Site Security Rule

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DEPARTMENT OF THE INTERIOR
Bureau of Land Management
43 CFR Parts 3160 and 3170
[17X.LLWO310000.L13100000.PP0000]
RIN 1004–AE15

Onshore Oil and Gas Operations;
Federal and Indian Oil and Gas Leases;
Site Security
Bureau of Land Management,
Interior.
ACTION: Final rule.
AGENCY:

This final rule replaces
Onshore Oil and Gas Order No. 3, Site
Security (Order 3), with new regulations
codified in the Code of Federal
Regulations (CFR). The final rule
establishes minimum standards for oil
and gas facility site security, and
includes provisions to ensure that oil
and gas produced from Federal and
Indian (except Osage Tribe) oil and gas
leases are properly and securely
handled, so as to ensure accurate
measurement, production
accountability, and royalty payments,
and to prevent theft and loss.
The BLM developed this rule based
on the proposed rule that was published
in the Federal Register on July 13, 2015,
and tribal and public comments the
BLM received on the proposed rule.
This rule strengthens the BLM’s policies
governing production verification and
accountability by updating and
replacing the existing requirements of
Order 3 to address changes in
technology and industry practices that
have occurred in the 25 years since
Order 3 was issued, and to respond to
recommendations made by the
Government Accountability Office
(GAO) and the Office of the Inspector
General (OIG) with respect to the BLM’s
production verification efforts.
Like the proposed rule, the final rule
addresses Facility Measurement Points
(FMPs), site facility diagrams, the use of
seals, bypasses around meters,
documentation, recordkeeping,
commingling, off-lease measurement,
the reporting of incidents of
unauthorized removal or mishandling of
oil and condensate, and immediate
assessments for certain acts of
noncompliance. The final rule also
establishes a process for the BLM to
consider variances from the
requirements of the final regulation.
Some of the key changes from the
proposed rule that are incorporated into
the final rule include: Additional
exemptions from the final rule’s
commingling requirements; a

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SUMMARY:

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streamlined FMP application and
approval process; simplified site facility
diagram submissions; and clarifications
to tank gauging procedures and
frequency.
The BLM believes that this final rule,
as well as the final rules to update and
replace Onshore Oil and Gas Order No.
4 (Order 4), related to measurement of
oil, and Onshore Oil and Gas Order No.
5 (Order 5), related to measurement of
gas enhance the BLM’s overall
production verification and
accountability program.
DATES: The final rule is effective on
January 17, 2017.
FOR FURTHER INFORMATION CONTACT:
Michael Wade, BLM Colorado State
Office, at 303–239–3737, for information
about the requirements of this final rule,
or Steven Wells, Division Chief, Fluid
Minerals Division, 202–912–7143, for
information regarding the BLM’s Fluid
Minerals Program. Persons who use a
telecommunications device for the deaf
(TDD) may call the Federal Relay
Service at 1–800–877–8339 to contact
the above individuals during normal
business hours. The Service is available
24 hours a day, 7 days a week to leave
a message or question with the above
individual. You will receive a reply
during normal business hours.
SUPPLEMENTARY INFORMATION:
I. Executive Summary and Background
II. Overview of the Final Rule, Section-bySection Analysis, and Response to
Comments
III. Overview of Public Involvement and
Consistency With GAO
Recommendations
IV. Procedural Matters

I. Executive Summary and Background
Under applicable law, royalties are
owed on all production removed or sold
from Federal and Indian oil and gas
leases, as well as on any oil or gas that
is avoidably lost during production. The
basis for those royalty payments is the
measured production from those leases.
In the fiscal year (FY) 2015 sales year,
onshore Federal oil and gas leases sold
180 million barrels (bbl) of oil,1 2.50
trillion cubic feet of natural gas,2 and
2.6 billion gallons of natural gas liquids,
with a market value of more than $17.7
billion and generating royalties of
almost $2.0 billion. Nearly half of these
1 Figures related to total production of oil include
168 million bbl of regularly classified oil, plus
additional sales of condensate, sweet and sour
crude, black wax crude, other liquid hydrocarbons,
inlet scrubber and drip or scrubber condensate, and
avoidable oil losses, all of which are considered to
be part of oil sales for accounting purposes.
2 Includes all processed and unprocessed
volumes recovered on-lease, nitrogen, fuel gas, coal
bed methane, and any volumes of gas avoidably lost
due to venting or flaring.

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revenues were distributed to the States
in which the leases are located. Leases
on tribal and Indian lands sold 59
million bbl of oil, 239 billion cubic feet
of natural gas, 182 million gallons of
natural gas liquids, with a market value
of over $3.6 billion and generating
royalties of over $0.6 billion, which
were distributed in their entirety to the
applicable tribes and individual allottee
owners.
As explained in the preamble for the
proposed rule (80 FR 40768), given the
magnitude of this production and the
BLM’s statutory and management
obligations, it is critically important that
the BLM ensure that operators
accurately measure, properly report, and
account for all production. This final
rule helps the BLM achieve that
objective by updating and replacing
Order 3’s requirements with regulations
codified in the CFR that reflect changes
in oil and gas measurement practices
and technology since Order 3 was first
promulgated in 1989.3
Specifically, the requirements in this
rule ensure the proper and secure
handling of production from Federal
and Indian (except Osage Tribe) oil and
gas leases. The proper handling of
production is essential to accurate
measurement, proper reporting, and
overall production accountability, all of
which are necessary to ensure that the
American public, as well as Indian
tribes and allottees, receive the royalties
to which they are entitled on oil and gas
produced from Federal and Indian
leases, respectively.
Order 3 was one of seven Onshore Oil
and Gas Orders that the BLM issued
under its regulations at 43 CFR part
3160.4 Order 3 primarily supplemented
the regulations at 43 CFR 3162.4
(records and reports), 3162.5
(environmental safety), 3162.7
(disposition and measurement of oil and
gas production and site security on
Federal and Indian (except Osage Tribe)
oil and gas leases), subpart 3163 (noncompliance, assessments, and civil
penalties), and subpart 3165 (relief,
conflicts, and appeals). While the BLM’s
Onshore Orders have all been published
in the Federal Register, both for public
comment and in final form, they were
never codified in the CFR. With this
final rule, the BLM is replacing Order 3
and updating and codifying its
3 Order 3, which was published in the Federal
Register on February 24, 1989 (54 FR 8056), has
been in effect since March 27, 1989.
4 These regulations provide for the issuance of
Onshore Oil and Gas Orders to ‘‘implement and
supplement’’ the regulations found in part 3160. 43
CFR 3164.1(a). The Onshore Orders apply
nationwide to all Federal onshore and Indian
(except Osage Tribe) oil and gas leases.

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requirements regarding site security, as
explained below.
The development of this rule was
driven largely by internal and external
reviews of the BLM’s existing
production measurement and
accountability program. These reviews
began in 2007 when the Secretary
appointed an independent panel—the
Subcommittee on Royalty Management
(Subcommittee)—to review the
Department’s procedures and processes
related to the management of mineral
revenues and to provide advice to the
Department based on that review.5 In a
report dated December 17, 2007, the
Subcommittee determined that the
BLM’s guidance regarding production
accountability is ‘‘unconsolidated,
outdated, and sometimes insufficient’’
(Subcommittee report, p. 30). The
Subcommittee report found that this
results in inconsistent and outmoded
approaches to production accountability
tasks, and the potential loss of royalty
revenue.
The Subcommittee report expressed
concern that the applicable ‘‘BLM
policy and guidance is outdated’’ and
‘‘some policy memoranda have expired’’
(Subcommittee report, p. 31). The
Subcommittee also expressed concern
that ‘‘BLM policy and guidance have not
been consolidated in a single document
or publication,’’ which has led to the
‘‘BLM’s 31 oil and gas field offices using
varying policy and guidance’’ (id.). For
example, ‘‘some BLM State Offices have
issued their own ‘Notices to Lessees’ for
oil and gas operations’’ (id.). While the
Subcommittee recognized that such
Notices to Lessees may have a positive
effect on some oil and gas field
operations, it also observed that they
necessarily ‘‘lack a national perspective
and may introduce inconsistencies
among State [Offices]’’ (id.).
The Subcommittee made a number of
recommendations relevant to site
security. It recommended that the BLM
re-evaluate its regulations and update its
policy and guidance on production
accountability, including requiring that
requests to commingle production from
multiple leases, unit participating areas
(PAs), or areas subject to
communitization agreements (CAs)
identify allocation among zones
(Subcommittee report, p. 32). The
Subcommittee also recommended that
5 The Subcommittee was commissioned to report
to the Royalty Policy Committee, which was
chartered under the Federal Advisory Committee
Act to provide advice to the Secretary and other
departmental officials responsible for managing
mineral leasing activities and to provide a forum for
the public to voice concerns about mineral leasing
activities. The Royalty Policy Committee’s chart has
since expired.

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the BLM re-evaluate its policies and
guidance for royalty-free use of gas in
lease operations. It also specifically
recommended that the BLM establish a
workgroup to evaluate Order 3. In
response, the Department formed a fluid
minerals team, comprising
Departmental employees who are oil
and gas experts. Based on its review, the
team determined that Order 3 should be
updated.
In addition to the Subcommittee
report, the GAO and the OIG have
performed multiple audits since 2009
and issued reports that included many
findings and recommendations
addressing similar issues: (1) Report to
Congressional Requesters, Oil and Gas
Management, Interior’s Oil and Gas
Production Verification Efforts Do Not
Provide Reasonable Assurance of
Accurate Measurement of Production
Volumes GAO–10–313 (GAO Report 10–
313); (2) Report to Congressional
Requesters, Oil and Gas Resources,
Interior’s Production Verification
Efforts: Data Have Improved but Further
Actions Needed, GAO 15–39 (GAO
Report 15–39); (3) Bureau of Land
Management’s Oil and Gas Inspection
and Enforcement Program, CR–EV–
0001–2009 (OIG Report 2009); and (4)
Energy Related Management Advisories,
CR–IS–MOA–0005–2014 (OIG Report
2014).
In 2010, the GAO found that Interior’s
measurement regulations and policies
do not provide reasonable assurance
that oil and gas are accurately measured.
Regarding matters relevant to site
security, the report found that the BLM
lacks regulatory or policy requirements
for operators to clearly identify points of
royalty measurement, creating
challenges for the BLM in verifying
production (GAO Report 10–313, p. 34).
It also found that the BLM does not have
sufficient national policies or a
consistent process for approving
arrangements that allow operators to
commingle production from multiple
Federal, Indian, State, and private
leases, which also makes it difficult for
the agency to verify production (GAO
Report 10–313, p. 36). In response, the
GAO specifically recommended that the
BLM: (1) Develop guidance clarifying
when Federal oil and gas may be
commingled and establish standardized
measurement methods for such
circumstances so that production can be
adequately measured and verified; (2)
Confirm that commingling agreements
are consistent with Interior guidance
before they are approved, and that the
agreements facilitate key production
verification activities; and (3) Track all
onshore meters, including information
about meter location, identification

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number, and owner, to help ensure that
Interior (through the BLM) is accurately
and consistently tracking where and
how onshore oil and gas are measured
nationwide.
The GAO reiterated some of these
concerns in 2015 (GAO Report 15–39).
In that report, the GAO acknowledged
the improvements the BLM had made in
its processes and policies (e.g., issuing
additional guidance in 2013 regarding
commingling approvals), but reiterated
the importance of the BLM updating its
regulations related to measurement and
site security (GAO Report 15–39, pp.
31–32).
Based in part on its concern that the
BLM’s production verification efforts do
‘‘not provide reasonable assurance that
operators are accurately measuring and
reporting’’ the volumes of oil and gas
produced from Federal and Indian
leases, the GAO included the BLM’s
onshore oil and gas program on its High
Risk List in 2011 (Report to
Congressional Committees, High Risk
Series, An Update, GAO–11–278 (GAO
Report 11–278), p. 15). Because the
GAO’s recommendations have not yet
been fully implemented, including
those related to production verification,
the onshore oil and gas program has
remained on the High Risk List in
subsequent updates in 2013 (Report to
Congressional Committees, High Risk
Series, An Update, GAO–13–283) and
2015 (Report to Congressional
Committees, High Risk Series, An
Update, GAO–15–290).
The OIG made similar observations as
part of its reviews of the BLM’s
inspection and enforcement program.
For example, in 2009 the OIG observed
that the BLM’s ‘‘inspection efforts are
hampered because of provisions in the
bureau’s regulations that have not kept
up with modern technology. Most
notably, six of the seven Onshore Oil
and Gas Orders, which address
activities, such as drilling operations,
the measurement of oil and gas, and site
security, are outdated as they were
enacted in the late 1980s and early
1990s.’’ The OIG specifically
recommended that the BLM ‘‘(e)nsure
that oil and gas regulations are current
by updating and issuing onshore
orders.’’ (OIG Report 2009, p. 10–11).
The OIG also expressed concern that
‘‘(c)urrent BLM policies (with respect to
penalties and assessments) do not allow
for immediate assessments for chronic
offenders. As a result, at times there is
little incentive for companies to meet
their regulatory responsibilities.’’ (id., p.
13). As a result, the OIG recommended
that the BLM ‘‘(e)nhance the deterrent
for operator noncompliance by
increasing the dollar amount of

