drill or
Workover Wells.
None.

None.

None.
Osage Form 139—Application for a Permit to Drill
or Workover Wells.
None.

None.
None.

2446

Federal Register / Vol. 88, No. 9 / Friday, January 13, 2023 / Proposed Rules
Section(s)

226.70(d) ..............................
226.72 ..................................
226.73(d) ..............................

226.73(f) ...............................

226.73(h) ..............................

226.74(a) ..............................

226.74(c) through (f) ............

226.74(h) ..............................

226.76 ..................................

226.77(c) ..............................
226.77(d) ..............................

226.77(f) ...............................
226.79(a) ..............................

226.80 ..................................

226.81 ..................................

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226.82(d) ..............................

226.83(f) ...............................

226.84(e) ..............................

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Proposed revision(s) to OMB 1076–0180

OMB 1076–0180 form(s)

3. The 100 ppm radius of exposure if greater than or equal to 3,000 feet.
The regulations specify the information that Public Protection Plans must include.
Lessees must maintain a record of all tests of H2S monitoring systems and make
the records available to the Superintendent upon request.
Lessees must submit a request to temporarily abandon a well for more than 30 calendar days. This requirement is the same as the requirement in existing § 226.28.
Lessees must submit an application for a permit to plug a well. This requirement is
the same the requirement in existing § 226.28(a), (c), but the burden hours are
reduced because Osage Form 139 is now a fillable form that can be completed
and submitted electronically.
Lessees must notify the Superintendent of planned plugging operations five days
prior to the commencement thereof. Notice may be provided by phone or email.
This requirement is the same as the requirement in existing § 226.16(c), except
that the new provision specifies that the timeframe for providing notice is five
days as opposed to ‘‘a reasonable time in advance.’’.
Lessees must submit any agreement with a surface owner whereby the parties
agree that lessee will condition a well that is being plugged for the surface owner’s use as a water supply well. This requirement is the same as the requirement
in existing § 226.29(d).
Lessees must make all books and records relating to lease operations available to
the Superintendent upon request. This requirement is the same as the requirement in existing § 226.30.
Lessees must submit a report upon completion of all approved drilling, workover,
and plugging operations, together with copies of the results for all samples, tests,
and surveys conducted on the well; copies of the electrical, mechanical, and radioactive logs or other surveys of the wellbore; core analysis; and for plugging
operations, cementing tickets. This requirement is the same as the requirement
in existing § 226.32(a), (b) and (c).
Lessees must submit a report upon completion of hydraulic fracturing operations together with a report of the fracking fluids used. The regulations specify the information that such reports of fracking fluids must include. Lessees or owners of the
fracking fluid information may withhold proprietary information that is exempt from
public disclosure by submitting a signed withholding statement.
Lessees must maintain well records and reports for six years from the date they
were generated unless the Superintendent requires a longer retention period due
to an audit or investigation. This requirement is the same as the requirement in
existing § 226.32(c), except that the new provision specifies the timeframe for retention.
Lessees must submit the results of tests and surveys performed to establish the effectiveness of measures taken to protect fresh water and mineral bearing formations upon request. This requirement is the same as the requirement in existing
§ 226.35.
Lessees must submit a request to construct, utilize, enlarge, or relocate a pit. This
requirement is the same as the requirement in existing § 226.22(d).
Lessees must file a copy of any agreement whereby the lessee and surface owner
reach an alternative agreement regarding the emptying and leveling of pits. This
requirement is the same as the requirement in existing § 226.22(b).
Lessees must submit a request for the land-application of waste ..............................
A lessee or individual wishing to conduct oil and gas geophysical exploration activities within the Osage Mineral Estate must submit an Application for an Oil and
Gas Geophysical Exploration Permit. This requirement is the same as the requirement in existing § 226.16(a), except that the Proposed Rule provides a form
for such applications.
A lessee or permittee must notify the Superintendent of planned oil and gas geophysical operations five days prior to the commencement thereof. Notice may be
provided by phone or email.
A lessee or permittee must submit a Completion Report for Oil and Gas Geophysical Exploration Operations providing a subsequent report of the exploration
operations performed.
A person claiming an interest in leased lands for the purpose of the settlement of
surface damages must notify the Superintendent of that interest. This requirement is the same as the requirement in existing § 226.20(d).
A lessee or permittee must file a report of each settlement agreement whereby the
lessee or permittee and an Indian landowner agree to the amount of surface
damages to be paid. This requirement is the same as the requirement in existing
§ 226.21(g).
Lessees must report the emergency pumping of oil into a pit. Emergency reports
must be submitted by phone.

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None.
None.
Osage Form 139—Application for a Permit to Drill,
Workover, or Plug Wells.
None.

None.

None.

Osage Form 208—Well
Completion or Recompletion Report.
Osage Form 209—Report
of Workover or Plugging
Operations.
Osage Form 210—Withholding of Proprietary Hydraulic Fracturing Information.
None.

None.

None.
None.

None.
Osage Form 339—Application for Oil and Gas Geophysical Exploration Permit.
None.

Osage Form 408—Completion Report for Oil and
Gas Geophysical Exploration Operations.
None.

None.

None.

Federal Register / Vol. 88, No. 9 / Friday, January 13, 2023 / Proposed Rules
Section(s)

Proposed revision(s) to OMB 1076–0180

226.86(a) through (e) ...........

Lessees must submit a site facility diagram for all permanent facilities. The regulations specify the information that site facility diagrams must include and the timeframe for submitting site facility diagrams, which varies depending on the date
the relevant facilities became operational. Lessees have an ongoing obligation to
update and amend site facility diagrams if facilities are modified to ensure that
the diagrams accurately represent facilities. Sample site facility diagrams are
available at https://www.bia.gov/regional-offices/eastern-oklahoma/osage-agency.
Lessees, purchasers, transporters, and other persons involved in producing, transporting, purchasing, selling, or measuring oil and gas must retain all records for a
minimum of six years from the date upon which the relevant transaction was recorded unless the Superintendent or ONRR requires retention for a longer period. Such records must be made available to the Superintendent or ONRR upon
request. The regulations specify the information that production records must include.
A lessee may request the use of alternative protective measures to prevent drainage.
Persons engaged in transporting oil by motor vehicle or pipeline must maintain documentation showing the amount, origin, and intended first purchaser of the oil.
Lessees, purchasers, or transporters who drain water from a production storage
tank must document such draining operations. The regulations specify the information that documentation of water draining operations must include.
Lessees must document the removal of oil from storage, temporary use of the oil
for operations, and return of the oil to storage during hot-oil, clean-up, or completion operations. The regulations specify the information that documentation for
temporary removal of oil from storage must include.
Lessees must maintain a record of the seals used on valves and meter components. The regulations specify the information that seal records must include.
Lessees must submit a request for off-lease measurement of production. The regulations specify the information that requests for off-lease measurement of production must include.
Lessees must report spills, theft, mishandling of production, blowouts, fires, and accidents that occur on the lease by phone or email immediately upon discovery,
but not later than one calendar day following discovery. Lessees must also submit a written report of the incident together with a proposed contingency or remediation plan. The initial report of spills, theft, mishandling of production, blowouts,
fires, and accidents is provided by phone. This requirement is the same as the
requirement in existing § 226.41.
Lessees measuring oil by tank gauging must submit tank tables within 45 days
after calibrating a tank or recalculation of the tables. This requirement is the
same as the requirement in existing § 226.38, except that the new provision
specifies the timeframe for submitting tank tables.
Lessee must submit a request to use automatic tank gauging for oil measurement.
The regulations specify the information that requests to use automatic tank gauging must include. This requirement is the same as the requirement in existing
§ 226.38.
Lessees must submit a detailed log of field verifications of automatic tank gauges
upon request. This requirement is the same as the requirement in existing
§ 226.38.
Lessees must provide notice of any LACT system failures or equipment malfunctions that may have resulted in measurement error within 15 calendar days of
discovering such failure or malfunction.
Lessees must submit Coriolis meter specifications upon request. Lessees must
maintain the following information on-site at the FMP:
• Make, model, and size of each sensor;
• Make, model, range, and calibrated span of the pressure and temperature
transducers used to determine gross standard volume; and
• A log of all meter factors, zero verifications, and zero adjustments.
Lessees must retain QTRs, configuration logs, event logs, and alarm logs for six
years from the date they were generated or such longer period as the Superintendent may require.
Lessees must have a certificate of calibration for the meter prover (e.g., a device
that verifies the accuracy of the meter) on-site and available for review.
Lessees must submit a report of meter proving and volume adjustments within 14
days after any LACT system or CMS malfunction, including excessive meter-factor deviation.
Lessees must submit run tickets on or before the last calendar day of the month
following the production month. The regulations specify the information that run
tickets for tank gauging, LACT, and CMS must include. This requirement is the
same as the requirement in existing § 226.16(b), except that the new provision
specifies the information run tickets must contain. The information required is
consistent with what is currently submitted and prevailing industry standards.
Lessees must submit a request to use any method of oil measurement other than
tank gauging, LACT system, or CMS.

226.88(a) through (c) ...........

226.92(b) ..............................
226.97(a) and (b) .................
226.98 ..................................
226.99(a) ..............................

226.100 ................................
226.101(a) ............................
226.102(a) and (c) ...............

226.107(f) .............................

226.108(a) ............................

226.108(b)(5)(ii)(B) ...............
226.109(e) ............................
226.112(c), (e), (f), and (g) ..

226.113(b) ............................

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226.113(j) .............................
226.114(d) ............................

226.115 ................................

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OMB 1076–0180 form(s)

13JAP3

None.

None.

None.
None.
None.
None.

None.
None.
Osage Form H—Spill and
Remediation Report.

None.

None.

None.
None.
None.

None.
None.
None.

None.

2448

Federal Register / Vol. 88, No. 9 / Friday, January 13, 2023 / Proposed Rules
Section(s)

Proposed revision(s) to OMB 1076–0180

226.116(c) ............................

Lessees must submit a request to sell or dispose of slop oil and, following the approved sale or disposal of slop oil, must submit a report identifying the volume of
slop oil sold or disposed of, the method used to computer that volume, and the
gross revenue from the sale. This provision codifies lessees’ existing practices
for the sale or disposal of slop oil. Accordingly, it does not impose a new burden
on lessees with respect to such sales.
Lessees must document orifice plate inspections and include that documentation as
part of the verification report submitted in accordance with §§ 226.123 (for mechanical recorders) or 226.126 (for EGM systems). The regulations specify the
information that documentation of orifice plate inspections must include.
Lessees must document meter tube inspections and must make such documentation available upon request. The regulations specify the information that documentation of meter tube inspections must include.
Lessees must notify the Superintendent at least 72 hours in advance of performing
basic or detailed meter tube inspections under § 226.121(d), (g), and (h) or submit a monthly or quarterly schedule or inspections. Notice may be provided by
phone or email. This provision codifies lessees’ existing practice of providing notice of meter tube inspections but specifies that 72 hours’ advance notice be provided. The provision introduces the option for lessees to submit inspection
schedules to provide additional flexibility for notice requirements.
Lessees must maintain certain data at FMPs for mechanical recorders. The regulations specify the information that mechanical recorder data maintained at FMPs
must include.
Lessees must retain documentation of mechanical recorder verifications and make
such documentation available to the Superintendent upon request. The regulations specify the information that documentation of mechanical recorder
verifications must include.
Lessees must notify the Superintendent at least 72 hours in advance of performing
mechanical recorder verifications following installation or repair or performing routine verifications. Notice may be provided by phone or email, or lessees may
submit a monthly or quarterly schedule of verifications.
Purchasers or purchasers’ representatives must retain documentation of test equipment certifications on-site. The regulations specify the information that documentation of certification of test equipment include. This collection does not impose a burden on respondents pursuant to 5 CFR 1320.3(h)).
Lessees must retain an unedited integration statement and make such statement
available to the Superintendent upon request. The regulations specify the information that unedited integration statements must include. Lessees already obtain
integration statements containing the above information consistent with industry
standards. This provision codifies lessees’ existing practices. The requirement to
retain such statements is the same as the requirement in existing § 226.30.
Lessees must maintain certain data at FMPs for EGM systems. The regulations
specify the information that data for EGM systems must include.
Lessees must retain documentation of each verification of EGM systems and make
such documentation available to the Superintendent upon request. The regulations specify the information that documentation of EGM system verifications
must include.
Lessees must notify the Superintendent at least 72 hours before conducting routine
EGM system verifications and verifications following installation or repairs. Notice
may be provided by phone or email, or lessees may submit a monthly or quarterly verification schedule. This provision codifies lessees’ existing practice of
providing notice EGM verifications but specifies that 72 hours’ advance notice be
provided.
Purchasers or purchasers’ representatives must maintain documentation of test
equipment certifications on-site. The regulations specify the information that documentation of test equipment certifications must include. This collection does not
impose a burden on respondents pursuant to 5 CFR 1320.3(h)).
Lessees must retain QTRs for EGM systems and make them available to the Superintendent upon request. The regulations specify the information that QTRs for
EGM systems must include.
Lessees must retain the original, unaltered, unprocessed, and unedited configuration log for the EGM system and make it available upon request. The regulations
specify the information that configuration logs must include.
Lessees must retain the original, unaltered, unprocessed, and unedited event log
for the EGM system and make it available upon request. The regulations require
the configuration log to contain the information identified in API 21.1, subsection
5.5 and have sufficient capacity to be retrieved and stored at intervals that will
maintain a continuous record of events for either the required six-year retention
period or the life of the FMP, whichever is shorter.
Lessees must retain an alarm log and make it available upon request. The regulations require alarm logs to comply with the requirements set forth in API 21.1,
Subsection 5.6.

226.121(e) ............................

226.121(i) .............................

226.121(j) .............................

226.122(g) ............................

226.123(d) ............................

226.123(e) ............................

226.123(g) ............................

226.124(a) ............................

226.125(e) ............................
226.126(e) ............................

226.126(f) .............................

226.126(h) ............................

226.128(a) ............................

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226.128(b) ............................

226.128(c) ............................

226.128(d) ............................

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13JAP3

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Federal Register / Vol. 88, No. 9 / Friday, January 13, 2023 / Proposed Rules
Section(s)

Proposed revision(s) to OMB 1076–0180

226.131(b) ............................

Lessees must notify the Superintendent at least 72 hours before obtaining a spot
sample. Notice may be provided by phone or email, or lessees may submit a
monthly or quarterly sampling schedule. This provision codifies lessees’ existing
practice of providing notice of spot sampling but specifies that 72 hours’ advance
notice be provided. The provision introduces the option for lessees to submit spot
sample schedules to provide additional flexibility for notice requirements.
Lessees must maintain documentation of the cleaning of sample cylinders and
make such documentation available upon request.
Lessees must maintain documentation demonstrating that the cylinder was evacuated and pre-charged before sampling for spot sampling using the Helium ‘‘pop’’
method and make such documentation available upon request.
Lessees must maintain documentation of the seal material and type of lubricant
used for the floating piston cylinder method of spot sampling and make such
documentation upon request.
Lessees must retain documentation of the gas chromatograph verifications and
make the documentation available upon request. The regulations specify the information that documentation of gas chromatograph verifications must include.
Lessees must submit all gas analysis reports within 14 calendar days after the due
date for the sample as specified in § 226.133. The regulations specify the information that gas analysis reports must include.
Lessees must document all edits made to reported heating value or volume data
before the report is submitted to ONRR, including verifiable justifications for the
edits made, and such documentation must be made available upon request.
Lessees must submit a request to stop furnishing gas to Tribally owned buildings or
enterprises or members of the Osage Nation residing in Osage County. This requirement is the same as the requirement in existing § 226.27(b)(3).
Lessees must submit a request for certain royalty-free uses of production on the
lease or unit. The regulations require the Superintendent’s approval of:
• Use of oil or gas the lessee removes from the pipeline at a location downstream of the FMP;
• Use of gas that has been removed from the lease or unit for treatment or
processing because the particular physical characteristics of the gas require
it to be treated or processed prior to use, where the gas is returned to, and
used on, the same lease or unit from which it is produced; and
• Any other uses of produced oil and gas for operations and production purposes that are not set forth in § 226.145.
The regulations specify the information that requests for royalty-free use of production on the lease or unit must include.
Lessees must submit a request for certain royalty-free uses of production off the
lease or unit. The regulations require the Superintendent’s approval of royaltyfree treatment of oil or gas used in operations conducted off the lease or unit if
the:
• Use is among those listed in §§ 226.145(a) or 226.146(a);
• Equipment or facility in which the operation is conducted is located off the
lease or unit for engineering, economic, resource protection, or physical accessibility reasons; and
• Operations are conducted upstream of the FMP.
The regulations specify the information that requests for royalty use of production
off the lease or unit must include.
Lessees must notify the Superintendent in writing if oil or gas is removed downstream of the FMP for royalty-free use pursuant to §§ 226.145 through 226.148
and obtain an approved FMP to measure the production removed for use.
Lessees must submit a request to vent or flare gas. The regulations require the Superintendent’s approval to vent or flare gas to ensure that the natural gas disposed of through venting or flaring is properly measured and, where applicable,
proper royalties paid. This provision codifies the Superintendent’s existing notice
to lessees requiring prior approval for all venting and flaring. Accordingly, this
provision does not impose a new burden on lessees.
Lessees must submit a self-certification following the correction of any lease violations for which a notice of non-compliance is received. This provision codifies the
Superintendent’s existing requirement that self-certification forms be submitted
upon completion of the correction of lease violations. Accordingly, this provision
does not impose a new burden on lessees.

226.131(c) ............................
226.132(a)(2) .......................
226.132(a)(3) .......................
226.136(e) ............................
226.138(a), (e) .....................
226.141(c)(2) ........................
226.142(d) ............................
226.146(b) ............................

226.148(c) ............................

226.149(d) ............................
226.152(a) ............................

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226.158 ................................

Title of Collection: Mining of the
Osage Mineral Estate for Oil and Gas.
OMB Control Number: 1076–0180.
Abstract: Under the 1906 Act, the BIA
is required to administer oil and gas
leasing and development of the Osage
Mineral Estate. The BIA needs to

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perform the IC activities set forth in the
regulations at 25 CFR part 226 to
perform its responsibilities under the
statute.
Form Number: Osage Form A (Lease
Contact of Record); Osage Form B
(Evidence of Authority to Execute

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OMB 1076–0180 form(s)
None.

None.
None.
None.
None.
None.
None.
None.

None.

None.

None.
None.

Osage Form I—Self-Certification for Correction of
Lease Violations.

Papers); Osage Form C (Oil and Gas
Mining Lease); Osage Form D (Lease
Amendment); Osage Form E
(Assignment of Record Title Interest);
Osage Form F (Oil and Gas Lease Bond);
Osage Form G (Oil and Gas Geophysical
Exploration Bond); Osage Form H (Spill

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2450

Federal Register / Vol. 88, No. 9 / Friday, January 13, 2023 / Proposed Rules

and Remediation Report); Osage Form I
(Self-Certification for Correction of
Lease Violations); Osage Form 139
(Application for Permit to Drill or
Workover Wells); Osage Form 208 (Well
Completion or Reentry Report); Osage
Form 209 (Report of Workover or
Plugging Operations); Osage Form 210
(Withholding of Proprietary Hydraulic
Fracturing Information); Osage Form
339 (Application for Permit to Conduct
Oil and Gas Geophysical Exploration
Operations); Osage Form 408 (Oil and
Gas Geophysical Exploration
Completion Report).
Type of Review: Revision of a
currently approved collection.

2. OMB Control Number 1012–0004
(ONRR)
The OMB has reviewed and approved
information collections for ONRR’s
royalty and production reporting
operations throughout the rest of Indian
country, which are assigned OMB
Control No. 1012–0004. ONRR is
proposing to renew information
collection 1012–0004 with revisions to
provide for such collections within the
Osage Mineral Estate. The following
ONRR royalty and production reporting
and recordkeeping requirements in the
proposed rule require OMB’s approval:

Section(s)

Proposed revision(s) to OMB 1012–0004

226.43(c) and (d) .................

Lessees must make royalty payments to ONRR by EFT (preferred) or the other
forms of payment identified in § 226.8. Non-EFT royalty payments submitted via
U.S. Postal Service must be addressed to: Office of Natural Resources Revenue,
P.O. Box 25627, Denver, CO 80225–0627. Royalty reports submitted manually
via courier or overnight delivery service must be addressed to: Office of Natural
Resources Revenue, Denver Federal Center, Building 85, Entrance N–1, Room
332, 6th Avenue and Kipling Street, Denver, CO 80225.
Lessees must submit certified monthly royalty reports to ONRR by 4 p.m. mountain
time on or before the last calendar day of the month that follows the month during which the oil and gas is produced and sold. Royalty reports must be submitted electronically via ONRR’s eCommerce Reporting website, https://
onrrreporting.onrr.gov, unless the lessee meets the qualifications for manual reporting. Royalty reports submitted manually via U.S. Postal Service must be addressed to: Office of Natural Resources Revenue, P.O. Box 25627, Denver, CO
80225–0627. Royalty reports submitted manually via courier or overnight delivery
service must be addressed to: Office of Natural Resources Revenue, Denver
Federal Center, Building 85, Entrance N–1, Room 332, 6th Avenue and Kipling
Street, Denver, CO 80225.
Lessees must make, retain, and preserve records demonstrating that rental, royalty, and other payments relating to oil and gas leases comply with the terms and
conditions of the lease, the regulations in 25 CFR part 226, and applicable orders and notices. Lessees must preserve records for a minimum of six years
from the date upon which the relevant transaction was recorded unless the Superintendent or ONRR provides notice that records must be maintained for a
longer period due to investigation or audit. Lessees must make records available
to the Superintendent ONRR for inspection upon request. Covered under burden
for §§ 226.32(c) and (d) and 226.45.
Lessees must submit certified monthly productions reports to ONRR by 4 p.m.
mountain time on or before the 15th day of the second month following the production month. Production reports must be submitted electronically via ONRR’s
eCommerce Reporting website, https://onrrreporting.onrr.gov, unless the lessee
meets the qualifications for manual reporting. Production reports submitted
manually via U.S. Postal Service must be addressed to: Office of Natural Resources Revenue, P.O. Box 25627, Denver, CO, 80225–0627. Production reports
submitted manually via courier or overnight delivery service must be addressed
to: Office of Natural Resources Revenue, Denver Federal Center, Building 85,
Entrance N–1, Room 332, 6th Avenue and Kipling Street, Denver, CO 80225.
Lessees, purchasers, transporters, and other persons involved in producing, transporting, purchasing, selling, or measuring oil and gas through the point of royalty
measurement or point of first sale, whichever is later, must retain all records, including source records, relevant to determining the quality, quantity, disposition,
and verification of production attributable to the subject lease. The regulations
specify the information that production records must include. Production records
must be preserved for a minimum of six years from the date upon which the relevant transaction was recorded unless the Superintendent or ONRR provides notice that records must be maintained for a longer period due to investigation or
audit. Lessees must make records available to the Superintendent ONRR for inspection upon request. Covered under burden for § 226.85.

226.45 ..................................

226.46 ..................................

226.85 ..................................

226.88 ..................................

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Respondents/Affected Public:
Individual Indians, businesses, and
Tribal authorities.
Total Estimated Number of Annual
Respondents: 4,974.
Total Estimated Number of Annual
Responses: 59,196.
Estimated Completion Time per
Response: Varies from six minutes to 40
hours.
Total Estimated Number of Annual
Burden Hours: 22,564.
Respondent’s Obligation: Required to
obtain a benefit.
Frequency of Collection: Varies from
monthly to yearly.
Total Estimated Annual Non-Hour
Burden Cost: $0.

Title of Collection: Royalty and
Production Reporting.

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OMB Control Number: 1012–0004.

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OMB 1012–0004 Form(s)
None.

ONRR 2014—Report of
Sales and Royalty Remittance.

None.

ONRR 4054—Oil and Gas
Operations Report
(OGOR).

None.

Revisions: Under the 1906 Act, the
BIA is required to administer oil and gas

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Federal Register / Vol. 88, No. 9 / Friday, January 13, 2023 / Proposed Rules
leasing and development of the Osage
Mineral Estate. The proposed rule
would allow BIA to transfer the royalty
and production reporting and
compliance functions for the Osage
Mineral Estate to ONRR. ONRR would
perform the specified IC activities in 25
CFR part 226 to carry out the BIA’s
responsibilities and ensure that lessees
pay proper royalties and revenues on oil
and gas produced from the Osage
Mineral Estate. The requirement to
timely and accurately report royalties
and production is mandatory.
Form Number: ONRR–2014, ONRR–
4054.
Type of Review: Revision of a
currently approved collection.
Respondents/Affected Public:
Businesses.

Frequency of Collection: Monthly.
Total Estimated Annual Non-Hour
Burden Cost: ONRR identified no ‘‘nonhour cost’’ burden associated with this
information collection.
3. OMB Control Number 1012–0006
(ONRR)
The OMB has reviewed and approved
information collections for ONRR’s
suspensions pending appeal and
bonding throughout the rest of Indian
country, which are assigned OMB
Control No. 1012–0006. ONRR is
proposing to renew information
collection 1012–0006 with revisions to
provide for such collections within the
Osage Mineral Estate. The following
ONRR suspensions pending appeal and
bonding requirements in the proposed
rule require OMB’s approval:

Section(s)

Proposed revision(s) to OMB 1012–0006

226.179(b)(2) .......................

A party who appeals an order regarding the payment and reporting of royalties, or
other payments due, may suspend compliance with such order by submitting an
ONRR-specified surety instrument within 60 days after receiving the Order or Notice of Order.

226.180(a) ............................

Any other person, including a designee, payor, or affiliate, may post a bond or
other surety instrument on behalf of an appellant. If such person is assuming an
appellant’s responsibility, they must notify ONRR in writing of such assumption.
Covered under burden for § 226.179(b)(2).
ONRR will suspend an obligation to comply with an order if the amount under appeal is $1,000 or more if the appellant submits an ONRR-specified surety instrument within the required timeframe. Covered under burden for § 226.179(b)(2).
An appellant whose appeal is not decided within one year from the filing date must
increase the surety amount to cover additional estimated interest for another
one-year period and continue such increases annually. Covered under burden for
§ 226.179(b)(2).

226.182(b)(2) .......................
226.185(c) ............................

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Total Estimated Number of Annual
Respondents: 3,490 oil, gas, and
geothermal reporters.
Total Estimated Number of Annual
Responses: 12,827,063 lines of data.
Estimated Completion Time per
Response: Varies between 1 and 7
minutes per line, depending on the
activity. The average completion time is
1.72 minutes per line. The average
completion time is calculated by first
multiplying the estimated annual
burden hours (369,379) by 60 to obtain
the total annual burden minutes. Then
the total annual burden minutes
(22,162,740) is divided by the estimated
annual number of lines submitted
(12,827,063).
Total Estimated Number of Annual
Burden Hours: 369,379.
Respondent’s Obligation: Mandatory.

Title of Collection: Suspensions
Pending Appeal and Bonding.
OMB Control Number: 1012–0006.
Revision: Under the 1906 Act, the BIA
is required to administer oil and gas
leasing and development of the Osage
Mineral Estate. The proposed rule
would allow BIA to transfer the royalty
and production reporting and
compliance functions for the Osage
Mineral Estate to ONRR. ONRR would
perform the specified IC activities in 25
CFR part 226 to carry out enforcement
and compliance actions for the Osage
Mineral Estate.
Form Number: ONRR–4435, ONRR–
4436, and ONRR–4437.
Type of Review: Revision of a
currently approved collection.
Respondents/Affected Public:
Businesses.
Total Estimated Number of Annual
Respondents: 107.
Total Estimated Number of Annual
Responses: 107.
Estimated Completion Time per
Response: The time per response is 120

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mins. The average completion time is
calculated by first multiplying the
estimated annual burden hours (214
burden hours) by 60 to obtain the total
annual burden minutes. Then the total
annual burden minutes (12,840) is
divided by the estimated annual
responses (107).
Total Estimated Number of Annual
Burden Hours: 214.
Respondent’s Obligation: Mandatory.
Frequency of Collection: Annually
and on occasion.
Total Estimated Annual Non-Hour
Burden Cost: There are no additional
recordkeeping costs associated with this
information collection. However, ONRR
estimates 5 appellants per year will pay
a $50 fee to obtain credit data from a
business information or credit reporting
service, which is a total non-hour cost
burden of $250 per year (5 appellants
per year × $50 = $250).

2451

OMB 1012–0006 Form(s)
ONRR 4435—Administrative Appeal Bond.
ONRR 4436—Letter of
Credit.
ONRR 4437—Assignment
of Certificate of Deposit.
None.

None.
None.

significantly affecting the quality of the
human environment under the National
Environmental Policy Act of 1969
(NEPA), 42 U.S.C. 4321, et seq.
Therefore, this proposed rule is
categorically excluded from further
review under 43 CFR 46.210(i) because
these are regulations ‘‘whose
environmental effects are too broad,
speculative, or conjectural to lend
themselves to meaningful analysis and
will later be subject to the NEPA review
process either collectively or case by
case.’’ No extraordinary circumstances
exist that require greater NEPA review.
K. Effects on the Energy Supply
(Executive Order 13211)
This proposed rule is not a significant
energy action under the definition in
Executive Order 13211. A statement of
Energy Effects is not required.

J. National Environmental Policy Act

L. Clarity of This Regulation (Executive
Orders 12866, 12988, and 13563)

This proposed rule does not
constitute a major Federal action

We are required by Executive Orders
12866, 12988, and 13563 and by the

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Federal Register / Vol. 88, No. 9 / Friday, January 13, 2023 / Proposed Rules

Presidential Memorandum of June 1,
1988, to write all rules in plain
language. This means that each rule
must:
(a) Be logically organized;
(b) Use the active voice to address
readers directly;
(c) Use clear language rather than
jargon;
(d) Be divided into short sections and
sentences; and
(e) Use lists and tables wherever
possible.
If you feel that we have not met these
requirements, send us comments using
one of the methods listed in the
ADDRESSES section. To better help the
BIA revise the rule, your comments
should identify the numbers of the
sections or paragraphs that you find
unclear and specify which sections or
sentences are too long, the sections
where you believe lists or tables would
be useful.
List of Subjects in 25 CFR Part 226
Administrative practice and
procedure, Environmental protection,
Incorporation by reference, Indianslands, Mineral royalties, Oil and gas
exploration, Oil and gas measurement,
Penalties, Reporting and recordkeeping
requirements.
For the reasons stated in the
preamble, the Bureau of Indian Affairs
proposes to revise 25 CFR part 226 as
follows:
PART 226—MINING OF THE OSAGE
MINERAL ESTATE FOR OIL AND GAS

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Subpart A—General
Sec.
226.0 Incorporation by reference (IBR).
226.1 Definitions.
226.2 Authorities that govern oil and gas
activities within the Osage Mineral
Estate.
226.3 Authority and responsibility of the
Superintendent of the Osage Agency.
226.4 Authority and responsibility of the
Office of Natural Resources Revenue
(ONRR).
226.5 Orders and notices.
226.6 Service of official correspondence.
226.7 Forms.
226.8 Acceptable forms of payment.
226.9 Environmental reviews and cultural
surveys.
226.10 Information collection.
226.11 Public availability of information.
Subpart B—Acquiring a Lease
Authorized Procedures
226.12 Procedures the Osage Minerals
Council may use to enter into a lease.
Competitive Leases
226.13 Advertisement of a lease sale.
226.14 Nominating lands for a lease sale.
226.15 Publication of a Notice of Lease
Sale.

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226.16 Bidding system.
226.17 Award of leases.
Non-Competitive Leases
226.18 Submitting an offer to lease.
226.19 Acceptance of an offer to lease.
Lease Terms
226.20 Types of leases.
226.21 Primary term of leases.
226.22 Effect of changes in current
regulations on existing leases.
226.23 U.S. Government employees may
not acquire leases.
Subpart C—Cooperative Agreements and
Unitization
226.24 Cooperative agreements.
226.25 Unit development plans.
Subpart D—Transferring a Lease by
Assignment
226.26 Assignment of record title interest in
a lease.
226.27 Qualifications of the assignee.
226.28 Effective date of transfer.
226.29 Effect of assignment on the
assignor’s liability under the lease.
226.30 Effect of assignment on the
assignee’s liability under the lease.
226.31 Overriding royalty agreements.
226.32 Drilling contracts.
Subpart E—Ending a Lease
226.33 Surrender of all or any portion of a
lease.
226.34 Termination of a lease by operation
of law.
Subpart F—Rental and Royalty
Rental Obligations
226.35 Annual rental requirements.
Royalty Obligations
226.36 Royalty rate for oil.
226.37 Calculating the value of oil for
royalty purposes.
226.38 Gravity adjustment for oil.
226.39 Royalty rate for gas.
226.40 Calculating the value of gas for
royalty purposes.
226.41 Minimum royalty.
226.42 Royalty-in-kind.
226.43 Royalty payments.
226.44 Royalty payment contracts and
division orders.
226.45 Royalty reports.
226.46 Requirements for royalty, rental, and
payment records.
226.47 Right of the U.S. Government to
purchase oil.
Audits
226.48 Audits and reviews.
Subpart G—Bonds
Lease Bonds
226.49 Grandfathering of existing bonds.
226.50 Bond obligations.
226.51 Individual well bond requirements.
226.52 Countywide and nationwide bond
requirements.
226.53 Authorization to increase the
required bond amount.
226.54 Bond forfeiture.
226.55 Termination of the period of liability
and release of bonds.

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Geophysical Exploration Bonds
226.56 Geophysical exploration bond
requirements.
226.57 Bond forfeiture.
226.58 Termination of the period of liability
and release of bonds.
Subpart H—Operations
General Requirements
226.59 Conduct of operations.
226.60 Inspection of operations.
Commencement of Operations
226.61 No operations may commence prior
to approval of a lease or geophysical
exploration permit.
226.62 Prior authorization required to
commence operations on trust or
restricted lands.
226.63 Notice and information to be given
to surface owners prior to
commencement of operations.
226.64 Payment of commencement money
and tank siting fees to the surface owner.
Drilling, Workover, and Well Abandonment
Operations
226.65 Use of surface lands and water for
operations.
226.66 Drilling operations.
226.67 Well control.
226.68 Use of gas for artificial lifting of oil.
226.69 Workover operations.
226.70 Requirements for operations in
Hydrogen Sulfide (H2S) areas.
226.71 Surveys, samples, and tests.
226.72 Temporary abandonment.
226.73 Permanent plugging and
abandonment operations.
226.74 Well records and reports.
226.75 Well and facility identification.
226.76 Pollution prevention.
226.77 Storage and disposal of fluids.
226.78 Removal of fire hazards.
Geophysical Exploration Operations
226.79 Applying for a geophysical
exploration permit.
226.80 Commencement of operations.
226.81 Records and reports.
Settlement of Surface Damages
226.82 Lessee or permittee required to settle
surface damages.
226.83 Procedure for settlement of surface
damages.
Subpart I—Production and Site Security
General Requirements
226.84 Production obligations.
226.85 Production reporting.
226.86 Site facility diagrams.
226.87 Assignment of facility measurement
point (FMP) numbers.
226.88 Requirements for production
records.
226.89 Easements for access to wells
located off-lease.
Waste Prevention
226.90 Prevention of waste.
226.91 Royalty on lost or wasted
production.
Drainage Requirements
226.92 Prevention of drainage.
226.93 Compensatory royalty for drainage.

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Site Security
226.94 Storage and sales facilities—seals.
226.95 Oil measurement system
components—seals.
226.96 Removing production from tanks for
sale and transportation by truck.
226.97 Documentation required for
transportation of oil and gas.
226.98 Water draining operations.
226.99 Hot oiling, clean-up, and completion
operations.
226.100 Seal records.
226.101 Requirements for off-lease
measurement of production.
226.102 Report of spills, theft, mishandling
of production, accidents, or fires.

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Subpart J—Oil Measurement
226.103 General requirements.
226.104 Timeframes for compliance.
226.105 [Reserved]
226.106 Specific measurement performance
requirements.
226.107 Tank gauging—general
requirements.
226.108 Tank gauging—procedures.
226.109 LACT system—general
requirements.
226.110 LACT system—components and
operating requirements.
226.111 Coriolis measurement systems
(CMS)—general requirements and
components.
226.112 Coriolis meter—operating
requirements.
226.113 Meter proving requirements.
226.114 Run tickets.
226.115 Oil measurement by alternate
methods.
226.116 Determination of oil volumes by
methods other than measurement.
Subpart K—Gas Measurement
226.117 General requirements.
226.118 Timeframes for compliance.
226.119 [Reserved]
226.120 Specific performance requirements.
226.121 Flange-tapped orifice plates
(primary devices).
226.122 Mechanical recorder (secondary
device).
226.123 Verification and calibration of
mechanical recorder.
226.124 Integration statements.
226.125 Electronic gas measurement
(secondary and tertiary device).
226.126 Verification and calibration of
electronic gas measurement systems.
226.127 Flow rate, volume, and average
value calculation.
226.128 Logs and records.
226.129 Gas sampling and analysis.
226.130 Sampling probe and tubing.
226.131 Spot samples—general
requirements.
226.132 Spot samples—allowable methods.
226.133 Spot samples—frequency.
226.134 Composite sampling methods.
226.135 On-line gas chromatographs.
226.136 Gas chromatographs.
226.137 Components to analyze.
226.138 Gas analysis report requirements.
226.139 Effective date of a spot or
composite gas sample.
226.140 Calculation of heating value and
volume.

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226.141 Reporting of heating value and
volume.
Subpart L—Tribal and Royalty-Free Use of
Production
Tribal Use of Gas Production
226.142 Use of gas by the Osage Nation and
Tribe members.
226.143 Royalty on gas furnished for Tribal
use.
Royalty–Free Use of Lease Production
226.144 Production on which no royalty is
due.
226.145 Uses of production on a lease or
unit that do not require the
Superintendent’s prior approval of
royalty-free treatment.
226.146 Uses of production on a lease or
unit that require the Superintendent’s
prior approval of royalty-free treatment.
226.147 Uses of production moved off the
lease or unit that do not require the
Superintendent’s prior approval of
royalty-free treatment.
226.148 Uses of production moved off the
lease or unit that require the
Superintendent’s prior approval of
royalty-free treatment.
226.149 Measurement or estimation of
royalty-free volumes of oil or gas.
226.150 Ownership of equipment or
facilities.
226.151 Requesting approval of royalty-free
treatment for volumes used.
Subpart M—Venting and Flaring
226.152 General requirements.
226.153 Gas-well gas.
226.154 Oil-well gas.
226.155 Limitations on venting gas.
226.156 Authorized venting and flaring of
gas.
226.157 Measurement and reporting of
volumes of gas vented or flared.
Subpart N—Assessments and Penalties
Lease Management Assessments and Civil
Penalties
226.158 Remedies for violations of lease or
permit terms and conditions, regulations,
orders, and notices.
226.159 Immediate assessments for
violations of certain operating
regulations.
226.160 Other assessments.
226.161 Civil penalties with a period to
correct.
226.162 Civil penalties without a period to
correct.
226.163 Penalty amount.
226.164 Shut-in actions.
226.165 Lease or permit cancellation.
226.166 Payment of assessments and civil
penalties.
Royalty Management Assessments and Civil
Penalties
226.167 Remedies for violations of lease or
permit terms and conditions, regulations,
orders, and notices.
226.168 Assessments for incorrect or late
reports and failure to report.
226.169 Assessments for failure to submit
payment amount indicated on a form or
bill document or to provide adequate
information.