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monetary assessments, seeking
congressional action for increasing civil
penalties, and expanding the infractions
for which immediate assessments may
be issued.’’ (id., p. 14).
The OIG supplemented these
recommendations in 2014 with a series
of recommendations that flowed from
individual OIG investigations that were
consolidated into one report—Energy
Related Management Advisories, CR–
IS–MOA–0005–2014 (Nov. 2014) (OIG
Report 2014).6 That report made a
number of recommendations, including
the following relevant to this rule:
• Develop and implement procedures
to ensure timely receipt of site facility
diagrams and ensure that they contain
adequate information related to
production and sales phases (OIG
Report 2014 at 10, 18);
• Take steps to address misreporting
associated with off-lease measurement
(id.);
• Ensure that adequate information
exists regarding on-lease beneficial use
in order to identify inappropriate
deductions (id., at 12); and
• Ensure that Federal measurement
points are properly documented and
recorded (id. at 21).
In addition to the concerns from these
entities, the BLM also recognized, based
on its own experience, that its site
security requirements needed
strengthening. For example, as
explained in the proposed rule, it is not
uncommon for a BLM inspector, a lease
operator, and field employees to all
have different understandings of where
the point of royalty measurement is on
a given lease, because Order 3 did not
require operators to formally identify
and obtain BLM approval for the use of
a particular royalty measurement point
on a given lease, unit PA, or CA. This
type of discrepancy can create needless
uncertainties in production, accounting,
and verification, and can increase the
time spent on individual inspections
and audits by both operators and the
BLM, which strains the BLM’s limited
resources and requires additional

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6 The OIG Report 2014, covered the following
investigations: Berry Petroleum Co. & Quinex
Energy Corp., DOI–OIG Case File Nos. OI–OG–07–
0359–I & OI–OG–07–0389–I; Petrox Resources, Inc.,
DOI–OIG Case File No. OI–OG–09–0266–I; SEECO,
Inc., OIG Case File No. OI–OG–09–0722–1; and
TEPPCO Partners, DOI–OIG Case File No. OI–OG–
09–0346–I).

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response and resources on the part of
operators. This final rule corrects this
problem by requiring operators to
identify and obtain BLM approval for
their royalty measurement points,
which are called FMPs under this rule.
Similarly, with respect to
commingling approvals, the BLM
recognizes that the absence of uniform
national guidance means that some
BLM-approved commingling agreements
may not provide the production data
that the BLM needs to independently
verify production that is attributable to
the Federal or Indian leases covered by
those agreements. The absence of this
data limits the BLM’s ability to fulfill its
obligation to ensure that all production
from Federal and Indian (except Osage
Tribe) oil and gas leases is properly
accounted for and that royalties are
properly calculated. The final rule
addresses these concerns by establishing
uniform requirements for both existing
and future commingling approvals.
With respect to existing approvals, the
final rule includes provisions: (1)
Specifically grandfathering existing
CAAs involving downhole commingling
and where production falls below
certain specified thresholds; (2)
Expressly exempting from compliance
with the rule’s commingling
requirements downhole commingling in
new wells in areas where the BLM has
specifically recognized that downhole
commingling is necessary to ensure
maximum economic recovery (such as
when a lower formation is necessary to
produce an upper one) or when
commingled production is below certain
levels; and, (3) Expressly recognizing as
compliant CAAs authorized by tribal
law or agreement. As explained in this
preamble, the provisions related to
grandfathering and the additional
exemptions were developed in response
to comments and are consistent with the
exceptions in the original proposed rule.
As explained in Section III of this
preamble, the requirements in this final
rule respond to the Subcommittee,
GAO, and OIG recommendations by
updating, enhancing, clarifying, and
codifying the Order 3 requirements to
reflect changes in technology, industry
practice, and applicable statutory
requirements. The final rule also
responds to comments received during
the public comment period on the

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proposed rule.7 In aggregate, the
provisions in the final rule help ensure
that the production of Federal and
Indian (except Osage Tribe) oil and gas
is adequately accounted for. By
replacing the patchwork of guidance
developed by BLM state and field
offices, the final rule also provides
operators with a level of consistency as
to the requirements applicable to their
operations on Federal and Indian
(except Osage Tribe) lands nationwide.
The Department of the Interior
(Department) plays the critical role of
ensuring that the country’s oil and gas
assets are carefully developed and that
the American people, Indian tribes and
individual allottees receive fair
compensation when these assets are
leased and developed. A key part of this
role consists of providing reasonable
assurance that Federal and Indian oil
and gas are accurately measured and
that measurement efforts undertaken by
the private companies developing these
resources are held to high standards.
II. Overview of the Final Rule, Sectionby-Section Analysis, and Response to
Comments
A. General Overview of the Final Rule
As discussed in the background
section of this preamble, the BLM’s
rules concerning site security and
production accountability found in
Order 3 have not kept pace with
industry standards and practices,
statutory requirements, or applicable
measurement technology and practices.
This final rule enhances the BLM’s
overall production accountability efforts
by addressing these concerns and will
ensure that the oil and gas produced
from Federal and Indian (except Osage
Tribe) leases is adequately accounted
for, ultimately ensuring that all royalties
due are paid. The following table
provides an overview of the changes
between the proposed rule and this final
rule. A similar chart explaining the
differences between the proposed rule
and Order 3 appears in the proposed
rule at 80 FR 40771.
7 As explained in the preamble to the proposed
rule, the proposal was developed based, in part, on
feedback received during a series of public meetings
held by the BLM on April 24 and 25, 2013. The
BLM also held public meetings and accepted
comments in December 2015.

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Proposed rule
43 CFR 3161.1(e)

Jurisdiction ......

43 CFR 3162.4–1(d)
and reports.

Well records

43 CFR 3161.1(b)

Substantive changes

Jurisdiction ....

43
CFR
3162.4–1(d)
records and reports.

Well

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

43 CFR 3163.2

43 CFR 3163.2(a)(l)

Civil penalties

43 CFR 3163.2(a)(1)
alties.

Civil pen-

43 CFR 3163.2(b)(l)

Civil penalties

43 CFR 3163.2(b)(l)
alties.

Civil pen-

43 CFR 3163.2(b)(2)
alties.

Civil pen-

43 CFR 3163.2(b)(2)
alties.

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Final rule

Civil pen-

Generally ...........

43 CFR 3163.2(d) Civil penalties.
Proposed as part of the Order 5
rulemaking.

43 CFR 3163.2(d)

Civil penalties

43 CFR 3163.2(e) Civil penalties.
Proposed as part of the Order 5
rulemaking.

43 CFR 3163.2(e)

Civil penalties

43 CFR 3163.2(f) Civil penalties.
Proposed as part of the Order 5
rulemaking.

43 CFR 3163.2(f)

Civil penalties

43 CFR 3165.3(a) Notice, State
Director review and hearing on
the record.

43 CFR 3165.3(a) Notice, State
Director review and hearing on
the record.

43 CFR 3170.3
acronyms.

43 CFR 3170.3
acronyms.

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The final rule removes a provision from the proposed rule that could
have unintentionally extended the regulations in part 3160 to State
or private tracts committed to a federally approved unit or CA.
In its place, the BLM clarifies that the regulations under part 3170, including subparts 3173, 3174, and 3175, relating to site security,
measurement, reporting of production and operations, and assessments or penalties for non-compliance with such requirements,
apply to all wells and facilities on State or privately owned lands
committed to a unit or CA, which includes Federal or Indian lease
interests, notwithstanding any contrary provision of the unit or communization agreement.
Consistent with the proposed rule, paragraph (d) has been revised to
incorporate the new records-retention period for Federal leases established by the 1996 amendments to Federal Oil and Gas Royalty
Management Act (FOGRMA), 30 U.S.C. 1701 et seq. In the final
rule, that provision has been restructured consistent with the
changes in paragraphs (c) through (e) of § 3170.7.
The changes being made as part of this rule are a combination of
the changes proposed as part of this rulemaking effort and the proposed rule to update and replace Order 5 (80 FR 61645). These
changes also reflect the modifications made by the BLM’s interim
final rule—Onshore Oil and Gas Operations—Civil Penalties Inflation Adjustments (81 FR 41860) (the ‘‘Civil Penalty Rule’’)—that
updates the various daily penalty maximums in this section.
Paragraph (a)(2) of the proposed rule is carried forward into the final.
The final rule deletes existing paragraphs (g) and (j) in their entirety and redesignates existing paragraph (i) as paragraph (g).
The final rule revises paragraph (a)(1) of the proposed rule to clarify
that this section applies to ‘‘any person,’’ as opposed to limiting it
to ‘‘operating rights owner or operator.’’ This change was proposed
as part of the Order 5 rulemaking and conforms the regulation to
the applicable statutory authority.
The final rule changes the references in the proposed rule to ‘‘operating rights owner, operator, purchaser, or transporter’’ to just ‘‘the
person’’ consistent with the change to paragraph (a)(1) to reference ‘‘any person.’’ Paragraph (b)(1) of the final also reflects the
increase in maximum daily penalty from $500 to $1,031 made by
the BLM’s Civil Penalty Rule.
The final rule changes the references in the proposed rule to ‘‘operating rights owner, operator, purchaser, or transporter’’ to just ‘‘the
person’’ consistent with the change to paragraph (a)(1) to reference ‘‘any person.’’ Paragraph (b)(2) of the final rule also reflects
the increase in the maximum daily penalty from $5,000 to $10,314
made by the BLM’s Civil Penalty Rule.
Consistent with the proposed rule to update and replace Order 5, the
final rule removes the regulatory cap on civil-penalty assessments.
It also reflects the increase in maximum daily penalty from $500 to
$1,031 made by the BLM’s Civil Penalty Rule. Finally, it moves the
substance of existing paragraph (k) to paragraph (d). As a result,
paragraph (k) is removed.
Consistent with the proposed rule to update and replace Order 5, the
final rule removes the regulatory cap on civil penalty assessments
and reflects the increase in maximum daily penalty from $10,000
to $20,628 made by the BLM’s Civil Penalty Rule.
Consistent with the proposed rule to update and replace Order 5, the
final rule removes the regulatory cap on civil penalty assessments
and reflects the increase in the maximum daily penalty from
$25,000 to $51,570 made by the BLM’s Civil Penalty Rule.
The final rule clarifies in paragraph (a) that any person is subject to
written notice or order by the authorized officer (AO) whenever
they fail to comply with any provisions of the lease, the regulations
in this part, applicable orders or notices, or any other appropriate
order of the AO. The proposed rule made this provision applicable
only to an operating rights owner or operator, as appropriate.
New definitions have been added for the terms ‘‘averaging period,’’
‘‘bias,’’ and ‘‘tampering’’ in response to comments received and
additional internal reviews.
In the final rule, the acronym Btu (British thermal unit) is moved from
§ 3173.1 to this section, and new acronyms—S&W (sediment and
water) and LACT (lease automatic custody transfer), are included
because they are used across multiple subparts in part 3170.

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Proposed rule

Final rule

43 CFR 3170.6(a)(2)

Variances ....

43 CFR 3170.6(a)(2)

Variances

43 CFR 3170.6(a)(3)

Variances ....

43 CFR 3170.6(a)(3)

Variances

43 CFR 3170.7(c) Required recordkeeping, records retention,
and records submission.
43 CFR 3170.7(d) Required recordkeeping, records retention,
and records submission.
43 CFR 3170.7(e) Required recordkeeping, records retention,
and records submission.

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Substantive changes

43 CFR 3170.7(c)(1) & (c)(2) Required recordkeeping, records
retention, and records submission.
43 CFR 3170.7(d)(1) & (d)(2)
Required
recordkeeping,
records retention, and records
submission.
43 CFR 3170.7(e)(1) & (e)(2)
Required
recordkeeping,
records retention, and records
submission.

43 CFR 3170.7(g) Required recordkeeping, records retention,
and records submission.

43 CFR 3170.7(g) Required recordkeeping, records retention,
and records submission.

3170.8

Appeal procedures ............

3170.8(a) & (b)
dures.

3173.1

Definitions and acronyms ..

3173.1

Appeal proce-

Definitions and acronyms

43 CFR 3173.3(a) Oil measurement system components—seals.

43 CFR 3173.3(a) Oil measurement system components—
seals.

43 CFR 3173.6
operations.

43 CFR 3173.6
operations.

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Final paragraph (a)(2) adds a sentence that encourages operators to
simultaneously submit variance requests and plans or applications
if those plans or applications are contingent upon the BLM approving the variance requests.
Final paragraph (a)(3) clarifies the process operators must use to
submit their variance requests to the BLM—via WIS, or, if the operator is a small business without access to the Internet, to the
BLM office having jurisdiction over the lease, unit, or CA.
Paragraph (c) did not change substantively, but is split into two paragraphs. Paragraph (c)(1) states that records must be maintained
for at least 7 years, and paragraph (c)(2) codifies the applicable
statutory requirements for further retention beyond 7 years.
Paragraph (d) did not change substantively, but is split into two paragraphs. Paragraph (d)(1) states that records must be maintained
for at least 6 years, and subparagraph (d)(2) codifies the applicable statutory requirements for further retention beyond 6 years.
The final rule moves paragraph (e)(2) of the proposed rule to (e)(1)
and removes the phrase ‘‘or until the Secretary or his designee releases the record holder from the obligation to maintain the
records, whichever is later.’’
The phrase in paragraph (e)(1) of the proposed rule—‘‘but a judicial
proceeding or demand is not commenced within 7 years after the
records are generated, the record holder must retain all records regarding production from the unit or CA until the Secretary or his
designee releases the record holder from the obligation to maintain
the records’’—is moved to its own paragraph (e)(2).
The final rule is revised to require record holders to include the FMP
number or the lease, unit PA, or CA number, along with a unique
equipment identifier (e.g., a unique tank identification number and
meter station number), on all their records.
The language from the proposed rule is moved to a new paragraph
(a) and a new paragraph (b) is added that creates a separate appeal process for decisions made by the BLM, based on a recommendation from the Production Measurement Team (PMT).
Under paragraph (b), a party may file a request for discretionary
review by the Assistant Secretary for Land and Minerals Management (ASLM). Paragraph (b) also provides that the ASLM may delegate this review function.
The final rule adds new definitions for the terms ‘‘commingling and
allocation approval (CAA),’’ ‘‘free water,’’ ‘‘permanent measurement
facility,’’ ‘‘payout period,’’ and ‘‘royalty net present value’’ in response to comments on the proposed rule.
The term ‘‘low volume property’’ is replaced with the term ‘‘economically marginal property,’’ and the definition has also been modified.
Lastly, the definition of the term ‘‘land description’’ is modified to be
consistent with the well and facility identification requirements contained in § 3162.6 of the final rule.
CAA (commingling and allocation approval) is removed from the acronym list because the acronym is introduced in the definition section; BIA (Bureau of Indian Affairs) is added to the list of acronyms.
The requirement in paragraph (a)(5) that flow computers be effectively sealed is removed and instead a new requirement is added
in paragraph (a)(6) that a LACT or CMS must be effectively
sealed.
Paragraph (a)(7) in the final rule clarifies that sealing the back pressure valve refers to the ‘‘pressure adjustment’’ on the valve, not
the valve itself.
The final rule removes the requirements that, when draining water
from a production storage tank, operators, purchasers, or transporters document the FMP number associated with the tank, the
time for when the opening and closing gauges took place, and the
name of the person and company draining the tank.
The final rule also clarifies that the gauging operation may be performed manually or automatically, to accommodate the use of
automatic tank gauging systems. If gauging is performed manually,
the final rule no longer specifies that the color cut method be used
for measurement. It leaves the method for capturing the measurement up to the operator and simply requires the accuracy of the
measurement to be to the nearest 1⁄2 inch.

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Proposed rule

Final rule

Substantive changes

43 CFR 3173.7(a) Hot oiling,
clean-up, and completion operations.

43 CFR 3173.7(a) Hot oiling,
clean-up, and completion operations.

43 CFR 3173.7(d) Hot oiling,
clean-up, and completion operations.

43 CFR 3173.7(d) Hot oiling,
clean-up, and completion operations.

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

43 CFR 3173.8(b)(8) Report of
theft or mishandling of production.

43 CFR 3173.9(a) Required recordkeeping for inventory and seal
records.

43 CFR 3173.9(a) Required recordkeeping for inventory and
seal records.

43 CFR 3173.10(b) Form 3160–5,
Sundry Notices and Reports on
Wells.

43 CFR 3173.10(b) Form 3160–
5, Sundry Notices and Reports
on Wells.

43 CFR 3173.11(c)(10)(i)
cility diagram.

43 CFR 3173.11(c)(9)(i)
cility diagram.

Site fa-

Site fa-

43 CFR 3173.11(c)(11)
diagram.

Site facility

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

43 CFR 3173.11(c)(1)
diagram.

Site facility

43 CFR 3173.11(d)(1)
ity diagram.

Site facil-

43 CFR 3173.11(d)
diagram.

Site facility

43 CFR 3173.11(d)(2)
ity diagram.

Site facil-

43 CFR 3173.11(e)
diagram.

Site facility

43 CFR 3173.11(e)(1)
ity diagram.

Site facil-

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The final rule also clarifies that during the opening gauge operations,
the total observed volume (TOV) and free-water measurements
must be documented, while during closing gauge operations only
the TOV must be measured, since the water will have already
been drained.
The final rule removes the requirements that operators document the
FMP number associated with the tank or group of tanks involved in
a hot oiling, clean-up, or completion operation, the time at which
the opening and closing gauges took place, and the name of the
person and company removing production from the tank.
The final rule also clarifies that the gauging operation may be performed manually or automatically; the accuracy of the measurement taken in either case must be to the nearest 1⁄2 inch.
Paragraph (d) of the final rule clarifies that when reporting production
used during hot oiling, line flushing, or completion operations, the
operator’s report must include ‘‘the period covering the production
in question.’’
In the final rule, a new reporting item is added to the list of information that an operator must include in their incident report: ‘‘Whether
the incident was reported to local law enforcement agencies and
company security.’’ This change was made in response to comments.
The final rule provides greater flexibility in how an operator determines the monthly volumes of production in their tanks. Unlike the
proposed rule, where the operator was required to measure the
TOV at the end of each calendar month, the final rule allows the
operator to either perform the inventory within +/¥ 3 days of the
last day of the calendar month or estimate the end of month inventory based on daily production that takes place between two measured inventories that are not more than 31 days, nor less than 20,
days apart. An equation has also been provided if the operator
elects to estimate the end-of-month inventory instead of performing
the inventory at the end of the calendar month.
Paragraph (b) now clarifies the process operators must use to submit
their Sundry Notices to the BLM Office having jurisdiction over the
lease, unit, or CA—namely via the applicable BLM electronic filing
system, unless the operator is a small business without access to
the Internet.
In paragraph (c)(9)(i), the final rule removes the requirement to identify the equipment manufacturer’s name, rated use, and equipment
serial number for each engine, motor, or major component powered by production from the lease, unit PA, or CA.
Proposed paragraph (c)(11) is eliminated. The final rule does not require the diagram to include a signature block to certify accuracy
and completeness of the information contained within this site facility diagram.
Paragraph (c)(1) is eliminated in its entirety and is replaced with
paragraph (d)(1), which now requires operators to submit site facility diagrams for new facilities within 30 days after the BLM assigns
an FMP to a facility. This is a change from the proposed rule,
which required operators to submit diagrams for new facilities within 30 days after completing construction of the new facilities.
Paragraph (d)(2), which applies to facilities that require FMP numbers and are in service before the effective date of this final rule, is
changed. Under the final rule, if such a facility already has a diagram on file with the BLM that meets the minimum site-facility-diagram requirements of Order 3, the operator is not initially required
to submit a new diagram meeting the requirements of this section.
However, the operator must submit a new site facility diagram for
the facility that complies with this section within 30 days after the
facility is modified, a non-Federal facility located on a Federal
lease or federally approved unit or communitized area is constructed or modified, or there is a change in operator.
Paragraph (e)(1) of the final rule applies to new facilities in service
after the effective date of the final rule that do not require an FMP
number (e.g., a water disposal facility). This paragraph is revised
to require the operator of such a facility to submit a new site facility
diagram within 30 days after that facility becomes operational.

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81362

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Proposed rule

Final rule

Substantive changes

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

43 CFR 3173.11(e)(2)
ity diagram.

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

43 CFR 3173.11(f)
diagram.

43 CFR 3173.12(d) Applying for a
facility measurement point.

43 CFR 3173.12(d) Applying for
a facility measurement point.

43 CFR 3173.12(e) Applying for a
facility measurement point.

43 CFR 3173.12(e) Applying for
a facility measurement point.

43 CFR 3173.12(e)(1) to (e)(3)
Applying for a facility measurement point.

43 CFR 3173.12(e)(1) to (e)(3)
Applying for a facility measurement point.

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

43 CFR 3173.12(e)(4) Applying
for a facility measurement point.

43 CFR 3173.12(e)(5) Applying for
a facility measurement point.

43 CFR 3173.12(e)(6) Applying for
a facility measurement point.

43 CFR 3173.12(f)(3) Applying for
a facility measurement point.

43 CFR 3173.12(f)(3) Applying
for a facility measurement point.

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A new paragraph (e)(2) is added, which applies to facilities that do
not require an FMP number and are in service before the effective
date of the final rule, is added to the final rule. If such a facility already has a diagram on file with the BLM that meets the minimum
requirements of Order 3, the operator is not initially required to
submit a diagram meeting the requirements of this section. However, the operator must submit a new site facility diagram for the
facility that complies with this section within 30 days after the facility is modified, a non-Federal facility located on a Federal lease or
federally approved unit or communitized area is constructed or
modified, or there is a change in operator.
The BLM added a new paragraph (f), which requires operators to
submit updated site facility diagrams on an ongoing basis within 30
days after that facility is modified, a non-Federal facility located on
a Federal lease or federally approved unit or communitized area is
constructed or modified, or there is a change in operator.
Paragraph (d) of this section applies to measurement facilities that
come into service after the effective date of the final rule. This
paragraph is changed to clarify that only ‘‘permanent’’ measurement facilities require an FMP number, and not temporary measurement equipment used during well-testing operations. New language has also been added that requires the operator to ‘‘apply’’
for FMP approval (as opposed to ‘‘obtaining’’ FMP approval, as in
the proposed rule) before removing any production from that facility. Finally, this paragraph clarifies that an operator must use the
lease, unit PA, or CA number for reporting production to ONRR,
until the BLM assigns an FMP number. After the BLM assigns the
FMP number, the operator must use the FMP number for all reporting to ONRR.
The final rule clarifies that the requirement to apply for an FMP for
facilities in service before the effective date of the final rule applies
only to permanent measurement facilities. The final rule also clarifies that the production levels that serve as the triggers for when
an operator must apply for an FMP for an existing facility are
based on the production level of any one of the leases, unit PAs,
or CAs, whether or not they are part of a CAA.
The deadlines for applying for FMP numbers have been changed
from 9 months, 18 months, and 27 months in the proposed rule to
1 year, 2 years, and 3 years in the final rule for existing producing
leases, unit PAs, and CAs. The deadlines are based on the production levels of any one of the leases, unit PAs, or CAs, which
have also been modified from the proposed rule. Under the final
rule, those facilities that produce:
1. 10,000 Mcf or more for gas or 100 bbl of oil or more—must file
within 1 year of the effective date;
2. 1,500 Mcf or more but less than 10,000 Mcf of gas per month or
10 bbl or more, but less than 100 bbl of oil per month—must file
within 2 years; and
3. Less than 1,500 Mcf of gas per month or less than 10 bbl of oil
per month—must file within 3 years.
A new paragraph (e)(4) is added to the final rule requiring the operator of a stand-alone lease, unit PA, or CA that has not produced
for a year or more before the effective date of the final rule to
apply for an FMP prior to the resumption of production.
Paragraph (e)(6) was paragraph (e)(5) in the proposed rule, but is renumbered because of the addition of a new paragraph (e)(4). The
final rule also clarifies that if the operator applies for an FMP within
the timeframes outlined in paragraphs (e)(1) to (e)(3), then the operator may continue using the lease, unit PA, or CA number for reporting production to ONRR, until the effective date of the BLM-assigned FMP number.
The final rule is revised and no longer requires operators to identify
the names and the manufacturer, model, and serial number of
each measurement component.
Paragraph (f)(3)(i) now requires operators to submit the following information on gas measurement equipment:
• The operator/purchaser/transporter unique station number;
• For primary elements, the meter tube size or serial number; and
• The type of secondary device, whether it is mechanical or electronic.