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226.170 Civil penalties with a period to
correct.
226.171 Civil penalties without a period to
correct.
226.172 Penalty amount.
226.173 Payment of civil assessments and
civil penalties.
226.174 Collection of unpaid civil
penalties.
226.175 Debt collection and administrative
offset.
Criminal Penalties
226.176 Penalties for filing fraudulent
reports.
Subpart O—Appeals
Appeals of BIA Decisions
226.177 Procedure for filing an
administrative appeal of a decision,
order, or notice of the Superintendent.
Appeals of ONRR Decisions
226.178 Procedures for filing an
administrative appeal of an order from
ONRR.
226.179 Suspension of compliance with an
ONRR order.
226.180 Requirements for posting a bond or
other surety on behalf of appellant.
226.181 Suspension of obligation to comply
with an ONRR order due to judicial
review in federal court.
226.182 ONRR’s collection of bonds and
other surety instruments.
226.183 ONRR bond-approving officer’s
determination of surety amount not
subject to appeal.
226.184 Standards for ONRR-specified
surety instruments.
226.185 ONRR’s determination of bond or
surety instrument amount.
Appendix A Appendix A to Part 226—
Table of Atmospheric Pressures
Authority: Sec. 3, Pub. L. 59–321, 34 Stat.
543; Secs. 1–2, Pub. L. 66–360, 41 Stat. 1249;
Secs. 1–2, Pub. L. 70–919, 45 Stat. 1478; Sec.
3, Pub. L. 75–711, 52 Stat. 1034; Pub. L. 81–
548, 65 Stat. 215; Pub. L. 88–632, 78 Stat.
1008; Secs. 2, 4, Pub. L. 95–496, 92 Stat.
1660.

Subpart A—General
§ 226.0

Incorporation by reference (IBR).

Certain material is incorporated by
reference into this part with the
approval of the Director of the Federal
Register under 5 U.S.C. 552(a) and 1
CFR part 51. To enforce any edition
other than those specified in this
section, the Bureau of Indian Affairs
(BIA) must publish a document in the
Federal Register, and the material must
be available to the public. All approved
incorporation by reference (IBR)
material is available for inspection at
the BIA and at the National Archives
and Records Administration (NARA).
To inspect the material at BIA, contact:
the BIA Osage Agency, 513 Grandview
Avenue, Pawhuska, OK 74056; phone
918–287–5700. For information on the
availability of this material at NARA,

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visit www.archives.gov/federal-register/
cfr/ibr-locations.html or email
[email protected]. The material
may be obtained from the following
sources:
(a) American Petroleum Institute
(API), 200 Massachusetts Avenue NW,
Suite 1100, Washington, DC 20005;
phone: 202–682–8000; website: https://
www.api.org.
(1) API Manual of Petroleum
Measurement Standards (MPMS),
Chapter 2—Tank Calibration, Section
2A—Measurement and Calibration of
Upright Cylindrical Tanks by the
Manual Tank Strapping Method; First
Edition, February 1995; Reaffirmed
August 2017 (‘‘API 2.2A’’); IBR
approved for § 226.107(f).
(2) API MPMS Chapter 2—Tank
Calibration, Section 2B—Calibration of
Upright Cylindrical Tanks Using the
Optical Reference Line Method; First
Edition, March 1989; Reaffirmed, April
2019; Addendum 1, October 2019 (‘‘API
2.2B’’); IBR approved for § 226.107(f).
(3) API MPMS Chapter 2—Tank
Calibration, Section 2C—Calibration of
Upright Cylindrical Tanks Using the
Optical-Triangulation Method; First
Edition, January 2002; Reaffirmed April
2019 (‘‘API 2.2C’’); IBR approved for
§ 226.107(f).
(4) API MPMS Chapter 3—Tank
Gauging, Section 1A—Standard Practice
for the Manual Gauging of Petroleum
and Petroleum Products; Third Edition,
August 2013; Reaffirmed December
2018 (‘‘API 3.1A’’); IBR approved for
§ 226.108(b).
(5) API MPMS Chapter 3—Tank
Gauging, Section 1B—Standard Practice
for Level Measurement of Liquid
Hydrocarbons in Stationary Tanks by
Automatic Tank Gauging; Third Edition,
April 2018 (‘‘API 3.1B’’); IBR approved
for § 226.108(b).
(6) API MPMS Chapter 3—Tank
Gauging, Section 6—Measurement of
Liquid Hydrocarbons by Hybrid Tank
Measurement Systems; First Edition,
February 2001; Errata September 2005;
Reaffirmed January 2017 (‘‘API 3.6’’);
IBR approved for § 226.108(b).
(7) API MPMS Chapter 4—Proving
Systems, Section 1—Introduction; Third
Edition, February 2005; Reaffirmed June
2014 (‘‘API 4.1’’); IBR approved for
§ 226.113(c).
(8) API MPMS Chapter 4—Proving
Systems, Section 2—Displacement
Provers; Third Edition, September 2003;
Reaffirmed March 2011, Addendum
February 2015 (‘‘API 4.2’’); IBR
approved for § 226.113(b) and (c).
(9) API MPMS Chapter 4—Proving
Systems, Section 5—Master-Meter
Provers; Fourth Edition, June 2016,

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(‘‘API 4.5’’); IBR approved for
§ 226.113(b).
(10) API MPMS Chapter 4—Proving
Systems, Section 6—Pulse Interpolation;
Second Edition, May 1999; Errata April
2007; Reaffirmed October 2013 (‘‘API
4.6’’); IBR approved for § 226.113(c).
(11) API MPMS Chapter 4—Proving
Systems, Section 8—Operation of
Proving Systems; Second Edition,
September 2013 (‘‘API 4.8’’); IBR
approved for § 226.113(b).
(12) API MPMS Chapter 4—Proving
Systems, Section 9—Methods of
Calibration for Displacement and
Volumetric Tank Provers, Part 2—
Determination of the Volume of
Displacement and Tank Provers by the
Waterdraw Method of Calibration; First
Edition, December 2005; Reaffirmed
July 2015 (‘‘API 4.9.2’’); IBR approved
for § 226.113(b).
(13) API MPMS Chapter 5—Metering,
Section 6—Measurement of Liquid
Hydrocarbons by Coriolis Meters; First
Edition, October 2002; Reaffirmed
November 2013 (‘‘API 5.6’’); IBR
approved for §§ 226.111(d); 226.113(i)
and (j).
(14) API MPMS Chapter 6—Metering
Assemblies, Section 1—Lease
Automatic Custody Transfer (LACT)
Systems; Second Edition, May 1991;
Reaffirmed May 2012 (‘‘API 6.1’’); IBR
approved for § 226.110(a) and (b).
(15) API MPMS Chapter 7—
Temperature Determination, Section 1—
Liquid-in-glass Thermometers, Second
Edition, August 2017 (‘‘API 7.1’’); IBR
approved for § 226.108(b).
(16) API MPMS Chapter 7—
Temperature Determination, Section 2—
Portable Electronic Thermometers;
Third Edition, May 2018 (‘‘API 7.2’’);
IBR approved for § 226.108(b).
(17) API MPMS Chapter 7—
Temperature Determination, Section 4—
Dynamic Temperature Measurement,
Second Edition, January 2018 (‘‘API
7.4’’); IBR approved for § 226.110(b).
(18) API MPMS Chapter 8—Sampling,
Section 1—Standard Practice for
Manual Sampling of Petroleum and
Petroleum Products; Fourth Edition,
October 2013 (‘‘API 8.1’’); IBR approved
for §§ 226.108(b); 226.113(i).
(19) API MPMS Chapter 8—Sampling,
Section 2—Standard Practice for
Automatic Sampling of Petroleum and
Petroleum Products; Fourth Edition,
November 2016 (‘‘API 8.2’’); IBR
approved for §§ 226.110(b); 226.113(i).
(20) API MPMS Chapter 8—Sampling,
Section 3—Standard Practice for Mixing
and Handling of Liquid Samples of
Petroleum and Petroleum Products;
First Edition, October 1995; Reaffirmed,
March 2015 (‘‘API 8.3’’); IBR approved
for §§ 226.110(b); 226.113(i).

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(21) API MPMS Chapter 9—Density
Determination, Section 1—Standard
Test Method for Density, Relative
Density, or API Gravity of Crude
Petroleum and Liquid Petroleum
Products by Hydrometer Method; Third
Edition, December 2012; Reaffirmed
May 2017 (‘‘API 9.1’’); IBR approved for
§§ 226.108(b); 226.110(b).
(22) API MPMS Chapter 9—Density
Determination, Section 2—Standard
Test Method for Density or Relative
Density of Light Hydrocarbons by
Pressure Hydrometer; Third Edition,
December 2012; Reaffirmed May 2017
(‘‘API 9.2’’); IBR approved for
§§ 226.108(b); 226.110(b).
(23) API MPMS Chapter 9—Density
Determination, Section 3—Standard
Test Method for Density, Relative
Density, and API Gravity of Crude
Petroleum and Liquid Petroleum
Products by Thermohydrometer
Method; Third Edition, December 2012;
Reaffirmed May 2017 (‘‘API 9.3’’); IBR
approved for §§ 226.108(b); 226.110(b).
(24) API MPMS Chapter 10—
Sediment and Water, Section 4—
Determination of Water and/or
Sediment in Crude Oil by the Centrifuge
Method (Field Procedure); Fourth
Edition, October 2013; Errata March
2015 (‘‘API 10.4’’); IBR approved for
§§ 226.108(b); 226.110(b).
(25) API MPMS Chapter 11—Physical
Properties Data, Section 1—
Temperature and Pressure Volume
Correction Factors for Generalized
Crude Oils, Refined Products and
Lubricating Oils; May 2004, Addendum
1 September 2007, Addendum 2 May
2019; Reaffirmed August 2012 (‘‘API
11.1’’); IBR approved for §§ 226.109(g);
226.110(b); 226.111(e); 226.114(a).
(26) API MPMS Chapter 12—
Calculation of Petroleum Quantities,
Section 2—Calculation of Petroleum
Quantities Using Dynamic Measurement
Methods and Volumetric Correction
Factors, Part 2—Measurement Tickets;
Third Edition, June 2003; Reaffirmed
February 2016 (‘‘API 12.2.2’’); IBR
approved for § 226.110(b).
(27) API MPMS Chapter 12—
Calculation of Petroleum Quantities,
Section 2—Calculation of Petroleum
Quantities Using Dynamic Measurement
Methods and Volumetric Correction
Factors, Part 3—Proving Report; First
Edition, October 1998; Reaffirmed May
2014 (‘‘API 12.2.3’’); IBR approved for
§ 226.113(c) and (j).
(28) API MPMS Chapter 12—
Calculation of Petroleum Quantities,
Section 2—Calculation of Petroleum
Quantities Using Dynamic Measurement
Methods and Volumetric Correction
Factors, Part 4—Calculation of Base
Prover Volumes by the Waterdraw

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Relative Density, Compressibility and
Theoretical Hydrocarbon Liquid
Content for Natural Gas Mixtures for
Custody Transfer; Third Edition,
January 2009; Reaffirmed November
2020 (‘‘API 14.5’’); IBR approved for
§§ 226.138(c); 226.140(a).
(35) API MPMS Chapter 18—Custody
Transfer, Section 1—Measurement
Procedures for Crude Oil Gathered from
Small Tanks by Truck; Third Edition,
May 2018 (‘‘API 18.1’’); IBR approved
for § 226.108(b).
(36) API MPMS Chapter 21—Flow
Measurement Using Electronic Metering
Systems, Section 1—Electronic Gas
Measurement; Second Edition, February
2013 (‘‘API 21.1’’); IBR approved for
§§ 226.125(a) and (g); 226.126(a), (c),
and (d); 226.127(c); 226.128(a) through
(d).
(37) API MPMS Chapter 21—Flow
Measurement Using Electronic Metering
Systems, Section 2—Electronic Liquid
Volume Measurement Using Positive
Displacement and Turbine Meters; First
Edition, June 1998; Reaffirmed October
2016 (‘‘API 21.2’’); IBR approved for
§§ 226.110(b); 226.111(e); 226.112(g).
(38) API Recommended Practice (RP)
12R1, Setting, Maintenance, Inspection,
Operation and Repair of Tanks in
Production Service; Fifth Edition,
August 1997; Reaffirmed April 2008;
Addendum 1, December 2017 (‘‘API RP
12R1’’); IBR approved for § 226.107(b).
(39) API RP 2556, Correction Gauge
Tables for Incrustation; Second Edition,
August 1993; Reaffirmed November
2013 (‘‘API RP 2556’’); IBR approved for
§ 226.107(f).
(b) American Gas Association (AGA),
400 North Capitol Street NW, Suite 450,
Washington, DC 20001; phone: 202–
824–7000; website: https://www.aga.org.
(1) AGA Report No. 3, Orifice
Metering of Natural Gas and Other
Related Hydrocarbon Fluids, Second
Edition, September 1985 (‘‘AGA Report
No. 3’’); IBR approved for § 226.124(b).
(2) AGA Transmission Measurement
Committee Report No. 8,
Compressibility Factors of Natural Gas

nd 2
n · 1.000 2
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4

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Definitions.

(a) As used in this part, the term:
Alarm log means a log for recording
any system alarm, user-defined alarm,
or error conditions (such as out-of-range
temperature or pressure) that occur.
This includes a description of each
alarm condition and the times the
condition occurred and cleared.
Appropriate valve means those valves
that provide access to production before
it is measured for sales and that are
subject to the sealing requirements set
forth in this part.
Area ratio means the smallest
unrestricted area at the primary device
divided by the cross-sectional area of
the meter tube. For example, the area
ratio (Ar) of an orifice plate is the area
of the orifice bore (Ad) divided by the
area of the meter tube (AD). For an
orifice plate with a bore diameter (d) of
1.000 inches in a meter tube with an
inside diameter (D) of 2.000 inches, the
area ratio is 0.25 and is calculated as
follows:

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0.25

when compared to a certified test

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nD 2
n · 2.000 2
Av = - - = - - - -

0.7854in2

Ar= -

and Other Related Hydrocarbon Gases;
Second Edition, November 1992 (‘‘AGA
Report No. 8’’); IBR approved for
§§ 226.127(a); 226.138(d).
(c) Gas Processors Association (GPA),
6526 E. 60th Street, Tulsa, OK 74145;
phone 918–493–3872; website: https://
www.gpamidstream.org.
(1) GPA Midstream Standard 2166–
17, Obtaining Natural Gas Samples for
Analysis by Gas Chromatography;
Reaffirmed 2017 (‘‘GPA 2166–17’’); IBR
approved for §§ 226.131(c) and (d);
226.132(a); 226.135(a).
(2) GPA Midstream Standard 2261–
20, Analysis for Natural Gas and Similar
Gaseous Mixtures by Gas
Chromatography; Revised 2020 (‘‘GPA
2261–20’’); IBR approved for
§ 226.136(a) and (c).
(3) GPA Midstream Standard 2198–
16, Selection, Preparation, Validation,
Care and Storage of Natural Gas and
Natural Gas Liquids Reference Standard
Blends; Revised 2016 (‘‘GPA 2198–16’’);
IBR approved for § 226.136(c).

device, prior to making any adjustments
to the transducer.

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EP13JA23.006

Method; First Edition, December 1997;
Reaffirmed September 2014 (‘‘API
12.2.4’’); IBR approved for § 226.113(b).
(29) API MPMS Chapter 13—
Statistical Aspects of Measuring and
Sampling, Section 3—Measurement
Uncertainty; Second Edition, December
2017 (‘‘API 13.3’’); IBR approved for
§ 226.106(a).
(30) API Manual of Petroleum
Measurement Standards (MPMS)
Chapter 14—Natural Gas Fluids
Measurement, Section 1—Collecting
and Handling of Natural Gas Samples
for Custody Transfer; Seventh Edition,
May 2016; Addendum August 2017;
Errata August 2017 (‘‘API 14.1’’); IBR
approved for §§ 226.130(b) and (c);
226.131(c); 226.132(b).
(31) API MPMS Chapter 14—Natural
Gas Fluids Measurement, Section 3—
Orifice Metering of Natural Gas and
Other Related Hydrocarbon Fluids—
Concentric, Square-edged Orifice
Meters, Part 1—General Equations and
Uncertainty Guidelines; Fourth Edition,
September 2012; Errata July 2013;
Reaffirmed September 2017 (‘‘API
14.3.1’’); IBR approved for §§ 226.106(a);
226.120(a).
(32) API MPMS Chapter 14—Natural
Gas Fluids Measurement, Section 3—
Orifice Metering of Natural Gas and
Other Related Hydrocarbon Fluids—
Concentric, Square-edged Orifice
Meters, Part 2—Specification and
Installation Requirements; Fifth Edition,
March 2016; Errata 1, March 2017;
Errata 2, January 2019 (‘‘API 14.3.2’’);
IBR approved for § 226.121(b) through
(f), (h), (i), and (l).
(33) API MPMS Chapter 14—Natural
Gas Fluids Measurement, Section 3—
Orifice Metering of Natural Gas and
Other Related Hydrocarbon Fluids—
Concentric, Square-edged Orifice
Meters, Part 3—Natural Gas
Applications; Fourth Edition, November
2013 (‘‘API 14.3.3’’); IBR approved for
§§ 226.124(b); 226.127(a).
(34) API MPMS, Chapter 14—Natural
Gas Fluids Measurement, Section 5—
Calculation of Gross Heating Value,

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As-left means the reading of a
mechanical or electronic transducer
when compared to a certified test device
after adjusting the transducer, but prior
to returning the transducer to service.
Audit means a review of production
reporting, royalty reporting, or payment
activities of lessees, designees, or other
persons or entities who report
production or pay royalties, rents,
bonuses, or other revenues on leases or
properties where a lease, or portion of
a lease, is committed to a cooperative
agreement.
Automatic ignition system means an
automatic ignitor and, where needed to
ensure continuous combustion, a
continuous pilot flame.
Averaging period means the previous
12 months or life of the meter,
whichever is shorter. For an FMP that
measures production from a newly
drilled well, the averaging period
excludes production from the well that
occurred during or prior to the first full
month of production.
Barrel (bbl) means 42 standard United
States gallons.
Beta (or diameter) ratio means the
reference inside diameter (measured
inside diameter corrected to a reference
temperature of 68 °F) of the orifice bore
divided by the reference inside diameter
of the meter tube. This is also referred
to as a diameter ratio.
Bias means a shift in the mean value
of a set of measurements away from the
true value of what is being measured.
Business day means any day Monday
through Friday, excluding weekends
and Federal holidays.
Bypass means any piping or
equipment used at an FMP to go around
or otherwise avoid a meter or other
measurement device, or any component
thereof, to allow oil or gas to flow
without accountability. Equipment that
allows the changing of the orifice plate
of a gas meter without bleeding the
pressure off the gas meter run (e.g.,
senior fitting) is not a bypass.
Capture means the physical
containment of natural gas for
transportation to market or productive
use of natural gas and includes injection
and royalty-free on-site uses pursuant to
the regulations in this part.
Calendar day means all days in a
month, including weekends and Federal
holidays.
Composite meter factor means a meter
factor corrected from normal operating
pressure to base pressure. The
composite meter factor is determined by
proving operations where the pressure
is considered constant during the
measurement period between provings.
This definition applies to liquid meter
provings only.

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Configuration log means a record that
contains all selected flow parameters
used in the generation of a quantity
transaction record.
Cooperative agreement means a
binding legal agreement between two or
more parties for the development or
operation of a designated area as a
single unit without regard to separate
ownership of the leased lands included
in the agreement. Such cooperative
agreements include, but are not limited
to, unit agreements and
communitization agreements.
Coriolis measurement system (CMS)
means a metering system using a
Coriolis meter in conjunction with a
tertiary device, pressure transducer, and
temperature transducer to derive and
report gross standard oil volume. A
CMS system provides real-time, on-line
measurement of oil.
Deleterious substance means any
chemical, saltwater, oil field brine,
waste oil, waste emulsified oil, basic
sediment, mud, or other injurious
substance produced or used in the
drilling, development, production,
transportation, refining, and processing
of oil and gas.
Director means the Director of ONRR,
the Director’s authorized representative
acting under delegated authority, or
such other person as the Director may
delegate to fulfill responsibilities and
exercise authorities under this part.
Discharge coefficient means an
empirically derived correction factor
that is applied to the theoretical
differential flow equation to calculate a
flow rate that is within stated
uncertainty limits.
Drainage means the migration of
hydrocarbons, inert gases, or associated
resources caused by production from
other wells.
Effectively sealed means sealed in
such a manner that the sealed
component cannot be accessed, moved,
or altered without breaking the seal.
Element range means the difference
between the minimum and maximum
value that the element of a mechanical
recorder (e.g., differential-pressure
bellows, static pressure element,
temperature element) is designed to
measure.
Ephemeral stream or water source
means a stream or water source that
only flows in direct response to
precipitation and whose channel is
always above the water table.
Escape rate means the maximum
volume of gas determined to be
available for escape (Q), calculated as
follows:
(1) For production facilities, the
maximum daily rate of gas produced

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through that facility or the best estimate
thereof;
(2) For oil wells, the producing gas/
oil ratio multiplied by the maximum
daily production rate or the best
estimate thereof; and
(3) For gas wells, the current daily
absolute open flow rate against
atmospheric pressure.
Event log means an electronic record
of all exceptions and changes to the
flow parameters contained within the
configuration log that have an impact on
a quantity transaction record.
Facility measurement point (FMP)
means a point where oil or gas produced
from a lease is measured and such
measurement affects calculation of the
volume or quality of production on
which royalty is owed. Each individual
meter installation (including its
primary, secondary, and tertiary
devices) and tank battery is a separate
FMP.
Free water means the measured
volume of water that is present in a
container and that is not in suspension
in the contained liquid at observed
temperature.
Gas means any fluid, either
combustible or non-combustible,
hydrocarbon or non-hydrocarbon,
which is extracted from a reservoir and
has neither independent shape nor
volume, but tends to expand
indefinitely, and which exists in a
gaseous or rarefied state under standard
temperature and pressure conditions.
Gas-to-oil ratio (GOR) means the ratio
of gas to oil in the production stream
expressed in standard cubic feet of gas
per barrel of oil.
Gas plant products means separate
marketable elements, compounds, or
mixtures, whether in liquid, gaseous, or
solid form, resulting from processing
gas. This does not include residue gas.
Gas well means a well that produces
natural gas that is not associated with
oil at the time of well completion or for
which the energy equivalent of the gas
produced, including its entrained
liquefiable hydrocarbons, exceeds the
energy equivalent of the oil produced by
at least 15,000 standard cubic feet for
each barrel of oil produced at the time
of well completion.
Geophysical exploration means
activity relating to the search for
evidence of oil and gas which requires
physical presence upon surface lands
and may result in damage to the lands
or resources located thereon. This
includes, but is not limited to,
geophysical operations, construction of
roads and trails, cross-country transit of
vehicles, and drilling operations to
place explosive charges, where

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approved. This does not include drilling
for oil and gas.
Gross proceeds means the total
monies and other consideration
accruing to a lessee for the disposition
of the oil, gas, or other marketable
products produced.
Gross standard volume means a
volume of oil corrected to base pressure
and temperature and includes meter
factor, as applicable.
Heating value means the gross heat
energy released by the complete
combustion of one standard cubic foot
of gas at 14.73 psia and 60 °F.
High-volume FMP means any gas FMP
that measures more than 200 Mcf/day,
but less than 1,000 Mcf/day, over the
averaging period. This definition only
applies to gas FMPs; it does not apply
to oil FMPs on an equivalent-gas basis.
Indicated volume means the
uncorrected volume indicated by the
meter in a LACT system or the Coriolis
meter in a CMS. For a positive
displacement meter, the indicated
volume is represented by the nonresettable totalizer on the meter head.
For Coriolis meters, the indicated
volume is the uncorrected (without the
meter factor) mass of liquid divided by
the density.
Innage gauge means the level of a
liquid in a tank, measured from the
datum plate or tank bottom to the
surface of the liquid.
Intermittent stream or water source
means a stream or water source flowing
only at certain times of the year when
it receives water from springs or other
surface sources.
Knowingly or willfully means an act,
or failure to act, that is committed with
actual knowledge, deliberate ignorance,
or reckless disregard of the facts
surrounding the event or violation; it
requires no proof of specific intent to
defraud. The knowing or willful nature
of conduct may be established by plain
indifference or reckless disregard of the
terms and conditions of the lease or
permit or applicable laws, regulations,
orders, or notices. A consistent pattern
of performance, or failure to perform,
may be sufficient to establish the
knowing or willful nature of the
conduct. Conduct that is regarded as
knowing or willful is not accidental, nor
is it mitigated by the belief that the
conduct is reasonable or legal.
Lease means any contract approved
by the United States under the Act of
June 28, 1906, Public Law 59–321, 34
Stat. 539, as amended, that authorizes
exploration for, or the extraction and
removal of, oil and gas from the Osage
Mineral Estate.
Lease automatic custody transfer
(LACT) system means a system of

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components designed for the
unattended custody transfer of oil
produced from a lease or unit to the
transporting carrier. The system must
determine the net standard volume and
quality and provide for safe and tamperproof operations.
Legal description means the
geographical description of a location
utilizing the quarter-section, section,
township, and range.
Lessee means any person holding
record title to, or owning operating
rights in, an oil and/or gas lease issued
under the regulations in this part and
any authorized representative thereof,
including any designee who reports
production or submits royalty payments
on behalf of the lessee.
Liquids unloading means the removal
of an accumulation of liquid
hydrocarbons or water from the
wellbore of a completed gas well.
Lost oil or gas means produced oil or
gas that escapes containment, whether
such loss is intentional or unintentional,
or that is flared before being removed
from the lease or unit and cannot be
recovered.
Low-volume FMP means any gas FMP
that measures more than 35 Mcf/day,
but less than or equal to 200 Mcf/day,
over the averaging period. This
definition only applies to gas FMPs; it
does not apply to oil FMPs on a gasequivalent basis.
Marketable condition means a
condition in which lease products are
sufficiently free from impurities or
otherwise so conditioned that a
purchaser will accept them under a
sales contract typical for the field or
area.
Maximum ultimate economic
recovery means the recovery of oil and
gas that a prudent lessee could be
expected to make from the field or
reservoir given existing knowledge and
other pertinent facts and utilizing
common industry practices for primary,
secondary, or tertiary recovery
operations.
Meter factor means a ratio obtained by
dividing the measured volume of liquid
that passed through a prover or master
meter during the proving by the
measured volume of liquid that passed
through the line meter during the
proving, corrected to base pressure and
temperature.
Mole percent means the number of
molecules of a particular type that are
present in a gas mixture divided by the
total number of molecules in the gas
mixture, expressed as a percentage.
Monthly Index Zone Price means the
index-based value per MMBtu for gas
production from a lease in an index
zone. The Monthly Index Zone Price is

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calculated by averaging the highest
reported prices for all index-pricing
points in the relevant index zone for
each ONRR-approved publication,
summing those averages, dividing by
the number of ONRR-approved
publications, and reducing the number
calculated by 10 percent, but not by less
than 10 cents per MMBtu or more than
30 cents per MMBtu.
Natural gas liquids (NGLs) means gas
plant products consisting of ethane,
propane, butane, or heavier liquid
hydrocarbons.
Net standard volume means the gross
standard volume corrected for quantities
of non-merchantable substances such as
sediment and water.
NYMEX Calendar Month Average
Price means the average of the New
York Mercantile Exchange (NYMEX)
daily settlement prices for light sweet
crude oil delivered at Cushing,
Oklahoma, calculated as follows: (1)
Sum the prices published for each day
during the calendar month of
production, excluding weekends and
Federal holidays, for oil to be delivered
in the nearest month of delivery for
which NYMEX futures prices are
published corresponding to each such
day; and (2) Divide the sum by the
number of days on which those prices
are published, excluding weekends and
Federal holidays.
Oil well means a well for which the
energy equivalent of the oil produced
exceeds the energy equivalent of the gas
produced at the time of completion.
Operating right (working interest)
means a percentage of ownership in a
lease granting the owner the right to
enter upon the leased lands to conduct
exploratory, drilling, or related
operations, including the production of
oil and gas, in accordance with the
terms and conditions of the lease.
Orphan well means an oil, gas,
disposal, injection, or service well that
is no longer in use whether dry,
inoperable, or incapable of production;
that the current lessee did not assume
through assignment; that has not been
drilled, re-entered, operated, or affected
by the current lessee; and for which
there is no legally or financially
responsible party with sufficient
resources to conduct proper plugging,
abandonment, and surface restoration
operations.
Osage Minerals Council means the
independent agency within the Osage
Nation created by Article XV, section 4,
of the Constitution of the Osage Nation
(2006) with administrative authority to
consider and approve leases of the
Osage Mineral Estate and propose other
forms of development thereof, and its
successors in interest.

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Osage Mineral Estate means the
subsurface mineral estate underlying
Osage County, Oklahoma that is held in
trust by the United States for the benefit
of the Osage Nation in accordance with
the Act of June 28, 1906, Public Law 59–
321, section 3, 34 Stat. 539, as amended.
Osage Nation means the federally
recognized Indian Tribe referred to by
Article I of the Constitution of the Osage
Nation (2006) and its predecessors and
successors in interest.
Perennial stream or water source
means a stream or water source that
flows continuously.
Permittee means any person, other
than a lessee, who applies for and
receives a geophysical exploration
permit.
Person means any individual,
corporation, partnership, association,
firm, consortium, joint venture, or other
entity.
Primary term means the initial term of
the lease during which the lease
contract may be kept in force by either
commencement of production in paying
quantities or the payment of annual
rental.
Production in paying quantities
means production of oil or gas from a
lease that is of sufficient value to exceed
direct operating costs and the cost of
annual rental or minimum royalty.
Production phase means that event
during which oil is delivered directly to
or through production equipment to the
storage facilities and includes all
operations at the facility other than
those defined as being within the sales
phase.
Prompt month means the nearest
month of delivery for which NYMEX
futures prices are published during the
trading month.
Quantity transaction record (QTR)
means a report generated by a flow
computer on a LACT, CMS, or other
approved system that summarizes the
daily and/or hourly volume calculated
by the flow computer and the average or
totals of the dynamic data that is used
in the calculation of gross standard
volume.
Record title means a lessee’s interest
in a lease which includes the obligation
to pay rental and the right to assign or
surrender the lease. Overriding royalty
and operating rights are severable from
record title interests.
Regional Director means the Regional
Director for the Eastern Oklahoma
Region, Bureau of Indian Affairs, or the
Regional Director’s authorized
representative acting under delegated
authority.
Residue gas means hydrocarbon gas
consisting principally of methane and
resulting from processing gas.

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Sales phase means that event during
which oil is removed from storage
facilities at an FMP for sale.
Seal means a uniquely numbered
device that completely secures either a
valve or those components of a
measuring system that affect the quality
or quantity of the oil being measured.
Senior fitting means a type of orifice
plate holder that allows the orifice plate
to be removed, inspected, and replaced
without isolating and depressurizing the
meter tube.
Slop oil means oil that is of such
quality that it is not acceptable to
normal purchasers and is usually sold to
oil reclaimers. Oil that can be made
acceptable to normal purchasers
through special treatment economically
provided at existing or modified
facilities or using portable equipment at,
or upstream of, the FMP, is not slop oil.
Source record means any unedited,
original record, document, or data that
is used to determine the volume and
quality of production, regardless of how
it was created or stored or the format it
is in (i.e., paper or electronic). This
includes, but is not limited to, raw and
unprocessed data (e.g., instantaneous
and continuous information used by
flow computers to calculate volumes);
gas charts; run tickets; calibration,
verification, prover and configuration
reports; lessee field logs; volume
statements; event logs; seal records; and
gas analyses.
Statistically significant means a
difference between two data sets that
exceeds the threshold of significance.
The threshold of significance is the
maximum difference between two data
sets (a and b) that can be attributed to
uncertainty effects, and is calculated as
follows:

Where:
Ts = Threshold of significance, in percent
Ua = Uncertainty (95 percent confidence) of
data set a, in percent
Ub = Uncertainty (95 percent confidence)
of data set b, in percent

Superintendent means the
Superintendent of the Osage Agency,
Bureau of Indian Affairs, the
Superintendent’s authorized
representative acting under delegated
authority, or such other person or
official that may be delegated to fulfill
responsibilities and exercise authorities
under this part.
Surface owner means any person who
owns a surface estate within Osage
County, Oklahoma, regardless of
whether the surface estate is held in fee,
restricted fee, or trust status.

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Total observed volume (TOV) means
the total measured volume of all oil,
sludge, S&W, and free water at the
measured or observed temperature and
pressure.
Trading month means the period
extending from the second business day
before the 25th day of the second
calendar month preceding the delivery
month (or, if the 25th day of that month
is a non-business day, the second
business day before the last business
day preceding the 25th day of that
month) through the third business day
before the 25th day of the calendar
month preceding the delivery month (or
if the 25th day of that month is a nonbusiness day, the third business day
before the last business day preceding
the 25th day of that month), unless the
NYMEX publishes a different definition
or different dates on its official website,
http://www.cmegroup.com, in which
case the NYMEX definition will apply.
Upper calibrated limit means the
maximum engineering value for which
a transducer was calibrated by certified
equipment, either in the factory or in
the field.
US well number means a unique,
permanent numeric identifier assigned
to each oil and gas well drilled in the
United States that includes the
completion code.
Very-high-volume FMP means any gas
FMP that measures more than 1,000
Mcf/day over the averaging period. This
definition only applies to gas FMPs; it
does not apply to oil FMPs on an
equivalent-gas basis.
Very-low-volume FMP means any gas
FMP that measures 35 Mcf/day or less
over the averaging period. This
definition only applies to gas FMPs; it
does not apply to oil FMPs on an
equivalent-gas basis.
Waste of oil or gas means any action
or inaction by the lessee that is not
sanctioned by the Superintendent as
necessary for proper development and
production, where compliance costs are
not greater than the monetary value of
the resources they are expected to
conserve, and that results in:
(1) A reduction in the quality or
quantity of oil or gas ultimately
producible from a reservoir under
prudent and proper operations; or
(2) Avoidable surface loss of oil or
gas.
Waste oil means oil that the
Superintendent determined is of such
quality that it cannot be treated
economically and put in a marketable
condition with existing or modified
lease facilities or portable equipment,
cannot be sold to reclaimers, and has no
economic value.

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Federal Register / Vol. 88, No. 9 / Friday, January 13, 2023 / Proposed Rules
(b) As used in this part, the following
acronyms apply:
API means American Petroleum
Institute.
BIA means Bureau of Indian Affairs.
Btu means British thermal unit.
CPL means correction for the effect of
pressure on a liquid.
CTL means correction for the effect of
temperature on a liquid.
FCCP means a Failure to Correct Civil
Penalty Notice.
ft msl means feet above mean sea
level.
GPA means Gas Processors
Association.
GPS means Global Positioning
System.
IBIA means the Interior Board of
Indian Appeals, Office of Hearings and
Appeals.
IBLA means the Interior Board of
Land Appeals, Office of Hearings and
Appeals.
ILCP means an Immediate Liability
Civil Penalty Notice.
IRS means Internal Revenue Service.
Mcf means 1,000 standard cubic feet.
MMBtu means million metric British
thermal units.
MMcf means million cubic feet.
NIST means National Institute of
Standards and Technology.
NONC means a Notice of
Noncompliance.
NTL means Notice to Lessee(s).
ONRR means Office of Natural
Resources Revenue.
psia means pounds per square inch—
absolute.
psig means pounds per square inch—
gauge.
S&W means sediment and water.
SWD means saltwater disposal.

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§ 226.2 Authorities that govern oil and gas
activities within the Osage Mineral Estate.

All oil and gas exploration and
development activities conducted
within the Osage Mineral Estate are
subject to:
(a) The regulations in this part;
(b) Lease and permit terms and
conditions;
(c) Orders, notices, and instructions
the Superintendent issues;
(d) Orders, notices, and instructions
ONRR issues; and
(e) All other applicable laws,
regulations, and authorities.
§ 226.3 Authority and responsibility of the
Superintendent of the Osage Agency.

The Superintendent of the Osage
Agency has the authority and
responsibility to administer leasing and
development of the Osage Mineral
Estate.

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§ 226.4 Authority and responsibility of the
Office of Natural Resources Revenue
(ONRR).

The Office of Natural Resources
Revenue (ONRR) has the authority and
responsibility for administering the
Osage Agency’s royalty management
program including, but not limited to,
royalty and production accounting,
reporting, verification, collection,
enforcement, and appeals.
§ 226.5

Orders and notices.

(a) The Superintendent is authorized
to issue orders and notices when
necessary to implement, supplement,
clarify, and enforce the regulations in
this part. Orders and notices the
Superintendent issues under this
section are binding on the lessee and
any other persons they apply to. The
Superintendent may, in their discretion,
grant an extension of the time to comply
with an order or notice.
(b) ONRR is authorized to issue orders
and notices when necessary to
implement, supplement, clarify, and
enforce the regulations in this part.
Orders that ONRR issues under this
section are binding on the lessee and
any other persons they apply to.
§ 226.6

Service of official correspondence.

(a) The Superintendent and ONRR
will serve all official correspondence by
regular U.S. mail, certified mail—return
receipt requested, private delivery
service (i.e., UPS or FedEx), or hand
delivery.
(b) The Superintendent will serve
official correspondence to the party
identified on the most recently received
Lease Contact of Record form. The
lessee is responsible for notifying the
Superintendent of any change in the
designated point of contact’s name,
address, or phone number by submitting
an updated form within two weeks of
any such change.
(c) ONRR will serve official
correspondence to the party identified
on the most recently received Form
ONRR–4444, Address/Addressee of
Record, for the type of correspondence
at issue. The reporter is responsible for
notifying ONRR of any name or address
changes within two weeks of any such
change.
(d) If the lessee, reporting party, or
payor fails to submit or update contact
information in accordance with the
requirements in this section:
(1) The Superintendent may use the
name and address listed on the lease;
and
(2) ONRR may use the individual or
departmental name, address, or position
title, contained in ONRR’s database
based on previous formal or informal
communications or correspondence.

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(e) The Superintendent and ONRR
may also obtain contact information
from public records and send official
correspondence to:
(1) The registered agent;
(2) A corporate officer; or
(3) The addressee of record reflected
in the files of any state Secretary, any
Federal or state agency that keeps
official records of business entities or
corporations, or other appropriate
public records for individuals, business
entities, and corporations.
(f) The Superintendent and ONRR
consider the date of service for official
correspondence to be:
(1) Seven calendar days for regular
U.S. mail;
(2) The date of receipt for certified
mail—return receipt requested and
private delivery service; and
(3) The date of delivery for hand
delivery.
(g) If, the Superintendent or ONRR
serves official correspondence using
multiple methods and the dates of
receipt differ, the date of the earliest
receipt is the date of service.
(h) If, after a reasonable effort, the
Superintendent or ONRR are unable to
deliver official correspondence to the
contact of record, the correspondence
will be considered constructively served
seven calendar days after the original
mailing date. This includes, but is not
limited to, situations where delivery
does not occur because:
(1) The contact of record moved
without filing a forwarding address,
Lease Contact of Record form, or ONRR
Form-4444;
(2) The forwarding order expired;
(3) Delivery was expressly refused; or
(4) The correspondence was
unclaimed and the U.S. Postal Service,
a private mailing service, or an
individual who attempted to make
delivery using a different method of
service substantiates the delivery
attempt.
§ 226.7

Forms.