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Proposed rule

Final rule

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Substantive changes

43 CFR 3173.12(f)(4) Applying for
a facility measurement point.

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

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

43 CFR 3173.12(f)(5) Applying
for a facility measurement point.
43 CFR 3173.12(g) Applying for
a facility measurement point.

43 CFR 3173.12(g) Applying for a
facility measurement point.

43 CFR 3173.12(h) Applying for a
facility measurement point.
43 CFR 3173.13(a) and (b) Requirements for approved facility
measurement points.

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

43 CFR 3173.13(c) Requirements
for approved facility measurement
points.

43 CFR 3173.13(a) Requirements for approved facility
measurement points.

43 CFR 3173.13(d)(1) and (d)(2)
Requirements for approved facility measurement points.

43 CFR 3173.13(b)(1) Requirements for approved facility
measurement points.

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

43 CFR 3173.13(b)(2) Requirements for approved facility
measurement points.

43 CFR 3173.13(d)(3) Requirements for approved facility measurement points.
43 CFR 3173.14(a) Conditions for
commingling and allocation approval (surface and downhole).

43 CFR 3173.13(b)(3) Requirements for approved facility
measurement points.
43 CFR 3173.14(a) Conditions
for commingling and allocation
approval
(surface
and
downhole).

3173.14(a)(1)(i) Conditions
for
commingling and allocation approval (surface and downhole).

3173.14(a)(1)(i) Conditions
for
commingling and allocation approval (surface and downhole).

3173.14(a)(1)(ii) Conditions
for
commingling and allocation approval (surface and downhole).

3173.14(a)(1)(ii) Conditions
for
commingling and allocation approval (surface and downhole).

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Paragraph (f)(3)(ii) now requires operators who measure oil tanks by
tank gauge to identify the equipment by either the tank number or
tank serial number (The proposed rule required operators to provide both pieces of information.). The final rule adds a new requirement that operators specify the tank size(s), in barrels or gallons.
Paragraphs (f)(3)(iii) and (f)(3)(iv) of the proposed rule have been
combined into a new paragraph (f)(3)(iii). This paragraph now requires operators who measure oil using LACT systems or CMSs to
identify the associated oil tank number(s) or tank serial number(s),
the size of the tank(s) in barrels or gallons, and whether the equipment used is a LACT system or CMS.
The final rule removes the requirement in paragraph (f)(4) to identify
the gas sampling method for gas measurements. Paragraph (f)(5)
in the proposed rule is now renumbered to paragraph (f)(4) in the
final rule and is unchanged.
New paragraph (f)(5) adds to the list of information that operators
must include in their FMP request.
Language is added to clarify that FMP requests—if they are submitted concurrently with requests for off-lease measurement or
commingling and allocation approvals—must be submitted separately from the other requests.
Paragraph (h) is eliminated from the final rule because it was determined to be redundant.
The final rule removes the requirement for operators to stamp or
stencil the FMP number on a fixed plate onto various pieces of oil
and gas measurement equipment and to maintain the number in a
legible condition.
The final rule removes the requirement for operators to begin using
the FMP number for recordkeeping on the first day of the month
after the FMP number is assigned.
A new provision is incorporated into paragraph (a) in the final rule
that requires operators of existing facilities to begin using their
FMP numbers for reporting production to the Office of Natural Resources Revenue (ONRR) on their Oil and Gas Operations Report
(OGOR) for the fourth production month after the BLM assigns the
FMP numbers. Operators of new facilities in service after this rule’s
effective date must start using their FMP numbers for production
reporting on their OGORs for the first production month after the
BLM assigns the FMP numbers.
Paragraph (b)(1) in the final rule requires operators to notify the BLM
via a Sundry Notice within 30 days after changing or modifying an
FMP (the proposed rule gave operators 20 business days). This
paragraph also describes the types of changes that require the operator to submit a Sundry Notice, e.g., changes in the metering
equipment or the wells served by the FMP. Paragraph (b)(1) also
clarifies that temporary modifications, such as those made for
maintenance purposes, do not require the filing of a Sundry Notice.
The final rule removes the requirement in proposed paragraph
(d)(2) that operators provide information about the old and new
meter manufacturer, serial number(s), and the owner’s name.
The final rule adds a new requirement that the operator’s description
of any modifications being made include details, such as the primary element, secondary element, LACT/CMS meter, tank number(s), and wells or facilities using the FMP.
Final paragraph (b)(3) removes the requirement that operators specify why a change was made to a piece of equipment.
Final paragraph (a) is modified so that it explicitly states that the criteria the BLM uses to approve a commingling application under
this paragraph is when the proposed allocation method used for
commingled measurement does not have the potential to affect the
BLM’s determination of the total volume or quality of the production
on which royalty is owed for all of the Federal or Indian leases,
unit PAs, or CAs which are proposed for commingling.
Paragraph (a)(1)(i) clarifies that commingling is permissible when it
involves properties that contain 100 percent Federal mineral interests, the same fixed royalty rate, and the same revenue distribution.
Paragraph (a)(1)(ii) clarifies that commingling is permissible when it
involves properties that are wholly owned by the same tribe and
have the same fixed royalty rate.

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81364

Federal Register / Vol. 81, No. 222 / Thursday, November 17, 2016 / Rules and Regulations
Proposed rule

Final rule

Substantive changes

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

3173.14(a)(1)(iii) Conditions for
commingling and allocation approval (surface and downhole).

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

3173.14(a)(1)(iv) Conditions for
commingling and allocation approval (surface and downhole).

3173.14(a)(2) Conditions for commingling and allocation approval
(surface and downhole).

3173.14(a)(2) Conditions
for
commingling and allocation approval (surface and downhole).

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

3173.14(b) Conditions for commingling and allocation approval
(surface and downhole).

3173.14(b)(1) Conditions for commingling and allocation approval
(surface and downhole).

3173.14(b)(1) Conditions
for
commingling and allocation approval (surface and downhole).

3173.14(b)(2) Conditions for commingling and allocation approval
(surface and downhole).

3173.14(b)(2) Conditions
for
commingling and allocation approval (surface and downhole).

3173.14(b)(3) Conditions for commingling and allocation approval
(surface and downhole).

3173.14(b)(3) Conditions
for
commingling and allocation approval (surface and downhole).

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

3173.14(b)(4) Conditions
for
commingling and allocation approval (surface and downhole).

43 CFR 3173.15(a)(1) and (a)(2)
Applying for a commingling and
allocation approval.

43 CFR 3173.15(a) Applying for
a commingling and allocation
approval.

3173.15(a)(2) Applying for a commingling and allocation approval.

43 CFR 3173.15(b) .......................

43 CFR 3173.15(b) Applying for a
commingling and allocation approval.

43 CFR 3173.15(c) Applying for
a commingling and allocation
approval.

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

43 CFR 3173.15(d) .......................

A new paragraph (a)(1)(iii) is added which clarifies that commingling
of Federal unit PAs or CAs is permissible even if Federal ownership is not 100 percent, so long as the properties have the same
proportion of Federal ownership, royalty rate and revenue distribution.
A new paragraph (a)(1)(iv) is added which clarifies that commingling
of tribal unit PAs or CAs is permissible even if tribal ownership is
not 100 percent, so long as the properties have the same proportion of tribal interest and fixed royalty rate.
This paragraph recognizes there are cases where multiple operators
are party to a CAA and clarifies that there must be a signed agreement amongst the operators about the allocation methodology for
the commingling proposal.
To complement paragraphs (a)(1)(iii) and (a)(1)(iv) to this section,
paragraph (b) clarifies that the BLM may consider commingling
that involves production from properties with different royalty rates
or revenue distributions, or multiple mineral ownerships.
This paragraph is revised to reflect the BLM’s switch from the term
‘‘low-volume property’’ to ‘‘economically marginal property.’’ It also
clarifies that if the BLM determines that a Federal or Indian lease,
unit PA, or CA included in a CAA ceases to be an economically
marginal property, then (b)(1) is no longer met.
In the proposed rule, paragraph (b)(2) allowed operators to be exempted from the BLM’s commingling standards if there are overriding considerations that indicated approval of the CAA was appropriate in spite of royalty impacts. In the final rule, this provision
is replaced with a new exemption if the average monthly production rate over the previous 12 months for each Federal or Indian
lease, unit PA, and CA included in the CAA is less than 1,000 Mcf
of gas per month or 100 bbl of oil per month.
Paragraph (b)(2) from the proposed rule is now renumbered as paragraph (b)(5).
New paragraph (b)(3) of the final rule adds a new exemption that allows the BLM to consider approval of a commingling proposal that
includes Indian leases, unit PAs, or CAs that has been authorized
under tribal law or otherwise approved by a tribe.
In the proposed rule, paragraph (b)(3) required the BLM to ensure
that approval of a CAA in cases where the CAA would be exempted from the standards in this rule was in the public interest. This
paragraph is eliminated and incorporated into the new paragraph
(b)(5).
A new exemption is included as part of the final rule that allows the
BLM to consider a commingling proposal if it covers the downhole
commingling of production from multiple formations where the BLM
has determined that the proposed commingling is an acceptable
practice for the purpose of achieving maximum ultimate economic
recovery and resource conservation.
Paragraph (a) of the final rule eliminates the numbering for paragraph (a)(1) in the proposed rule, and clarifies that if off-lease
measurement is a feature of the commingling proposal, then a
separate Sundry Notice requesting approval for off-lease measurement is not necessary as long as the off-lease measurement request is included as part of the commingling application and the information required in § 3173.23(b) through (e) and, where applicable, § 3173.23(f) through (i) is included in the commingling application.
Paragraph (a)(2) from the proposed rule is renumbered to a new
paragraph (b) and clarifies that submission of a completed Sundry
Notice for approval of off-lease measurement is required if any of
the proposed FMPs are outside the boundaries of any lease, unit
PA, or CA whose production would be commingled. This paragraph clarifies that this requirement does not apply if the circumstances under paragraph (a) of this section are applicable.
In addition to requiring operators to provide their proposed allocation
agreement, final paragraph (c) is revised to require operators to
provide an allocation methodology, along with an example of how
the methodology is to be applied.
Requires the operator to include a list of all Federal or Indian lease,
unit PA, or CA numbers in the proposed CAA, specifying the type
of production (i.e., oil, gas, or both) for which commingling is requested.

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81365

Proposed rule

Final rule

Substantive changes

43 CFR 3173.15(d) Applying for a
commingling and allocation approval.

43 CFR 3173.15(e) Applying for
a commingling and allocation
approval.

43 CFR 3173.15(e) Applying for a
commingling and allocation approval.

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

43 CFR 3173.15(f)
commingling and
proval.
43 CFR 3173.15(g)
commingling and
proval.

Applying for a
allocation ap-

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

Applying for a
allocation ap-

43 CFR 3173.15(f) Applying for a
commingling and allocation approval.

43 CFR 3173.15(h) Applying for a
commingling and allocation approval.

43 CFR 3173.15(g) Applying for
a commingling and allocation
approval.

43 CFR 3173.15(i) Applying for a
commingling and allocation approval.
None ................................................

43 CFR 3173.15(h) Applying for
a commingling and allocation
approval.
43 CFR 3173.15(i) Applying for a
commingling and allocation approval.

Final paragraph (e) continues to require operators to provide maps
with their commingling and allocation requests, but the information
requirements for the maps are changed. Please note that in the
final rule, paragraphs (d)(2) and (d)(3) have been consolidated and
renumbered as paragraphs (e)(1) and (e)(2) in the final rule. The
final rule also reduces the amount of information that must be submitted with a commingling application relative to the proposed
rule.8
Proposed paragraph (e), which required submission a site facility diagram showing any changes to existing diagrams if changes were
being proposed to an existing facility, is eliminated from the final
rule.
Proposed paragraph (f), which required submission of a schematic or
engineering drawing for all new proposed facilities, is eliminated
from the final rule.
Paragraph (f) of the final rule (paragraph (g) of the proposed rule) is
revised to clarify that operators must submit a surface use plan of
operations if new surface disturbance is proposed for the FMP and
its associated facilities, if those facilities are located on BLM-managed land within the boundaries of the lease, units, or
communitized areas whose production will be commingled.
Final paragraph (g) clarifies that the operator must submit a right-ofway grant application (Standard Form 299) if the proposed FMP is
on a pipeline or is a meter or storage tank that entails new surface
disturbance located on BLM-managed land outside any of the
leases, units, or communitized areas whose production would be
commingled.
Final paragraph (h) is essentially the same as proposed paragraph (i)
but is renumbered.

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

43 CFR 3173.15(j) .........................

43 CFR 3173.15(k) Applying for a
commingling and allocation approval.
43 CFR 3173.16(a) Existing commingling and allocation approvals.

43 CFR 3173.15(k) Applying for
a commingling and allocation
approval.
43
CFR
3173.16(a) Existing
commingling and allocation approvals.

43 CFR 3173.16(b) Existing commingling and allocation approvals.

43
CFR
3173.16(b) Existing
commingling and allocation approvals.

43 CFR 3173.16(c) Existing commingling and allocation approvals.

43 CFR 3173.16(b)(2) Existing
commingling and allocation approvals.

43 CFR 3173.16(e) Existing commingling and allocation approvals.

43
CFR
3173.16(c) Existing
commingling and allocation approvals.

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A new final paragraph (i) has been added to clarify that the operator
must submit a right-of-way grant application to the appropriate BIA
office if any of the proposed surface facilities are on Indian land
outside the lease, unit, or communitized area from which the production would be commingled.
Requires the operator to include documentation demonstrating that
each of the leases, unit PAs, or CAs proposed for inclusion in the
CAA is producing or capable of production in paying quantities.
Final paragraph (k) clarifies that gas analysis and oil gravity data is
not needed if the CAA falls under § 3173.14(a).
This section is extensively rewritten from the proposed rule based on
comments received. Final paragraph (a) includes new provisions
that grandfather the following types of existing commingling operations and their associated off-lease measurement approvals,
where applicable, that are in effect prior to the effective date of the
final rule:
• Existing CAAs involving downhole commingling that includes Federal or Indian leases, unit PAs, or CAs; or
• Existing CAAs for surface commingling whose average production
rate over the previous 12 months for each Federal or Indian lease,
unit PA, and CA included in the CAA is less than 1,000 Mcf of gas
per month or 100 bbl of oil per month.
A new provision has been added to paragraph (b), which clarifies
that if the grandfathering conditions in paragraph (a) of this section
are not met, then the existing CAA must meet the minimum standards and requirements for a CAA under § 3173.14 of the final rule.
This section also clarifies that the AO will notify the operator in writing of any inconsistencies or deficiencies with an existing CAA.
When the AO is satisfied that the operator has corrected any inconsistencies or deficiencies, the AO will terminate the existing
CAA and grant a new CAA based on the operator’s corrections.
Paragraph (b)(2) of the final rule clarifies that the AO may terminate
an existing CAA and grant a new CAA with new or amended
COAs to make the approval consistent with the requirements for
CAAs under § 3173.14 of the final rule. Under the proposed rule
the AO could simply impose new or amended COAs to an existing
commingling approval.
Proposed paragraph (e) is now paragraph (c) and clarifies that any
new allocation percentages resulting from the new CAA will only
apply from the effective date of the CAA forward.

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Federal Register / Vol. 81, No. 222 / Thursday, November 17, 2016 / Rules and Regulations
Proposed rule

Final rule

Substantive changes

43 CFR 3173.18(a) Modification of
a commingling and allocation approval.

43 CFR 3173.18(a) Modification
of a commingling and allocation
approval.

43 CFR 3173.18(b) Modification of
a commingling and allocation approval.

43 CFR 3173.18(b) Modification
of a commingling and allocation
approval.

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

43 CFR 3173.20(a) Terminating a
commingling and allocation approval.

43 CFR 3173.18(c) Modification
of a commingling and allocation
approval.
43 CFR 3173.20(c) Terminating
a commingling and allocation
approval.

Paragraph (a) is changed to require operators to modify a CAA
under certain circumstances. The final rule no longer includes ‘‘a
change in operator’’ in the list of circumstances that warrant a CAA
modification.
Final paragraph (b)(2) includes a new requirement to describe not
only a new allocation methodology for oil and gas production, if appropriate, but also an allocation methodology for produced water
and an example of how the methodology is applied.
A new paragraph (c) is added that states that a change in operator
does not trigger the need to modify a CAA.

43 CFR 3173.20(d) Terminating a
commingling and allocation approval.

43 CFR 3173.20(d) Terminating
a commingling and allocation
approval.

43 CFR 3173.20(e) Terminating a
commingling and allocation approval.

43 CFR 3173.20(e) Terminating
a commingling and allocation
approval.

43 CFR 3173.21(b) Combining
production downhole in certain
circumstances.

43 CFR 3173.21(b) Combining
production downhole in certain
circumstances.

43 CFR 3173.22(c) Requirements
for off-lease measurement.

43 CFR 3173.22(c) Requirements for off-lease measurement.

43 CFR 3173.23(a) Applying for
off-lease Measurement.

43 CFR 3173.23(a) Applying for
off-lease Measurement.

43 CFR 3173.23(c)(2) Applying for
off-lease Measurement.

43 CFR 3173.23(c)(2) Applying
for off-lease Measurement.

43 CFR 3173.23(d) Applying for
off-lease Measurement.

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

43 CFR 3173.23(e) Applying for
off-lease Measurement.

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

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The final rule redesignates and modifies proposed paragraph (a),
which allows any operator who is a party to a CAA to unilaterally
terminate the CAA.
New paragraph (c) in the final rule clarifies that it allows an operator
to terminate the CAA through the submission of a Sundry Notice to
the BLM. It also clarifies that the termination by one operator does
not terminate the CAA for all other operators, so long as the requirements of this part with respect to CAAs are still met as to the
remaining operators and they submit a Sundry Notice requesting a
new CAA as required by § 3173.20(e).
Paragraph (d) of the final rule clarifies that the BLM will notify all parties to a CAA the effective date of the termination and the inconsistencies or deficiencies with their CAA that serve as the reason(s) for termination.
The final rule also gives operators the opportunity to correct the inconsistencies or deficiencies, or provide additional information,
within 20 business days after receipt of the BLM’s notice. Otherwise, the CAA will be terminated.
Paragraph (e) of the final rule clarifies that if a CAA is terminated,
each lease, unit PA, or CA that was included in the CAA may require a new FMP number, or a new CAA may need to be applied
for. In such cases, operators will have 30 days to apply for a new
FMP number or CAA. Unlike the proposed rule—where operators
would have been required to revert back to separate measurement
for each lease, unit PA, or CA—the final rule allows the operator to
use the existing FMP number for production reporting until a new
FMP number is assigned or a new CAA is approved.
Paragraph (b) makes clear that combining production downhole from
different geologic formations on the same lease in a single well is
not considered to be commingling for production accounting purposes. This applies even in cases where the respective geologic
formations have different ownership. The proposed rule made this
distinction, which no longer applies in the final rule.
The final rule also clarifies that such activities are not subject to the
commingling standards and requirements contained in §§ 3173.14
through 3173.20.
Changes to this paragraph clarify that topographic and environmental
issues that make on-lease measurement physically impractical are
factors to be considered when deciding if off-lease measurement is
in the public interest.
The second sentence of proposed paragraph (a) is removed because
§ 3173.15(a) states that if off-lease measurement is a feature of
the CAA proposal, then a separate Sundry Notice is not necessary
as long as the information required under § 3173.23(b) through (e)
and, where applicable, § 3173.23(f) through (i), is included as part
of the request for approval of a CAA.
The final rule in this paragraph no longer requires location identification by land description, but does include a new requirement to
identify existing or proposed (to the extent known) FMPs.
Paragraph (d) of the proposed rule requiring operators to submit a
schematic or engineering drawing for all new proposed facilities is
deleted.
Paragraph (e) of the proposed rule, which required operators to submit as part of their off-lease measurement application, site facility
diagrams clearly showing any proposed change to current site facility diagrams for existing facilities is deleted.

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Federal Register / Vol. 81, No. 222 / Thursday, November 17, 2016 / Rules and Regulations
Proposed rule

Final rule

Substantive changes

43 CFR 3173.23(f) Applying for
off-lease Measurement.

43 CFR 3173.23(e) Applying for
off-lease Measurement.

43 CFR 3173.23(g) Applying for
off-lease Measurement.

43 CFR 3173.23(f) Applying for
off-lease Measurement.

43 CFR 3173.23(h) Applying for
off-lease Measurement.

43 CFR 3173.23(g) Applying for
off-lease Measurement.

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

43 CFR 3173.23(h) Applying for
off-lease Measurement.

3173.25(b) Existing approved offlease measurement.

3173.25(b) Existing approved offlease measurement.

3173.25(c) Existing approved offlease measurement.

3173.25(c) Existing approved offlease measurement.

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

43 CFR 3173.25(e) Existing approved off-lease measurement.

43 CFR 3173.25(e) Existing approved off-lease measurement.
43 CFR 3173.27(a) Termination of
off-lease measurement approval.

43 CFR 3173.25(f) Existing approved off-lease measurement.
43 CFR 3173.27(c) Termination
of off-lease measurement approval.
43 CFR 3173.27(a) Termination
of off-lease measurement approval.
43 CFR 3173.27(b) Termination
of off-lease measurement approval.

In the event there is a change in the ownership of the non-Federal
surface or of the measurement facilities, the final rule includes a
new 30-day deadline for when an operator must submit written
concurrence from the new owner that it will give the BLM unrestricted access to the off-lease measurement facility and the surface on which it is located to inspect the FMP and any associated
equipment.
Final paragraph (f) clarifies that if the proposed off-lease FMP is on a
pipeline or is a meter or storage tank, then a right-of-way grant application using Standard Form 299 must be submitted.
This paragraph also clarifies that this requirement applies only when
new surface disturbance is proposed for the FMP and its associated facilities are located on BLM-managed land.
Final paragraph (g) (re-lettered from paragraph (h)) clarifies that if
any of the proposed surface facilities are on Indian land outside
the lease, unit, or communitized area, then a right-of-way grant application filed under 25 CFR part 169 must be filed with the appropriate BIA office.
The final rule adds a new paragraph (h) that requires written approval from the appropriate surface-management agency if new
surface disturbance is proposed for the FMP and its associated facilities are located on Federal land managed by an agency other
than the BLM.
Paragraph (b) of the final rule has been revised to provide an opportunity for operators to request additional time to correct any inconsistencies or deficiencies that the AO identifies. This paragraph
also clarifies that the extension request must explain the factors
preventing the operator from timely compliance.
Paragraph (c) of the final rule clarifies that if new or amended conditions of approval (COAs) are necessary to make an existing offlease measurement approval consistent with the final rule’s standards, then the BLM could address that situation by terminating the
existing approval and issuing a new off-lease measurement approval with new or amended COAs.
A new paragraph (e) is added to the final rule, clarifying that if the
existing off-lease measurement approval under this section is consistent with the requirements under § 3173.22, then that existing
off-lease measurement is grandfathered and will be part of its FMP
approval.
Proposed paragraph (e) is re-lettered to paragraph (f).

43 CFR 3173.27(b) Termination of
off-lease measurement approval.
43 CFR 3173.27(c) Termination of
off-lease measurement approval.

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43 CFR 3173.27(d) Termination of
off-lease measurement approval.

43 CFR 3173.27(d) Termination
of off-lease measurement approval.

43 CFR 3173.29
sessments.

43 CFR 3173.29
sessments.

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Proposed paragraph (a) is deleted from the final rule and the provision in that paragraph allowing an operator to terminate off-lease
measurement is moved to paragraph (c).
Paragraphs re-lettered. No change.