Leases, assignments, applications,
bonds, affidavits, reports, and other
instruments must be on forms approved
by the Superintendent or ONRR. Only
the official version and current edition
of such forms will be accepted.
§ 226.8

Acceptable forms of payment.

All sums due under a lease or the
regulations in this part must be paid by
electronic funds transfer (EFT), certified
check, cashier’s check, money order, or
commercial or personal check drawn on
a solvent bank, otherwise specified
herein or notified by the Superintendent
or ONRR in writing. Such sums
constitute a prior lien on all equipment

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and unsold oil located on the lease or
unit.

Subpart B—Acquiring a Lease
Authorized Procedures

§ 226.9 Environmental reviews and
cultural surveys.

Prior to approving leases and permit
applications for operations requiring
new or additional ground-disturbance,
the Superintendent must:
(a) Ensure that environmental review
has been conducted in accordance with
the National Environmental Policy Act
of 1969 (NEPA), 42 U.S.C. 4321, et seq.,
the regulations promulgated by the
Council on Environmental Quality
(CEQ), 40 CFR parts 1500 through 1508,
and the Department’s regulations
implementing NEPA, 43 CFR part 46,
and that an environmental record of
review (e.g., categorical exclusion
checklist, determination of NEPA
adequacy), environmental assessment,
or environmental impact statement has
been prepared, as appropriate.
(b) Ensure that all necessary
archeological or cultural surveys are
performed, and clearances obtained, in
accordance with the National Historic
Preservation Act (NHPA), 54 U.S.C.
300101, et seq., the regulations
promulgated by the Advisory Council
on Historic Preservation, 36 CFR part
800 et seq., and the Archaeological
Resources Protection Act of 1979
(ARPA), 16 U.S.C. 470aa–470mm, as
applicable.
§ 226.10

Information collection.

The collections of information in this
part have been approved by the Office
of Management and Budget under 44
U.S.C. 3501 et seq. and assigned OMB
Control Number 1076–0180 (BIA
collections) and OMB Control Numbers
1012–0004 and 1012–0006 (ONRR
collections). Response is required to
obtain a benefit. A Federal agency may
not conduct or sponsor, and you are not
required to respond to, a collection of
information unless it displays a valid
OMB Control Number.

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§ 226.11

Public availability of information.

The BIA and ONRR will make all
records and information submitted in
accordance with the regulations in this
part available to the public for
inspection, without notification of the
submitter, subject to the following
exceptions:
(a) Trade secrets;
(b) Privileged or confidential
commercial or financial information;
and
(c) Information protected from
disclosure by the Privacy Act (5 U.S.C.
552a).

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§ 226.12 Procedures the Osage Minerals
Council may use to enter into a lease.

The Osage Minerals Council may
utilize the following procedures to enter
into a lease of the Osage Mineral Estate:
(a) Competitive bidding at an
advertised lease sale; or
(b) Negotiation with prospective
lessees. The Osage Minerals Council
may negotiate directly or request that
the Superintendent undertake
negotiation on its behalf. Requests that
the Superintendent negotiate leases
must be submitted in writing together
with a resolution authorizing such
negotiation.
Competitive Leases
§ 226.13

Advertisement of a lease sale.

(a) The Osage Minerals Council may
request that the Superintendent
advertise a competitive lease sale. Such
requests must be submitted to the
Superintendent in writing at least 60
calendar days in advance of the date the
Osage Minerals Council would like the
Notice of Lease Sale published, together
with a resolution authorizing the lease
sale. The resolution must identify the:
(1) Location, date, and time of the
lease sale; and
(2) Minimum acceptable bid.
(b) Upon receipt of the Osage
Minerals Council’s written request
under paragraph (a) of this section, the
Superintendent will publish a Lease
Sale Bulletin advertising the lease sale
and calling for nominations.
§ 226.14

Nominating lands for a lease sale.

(a) You must submit a nomination
letter to the Superintendent to nominate
lands for a lease sale. The nomination
letter must:
(1) Include the name and address of
the person making the nomination;
(2) Identify the legal description of the
lands nominated; and
(3) Be legible and signed in ink.
(b) Nomination letters must be
submitted to the Superintendent by mail
or hand delivery prior to expiration of
the nomination period identified in the
Lease Sale Bulletin. Nomination letters
that do not meet the requirements in
paragraph (a) of this section will be
rejected.
§ 226.15
Sale.

Publication of a Notice of Lease

The Superintendent will publish a
Notice of Lease Sale at least 30 calendar
days prior to the date of the sale. The
Notice of Lease Sale will offer leases for
sale to the highest responsible bidder

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and identify the nominated lands;
primary term of each lease offered;
location, date, and time of the sale; and
method for submitting bids.
§ 226.16

Bidding system.

(a) Leases will be offered for sale by
competitive bonus bidding under the
terms and conditions specified in the
Notice of Lease Sale and in accordance
with applicable laws and regulations.
(b) All bids are subject to the Osage
Minerals Council’s acceptance and the
Superintendent’s approval. The
Superintendent reserves the right to
reject any bid and may require any
bidder to submit evidence of good faith
and ability to comply with the
requirements in the Notice of Lease
Sale.
(c) A winning bid is the highest bid
by a qualified bidder that is equal to, or
exceeds, the minimum acceptable bid.
(d) Each successful bidder must
deposit 25 percent of the bonus bid with
the Superintendent by 4:30 p.m. central
standard time on the day of the lease
sale. Deposits must be paid by EFT,
cashier’s check, or money order.
§ 226.17

Award of leases.

(a) A successful bidder must deposit
the following with the Superintendent
within 20 calendar days of the lease
sale:
(1) The balance of the bonus;
(2) An executed Oil and Gas Mining
Lease form;
(3) An Evidence of Authority to
Execute Papers form; and
(4) A certificate of good standing
issued by the Oklahoma Secretary of
State.
(b) The Superintendent may extend
the time for submitting the executed
lease, evidence of authority to execute
papers, and certificate of good standing.
No extension of time may be granted for
depositing the balance of the bonus.
(c) The bonus, or any portion thereof,
deposited with the Superintendent will
be forfeited for the use and benefit of the
Osage Nation if:
(1) A successful bidder fails to pay the
bonus in full by the required deadline;
(2) A successful bidder fails to file the
items in paragraphs (a)(2) through (4) of
this section by the required deadline; or
(3) The Superintendent denies
approval of the lease pursuant to
paragraph (d) of this section, through no
fault of the Osage Minerals Council or
BIA.
(d) Competitive leases are subject to
the Superintendent’s approval. The
Superintendent may deny the approval
of a lease executed by a successful
bidder upon satisfactory evidence of
collusion, fraud, or other irregularity.

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Non-Competitive Leases
§ 226.18

Submitting an offer to lease.

(a) You may submit non-competitive
offers to lease the Osage Mineral Estate
to the Osage Minerals Council. Such
offers must include the:
(1) Name and address of the offeror;
(2) Legal description of the lands
covered by the proposed lease;
(3) Bonus amount; and
(4) Such other information as may be
required by the Osage Minerals Council.
(b) Upon receipt of a non-competitive
offer to lease, the Osage Minerals
Council may accept the offer, reject the
offer, or enter negotiations with the
offeror directly or through the
Superintendent.
§ 226.19

Acceptance of an offer to lease.

(a) A successful offeror must deposit
the following with the Superintendent
within 20 calendar days of the Osage
Minerals Council’s acceptance of a noncompetitive offer to lease:
(1) The full bonus;
(2) An executed Oil and Gas Mining
Lease form;
(3) An Evidence of Authority to
Execute Papers form; and
(4) A certificate of good standing
issued by the Oklahoma Secretary of
State.
(b) Non-competitive leases are subject
to the Superintendent’s approval.
Lease Terms
§ 226.20

Types of leases.

All leases of the Osage Mineral Estate
issued after [effective date of final rule]
will be combination oil and gas leases.
Oil-only and gas-only leases issued
prior to [effective date of final rule] will
remain in full force and effect until such
time as they terminate or are cancelled
but cannot be assigned unless the
assignee executes a new combination oil
and gas lease covering the subject lands.

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§ 226.21

Primary term of leases.

(a) Leases will be for a primary term
established by the Osage Minerals
Council, subject to the Superintendent’s
approval, and will continue so long
thereafter as oil and/or gas is produced
in paying quantities.
(b) The Superintendent may approve
an amendment extending the primary
term of a lease for up to two years if
actual drilling operations commenced
prior to expiration of the primary term,
operations are being diligently pursued
at the end of the primary term, and the
parties jointly submit a Lease
Amendment form evidencing their
agreement. This includes any lease that
is part of an approved cooperative
agreement where actual drilling

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operations took place within the unit or
area covered by the agreement. The
following requirements must be met to
qualify for an extension of the primary
term:
(1) Actual drilling operations must
have been conducted in a manner
consistent with serious oil and gas
exploration in that area based on
existing knowledge of the geology or
other pertinent facts and information.
(2) In drilling a new well on a lease,
or for the benefit of a lease pursuant to
the terms of an approved cooperative
agreement, the lessee must take the well
to a depth sufficient to penetrate at least
one formation recognized as having
potential to produce oil or gas.
(3) In the reentry of an existing well,
the lessee must take the well to a depth
sufficient to penetrate at least one new
and deeper formation recognized as
having the potential to produce oil or
gas.
§ 226.22 Effect of changes in current
regulations on existing leases.

Leases issued pursuant to this part are
subject to the current regulations, all of
which are made a part of such leases.
No amendment or change in the
regulations after the approval of any
lease will operate to affect the primary
term, acreage, royalty rate, or rental set
forth therein unless the parties jointly
submit a Lease Amendment form
evidencing their agreement to the
amended terms and the Superintendent
approves the amendment.
§ 226.23 U.S. Government employees may
not acquire leases.

U.S. Government employees are
prohibited from acquiring leases of the
Osage Mineral Estate or any interests
therein.
Subpart C—Cooperative Agreements
and Unitization

Superintendent’s approval. Upon
approval of termination, the leases
covered by the cooperative agreement
will be restored to their original terms.
§ 226.25

Cooperative agreements.

(a) The Osage Minerals Council and
lessees may unitize or merge two or
more leases into a cooperative
agreement to promote the development
of any pool, field, or similar area, or any
part thereof, subject to the
Superintendent’s approval.
(b) The Osage Minerals Council and
lessees must submit requests for
approval of cooperative agreements to
the Superintendent at least 90 calendar
days prior to the earliest expiration date
of any of the leases proposed to be
covered by the agreement.
(c) Any agreement by the parties in
interest to supplement, modify, amend,
or terminate a cooperative agreement as
to all the lands covered, or any portion
thereof, is subject to the

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Unit development plans.

The Superintendent may, with the
consent of the Osage Minerals Council,
require all leases issued under this part
to join a unit development plan for the
purpose of preventing waste and
promoting development of the Osage
Mineral Estate. Any such plan must
adequately protect the rights of all
parties in interest.
Subpart D—Transferring a Lease by
Assignment
§ 226.26 Assignment of record title
interest in a lease.

(a) A lease, or any divided or
undivided interest in a lease, may be
transferred by assignment subject to the
Superintendent’s approval. If an
assignment will only cover a portion of
a lease, the transfer requires both the
Osage Minerals Council’s consent and
the Superintendent’s approval. The
assignment of a separate zone or
deposit, or part of a legal subdivision, is
prohibited.
(b) If a lease is divided by the
assignment of an entire interest in any
part, the assigned and retained portions
of the lease are segregated and become
separate and distinct leases.
(c) The assignor must submit the
Assignment of Record Title Interest
form to the Superintendent for approval
within 30 calendar days of the date the
last party executes the instrument.
§ 226.27

Qualifications of the assignee.

The assignee must be qualified to
hold the lease, or interest therein, under
the regulations in this part and must
furnish a satisfactory bond.
§ 226.28

§ 226.24

2461

Effective date of transfer.

The effective date of the transfer is
12:01 a.m. central standard time on the
first calendar day following the day the
Superintendent approves the
assignment.
§ 226.29 Effect of assignment on the
assignor’s liability under the lease.

(a) The assignor remains liable for the
performance of all lease obligations,
monetary and non-monetary, that accrue
in connection with the lease prior to the
effective date of the assignment
specified in § 226.28.
(b) After the assignment is approved,
the Superintendent and ONRR may
require the assignor to bring the lease
into compliance if the assignee fails to
satisfy an obligation that accrued prior
to the effective date of the assignment.

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This does not include the obligation to
plug and abandon wells the assignee
assumed liability for pursuant to the
assignment.
§ 226.30 Effect of assignment on the
assignee’s liability under the lease.

(a) The assignee must comply with
the terms and conditions of the lease,
any approved permits for wells located
thereon, and the regulations in this part
as they apply to the rights and
obligations acquired.
(b) The assignee is liable for all
obligations that accrue after the effective
date of the assignment specified in
§ 226.28 including, but not limited to,
properly plugging and abandoning all
wells that the assignee drills, operates,
or controls following the effective date
of the transfer and remediating
environmental problems or other lease
violations, regardless of whether such
problems were identified at the time of
the assignment. For purposes of this
section, an assignee is considered to
‘‘control’’ all unplugged wells located
on the lease that are recorded in the
Osage Agency’s plat book or that a
purchaser exercising reasonable
diligence could or should have known
of at the time of the assignment, except
for orphan wells that neither the
assignor nor assignee occasioned.

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§ 226.31

Overriding royalty agreements.

(a) Agreements creating overriding
royalties or payments out of production
are not considered an interest in a lease
as that term is used in § 226.26.
(b) Agreements creating overriding
royalties or payments out of production
are hereby authorized and do not
require the Superintendent’s approval,
subject to the condition that nothing in
any such agreement will be construed as
modifying the lessee’s obligations under
the terms and conditions of the lease or
the regulations in this part. All such
obligations remain in full force and
effect, the same as if free of any
overriding royalties or payments out of
production.
(c) The Superintendent will not
consider the existence of agreements
creating overriding royalties or
payments out of production as
justification for approving the
abandonment of any well, regardless of
whether they are actually paid.
(d) The Superintendent will suspend
an agreement creating overriding
royalties or payments out of production
if it is determined that the working
interest income of an active producing
well is less than or equal to the
operational cost of the well.

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§ 226.32

Drilling contracts.

The lessee is authorized to enter into
drilling contracts with a stipulation that
nothing in such contracts may bind the
Department or otherwise require the
Superintendent’s approval of
subsequent assignments that may be
contemplated by the contract.
Subpart E—Ending a Lease
§ 226.33
a lease.

Surrender of all or any portion of

(a) A lessee may surrender all or any
portion of a lease at any time by
submitting a written request for
surrender to the Superintendent. All
parties holding record title interests in
the lease must sign the request for
surrender.
(b) The Superintendent may approve
the surrender, or partial surrender, of a
lease subject to the following
conditions:
(1) All royalties, including minimum
and compensatory royalties, rental,
interest, late charges, assessments, civil
penalties, and other amounts that may
be due under the regulations in this part
have been paid in full; and
(2) All wells located on the leased
lands being surrendered that are no
longer capable of producing in paying
quantities have been properly plugged
and abandoned and the well sites
restored.
(c) The Superintendent must obtain
the Osage Minerals Council’s consent to
approve the partial surrender of a lease
if the acreage to be retained is less than
160 acres.
(d) The lessee and surety are not
relieved of any obligations or liabilities
under the lease or the regulations in this
part until the Superintendent approves
the request for surrender.
(e) If a lease has been recorded, the
lessee must execute a release and record
it in the proper office upon the
Superintendent’s approval of the
request for surrender.
(f) Surrender or partial surrender of a
lease does not entitle the lessee to a
refund of advance rental or other sums
paid under the lease or the regulations
in this part.
§ 226.34 Termination of a lease by
operation of law.

(a) If a lessee fails to timely pay
advance annual rental in accordance
with § 226.35, the lease terminates by
operation of law as of the date rental
was due.
(b) If a lessee fails to drill a well
capable of producing oil or gas in
paying quantities during the primary
term in accordance with § 226.21, the
lease terminates by operation of law as
of the date the primary term expires.

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(c) Any lease in the extended term
upon which there are no wells capable
of producing oil or gas in paying
quantities terminates by operation of
law as of the date production ceases
unless the Superintendent approved a
request to temporarily abandon the
wells on the lease under § 226.72.
(d) When a lease terminates,
permanent improvements remain part of
the land and become the property of the
surface owner unless the lessee and
surface owner agree otherwise. The
lessee must file a copy of any such
agreement with the Superintendent
within 15 calendar days of its execution.
(e) The lessee must remove all trash,
debris, and personal property from the
lease within 90 calendar days of
termination. For purposes of this
section, personal property includes, but
is not limited to, tools, tanks, pumping
and drilling equipment, derricks,
engines, machinery, tubing, and casings.
Upon expiration of the 90-day removal
period, the ownership of all casings
reverts to the Osage Nation and the
ownership of all other personal property
transfers to the surface owner.
(f) Nothing in this section relieves the
lessee of the responsibility for removing
permanent improvements and personal
property from the leased lands if the
Superintendent orders such removal.
Subpart F—Rental and Royalty
Rental Obligations
§ 226.35

Annual rental requirements.

(a) The annual rental for leases
approved after [effective date of final
rule] is $8 per acre or fraction thereof.
(b) The lessee must pay advance
annual rental for each year of the
primary term within 15 calendar days of
the Superintendent’s approval of the
lease. If the lease is amended to extend
the primary term, the lessee must pay
advance annual rental for each
additional year of the primary term
within 15 calendar days of the
Superintendent’s approval of the
extension.
(c) Rental must be paid for a full year
and may not be prorated, refunded, or
credited against production royalty.
(d) Rental payments must be mailed
to the Superintendent addressed to:
Osage Agency—BIA, Dept. C155, P.O.
Box 105533, Atlanta, GA 30348–5533.
Royalty Obligations
§ 226.36

Royalty rate for oil.

The lessee must pay to the
Superintendent as royalty no less than
162⁄3 percent of the value of all oil
produced and removed or sold from the
lease. The Osage Minerals Council may,

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Federal Register / Vol. 88, No. 9 / Friday, January 13, 2023 / Proposed Rules
upon presentation of justifiable
economic evidence by a lessee, agree to
a lower royalty rate, of no less than 121⁄2
percent of the value of all oil produced
and removed or sold from the lease,
subject to the Superintendent’s
approval. The Superintendent may only
approve a lower royalty rate if it is
determined to be in the best interest of
the Osage Nation.

(a) Unless the Osage Minerals Council
elects to take royalty in kind under
§ 226.42, the value of oil for royalty
purposes is the greater of the:
(1) NYMEX Calendar Month Average
Price of oil at Cushing, Oklahoma, for
the month in which the produced oil
was removed or sold from the lease,
adjusted for gravity using the scale set
forth in § 226.38; or

(2) Actual selling price for the
transaction, adjusted for gravity using
the scale set forth in § 226.38.
(b) The applicable NYMEX Calendar
Month Average Price will be published
on ONRR’s website at https://
www.onrr.gov.
§ 226.38

Gravity adjustment for oil.

(a) The gravity adjustment of the
NYMEX Calendar Month Average Price
of oil at Cushing, Oklahoma under
§ 226.37(a) is a deduction from the price
per barrel, as follows:

If the gravity of the oil is . . .

the rate is . . .

for each . . .

(1)
(2)
(3)
(4)

zero
$0.02 ................................................................
$0.10 plus an additional $0.015 .......................
$0.015 ..............................................................

degree or fraction thereof below 40.0.
one-tenth of one degree below 35.0.
for each one-tenth of one degree above 44.9.

At or between 40.0 and 44.9 degrees .........
At or between 35.0 and 39.9 degrees .........
Below 35.0 degrees .....................................
Above 44.9 degrees .....................................

(b) The Superintendent may, on or
before the fifth calendar day of the
month following production, publish a
gravity adjustment scale for oil of
gravity below 40.0 degrees or above 44.9
degrees that supersedes this section if
they determine that such adjustments
are warranted based on market
conditions.
§ 226.39

Royalty rate for gas.

The lessee must pay to the
Superintendent as royalty no less than
162⁄3 percent of the value of all gas,
including residue gas and gas plant
products, produced and removed or
sold from the lease. The Osage Minerals
Council may, upon presentation of
justifiable economic evidence by a
lessee, agree to a lower royalty rate, of
no less than 121⁄2 percent of the value
of all gas, including residue gas and gas
plant products, produced and removed
or sold from the lease, subject to the
Superintendent’s approval. The
Superintendent will only approve a
lower royalty rate if it is determined to
be in the best interest of the Osage
Nation.
§ 226.40 Calculating the value of gas for
royalty purposes.

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§ 226.37 Calculating the value of oil for
royalty purposes.

2463

Unless the Osage Minerals Council
elects to take royalty-in-kind under
§ 226.42, the value of production for
royalty purposes is calculated by
multiplying the measured volume of gas
at the well (Mcf), times the heating
value of the gas (MMBtu/Mcf), times the
Monthly Index Zone Price of the gas ($/
MMBtu) for Oklahoma Zone 1
published by ONRR on its website,
https://www.onrr.gov. The heating value
of the gas must be calculated and
reported in accordance with
§§ 226.140(a) and (b) and 226.141,

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respectively. If the Monthly Index Zone
Price ceases to be published or is
otherwise unavailable, the
Superintendent must establish a
comparable method for calculating the
value of production. No deductions or
allowances, whether monetary,
volumetric, or otherwise, are allowed.
§ 226.41

Minimum royalty.

(a) If the royalty paid for a producing
lease during any year is less than the
amount of the annual rental for the
lease, the lessee must pay minimum
royalty.
(b) Minimum royalty in an amount
equal to the annual rental specified for
the lease less the amount of the royalty
paid on production is due on or before
the lease anniversary date.
(c) Failure to timely pay minimum
royalty will result in the assessment of
interest on all unpaid or underpaid
minimum royalty amounts. Interest will
be charged at the IRS underpayment rate
pursuant to 26 U.S.C. 6621(a)(2), or such
other rate as the Superintendent or
ONRR may prescribe. The IRS
underpayment rate is posted quarterly
and is available online at https://
www.irs.gov. Interest will be charged
only for the number of days the
payment is late.
(d) Minimum royalty payments must
be paid to ONRR in accordance with the
requirements set forth in § 226.43.
§ 226.42

Royalty-in-kind.

(a) The Osage Minerals Council may
take oil and gas royalty-in-kind on a
lease-by-lease basis or for all leases in
Osage County.
(b) The Osage Minerals Council must
provide the Superintendent and affected
lessees with at least 30 calendar days’
written notice of its decision to take
royalty-in-kind and at least 60 calendar

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days’ written notice of its decision to
terminate royalty-in-kind. The Osage
Minerals Council must submit
resolutions to the Superintendent for its
decisions to take and terminate royaltyin-kind.
(c) The Osage Minerals Council must
take 100 percent of the daily royalty oil
and royalty gas produced from all leases
placed in royalty-in-kind status. Royalty
oil and royalty gas must be taken inkind at the wellhead. For purposes of
this section, royalty oil and royalty gas
mean the daily lease production
multiplied by the royalty rate.
(d) Lessees must furnish free storage
for royalty oil and royalty gas for 30
calendar days from the date of
production. The Osage Minerals Council
must negotiate agreements for the
storage of royalty oil and royalty gas
directly with lessees. The
Superintendent will not negotiate,
review, or approve royalty-in-kind
storage agreements.
(e) All rights, duties, and obligations
that exist under the terms and
conditions of the lease and the
regulations in this part remain in effect
when royalty is taken in kind, including
the lessee’s obligation to pay advance
annual rental and minimum royalty.
§ 226.43

Royalty payments.

(a) Royalty payments must be
remitted to ONRR. The lessee or
purchaser may remit royalty payments
in accordance with § 226.44.
(b) Royalty payments are due on or
before the last calendar day of the
month following the month during
which the oil or gas is produced and
removed or sold and shall cover all
volumes removed or sold for the
preceding month. If the last calendar
day of the month falls on a weekend or

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Federal holiday, payments are due on
the first business day of the next month.
(c) All royalty payments must be
remitted using one of the forms of
payment identified in § 226.8 unless
ONRR specifies otherwise. Payment by
EFT is preferred.
(d) Non-EFT royalty payments must
be made payable to ‘‘DOI–ONRR for BIA
Osage Nation.’’ Payments mailed via
U.S. Postal Service must be addressed
to: Office of Natural Resources Revenue,
P.O. Box 25627, Denver, CO 80225–
0627. Payments sent via courier or
overnight delivery service must be
addressed to: Office of Natural
Resources Revenue, Denver Federal
Center, Building 85, Entrance N–1,
Room 332, 6th Avenue and Kipling
Street, Denver, CO 80225.
(e) ONRR must receive royalty
payments submitted by EFT in its
account on or before the due date.
ONRR must receive royalty payments
submitted via U.S. Postal Service,
courier, or overnight delivery service at
the applicable address set forth in
paragraph (d) of this section before 4
p.m. mountain time on the due date.
(f) Failure to timely and properly
make royalty payments will result in the
assessment of interest on all unpaid or
underpaid royalty amounts. Interest will
be charged at the IRS underpayment rate
pursuant to 26 U.S.C. 6621(a)(2), or such
other rate as the Superintendent or
ONRR may prescribe. The IRS
underpayment rate is posted quarterly
and is available online at https://
www.irs.gov. Interest will be charged
only for the number of days the
payment is late.
(g) A payor may recoup an
overpayment through a recoupment on
Form ONRR–2014 against the current
month’s royalties or other revenues
owed on the same lease. For any month,
a payor may not recoup more than 100
percent of the royalties or other
revenues owed in that month.
Overpayments subject to recoupment
include all payments made in excess of
the required payment for royalty, rental,
bonus, or other amounts owed as
specified by the terms and conditions of
the lease, the regulations in this part,
orders and notices the Superintendent
or ONRR issue, and other applicable
law. ONRR may order any payor not to
recoup any amount for such reasonable
period as may be necessary for ONRR to
review the claimed overpayment.
§ 226.44 Royalty payment contracts and
division orders.

(a) The lessee may enter into contracts
or division orders with purchasers of oil
and gas, or derivatives therefrom, that
designate the purchaser as the party

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responsible for remitting royalty
payments. The lessee must provide the
Superintendent with a copy of the
contract or division order evidencing
such designation.
(b) A contract or division order does
not relieve the lessee from responsibility
for the payment of royalty or from
responsibility for ensuring the accurate
measurement and reporting of all oil
and gas removed or sold from the lease.
If the purchaser fails to pay or
underpays royalty, the lessee is
responsible for payment in full of all
amounts due and owing, including any
interest that may be assessed.
§ 226.45

Royalty reports.

(a) The lessee must submit a certified
monthly royalty report to ONRR using
Form ONRR–2014, Report of Sales and
Royalty Remittance.
(b) ONRR must receive reports by 4
p.m. mountain time on or before the last
calendar day of the month that follows
the month during which the oil and gas
is produced and removed or sold. If the
last calendar day of the month falls on
a weekend or Federal holiday, the report
is due on the first business day of the
next month.
(c) The lessee must submit Form
ONRR–2014 electronically via ONRR’s
eCommerce Reporting website, https://
onrrreporting.onrr.gov, unless they
qualify for an exception under
paragraph (d) of this section. The lessee
must enter royalty data into the system
manually or upload data files using the
American Standard Code for
Information Interchange (ASCII) or
Comma Separated Values (CSV) file
layout formats specified by ONRR.
Detailed information regarding how to
complete and submit Form ONRR–2014
is available at https://www.onrr.gov/
ReportPay/royalty-reporting.htm.
(d) The lessee may submit Form
ONRR–2014 manually if they:
(1) Have never reported to ONRR
before, in which case they have three
months from the date the first royalty
report is due to begin reporting
electronically;
(2) Are only reporting minimum
royalty; or
(3) Are a small business, as defined by
the Small Business Administration, and
do not own a computer.
(e) Royalty reports submitted
manually via U.S. Postal Service must
be addressed to: Office of Natural
Resources Revenue, P.O. Box 25627,
Denver, CO, 80225–0627. Royalty
reports submitted manually via courier
or overnight delivery service must be
addressed to: Office of Natural
Resources Revenue, Denver Federal
Center, Building 85, Entrance N–1,

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Room 332, 6th Avenue and Kipling
Street, Denver, CO 80225. If a lessee
who is submitting royalty reports
manually has three or more late
submissions, ONRR may issue an order
requiring the lessee to submit all future
royalty reports electronically.
§ 226.46 Requirements for royalty, rental,
and payment records.

(a) The lessee must make, retain, and
preserve accurate and complete records
demonstrating that rental, royalty, and
other payments relating to oil and gas
leases comply with the terms and
conditions of the lease, the regulations
in this part, and applicable orders or
notices. Such records include, but are
not limited to, royalty and production
reports; computer programs, automated
files, and supporting systems
documentation used to produce reports
submitted to the Superintendent and
ONRR; and relevant statements,
receipts, run tickets, QTRs, contracts
and agreements.
(b) The lessee must maintain and
preserve records under this section for
a minimum of six years from the date
upon which the relevant transaction
was recorded unless the Superintendent
or ONRR provides written notice to the
lessee that an audit or investigation is
being conducted and the records must
be maintained for a longer period. If an
audit or investigation of the records is
being conducted, the lessee must
maintain the records until the
Superintendent or ONRR issues a
written release of such obligation.
(c) The lessee must make records
available to the Superintendent and
ONRR for inspection upon request. The
lessee will be given a reasonable period
of time to produce historical records.
§ 226.47 Right of the U.S. Government to
purchase oil.

Any of the executive departments of
the U.S. Government have the option to
purchase all or any part of the oil
produced from any lease under this part
at no less than the price set forth in
§ 226.37.
Audits
§ 226.48

Audits and reviews.

ONRR may initiate and conduct
audits and reviews relating to the scope,
nature, and extent of lessees’ and
purchasers’ compliance with rental,
royalty, and other payment and
reporting requirements under the terms
and conditions of the lease, the
regulations in this part, and applicable
orders or notices.

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Subpart G—Bonds
Lease Bonds
§ 226.49

Grandfathering of existing bonds.

(a) Existing $5,000 lease bonds filed
with leases and assignments approved
prior to [effective date of final rule] are
exempt from §§ 226.51(b) and
226.53(a)(3).
(b) Existing $50,000 collective bonds
filed with leases and assignments
approved prior to [effective date of final
rule] are exempt from §§ 226.52(a) and
226.53(a)(3).
(c) Existing lease and collective bonds
will cover all unplugged wells located
on the subject lease(s) that the lessee of
record drilled and completed, operated,
or controlled prior to [effective date of
final rule] according to the Osage
Agency’s records. For purposes of this
section, a lessee is considered to
‘‘control’’ all unplugged wells located
on the lease that are recorded in the
Osage Agency’s plat book or that a
purchaser exercising reasonable
diligence could or should have known
of at the time the lease or assignment
was executed, except for orphan wells.
(d) Lessees with existing lease and
collective bonds must file performance
bonds that comply with the
requirements set forth in this subpart for
all wells they propose to drill, reenter,
recomplete, and accept via assignment
after [effective date of final rule].
(e) Existing lease and collective bonds
will be considered an acceptable form of
financial security for the lessee of record
on [effective date of final rule] only. The
right to maintain existing lease and
collective bonds cannot be conveyed to
any other person through assignment, a
transfer of operating rights or working
interests, or otherwise. All future
lessees, including assignees, of leases
with grandfathered lease or collective
bonds must file performance bonds that
comply with the requirements set forth
in this subpart.

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§ 226.50

Bond obligations.

(a) The lessee must file a performance
bond conditioned upon compliance
with the terms and conditions of the
lease and the regulations in this part
prior to drilling, reentering, and
recompleting wells or accepting
responsibility for wells through
assignment. The lessee must also file a
performance bond for all saltwater
disposal (SWD) easements.
(b) Performance bonds must be in one
of the following forms:
(1) Surety bond issued by a qualified
surety company approved by the
Department of the Treasury (see
Department of the Treasury Circular No.
570);

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(2) Certificate of deposit issued by a
financial institution, the deposits of
which are federally insured, explicitly
granting the Superintendent the full
authority to demand immediate
payment in the event of default;
(3) Cashier’s check;
(4) Certified check;
(5) Negotiable Treasury securities of
the United States of a value equal to the
amount specified in the bond and
including a proper conveyance to the
Superintendent of the full authority to
sell such securities in the event of
default; or
(6) Irrevocable letter of credit issued
by a financial institution, the deposits of
which are federally insured, for a
specific term, identifying the
Superintendent as the sole payee with
full authority to demand immediate
payment in the event of default and
subject to the following requirements:
(i) The letter of credit must be issued
by a financial institution organized or
authorized to do business in the United
States;
(ii) The letter of credit must be
irrevocable during its term. A letter of
credit used as security for any well(s)
that have been drilled, but for which
final approval of abandonment has not
been given, shall be forfeited and
collected by the Superintendent if not
replaced by a suitable bond or letter of
credit at least 30 calendar days before its
expiration date;
(iii) The letter of credit must be
payable to the Superintendent upon
demand, in full or in part, upon receipt
of a notice of attachment from the
Superintendent stating the basis
therefore (e.g., default or failure to file
a replacement in accordance with
paragraph (c)(5)(ii) of this section);
(iv) The initial expiration date of the
letter of credit must be at least one year
following the date it is filed with the
Superintendent; and
(v) The letter of credit must contain a
provision for automatic renewal for
periods of not less than one year in the
absence of notice to the Superintendent
at least 90 calendar days prior to the
original or extended expiration date.
§ 226.51 Individual well bond
requirements.

(a) After [effective date of final rule],
individual performance bonds must be
filed for:
(1) Each well the lessee proposes to
drill, reenter, recomplete, or accept
responsibility for through assignment;
and
(2) Each SWD well under an approved
SWD easement.
(b) Individual well bonds must be in
the amount of not less than $6 per foot

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of the measured well depth for each
existing well or the projected well depth
for each proposed well.
(c) Individual well bonds must be
filed with the permit application,
executed assignment, or executed SWD
easement.
§ 226.52 Countywide and nationwide bond
requirements.

(a) In lieu of an individual well bond,
the lessee may file a countywide bond
in the amount of not less than $75,000
covering all leases of, and SWD
easements within, the Osage Mineral
Estate to which the lessee is, or may
become, a party. The total lease acreage
covered by a single countywide bond
cannot exceed 10,240 acres.
(b) In lieu of individual well or
countywide bonds, the lessee may file a
$150,000 nationwide bond covering all
leases to which the lessee is, or may
become, a party in the United States and
all SWD easements to which the lessee
is, or may become, as party within the
Osage Mineral Estate.
(c) Countywide and nationwide bonds
must be filed with the executed lease,
assignment, or SWD easement.
§ 226.53 Authorization to increase the
required bond amount.

(a) The Superintendent may require
an increase in the amount of any bond,
including grandfathered bonds, if the:
(1) The lessee defaults on an
obligation incurred under the lease,
approved permits, the regulations in
this part, or applicable orders and
notices;
(2) The lessee is deemed high risk due
to a history of lease violations in Osage
County; enforcement action by other
Federal or state agencies; unpaid
royalties, civil penalties, or other
amounts due and owing; or other
factors; or
(3) The total estimated cost of
plugging existing wells exceeds the
present bond amount.
(b) The Superintendent may increase
the bond amount to any level, but in no
circumstances will the bond amount
exceed the sum of the amounts owed for
prior violations that remain outstanding,
the amount of uncollected royalties or
other amounts due, and the total
estimated costs of plugging.
§ 226.54

Bond forfeiture.

(a) The Superintendent may call for
forfeiture of all or part of a performance
bond if the lessee defaults on, refuses to
comply with, or otherwise fails to
satisfy an obligation incurred under a
lease, approved permit, the regulations
in this part, or applicable notices and
orders.

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(b) Where the surety makes payment
to the Superintendent due to default,
the face amount of the bond and the
surety’s liability thereunder will be
reduced by the amount of such
payment.
(c) If the value of the bond is reduced
due to default, and the obligation in
default is less than or equal to the face
amount of the bond, the lessee must
either restore the existing bond or post
a new bond. If the obligation in default
exceeds the face amount of the bond,
the lessee must make full payment to
the BIA for all costs incurred that are in
excess of the face amount of the bond
and must post a new bond. If the lessee
fails to make full payment for all such
obligations, the United States or Osage
Minerals Council may take action to
recover from the lessee all costs in
excess of the amount collected under
the bond. The United States has sole
discretion regarding whether to take
action to recover costs and nothing in
this section will be construed as
imposing an obligation on the United
States to take such action.
(d) The lessee must restore the
existing bond or post a new bond under
paragraph (c) of this section within six
months of receiving the notice of
default, or such shorter period as the
Superintendent may specify.
(e) Failure to restore or replace a
deficient bond may subject the lease(s)
of, and SWD easements within, the
Osage Mineral Estate covered by the
bond to cancellation under § 226.165.
§ 226.55 Termination of the period of
liability and release of bonds.

(a) The Superintendent will not
terminate the period of liability or
release a bond unless an acceptable
replacement bond has been filed or all
obligations incurred under the lease,
approved permits, regulations in this
part, and applicable notices and orders
have been satisfied.
(b) Termination of the period of
liability ends the period during which
obligations accrue but does not relieve
the surety of responsibility for
obligations that accrued during the
period of liability. Release of the bond
relieves the surety of all liability.
Geophysical Exploration Bonds

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§ 226.56 Geophysical exploration bond
requirements.

(a) Lessees and permittees must file a
bond conditioned on compliance with
the terms and conditions of the
geophysical exploration permit and the
regulations in this part prior to
commencing exploration operations.
The bond must be in one of the forms
identified in § 226.50(b).

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(b) A lessee holding a valid lease of
the Osage Mineral Estate under this part
for which the required performance
bond has been posted, may conduct
geophysical exploration operations on
the covered lease without further
bonding.
(c) A lessee holding a valid lease of
the Osage Mineral Estate for which an
individual well bond has been posted
who wishes to explore unleased lands,
must post a geophysical exploration
bond in accordance with paragraph (d)
of this section. A lessee holding a valid
lease of the Osage Mineral Estate for
which a countywide or nationwide
bond has been posted who wishes to
explore unleased lands, may obtain a
bond rider to include geophysical
exploration operations.
(d) Individual exploration bonds in
the amount of $5,000 must be filed with
each geophysical exploration permit. In
lieu of individual exploration bonds,
lessees and permittees may file a
countywide bond in the amount of
$25,000 covering all exploration
operations within Osage County or a
nationwide bond in the amount of
$50,000 covering all exploration
operations within the United States.
§ 226.57

Bond forfeiture.

The Superintendent may call for
forfeiture of all or part of the bond
posted for geophysical exploration
operations if the lessee or permittee
defaults on, refuses to comply with, or
otherwise fails to satisfy an obligation
incurred under the geophysical
exploration permit, the regulations in
this part, or applicable notices and
orders.

notices the Superintendent issues, and
all other applicable laws and regulations
in the conduct of all operations.
(b) Lessees and permittees must
conduct all exploration, testing,
development, production, and other
operations in a safe and workmanlike
manner that:
(1) Protects the leased or permitted
lands and improvements thereon;
(2) Protects natural resources, cultural
resources, and environmental quality;
(3) Protects health and safety;
(4) Ensures proper management,
measurement, disposition, and security
of production; and
(5) Results in the maximum ultimate
recovery of oil and gas with minimum
waste and minimal adverse effect on the
recovery of other mineral resources.
(c) Lessees and permittees must not
commit waste on leased or permitted
lands, nor allow avoidable nuisance to
be maintained thereon.
(d) Lessees and permittees must use
and maintain all installations and
equipment in a manner that ensures
structural and mechanical integrity,
proper function, and the safe conduct of
operations at the location of the
installation or equipment.
(e) Lessees and permittees must
comply with the National Electrical
Code in the installation, operation,
maintenance, and use of all electrical
lines.
§ 226.60

Inspection of operations.

Subpart H—Operations

(a) The Superintendent has the right
to enter or travel across any lands
covered by a lease or permit for the
purpose of conducting an inspection or
investigation.
(b) The Superintendent may conduct
inspections and investigations with or
without advance notice to the lessee or
permittee. Inspections and
investigations may take place at any
time but will normally be conducted
during those hours when responsible
persons are expected to be present at the
site being inspected or investigated.
(c) Lessees and permittees must allow
the Superintendent to inspect and
investigate:
(1) Lands covered by the lease or
permit;
(2) Operations; and
(3) Improvements, facilities,
structures, fixtures, and equipment
located on leased or permitted lands
and any records of design, construction,
maintenance, or repairs relating thereto.

General Requirements

Commencement of Operations

§ 226.59

§ 226.61 No operations may commence
prior to approval of a lease or geophysical
exploration permit.

§ 226.58 Termination of the period of
liability and release of bonds.

(a) The Superintendent will not
terminate the period of liability or
release a geophysical exploration bond
unless all obligations incurred under the
geophysical exploration permit and the
regulations in this part have been
satisfied.
(b) Terminating the period of liability
ends the period during which
obligations accrue but does not relieve
the surety of responsibility for
obligations that accrued during the
period of liability. Release of the bond
relieves the surety of all liability.

Conduct of operations.

(a) Lessees and permittees must
comply with the terms and conditions
of the lease and approved permits, the
regulations in this part, orders and

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No operations may commence on any
tract of land until the Superintendent

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approves a lease or geophysical
exploration permit covering such land.
§ 226.62 Prior authorization required to
commence operations on trust or restricted
lands.

(a) No operations are permitted on
trust or restricted lands without the
Superintendent’s approval.
(b) If an Indian landowner is
unwilling to allow the commencement
of operations on their lands, the
Superintendent will conduct an
examination of the lands with the
Indian landowner and lessee or
permittee. If the Superintendent
determines that the interests of the
Osage Nation require that the lands be
developed or explored, they will
instruct the parties to reach an
agreement under which operations may
be conducted.
(c) If the Indian landowner and lessee
or permittee cannot reach an agreement
under paragraph (b) of this section, the
parties must present the matter to the
Osage Minerals Council, which will
issue a written recommendation. The
Osage Minerals Council’s
recommendation will be considered
final and binding upon the Indian
landowner and lessee or permittee. A
guardian or authorized representative
may represent the Indian landowner
before the Osage Minerals Council. If no
such guardian or authorized
representative exists, or where the
Superintendent determines that there is
no proper party to speak for an Indian
landowner of unsound mind, the
Principal Chief of the Osage Nation will
represent the Indian landowner.
(d) If the Indian landowner or their
guardian or authorized representative
fails to appear before the Osage Minerals
Council as required, or the Osage
Minerals Council fails to act within 10
calendar days after the matter is referred
for recommendation, the
Superintendent may authorize the
lessee or permittee to proceed with
operations.

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§ 226.63 Notice and information to be
given to surface owners prior to
commencement of operations.

(a) The lessee or permittee must meet
with the surface owner prior to the
commencement of any operations on
leased or permitted lands, except for
archeological or biological surveying
and the staking of wells.
(b) For operations other than those
identified in paragraph (a) of this
section, the lessee or permittee must
send the surface owner a written request
for a meeting by certified mail. The
meeting must be held at least 10
calendar days prior to the

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commencement of operations unless the
Superintendent waives such
requirement, or the parties agree
otherwise. At the meeting, the lessee or
permittee must:
(1) Indicate the location of the well(s),
shot holes to be drilled, or seismic
survey site;
(2) Arrange for a route of ingress and
egress. If the lessee or permittee and
surface owner fail to agree on a route of
ingress and egress, the Superintendent
will set the route; and
(3) Provide the name and address of
the representative upon whom the
surface owner must serve any claim for
damages that may be sustained from
operations and the procedure for the
settlement of such claims as set forth in
§ 226.83.
(c) Where operations will occur on
trust or restricted land, the lessee or
permittee must conduct the meeting
required under paragraph (b) of this
section with the Superintendent and, if
possible, the Indian landowner.
(d) If the surface owner cannot be
contacted at their last known address or
has not accepted the meeting request
within 30 calendar days of receipt
thereof, the Superintendent will
authorize the lessee or permittee to
commence operations.
§ 226.64 Payment of commencement
money and tank siting fees to the surface
owner.

(a) Prior to commencing drilling,
reentry, or geophysical exploration
operations, the lessee or permittee must
pay the surface owner commencement
money in the amount of:
(1) $1,500 per well to be drilled or
reentered;
(2) $25 per seismic shot hole; and
(3) $12 per acre, or fraction thereof,
occupied by the lessee or permittee
while conducting a seismic survey.
(b) The lessee must pay the surface
owner $200 per tank for each tank to be
sited on the leased lands, except for
tanks temporarily set on well sites for
drilling, completion, or testing purposes
only.
(c) Commencement money and tank
siting fees must be paid in full prior to
the commencement of operations or
siting of tanks on the lease, subject to
the exception set forth in paragraph (e)
of this section.
(d) Where the surface estate is trust or
restricted land, commencement money
and tank siting fees must be paid to the
Superintendent for the Indian
landowner.
(e) Where the surface estate is not
trust or restricted land, commencement
money and tank siting fees must be paid
to the surface owner directly. If the

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surface owner is not a resident of Osage
County, such payment must be sent by
certified mail to the surface owner’s last
known address. If the payment is
returned as undeliverable or the surface
owner refuses to accept the payment,
the commencement money or tank
siting fees will be deemed forfeited.
Nothing herein affects the surface
owner’s right to the settlement of
surface damages under §§ 226.82 and
226.83.
(f) Commencement money and tank
siting fees are a credit toward the
settlement of surface damages. The
surface owner’s acceptance of
commencement money and tank siting
fees does not affect their right to
compensation for damages occasioned
by operations. A settlement covering the
actual surface damages resulting from
drilling, reentry, or geophysical
exploration operations does not need to
be paid until such operations are
complete.
Drilling, Workover, and Well
Abandonment Operations
§ 226.65 Use of surface lands and water
for operations.

(a) The lessee has the right to use so
much of the surface of the leased lands
as may be reasonable for the
development, extraction, marketing, and
sale of oil and gas. The right to use the
surface lands includes the right-of-way
for ingress and egress to any point of
operations. The right to surface lands
also includes, but is not limited to, the
right to install and maintain pipelines,
electric lines, and other necessary
equipment and facilities. The
Superintendent will determine the
routing of pipelines and electric lines,
as well as the siting of equipment and
facilities of the lessee and surface owner
are unable to agree.
(b) Drilling sites must be held to the
minimum area essential for operations
and must not exceed the acreage set
forth in the approved EA unless the
Superintendent authorizes such
expansion in writing.
(c) The lessee may use water from
natural water courses for approved lease
operations, provided that such use does
not diminish the supply below the
requirements of the surface owner from
whose land the water is taken.
(d) The lessee may use water from
reservoirs formed by the impoundment
of water from natural water courses for
approved lease operations, provided
that such use does not exceed the
quantity to which the lessee would
originally have been entitled had the
reservoirs not been constructed.
(e) The lessee may install necessary
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Osage Mineral Estate to obtain water in
accordance with paragraphs (c) and (d)
of this section. If any such installation
will be over or across surface lands that
are held in trust or restricted status, the
lessee must obtain a right-of-way
pursuant to part 169 of this title prior
to commencing the necessary
installation operations. Any damages
resulting from installations to obtain
water must be settled as provided in
§ 226.83.
§ 226.66

Drilling operations.

(a) The lessee must submit an
Application for Permit to Drill, together
with any required information or
documentation, for each well to be
drilled or reentered. No drilling or
reentry operations, or surface
disturbance preliminary thereto, may
commence prior to the Superintendent’s
approval of the permit.
(b) The Superintendent will not
accept an application for a permit to
drill unless it is administratively
complete.
(c) The lessee must notify the
Superintendent of planned drilling or
reentry operations at least five business
days prior to the commencement
thereof. The Superintendent may
witness such operations without
advance notice.
(d) The lessee may not drill, or
conduct surface disturbance preliminary
to drilling, within 300 feet of the
boundary line of leased lands without
the Superintendent’s approval. The
lessee may not locate a well or tank
within 200 feet of any Federal, state,
county, or municipal road or highway
that is owned and maintained for public
use; any intermittent, ephemeral, or
perennial streams or water sources; or
any building used as a residence,
granary, or barn without the
Superintendent’s approval. Failure to
obtain such approval will result in the
assessment of civil penalties under
§ 226.161 and the issuance of an order
to immediately plug the well or remove
the tank(s) and may subject the lease to
cancellation under § 226.165.
(e) The lessee must submit a
subsequent Well Completion or Reentry
Report following drilling and reentry
operations in accordance with
§ 226.74(c) through (g).
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§ 226.67

Well control.

(a) Drilling wells. The lessee must take
the necessary precautions to keep wells
under control and must use and
maintain materials and equipment
necessary to ensure the safety of
operating conditions and procedures.
(b) Vertical drilling. The lessee must
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that prevents the completed well from
deviating significantly from the vertical
unless the Superintendent’s prior
approval of such deviation is obtained.
The lessee must promptly report any
well that deviates significantly from the
vertical without prior approval to the
Superintendent and conduct a
directional survey. For purposes of this
section, significant deviation means a
projected deviation of the well bore
from the vertical of 10 degrees or more
or a projected bottom hole location that
may be less than 300 feet from the lease
boundary.
(c) High pressure or loss of
circulation. The lessee must take
immediate steps to maintain or restore
control of any well in which the
pressure equilibrium becomes
unbalanced.
§ 226.68
oil.

Use of gas for artificial lifting of

A lessee with an oil-only lease
executed prior to [effective date of final
rule] is prohibited from using gas from
a distinct or separate stratum for the
purpose of flowing or lifting oil. A
lessee with a combined oil and gas lease
may use gas from a distinct or separate
stratum for the purpose of flowing or
lifting oil subject to the requirements set
forth in §§ 226.144 through 226.151.
§ 226.69

Workover operations.

(a) The lessee must submit an
Application for Permit to Workover
Wells, together with any required
information or documentation, for each
well to be worked over. The following
workover operations, and surface
disturbance preliminary thereto, may
not commence prior to the
Superintendent’s approval of the
permit:
(1) Recompletion;
(2) Deepening, plugging back, or
converting a well;
(3) Formation treatments and
acidizing jobs, including acid fracturing;
(4) Hydraulic fracturing; and
(5) Pulling or altering the casing.
(b) The Superintendent will not
accept an application for a workover
permit unless it is administratively and
technically complete.
(c) The lessee must notify the
Superintendent of planned
recompletion, deepening, and hydraulic
fracturing operations at least five
business days prior to the
commencement thereof. The lessee does
not need to provide notice prior to
commencement of the other workover
operations identified in paragraph (a) of
this section. The Superintendent may
witness any workover operations
without advance notice.

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(d) The lessee must submit a
subsequent Report of Workover
Operations following all workover
operations identified in paragraph (a) of
this section in accordance with
§ 226.74(c) through (g).
(e) Prior approval and a subsequent
report of operations are not required for
well cleanout work, well maintenance,
or bottom hole pressure surveys. The
operations listed in paragraph (a) of this
section do not qualify as well cleanout
work or well maintenance.
§ 226.70 Requirements for operations in
Hydrogen Sulfide (H2S) areas.

(a) Testing requirements. (1) The
lessee must conduct an initial test of the
H2S concentration of the gas stream for
each well and production facility
completed and make the results of such
test(s) available to the Superintendent
upon request.
(2) The lessee must determine the
radius of exposure for each well and
production facility having an H2S
concentration of 100 ppm or more in the
gas stream and submit a report of such
calculations to the Superintendent. The
radius of exposure must be calculated as
follows:
(i) For determining the 100-ppm
radius of exposure where the H2S
concentration in the gas stream is less
than 10 percent:
X = [(1.589)(H2S
Concentration)(Q)](0.6258)
(ii) For determining the 500-ppm
radius of exposure where the H2S
concentration in the gas stream is less
than 10 percent:
X = [(0.4546)(H2S
Concentration)(Q)](0.6258)
Where:
X = radius of exposure in feet
H2S Concentration = decimal equivalent of
the mole or volume fractions of the H2S
in the gaseous mixture
Q = maximum volume of gas determined to
be available for escape, or escape rate, in
cubic feet per day (at standard condition
of 14.73 psia and 60 °F)

(iii) For determining the 100-ppm or
500-ppm radius of exposure where the
H2S concentration in the gas stream is
10 percent or greater, the lessee must
use an air dispersion model approved
by the EPA, or such another method the
Superintendent approves.
(3) The lessee must calculate the
radius of exposure pursuant to
paragraph (a)(2) of this section for each
well and production facility completed
prior to [effective date of final rule] that
has a H2S concentration of 100 ppm or
greater in the gas stream and submit a
report of such calculations to the
Superintendent on or before [six months
from effective date of final rule].

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(4) If a change in operations or
production results in an increase in the
H2S concentration or radius of exposure
of five percent or more as calculated
pursuant to paragraph (a)(2) of this
section, the lessee must notify the
Superintendent in writing of such
increase within 60 calendar days of
identification of the change.
(b) Public protection. (1) The lessee
must report any release of a potentially
hazardous volume of H2S to the
Superintendent as soon as practicable,
but not later than 24 hours following
identification of the release.
(2) The lessee must submit a Public
Protection Plan providing a detailed
plan of action for alerting and protecting
the public in the event of a release of a
potentially hazardous volume of H2S
when any of the following conditions
apply:
(i) The 100-ppm radius of exposure is
greater than 50 feet and includes any
part of a residence, school, church,
place of business, or other area the
public can reasonably be expected to
frequent;
(ii) The 500-ppm radius of exposure is
greater than 50 feet and includes any
part of a Federal, state, county, or
municipal road or highway that is
owned and maintained for public use;
or
(iii) The 100-ppm radius of exposure
is greater than or equal to 3,000 feet.
(3) The details of the Public
Protection Plan may vary according to
site-specific characteristics expected to
be encountered and the proximity and
density of the population at risk. All
plans must include the following:
(i) The lessee’s name and phone
number;
(ii) The names, phone numbers, and
responsibilities of key personnel;
(iii) The names and phone numbers of
residents within the radius of exposure;
(iv) The names and phone numbers of
the responsible parties for each of the
schools, churches, businesses, roads,
highways, or other public areas or
facilities within the radius of exposure;
(v) A call list including the Osage
Agency, Osage Minerals Council,
Federal and state regulatory agencies,
local law enforcement, local fire
departments, and other public safety
personnel;
(vi) Instructions and procedures for
notifying the Osage Agency, Osage
Minerals Council, and public of an
emergency;
(vii) Instructions and procedures for
notifying Federal and state regulatory
agencies, local law enforcement, local
fire departments, and public safety
personnel of an emergency and
requesting their response;

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(viii) A plat showing the location of
residences, schools, churches, places of
business, roads, highways, or other
areas the public may reasonably be
expected to frequent within the radius
of exposure;
(ix) Advance briefing of residences,
schools, and churches within the 100ppm radius of exposure. Advance
briefing may be conducted in-person or
by certified letter and must provide:
(A) Information regarding the
characteristics and hazards of H2S and
SO2;
(B) A list of possible sources of H2S
and SO2 within the radius of exposure;
(C) Detailed instructions for reporting
a gas leak to the lessee;
(D) Information regarding the
necessity of having an emergency action
plan;
(E) The way the public will be
notified of an emergency; and
(F) The steps that should be taken in
the event of an emergency;
(x) The title(s) or position(s) of the
individuals authorized by the lessee to
ignite escaping gas, circumstances
under which those individuals may
ignite escaping gas, and way in which
escaping gas will be ignited;
(xi) Procedures for monitoring H2S
and SO2 levels and wind direction,
maintaining site security, controlling
access to the affected site, and
implementing any other measures
necessary to monitor the situation and
protect the public until the release is
contained; and
(xii) A description of the detection
system(s) that will be used to determine
the concentration of H2S released in the
event of a release from a production
facility.
(4) The Public Protection Plan must
be activated immediately upon
detection of the release of a potentially
hazardous volume of H2S. The lessee
must notify the Superintendent of
activation of the Public Protection Plan.
(5) A copy of the Public Protection
Plan must be maintained at the well
site, production facility, or such other
location on the lease that the plan is
readily accessible if activation is
required.
(6) The lessee must review the Public
Protection Plan on an annual basis and
submit any revisions to the
Superintendent.
(c) Operating requirements for
drilling, completion, and workover
operations. (1) If the lessee encounters
zones containing H2S concentrations in
excess of 100 ppm while drilling with
air, gas, mist, or other non-mud
circulating mediums for aerated mud,
the well must be killed with waterbased or oil-based drilling mud, and

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thereafter, mud must be used as the
circulating medium for continued
drilling.
(2) A flare system meeting the
following requirements must be
installed to safely gather and burn H2Sbearing gas:
(i) Flare lines must be located as far
from the operating site as feasible and
must compensate for changes in wind
direction;
(ii) Flare lines must be straight unless
targeted with running tees; and
(iii) The flare system must be
equipped with a safe means of ignition.
(3) The lessee must check the SO2
level in the flare impact area using
portable detection equipment at any site
where SO2 may be released due to the
flaring of H2S during drilling,
completion, or workover operations.
The lessee must implement the Public
Protection Plan if the flare impact area
reaches a sustained ambient threshold
of 2 ppm or greater of SO2 in air and
includes any part of a residence, school,
church, place of business, or other area
the public can reasonably be expected to
frequent.
(4) The lessee must install a remotecontrolled choke or valve for all H2S
drilling operations and, where feasible,
completion operations.
(d) H2S training and safety
requirements. (1) The lessee must
provide appropriate H2S training for all
personnel including, but not limited to,
training regarding:
(i) The hazards and characteristics of
H2S;
(ii) The effect of H2S on metal
components of the well system;
(iii) The operation of safety
equipment;
(iv) First aid procedures in the event
of exposure; and
(v) Emergency response procedures
and evacuation routes if there is a
release of a potentially hazardous
volume of H2S.
(2) The lessee must ensure that the
following safety equipment is available
for use on the lease and maintained in
good working condition:
(i) Protective breathing apparatus for
personnel;
(ii) Communication devices that can
be used with protective breathing
apparatus; and
(iii) A flare gun and flares to ignite the
well.
(3) Each drilling and well completion
site must have an H2S detection and
monitoring system that automatically
activates audible and visible alarms
when the ambient air concentration of
H2S reaches 10 ppm. The system must
have rapid response sensors capable of
sensing a minimum of 10 ppm of H2S

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in ambient air, with at least three
sensing points located at the shale
shaker, rig floor, and bell nipple for a
drilling site, and the cellar, rig floor, and
circulating tanks or shale shaker for a
well completion site. During workover
operations, one sensing point must be
located as close as possible to the
wellbore. The lessee must maintain a
record of all tests of the H2S monitoring
system and make such records available
to the Superintendent upon request.
(4) The lessee must install at least one
wind direction indicator at a location
that is visible at all times during
drilling, completion, and workover
operations.
(5) The lessee must display a red flag
at the entrance to the well or production
facility site when H2S is detected in
excess of 10 ppm at any detection point.
(6) The lessee must post danger or
caution signs on all roads and
controlled access routes to the well or
production facility site. The lessee must
post a danger or caution sign a
minimum of 200 feet, but no more than
500 feet, from the well or production
facility site at a location that allows
vehicles to turn around at a safe
distance. Signs must meet the following
requirements:
(i) Signs must be prominently
displayed, legible, and large enough to
be read from the road or entrance to the
site;
(ii) Signs must be visible to all
personnel and members of the public
approaching the site under normal
lighting and weather conditions;
(iii) Signs must read ‘‘Danger—Poison
Gas—Hydrogen Sulfide’’ or ‘‘Caution—
Poison Gas May Be Present—H2S;’’ and
(iv) Signs must be painted highvisibility red, white, and black, or
yellow and black.
(7) Storage tanks that are utilized as
part of production operations and are
operated at or near atmospheric
pressure, where the vapor accumulation
has an H2S concentration of 500 ppm or
greater in the tank, are subject to the
following requirements:
(i) All stairs and ladders leading to the
top of the storage tank must be chained
and marked to restrict entry;
(ii) The lessee must install at least one
wind direction indicator at the storage
tank site; and
(iii) The lessee must post a danger or
caution sign on the storage tank or
within 50 feet thereof. The sign must
comply with the requirements set forth
in paragraphs (c)(6)(i) through (iv) of
this section.
(8) Production facilities with a H2S
concentration of 100 ppm or greater in
the gas stream are subject to the
following requirements:

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(i) The lessee must install at least one
wind direction indicator at the
production facility site. If the
production facility and storage tank(s)
are located at the same site, only one
indicator is required;
(ii) The lessee must post a danger or
caution sign within 50 feet of the
production facility. The sign must
comply with the requirements set forth
in paragraphs (c)(6)(i) through (iv) of
this section. If the facility is fenced, the
sign may be posted on the gate; and
(iii) The lessee must post danger or
caution signs at each location where a
well flowline or lease gathering line
crosses lease or public roads. The signs
must be posted on each side of the road,
as close to the pipeline as possible, and
must contain the name of the lessee and
a 24-hour phone number.
(9) The lessee must install automatic
safety valves or shutdowns at the
wellhead, or other appropriate shut-in
controls for wells equipped with
artificial lift, where the H2S 100-ppm
radius of exposure includes any part of
a residence, school, church, place of
business, or other area the public may
be reasonably expected to frequent.
Such valves must be set to activate upon
the release of a potentially hazardous
volume of H2S.
(10) All equipment that has the
potential to be exposed to H2S must be
suitable for the H2S working
environment.
§ 226.71

Surveys, samples, and tests.

(a) The Superintendent may require
the lessee to conduct tests, run logs, and
take any other surveys necessary to
determine the following during the
drilling and completion of a well:
(1) The presence, quantity, and
quality of oil and gas;
(2) The presence and quality of water;
(3) The amount and direction of
deviation of any well from the vertical;
and
(4) The formations drilled and
relevant characteristics of the oil and
gas reservoirs penetrated.
(b) After a well is completed, the
lessee must conduct periodic well tests
to determine the quality and quantity of
the oil, gas, and water. The
Superintendent may determine the
method and frequency of such tests.
(c) The Superintendent may require
the lessee to conduct reasonable tests of
the mechanical integrity of downhole
equipment.
§ 226.72

Temporary abandonment.

A lessee may not temporarily
abandon, shut down, or otherwise
discontinue the use or operation of any
producing well for more than 30

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calendar days without the
Superintendent’s prior approval. The
lessee must submit a request for
temporary abandonment to the
Superintendent in writing, together with
any relevant supporting documentation,
for each well to be temporarily
abandoned. Wells cannot be temporarily
abandoned prior to the Superintendent’s
approval of such request.
§ 226.73 Permanent plugging and
abandonment operations.

(a) A lessee may not permanently
abandon a newly completed or
recompleted well unless oil and gas is
not encountered in paying quantities.
(b) A lessee may not permanently
abandon a producing well without the
Superintendent’s approval.
(c) The lessee must promptly plug dry
and permanently abandoned wells in a
manner that protects formations bearing
fresh water, saltwater, oil, gas, and other
minerals.
(d) The lessee must submit an
Application for Permit to Plug Wells,
together with evidence that the well is
no longer capable of producing in
paying quantities, proposed plugging
instructions, and any other required
information or documents, for each well
to be permanently plugged and
abandoned. No plugging and
abandonment operations may
commence prior to the Superintendent’s
approval of the permit.
(e) The Superintendent will not
accept an application for a plugging
permit unless it is administratively and
technically complete.
(f) The lessee must notify the
Superintendent of planned plugging
operations at least five business days
prior to the commencement thereof. The
Superintendent may witness such
operations without advance notice.
(g) The lessee must submit a
subsequent Report of Plugging
Operations in accordance with
§ 226.74(c) through (g).
(h) Upon written agreement with the
surface owner, the lessee may condition
a well that is being plugged and
abandoned for use as a fresh water
supply source for the surface owner.
The lessee must file a copy of any such
agreement with the Superintendent. The
surface owner assumes all risk for the
use of a reconditioned well as a fresh
water supply source.
§ 226.74

Well records and reports.

(a) The lessee must keep accurate and
complete records for all lease operations
and submit reports thereof as required
by the Superintendent and the
regulations in this part. The lessee must
make all books and records available to

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the Superintendent for inspection upon
request.
(b) Records for operations including,
but not limited to, the drilling, reentry,
recompletion, deepening, repair,
conversion, plugging and abandonment
of all wells must show:
(1) All formations penetrated, the
content and character of the oil, gas, and
water in each formation, and the kind,
weight, size, landed depth, and cement
record of casing used;
(2) The record of drill-stem and other
bottom hole pressure or fluid sample
surveys, temperature surveys,
directional surveys, or reports;
(3) The materials and procedures used
in the treating or plugging of wells or
the preparation of wells for temporary
abandonment; and
(4) Any other information obtained
during well operations.
(c) The lessee must submit the
following to the Superintendent within
10 calendar days after the completion of
operations on any well, or any required
sampling, testing, or surveying thereof:
(1) A subsequent report of operations
on the required form;
(2) A copy of the results of all
samples, tests, and surveys required
under this subpart;
(3) A copy of the electrical,
mechanical, and radioactive logs or any
other surveys of the well bore; and
(4) The core analysis obtained from
the well, if available.
(d) For plugging operations, the lessee
must submit copies of all cementing
service tickets together with the
subsequent report of operations.
(e) For hydraulic fracturing
operations, the lessee must submit the
following information together with the
subsequent report of operations:
(1) The total volume of water used;
(2) The total volume of base fluid
used;
(3) The type of base fluid used;
(4) The trade name, supplier, general
purpose, ingredients, Chemical Abstract
Service (CAS) Number, and maximum
ingredient concentration in the
hydraulic fracturing fluid (percent by
mass), for each chemical additive or
other substance added to the base fluid
or, if such chemical identity information
is withheld under paragraph (f) of this
section, the generic chemical name or a
similar descriptor for the chemical;
(5) The actual, estimated, or
calculated fracture length, height, and
direction;
(6) The actual measured depth of
perforations and shots per foot or the
open-hole interval; and
(7) The total volume of fluid
recovered between completion of the
last stage of the hydraulic fracturing

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operation and the point at which the
lessee begins reporting water produced
from the well to ONRR.
(f) If the lessee or owner of the
information claims that any information
that must be reported under paragraph
(e) of this section is exempt from public
disclosure, the information may be
withheld. If information is withheld, the
lessee must submit a Withholding of
Proprietary Hydraulic Fracturing
Information form with the report.
(g) The Superintendent may require a
lessee to submit any information
withheld under paragraph (f) of this
section. The Superintendent will
maintain the confidentiality of the
information unless they determine that
the information is not exempt from
public disclosure. The Superintendent
will provide the lessee with written
notice of any such determination.
(h) The lessee must maintain and
preserve records and reports required
under this section for six years from the
date they were generated, unless the
Superintendent provides written notice
to the lessee that an audit or
investigation is being conducted and the
records must be maintained for a longer
period. If an audit or investigation of the
records is being conducted, the lessee
must maintain the records until the
Superintendent issues a written release
of such obligation.
§ 226.75

Well and facility identification.

(a) The lessee must properly identify
each well located on the lease,
excluding those wells that have been
permanently abandoned, by a sign
placed in a conspicuous location. The
well sign must include the well number,
lessee’s name, lease name, lease
number, and legal description.
(b) The lessee must mark each
permanently abandoned well located on
the lease with a permanent monument
containing the information required
under paragraph (a) of this section. The
Superintendent reserves the right to
waive the requirement for a permanent
monument.
(c) The lessee must properly identify
all facilities at which oil and gas
produced from a lease is stored,
measured, or processed by a sign placed
in a conspicuous location. The sign
must include the lessee’s name, lease
name, lease number, and legal
description.
(d) All signs required by this section
must be maintained in legible condition.
§ 226.76

Pollution prevention.

The lessee or permittee must take
measures to prevent the unauthorized
discharge of pollutants and migration of
oil, gas, saltwater, or other deleterious

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substances to fresh water or other
mineral bearing formations during the
exploration, development, production,
and transportation of oil and gas. The
lessee or permittee must conduct tests
and surveys of the effectiveness of the
measures taken to ensure the protection
of fresh water and mineral bearing
formations and make the results of such
tests available to the Superintendent
upon request.
§ 226.77

Storage and disposal of fluids.

(a) Pits for drilling mud and
deleterious substances used in the
drilling, completion, recompletion,
workover, or plugging of any well must
be constructed and maintained to
prevent the pollution of surface and
subsurface fresh water. The lessee must
routinely inspect and maintain pits to
ensure that there is no fluid leakage into
the environment.
(b) Pits constructed after [effective
date of final rule] may not be located:
(1) In areas subject to frequent
flooding according to the USDA Natural
Resources Conservation Service (NCRS)
Soil Survey;
(2) Within 300 feet of intermittent or
ephemeral streams or water sources; or
(3) Within 500 feet of perennial
streams, springs, fresh water sources, or
wetlands.
(c) Pits may not be constructed,
utilized, enlarged, or relocated without
the Superintendent’s prior approval.
(d) Immediately after the completion
of operations, pits must be emptied and
leveled as the Superintendent directs or
as provided by written agreement with
the surface owner. The lessee must file
a copy of any surface owner agreement
with the Superintendent.
(e) All produced water must be
disposed of by injection into the
subsurface, collection in approved pits,
or other methods the Superintendent
authorizes.
(f) Land application of water-based
fluids from pits, tanks, and containment
vessels; waste oil; waste oil residue;
crude oil contaminated soil; freshwater
drill cuttings; drilling mud; and other
deleterious substances is not permitted
upon any lease without the
Superintendent’s prior approval.
§ 226.78

Removal of fire hazards.

Any material that may constitute a
fire hazard must be moved to a safe
distance from the well site, tanks, and
other surface facilities. Waste oil must
be burned or disposed of in a matter that
prevents creation of a fire hazard.

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Geophysical Exploration Operations
§ 226.79 Applying for a geophysical
exploration permit.

(a) Any party wishing to conduct oil
and gas geophysical exploration
activities on leased or unleased tracts of
the Osage Mineral Estate must submit
an Application for Oil and Gas
Geophysical Exploration Permit and
obtain the Superintendent’s approval
thereof prior to commencing exploratory
operations or any surface disturbance
preliminary thereto.
(b) Upon approval of an application,
the Superintendent will issue a
geophysical exploration permit that
includes the terms and conditions
deemed necessary to protect mineral
resources and other resource values.
The permit does not grant the permittee
any option or preference rights to a lease
of the subject lands or authorize the
production, extraction, removal, or sale
of oil, gas, or other mineral resources
therefrom.
§ 226.80

Commencement of operations.

Permittees must notify the
Superintendent of planned geophysical
exploration operations at least five
business days prior to the
commencement thereof. The
Superintendent may witness any such
activities without advance notice.
§ 226.81

Records and reports.

Within 30 calendar days after the
completion of geophysical exploration
operations, the permittee must submit a
subsequent Oil and Gas Geophysical
Exploration Report.
Settlement of Surface Damages

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§ 226.82 Lessee or permittee required to
settle surface damages.

(a) The lessee or permittee must pay
for damages to growing crops,
improvements on the land, and all other
surface damages occasioned by
operations.
(b) In the settlement of surface
damages on unrestricted lands, all sums
due and payable must be paid to the
surface owner. The surface owner must
apportion damages among the parties
having legal interests in the surface as
the parties mutually agree or as their
interests dictate. Parties having legal
interests in the surface include, but are
not limited to, owners, tenants, and
surface lessees.
(c) In the settlement of damages on
restricted lands, all sums due and
payable must be paid to the
Superintendent. The Superintendent
will apportion damages among the
surface owner, tenants, and surface
lessees of record and credit the surface

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owner’s account with the amount of
damages apportioned.
(d) Any person claiming an interest in
leased trust or restricted lands and
damages thereto must notify the
Superintendent, in writing, of the
interest claimed and provide any
documentation the Superintendent
requests in support thereof. Failure to
submit a written statement or the
required supporting documentation to
the Superintendent constitutes a waiver
of notice and bars that person from
asserting a claim for any portion of
surface damages after such damages
have been disbursed.
§ 226.83 Procedure for settlement of
surface damages.

If a surface owner, tenant, or surface
lessee suffers damages due to oil and gas
exploration or development operations,
the procedure for recovery is as follows:
(a) The aggrieved party or parties
must serve written notice upon the
lessee or permittee as soon as possible
after the discovery of any damages. The
written notice must describe the nature
and location of the alleged damages,
date of occurrence, name of the party or
parties that caused the damages, and
amount of the damages. This
requirement does not limit the time
within which any action must be
brought in a court of competent
jurisdiction to less than the 90-day
period allowed by section 2 of the Act
of March 2, 1929 (45 Stat. 1478, 1479).
(b) If the alleged damages are not
adjusted at the time that written notice
is served, the lessee or permittee must
try to adjust the claim with the
aggrieved party or parties within 20
calendar days of receipt of such notice.
(c) If the parties fail to adjust the
claim within 20 calendar days as
specified in paragraph (b) of this
section, each party has 10 calendar days
to appoint an arbitrator. Immediately
upon their appointment, the two
arbitrators must agree upon a third
arbitrator. If the two arbitrators fail to
agree upon a third arbitrator within 10
calendar days of their appointment, they
must immediately notify the parties. If
the parties cannot agree upon a third
arbitrator within five calendar days after
receipt of such notice, the
Superintendent must appoint the third
arbitrator.
(1) All arbitrators must be
disinterested persons.
(2) Where both a surface owner and
their tenant(s) or surface lessee(s) are
injured, the aggrieved parties must join
in the appointment of an arbitrator.
Where an injury is chargeable to more
than one lessee or permittee, all

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chargeable lessees or permittees must
join in the appointment of an arbitrator.
(3) Each claimant and lessee or
permittee must pay the fees and
expenses for the arbitrator they appoint.
The fees and expenses of the third
arbitrator must be borne equally by the
claimant(s) and lessee(s) or permittee(s).
(d) Immediately following the
appointment of the third arbitrator, the
arbitrators must meet, hear the evidence
and arguments of the parties, and
examine the crops, improvements,
lands, or other property allegedly
damaged. Within 10 calendar days
thereafter, the arbitrators must issue a
written decision regarding the amount
of damages due and serve the decision
upon all interested parties. Any two of
the arbitrators may render the decision
as to the amount of damages due.
(e) Each party has 90 calendar days
from the date the arbitrators’ decision is
served to file an action in a court of
competent jurisdiction challenging the
decision. If no such action is filed and
the arbitration resulted in a decision
finding the lessee or permittee liable for
surface damages, the lessee or permittee
must pay all damages together with
interest assessed from the date of the
award at the IRS underpayment rate
pursuant to 26 U.S.C. 6621(a)(2) within
10 calendar days after expiration of the
period for filing an action in court. The
IRS underpayment rate is posted
quarterly and is available online at
https://www.irs.gov.
(f) If the claimant is an Indian
landowner, the lessee or permittee must
submit any surface damages settlement
agreement to the Superintendent for
approval. The settlement agreement
must describe the nature and location of
the damages, date(s) of occurrence,
settlement amount, and any other
pertinent information.
Subpart I—Production and Site
Security
General Requirements
§ 226.84

Production obligations.

(a) The Superintendent may order a
lessee to promptly drill and produce
wells on any lease acreage regardless of
whether the lessee has drilled and paid
rental if, in their opinion:
(1) A prudent lessee would conduct
further development; or
(2) Such drilling is necessary to
ensure that the lease is properly and
timely developed in accordance with
sound economic operating practices.
(b) Failure to develop a lease in
compliance with the Superintendent’s
order is a violation of the terms and
conditions of the lease and results in

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Federal Register / Vol. 88, No. 9 / Friday, January 13, 2023 / Proposed Rules
termination of the lease by operation of
law as to the acreage the lessee was
ordered to develop.
(c) The lessee must put all oil and gas
produced from the lease into marketable
condition at no cost to the Osage Nation.
(d) Where oil accumulates in a pit,
such oil must either be recirculated
through the regular treating system and
returned to the stock tanks for sale or
pumped into a stock tank without
treatment and measured for sale in the
same manner as from any sales tank
under the regulations in this part.
(e) Except in an emergency, no oil
may be pumped into a pit without the
Superintendent’s prior approval. Each
such pumping occurrence must be
reported to the Superintendent
immediately, but not later than the next
business day, and the oil promptly
recovered in accordance with applicable
orders and notices.

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§ 226.85

Production reporting.

(a) The lessee must submit certified
monthly production reports to ONRR
using Form ONRR–4054, Oil and Gas
Operations Report, regardless of
whether there was production during
the reporting period, if the lessee
operates a lease or cooperative
agreement upon which one or more
wells are not permanently plugged and
abandoned.
(b) The lessee must submit Form
ONRR–4054 for each well every month
beginning with the month in which
drilling is completed or, if production
testing is conducted during drilling
operations, beginning with the month in
which testing occurs. Such reporting
must continue until the lease or
cooperative agreement terminates or is
cancelled and the Superintendent
determines that all wells have been
permanently plugged and abandoned.
(c) Reports must be received by 4 p.m.
mountain time on or before the 15th day
of the second month following the
production month.
(d) The lessee must submit Form
ONRR–4054 electronically via ONRR’s
eCommerce Reporting website, https://
onrrreporting.onrr.gov, unless they
qualify for an exception under
paragraph (e) of this section. The lessee
must enter production data into the
system manually or upload data files in
American Standard Code for
Information Exchange (ASCII) or
Comma Separated Values (.csv) file
formats that ONRR specifies.
Information regarding how to complete
and submit Form ONRR–4054 is
available at https://www.onrr.gov/
ReportPay/royalty-reporting.htm.
(e) The lessee may submit Form
ONRR–4054 manually if they:

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(1) Have never reported to ONRR
before. In such instance, they have three
months from the date the first
production report is due to begin
reporting electronically; or
(2) Have a small business, as defined
by the Small Business Administration,
and do not own a computer.
(f) Production reports submitted
manually via U.S. Postal Service must
be addressed to: Office of Natural
Resources Revenue, P.O. Box 25627,
Denver, CO 80225–0627. Production
reports submitted manually via courier
or overnight delivery service must be
addressed to: Office of Natural
Resources Revenue, Denver Federal
Center, Building 85, Room A–614, 6th
Avenue and Kipling Street, Denver, CO
80225.
§ 226.86

Site facility diagrams.