Final paragraph (b) is changed to say the BLM will notify the operator in writing of any inconsistencies or deficiencies with its offlease measurement approval that serve as the reason(s) for termination.
The final rule is also changed to give the operator 20 business days
after receipt of the notification to correct the inconsistencies or deficiencies that the BLM identifies, or provide additional information
that the AO requests, or the off lease measurement approval terminates. The operator may request an extension of the 20-business-day timeframe.
Final paragraph (d) explains that if an off lease measurement approval is terminated, each lease, unit PA, or CA that was in the approval may require a new FMP number(s) or a new off lease
measurement approval. Operators will have 30 days to apply for a
new FMP number or off lease measurement approval. The final
rule allows operators to use the existing FMP number for production reporting until a new FMP number is assigned or a new off
lease measurement approval is approved.
The final rule exempts purchasers and transporters from the immediate assessments that will be imposed for certain instances of
non-compliance. In addition, the final rule modifies the description
of violations number 7 through 11.
• For violation number 7, the final rule clarifies that the applicable
regulation is § 3170.7, not § 3173.9(a)(1) and (a)(2).

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Federal Register / Vol. 81, No. 222 / Thursday, November 17, 2016 / Rules and Regulations
Proposed rule

Final rule

Substantive changes
• For violation 8, the final rule clarifies that an immediate assessment could result if operators fail to ‘‘apply for’’ the required FMP
approval. The proposed rule required operators to ‘‘obtain’’ FMP
approval.
• For violations 9, 10, and 11, the final rule clarifies that an immediate assessment could result if production is removed from a facility in operation after the effective of the final rule prior to receiving
BLM approval for off-lease measurement or commingling. For an
existing facility in service on or before the effective date of the final
rule, an immediate assessment could result if production is removed from a facility that does not already have an existing BLM
approval for off-lease measurement or commingling, if applicable.

Subpart 3170 and Related Provisions
B. Section-by-Section Analysis and
Response to Comments on Specific
Provisions

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This final rule is codified primarily in
a new 43 CFR subpart 3173 within a
new part 3170. The BLM is also issuing
final rules that update and replace
Order 4 (oil measurement) and Order 5
(gas measurement). Those final rules are
codified at new 43 CFR subparts 3174
and 3175, respectively, within the new
part 3170. Subpart 3170 of this final rule
contains definitions of certain terms and
provisions that are common to all three
rules (and to any other provisions
within part 3170), i.e., provisions
prohibiting by-pass of or tampering with
meters; procedures for obtaining
variances from the requirements of a
particular rule; requirements for
recordkeeping, records retention, and
submission; and administrative appeal
procedures.
In addition, this final rule makes
changes to various provisions in 43
CFR part 3160 and in 43 CFR 3161.1,
3162.3–2, 3162.4–1, 3162.6, 3162.7–1,
3163.2, and 3165.3. Public comments on
changes to the provisions in part 3160
are discussed in connection with the
new subparts 3170 or 3173 provisions to
which the particular comment relates.
Other comments on changes to
provisions in part 3160 are discussed at
the end of this Section-by-Section
analysis.
8 Specifically, the final rule no longer requires the
commingling application to include the following
items: (i) The land description of the FMP that will
be used to measure the commingled production; (ii)
Production facilities and flow lines proposed to be
installed to the extent known; and (iii) A map or
diagram showing all of the infrastructure-related
facilities that are part of the commingling proposal.
The final rule only requires identification of
existing or planned facilities, all wellheads, and
piping that will be included in the CAA, as well
as existing or proposed FMPs to be installed (if
known).

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Section 3170.1 Authority
Section 3170.1 of the final rule
identifies the various grants of
rulemaking authority in the Federal and
Indian mineral leasing statutes and
related statutes that give the Secretary
authority to promulgate this rule. As
explained in that section, the
Department is authorized to lease
Federal and Indian (except Osage Tribe)
oil and gas under various mineral
leasing statutes, including the Mineral
Leasing Act, 30 U.S.C. 181 et seq.; the
Mineral Leasing Act for Acquired
Lands, 30 U.S.C. 351 et seq.; the Federal
Oil and Gas Royalty Management Act
(FOGRMA), 30 U.S.C. 1701 et seq.; the
Indian Mineral Leasing Act, 25 U.S.C.
396a et seq.; the Act of March 3, 1909,
25 U.S.C. 396; the Indian Mineral
Development Act, 25 U.S.C. 2101 et
seq.; and the Federal Land Policy and
Management Act (FLPMA), 43 U.S.C.
1701 et seq.
Each of these statutes expressly
authorizes the Secretary of the Interior
to promulgate necessary and
appropriate rules and regulations
governing those leases. See e.g., 30
U.S.C. 189; 30 U.S.C. 359; 30 U.S.C.
1751; 25 U.S.C. 396d; 25 U.S.C. 396; 25
U.S.C. 2107; and 43 U.S.C 1740. The
Secretary has delegated this authority to
the Bureau of Land Management (BLM).
Specifically, under Secretarial Order
Number 3087, dated December 3, 1982,
as amended on February 7, 1983 (48 FR
8983), and the Departmental Manual
(235 DM 1.1), the Secretary has
delegated regulatory authority over
onshore oil and gas development on
Federal and Indian (except Osage Tribe)
lands to the BLM. For Indian leases, the
delegation of authority to the BLM is
reflected in 25 CFR parts 211, 212, 213,
225, and 227. In addition, as authorized
by 43 U.S.C. 1731(a), the Secretary has
delegated to the BLM regulatory
responsibility for oil and gas operations
in Indian lands. 235 DM 1.1.K.
These statutes and regulations form
the basis of and provide the authority

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for the issuance of this final rule. For
example, § 101(a) of FOGRMA directs
the Secretary to ‘‘establish a
comprehensive inspection, collection
and fiscal and production accounting
and auditing system to provide the
capability to accurately determine oil
and gas royalties, interest, fines,
penalties, fees, deposits, and other
payments owed, and to collect and
account for such amounts in a timely
manner.’’ Ensuring that oil and gas
produced from Federal and Indian
leases is accurately measured and
properly accounted for is a critical
component of any system to ensure that
all royalties due are paid. Under § 101(a)
of FOGRMA, the Secretary is authorized
to promulgate ‘‘such rules and
regulations as [s]he deems reasonably
necessary to carry out.’’ the purposes of
the act. The FOGRMA mandate
complements the policy articulated in
FLPMA that the United States receive
fair compensation for the use of public
lands and resources. See 43 U.S.C.
1701(a)(9). This rule, by improving BLM
requirements governing site security
and related measures, helps ensure that
all royalties due are paid, and thus that
the United States receives fair
compensation for the use of public
minerals.
The BLM did not receive any public
comments related to this provision and
only made minor changes for clarity
between the proposed and final
versions.
Section 3170.2

Scope

Section 3170.2(a) explains that the
regulations in part 3170 apply to all
onshore Federal and Indian (except
Osage Tribe) oil and gas leases.
Paragraph (b) explains that part 3170
also applies to agreements for oil and
gas development under the Indian
Mineral Development Act, unless the
relevant provisions of the rule are
inconsistent with the specific terms of
such agreement. Paragraph (c) explains
that a Tribal Energy Resource
Agreement entered into with the

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Federal Register / Vol. 81, No. 222 / Thursday, November 17, 2016 / Rules and Regulations
Secretary is subject to part 3170, unless
specifically excluded in such lease,
other business agreement or Tribal
Energy Resource Agreement. Paragraph
(d) explains that State or private tracts
committed to a federally approved unit
or CA as defined by or established
under 43 CFR subpart 3105 or 43 CFR
part 3180 are also subject to the
requirements of part 3170. Finally,
paragraph (e) states that all FMPs
measuring production from any of the
aforementioned leases or agreements are
subject to the requirements of part 3170.
The BLM received several comments
expressing concern with proposed
paragraph (d), which applies the part
3170 regulations to State or private
tracts committed to a federally approved
unit or CA as defined by or established
under 43 CFR subpart 3105 or 43 CFR
part 3180. The same language also
appeared in a new paragraph (e) that
was proposed to be added to § 3161.1
Jurisdiction. Comments received on
both sections are discussed here.
Many commenters thought that the
new paragraph (e) language proposed
for § 3161.1 would extend the BLM’s
jurisdiction over oil and gas to activities
that are not covered by this rule.
Specifically, commenters were
concerned that adding the proposed
language to § 3161.1 and also to
proposed § 3170.2 would expand the
BLM’s authority over the processing and
approval of Applications for Permits to
Drill (APDs) within State and private
tracts committed to a BLM-approved
Federal or Indian unit or CA.
Commenters said that such an
expansion of authority would force
operators to obtain Federal drilling
permits for drilling on State and private
tracts. From the commenters’
perspective, this perceived expansion in
jurisdiction would fundamentally alter
the way in which operators plan for
development.
The BLM disagrees with this
interpretation of the new language and
never intended for this rule to extend
the BLM’s permitting authority over
State and private drilling approvals.
However, to avoid confusion, the BLM
in this final rule added a new paragraph
(b) to its § 3161.1 revisions, which
clarifies that it is the regulations in parts
3160 and 3170 relating to site security,
measurement, reporting of production
and operations, and assessments or
penalties for non-compliance with such
requirements (i.e., those found in
subparts 3173, 3174, and 3175) that are
applicable to all wells and facilities on
State or privately owned lands
committed to a unit or CA where the
unit or CA affects Federal or Indian
interests. Proposed § 3170.2(d) has not

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been changed because it is appropriate
for this rule to state that the regulations
under part 3170, which includes
subparts 3173, 3174, and 3175, do in
fact apply to State or private tracts
committed to a federally approved unit
or CA as defined by or established
under 43 CFR subpart 3105 or 43 CFR
part 3180. This is consistent with the
BLM’s past application of its
regulations, including its Onshore
Orders, under existing 43 CFR
3161.1(b).
Section 3170.3 Definitions and
Acronyms
This section defines terms and
acronyms used across all of the various
subparts of part 3170.
The BLM did not receive any
comments on the majority of the
definitions that appeared in the
proposed rule and that are now in the
final rule. Those definitions for which
we received no comments were carried
forward in this final rule and are not
discussed further here. As explained in
the proposed rule, a number of the
definitions in § 3170.3 of the proposed
rule were the same definitions that were
found in Order 3, with only minor
revisions to either simplify or clarify
those definitions.
The following discussion first
describes the new definitions that have
been added to § 3170.3 in the final rule,
and then summarizes and responds to
comments that the BLM received on a
handful of the proposed definitions.
With respect to the former, based on
comments received and its own internal
reviews, the BLM added three new
definitions to § 3170.3: ‘‘Averaging
period,’’ ‘‘bias,’’ and ‘‘tampering.’’ As
explained below some of these
definitions were originally proposed as
part of the proposed rules to replace
Order 4 (80 FR 58952) and Order 5 (80
CFR 61646). The BLM determined that
it was appropriate to move those
definitions from those rulemakings to
§ 3170.3, because the terms are used in
multiple subparts, and should therefore
be defined once in a section that covers
the entirety of part 3170. Other
definitions were added in response to
public comments.
The final rule defines ‘‘averaging
period’’ to mean the previous 12 months
or the life of the meter, whichever is
shorter. For FMPs that measure
production from a newly drilled well,
the averaging period excludes
production from that well that occurred
in or before the first full month after
production began. For example, if an oil
FMP or a gas FMP were installed to
measure the production from a new well
that first produced on April 10, the

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81369

averaging period for this FMP would not
include the production that occurred in
April and May of that year. The BLM
added this definition to § 3170.3
because the term is used multiple times
in subparts 3174 (oil measurement) and
3175 (gas measurement), relating to the
applicability of uncertainty threshold
requirements. The BLM determined it
was important to provide a single
definition of the averaging period in
order to provide for consistent
application of the BLM’s oil and gas
measurement rules.
The final rule adds a definition for the
term ‘‘bias’’ to § 3170.3 because that
term is used in both subparts 3174 and
3175. ‘‘Bias’’ is defined to mean a ‘‘shift
in the mean value of a set of
measurements away from the true value
of what is being measured.’’ This
definition was originally proposed as
part of the rule to replace Order 5 in
§ 3175.10. The definition added to part
3170.3 is identical to the definition in
proposed § 3175.10, because the BLM
did not receive any comments on that
definition in the context of the Order 5
rulemaking.
In response to recommendations from
many commenters, the BLM added a
definition of the term ‘‘tampering’’ to
§ 3170.3. The proposed and final rules
prohibit operators from tampering with
measurement equipment, components,
or processes and appropriate valves.
While the meaning of tampering is
commonly understood, the BLM agrees
with commenters that the term should
be defined to ensure there is a common
understanding of what is meant by
tampering for purposes of this rule.
Section 3170.3 defines tampering to
include ‘‘any deliberate adjustment or
alteration to a meter or measurement
device, appropriate valve, or
measurement process that could
introduce bias into the measurement or
affect the BLM’s ability to
independently verify volumes or
qualities reported.’’ The BLM modified
the definition of ‘‘commingling’’ in the
final rule to clarify that combining
production from multiple wells within
a single lease, unit PA, or CA, or the
downhole combining of production
from different zones or formations that
are part of the same lease, unit PA, or
CA, is not considered ‘‘commingling’’
for the purpose of the final rule. Many
commenters expressed concern that the
definition for commingling in the
proposed rule would have required an
operator to obtain approval to combine
production from multiple properties
within a CA or unit PA prior to
measurement, particularly when the CA
or unit PA contains leases with multiple
owners (i.e., Federal, Indian, State, or

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private). Commenters said the proposed
definition negates one of the primary
benefits of establishing a CA or unit PA,
which is the operation of the CA or unit
PA as one entity and the sharing of
revenues from that CA or unit PA on a
fixed allocation schedule, typically
based on ownership percentage within
the CA or unit PA.
The conclusions reached by these
commenters were incorrect. Neither the
proposed rule nor the final rule defined
‘‘commingling’’ to include the
combining of production from multiple
properties within a CA or unit PA prior
to measurement. However, in response
to these comments, the BLM revised the
definition of commingling to help
clarify the situations that are and are not
considered commingling, and to
emphasize that the combining of
production from multiple properties
within a CA or unit PA prior to royalty
measurement is not commingling.
One commenter said the proposed
commingling definition could deter
operators from drilling horizontal wells
through several sections that contain
different mineral estates and reduce the
production and utilization of the State’s
oil and gas resources. The BLM agrees
with this comment with respect to the
limited situations in which there is no
unit agreement or CA in place for those
sections. Downhole commingling when
there is multiple ownership and no unit
or CA in place would adversely affect
the uncertainty, bias, and verifiability of
the measurement of the volumes
produced from each property, and the
BLM would deny such a request unless
it qualified under § 3173.14(b) of the
final rule. If there was a unit or CA in
place, however, the BLM would not
consider the combining of production
between several sections within the unit
or CA to be commingling and no
approval would be required. The BLM
did not make any changes to the rule
based on this comment.
The definition of an FMP in this final
rule is carried forward from the
proposed rule, which defined an FMP to
be a ‘‘BLM-approved point where oil or
gas produced from a Federal or Indian
lease, unit PA, or CA is measured and
the measurement affects the calculation
of the volume or quality of production
on which royalty is owed.’’ As
explained in more detail below in the
discussion of comments for § 3173.12,
the final rule sets forth a process for an
operator of a new or existing facility to
apply for approval of an FMP and
issuance of an FMP number in proposed
§ 3173.12. Because § 3173.12 of the final
rule requires operators of existing
facilities to apply for an FMP in stages
over a 36-month period, it will require

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3 years from the effective date of the
final rule for the BLM to receive,
evaluate, and act on an FMP application
for existing facilities. Therefore, for
purposes of compliance with other
provisions of this final rule, during this
interim period, the definition of an FMP
makes clear, as in the proposed rule,
that an FMP ‘‘also includes a meter or
measurement facility used in the
determination of the volume or quality
of royalty-bearing oil or gas produced
before BLM approval of an FMP under
§ 3173.12 of this part.’’
The BLM received many comments
on the proposed definition of an FMP.
A couple of commenters pointed out
that there are differences between the
BLM’s proposed definition and the
ONRR’s definition at 30 CFR 1206.171.
Commenters said these differences
could cause confusion for industry, the
BLM, and ONRR, and recommended
that a single definition be established
for both agencies. These commenters
did not provide specific details or any
examples of the confusion that could
arise as a result of these definitional
differences. The BLM compared both
definitions and agrees that there are
differences, but disagrees with
commenters that these differences will
cause confusion. The intent of both
definitions is the same. Both agencies
want to ensure that the FMP is the point
at which measurement determines the
royalty that is owed to the Federal
Government or the Indian mineral
owners. In general, the ONRR definition
applies to offshore oil and gas
operations, whereas the BLM definition
applies only to onshore operations. So,
while the two agencies’ FMP definitions
are not exactly the same, they capture a
similar concept (i.e., the specific
measurement point where operators
determine the royalty due the Federal
Government or Indian mineral owners).
These comments did not result in a
change to the final rule.
It should be noted that in 2013, the
GAO specifically noted in report GAO–
10–313 that Interior’s onshore and
offshore policies for tracking and
approving where and how oil and gas
are measured are inconsistent. The
Bureau of Safety and Environmental
Enforcement (BSEE) already assigns
FMP numbers for offshore oil and gas
leases, which the operator, transporter,
or purchaser must then use when
reporting production results to ONRR.
Based on that practice, the GAO
recommended that the BLM clearly
identify points of measurement where
oil and gas royalties due to the Federal
Government are determined and
reported. By including the definition of
FMP in the final rule, the BLM is able

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to both address the GAO’s concerns and
bring onshore reporting in-line with the
approach used offshore.
The BLM received additional
comments pertaining to the FMP
definition. One recommended that the
definition be changed to allow operators
to use gas processing plant tailgate
meters located off the lease, unit, or CA
as FMPs as a general matter, or to allow
those meters to be used as FMPs under
a variance. Another commenter asked
whether an FMP is the same as a Central
Delivery Point or Point of Royalty
Measurement as defined in Washington
Office Instruction Memorandum (IM)
2013–152, a BLM policy document
created in 2013 regarding commingling
approvals.
The BLM did not change the
definition of an FMP to include tailgate
meters because, under the Mineral
Leasing Act (MLA) and FOGRMA, the
Secretary’s authority to regulate onshore
oil and gas operations applies to lessees/
operators and, during certain activities,
to purchasers and transporters. While
the owners of off-lease/unit/CA gas
processing plants may sometimes fall
into these categories of regulated
entities, they will not always, and while
the BLM may consider requests for offlease measurement it is not required to
approve such request. Therefore, the
BLM chose not to include off-lease/unit/
CA tailgate meters in the definition of
an FMP in order to avoid default
applications of this rule that might be
inconsistent with BLM’s statutory
authority or the requirements of this
final rule related to off-lease
measurement at §§ 3173.23 through
3173.28. With respect to whether the
definition of an FMP is the same as the
Central Delivery Point or Point of
Royalty Measurement as defined in IM
2013–152, the BLM can confirm that
they are the same.
The definition of ‘‘off-lease
measurement,’’ in both the proposed
and final rules, means measurement at
an FMP that is not located on the lease,
unit, or communitized area from which
the production came. The BLM received
several comments requesting that the
definition be expanded to exempt from
the proposed rule’s off-lease
measurement approval requirement
cases in which a horizontally or
directionally drilled well is completed
through a Federal or Indian lease, unit,
or communitized area, but conducts
measurement operations off-lease at the
wellhead. The commenters said that, in
many instances, wells are being drilled
from a surface location that is sited offlease due to environmental conditions,
such as rugged terrain or sensitive
wildlife habitat. The BLM did not

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change the definition of off-lease
measurement in response to this
comment because § 3173.28(a) of the
proposed and final rules already
addresses this situation. Under
§ 3173.28(a), measurement at an
approved FMP is not considered offlease measurement when the FMP is
located on the well pad of a
directionally or horizontally drilled well
that produces oil and gas from a lease,
unit, or CA on which the well pad is not
located. Therefore, approval for off-lease
measurement is not required under
those circumstances, so long as
measurement operations occur on the
well pad of the directionally or
horizontally drilled well.
The final rule makes minor changes to
the list of acronyms that appear in
proposed § 3170.3 based on the
acronyms used in part 3170. The BLM
did not receive any comments on this
list. The acronym Btu (British thermal
unit) has been relocated from § 3173.1 to
§ 3170.3 because this acronym is used in
both subparts 3173 and 3175. The
acronym S&W (sediment and water) is
new to section. The BLM decided to
include it in § 3170.3 because the
acronym is used in both subparts 3173
and. Although it is a commonly
understood acronym in the oil and gas
industry, the BLM believes it is
appropriate to include the acronym here
for clarity and to help inform the
general public. The BLM also added the
acronym LACT (lease automatic custody
transfer) because it is used in both
subparts 3173 and 3174.
Section 3170.4 Prohibitions Against
By-Pass and Tampering
The BLM did not make any changes
to the requirements of this section
between the proposed and final
versions. Section 3170.4 strengthens the
prohibition against meter by-passes
contained within section III.D of Order
3 by adding language that prohibits
tampering with any measurement
device, component of a measurement
device, or measurement process. As
explained in § 3170.3, tampering
includes any deliberate adjustment or
alteration to the meter or measurement
device or measurement process that
could introduce bias into the
measurement or affect the BLM’s ability
to independently verify volumes or
qualities reported. Examples of
tampering include deliberately
installing an orifice plate in a gas meter
with the bevel upstream, adjusting a
transducer to read higher or lower than
a certified test device, entering incorrect
information into the configuration log of
an electronic gas measurement system,
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volume statement in lieu of raw data, or
making analogous adjustments or
alterations to an oil measurement
system.
The BLM received many comments
on this section of the proposed rule,
most of which suggested that the BLM
clarify that inadvertent human error or
force majeure events should not be
considered ‘‘tampering’’ for purposes of
this section. For example, one
commenter said meter reports may use
derived values due to tap freezes or data
loss. The commenter believes that these
situations should not be considered
‘‘tampering.’’ The commenter said the
language in the proposed rule would not
allow for such cases, and should be
modified. The BLM agrees with this
comment and in the final rule has
provided a definition for the term
‘‘tampering,’’ as previously discussed,
that clearly states that the act of
tampering must be deliberate on the part
of the operator. By requiring acts to be
deliberate, consistent with the
commenter’s suggestion, the BLM is
able to take into consideration whether
a particular act is due to human error or
is outside of the operator’s control.
The BLM did not amend the
definition of tampering in response to
the comment about the use of derived
values rather than raw data in a meter
report, such as when a tap freezes or
other malfunctions are experienced.
These circumstances can occur in the
context of either oil or gas measurement,
and they are addressed in specific
provisions of subparts 3174 and 3175
(the new rules replacing Orders 4 and 5)
that establish procedures that an
operator must follow to notify the BLM
of the malfunctioning equipment,
document how derived values were
determined, and indicate on the
quantity transaction record that derived
values, rather than raw data, were used
to determine volumes. As a result, the
BLM did not amend the definition of
tampering in response to comments
about derived values.
Section 3170.5 Industry Standards
Incorporated by Reference
Section 3170.5 is reserved for
potential future incorporation by
reference of standards that apply to
more than one of the subparts of part
3170.
Section 3170.6

Variances

Section 3170.6 of the final rule
clarifies and makes more uniform the
BLM’s existing process and regulations
for granting variances from the
minimum standards contained in part
3170.