(a) A site facility diagram is required
for all permanent facilities. A site
facility diagram is not required for
temporary measurement facilities used
during well testing operations. No
format is prescribed for site facility
diagrams. The diagram should be
formatted to fit on an 81⁄2 x 11-inch
sheet of paper, if possible, and must be
legible and comprehensible to an
individual with an ordinary working
knowledge of oil and gas field
operations. If more than one page is
required, each page must be numbered
using the format ‘‘N of X pages.’’ The
diagram does not need to be to scale.
Sample site facility diagrams are
available at https://www.bia.gov/
regional-offices/eastern-oklahoma/
osage-agency.
(b) The site facility diagram must:
(1) Clearly identify the name of the
lessee, lease(s) the diagram applies to,
and facility location. Facility location
must include both GPS coordinates and
the legal description;
(2) Reflect the position of the
production and water recovery
equipment, piping for oil, gas, and
water, and metering or other measuring
systems in relation to each other;
(3) Commencing with the header,
identify all equipment including, but
not limited to, the header, wellhead,
piping, tanks, metering systems located
on the site, appropriate valves, and any
other equipment used in the handling,
conditioning, or disposal of production
and water, and must indicate the
direction or flow;
(4) Identify the wells flowing into
headers by US Well Number;
(5) Indicate which valve(s) must be
sealed and in what position during the
production phase, sales phase, and
during other production activities (e.g.,
circulating tanks or drawing off water),

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which may be shown by an attachment,
if necessary;
(6) Clearly identify all meters and
measurement equipment on the diagram
or in an attachment to the diagram; and
(7) Clearly identify the FMP(s) for
each measurement facility where the
measurement affects calculation of the
volume or quality of oil and gas
production upon which royalty is owed.
Where production from more than one
well will flow into the FMP(s), the
lessee must list all US Well Numbers
associated with each FMP.
(c) For new, permanent facilities that
become operational after [effective date
of final rule], a site facility diagram
must be filed within 60 calendar days
after the facilities become operational.
(d) For facilities that are in service on
or before [effective date of final rule], a
site facility diagram identifying FMPs,
as required by paragraph (b)(7) of this
section, must be filed by [120 days after
effective date of final rule] or such
longer period as the Superintendent
may authorize.
(e) After a site facility diagram is
submitted pursuant to this section, the
lessee has an ongoing obligation to
amend the diagram within 60 calendar
days after any facilities are modified.
§ 226.87 Assignment of facility
measurement point (FMP) numbers.

The BIA will assign a unique FMP
number to each oil and gas FMP
identified on the site facility diagram
submitted under § 226.85.
(a) For a new facility in service after
[effective date of final rule], the lessee
must start using FMP numbers for
reporting to ONRR the first production
month after the BIA assigns the FMP
numbers and every month thereafter.
(b) For an existing facility in service
on or before [effective date of final rule],
the lessee must start using FMP
numbers for reporting to ONRR the third
production month after the BIA assigns
the FMP numbers and every month
thereafter.
§ 226.88 Requirements for production
records.

(a) Lessees, purchasers, transporters,
and other persons involved in
producing, transporting, purchasing,
selling, or measuring oil and gas
through the point of royalty
measurement or point of first sale,
whichever is later, must retain all
records, including source records,
relevant to determining the quality,
quantity, disposition, and verification of
production attributable to the subject
lease. This applies to all records
generated during, or for, the period the
lessee has an interest in, or conducts

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operations on, the lease or the period in
which a purchaser, transporter, or other
persons are involved in transporting,
purchasing, or selling production
therefrom.
(b) Records that are created after
[effective date of final rule] must be
legible and include the following:
(1) The FMP, lease, or unit number;
(2) A unique equipment identifier
(e.g., a unique tank or meter station
number);
(3) The name of the person who
created the record; and
(4) The signor’s printed name, for any
records requiring a signature.
(c) Records under this section must be
maintained and preserved for a
minimum of six years from the date
upon which the relevant transaction
was recorded unless the Superintendent
or ONRR provides written notice to the
lessee that an audit or investigation is
being conducted and the records must
be maintained for a longer period. If an
audit or investigation of the records is
being conducted, the lessee must
maintain the records until the
Superintendent or ONRR issues a
written release of such obligation.
(d) Records under this section must be
made available to the Superintendent or
ONRR for inspection upon request. A
reasonable period of time will be
provided to produce historical records.
§ 226.89 Easements for access to wells
located off-lease.

(a) The Superintendent may grant
commercial and non-commercial SWD
easements for access to existing wells
located off-lease on trust or restricted
Indian lands in accordance with the
regulations in part 169 of this title.
(b) The grantee must post a
performance bond for all SWD
easements in accordance with the
requirements in subpart G.
(c) The lessee is responsible for all
surface damages resulting from use of
the easement and must settle such
damages as provided in § 226.83.
Waste Prevention

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§ 226.90

Prevention of waste.

(a) A lessee must conduct all
operations in a manner that prevents the
waste of oil and gas and must not use
oil and gas in a wasteful manner.
(b) The Superintendent has authority
to impose requirements deemed
necessary to prevent the waste of oil and
gas and promote the maximum ultimate
economic recovery thereof, consistent
with conservation of the resources.
(c) For purposes of this section, waste
includes, but is not limited to,
inefficient, excessive, or improper use
or dissipation of reservoir energy

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resulting in a reasonable reduction in
the quality of oil and gas that may be
produced or the unnecessary or
excessive surface loss or destruction of
oil and gas without beneficial use.

(ix) Emergencies, subject to the
limitations in § 226.156(d).
(3) Produced gas that is vented or
flared with the Superintendent’s
approval.

§ 226.91 Royalty on lost or wasted
production.

Drainage Obligations

(a) Royalty is due on all oil and gas
avoidably lost or wasted. The
Superintendent and ONRR will
determine the volume and quality of
lost or wasted production. Royalty is not
due on oil and gas that is unavoidably
lost.
(b) The following qualify as avoidably
lost production:
(1) Gas that is vented or flared
without the Superintendent’s prior
approval; and
(2) Produced oil or gas that the
Superintendent determines was lost
because of the lessee’s:
(i) Negligence;
(ii) Failure to take all reasonable
measures to prevent or control the loss;
or
(iii) Failure to comply with applicable
lease and permit terms and conditions,
the regulations in this part, or
applicable orders and notices.
(c) The following qualify as
unavoidably lost production:
(1) Oil or gas that is lost because of
line failures, equipment malfunctions,
blowouts, fires, or other similar
circumstances, except where the
Superintendent determines that the loss
was avoidable pursuant to paragraph
(b)(2) of this section;
(2) Oil or gas that is lost during the
following operations, and from the
following sources, except where the
Superintendent determines that the loss
was avoidable pursuant to paragraph
(b)(2) of this section:
(i) Well drilling;
(ii) Well completion and related
operations;
(iii)Initial production tests, subject to
the limitations in § 226.156(a);
(iv) Subsequent well tests, subject to
the limitations in § 226.156(b);
(v) Exploratory coalbed methane well
dewatering;
(vi) Normal gas vapor losses from a
storage tank or other low-pressure
vessel, unless the Superintendent
determines that recovery of the gas
vapors is warranted;
(vii) Well venting during downhole
well maintenance or liquids unloading,
performed in compliance with
§ 226.156(c);
(viii) Facility and pipeline
maintenance, such as when the lessee
must blow-down and depressurize
equipment to perform maintenance or
repairs; and

§ 226.92

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Prevention of drainage.

(a) Where any lease is being drained
of oil and gas by wells on an adjacent
lease issued at a lower royalty rate, the
Superintendent may require the lessee
being drained to:
(1) Drill or modify and produce all
wells necessary to protect the lease from
drainage;
(2) Enter into a cooperative agreement
with the lease upon which the draining
well is located; or
(3) Pay compensatory royalties for
drainage that has occurred and
continues to occur.
(b) The Superintendent may, in their
discretion, approve alternative,
equivalent protective measures outside
of those set forth in paragraph (a) of this
section.
(c) The lessee must take protective
action within a reasonable time after
they first knew, or had constructive
notice, that drainage may be occurring.
For purposes of this section, a lessee is
considered to have constructive notice
of drainage if they operate or own any
interest in the draining lease or well.
(d) If the Superintendent has reason to
believe that drainage is occurring, they
will notify the lessee in writing. Such
notification does not alleviate the
lessee’s responsibility to take protective
action when they first knew, or had
constructive notice, that drainage may
be occurring, which date may precede
the receipt of notice from the
Superintendent.
(e) The Superintendent will
determine whether a lessee took
protective action within a reasonable
time on a case-by-case basis taking into
consideration the time required to
evaluate the characteristics and
performance of the draining well; rig
availability; well depth; the need for
environmental analysis; weather
conditions; and other relevant factors.
(f) The lessee is not required to take
any of the protective actions listed in
paragraph (a) of this section if they can
prove, to the Superintendent’s
satisfaction, that when they first knew,
or had constructive notice, of drainage,
a sufficient quantity of oil or gas could
not be produced from a protective well
for a reasonable profit above the cost of
drilling, completing, and operating the
protective well.

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§ 226.93 Compensatory royalty for
drainage.

(a) If the Superintendent determines
that a lessee was required to take
protective action to prevent drainage
under § 226.92 and failed to take such
action within a reasonable time, the
lessee must pay compensatory royalty
for the period of the delay.
(b) The Superintendent will assess
compensatory royalty beginning on the
first calendar day of the month
following the earliest reasonable time
the lessee should have taken protective
action and continuing until:
(1) The lessee drills adequate
economic protective wells, and such
wells remain in continuous production;
(2) The Superintendent approves a
cooperative agreement that covers the
mineral resources being drained or
alternative protective measures;
(3) The draining well stops producing;
or
(4) The lessee relinquishes their
interest in the lease through an
assignment.
(c) If a lessee assigns their interest in
a lease, they are not liable for drainage
that occurs after the effective date of the
assignment.
(d) An assignee is liable for all
drainage obligations that accrue after the
effective date of the assignment.
Site Security

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§ 226.94
seals.

Storage and sales facilities—

(a) All lines entering or leaving any
oil storage tank must have valves
capable of being effectively sealed
during the production and sales phases
unless otherwise provided by the
regulations in this part. Existing valves
may be modified so that they are
capable of being effectively sealed.
Appropriate valves must be in an
operable condition and accurately
reflect whether the valve is open or
closed.
(1) During the production phase, all
appropriate valves that allow
unmeasured production to be removed
from storage must be effectively sealed
in the closed position. During any other
phase (e.g., sales, water draining, hot
oiling), and prior to taking the top tank
gauge measurement, all appropriate
vales that allow unmeasured production
to enter or leave the sales tank must be
effectively sealed in the closed position.
(2) Each unsealed or ineffectively
sealed valve is a separate violation.
(b) Valves, or combinations of valves
and tanks, that provide access to
production before it is measured for sale
are considered appropriate valves and
are subject to the seal requirements in

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this part. If there is more than one valve
on a line from a tank, the valve closest
to the tank must be sealed.
(c) All appropriate valves must be in
operable condition and accurately
reflect whether the valve is open or
closed.
(d) The following are not considered
appropriate valves and, therefore, are
not subject to the seal requirements in
this part:
(1) Valves on production equipment
(e.g., dehydrator, gun barrel, or wash
tank);
(2) Valves on water tanks, provided
that the possibility of access to
production in the sales and storage
tanks does not exist through a common
circulating drain, overflow, or equalizer
system;
(3) Valves on tanks that contain what
the Superintendent determines to be
slop or waste oil;
(4) Sample cock valves used on piping
or tanks with a Nominal Pipe Size of
one inch or less in diameter;
(5) Fill-line valves during shipment
when a single tank with a nominal
capacity of 500 bbl or less is used for
collecting marginal production of oil
produced from a single well (i.e.,
production that is less than three bbl per
day). All other seal requirements apply;
(6) Gas line valves used on piping
with a Nominal Pipe Size of one inch
or less used as tank bottom ‘‘roll’’ lines,
provided that there is no access to the
contents of the storage tank and the roll
lines cannot be used as equalizer lines;
(7) Valves on tank heating systems
that use a fluid other than the contents
of the storage tank (i.e., steam, water,
glycol);
(8) Valves used on piping with a
Nominal Pipe Size of one inch or less,
connected directly to the pump body or
used on pump bleed off lines;
(9) Tank vent-line valves; and
(10) Sales, equalizer, or fill-line valves
on systems where production may be
removed only through approved oil
metering systems (e.g., LACT or CMS).
Any valve that allows access for
removal of oil before it is measured
through the metering system must be
effectively sealed.
(e) Tampering with any appropriate
valve is prohibited.
§ 226.95 Oil measurement system
components—seals.

(a) Components used for determining
the quality or quantity of oil must be
effectively sealed to indicate tampering.
Such components include, but are not
limited to, the following components of
LACT meters and CMSs:
(1) The sampler volume control;
(2) All valves on lines entering or
leaving the sample container, excluding

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the safety pop-off valve, if so equipped.
Each valve must be sealed in the open
or closed position, as appropriate;
(3) The mechanical counter head
(totalizer) and meter head;
(4) The stand-alone temperature
averager monitor;
(5) The non-automatic adjusting, fixed
back-pressure valve pressure adjustment
downstream of the meter;
(6) Any drain valves larger than one
inch in nominal diameter; and
(7) The right-angle drive.
(b) Each missing or ineffectively
sealed component is a separate
violation.
§ 226.96 Removing production from tanks
for sale and transportation by truck.

(a) When a single truckload
constitutes a completed sale, the driver
must possess the documentation
required in § 226.114.
(b) When multiple trucks are involved
in a sale and the oil measurement
method is based on the difference
between the opening and closing
gauges, the driver of the last truck must
possess the documentation required in
§ 226.114. All other drivers involved in
the sale must possess a trip log or
manifest.
(c) After the seals have been broken,
the purchaser or transporter is
responsible for the entire contents of the
tank until it is resealed. When a single
truck is involved in a sale with multiple
truckloads, the purchaser or transporter
must seal the tank in between each
individual truckload.
§ 226.97 Documentation required for
transportation of oil and gas.

(a) Any person engaged in
transporting by motor vehicle any oil
produced from or allocated to any lease,
must carry on their person, in their
vehicle, or have in their immediate
control, documentation showing the
amount, origin, and intended first
purchaser of the oil.
(b) Any person engaged in
transporting any oil or gas produced
from or allocated to any lease by
pipeline, must maintain documentation
showing the amount, origin, and
intended first purchaser of the oil or gas.
(c) Any properly identified authorized
representative of the Superintendent
may stop and inspect any motor vehicle
on a lease if they have probable cause
to believe the vehicle is carrying oil
produced from or allocated to the lease,
to determine whether the driver
possesses proper documentation for the
load of oil.
(d) Any appropriate law enforcement
officer or properly identified authorized
representative of the Superintendent

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accompanied by an appropriate law
enforcement officer, may stop and
inspect any motor vehicle that is off
lease, if there is probable cause to
believe the vehicle is carrying oil
produced from or allocated to a lease, to
determine whether the driver possesses
proper documentation for the load of
oil.
§ 226.98

Water draining operations.

When water is drained from a
production storage tank, the lessee,
purchaser, or transporter must
document the following information:
(a) The lease number;
(b) The tank location using both GPS
coordinates and legal description;
(c) The unique tank number and
nominal capacity;
(d) The date of the opening gauge;
(e) The opening gauge (gauged
manually or automatically), TOV, and
free water measurements, all to the
nearest 1⁄2 inch;
(f) The unique identifying number of
each seal removed;
(g) The closing gauge (gauged
manually or automatically) and TOV
measurement to the nearest 1⁄2 inch; and
(h) The unique identifying number of
each seal installed.

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§ 226.99 Hot oiling, clean-up, and
completion operations.

(a) During hot oil, clean-up,
completion operations, or any other
situation where the lessee removes oil
from storage, temporarily uses it for
operational purposes, and then returns
it to storage, they must document the
following information:
(1) The lease number;
(2) The tank location using both GPS
coordinates and legal description;
(3) The unique tank number and
nominal capacity;
(4) The date of the opening gauge;
(5) The opening gauge measurement
(gauged manually or automatically) to
the nearest 1⁄2 inch;
(6) The unique identifying number of
each seal removed;
(7) The closing gauge measurement
(gauged manually or automatically) to
the nearest 1⁄2 inch;
(8) The unique identifying number of
each seal installed;
(9) How the oil was used; and
(10) Where the oil was used (e.g., well
or facility name and number).
(b) During hot oiling, line flushing, or
completion operations of any other kind
where the lessee removes production
from storage for use on a different lease,
the production is considered sold and
must be measured in accordance with
the requirements in the regulations in
this part and reported to ONRR for the

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period covering the production in
question.
§ 226.100

Seal records.

For each seal, the lessee must
maintain a record that includes the:
(a) Unique identifying number of each
seal and the valve or meter component
on which the seal is, or was, used;
(b) Date of installation or removal of
each seal;
(c) Position in which the valve was
sealed (e.g., open or closed); and
(d) Reason the seal was removed.
§ 226.101 Requirements for off-lease
measurement of production.

(a) The lessee must submit a request,
in writing, for off-lease measurement of
production and obtain the
Superintendent’s approval thereof. The
request must include the following
information:
(1) The lessee’s name;
(2) The lease number for which the
lessee is requesting off-lease
measurement;
(3) The US Well Number(s) and GPS
coordinates for each well included in
the off-lease measurement proposal; and
(4) The lease number and legal
description for the existing or proposed
off-lease FMP.
(b) Off-lease measurement of
production must occur at an identified
FMP unless the Superintendent
authorizes otherwise.
§ 226.102 Report of spills, theft,
mishandling of production, accidents, or
fires.

(a) Lessees must report the following
to the Superintendent and surface
owner(s) immediately upon discovery,
but not later than the calendar day
following discovery:
(1) All spills or releases of oil, gas,
produced water, toxic liquids,
deleterious substances, or waste
materials;
(2) Theft of equipment or production;
(3) Blowouts;
(4) Fires;
(5) Mishandling of production; and
(6) Accidents on the lease that
resulted in the loss of production or
damage to measurement equipment.
(b) In addition to providing
emergency notification by phone or in
person, the lessee must also send
written notice of the incidents identified
in paragraphs (a)(1) through (4) of this
section to surface owner(s) by certified
mail—return receipt requested.
(c) The lessee must submit a Spill and
Remediation Report for all spills and
releases, and a written report of all other
incidents, to the Superintendent within
five business days of any incident
identified in paragraph (a) of this

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section, together with a proposed
contingency or remediation plan that
describes the procedures being
implemented to restore resource values
and protect life, property, and the
environment.
(d) The lessee must exercise due
diligence in taking necessary measures
to control and remove pollutants and
extinguish fires.
(e) Compliance with the requirements
set forth in the regulations in this part
does not relieve the lessee of the
obligation to comply with all other
applicable laws and regulations.
Subpart J—Oil Measurement
§ 226.103

General requirements.

(a) Oil must be measured on the lease
or unit area from which it is produced
unless approval for off-lease
measurement of production is obtained
in accordance with § 226.101.
(b) All bypasses of meters are
prohibited.
(c) Tampering with any measurement
device, component of a measurement
device, or measurement process is
prohibited.
(d) Violation of the prohibitions set
forth in paragraphs (b) and (c) of this
section will result in assessment of the
maximum penalty available under
§ 226.162(c).
§ 226.104

Timeframes for compliance.

(a) All equipment and procedures
used to measure the volume of oil for
royalty purposes after [effective date of
final rule] must comply with the
requirements in this subpart.
(b) All equipment and procedures
used to measure the volume of oil for
royalty purposes installed or in-use on
leases approved prior to [effective date
of final rule] must comply with the
requirements in this subpart by [one
year from effective date of final rule].
Prior to that date, the equipment and
procedures used to measure oil for
royalty purposes must continue to
comply with § 226.38, as it appears in
25 CFR part 226 (April 1, 2017, edition)
and any applicable orders or notices.
§ 226.105

[Reserved]

§ 226.106 Specific measurement
performance requirements.

(a) Volume measurement uncertainty
levels. (1) The FMP must achieve the
following volume measurement
uncertainty levels, calculated in
accordance with the statistical
methodologies set forth in API 13.3 and
the quadrature sum method set forth in
Subsection 12.3 of API 14.3.1 (both
incorporated by reference, see § 226.0):

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(f) The lessee must accurately
TABLE 1 TO PARAGRAPH (a)(1)—VOLUME MEASUREMENT UNCERTAINTY calibrate each oil storage tank that has
a tank gauging system and is associated
LEVELS
If the averaging period
volume is:
1. Greater than or equal
to 30,000 bbl/month.
2. Less than 30,000 bbl/
month.

The overall volume
measurement
uncertainty level
must be within:
+/¥0.50 percent.
+/¥1.50 percent.

(2) The Superintendent may grant an
exception to the uncertainty levels in
paragraph (a) of this section only upon
the lessee’s showing that meeting the
required uncertainty level would
involve extraordinary cost or
unacceptable adverse environmental
effects.
(b) Bias. The measurement equipment
used for volume determinations must
achieve measurement without
statistically significant bias.
(c) Verifiability. All FMP equipment
must be susceptible to the BIA’s
independent verification of the accuracy
and validity of all inputs, factors, and
equations used to determine quality or
quantity. Verifiability includes the
ability to independently recalculate the
volume and quality of oil based on
source records.

lotter on DSK11XQN23PROD with PROPOSALS3

§ 226.107 Tank gauging—general
requirements.

(a) Oil measurement by tank gauging
must be performed using the procedures
set forth in § 226.108 and accurately
compute the total net standard volume
of oil withdrawn from a properly
calibrated sales tank.
(b) Each tank used for oil storage must
comply with the recommended
practices in Subsection 4 of API RP
12R1 (incorporated by reference, see
§ 226.0) and must be connected,
maintained, and operated in compliance
with §§ 226.94, 226.98, and 226.99.
(c) All oil storage tanks must be
clearly identified and have a unique
number the lessee generated stenciled
on the tank and maintained in a legible
condition.
(d) Each oil storage tank that has a
tank gauging system and is associated
with an FMP must be set and
maintained on a level plane.
(e) Each oil storage tank that has a
tank gauging system and is associated
with an FMP must be gauged using a
gauging reference point located at 180
degrees (6:00 o’clock) when the
individual performing the gauging is
facing the tank hatch unless the
Superintendent approves an alternative
method.

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with an FMP using either API 2.2A, API
2.2B, or API 2.2C and API RP 2556 (all
incorporated by reference, see § 226.0)
and:
(1) Determine sales tank capacities by
tank calibration using actual tank
measurements, with unit volume in bbl
and incremental height measurements
that match the gauging increment
specified in § 226.108(b)(5)(i)(d);
(2) Recalibrate the sales tank if there
is a change in purchaser, the tank is
relocated or repaired, or the capacity of
the tank changes due to denting,
damage, installation, removal of interior
components, or other alterations; and
(3) Submit sales tank tables to the
Superintendent within 45 calendar days
after calibration or recalculation of the
tables.

§ 226.108

Tank gauging—procedures.

(a) The lessee may use manual or
automatic tank gauging to determine the
quality and quantity of oil measured
under field conditions at an FMP. The
Superintendent’s prior approval is
required for all automatic tank gauging.
Requests for authorization to use
automatic tank gauging must be
submitted to the Superintendent in
writing and include the make and
model of the automatic tank gauge
(ATG) the lessee proposes to use.
(b) The lessee must comply with the
following procedures to determine the
quality and quantity of oil measured:
(1) Isolate tank. Isolate the tank for at
least 30 minutes to allow the contents
to settle before conducting tank gauging
operations. Tank isolating valves must
be closed and sealed in accordance with
§ 226.94.
(2) Determine opening oil
temperature. Determine the temperature
of oil contained in the sales tank in
accordance with API 7.1 or API 7.2
(both incorporated by reference, see
§ 226.0) and the following requirements:
(i) A single temperature measurement
at the middle of the liquid may be used
for tanks with less than 5,000 bbls
nominal capacity;
(ii) Glass thermometers must be clean,
free of fluid separation, and have a
minimum graduation of 1.0 °F and an
accuracy of +/¥0.5 °F; and
(iii) Electronic thermometers must
have a minimum graduation of 1.0 °F
and an accuracy of +/¥0.5 °F.
(3) Take oil samples. The lessee must
conduct sampling operations prior to
taking the opening gauge unless
automatic sampling methods are used.
Sampling of oil removed from an FMP
tank must yield a representative sample

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of the oil and its physical properties and
comply with the requirements in API
8.1 (incorporated by reference, see
§ 226.0).
(4) Determine observed oil gravity.
The lessee must conduct tests for oil
gravity in accordance with API 9.1, API
9.2, or API 9.3 (all incorporated by
reference, see § 226.0) and the following
requirements:
(i) The hydrometer or
thermohydrometer must be clean with a
clear, legible oil gravity scale and no
loose shot weights and must be
calibrated for an oil gravity range that
includes the observed gravity of the oil
sample being tested;
(ii) The lessee must allow the
temperature to stabilize for a minimum
of five minutes prior to reading the
hydrometer or thermohydrometer; and
(iii) The lessee must read and record
the observed API oil gravity to the
nearest 0.1 degree and the temperature
to the nearest 1.0 °F.
(5) Measure opening tank fluid level.
The lessee must take and record the
opening gauge only after samples have
been taken.
(i) The lessee must conduct manual
gauging in accordance with API 3.1A
and API 18.1 (both incorporated by
reference, see § 226.0) subject to the
following exceptions, additions, and
clarifications:
(A) The proper innage-gauging bob for
the measurement method must be used;
(B) A gauging tape must be used. The
tape must be made of steel or corrosionresistant material with graduation
clearly legible and must not be kinked
or spliced;
(C) A suitable product-indicating
paste must be used on the gauging tape
to facilitate the reading. The use of
chalk or talcum powder is prohibited;
and
(D) The lessee must obtain two
consecutive gauging measurements that
are within 1⁄4 inch of each other for any
tank regardless of size.
(ii) The lessee must conduct
automatic tank gauging in accordance
with API 3.1B, and API 3.6 (both
incorporated by reference, see § 226.0)
and the following requirements:
(A) The ATG must be inspected, and
its accuracy verified to within +/¥1⁄4
inch, in accordance with the procedures
in Subsection 9 of API 3.1B
(incorporated by reference, see § 226.0)
prior to sales and upon the
Superintendent’s request. If the ATG is
found to be out of the manufacturer’s
tolerance, the lessee will be required to
calibrate the ATG prior to sales; and
(B) The lessee must make a detailed
log of ATG field verifications available
to the Superintendent upon request.

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(6) Determine S&W content.
Determine the S&W content of the oil in
the sales tanks in accordance with API
10.4 (incorporated by reference, see
§ 226.0) using the oil samples obtained
pursuant to paragraph (d) of this
section.
(7) Transfer oil. Break the tank load
valve seal and transfer the oil to the
tanker truck. After the transfer is
complete, close and seal the tank valve
in accordance with §§ 226.94 and
226.96.
(8) Determine closing oil temperature.
Determine the closing oil temperature
using the procedures set forth in
paragraph (b)(2) of this section.
(9) Take closing tank gauge. Take the
closing tank gauge using the procedures
set forth in paragraph (b)(5) of this
section.
(10) Complete run ticket. Complete
the run ticket in accordance with
§ 226.114.
§ 226.109 LACT system—general
requirements.

(a) LACT systems must meet the
construction and operation
requirements and minimum standards
set forth in this section and §§ 226.103
and 226.110.
(b) LACT systems must be proven as
set forth in § 226.113.
(c) Run tickets must be completed as
set forth in § 226.114.
(d) All components of LACT systems
must be accessible for inspection.
(e) The lessee must notify the
Superintendent, in writing, of any LACT
system failure or equipment
malfunction that may have resulted in
measurement error within 15 calendar
days of discovering the failure.
(f) Any tests conducted on oil samples
extracted from LACT system samplers
for determination of S&W content and
observed oil gravity must meet the
requirements and minimum standards
set forth in § 226.108(b)(2), (4), and (6).
(g) The average temperature for the
run ticket must be calculated for the
measurement period covered by the run
ticket and must be the temperature used
to calculate the CTL correction factor
using API 11.1 (incorporated by
reference, see § 226.0).

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§ 226.110 LACT system—components and
operating requirements.

(a) Each LACT system must include
all equipment listed in API 6.1
(incorporated by reference, see § 226.0),
subject to the following exceptions:
(1) The LACT meter must be a
positive displacement or Coriolis meter;
(2) An electronic temperature
averaging device must be installed; and
(3) Meter back-pressure must be
applied by a back-pressure valve or

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other controllable means of applying
back-pressure. Back-pressure may be
maintained by an automatic-adjusting
back-pressure control to adjust for
changing flow conditions. Back-pressure
control must maintain a pressure that is
above the bubble point of the liquid to
prevent the formation of vapor, ensuring
single-phase flow.
(b) All LACT system components
must be operated in accordance with
API 6.1 (incorporated by reference, see
§ 226.0) and the following requirements:
(1) Sampling and mixing must be
conducted in accordance with API 8.2
and API 8.3 (both incorporated by
reference, see § 226.0), and the sample
exactor probe must be inserted in the
center half of the flowing stream,
horizontally oriented, and have external
markings that show the orientation of
the probe in relation to the direction of
flow.
(2) All tests conducted on oil samples
extracted from LACT system samplers
for determination of oil gravity must be
conducted in accordance with API 9.1,
API 9.2, or API 9.3 (all incorporated by
reference, see § 226.0). All tests for the
determination of S&W content must be
conducted in accordance with API 10.4
(incorporated by reference, see § 226.0).
(3) The composite sample container
must be emptied and cleaned upon
completion of the sample withdrawal.
(4) The positive displacement or
Coriolis meter must be equipped with a
non-resettable totalizer. The nonresettable totalizer display may reside in
an electronic flow computer. The meter
must include or allow for the
attachment of a device that generates at
least 8,400 pulses per bbl of registered
volume.
(5) The pressure-indicating device
must be located downstream of the
meter, but upstream of the first valve of
the prover connections. The pressureindicating device must be capable of
providing pressure data to calculate the
CPL correction factor.
(6) The electronic temperature
averaging device may be a stand-alone
device or a function of a flow computer
and must be installed, operated, and
maintained as follows:
(i) The temperature thermowell and
transducer must be installed as set forth
in Subsections 6.3 and 7.2 of API 7.4
(incorporated by reference, see § 226.0);
(ii) The electronic temperature
averaging device must be volumeweighted and take a temperature
reading as set forth in Subsection 9.2.8
of API 21.2 (incorporated by reference,
see § 226.0);
(iii) The average temperature for the
run ticket must be calculated using the
volumetric averaging method set forth

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in Subsection 9.2.13.2a of API 21.2
(incorporated by reference, see § 226.0);
(iv) The temperature averaging device
must have a reference accuracy of +/
¥0.5 °F or better and a minimum
graduation of 0.1 °F.
(v) The temperature averaging device
must include a display of the
instantaneous temperature and average
temperature calculated since the run
ticket was opened. The display may be
a function of an electronic flow
computer; and
(vi) The average temperature
calculated since the run ticket was
opened must be used to calculate the
CTL correction factor.
(7) The net standard volume must be
calculated at the close of each run ticket
in accordance with the guidelines set
forth in API 11.1 and API 12.2.2 (both
incorporated by reference, see § 226.0).
§ 226.111 Coriolis measurement systems
(CMS)—general requirements and
components.

This section applies to Coriolis
measurement applications that are
independent of LACT systems.
(a) A CMS must meet the
requirements and minimum standards
set forth in this section and §§ 226.106
and 226.112.
(b) A CMS must be proven as set forth
in § 226.113.
(c) Run tickets must be completed as
set forth in § 226.114.
(d) A CMS at an FMP must be
installed with the components listed in
API 5.6 (incorporated by reference, see
§ 226.0) and in accordance with the
following requirements:
(1) The pressure transducer must meet
the requirements set forth in
§ 226.110(b)(5);
(2) The temperature determination
must meet the requirements set forth in
§ 226.110(b)(6);
(3) The sampling system must meet
the requirements set forth in
§ 226.110(b)(1) through (3) if nonzero
S&W content is to be used in
determining net oil volume. If no
sampling system is used, or the
sampling system does not meet the
requirements in § 226.110(b)(1) through
(3), the S&W content must be reported
as zero.
(4) Sufficient back-pressure must be
applied to ensure single-phase flow
through the meter.
(e) The API oil gravity reported for the
run ticket period must be:
(1) Determined from a composite
sample taken in accordance with
§ 226.110(b)(1) through (3); or
(2) Calculated from the average
density as measured by the CMS over
the run ticket period in accordance with

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Subsection 9.2.13.2a of API 21.2
(incorporated by reference, see § 226.0).
Density must be corrected to base
temperature and pressure in accordance
with API 11.1 (incorporated by
reference, see § 226.0).

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§ 226.112 Coriolis meter—operating
requirements.

(a) Minimum electronic pulse level.
The Coriolis meter must register the
volume of oil passing through the meter
as determined by a system that
constantly emits electronic pulse signals
representing the indicated volume
measured. The pulse per unit volume
must be set at a minimum of 8,400
pulses per bbl.
(b) Meter specifications. The Coriolis
meter specifications must identify the
make and model of the meter they apply
to and include the following:
(1) The reference accuracy for both
mass flow rate and density, stated in
percent of reading, percent of full scale,
or units of measure;
(2) The effect of changes in
temperature and pressure on both mass
flow and fluid density readings, and the
effect of flow rate on density readings,
stated in percent of reading, percent of
full scale, or units of measure over a
stated amount of change in temperature,
pressure, or flow rate (e.g., +/¥0.1
percent of reading per 20 psi);
(3) The stability of the zero reading for
volumetric flow rate, stated in percent
of reading, percent of full scale, or units
of measure;
(4) The design limits for flow rate and
pressure; and
(5) The pressure drop through the
meter as a function of flow rate and
fluid viscosity.
(c) Submission of meter
specifications. The lessee must submit
Coriolis meter specifications to the
Superintendent upon request.
(d) Non-resettable totalizer. The
Coriolis meter must have a nonresettable internal totalizer for indicated
volume.
(e) Verification of meter zero-value
using the manufacturer’s specifications.
If the indicated flow rate is within the
manufacturer’s specifications for zero
stability, no adjustments are required. If
the indicated flow rate is outside such
specifications, the meter’s zero reading
must be adjusted. After the meter’s zero
has been adjusted, the meter must be
proven as set forth in § 226.113. A copy
of the zero-value verification procedure
must be provided to the Superintendent
upon request.
(f) Required on-site information.
(1) The Coriolis meter display must be
readable without using data collection
units, laptop computers, or any special

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equipment and must be on-site and
accessible to the Superintendent.
(2) The following values and
corresponding units of measurement
must be displayed for each Coriolis
meter:
(i) The instantaneous display of liquid
density (pounds/bbl, pounds/gal, or
degrees API);
(ii) The instantaneous indicated
volumetric flow rate through the meter
(bbl/day);
(iii) The meter factor;
(iv) The instantaneous pressure (psi);
(v) The instantaneous temperature
(°F);
(vi) The cumulative gross standard
volume through the meter (nonresettable totalizer) (bbl); and
(vii) The previous day’s gross
standard volume through the meter
(bbl).
(3) The following information must be
correct, maintained in legible condition,
and accessible to the Superintendent at
the FMP without the use of data
collection equipment, laptop computers,
or any other special equipment:
(i) The make, model, and size of each
sensor; and
(ii) The make, model, range, and
calibrated span of the pressure and
temperature transducer used to
determine gross standard volume.
(4) The lessee must maintain a log of
all meter factors, zero verifications, and
zero adjustments. For zero adjustments,
the log must include the zero value after
adjustment. The log must be made
available to the Superintendent upon
request.
(g) Audit trail requirements. The
information identified in paragraphs
(g)(1) through (4) of this section must be
recorded and maintained by the lessee
for six years from the date it was
generated unless the Superintendent
provides written notice to the lessee that
an audit or investigation is being
conducted and the records must be
maintained for a longer period. If an
audit or investigation of the records is
being conducted, the lessee must
maintain the records until the
Superintendent issues a written release
of such obligation. Audit trail
requirements must follow Subsection 10
of API 21.2 (incorporated by reference,
see § 226.0). All data and records must
be provided to the Superintendent upon
request.
(1) Quantity transaction record (QTR).
The QTR must comply with the
requirements for run tickets set forth in
§ 226.114.
(2) Configuration log. The
configuration log must comply with the
requirements set forth in Subsection
10.2 of API 21.2 (incorporated by

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reference, see § 226.0), and identify all
constant flow parameters used in
generating the QTR.
(3) Event log. The event log must
comply with the requirements set forth
in Subsection 10.6 of API 21.2
(incorporated by reference, see § 226.0).
(4) Alarm log. The alarm log must
record the type and duration of density
deviations from acceptable parameters
and instances in which the flow rate
exceeded the manufacturer’s maximum
recommended flow rate or was below
the manufacturer’s minimum
recommended flow rate.
(h) Data protection. To ensure that
audit trail requirements under
paragraph (g) of this section are met,
each Coriolis meter must have a backup
power supply installed and maintained
in operable condition or a non-volatile
memory capable of retaining all data in
the unit’s memory.
§ 226.113

Meter proving requirements.

(a) This section specifies the
minimum requirements for conducting
volumetric meter proving for all FMP
meters.
(b) Meter prover. The only acceptable
provers are positive displacement
master meters, Coriolis master meters,
and displacement provers. The lessee
must ensure that the meter prover used
to determine the meter factor has a valid
certificate of calibration, identifying the
prover by serial number, on site and
available for the Superintendent’s
review. The certificate must show that
the prover was calibrated as follows:
(1) Master meters must have a meter
factor within 0.9900 to 1.0100
determined by a minimum of five
consecutive prover runs within 0.0005
(0.05 percent repeatability) as set forth
in Subsection 6.5, Table 2 of API 4.5
(incorporated by reference, see § 226.0).
The master meter must not be
mechanically compensated for oil
gravity or temperature; its readout must
indicate units of volume without
corrections.
(2) The meter factor must be
documented on the calibration
certificate and must be calibrated at
least once every 12 months. New master
meters must be calibrated immediately
and recalibrated three months
thereafter. Master meters that have
undergone mechanical repairs,
alterations, or changes that affect the
calibration must be calibrated
immediately upon the completion of
this work and recalibrated three months
thereafter in accordance with Annex B
of API 4.8 (incorporated by reference,
see § 226.0).
(3) Displacement provers must meet
the requirements set forth in API 4.2

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and be calibrated using the water-draw
method set forth in API 4.9.2 at the
calibration frequencies specified in
Subsection 10.1(b) of API 4.8 (all
incorporated by reference, see § 226.0).
(4) The base prover volume of a
displacement prover must be calculated
in accordance with API 12.2.4
(incorporated by reference, see § 226.0).
(5) Displacement provers must be
sized to obtain a displacer velocity
through the prover that is within the
appropriate range during proving in
accordance with Subsections 4.3.4.1 and
4.3.4.2 of API 4.2 (incorporated by
reference, see § 226.0).
(6) Fluid velocity is calculated using
Subsection 4.3.4.3, Equation 12 of API
4.2 (incorporated by reference, see
§ 226.0).
(c) Meter proving runs. Meter proving
must comply with the applicable
section(s) of API 4.1 (incorporated by
reference, see § 226.0) and the following
requirements:
(1) Meter proving must be performed
under normal operating conditions. The
normal operating conditions will be
established by the flow rate, fluid
pressure, fluid temperature, and fluid
gravity at the time of proving. These
established conditions will be in effect
until the next proving.
(i) The oil flow rate through the LACT
or CMS during proving must be within
10 percent of the normal flow rate;
(ii) The pressure as measured by the
LACT or CMS during proving must be
within 10 percent of the normal flow
rate;
(iii) The temperature as measured by
the LACT or CMS during the proving
must be within 10 °F of the normal
operating temperature;
(iv) The gravity of the oil during
proving must be within 5° API of the
normal oil gravity; and
(v) If the normal flow rate, pressure,
temperature, or oil gravity vary by more
than the limits defined in paragraphs
(c)(1) through (4) of this section, meter
provings must be conducted at the
upper, lower, and midpoint limits of
normal operating conditions.
(2) If each proving run is not of
sufficient volume to generate at least
10,000 pulses from the positive
displacement meter or the Coriolis
meter as specified in Subsection 4.3.2.1
of API 4.2, then pulse interpolation
must be used in accordance with API
4.6 (both incorporated by reference, see
§ 226.0).
(3) Proving runs must be made until
the calculated meter factor or metergenerated pulses from five consecutive
runs match within a tolerance of 0.0005
(0.05 percent) between the highest and
lowest value in accordance with

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Subsection 9 of API 12.2.3 (incorporated
by reference, see § 226.0).
(4) The new meter factor is the
arithmetic average of the metergenerated pulses or intermediate meter
factors calculated from the five
consecutive runs in accordance with
Subsection 9 of API 12.2.3 (incorporated
by reference, see § 226.0).
(5) Meter factor computations must
follow the sequence set forth in
Subsection 12 of API 12.2.3
(incorporated by reference, see § 226.0).
(6) If multiple meter factors are
determined over a range of normal
operating conditions, then:
(i) If all the meter factors determined
over a range of conditions fall within
0.0020 of each other, a single meter
factor may be calculated for that range
as the arithmetic average of all the meter
factors within that range. The full range
of normal operating conditions may be
divided into segments such that all the
meter factors within each segment fall
within a range of 0.0020. In such case,
a single meter factor for each segment
may be calculated as the arithmetic
average of the meter factors within that
segment; or
(ii) The metering system may apply a
dynamic meter factor derived (using
linear interpolation, polynomial fit, etc.)
from the series of meter factors
determined over the range of normal
operating conditions, so long as no two
neighboring meter factors differ by more
than 0.0020.
(7) The meter factor must be at least
0.9900 and no more than 1.0100.
(8) The initial meter factor for a new
or repaired meter must be at least 0.9950
and no more than 1.0050.
(9) For positive displacement meters,
the back-pressure valve may be adjusted
after proving only within the normal
operating fluid flow rate and fluid
pressure as described in paragraph (c)(1)
of this section. If the back-pressure
valve is adjusted after proving, the
lessee must document the as-left fluid
flow rate and fluid pressure on the
proving report.
(10) If a composite meter factor is
calculated, the CPL value must be
calculated from the pressure setting of
the back-pressure valve or the normal
operating pressure at the meter.
Composite meter factors must not be
used with a Coriolis meter.
(d) Minimum proving frequency. The
lessee must prove all FMP meters every
three months (quarterly) or each time
the registered volume flowing through
the meter, as measured on the nonresettable totalizer from the last proving,
increases by 75,000 bbls, whichever
occurs first, but not more frequently
than monthly.

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(e) Events triggering proving. The
lessee must prove all FMP meters before
the removal or sale of production after
any of the following events occur:
(1) Initial meter installation;
(2) Meter zeroing (Coriolis meter);
(3) Modification of mounting
conditions;
(4) A change in fluid temperature that
exceeds the transducer’s calibrated
span;
(5) A change in the flow rate,
pressure, temperature, or gravity that
exceeds the normal operating conditions
as set forth in paragraph (c)(1) of this
section;
(6) The mechanical or electrical
components of the meter are changed,
repaired, or removed;
(7) Internal calibration factors are
changed or reprogrammed; or
(8) The Superintendent requests
proving.
(f) Excessive meter factor deviation. If
the difference between meter factors
established in two successive provings
exceeds +/¥0.0025, the meter must be
immediately removed from service,
checked for damage or wear, adjusted or
repaired, and reproved before being
returned to service.
(1) The arithmetic average of the two
successive meter factors must be
applied to the production measured
through the meter between the date of
the previous meter proving and the date
of the most recent meter proving.
(2) The proving report must clearly
show the most recent meter factor and
describe all subsequent adjustments or
repairs.
(g) Verification of the temperature
transducer. As part of each required
meter proving and upon replacement,
the temperature averager for a LACT
system and temperature transducer used
in conjunction with a CMS must be
verified against a known standard in
accordance with the following
requirements:
(1) The temperature averager or
temperature transducer must be
compared with a test thermometer
traceable to NIST and having a stated
accuracy of +/¥0.25° or better; and
(2) The temperature reading displayed
on the temperature averager or
temperature transducer must be
compared with the reading of the test
thermometer using one of the following
methods:
(i) The test thermometer must be
placed in a test thermometer well
located not more than 12 inches from
the probe of the temperature averager or
temperature transducer; or
(ii) Both the test thermometer and
probe of the temperature averager or
temperature transducer must be placed

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in an insulated water bath. The water
bath temperature must be within 20 °F
of the normal flowing temperature of the
oil.
(3) The displayed reading of
instantaneous temperature from the
temperature averager or temperature
transducer must be compared with the
reading from the test thermometer. If the
readings differ by more than 0.5 °F, the
difference must be noted on the meter
proving report and the temperature
average or temperature transducer must
be:
(i) Adjusted to match the reading of
the test thermometer; or
(ii) Recalibrated, repaired, or
replaced.
(h) Verification of the pressure
transducer (if applicable). As part of
each required meter proving and upon
replacement, the pressure transducer
must be compared with a test pressure
device (dead weight or pressure gauge)
traceable to NIST and having a stated
maximum uncertainty of no more than
one-half of the accuracy required from
the transducer being verified.
(1) The pressure reading displayed on
the pressure transducer must be
compared with the reading of the test
pressure device.
(2) The pressure transducer must be
tested at the following three points:
(i) Zero (atmospheric pressure);
(ii) 100 percent of the calibrated span
of the pressure transducer; and
(iii) A point that represents the
normal flowing pressure through the
Coriolis meter.
(3) If the pressure applied by the test
pressure device and the pressure
displayed on the pressure transducer
vary by more than the required accuracy
of the pressure transducer, the pressure
transducer must be adjusted to read
within the stated accuracy of the test
pressure device.
(i) Density verification (if applicable).
If the API gravity of oil is determined
from the average density measured by
the Coriolis meter (rather than from a
composite sample), then during each
proving of the Coriolis meter, the
instantaneous flowing density
determined by the Coriolis meter must
be verified by comparing it with an
independent density measurement as
set forth in Subsection 9.1.2.1 of API 5.6
(incorporated by reference, see § 226.0).
The difference between the indicated
density determined from the Coriolis
meter and the independently
determined density must be within the
density reference accuracy specification
of the Coriolis meter. Sampling must be
performed in accordance with API 8.1,
API 8.2, or API 8.3, as appropriate, (all
incorporated by reference, see § 226.0).

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(j) Reporting requirements for meter
proving. The lessee must report all
meter proving and volume adjustments
following any LACT system or CMS
malfunction, including excessive meterfactor deviation, to the Superintendent
within 14 calendar days after proving.
Meter proving reports may use the forms
in Subsection 13 of API 12.2.3 or
Appendix C of API 5.6 (see § 226.0 for
availability information) or any other
format containing the same information
as the API forms, provided that the
calculation of meter factors maintains
the proper calculation sequence and
rounding.
(k) Edits and adjustments to reported
volume. (1) If there are measurement
errors stemming from an equipment
malfunction that results in
discrepancies to the calculated volume,
the lessee must estimate the volume
reported during the period in which the
error occurred.
(2) All edits made to the data before
submission of the report to ONRR must
be documented and include verifiable
justifications of the edits made. Such
documentation must be made available
to the Superintendent and ONRR upon
request.
(3) All values on QTRs that have been
changed or edited must be clearly
identified and cross-referenced to the
justification required in paragraph (k)(2)
of this section.
(4) The volumes reported to ONRR
must be corrected beginning with the
date that the inaccuracy occurred. If the
date is unknown, the volumes must be
corrected beginning with the production
month that includes the date that is
halfway between the date of the
previous and most recent verifications.
§ 226.114

Run tickets.

(a) Tank gauging. After oil is
measured by tank gauging, the lessee,
purchaser, or transporter, as
appropriate, must complete a uniquely
numbered run ticket containing the
following information:
(1) The lessee’s name;
(2) The lease number;
(3) The name of the individual that
performed the tank gauging;
(4) The unique tank number and
nominal tank capacity;
(5) The opening and closing dates and
times;
(6) The open and closing gauges and
observed temperatures in °F;
(7) The observed volume for opening
and closing gauge using tank-specific
calibration charts (see § 226.107(f));
(8) The total net standard volume
removed from the tank following API
11.1 (incorporated by reference, see
§ 226.0);

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(9) The observed API oil gravity and
temperature in °F;
(10) The API oil gravity at 60 °F,
following API 11.1 (incorporated by
reference, see § 226.0);
(11) The S&W content percentage; and
(12) The unique numbering of each
seal removed and installed.
(b) LACT system and CMS. Unless the
lessee is using a flow computer, at the
beginning of every month, before
conducting proving operations on a
LACT system, the lessee, purchaser, or
transporter, as appropriate, must
complete a uniquely numbered run
ticket containing the following
information:
(1) The lessee’s name;
(2) The name of the purchaser’s
representative;
(3) The lease number;
(4) The unique meter ID number;
(5) The opening and closing dates and
times;
(6) The opening and closing totalizer
readings of the indicated volume;
(7) The meter factor, indicating
whether it is a composite meter factor;
(8) The total gross standard volume
removed through the LACT system or
CMS;
(9) The API oil gravity;
(i) For API oil gravity determined
from a composite sample, the observed
API oil gravity and temperature must be
indicated in °F and the API oil gravity
must be indicated at 60 °F;
(ii) For API oil gravity determined
from average density (CMS only), the
CMS must determine the average
uncorrected density;
(10) The average temperature for the
measurement period in °F;
(11) The average flowing pressure for
the measurement period in psia;
(12) The S&W content percent; and
(13) The unique number of each seal
removed and installed.
(c) Any accumulators used in the
determination of average pressure,
average temperature, and average
density for the measurement period
must be reset to zero whenever a new
run ticket is opened.
(d) Run tickets must be submitted to
the Superintendent on or before the last
calendar day of the month following the
production month.
§ 226.115 Oil measurement by alternate
methods.

Any method of oil measurement at an
FMP, other than tank gauging, LACT
system, or CMS, requires the
Superintendent’s prior approval.
§ 226.116 Determination of oil volumes by
methods other than measurement.

(a) When production cannot be
measured due to a spill or leak, the

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amount of production will be
determined using the method the
Superintendent requires. This category
of production includes, but is not
limited to, oil classified as slop or waste
oil.
(b) No oil may be classified or
disposed of as waste oil unless the
lessee demonstrates to the
Superintendent’s satisfaction that it is
not economically feasible to put such oil
into marketable condition.
(c) The lessee must not sell or
otherwise dispose of slop oil without
prior approval from the Superintendent.
The sale or disposal of slop oil must be
reported to ONRR in accordance with
the requirements set forth in §§ 226.45
and 226.87.

§ 226.118

Subpart K—Gas Measurement

§ 226.120 Specific performance
requirements.

§ 226.117

General requirements.

(a) Gas must be measured on the lease
or cooperative agreement unit area from
which it is produced unless approval for
off-lease measurement is obtained
pursuant to § 226.101.
(b) All bypasses of meters are
prohibited.
(c) Tampering with any measurement
device, component of a measurement
device, or measurement process is
prohibited. Violation of this prohibition
will result in the assessment of the
maximum penalty available under
§ 226.162(c).

Timeframes for compliance.

(a) All equipment and procedures
used to measure the volume of gas for
royalty purposes after [effective date of
final rule] must comply with the
requirements in this subpart.
(b) All equipment and procedures
used to measure the volume of gas for
royalty purposes in use on [effective
date of final rule] must comply with the
requirements in this subpart by [one
year from effective date of final rule].
Prior to that date, the equipment and
procedures used to measure gas for
royalty purposes must continue to
comply with § 226.39, as it appears in
25 CFR part 226 (April 1, 2017, edition)
and any applicable orders or notices.
§ 226.119

[Reserved]

(a) Flow rate measurement
uncertainty levels. (1) For high-volume
FMPs, the measuring equipment must
achieve an overall flow rate
measurement uncertainty within +/¥ 3
percent.
(2) For very-high-volume FMPs, the
measuring equipment must achieve an
overall flow rate measurement
uncertainty within +/¥ 2 percent.
(3) There are no measurement
uncertainty requirements for low- and
very-low-volume FMPs.
(4) The measurement uncertainty is
based on the values of flowing

UHV

= 0.951

X V95%

parameters (e.g., differential pressure,
static pressure, and flowing temperature
for differential meters or velocity, mass
flow rate, and volumetric flow rate for
linear meters) determined as follows,
listed in order of priority:
(i) The average flowing parameters
listed on the most recent daily QTR, if
available to the Superintendent at the
time of the uncertainty determination;
or
(ii) The average flowing parameters
from the previous day, as required
under § 226.125(d)(4)(i) through (iii) (for
differential meters).
(5) The uncertainty must be
calculated in accordance with Section
12 of API 14.3.1 (incorporated by
reference, see § 226.0) or other methods
the Superintendent approves.
(b) Heating value uncertainty levels.
(1) For high-volume FMPs, the
measuring equipment must achieve an
annual average heating value
uncertainty within +/¥ 3 percent.
(2) For very-high-volume FMPs, the
measuring equipment must achieve an
annual average heating value
uncertainty within +/¥ 2 percent.
(3) There are no heating value
uncertainty requirements for low- and
very-low-volume FMPs.
(4) Unless otherwise approved by the
Superintendent, the average annual
heating value uncertainty must be
determined as follows:

fi

Where:
UHv

= average annual heating value uncertainty

V95 %

= heating value variability

= number of samples taken per year (N = 1, 2, 4, 6, 12, or 26)

(c) Bias. For low-, high-, and veryhigh-volume FMPs, the measuring
equipment used for either the flow rate
or heating value determination must
achieve measurement without
statistically significant bias.
(d) Verifiability. The lessee must not
use measurement equipment for which
the Superintendent cannot
independently verify the accuracy and
validity of any input, factor, or equation

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used by the measuring equipment to
determine quantity, rate, or heating
value. Verifiability includes the ability
to independently recalculate the
volume, rate, and heating value based
on source records and field
observations.
§ 226.121 Flange-tapped orifice plate
(primary devices).

(a) Exemptions from requirements.
The standards and requirements in this

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section apply to all flange-tapped orifice
plates subject to the following
exceptions:
(1) Low-volume FMPs are exempt
from the standards in paragraph (b) of
this section; and
(2) Very-low-volume FMPs are
exempt from the standards and
requirements in paragraphs (b), (c), (f)
and (l) of this section.

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(b) Orifice plate specifications. Orifice
plates must meet the requirements set
forth in Section 4 of API 14.3.2
(incorporated by reference, see § 226.0)
and the:
(1) Beta ratio must be no less than
0.10 and no greater than 0.75; and
(2) Orifice bore diameter must be no
less than 0.45 inches.
(c) Initial orifice plate inspection. If an
FMP measures oil from wells first
coming into production or existing
wells that have been re-fractured, the
lessee must inspect the orifice plate
upon installation and every two weeks
thereafter until the production of
particulate matter from the wells
subsides. If the orifice plate does not
comply with the requirements set forth
in Subsection 4 of API 14.3.2
(incorporated by reference, see § 226.0),
the lessee must replace it. Once the
orifice plate complies with API 14.3.2,
Subsection 4, the lessee must conduct
inspections as set forth in paragraph (d)
of this section.
(d) Routine orifice plate inspection.
(1) Lessees must pull and inspect the
orifice plate as follows:
(i) Once every 12 months for verylow-volume FMPs;
(ii) Once every 6 months for lowvolume FMPs;
(iii) Once every 3 months for highvolume FMPs; and
(iv) Once a month for very-highvolume FMPs.
(2) If a routine inspection reveals that
an orifice plate does not comply with
Section 4 of API 14.3.2 (incorporated by
reference, see § 226.0), the lessee must
replace it.
(e) Documentation of orifice plate
inspections. The lessee must document
each orifice plate inspection and
include that documentation as part of
the verification report submitted in
accordance with §§ 226.123 or 226.126.
The documentation must include:
(1) The lessee’s name;
(2) The lease number;
(3) The well or facility name and
number;
(4) The plate orientation (bevel
upstream or downstream);
(5) The measured orifice bore
diameter;
(6) The plate condition (documenting
compliance with Section 4 of API 14.3.2
(incorporated by reference, see § 226.0);
(7) The presence of oil, grease,
paraffin, scale, or other contaminants on
the plate;
(8) The date and time of inspection;
and
(9) Whether the plate was replaced.
(f) Meter tube specifications.
(1) Meter tubes must meet the
requirements set forth in Subsections

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5.1 through 5.4 of API 14.3.2
(incorporated by reference, see § 226.0).
If flow conditioners are used, they must
be isolating flow conditioners or 19-tube
bundle flow straighteners constructed in
compliance with Subsections 5.5.2
through 5.5.4 of API 14.3.2 and located
in compliance with Subsection 6.3 of
API 14.3.2 (all incorporated by
reference, see § 226.0).
(2) Meter tube lengths and the
location of 19-tube bundle flow
straighteners, if applicable, must
comply with the requirements set forth
in Subsection 6.3 of API 14.3.2
(incorporated by reference, see § 226.0).
If the diameter ratio falls between the
values set forth in Subsection 6.3,
Tables 7, 8a, or 8b of API 14.3.2
(incorporated by reference, see § 226.0),
the length identified for the larger
diameter ratio in the appropriate table is
the minimum requirement for meter
tube length and determines the location
of the end of the 19-tube bundle flow
straightener that is closest to the orifice
plate.
(g) Basic meter tube inspection. The
lessee must perform a basic inspection
of meter tubes that can identify
obstructions, pitting, and buildup of
foreign substances within the following
timeframe:
(1) Frequency. (i) Once every 10 years
for low-volume and very-low-volume
FMPs; and
(ii) Once every 5 years for highvolume and very-high-volume FMPs.
(2) Corrective action. If the basic
meter tube inspection identifies
obstructions, pitting, or buildup of
foreign substances, the lessee must take
one of the following corrective actions
within 30 calendar days:
(i) For all FMPs, if the inspection only
identifies the presence of an obstruction
(such as debris in front of the flow
conditioner), the lessee must remove the
obstruction. If the inspection only
identifies pitting, no corrective action is
required;
(ii) For low- and very-low volume
FMPs, if the inspection identifies the
buildup of foreign substances, the lessee
must clean the meter tube of such
buildup; and
(iii) For high- and very-high-volume
FMPs, if the inspection indicates pitting
or the buildup of foreign substances, the
lessee must clear or repair the meter
tube and conduct a detailed meter tube
inspection under paragraph (h) of this
section; or
(iv) Submit a written request to the
Superintendent for an extension of the
30-day corrective action timeframe,
justifying the need for the extension and
specifying the length of the extension
requested.

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(h) Detailed meter tube inspection. If
a detailed meter tube inspection is
required under paragraph (g)(2)(iii) of
this section, the lessee must measure
and inspect the meter tube to determine
whether it complies with Subsections
5.1 through 5.4 of API 14.3.2
(incorporated by reference, see § 226.0).
If the meter tube does not comply with
the required standards, the lessee must
repair or replace the meter tube and
bring into compliance.
(i) Documentation of meter tube
inspections. The lessee must document
all inspections and make such
documentation available to the
Superintendent upon request. The
documentation must include:
(1) The lessee’s name;
(2) The lease number;
(3) The well or facility name and
number;
(4) The date and time of the
inspection;
(5) The type of equipment used to
perform the inspection;
(6) For a basic meter tube inspection,
a description of findings, including the
location and severity of pitting,
obstructions, and buildup of foreign
substances; and
(7) For detailed meter tube
inspections, information demonstrating
that the meter tube complies with
Subsection 5.1 through 5.4 of API 14.3.2
(incorporated by reference, see § 226.0)
and showing all required measurements.
(j) Advance notice of inspections. The
lessee must notify the Superintendent at
least 72 hours in advance of performing
an inspection under paragraphs (d), (g),
and (h) of this section or submit a
monthly or quarterly schedule of
inspections at least 15 calendar days
prior to the date of the first inspection
scheduled.
(k) Other inspections. The lessee must
conduct additional inspections at the
Superintendent’s request.
(l) Thermometer well. Thermometer
wells used for determining the flowing
temperature of the gas and verification
(test well), must be located in
compliance with Subsection 6.5 of API
14.3.2 (incorporated by reference, see
§ 226.0). Where multiple thermometer
wells have been installed in a meter
tube, the flowing temperature must be
measured from the thermometer well
closest to the primary device.
Thermometer wells used to measure or
verify flowing temperature must contain
a thermally conductive liquid.
(m) Sampling probe. The sampling
probe must be located as specified in
§ 226.130.

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Federal Register / Vol. 88, No. 9 / Friday, January 13, 2023 / Proposed Rules
Mechanical recorder (secondary

(a) Mechanical recorders may be used
as a secondary device on low- and verylow-volume FMPs only.
(b) Chart recorders used in
conjunction with differential-type
meters are approved for low- and verylow-volume FMPs only.
(c) Very-low-volume FMPs are exempt
from the standards and requirements set
forth paragraphs (e), (f), and (g) of this
section.
(d) The connection between the
pressure taps and the mechanical
recorder must meet the following
requirements:
(1) Gauge lines must:
(i) Have a nominal diameter of not
less than 3⁄8 inch;
(ii) Be sloped upwards from the
pressure taps at a minimum pitch of one
inch per foot of length with no visible
sag;
(iii) Have the same internal diameter
along their entire length; and
(iv) Be no longer than 6 feet.
(2) Valves, including the valves in
manifolds, must have a full-opening
internal diameter of not less than 3/8
inch;
(3) There must not be any tees except
for the static-pressure line; and
(4) There must be no connections to
any other devices or more than one
differential-pressure bellows and static
pressure element.
(e) The differential-pressure pen must
record at a minimum reading of 10
percent of the differential-pressure
bellows range for the majority of the
flowing period. This requirement does
not apply to inverted charts.
(f) The flowing temperature of the gas
must be continuously recorded and
used in the volume calculations.
(g) The following information must
always be maintained at the FMP in a
legible condition and accessible to the
Superintendent:
(1) The differential-pressure-bellows
range;
(2) The static-pressure-element range;
(3) The temperature-element range;
(4) The relative density (specific
gravity) of the gas;
(5) The static-pressure units of
measure (psia or psig);
(6) The elevation of, or atmospheric
pressure at, the FMP;
(7) The reference inside diameter of
the meter tube;
(8) The primary device type;
(9) The orifice-bore or other primary
device dimensions necessary for device
verification, Beta or area ratio
determination, and gas volume
calculation;
(10) The location of isolating flow
conditioners, if used;

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(11) The location of the downstream
end of the 19-tube-bundle flow
straighteners, if used;
(12) The date of last primary device
inspection; and
(13) The date of last meter
verification.
(h) The differential pressure, static
pressure, and flowing temperature
elements must be operated between the
lower- and upper-calibrated limits of the
respective elements.
§ 226.123 Verification and calibration of
mechanical recorder.

(a) Verification following installation
or repair.
(1) Prior to performing any
verification of a mechanical recorder,
the lessee must perform a leak test. The
test must be conducted in a manner that
will detect leaks in all connections and
fittings of the secondary device,
including meter manifolds and
verification equipment, isolation valves,
and equalizer valves. If leaks are
detected, the lessee must repair the
leaks before proceeding with
verification.
(2) The lessee must adjust the time lag
between the differential- and staticpressure pens, if necessary, to be 1⁄96 of
the chart rotation period measured at
the chart hub.
(3) The meter’s differential pen arc
must be able to duplicate the test chart’s
time arc over the full range of the test
chart and must be adjusted if necessary.
(4) The as-left values must be verified,
in the following sequence, against a
certified pressure device for the
differential- and static-pressure
elements (if the static-pressure pen has
been offset for atmospheric pressure, the
static-pressure element range is in psia):
(i) Zero (vented to atmosphere);
(ii) 50 percent of element range;
(iii) 100 percent of element range;
(iv) 80 percent of element range;
(v) 20 percent of element range; and
(vi) Zero (vented to atmosphere).
(5) The following as-left temperatures
must be verified by placing the
temperature probe in a water bath with
a certified test thermometer:
(i) Approximately 10 °F below the
lowest expected flowing temperature;
(ii) Approximately 10 °F above the
highest expected flowing temperature;
and
(iii) At the expected average flowing
temperature.
(6) If any of the readings required in
paragraph (a)(4) or (5) of this section
vary from the test device reading by
more than the following tolerance
levels, the lessee must replace and
verify the element for which readings
were outside the applicable tolerances
before returning the meter to service:

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(i) Differential pressure element, +/
¥0.5 percent;
(ii) Static pressure element, +/¥1.0
percent; and
(iii) Temperature element, +/¥2 °F.
(7) If the static-pressure pen is offset
for atmospheric pressure, the
atmospheric pressure must be
calculated in accordance with Appendix
A to this part and the pen must be offset
prior to obtaining the as-left verification
values required in paragraph (a)(4) of
this section.
(b) Routine verification frequency.
The differential pressure bellows, static
pressure element, and temperature
element must be verified according to
the requirements in this section at the
following frequencies:
(1) Once every 6 months for very-lowvolume FMPs; and
(2) Once every 3 months for lowvolume FMPs.
(c) Routine verification procedures.
(1) Prior to performing any verification
required in this subpart, the lessee must
perform a leak test in the manner
specified in paragraph (a)(1) of this
section.
(2) No adjustments to the pens or
linkages may be made until an as-found
verification is obtained. If the static pen
has been offset for atmospheric
pressure, the static pen must not be
reset to zero until the as-found
verification is obtained.
(3) The lessee must obtain and verify
the as-found values of differential and
static pressure against a certified
pressure device at the readings listed in
paragraph (a)(4) of this section, subject
to the following additional
requirements:
(i) If there is sufficient data on-site to
determine the point at which the
differential and static pens normally
operate, the lessee must also obtain an
as-found value at those points;
(ii) If sufficient data is not available
on-site, the lessee must also obtain asfound values at 5 percent and 10
percent of the element range; and
(iii) If the static pressure pen has been
offset for atmospheric pressure, the
static-pressure element range is in units
of psia.
(4) The as-found value for
temperature must be taken using a
certified test thermometer placed in a
test thermometer well if there is flow
through the meter and the meter tube is
equipped with such a well. If there is no
flow through the meter, or if the meter
is not equipped with a test thermometer
well, the temperature probe must be
verified by placing it in an insulated
water bath along with a test
thermometer.

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(5) The element undergoing
verification must be calibrated
according to manufacturer
specifications if any of the as-found
values determined under paragraph
(c)(3) or (4) of this section are not within
the tolerances specified in paragraph
(a)(6) of this section, when compared to
the values applied by the test
equipment.
(6) The lessee must adjust the time lag
between the differential- and staticpressure pens, if necessary, to be 1⁄96 of
the chart rotation period, measured at
the chart hub.
(7) The meter’s differential pen arc
must be able to duplicate the test chart’s
time arc over the full range of the test
chart and must be adjusted if necessary.
(8) If any adjustment to the meter was
made, the lessee must perform an as-left
verification on each element adjusted
using the procedures in paragraphs
(c)(3) and (4) of this section.
(9) If, after an as-left verification, any
of the readings required by paragraphs
(c)(3) and (4) of this section vary by
more than the tolerances set forth in
paragraph (a)(6) of this section when
compared with the test device reading,
the lessee must replace and verify any
element which has readings outside of
the applicable tolerances under this
section before returning the meter to
service.
(10) If the static-pressure pen is offset
for atmospheric pressure:
(i) The atmospheric pressure must be
calculated in accordance with Appendix
A to this part; and
(ii) The pen must be offset prior to
obtaining the as-left verification values
required in paragraph (c)(3) of this
section.
(d) The lessee must retain
documentation of each verification and
make such documentation available to
the Superintendent upon request. The
documentation must include:
(1) The date and time of the
verification;
(2) The date of the prior verification;
(3) Primary device data (reference
inside diameter of the meter tube and
differential-device size and Beta or area
ratio) if the orifice plate is pulled and
inspected;
(4) The type and location of taps
(flange or pipe, upstream or downstream
static tap);
(5) The atmospheric pressure used to
offset the static-pressure pen, if
applicable;
(6) Mechanical recorder data
(differential pressure, static pressure,
and temperature element ranges);

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(7) The normal operating points for
differential pressure, static pressure,
and flowing temperature;
(8) The verification points (as-found
and applied) for each element;
(9) The verification points (as-left and
applied) for each element if a calibration
is performed; and
(10) The name and contact
information for each individual who
performed or witnessed the verification,
if applicable.
(e) Notification of verification. (1) For
verifications performed after installation
or following repair, the lessee must
notify the Superintendent at least 72
hours before conducting the
verification.
(2) For routine verifications, the lessee
must notify the Superintendent at least
72 hours before conducting the
verification or must submit a monthly or
quarterly verification schedule to the
Superintendent in advance.
(f) Correction of reported volumes. If
during the verification, the combined
errors in as-found differential pressure,
static pressure, and flowing temperature
taken at the normal operating points
tested resulted in a flow-rate error
greater than 2 percent and 2 Mcf/day,
the volumes reported to ONRR must be
corrected beginning with the date that
the inaccuracy occurred. If such date is
unknown, the volumes must be
corrected beginning with the production
month that includes the date that is
halfway between the date of the last
verification and the date of the current
verification. Corrected reports must be
submitted to ONRR within 30 calendar
days of discovery of the error in the
reported volumes.
(g) Test equipment certification. Test
equipment used to verify or calibrate
elements at an FMP must be certified at
least once every two years.
Documentation of the recertification
must be available on site during all
verifications and must show the:
(1) Test equipment serial number,
make, and model;
(2) Date that recertification took place;
(3) Test equipment measurement
range; and
(4) Uncertainty determined or verified
as part of the recertification.
§ 226.124

Integration statements.

(a) The lessee must retain an unedited
integration statement and make such
statement available to the
Superintendent upon request. The
integration statement must contain the
following:
(1) The lessee’s name;

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(2) The lease number;
(3) The well or facility name and
number;
(4) The name of the company
performing the integration;
(5) The month and year to which the
integration statement applies;
(6) The reference inside diameter of
the meter tube (inches);
(7) The orifice bore diameter (inches)
or Beta or area ratio and discharge
coefficient, as applicable, and any other
information necessary to calculate flow
rate;
(8) The relative density (specific
gravity);
(9) The CO2 content (mole percent);
(10) The Dinitrogen (N2) content
(mole percent);
(11) The heating value calculated
under § 226.140 (Btu/standard cubic
feet);
(12) The atmospheric pressure or
elevation at the FMP;
(13) The pressure base;
(14) The temperature base;
(15) The static-pressure tap location
(upstream or downstream);
(16) The chart rotation (hours or
days);
(17) The differential-pressure bellows
range (inches of water);
(18) The static-pressure element range
(psi); and
(19) For each chart integrated:
(i) The date and time on, and date and
time off;
(ii) The average differential pressure
(inches of water)
(iii) The average static pressure;
(iv) The static-pressure units of
measure (psia or psig);
(v) The average temperature (°F);
(vi) The integrator counts or
extension;
(vii) The hours of flow; and
(viii) The volume (Mcf).
(b) The volume for each chart
integrated must be determined as
follows:
V = IMV × IV
Where:
V = reported volume, Mcf
IMV = integral multiplier value, as calculated
under this section
IV = the integral value determined by the
integration process (also known as the
‘‘extension,’’ ‘‘integrated extension,’’ and
‘‘integrator count’’)

(1) If the primary device is a flangetapped orifice plate, a single IMV must
be calculated for each chart or chart
interval using the following equation:

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Where:
Cd = discharge coefficient or flow coefficient,
calculated under API 14.3.3 or Section 5
of AGA Report No. 3 (both incorporated
by reference, see § 226.0)
b = beta ratio
Y = gas expansion factor, calculated under
Subsection 5.6 of API 14.3.3, or Section
5 of AGA Report No. 3 (both
incorporated by reference, see § 226.0)
d = orifice diameter, in inches
Zb = supercompressibility at base pressure
and temperature
Gr = relative density (specific gravity)
Zf = supercompressibility at flowing
temperature and pressure
Tf = average flowing temperature, in degrees
Rankine

(2) Variables that are functions of
differential pressure, static pressure, or
flowing temperature (e.g., Cd, Y, Zf)
must use the average values of
differential pressure, static pressure,
and flowing temperature as determined
from, and reported on, the integration
statement for the chart or chart interval
integrated. The flowing temperature
must be the average flowing temperature
reported on the integration statement for
the chart or chart interval being
integrated.
(c) Atmospheric pressure used to
convert static pressure in psig to static
pressure in psia, must be determined in
accordance with Appendix A to this
part.

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§ 226.125 Electronic gas measurement
(secondary and tertiary device).

(a) All electronic gas measurement
systems (EGMs) must meet the
requirements set forth in Section 9 and
Subsection 4.4.5 of API 21.1
(incorporated by reference, see § 226.0).
(b) Very-low-volume FMPs are
exempt from the standards and
requirements set forth in paragraphs (c),
(f), and (g) of this section.
(c) The connection between pressure
taps and the secondary device must
meet the following requirements:
(1) If gauge lines are used, they must:
(i) Have a nominal diameter of not
less than 3⁄8 inch;
(ii) Be sloped upwards from the
pressure taps at a minimum pitch of one
inch per foot of length, with no visible
sag;
(iii) Have the same internal diameter
along their entire length; and
(iv) Be no longer than 6 feet.
(2) Valves, including the valves in
manifolds, must have a full-opening
internal diameter of not less than 3⁄8
inch;

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(3) There must not be any tees, except
for the static pressure line; and
(4) There must be no connections to
any other devices or more than one
differential pressure and static pressure
transducer, except that where the lessee
is employing redundancy verification,
two differential pressure and two static
pressure transducers may be connected.
(d) Each FMP must include a display
that:
(1) Is readable without the need for
data collection units, laptop computers,
a password, or any special equipment;
(2) Is on-site and in a location that is
accessible to the Superintendent;
(3) Includes the units of measure for
each required variable;
(4) Displays the previous day’s
volume and the following variables
consecutively:
(i) Current flowing static pressure
with units (psia or psig);
(ii) Current differential pressure
(inches of water);
(iii) Current flowing temperature (°F);
(iv) Current flow rate (Mcf/day or scf/
day); and
(5) Displays an hourly or daily QTR
no more than 31 calendar days old and
shows the following information:
(i) The previous period (for this
section, previous period means at least
1 day prior, but no longer than 1 month
prior) average differential pressure
(inches of water);
(ii) The average static pressure with
units (psia or psig); and
(iii) The average flowing temperature
(°F).
(e) The lessee must always maintain
the following at the FMP in legible
condition and accessible to the
Superintendent:
(1) The unique meter identification
number;
(2) The relative density (specific
gravity);
(3) The elevation of, or the
atmospheric pressure at, the FMP;
(4) Primary device information, such
as orifice bore diameter (inches) or Beta
or area ratio and discharge coefficient,
as applicable;
(5) The reference inside diameter of
meter tube;
(6) The make, model, and location of
isolating flow conditioners, if used;
(7) The location of the downstream
end of 19-tube-bundle flow
straighteners, if used;
(8) The upper calibrated limit for each
transducer;

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(9) The location of the static-pressure
tap (upstream or downstream);
(10) The date of last orifice plate
inspection;
(11) The date of last meter tube
inspection; and
(12) The date of last secondary device
inspection.
(f) The differential pressure, static
pressure, and flowing temperature
transducers must be operated between
the upper and lower calibrated limits of
the transducer.
(g) The flowing temperature of the gas
must be continuously measured and
used in the flow-rate calculations in
accordance with Section 4 of API 21.1
(incorporated by reference, see § 226.0).
§ 226.126 Verification and calibration of
electronic gas measurement systems.

(a) Transducer verification and
calibration after installation or repair.
(1) Prior to performing any verification
required in this section, the lessee must
perform a leak test in the manner set
forth in § 226.123(a)(1).
(2) The lessee must verify the points
listed in Subsection 7.3.3 of API 21.1
(incorporated by reference, see § 226.0),
by comparing the values from the
certified test device with the values
used by the flow computer to calculate
flow rate. If any of these as-left readings
vary from the test equipment reading by
more than the tolerance calculated using
Subsection 8.2.2.2, Equation 24 of API
21.1 (incorporated by reference, see
§ 226.0), the transducer must be
replaced and tested under this
paragraph.
(3) For absolute static pressure
transducers, the value of atmospheric
pressure used when the transducer is
vented to atmosphere must be
calculated in accordance with Appendix
A to this part, measured by a NISTcertified barometer with a stated
accuracy of +/¥0.06 psi (±4 millibars)
or better, or obtained from an absolute
pressure calibration device.
(4) Prior to putting the meter into
service, the differential pressure
transducer must be tested at zero with
full working pressure applied to both
sides of the transducer. If the absolute
value of the transducer reading is
greater than the reference accuracy of
the transducer, expressed in inches of
water column, the transducer must be
re-zeroed.
(b) Routine verification frequency. (1)
If redundancy verification under

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paragraph (d) of this section is not used,
the differential pressure, static pressure,
and temperature transducers must be
verified in accordance with the
procedures set forth in paragraph (c) of
this section at the following frequencies:
(i) Once every 24 months for lowvolume and very-low-volume FMPs;
(ii) Once every 6 months for highvolume and very-high-volume FMPs.
(2) If redundancy verification under
paragraph (d) of this section is used, the
differential pressure, static pressure,
and temperature transducers must be
verified in accordance with the
procedures set forth therein. In addition,
the temperature transducers must be
verified in accordance with the
procedures set forth in paragraph (c) of
this section at least once a year.
(c) Routine verification procedures.
Verifications must be performed in
accordance with Subsection 8.2 of API
21.1 (incorporated by reference, see
§ 226.0), subject to the following
exceptions, additions, and clarifications:
(1) Prior to performing any
verification required under this section,
the lessee must perform a leak test in
the manner set forth in § 226.123(a)(1).
(2) An as-found verification for
differential pressure, static pressure,
and temperature must be conducted at
the normal operating point of each
transducer.
(i) The normal operating point is the
mean value taken over a previous time
period that is not less than one day, or
greater than one month, prior.
Acceptable mean values include means
that are weighted based on flow time
and flow rate.
(ii) For differential and static pressure
transducers, the pressure applied to the
transducer must be within five
percentage points of the normal
operating point.
(iii) For the temperature transducer,
the water bath or test thermometer well
must be within 20 °F of the normal
operating point for temperature.
(3) If a transducer is calibrated, the asleft verification must include the normal
operating point of that transducer, as
defined in paragraph (c)(2) of this
section.
(4) The as-found values for
differential pressure obtained with the
low side vented to atmospheric pressure
must be corrected to working pressure
values using Annex H, Equation H.1 of
API 21.1 (incorporated by reference, see
§ 226.0).
(5) The verification tolerance for
differential and static pressure is
calculated using Subsection 8.2.2.2,
Equation 24 of API 21.1 (incorporated
by reference, see § 226.0). The
verification tolerance for temperature is

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equivalent to the uncertainty of the
temperature transmitter or 0.5 °F,
whichever is greater.
(6) All required verification points
must be within the applicable
verification tolerance before returning
the meter to service.
(7) Prior to putting a meter into
service, the differential pressure
transducer must be tested at zero with
full working pressure applied to both
sides of the transducer. If the absolute
value of the transducer reading is
greater than the reference accuracy of
the transducer, as expressed in inches of
water column, the transducer must be
re-zeroed.
(d) Redundancy verification
procedures. Redundancy verification
must be performed as required under
Subsection 8.2 of API 21.1 (incorporated
by reference, see § 226.0), subject to the
following exceptions, additions, and
clarifications:
(1) The lessee must identify which set
of transducers is used for reporting on
the Form ONRR–4054 (the primary
transducers) and which set of
transducers is used as a check (the
check set of transducers);
(2) For every calendar month, the
lessee must compare the flow-time
linear averages of differential pressure,
static pressure, and temperature
readings from the primary transducers
with those from the check transducers;
and
(3) If for any transducer the difference
between the averages exceeds the
tolerance defined by the equation
below, the lessee must verify both the
primary and check transducer under
paragraph (c) of this section within the
first five days of the month following
the month in which the redundancy
verification was performed. For
example, if the redundancy verification
for March reveals that the difference in
flow-time linear averages of differential
pressure exceeded the verification
tolerance, both the primary and check
differential-pressure transducers must
be verified under paragraph (c) of this
section by April 5th.

Tolerance

~
rte

✓ rip T

Where:
AP is the reference accuracy of the primary
transducer and
AC is the reference accuracy of the check
transducer

(e) Documentation of verifications.
The lessee must retain documentation of
each verification and make such
documentation available to the
Superintendent upon request. The

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documentation must include the
following:
(1) The lessee’s name;
(2) The lease number;
(3) The well or facility name and
number;
(4) The date and time of verification,
and date of the last verification;
(5) Primary device information
(reference inside diameter of the meter
tube and orifice plate or differential
device size, and Beta or area ratio);
(6) The type and location of taps
(flange or pipe, upstream or
downstream, static tap);
(7) The upper calibrated limit for each
transducer;
(8) The normal operating points for
differential pressure, static pressure,
and flowing temperature;
(9) The atmospheric pressure;
(10) The verification points (as-found
and applied) for each transducer;
(11) The verification points (as-left
and applied) for each transducer if
calibration was performed;
(12) The differential device date of
inspection and condition (e.g., clean,
sharp edge, or surface condition);
(13) The verification equipment make,
model, range, accuracy, and date of last
certification; and
(14) The name(s) and contact
information for individuals that
performed or witnessed the verification,
if applicable.
(f) Notification of verification. (1) The
lessee must notify the Superintendent at
least 72 hours before conducting
verifications after installation or
following repair.
(2) The lessee must notify the
Superintendent at least 72 hours before
conducting routine verifications or
provide the Superintendent with a
monthly or quarterly verification
schedule in advance.
(g) Correction of reported volumes. If
during the verification, the combined
errors in as-found differential pressure,
static pressure, and flowing temperature
taken at the normal operating points
tested result in a flow-rate error greater
than 2 percent and 2 Mcf/day, the
volumes reported to ONRR must be
corrected beginning with the date that
the inaccuracy occurred. If that date is
unknown, the volumes must be
corrected beginning with the production
month that includes the date that is
halfway between the date of the last
verification and the date of the present
verification. Corrected reports must be
submitted to ONRR within 30 calendar
days of discovery of the error in the
reported volumes.
(h) Certification of test equipment.
Test equipment used to verify or
calibrate transducers at an FMP must be

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Federal Register / Vol. 88, No. 9 / Friday, January 13, 2023 / Proposed Rules

certified at least once every two years.
Documentation of the certification must
be on-site and available to the
Superintendent during all verifications.
Such documentation must show the:
(1) Test equipment serial number,
make and model;
(2) Date that recertification took place;
(3) Test equipment measurement
range; and
(4) Uncertainty determined or verified
as part of the recertification.
(i) Accuracy standards for test
equipment. Test equipment used to
verify or calibrate transducers at an FMP
must meet the following accuracy
standards:
(1) The accuracy of the test
equipment, stated in actual units of
measure, must be no greater than 0.5
times the reference accuracy of the
transducer being verified, also stated in
actual units of measure; or
(2) The equipment must have a stated
accuracy of 0.10 percent of the upper
calibrated limit of the transducer being
verified.
§ 226.127 Flow rate, volume, and average
value calculation.

(a) For flange-tapped orifice plates,
the flow rate must be calculated under:
(1) Sections 4 and 5 of API 14.3.3
(incorporated by reference, see § 226.0);
and
(2) AGA Report No. 8 (incorporated
by reference, see § 226.0), for
supercompressibility.
(b) Atmospheric pressure used to
convert static pressure in psig to static
pressure in psia must be determined
using Appendix A of this part.
(c) Hourly and daily gas volumes,
average values of the live input
variables, flow time, and integral value
or average extension required under
§ 226.128 must be determined using
Section 4 and Annex B of API 21.1
(incorporated by reference, see § 226.0).

lotter on DSK11XQN23PROD with PROPOSALS3

§ 226.128

Logs and records.

(a) The lessee must retain, and make
available to the Superintendent upon
request, the original, unaltered,
unprocessed, and unedited daily and
hourly QTRs, which must contain the
information identified in Subsection 5.2
of API 21.1 (incorporated by reference,
see § 226.0), subject to the following
additions and clarifications:
(1) The QTRs must contain the
lessee’s name, lease number, and well or
facility name and number;
(2) The volume, flow time, and
integral value or average extension must
be reported to at least five significant
digits;
(3) The average differential pressure,
static pressure, and temperature, as

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calculated in § 226.127(c), must be
reported to at least three significant
digits; and
(4) The QTRs must include a
statement indicating whether the lessee
submitted the integral value or average
extension.
(b) The lessee must retain, and make
available to the Superintendent upon
request, the original unaltered,
unprocessed, and unedited
configuration log, which must contain
the information specified in Subsection
5.4 (including the flow-computer
snapshot report in Subsection 5.4.2) of
API 21.1 and Annex G of API 21.1 (both
incorporated by reference, see § 226.0),
as well as the following:
(1) The lessee’s name;
(2) The lease number;
(3) The well or facility name and
number;
(4) For very-low-volume FMPs only,
the fixed temperature, if not
continuously measured (°F); and
(5) The static-pressure tap location
(upstream or downstream).
(c) The lessee must retain, and make
available to the Superintendent upon
request, the original, unaltered,
unprocessed, and unedited event log.
The event log must comply with the
requirements set forth in Subsection 5.5
of API 21.1 (incorporated by reference,
see § 226.0), and must have sufficient
capacity to be retrieved and stored at
intervals that will maintain a
continuous record of events for the
required six-year retention period or the
life of the FMP, whichever is shorter.
(d) The lessee must retain, and make
available to the Superintendent upon
request, an alarm log. The alarm log
must comply with the requirements set
forth in Subsection 5.6 of API 21.1
(incorporated by reference, see § 226.0).
§ 226.129

Gas sampling and analysis.

(a) Samples must be taken using one
of the following methods:
(1) Spot sampling under §§ 226.131,
226.132, and 226.133;
(2) Flow-proportional composite
sampling under § 226.134; or
(3) On-line gas chromatograph under
§ 226.135.
(b) At all times during the sampling
process, the minimum temperature of
all gas sampling components must be
the lesser of:
(1) The flowing temperature of the gas
measured at the time of sampling; or
(2) 30 °F above the calculated
hydrocarbon dew point of the gas.
§ 226.130

Sampling probe and tubing.

(a) Exemptions. Very-low-volume
FMPs are exempt from the standards
and requirements set forth in this
section.

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(b) Location of sample probe. (1) The
sampling probe must be located as
specified in Subsection 6.4.2 of API 14.1
(incorporated by reference, see § 226.0)
and must be the first obstruction
downstream of the primary device.
(2) The sample probe must be exposed
to the same ambient temperature as the
primary device. The lessee may
accomplish this by physically locating
the sample probe in the same ambient
temperature conditions as the primary
device (such as in a heated meter house)
or by installing insulation and/or heat
tracing along the entire meter run.
(c) Sample probe design and type. (1)
Sample probes must be made from
stainless steel.
(2) If a regulating type of sample
probe is used, the pressure-regulating
mechanism must be inside the pipe or
maintained at a temperature of at least
30 °F above the hydrocarbon dew point
of the gas.
(3) The sample probe length must be
the shorter of the:
(i) Length necessary to place the
collection end of the probe in the center
one-third of the pipe cross-section; or
(ii) Recommended probe length in
Subsection 6.4, Table 1 of API 14.1
(incorporated by reference, see § 226.0).
(4) The use of membranes, screens, or
filters at any point in the sample probe
is prohibited.
(d) Sample tubing type. Sample
tubing connecting the sample probe to
the sample container or analyzer must
be made of stainless steel or nylon 11.
§ 226.131 Spot samples—general
requirements.

(a) Sampling while flowing. The FMP
must be flowing when a gas sample is
taken. If an FMP is in non-flowing status
on the date that a sample is due under
§ 226.133, no sample is required. The
lessee must take a sample within 15
calendar days of the date that flow to
the FMP is reinitiated. For purposes of
this section, non-flowing status means
there has been no flow through the FMP
for at least 30 consecutive days. Nonflowing status does not apply to meters
at FMPs that flow intermittently on a
daily or weekly basis.
(b) Notice of spot samples. The lessee
must provide the Superintendent with
at least 72 hours’ advance notice before
obtaining a spot sample or submit a
monthly or quarterly sampling schedule
to the Superintendent in advance of
taking samples.
(c) Sample cylinder requirements.
Sample cylinders must:
(1) Comply with the requirements set
forth in Subsection 9.1 of API 14.1
(incorporated by reference, see § 226.0);
(2) Have a minimum capacity of 300
cubic centimeters; and

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(3) Be cleaned prior to sampling in
accordance with Appendix A of GPA
2166–17 (incorporated by reference, see
§ 226.0) or an equivalent method. The
lessee must maintain documentation of
cleaning, have the documentation onsite during sampling, and provide the
documentation to the Superintendent
upon request.
(d) Spot sampling using portable gas
chromatographs. (1) If used, sampling
separators must be:
(i) Constructed of stainless steel;
(ii) Cleaned prior to sampling in
accordance with Appendix A of GPA
2166–17 (incorporated by reference, see
§ 226.0) or an equivalent method. The
lessee must maintain documentation of
cleaning, have the documentation onsite during sampling, and provide the
documentation to the Superintendent
upon request; and
(iii) Operated under Appendix B.3 of
GPA 2166–17 (incorporated by
reference, see § 226.0).
(2) The sample port and inlet to the
sample line must be purged using the
gas being sampled before completing the
connection between them.
(3) The portable gas chromatograph
must be operated, verified, and
calibrated as set forth in § 226.136 and
documentation of such verification and
calibration must be available for
inspection by the Superintendent at the
time of sampling.
(4) The documentation of verification
or calibration required in § 226.136(e)
must be available for the
Superintendent’s inspection at the time
of sampling.
(5) The minimum number of samples
and analyses is as follows:
(i) For low-volume and very-lowvolume FMPs, at least three samples
must be taken and analyzed;
(ii) For high-volume FMPs, samples
must be taken and analyzed until the
difference between the maximum and
minimum heating values calculated
based on three consecutive analyses is
less than or equal to 16 Btu/scf; and
(iii) For very-high-volume FMPs,
samples must be taken and analyzed
until the difference between the
maximum and minimum heating values
calculated based on three consecutive
analyses is less than or equal to 8 Btu/
scf.
(6) Unless the Superintendent
approves an alternative method of
calculation, the heating value and
relative density used for reporting to
ONRR must be either the mean or
median heating value and relative
density calculated from the three
analyses required in paragraph (d)(5) of
this section.

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§ 226.132 Spot samples—allowable
methods.

(a) Spot samples must be obtained
using one of the following methods:
(1) Purging—fill and empty method.
Samples taken using this method must
comply with the requirements set forth
in Section 9.1 of GPA 2166–17
(incorporated by reference, see § 226.0);
(2) Helium ‘‘pop’’ method. Samples
taken using this method must comply
with the requirements set forth in
Section 9.5 of GPA 2166–17
(incorporated by reference, see § 226.0).
The lessee must maintain
documentation demonstrating that the
cylinder was evacuated and pre-charged
before sampling and make such
documentation available to the
Superintendent upon request;
(3) Floating piston cylinder method.
Samples taken using this method must
comply with the requirements set forth
in Sections 9.7.1 and 9.7.3 of GPA
2166–17 (incorporated by reference, see
§ 226.0). The lessee must maintain
documentation of the seal material and
type of lubricant used and make such
documentation available to the
Superintendent upon request;
(4) Portable gas chromatograph.
Samples taken using this method must
comply with § 226.136; or
(5) Alternative methods. Other
methods the Superintendent approves.
(b) If the lessee uses the sampling
methods in paragraph (a)(1) or (2) of this
section and the flowing pressure at the
sample port is less than or equal to 15
psig, the lessee may also employ a
vacuum gathering system. Samples
taken using a vacuum-gathering system
must comply with the requirements set
forth in Subsection 11.10 of API 14.1
(incorporated by reference, see § 226.0)
and the samples must be obtained from
the discharge of the vacuum pump.
§ 226.133

Spot samples—frequency.

(a) Spot samples must be taken and
analyzed at the following frequencies:
(1) Once every 12 months for verylow-volume FMPs;
(2) Once every 6 months for lowvolume FMPs;
(3) One every 3 months for highvolume FMPs; and
(4) Once a month for very-highvolume FMPs.
(b) The Superintendent may change
the required sampling frequency for
high- and very-high-volume FMPs if a
determination is made that the
frequency under paragraph (a) of this
section does not achieve the heating
value uncertainty levels required in
§ 226.120(b).
(1) The Superintendent may change
the sampling frequency no sooner than

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2489

[two years from effective date of final
rule].
(2) The new sampling frequency will
remain in effect until the heating value
variability justifies a different
frequency.
(3) The Superintendent may not
change the sampling frequency to more
than once every two weeks or less than
once every six months.
(c) The time between any two spot
samples must not exceed:
(1) 18 calendar days, if the required
sampling frequency is every two weeks;
(2) 45 calendar days, if the required
sampling frequency is once a month;
(3) 105 calendar days, if the required
sampling frequency is once every 3
months;
(4) 195 calendar days, if the required
sampling frequency is once every 6
months; and
(5) 380 calendar days, if the required
sampling frequency is once every 12
months.
§ 226.134

Composite sampling methods.

(a) Composite samplers must be flowproportional.
(b) Samples must be collected using a
positive-displacement pump.
(c) Sample cylinders must be sized to
ensure the cylinder capacity is not
exceeded within the normal collection
frequency.
§ 226.135

On-line gas chromatographs.

(a) On-line gas chromatographs must
be installed, operated, and maintained
in accordance with, Appendix D of GPA
2166–17 (incorporated by reference, see
§ 226.0), and the manufacturer’s
specifications, instructions, and
recommendations.
(b) On-line gas chromatographs must
comply with the verification and
calibration requirements set forth in
§ 226.136. The lessee must maintain
documentation of verifications and
calibrations and make such
documentation available to the
Superintendent upon request.
§ 226.136

Gas chromatographs.

(a) All gas chromatographs must be
installed, operated, and calibrated in
accordance with GPA 2261–20
(incorporated by reference, see § 226.0).
(b) Gas chromatographs must be
verified under the requirements in
paragraph (c) of this section not less
than once every seven calendar days.
(c) Verifications must be performed in
accordance with 2261–20 (incorporated
by reference, see § 226.0), with the
following additions and clarifications:
(1) All gases used for verification and
calibration must meet the standards of
Sections 3 and 4 of GPA 2198–16
(incorporated by reference, see § 226.0);

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Federal Register / Vol. 88, No. 9 / Friday, January 13, 2023 / Proposed Rules

(2) All new gases used for verification
and calibration must be authenticated
prior to verification or calibration in
accordance with Section 6 of GPA
2198–16 (incorporated by reference, see
§ 226.0);
(3) The gas used to calibrate a gas
chromatograph must be maintained in
accordance with Section 5 of GPA
2198–16 (incorporated by reference, see
§ 226.0);
(4) If the composition of the gas used
for verification as determined by the gas
chromatograph varies from the certified
composition of the gas used for
verification by more than the
reproducibility values in Section 10 of
GPA 2261–20, the gas chromatograph
must be calibrated in accordance with
Section 6 of GPA 2261–20 (both
incorporated by reference, see § 226.0);
and
(5) If the gas chromatograph is
calibrated, it must be re-verified under
paragraph (c)(4) of this section.
(d) Samples must be analyzed until
the un-normalized sum of the mole
percent of all gases analyzed is between
97 and 103 percent.
(e) The lessee must retain
documentation of the verifications and
make such documentation available to
the Superintendent upon request. The
documentation must include:
(1) The components analyzed;
(2) The response factor for each
component;
(3) The peak area for each component;
(4) The mole percent of each
component as determined by the gas
chromatograph;
(5) The mole percent of each
component in the gas used for
verification;
(6) The difference between the mole
percentages determined in paragraphs
(e)(4) and (5) of this section, expressed
in relative percent;
(7) Evidence that the gas used for
verification and calibration:
(i) Meets the requirements of
paragraph (c)(2) of this section,
including a unique identification
number of the calibration gas used, the
name of the supplier of the calibration
gas, and the certified list of the mole
percent of each component in the
calibration gas;
(ii) Was authenticated under
paragraph (c)(3) of this section prior to
verification or calibration, including the
fidelity plots; and
(iii) Was maintained under paragraph
(c)(4) of this section, including the
fidelity plot made as part of the
calibration run;
(8) The chromatograms generated
during the verification process;
(9) The time and date the verification
was performed; and

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(10) The name and affiliation of the
person performing the verification.
§ 226.137

Components to analyze.

(a) Low- and very-low-volume FMPs
are exempt from the standards and
requirements set forth in paragraphs (c),
(d), and (e) of this section.
(b) Gas must be analyzed for the
following components:
(1) Methane;
(2) Ethane;
(3) Propane;
(4) Isobutane;
(5) Normal Butane;
(6) Pentanes;
(7) Hexanes + (C6+);
(8) Carbon dioxide; and
(9) Nitrogen.
(c) When the concentration of C6+
exceeds 0.5 mole percent, hexanes,
heptanes, octanes, and Nonanes-plus
(C9+) must also be analyzed.
(d) In lieu of testing each sample for
the components required under
paragraph (c) of this section, the lessee
may periodically test for these
components and adjust the assumed C6+
composition to remove bias in the
heating value. The adjusted C6+
composition must be applied to the
mole percent of C6+ analyses until the
next analysis is done under paragraph
(c) of this section.
(e) The minimum analysis frequency
for components listed in paragraph (c)
of this section is:
(1) Once every 12 months, for highvolume FMPs; and
(2) Once every 6 months, for veryhigh-volume FMPs.
§ 226.138 Gas analysis report
requirements.

(a) The gas analysis report must
contain the following information:
(1) The lessee’s name;
(2) The lease number;
(3) The well or facility name and
number;
(4) The date and time the sample or
spot samples were taken or, for
composite samples, the date the
cylinder was installed and date it was
removed;
(5) The date and time of the analysis;
(6) For spot samples, the effective
date, if other than the date of sampling;
(7) For composite samples, the
effective start and end dates;
(8) The name of the laboratory where
the analysis was performed, if
applicable;
(9) The device used for analysis (i.e.,
gas chromatograph, calorimeter, or mass
spectrometer);
(10) The make and model of the
analyzer;
(11) The date of the last verification
or calibration of the analyzer;

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(12) The flowing temperature at the
time of sampling;
(13) The flowing pressure at the time
of sampling, including units of measure
(psia or psig);
(14) The flow rate at the time of
sampling;
(15) The ambient air temperature at
the time of sampling;
(16) Whether or not heat trace or any
other method of heating was used;
(17) The type of sample (i.e., spotcylinder, spot-portable gas
chromatograph, composite);
(18) The sampling method if spotcylinder (e.g., fill and empty, helium
pop);
(19) A list of the components tested;
(20) The total un-normalized mole
percent of the components tested;
(21) The normalized mole percent of
each component tested, including a
summation of those mole percentages;
(22) The ideal heating value (Btu/scf);
(23) The real heating value (Btu/scf),
dry basis;
(24) The hexanes-plus heating value
(Btu/scf), if applicable;
(25) The pressure base and
temperature base;
(26) The relative density; and
(27) The name of company obtaining
the gas sample.
(b) Components that are listed on the
analysis report but are not tested must
be annotated as such.
(c) The heating value and relative
density must be calculated using API
14.5 (incorporated by reference, see
§ 226.0).
(d) The base supercompressibility
must be calculated using AGA Report
No. 8 (incorporated by reference, see
§ 226.0).
(e) The lessee must submit all gas
analysis reports to the Superintendent
within 14 calendar days after the due
date for the sample as specified in
§ 226.133.
§ 226.139 Effective date of a spot or
composite gas sample.

(a) Unless otherwise specified in the
gas analysis report, the effective date of
a spot sample is the date on which the
sample was taken. The effective date of
a spot sample may be no later than the
first day of the production month
following the lessee’s receipt of the
laboratory analysis of the sample.
(b) Unless otherwise specified in the
gas analysis report, the effective date of
a composite sample is the first day of
the month in which the sample was
removed.
§ 226.140
volume.

Calculation of heating value and

(a) Heating value of sample. The
heating value of gas sampled must be
calculated as follows:

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Federal Register / Vol. 88, No. 9 / Friday, January 13, 2023 / Proposed Rules

HV

= L(HVi

xVi)

i=l
i=n

LVi
i=l
Where:
HV = the average heating value for the lease
for the reporting month, in Btu/scf
HVi = the heating value for FMPi during the
reporting month (see § 226.140(a)(2), if
an FMP has multiple heating values
during the reporting month), in Btu/scf
Vi = the volume measured by FMPi during
the reporting month, in Btu/scf
i = each FMP for the lease
n = the number of FMPs for the lease

(2) If the effective date of a heating
value for an FMP is other than the first
day of the reporting month, the average
heating value of the FMP must be the
volume-weighted average of heating
values, determined as follows:
j=m

HVi

=

L (HVi,j xVi,j)
j=l
j=m

I ViJ

lotter on DSK11XQN23PROD with PROPOSALS3

j=l

Where:
HVi = the heating value for FMPi, in Btu/scf
HVi,j = the heating value for FMPi, for partial
month j, in Btu/scf
Vi,j = the volume measured by FMPi, for
partial month j, in Btu/scf
i = represents each FMP for the lease
j = represents a partial month for which
heating value HVi,j is effective
m = the number of different heating values
in a reporting month for an FMP

(c) Calculation of volume. The volume
must be determined under § 226.124(b)
and (c) (mechanical recorders) or
§ 226.125(c) (electronic gas
measurement systems).

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Reporting of heating value and

(a) Reported gross and real heating
values. The gross heating value and real
heating value, or average gross heating
value and average real heating value, as
applicable, derived from all samples
and analyses must be reported to ONRR
in units of Btu/scf under the following
conditions:
(1) Containing no water vapor (‘‘dry’’),
unless the water vapor content has been
determined through actual on-site
measurement, included in heating value
calculations, and reported on the gas
analysis report. The heating value may
not be reported based on assumed water
vapor content. Acceptable methods of
measuring water vapor are chilled
mirror and other methods the
Superintendent approves;
(2) Adjusted to a pressure of 14.73
psia and a temperature of 60 °F; and
(3) For samples analyzed under
§ 226.137(a), notwithstanding any
provision of a contract between the
lessee and purchaser or transporter, the
composition of hexanes + must have a
heating value of not less than:
(i) 5,129 Btu/scf (equivalent heating
value of 60 percent hexanes, 30 percent
heptanes, and 10 percent octanes); or
(ii) The heating value of the C9+
composition determined under
§ 226.137(c).
(b) Reported volume. The volume for
royalty purposes must be reported to
ONRR in units Mcf, as follows:
(1) The volume must not be adjusted
for water-vapor content or any other
factors that are not included in
calculations required in § 226.124(b)
and (c) or § 226.127; and
(2) The volume must match the
monthly volume(s) shown in the
unedited QTR(s) or integration
statement(s) unless edits to the data are
documented under paragraph (c) of this
section.
(c) Edits and adjustments to reported
heating value or volume. (1) If there are
measurement errors stemming from an
equipment malfunction that results in
discrepancies in the calculated heating
value or volume of the gas, the heating
value or volume reported during the
period in which the error persisted must
be estimated.
(2) All edits made to the data before
the report is submitted to ONRR must be
documented and include verifiable
justifications for the edits made. Such
documentation must be available to the
Superintendent and ONRR upon
request.
(3) All values on daily and hourly
QTRs that have been changed or edited
must be clearly identified and cross

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referenced to the justification required
in paragraph (c)(2) of this section.
(4) The volumes reported to ONRR
must be corrected beginning with the
date that the inaccuracy occurred. If the
date is unknown, the volumes must be
corrected beginning with the production
month that includes the date that is
halfway between the date of the
previous verification and the date of the
most recent verification. Corrected
reports must be submitted to ONRR
within 30 calendar days of discovery of
the error in the reported volumes.
Subpart L—Tribal and Royalty-Free
Use of Production
Tribal Use of Gas Production
§ 226.142 Use of gas by the Osage Nation
and Tribe members.

(a) Gas from any well must be
furnished to any Tribally-owned
building or enterprise at a rate not to
exceed the rate set forth in § 226.40,
subject to the Superintendent’s
determination that the lease is
producing gas in excess of the lessee’s
requirements for operations and that no
waste will result. The Osage Nation
must furnish all labor and materials
necessary for connection with the
lessee’s gas system. The Osage Nation
uses gas under this section at its own
risk.
(b) Any member of the Osage Nation
who resides in Osage County outside of
an incorporated city is entitled to use a
maximum of 400,000 cubic feet of gas
per calendar year for their primary
residence at a rate not to exceed the rate
set forth in § 226.40, subject to the
Superintendent’s determination that the
lease is producing gas in excess of the
lessee’s requirements and that no waste
will result. The Tribe member must
furnish all labor and materials necessary
for connection with the lessee’s gas
system and must maintain their own
lines. Tribal members use gas under this
section at their own risk.
(c) The lessee may not stop furnishing
gas pursuant to paragraphs (a) and (b) of
this section without Superintendent’s
approval. To obtain such approval, the
lessee must submit a request to the
Superintendent, in writing, providing
justification for terminating the Tribe
member’s use of gas from the lessee’s
well.
§ 226.143 Royalty on gas furnished for
Tribal use.

The lessee must pay royalty on all gas
furnished to Tribally owned buildings
and enterprises and Tribe members in
accordance with §§ 226.39 and 226.40.

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13JAP3

EP13JA23.012

i=n

§ 226.141
volume.

EP13JA23.011

(1) Gross heating value is defined in
Subsection 3.7 of API 14.5, and must be
calculated using Subsection 7.1 of API
14.5 (incorporated by reference, see
§ 226.0); and
(2) Real heating value must be
calculated by dividing the gross heating
value of the gas calculated under
paragraph (a)(1) of this section by the
compressibility factor of the gas at 14.73
psia and 60 °F.
(b) Average heating value. (1) If a
lease has more than one FMP, the
average heating value for the lease for a
reporting month must be the volumeweighted average of heating values,
calculated as follows:

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Royalty-Free Use of Lease Production
§ 226.144
is due.

Production on which no royalty

To the extent specified in §§ 226.145
and 226.146, royalty is not due on:
(a) Oil and gas produced from a lease
and used for operations or production
purposes (including placing the oil and
gas in marketable condition) on the
same lease without being removed
therefrom; or
(b) Oil and gas produced from a unit
and used for operations or production
purposes (including placing the oil and
gas in marketable condition) on the
same unit, under the same cooperative
agreement, without being removed
therefrom.

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§ 226.145 Uses of production on a lease or
unit that do not require the
Superintendent’s prior approval of royaltyfree treatment.

(a) The following uses of oil and gas
for operations or production purposes
do not require the Superintendent’s
prior approval to be royalty-free:
(1) Use of fuel to generate power or
operate combined heat and power;
(2) Use of fuel to power equipment,
including artificial lift equipment,
equipment used for enhanced recovery,
drilling rigs, and completion and
workover equipment;
(3) Use of gas to actuate pneumatic
controllers or operate pneumatic pumps
at production facilities;
(4) Use of fuel to heat, separate, or
dehydrate production;
(5) Use of gas as a pilot fuel or as
assist gas for a flare, combustor, thermal
oxidizer, or other control device;
(6) Use of fuel to compress or treat gas
to place it in marketable condition;
(7) Use of oil to clean the well and
improve production (e.g., hot oil
treatments). The lessee must document
removal of the oil from the tank or
pipeline in accordance with § 226.99;
(8) Use of oil as a circulating medium
in drilling operations if such use is part
of an approved drilling plan;
(9) Injection of gas for the purpose of
conserving gas or increasing the
recovery of oil or gas if the
Superintendent ordered or approved
such injection; and
(10) Injection of gas that is cycled in
a contained gas-lift system.
(b) The volumes of oil and gas treated
as royalty-free under this section must
not exceed the amount of fuel necessary
to perform the operation using
equipment of appropriate capacity.
§ 226.146 Uses of production on a lease or
unit that require the Superintendent’s prior
approval of royalty-free treatment.

(a) The following uses of oil and gas
for operations or production purposes

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require the Superintendent’s prior
approval of royalty-free treatment to
ensure that accountability is
maintained:
(1) Use of oil or gas the lessee removes
from the pipeline at a location
downstream of the FMP;
(2) Use of gas that has been removed
from the lease or unit for treatment or
processing because the physical
characteristics of the gas require it to be
treated or processed prior to use, where
the gas is returned to, and used on, the
same lease or unit from which it was
produced; and
(3) Any other uses of produced oil
and gas for operations and production
purposes that are not set forth in
§ 226.145.
(b) The lessee must submit a request
to conduct activities under paragraph (a)
of this section to the Superintendent, in
writing, to obtain approval of royaltyfree treatment for the volumes of oil and
gas used. Such request must include the
information required by § 226.151. If the
Superintendent approves a request for
royalty-free treatment under this
section, the effective date of such
approval will be the date the
Superintendent received the lessee’s
request. If the Superintendent denies a
request for royalty-free treatment under
this section, the lessee must pay
royalties on all volumes utilized to
conduct activities under paragraph (a) of
this section.
(c) The lessee must measure the
volumes of oil and gas used to conduct
activities under paragraph (a)(1) of this
section in accordance with subparts J
and K, as applicable. The lessee must
measure the volume of gas returned to
the lease or unit following removal
under paragraph (a)(2) of this section in
accordance with subpart K.
§ 226.147 Uses of production moved off
the lease or unit that do not require the
Superintendent’s prior approval of royaltyfree treatment.

Oil and gas moved off the lease or
unit may be treated as royalty-free
without the Superintendent’s prior
approval if the use meets the criteria in
§ 226.145 and:
(a) The oil or gas is transported from
one area of the lease or unit to be used
at another area of the same lease or unit
and no oil or gas is added to, or
removed from, the pipeline while
crossing lands that are not part of the
lease or unit from which the oil or gas
was produced; or
(b) A well is directionally drilled, the
wellhead is not located on the
producing lease or unit, and the oil or
gas is being used on the same well pad

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for operations or production purposes
for that well.
§ 226.148 Uses of production moved off
the lease or unit that require the
Superintendent’s prior approval of royaltyfree treatment.

(a) Except as provided in § 226.147(b)
and paragraph (b) of this section, royalty
is owed on all oil and gas used in
operations conducted off the lease or
unit from which it is produced.
(b) The Superintendent may grant
prior approval of royalty-free treatment
of oil or gas used in operations
conducted off the lease or unit if the:
(1) Use is among those listed in
§§ 226.145(a) or 226.146(a);
(2) Equipment or facility in which the
operation is conducted is located off the
lease or unit for engineering, economic,
resource protection, or physical
accessibility reasons; and
(3) Operations are conducted
upstream of the FMP.
(c) The lessee must submit a request
to the Superintendent, in writing, to
obtain approval of royalty-free treatment
of the volumes of oil and gas used. Such
request must comply with the
requirements set forth in § 226.151. If
the Superintendent approves a request
for royalty-free treatment under this
section, the effective date of such
approval will be the date the
Superintendent received the lessee’s
request. If the Superintendent denies a
request for royalty-free treatment under
this section, the lessee must pay
royalties on all volumes used.
(d) If equipment or a facility located
on a particular lease treats oil or gas
produced from the lease as well as oil
or gas produced from properties that are
not unitized with the lease, the lessee
may only report as royalty-free that
portion of the oil or gas used as fuel that
is properly allocated to the share of
production contributed by the lease or
unit upon which the equipment or
facility is located.
§ 226.149 Measurement or estimation of
royalty-free volumes of oil or gas.

(a) The lessee must measure or
estimate the volumes of royalty-free gas
used upstream of the FMP.
(b) The lessee must measure the
volume of gas that is removed from the
product stream downstream of the FMP
and used royalty-free pursuant to
§§ 226.145 through 226.148.
(c) The lessee must measure the
volume of oil that is used royalty-free
pursuant to §§ 226.145 through 226.148.
The lessee must also document the
removal of such oil from the tank or
pipeline.
(d) If the lessee removes oil or gas
downstream of the FMP and it is used

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Federal Register / Vol. 88, No. 9 / Friday, January 13, 2023 / Proposed Rules
royalty-free pursuant to §§ 226.145
through 226.148, the lessee must notify
the Superintendent, in writing, and
obtain an approved FMP under § 226.86
to measure the production removed for
use.
(e) The lessee must use the best
available information when estimating
gas volumes.
(f) The lessee must report each of the
volumes required to be measured or
estimated under this subpart to ONRR
in accordance with §§ 226.45 and
226.87.
§ 226.150
facilities.

Ownership of equipment and

The lessee is not required to own or
lease the equipment or facility that uses
oil or gas royalty-free under this
subpart. The lessee is responsible for
obtaining required authorizations,
measuring and reporting production,
and all other applicable requirements.
§ 226.151 Requesting approval of royaltyfree treatment for volumes used.

The lessee must submit a request to
the Superintendent, in writing, for
approval of royalty-free use of
production under this subpart. Such
requests must include the following
information:
(a) A complete description of the
operation to be conducted, including
the location of all equipment and
facilities involved in the operation and
the location of the FMP;
(b) The volumes of oil and gas the
lessee expects will be used to conduct
the operation and the method used to
measure or estimate such volumes;
(c) If the volume of gas expected to be
used is estimated, the basis for the
estimate (e.g., equipment manufacturer’s
published consumption or usage rates);
and
(d) The proposed disposition of the
oil and gas used (e.g., whether gas used
would be consumed as fuel, vented
through use of a gas-activated
pneumatic controller, returned to the
reservoir, or used in some other way).
Subpart M—Venting and Flaring

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§ 226.152

General requirements.

(a) No venting or flaring of gas is
permitted without the Superintendent’s
prior approval, except as defined in
§ 226.156.
(b) The lessee must notify the
Superintendent by email or facsimile at
least three business days prior to
conducting approved venting or flaring
operations.
(c) For purposes of this subpart, all
flares or combustible devices must be
equipped with an automatic ignition
system.

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§ 226.153

Gas-well gas.

Gas-well gas may not be vented or
flared except where it is unavoidably
lost under § 226.91(c).
§ 226.154

Oil-well gas.

Oil-well gas may be vented or flared
in accordance with §§ 226.155, 226.156,
and 226.157.
§ 226.155

Limitations on venting gas.

(a) The lessee must flare, rather than
vent, any gas that is not captured,
except when:
(1) Flaring the gas is technically
infeasible, such as when the gas is not
readily combustible, or the volumes are
too small to flare;
(2) There are emergency conditions,
as defined in § 226.156(d), and the loss
of gas is uncontrollable, or venting is
necessary for safety reasons;
(3) Gas is vented through normal
operations of a natural gas-activated
pneumatic controller or pump;
(4) Gas vapor is vented from a storage
tank or other low-pressure production
vessel, unless the Superintendent
determined that recovery of the gas
vapors is warranted;
(5) Gas is vented during downhole
well maintenance or liquids unloading
activities;
(6) Venting is necessary to allow the
performance of non-routine facility and
pipeline maintenance, such as when the
lessee must occasionally blow-down
and depressurize equipment to perform
maintenance or repairs; or
(7) A release of gas is unavoidable
under § 226.91(c) and flaring is
prohibited by Federal law.
(b) Venting of gas that has an H2S
content of 100 ppm or greater is
prohibited.
§ 225.156
gas.

Authorized venting and flaring of

(a) Initial production testing. Gas
flared during the initial production test
of each completed interval in a well is
royalty-free until one of the following
occurs:
(1) The lessee obtains adequate
reservoir information;
(2) It has been 30 calendar days since
the beginning of the production test,
unless the Superintendent approves a
longer test period; or
(3) The lessee has flared 50 MMcf of
gas.
(b) Subsequent well tests. Gas flared
during well tests after the initial
production test is royalty-free for a
period not to exceed 24 hours unless the
Superintendent approves or requires a
longer test period.
(c) Downhole well maintenance and
liquids unloading. Gas vented during

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2493

downhole well maintenance and well
purging is royalty-free for a period not
to exceed 24 hours per event, provided
that the requirements in paragraphs
(c)(1) through (3) of this section are met.
Gas vented from a plunger lift system or
automated well control system is
royalty-free, provided that the
requirements in paragraphs (c)(1) and
(2) of this section are met. For purposes
of this section, ‘‘well purging’’ means
blowing accumulated liquids out of a
wellbore using reservoir gas pressure,
whether manually or by an automatic
control system that relies on real-time
pressure or flow, times, or other well
data, where gas is vented to the
atmosphere. The term ‘‘well purging’’
does not apply to wells equipped with
plunger lift systems.
(1) The lessee must minimize the loss
of gas associated with downhole well
maintenance and liquids unloading
consistent with safe operations.
(2) For wells equipped with a plunger
lift system or automated well control
system, minimizing the loss of gas
under paragraph (c)(1) of this section
includes optimizing operation of the
system to minimize gas losses to the
maximum extent possible, consistent
with removing liquids that would
inhibit proper function of the well.
(3) For any liquids unloading by
manual well purging, the lessee must
ensure that the person conducting the
well purging remains on-site throughout
the operation so he can end the
operation as soon as practical, thereby
minimizing venting to the atmosphere
to the maximum extent possible.
(d) Emergencies. (1) Gas vented or
flared during an emergency is royaltyfree for a period not to exceed 24 hours,
unless the Superintendent determines
that emergency conditions exist that
necessitate venting or flaring for a
longer period.
(2) For purposes of this subpart, an
‘‘emergency’’ is a temporary, infrequent,
and unavoidable situation in which the
loss of oil or gas is uncontrollable or
necessary to avoid the risk of immediate
and substantial adverse impacts on
public health, safety, or the
environment and that is not the result
of lessee negligence or non-compliance.
(3) The following do not constitute
emergencies for the purpose of royalty
assessment:
(i) Failure to install appropriate
equipment with sufficient capacity to
accommodate the production
conditions;
(ii) Failure to limit production when
the production rate exceeds the capacity
of the necessary equipment, pipeline, or
gas plant or exceeds sales contract
volumes of oil or gas;

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(iii) Scheduled maintenance;
(iv) Situations caused by lessee
negligence or non-compliance,
including equipment failures; and
(v) Situations on a lease or unit that
has experienced three or more
emergencies within the past 30 days
unless the Superintendent determines
that the occurrence of such emergencies
within the 30-day period could not have
been anticipated and was beyond the
lessee’s control.
(4) The lessee must notify the
Superintendent of all emergencies in
writing, by email or facsimile,
immediately upon discovery, but not
later than the next calendar day.
(5) The lessee must estimate and
report the volumes vented or flared
beyond the timeframe specified in
paragraph (c)(1) of this section within
45 calendar days of the date the
emergency started.
§ 226.157 Measurement and reporting of
volumes of gas vented or flared.

(a) The lessee must estimate or
measure all volumes of oil and gas
avoidably and unavoidably lost from
wells, facilities, and equipment on a
lease or unit and report such volumes to

ONRR in accordance with §§ 226.45 and
226.87.
(b) The lessee may:
(1) Estimate the volume of gas vented
or flared based on the results of a
regularly performed GOR test and
measured values for the volumes of oil
production and gas sales to allow the
Superintendent to independently verify
the volume, rate, and heating value of
the flared gas; or
(2) Measure the volume of the flared
gas.
(c) The Superintendent may require
the installation of additional
measurement equipment whenever it is
determined that the existing methods
are inadequate to meet the purposes of
this subpart.
(d) The lessee may combine gas from
multiple leases or units for the purpose
of venting or flaring at a common point
but must allocate the quantities of the
vented or flared gas to each lease or unit
using a method the Superintendent
approves.

Subpart N—Assessments and
Penalties
Lease Management Assessments and
Civil Penalties
§ 226.158 Remedies for violations of lease
or permit terms and conditions, regulations,
orders, and notices.

Violation of, or non-compliance with,
the terms and conditions of any lease or
permit, the regulations in this part, or
orders and notices the Superintendent
issues, may result in:
(a) Assessments;
(b) Civil penalties for each day such
violation continues;
(c) Shut-in action; and
(d) Cancellation of the lease or permit
and bond forfeiture.
§ 226.159 Immediate assessments for
violations of certain operating regulations.

The Superintendent will issue
immediate assessments upon discovery
of the violations identified in Table 1.
Assessments will be issued in the
specified amounts per violation, per
inspection. Imposition of these
assessments does not preclude other
appropriate enforcement action and
civil penalties.

TABLE 1 TO § 226.159—VIOLATIONS SUBJECT TO AN IMMEDIATE ASSESSMENT
Assessment
amount per
violation
($)

Violation

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1. Failure to post signs and install flags and wind indicators as required by § 226.70(d)(4) through (8) ..........................................
2. Failure to properly identify wells, tanks, and facilities as required by § 226.75 .............................................................................
3. Failure to seal an appropriate valve on an oil storage tank as required by § 226.94 ....................................................................
4. Failure to seal an appropriate valve or component on an oil metering system as required by § 226.95 ......................................
5. Failure to properly measure oil before removal from storage for use on a different lease or unit as required by § 226.99(b) .....
6. Failure to retain records necessary to determine the quality and quantity of production as required by § 226.88 .......................
7. Missing or non-functioning FMP LACT system components as required by § 226.110 .................................................................
8. Missing or non-functioning FMP CMS components as required by § 226.111 ..............................................................................
9. Failure to meet the proving frequency requirements for an FMP as set forth in § 226.113 ..........................................................
10. Failure to obtain the Superintendent’s approval prior to using any oil measurement method other than tank gauging, LACT
system, or CMS at an FMP as required by § 226.115 ....................................................................................................................
11. Failure to conduct new FMP orifice plate inspections as required by § 226.121(c) .....................................................................
12. Failure to conduct routine FMP orifice plate inspections as required by § 226.121(d) ................................................................
13. Failure to conduct basic meter-tube inspections as required by § 226.121(g) .............................................................................
14. Failure to conduct detailed meter-tube inspections as required by § 226.121(h) .........................................................................
15. Failure to conduct an initial mechanical recorder verification as required by § 226.123(a) .........................................................
16. Failure to conduct routine mechanical recorder verifications as required by § 226.123(b) ..........................................................
17. Failure to conduct an initial EGM system verification as a required by § 226.126(a) ..................................................................
18. Failure to conduct routine EGM system verifications as required by § 226.126(b) ......................................................................
19. Failure to take spot samples for FMPs as required by § 226.133 ................................................................................................
20. Failure to construct and maintain pits as required by § 226.77 ....................................................................................................
21. Failure to install and maintain H2S detection equipment as required by § 226.70(d)(2) ..............................................................

§ 226.160

Other assessments.

If a lessee fails to commence or
perform an operation within five
calendar days after the Superintendent
orders such operation in writing, or
such other time as may be specified in
the order, the Superintendent may enter
upon the lease and perform the

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operation, or have a third-party perform
the operation, at the sole risk and
expense of the lessee. The
Superintendent will issue an assessment
for the actual cost of performance plus
an additional 25 percent of such amount
for all operations performed by or

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$250
250
1,000
1,000
1,000
1,000
1,000
1,000
1,000
1,000
1,000
1,000
1,000
1,000
1,000
1,000
1,000
1,000
1,000
2,500
2,500

through the Superintendent due to the
lessee’s non-compliance.
§ 226.161
correct.

Civil penalties with a period to

(a) If a lessee or permittee violates the
terms and conditions of the lease or
permit, the regulations in this part, or

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orders and notices the Superintendent
issues, the Superintendent may issue a
NONC informing the lessee or permittee
of the violation and specifying what
actions, if any, must be taken to correct
the non-compliance and avoid the
assessment of civil penalties and
cancellation of the lease or permit.
Upon completion of the required
corrective actions, the lessee must
submit a Self-Certification for
Correction of Lease Violations form to
the Superintendent.
(b) If the violation is corrected within
20 calendar days of the NONC, or such
longer period for correction specified in
the NONC, the Superintendent will not
assess a civil penalty or cancel the lease
or permit but will consider the
violations part of the lessee’s or
permittee’s history of non-compliance
for future penalty assessments.
(c) If the violation is not corrected
within 20 calendar days of the NONC,
or such longer period for correction
specified in the NONC, the lessee or
permittee will be liable for a civil
penalty of up to $1,198 per violation for
each day such violation continues,
commencing with the date of the NONC.
(d) If the violation is not corrected
within 40 calendar days of the notice, or
such longer period for correction
specified in the NONC, the lessee or
permittee will be liable for a civil
penalty of up to $11,995 per violation
for each day such violation continues,
commencing with the date of the NONC.
(e) If the Superintendent agrees to an
extension of the time to take corrective
action exceeding 20 calendar days, the
date of the NONC will be deemed to be
20 calendar days prior to the end of the
extended period for the purpose of civil
penalty calculation.
(f) Any amount imposed and paid as
assessments under § 226.159 will be
deducted from penalties under this
section.

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§ 226.162 Civil penalties without a period
to correct.

(a) The Superintendent may assess
civil penalties for the violations
identified in paragraphs (b) and (c) of
this section without prior notice or an
opportunity to correct the violation. The
Superintendent will inform lessees,
permittees, and other persons of
violations resulting in civil penalties
without a period to correct by issuing an
ILCP identifying the violation and the
amount of the civil penalty. For
purposes of this section, civil penalties
begin to accrue on the day the violation
is committed.
(b) Any person is liable for a civil
penalty of up to $23,989 per violation

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for each day such violation continues, if
such person:
(1) Fails or refuses to permit the
Superintendent’s lawful entry or
inspection pursuant to § 226.60; or
(2) Knowingly or willfully
commences drilling, recompletion, or
reentry operations, or causes surface
disturbance preliminary thereto,
without the Superintendent’s prior
approval in accordance with § 226.61.
(c) Any person is liable for a civil
penalty of up to $59,973 per violation
for each day such violation continues, if
such person:
(1) Knowingly or willfully prepares,
maintains, or submits false, inaccurate,
or misleading reports, notices,
affidavits, records, data, or other
documents and information required by
this part;
(2) Knowingly or willfully removes,
transports, uses, or diverts any oil or gas
from any lease or unit without valid
legal authority to do so;
(3) Tampers with or bypasses any
measurement device, component of a
measurement device, or the
measurement process;
(4) Purchases, accepts, sells,
transports, or conveys oil or gas to any
other person knowing or having reason
to know that such oil or gas was stolen
or unlawfully removed or diverted from
a lease or unit of the Osage Mineral
Estate.
§ 226.163

Penalty amount.

(a) The Superintendent will
determine the amount of the penalty to
assess by considering:
(1) The severity of the violation; and
(2) The lessee’s or permittee’s history
of non-compliance.
(b) The Superintendent may
compromise or reduce a civil penalty
assessed under this subpart.
§ 226.164

Shut-in actions.

(a) The Superintendent may take
immediate shut-in action, without
notice, when necessary for compliance;
when operations are commenced or
conducted without the required
approval; or where continued
operations could result in immediate
adverse impacts on public health and
safety, natural resources, the
environment, production accountability,
or royalty income.
(b) The Superintendent may take
shut-in action in situations other than
those identified in paragraph (a) of this
section only after providing written
notice to the lessee or permittee.
§ 226.165

Lease or permit cancellation.

(a) The Superintendent may issue a
Notice of Cancellation for a lease or
permit if a lessee or permittee:

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(1) Is determined to have obtained the
lease or permit by collusion, fraud, or
misrepresentation;
(2) Fails to comply with the terms and
conditions of the lease or permit, the
regulations in this part, or other
applicable laws;
(3) Fails to timely comply with, or
respond to, an order or notice the
Superintendent or ONRR issues;
(4) Fails to timely correct a violation
under § 226.161;
(5) Fails to pay civil penalties in full
on or before the date the Superintendent
or ONRR specifies;
(6) Knowingly and willfully commits
a violation that results in immediate
adverse impacts on public health and
safety, natural resources, or the
environment, production accountability,
or royalty income; or
(7) Has a history of non-compliance.
(b) The Notice of Cancellation will
inform the lessee or permittee of the
violation, set forth the reasons why
cancellation is warranted, and specify
what actions, if any, may be taken to
avoid cancellation of the lease or permit
and bond forfeiture.
(c) Cancellation of a lease or permit
does not relieve the lessee or permittee
of any continuing obligations under the
lease, permit, or regulations in this part.
(d) Upon cancellation of a lease, the
Osage Minerals Council may take
immediate possession of the leased
lands and all permanent improvements
and surface equipment necessary for
operation of the lease.
§ 226.166 Payment of assessments and
civil penalties.

(a) The lessee or permittee must remit
payment for civil penalties and
immediate assessments set forth in this
subpart within 10 business days of
receipt of the notice of collection from
the Superintendent by certified mail
unless a different date is specified
therein.
(b) Failure to timely pay civil
penalties will result in the assessment of
an interest charge on all unpaid or
underpaid penalty and assessment
amounts. Interest will be charged at the
IRS underpayment rate pursuant to 26
U.S.C. 6621(a)(2), or such other rate as
the Superintendent may prescribe. The
IRS underpayment rate is posted
quarterly and is available online at
https://www.irs.gov. Interest will only
be charged on the amount of the
payment not received and for the
number of days the payment is late.
(c) Payments made pursuant to
subpart N of this part do not relieve the
lessee or permittee of compliance with
the terms and conditions of the lease or
permit or the regulations in this part,

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nor do they relieve the lessee or
permittee of liability for waste, surface
damages, or any other damages that may
be occasioned. A waiver, compromise,
or reduction of any penalty must not be
construed as precluding or limiting the
imposition of penalties for any other
violations or acts of non-compliance at
that time or any other time.
Royalty Management Assessments and
Civil Penalties
§ 226.167 Remedies for violations of lease
or permit terms and conditions, regulations,
orders, and notices.

Violation of the terms or conditions of
a lease, permit, or the regulations in this
part relating to royalty payment and
reporting, production reporting, or noncompliance with any orders ONRR
issues, may result in:
(a) Assessments;
(b) Civil penalties for each day such
violation or non-compliance continues;
(c) Shut-in or cancellation of the lease
and bond forfeiture under §§ 226.164
and 226.165; and
(d) The transfer of delinquent debts to
the U.S. Department of Treasury for
collection.
§ 226.168 Assessments for incorrect or
late reports and failure to report.

(a) ONRR may issue assessments of up
to $10 per day for each report it does not
receive by the designated due date and
for each report submitted that is
incorrectly completed.
(b) ONRR will periodically establish
the amount of the assessments imposed
under paragraph (a) of this section based
on its experience with costs and
improper reporting. ONRR will publish
notice of the assessment amount in the
Federal Register.

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§ 226.169 Assessments for failure to
submit payment amount indicated on a
form or bill document or to provide
adequate information.

(a) ONRR may issue an assessment of
up to $250 when the amount of a
payment a reporter or payor submits is
not equivalent in amount to the total of
individual line items on the associated
form or bill document, unless ONRR
authorized the difference in amount.
(b) ONRR may issue an assessment of
up to $250 for each payment a reporter
or payor submits that cannot be
automatically applied to the associated
form or bill document because the
reporter or payor submitted inadequate
or erroneous information.
(c) For purposes of this section, the
term ‘‘applicable forms’’ include Form
ONRR–2014, Form ONRR–4054, and
any other forms ONRR requires under
this part.

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(d) For purposes of this section, the
term ‘‘bill document’’ means any
invoice that ONRR issues for
assessments, late-payment interest
charges, or other amounts owed. A
payment document is defined as a check
or wire transfer message.
(e) For purposes of this section,
‘‘inadequate or erroneous information’’
is defined as an:
(1) Absent or incorrect payor-assigned
document number the reporter or payor
is required to identify in Block 4 on
Form ONRR–2014 (document 4
number), or the reuse of the same
incorrect payor-assigned document 4
number in a subsequent reporting
period;
(2) Absent or incorrect bill document
invoice number (to include the threecharacter alpha prefix and the nine-digit
number) or the payor-assigned
document 4 number the reporter or
payor is required to be identify on the
associated payment document, or reuse
of the same incorrect payor-assigned
document 4 number in a subsequent
reporting period;
(3) Absent or incorrect name of the
administering BIA agency or office or
the Tribe name on payment documents
remitted. If the payment is made by
EFT, the reporter or payor must identify
the Tribe on the EFT message by a preestablished five-digit code;
(4) Absent or incorrect ONRRassigned payor code on a payment
document; or
(5) Absent or incorrect identification
on a payment document.
(f) ONRR will periodically establish
the amount of the assessment to be
imposed under paragraphs (a) and (b) of
this section. The amount of the
assessment for each violation will be
based on ONRR’s experience with costs
and improper reporting. ONRR will
publish notice of the assessment amount
in the Federal Register.
§ 226.170
correct.

Civil penalties with a period to

(a) If a reporter or payor violates the
terms and conditions of the lease, the
regulations in this part or any order
relating to royalty and production
reporting and payment requirements,
ONRR may issue a NONC informing the
reporter or payor of the violation and
specifying what actions, if any, must be
taken to correct the violation and avoid
the assessment of civil penalties.
(b) If the violation is corrected within
20 calendar days of the NONC, or such
longer period for correction specified in
the NONC, ONRR will not assess a civil
penalty or request that the
Superintendent shut-in or cancel the
lease or permit but will consider the

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violations part of the reporter’s or
payor’s history of non-compliance for
future penalty assessments.
(c) If the violation is not corrected
within 20 calendar days after the date
on which the NONC is served, or within
20 days following the expiration of any
longer period for correction specified in
the NONC, ONRR may issue an FCCP.
(1) The FCCP will state the amount of
the penalty. The penalty will:
(i) Begin to run on the day the NONC
is served; and
(ii) Continue to accrue for each
violation identified in the NONC until
it is corrected.
(2) The penalty may be up to $1,368
per day for each violation identified in
the NONC that has not been corrected.
(d) If the violation is not corrected
within 40 calendar days from the date
the NONC is served, or within 20
calendar days following the expiration
of any longer correction period specified
in the NONC, the reporter or payor will
be liable for a penalty of up to $13,693
per day for each day the violation
identified in the NONC that has not
been corrected. The increased penalty
will:
(1) Begin to run on the 40th day after
the day the NONC was served or on the
20th day after the expiration of any
longer correction period in the NONC;
and
(2) Continue to accrue for each
violation identified in the NONC until
it is corrected.
§ 226.171 Civil penalties without a period
to correct.

(a) ONRR may assess a penalty for a
violation identified in paragraphs (b)
and (c) of this section without prior
notice or an opportunity to correct the
violation. ONRR will inform reporters
and payors of violations without a
period to correct by issuing an ILCP
explaining the violation and the amount
of the civil penalty. The penalty will
begin to run on the day the violation is
committed.
(b) A reporter or payor is liable for a
civil penalty of up to $27,384 per
violation for each day the violation
continues if they:
(1) Fail or refuse to permit lawful
entry, inspection, or audit, including
refusal to keep, maintain, or produce
documents; or
(2) Knowingly or willfully fail to
make any royalty payment by the date
specified in the lease, regulations in this
part, or any applicable order.
(c) A reporter or payor is liable for a
civil penalty up to $68,462 per violation
for each day the violation continues if
they knowingly or willfully prepare,
maintain, or submit false, inaccurate, or

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misleading reports, notices, affidavits,
records, data, or other information to
ONRR.
(d) ONRR may use any information as
evidence that a reporter or payor
knowingly or willfully committed a
violation including, but not limited to:
(1) Any acts, or failures to act, by a
reporter’s or payor’s employee or agent;
(2) An email indicating the reporter’s
or payor’s concurrence with an issue;
(3) An order that the reporter or payor
failed to appeal an order, NONC, or
ILCP for which no further appeal is
available; and
(4) Any oral or written
communication that identifies a
violation that the reporter or payor:
(i) Acknowledges as true and fails to
correct;
(ii) Fails to appeal, or cannot further
appeal, and fails to correct; or
(iii) Corrects, but the reporter or payor
subsequently commits the same
violation.
§ 226.172

Penalty amount.

(a) ONRR will determine the amount
of the penalty to assess by considering
the:
(1) Severity of the violation;
(2) History of non-compliance; and
(3) Size of the reporter’s or payor’s
business. To determine business size,
ONRR may consider the number of
employees in the reporter’s or payor’s
company, parent company or
companies, and any subsidiaries or
contractors.
(b) ONRR will not consider the
royalty consequence of the underlying
violation when determining the amount
of the civil penalty for a violation under
§§ 226.170, 226.171(b)(1), and
226.171(c).
(c) FCCP and ILCP assessment
matrices and adjustments thereto are
posted on ONRR’s website.
(d) Penalties ONRR assesses under
this subpart are in addition to interest
owed on any underlying payments or
unpaid debts and are supplemental to,
not in derogation of, any other penalties
or assessments for non-compliance set
forth in this part or other applicable
laws and regulations.
(e) ONRR may compromise or reduce
a civil penalty assessed under this
subpart.

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§ 226.173 Payment of assessments and
civil penalties.

(a) The reporter or payor must remit
payment for the civil penalties and
assessments set forth in §§ 226.168
through 226.171 on or before the due
date identified in the bill accompanying
the FCCP or ILCP.
(b) Failure to timely pay civil
penalties and assessments will result in

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the reporter or payor owing latepayment interest on all unpaid or
underpaid penalty and assessment
amounts. Interest will be charged in
accordance with § 226.166(b) beginning
on the day the payment was due and
continuing until all debts are paid in
full.
§ 226.174 Collection of unpaid civil
penalties.

If a reporter or payor fails to pay a
civil penalty amount on or before the
date it is due, ONRR may use all
available means to collect the penalty
including, but not limited to:
(a) For an amount owed by a lessee,
requiring the lease surety to pay the
penalty;
(b) Deducting the amount of the
penalty from any sum the United States
may owe the reporter or payor; or
(c) Referring the debt to the U.S.
Department of the Treasury (Treasury)
for collection in accordance with
§ 226.175.
§ 226.175 Debt collection and
administrative offset.

(a) ONRR will transfer any past due,
legally enforceable non-tax debt to
Treasury within 180 days from the date
the debt becomes past due so that
Treasury may take appropriate action to
collect the debt or terminate the
collection action 26 U.S.C. 6402(d)(1)–
(2); 31 U.S.C. 3711, 3716, and 3720A;
Federal Claims Collection Standards (31
CFR parts 900 through 904); and 31 CFR
285.2 and 285.5.
(b) If ONRR determines that a person
owes, or may owe, a legally enforceable
debt to ONRR, it will send a written
notice to the debtor advising that ONRR
intends to refer the debt to Treasury.
The notice will inform the debtor of the:
(1) Amount, nature, and basis of the
debt;
(2) Methods of offset that ONRR or
Treasury may use;
(3) Opportunity to inspect and copy
Agency records related to the debt;
(4) Opportunity to enter into a written
agreement with ONRR to repay the debt;
(5) ONRR’s policy regarding interest
and administrative costs, including a
statement that ONRR will make such
assessments unless it determines
otherwise under the criteria of the
Federal Claims Collection Standards
and this part;
(6) Date by which payment must be
remitted to avoid additional late charges
and enforced collection; and
(7) Name, address, and phone number
of an ONRR representative who is
available to discuss the debt.
(c) Debtors that receive a notice issued
pursuant to paragraph (b) of this section

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2497

may not appeal unless the notice
specifically provides for such
opportunity because the debtor did not
previously receive a notice of the order,
decision on appeal, or any other notice
or decision that is the basis of the debt
that ONRR intends to refer to Treasury
and for which the debtor may be liable
in whole or in part under applicable
law. Debtors may not dispute matters
related to delinquent debts that were the
subject of a final order or appeal
decision of which they were the
recipient or a party thereto and that are
the basis of the delinquent debt. The
requirements under this paragraph
apply whether the debtor appealed the
order, demand, NONC, or assessment.
(d) ONRR will issue an initial
assessment of $436 for administrative
costs incurred because of a debtor’s
failure to pay a delinquent debt. ONRR
will publish notice of any increases in
administrative costs in the Federal
Register. ONRR may also assess an
additional $436 for administrative costs
that continue to accrue during any
appeal process if:
(1) The notice issued under paragraph
(b) of this section grants the right to
appeal and the debtor exercises that
right; and
(2) The appeal is denied and ONRR
refers the delinquent debt to Treasury.
(e) ONRR will apply a partial or
installment payment made on a
delinquent debt sent to Treasury in the
following order: outstanding penalty
assessments, administrative costs,
accrued interest, and outstanding debt
principal.
(f) The Director of ONRR may waive
collection of all or part of the
administrative costs under paragraph (d)
of this section if they determine that
collection of this charge would be
against equity and good conscience or
the Federal Government’s best interest.
The Director’s decision to collect or
waive administrative costs is the final
decision for the Department and is not
subject to administrative review.
(g) The Director of ONRR may
recommend that the Superintendent
revoke a debtor’s ability to engage in the
leasing of any trust or restricted lands or
the granting of easements, permits, or
rights-of-way if the debtor inexcusably
or willfully fails to pay a debt. Any such
recommendation will remain in effect
until such time as the debt is paid in full
or otherwise resolved to ONRR’s
satisfaction.
(h) ONRR may refer any past due,
legally enforceable debt to Treasury to
collect through administrative offset or
tax refund offset at least 60 calendar
days after it issues notice under
paragraph (b) of this section if the debt

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is at least $250 or such other base
amount as may be established by
Treasury.
(i) ONRR may refer debts reduced to
judgment to Treasury for tax refund
offset at any time.
Criminal Penalties
§ 226.176
reports.

Penalties for filing fraudulent

Any person who knowingly and
willfully files fraudulent reports or
information under the regulations in
this part is subject to criminal penalties
under 18 U.S.C. 1001.
Subpart O—Appeals
Appeals of BIA Decisions
§ 226.177 Procedure for filing an
administrative appeal of a decision, order,
or notice of the Superintendent.

(a) Any party adversely affected by a
decision, order, or notice the
Superintendent issues by virtue of the
regulations in this part may appeal
pursuant to 25 CFR part 2.
(b) If an appeal is not timely filed
with the Regional Director under 25
CFR part 2 and subsequently with the
IBIA under 43 CFR part 4, subpart D
(where required):
(1) The subject decision, order, or
notice will be final for the Department;
and
(2) The affected party will be barred
from contesting the validity or merits of
the decision, order, or notice in
subsequent administrative or judicial
proceedings due to failure to exhaust
administrative remedies.
Appeals of ONRR Decisions

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§ 226.178 Procedures for filing and
administrative appeal of an order from
ONRR.

(a) Any party adversely affected by an
order ONRR issues by virtue of the
regulations in this part may appeal to
the Director of ONRR as set forth in this
section.
(b) For purposes of this section, the
term ‘‘order’’ means any document
ONRR issues that contains language
mandating or directing the recipient to
report, compute, or pay royalties or
other obligations; report production; or
provide any other information.
(1) An order includes, but is not
limited to:
(i) An Order to Pay or Order to
Perform a Restructured Accounting;
(ii) A decision from ONRR denying a
lessee’s, reporter’s, or payor’s written
request and that imposes an obligation
on the lessee, reporter, or payor (a
denial); and
(iii) A NONC, FCCP, or ILCP.

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(2) An order does not include:
(i) A non-binding request,
information, or guidance, such as a
policy determination or guidance on
how to report or pay, including a
valuation determination, unless it
contains language indicating that an
action is mandatory or expressly orders
the recipient(s) to take a certain action;
(ii) A subpoena;
(iii) An order that ONRR issues to a
refiner or other person involved in
disposition of royalty taken in-kind;
(iv) A ‘‘Dear Lessee,’’ ‘‘Dear Payor,’’ or
‘‘Dear Reporter’’ letter, unless it
explicitly includes the right to appeal;
or
(v) Any other correspondence from
ONRR that does not include the right to
appeal.
(c) A lessee or designee may appeal an
order to the Director of ONRR by filing
a Notice of Appeal in the office of the
official that issued the order within 30
calendar days from the date the order
was received. If a designee is filing an
appeal, they must concurrently serve
the Notice of Appeal on all lessees for
the lease(s) identified in the order by
certified mail—return receipt requested.
Within the same 30-day period, the
lessee or designee must file a Statement
of Reasons setting forth any factual and
legal arguments justifying reversal or
modification of the order. No extension
of time will be granted for filing the
Notice of Appeal.
(d) A lessee may join an appeal filed
by a designee within 30 calendar days
from the date the lessee receives the
Notice of Appeal by filing a Notice of
Joinder with the office of the official
that issued the order. If a lessee joins an
appeal, they are deemed to appeal the
order jointly with the designee, but the
designee must fulfill all requirements
imposed on appellants under this
section and 43 CFR part 4, subpart E.
Lessees may not file pleadings
separately from the designee.
(1) If a lessee does not appeal, or join
the designee’s appeal, the designee’s
actions with respect to the appeal and
any decisions therein are binding on the
lessee.
(2) If a designee decides to
discontinue participation in an appeal,
they must serve written notice at least
30 calendar days before the next
pleading is due. The notice must be
served on:
(i) All lessees who joined the appeal
under this section;
(ii) The office or officer with whom
subsequent pleadings must be filed; and
(iii) All other parties to the appeal.
(e) Any party adversely affected by a
decision the Director of ONRR issues
under this section may appeal the

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decision to the IBLA pursuant to 43 CFR
part 4, subpart E.
(f) If an order is neither paid, nor
appealed to the Director of ONRR under
this section and, subsequently, to the
IBLA under 43 CFR part 4, subpart E:
(i) The order is the final decision of
the Department; and
(ii) The affected party will be barred
from contesting the validity or merits of
the order in subsequent administrative
or judicial proceedings, including
enforcement proceedings.
§ 226.179 Suspension of compliance with
an ONRR order.

(a) For purposes of this subpart,
‘‘ONRR-specified surety instrument’’
means an ONRR-specified
administrative appeal bond, an ONRRspecified irrevocable letter of credit, or
a financial institution book-entry
certificate of deposit.
(b) Subject to paragraph (d) of this
section, if an affected party appeals an
order regarding the payment or
reporting of royalties and other
payments due from leases of the Osage
Mineral Estate:
(1) If the amount under appeal is less
than $1,000, or does not require
payment, the appellant’s obligation to
comply with the order is suspended
while the appeal is pending. ONRR will
use the performance bond posted with
the BIA as collateral for the obligation.
(2) If the amount under appeal is
$1,000 of more, ONRR will suspend the
appellant’s obligation to comply with
the order if they submit an ONRRspecified surety instrument under this
subpart within 60 calendar days of the
date they receive the order or Notice of
Order.
(c) Nothing in this subpart prohibits
an appellant from paying any demanded
amount or otherwise complying with
any other requirement pending
resolution of their appeal. Voluntarily
paying any demanded amount or
otherwise complying with any other
requirement when suspension of an
order is available under the regulations
does not create a final agency action
subject to judicial review under 5 U.S.C.
704.
(d) Regardless of the amount under
appeal, ONRR may inform an appellant
that it will not suspend their obligation
to comply with the order under
paragraph (a) of this section because
suspension would harm the interests of
the United States or Osage Nation.
§ 226.180 Requirements for posting a
bond or other surety on behalf of an
appellant.

Any person, including a designee,
payor, or affiliate, may post a bond or

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Federal Register / Vol. 88, No. 9 / Friday, January 13, 2023 / Proposed Rules
surety instrument under this subpart on
behalf of an appellant. If you assume an
appellant’s responsibility to post a bond
or other surety instrument, you:
(a) Must notify ONRR in writing that
you are assuming the appellant’s
responsibility under this subpart;
(b) May not assert that you are not
otherwise liable for royalties or other
payments under the lease, or any other
theory, as a defense if ONRR collects
your bond or other surety instrument;
and
(c) May end your voluntarily assumed
responsibility for posting a bond or
other surety instrument only after the
appellant pays or posts a bond or other
surety instrument.
§ 226.181 Suspension of the obligation to
comply with an ONRR order due to judicial
review in federal court.

(a) If an appellant seeks judicial
review of an IBLA decision or another
final action of the Department of the
Interior regarding an ONRR order,
ONRR will suspend the appellant’s
obligation to comply with that order
pending judicial review if they continue
to meet the requirements of this subpart.
(b) Notwithstanding paragraph (a) of
this section, ONRR may decide that it
will not suspend an appellant’s
obligation to comply with an order.
ONRR will notify the appellant in
writing of such decision and the reasons
for it.
§ 226.182 ONRR’s collection of bonds and
other surety instruments.

(a) This section applies to you if you
maintain a bond or an ONRR-specified
surety instrument on your own behalf or
on another person’s behalf for an appeal
of an order under this subpart.
(b) ONRR may initiate collection of
your bond or other surety instrument if:
(1) The Director of ONRR decides the
appeal adversely to you and you do not
pay the amount due or appeal the
decision further to the IBLA under 43
CFR part 4, subpart E;

(2) The IBLA, Director of the Office of
Hearings and Appeals, an Assistant
Secretary, or the Secretary decides the
appeal adversely to you and you do not
pay the amount due or pursue judicial
review within 90 calendar days of the
decision;
(3) A court of competent jurisdiction
issues a final non-appealable decision
adverse to you and you do not pay the
amount due within 30 calendar days of
the decision;
(4) You do not increase the amount of
your bond or other surety instrument as
required under § 226.185(c), or
otherwise fail to maintain an adequate
surety instrument in effect, and you do
not pay the amount due under the
ONRR order within 30 calendar days of
receipt of the notice from ONRR under
§ 226.185(c); or
(5) The obligation to comply with an
order or decision is not suspended and
you do not pay the amount required
under the order or decision.
§ 226.183 ONRR bond-approving officer’s
determination of surety amount not subject
to appeal.

Any decision regarding the amount of
the surety due under this subpart is
final and not subject to appeal.
§ 226.184 Standards for ONRR-specified
surety instruments.

(a) An ONRR-specified surety
instrument must be in a form identified
in ONRR’s instructions. ONRR will
provide written information and
standards forms for ONRR-specified
surety instrument requirements.
(b) ONRR will use a bank-rating
service to determine whether a financial
institution has an acceptable rating to
provide a surety instrument adequate to
indemnify the lessor from loss or
damage.
(1) Administrative appeal bonds must
be issued by a qualified surety company
that Treasury approved.
(2) Irrevocable letters of credit or
certificates of deposit must be from a
Atmos.
pressure
(psi)

lotter on DSK11XQN23PROD with PROPOSALS3

Elevation
(ft msl)
0 ...........................................................................................
100 .......................................................................................
200 .......................................................................................
300 .......................................................................................
400 .......................................................................................
500 .......................................................................................
600 .......................................................................................
700 .......................................................................................
800 .......................................................................................
900 .......................................................................................
1,000 ....................................................................................
1,100 ....................................................................................
1,200 ....................................................................................
1,300 ....................................................................................
1,400 ....................................................................................

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Frm 00071

Elevation
(ft msl)

14.70
14.64
14.59
14.54
14.49
14.43
14.38
14.33
14.28
14.23
14.17
14.12
14.07
14.02
13.97

Fmt 4701

Sfmt 4700

financial institution acceptable to ONRR
with a minimum one-year period of
coverage subject to automatic renewal
up to five years.
§ 226.185 ONRR’s determination of bond
or surety instrument amount.

(a) The ONRR bond-approving officer
may approve an appellant’s surety if
they determine that the amount is
adequate to guarantee payment. The
amount of the appellant’s surety may
vary depending on the form of the
surety and how long the surety is
effective.
(b) The amount of the ONRR-specified
surety instrument must include the
principal amount owed under the order
plus any accrued interest ONRR
determines is owed plus projected
interest for a one-year period.
(c) If an appeal is not decided within
one year from the date of filing, the
appellant must increase the surety
amount to cover additional estimated
interest for another one-year period. The
appellant must continue to increase the
surety amount annually on the date of
filing for the duration of the appeal.
ONRR will determine the additional
estimated interest and notify the
appellant of the amount so it can amend
your surety instrument.
(d) The appellant may submit a single
surety instrument that covers multiple
appeals. The appellant may change the
instrument to add new amounts under
appeal or remove amounts that have
been adjudicated in their favor or that
they have paid if they:
(1) Amend the single surety
instrument annually on the date they
filed their first appeal; and
(2) Submit a separate surety
instrument for new amounts under
appeal until they amend the instrument
to cover the new appeals.
Appendix A to Part 226—Table of
Atmospheric Pressures
Atmos.
pressure
(psi)

4,000
4,100
4,200
4,300
4,400
4,500
4,600
4,700
4,800
4,900
5,000
5,100
5,200
5,300
5,400

E:\FR\FM\13JAP3.SGM

12.70
12.65
12.60
12.56
12.51
12.46
12.42
12.37
12.32
12.28
12.23
12.19
12.14
12.10
12.05

13JAP3

Elevation
(ft msl)
8,000
8,100
8,200
8,300
8,400
8,500
8,600
8,700
8,800
8,900
9,000
9,100
9,200
9,300
9,400

Atmos.
pressure
(psi)
10.92
10.88
10.84
10.80
10.76
10.72
10.68
10.63
10.59
10.55
10.51
10.47
10.43
10.39
10.35

2500

Federal Register / Vol. 88, No. 9 / Friday, January 13, 2023 / Proposed Rules
Atmos.
pressure
(psi)

Elevation
(ft msl)
1,500
1,600
1,700
1,800
1,900
2,000
2,100
2,200
2,300
2,400
2,500
2,600
2,700
2,800
2,900
3,000
3,100
3,200
3,300
3,400
3,500
3,600
3,700
3,800
3,900

....................................................................................
....................................................................................
....................................................................................
....................................................................................
....................................................................................
....................................................................................
....................................................................................
....................................................................................
....................................................................................
....................................................................................
....................................................................................
....................................................................................
....................................................................................
....................................................................................
....................................................................................
....................................................................................
....................................................................................
....................................................................................
....................................................................................
....................................................................................
....................................................................................
....................................................................................
....................................................................................
....................................................................................
....................................................................................

Calculated as:
Palm = 14.696 × (1×0.00000686E)525577

Elevation
(ft msl)

13.92
13.87
13.82
13.77
13.72
13.67
13.62
13.57
13.52
13.47
13.42
13.37
13.32
13.27
13.22
13.17
13.13
13.08
13.03
12.98
12.93
12.89
12.84
12.79
12.74

Atmos.
pressure
(psi)

5,500
5,600
5,700
5,800
5,900
6,000
6,100
6,200
6,300
6,400
6,500
6,600
6,700
6,800
6,900
7,000
7,100
7,200
7,300
7,400
7,500
7,600
7,700
7,800
7,900

12.01
11.96
11.92
11.87
11.83
11.78
11.74
11.69
11.65
11.61
11.56
11.52
11.48
11.43
11.39
11.35
11.30
11.26
11.22
11.18
11.13
11.09
11.05
11.01
10.97

From: U.S. Standard Atmosphere, 1976,
U.S. Government Printing Office,
Washington, DC 1976.
Bryan Newland,
Assistant Secretary—Indian Affairs.
[FR Doc. 2022–28098 Filed 1–12–23; 8:45 am]

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BILLING CODE 4337–15–P

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13JAP3

Elevation
(ft msl)
9,500
9,600
9,700
9,800
9,900
10,000
10,100
10,200
10,300
10,400
10,500
10,600
10,700
10,800
10,900
11,000
11,100
11,200
11,300
11,400
11,500
11,600
11,700
11,800
11,900

Atmos.
pressure
(psi)
10.31
10.27
10.23
10.19
10.15
10.12
10.08
10.04
10.00
9.96
9.92
9.88
9.84
9.81
9.77
9.73
9.69
9.65
9.62
9.58
9.54
9.50
9.47
9.43
9.39