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Paragraph (a)(1) lists all the
information that a party seeking a
variance from the requirements of part
3170 must include when filing a
request, including: Identification of the
specific requirement from which a
variance is sought, and the length of
time the variance is requested; an
explanation of the need for the variance;
a detailed explanation of the proposed
alternative means of compliance; and a
showing that the proposed alternative
meets or exceed the objectives of the
applicable requirement. Paragraph (a)(2)
requires that variance requests be
submitted as separate documents from
any plans or applications. The BLM will
not consider variance-request
documents that are submitted as part of
a master development plan, APD, rightof-way application, or other
applications for approval. This
requirement does not preclude operators
from submitting variance requests at the
same time that they submit a master
development plan or other application.
In fact, the final rule encourages
operators to submit their variance
requests simultaneously with, but
separately from, their development
plans or applications, especially if the
operators’ proposals are contingent
upon the BLM approving their variance
requests. The BLM’s primary rationale
for requiring separate submittal is that,
in the past, operators have put their
variance requests in the cover letters
that accompanied their development
proposals, where they are sometimes
overlooked. Having operators submit
their variance requests via a separate
Sundry Notice will help the BLM easily
identify them when they are submitted
simultaneously with other applications.
Paragraph (a)(2) clarifies that approval
of a plan or application that contains a
request for a variance does not
constitute approval of the variance. The
BLM made this clarification to ensure
that variances are submitted separately
and brought to the attention of the BLM.
Paragraph (a)(3) tells operators how to
submit their variance requests.
Operators must use WIS, which is an
acronym described in the final rule to
mean the Well Information System or
any successor electronic filing system
that might be developed by the BLM, to
file their request, along with any
supporting documents associated with
it. This paragraph also provides an
option for operators to submit a
hardcopy application if electronic filing
is not possible or practical. In such
cases, the operator must submit a
variance in hardcopy as directed by the
AO in the Field Office having
jurisdiction over the lands described in

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the application. The BLM made minor
revisions to this section to clarify the
intent of this provision regarding
electronic filing, and to provide
additional flexibility as the BLM rolls
out new electronic systems to replace its
existing systems, including the Well
Information System and the Automated
Fluid Management Support System
(AFMSS).
No substantive changes were made to
proposed paragraph (a)(4). This
paragraph strengthens and standardizes
the criteria the BLM uses for granting
variances. Under Order 3, the AO was
required to make only one
determination—whether or not the
variance request meets or exceeds the
objectives of the applicable minimum
standard. Under this paragraph in the
final rule, the AO will still have to make
that determination before granting a
variance. Additionally, the final rule
requires the AO to make two more
determinations before granting a
variance—that issuing a variance: (1)
Will not adversely affect royalty income
or production accountability; and (2) Is
consistent with maximum ultimate
economic recovery.
Paragraphs (a)(5) and (a)(6) specify
that granting or denying a variance is
entirely within the BLM’s discretion,
and that a variance from a requirement
in a regulation does not constitute a
variance from any other regulations,
including other Onshore Oil and Gas
Orders. These paragraphs did not
change from the proposed rule.
Paragraph 3170.6(b) affirms the BLM’s
authority to rescind a variance or
modify any condition of approval of a
variance due to changes in Federal law,
technology, regulation, BLM policy,
field operations, noncompliance, or for
any other reason.
The BLM received many comments
on this section of the proposed rule. A
few commenters were concerned that
the proposed rule would void existing
variances and that operators with
existing variances would have to apply
for new ones. These commenters were
concerned this would place an
unnecessary burden on affected parties.
They recommended that the provision
be revised to expressly ‘‘grandfather’’
existing variances.
The BLM did not make a change to
the rule in response to these comments.
This final rule does not automatically
rescind any existing variance approvals.
Rather, it clarifies the BLM’s authority
to rescind variances and provides the
means by which it may rescind an
existing approval if necessary. The BLM
will re-evaluate existing variance
approvals on a case-by-case basis, such
as during the FMP application and

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review process under § 3173.16. For
example, if an operator has an existing
variance approval from the BLM’s
previous commingling requirements,
but during the FMP approval process
the BLM determines that the existing
approval is inconsistent with this final
rule’s new commingling standards, or
the operator cannot be exempted from
the new commingling standards, then
the BLM will rescind the existing
variance if the deficiencies are not
corrected within the time specified by
the BLM.
Several commenters disagreed with
the provision in paragraph (b) that
allows the BLM to rescind variance
approvals and modify conditions of
approval. These commenters stated that
companies made investments and
proceeded with projects based on
previously approved BLM variances.
These commenters said that rescinding
existing authorizations and what they
believe to be contractual agreements
would pose a great risk to their
operations.
The BLM did not make a change in
the rule in response to these comments.
The BLM’s overriding contractual
agreement with the operator is the lease
agreement, which is expressly made
subject to regulations and formal orders
subsequently promulgated as long as
such regulations are not inconsistent
with the lease rights granted or the
specific lease provisions (See BLM
Lease Form 3100–11). The Department
has long interpreted this language as
‘‘incorporat(ing) future regulations, even
though inconsistent with those in effect
at the time of lease execution, and even
though to do so creates additional
obligations or burdens for the lessee.’’ 9
The BLM’s authority to update the
regulations that apply to existing leases
and operations is well-established, and
this authority necessarily includes the
authority to rescind existing variances
and authorizations when these
variances and authorizations are
inconsistent with applicable
regulations.
The BLM recognizes that the
commingling and off-lease measurement
requirements in this rule may result in
the termination of existing commingling
and off-lease measurement variance
approvals. However, the BLM has
sought to minimize the adverse impacts
of these requirements by providing
exemptions for economically marginal
properties. These additional exemptions
are discussed in further detail in the
sections of this preamble that address
commingling and off lease
9 Coastal Oil & Gas Corp., et al., 108 IBLA 62, 66
(1989).

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measurement. See the Section-bySection discussions of §§ 3173.1,
3173.14, 3173.25, and 3173.27. For
example, the final rule provides publicinterest exemptions for operators that
cannot meet its new off-lease
measurement standards.
One commenter supported the
standards in paragraph (a)(4) that the
BLM will use to determine whether to
grant a variance but went one step
further to recommend that operators be
required to demonstrate that compliance
with the regulation is not feasible, so
that the rule’s relatively limited
opportunities for variances are not
abused. The BLM does not expect
operators to abuse the variance process,
which requires them to submit an
application requesting a variance, and
provide sufficient information and
justification for the variance that the
BLM will then review prior to making
a determination on the variance request.
In fact, this rule strengthens and
standardizes the criteria that the BLM
will use to determine whether to grant
a variance and requires that the BLM
make a determination that ‘‘the
proposed alternative meets or exceeds
the objectives of the applicable
requirement(s) of the regulation.’’ As a
result, the BLM does not believe the
change requested by the commenter is
necessary and did not make any changes
the rule based on this comment.
A few commenters expressed concern
with language in paragraph (b) that
allows the BLM to rescind a variance for
‘‘other reasons’’ because, they said, it
could result in the BLM acting
arbitrarily. The BLM disagrees that this
language would allow it to act
arbitrarily because paragraph (b)
requires the BLM to provide a written
justification when it rescinds a variance.
The BLM included the term ‘‘other
reason’’ because the BLM cannot
anticipate every possible situation in
which there will be good cause for
rescinding a variance. The BLM must
preserve its ability to rescind a variance
approval if that approval adversely
affects royalty income or production
accountability, or is not consistent with
maximum ultimate economic recovery.
If the operator does not agree with the
BLM’s decision to rescind a variance,
the operator may file an appeal under
applicable BLM regulations at 43 CFR
subpart 3165—Relief, Conflicts, and
Appeals.
A few commenters stated that even
though the BLM will provide written
justification when it rescinds a variance
or modifies a COA, operators should be
given a 30-day advance notice if their
variance is about to be rescinded, or
COA modified, in order to give them an

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opportunity to avoid a rescission or
modification, or to adjust to operating
without the variance. The BLM
disagrees with this comment and did
not change the rule in response. As
previously noted, if an operator
disagrees with the BLM’s decision to
rescind a variance or change a COA, the
operator may file an appeal under the
applicable regulations.
Section 3170.7 Required
Recordkeeping, Records Retention and
Records Submission
Section 3170.7 of the final rule
updates BLM regulations to reflect the
records-retention requirement for
Federal oil and gas leases that Congress
established in the 1996 amendments to
FOGRMA.10
Paragraphs (a) and (b) are the same as
in the proposed rule. These paragraphs
establish both the entities covered and
the time period over which the recordsretention requirements apply. In the
final rule, purchasers and transporters
are held to the same minimum
standards as operators for
recordkeeping, records retention, and
records submission—i.e., to maintain all
records that are relevant to determining
the quality, quantity, disposition, and
verification of production from Federal
and Indian leases. As described in the
proposed rule, the BLM has authority to
impose these requirements on
purchasers and transporters under
FOGRMA. Specifically, Section 103(a)
of FOGRMA, 30 U.S.C. 1713(a), requires
persons involved in transporting and
purchasing oil or gas through the point
of first sale or the point of royalty
computation, whichever is later (along
with persons involved in producing or
selling), to ‘‘establish and maintain any
records, make any reports, and provide
any information that the Secretary may,
by rule, reasonably require.’’
Although paragraph (c) did not
change substantively from the proposed
rule, the final rule splits it up into two
paragraphs for clarity. Paragraph (c)(1)
states that records pertaining to Federal
leases, units, or CAs must be maintained
for at least 7 years, consistent with
applicable statutory requirements.
Paragraph (c)(2) codifies the applicable
statutory requirements for further
retention beyond 7 years under the
circumstances specifically identified by
statute (see 30 U.S.C. 1724(f)), as
required under the 1996 amendments to
FOGRMA.
Similarly, although paragraph (d) did
not change substantively from the
10 Federal Oil and Gas Royalty Simplification and
Fairness Act of 1996, Public Law 104–185, 110 Stat.
1700 (Aug. 13, 1996).

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proposed rule, the final rule splits it up
into two paragraphs for clarity.
Paragraph (d)(1) states that records
pertaining to Indian leases, units, or
CAs must be maintained for at least 6
years, consistent with applicable
statutory requirements. Paragraph (d)(2)
codifies the applicable statutory
requirements for further retention
beyond 6 years under the circumstances
specifically identified by statute (see 30
U.S.C. 1713(b)). The records-retention
requirement on Indian leases remains
unchanged because the 1996
amendments to FOGRMA, by their
express terms, applied only to Federal
leases and not to Indian leases.
Paragraph (e)(1) addresses the
discrepancy between the recordsretention requirements for Federal (7
years) and Indian (6 years) leases, as
relevant to units and CAs that contain
both Federal and Indian leases. No
substantive changes were made as part
of the final rule. However, the phrase,
‘‘but a judicial proceeding or demand is
not commenced within 7 years after the
records are generated, the record holder
must retain all records regarding
production from the unit or CA until the
Secretary or his designee releases the
record holder from the obligation to
maintain the records’’ has been
eliminated from this paragraph of the
proposed rule and moved to its own
paragraph (e)(2).
In paragraph (e)(2) of the proposed
rule, which is now paragraph (e)(1) of
the final rule, the phrase ‘‘or until the
Secretary or his designee releases the
record holder from the obligation to
maintain the records, whichever is
later,’’ was removed from the final rule
in order to more closely track the
authorizing language in FOGRMA, and
also to make the record-retention
obligation clearer.
Paragraph (f) requires the record
holder to maintain an audit trail and is
unchanged from the proposed rule.
Paragraph (g) requires operators,
purchasers, and transporters to place
specific identifying information on all
records, including source records, used
to determine quality, quantity,
disposition, and verification of
production attributable to a Federal or
Indian lease, unit PA, or CA. The
proposed rule would have required
record holders to use BLM-assigned
FMP numbers on such records. The
final rule is revised to allow record
holders, in lieu of an FMP number, to
use the lease, unit PA, or CA number,
as applicable, on their records,
including source records. In any case,
the record holder must also include a
unique equipment identifier, such as a
unique tank identification number or

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meter station number. The BLM made
this change in response to many
comments that it would be difficult or
impossible for some record holders to
modify their electronic systems to
accommodate FMP numbers on their
records. In these instances, the final rule
allows record holders to use the lease,
unit PA, or CA number instead of the
FMP number.
Paragraph (h) requires operators,
purchasers, and transporters to provide
all records to the BLM upon request.
This ensures that all records—whether
they are created by lessees, operators,
transporters, or purchasers—are readily
available to the BLM. The BLM did not
receive any comments on this paragraph
and did not change it in the final rule.
Paragraph (i) requires that all records
be legible. The BLM did not receive any
comments on this paragraph and did not
change it in the final rule.
Paragraph (j) requires that all records
requiring a signature must also have the
signer’s printed name. The BLM did not
receive any comments on this paragraph
of the proposed rule and did not change
it in the final rule.
The BLM received a number of
comments on § 3170.7 of the proposed
rule as a whole requesting various
changes to be made to the proposed
requirements. Each of these comments
is addressed below.
One commenter stated that
maintaining audit records for 7 years, as
required in paragraph (c)(1), would
result in unnecessary costs for
purchasers and transporters, and that
they should not have to account for
production volumes. The BLM does not
agree with this comment, nor can it
make the changes suggested by the
commenter. As discussed earlier, the
records retention period set by
FOGRMA for Federal leases is now 7
years and the change in retention period
in this final rule merely conforms the
regulations to that statutory authority.
A number of other commenters
asserted that the BLM does not have the
authority to hold purchasers and
transporters to the same recordsretention and recordkeeping
requirements as lessees and operators,
as outlined in paragraphs (a) and (f) of
§ 3170.7. Other commenters indicated
that they did not see a need for this new
requirement and that it would be too
costly. Still others disagreed that
FOGRMA authorizes the BLM to impose
recordkeeping and records-retention
requirements on purchasers and
transporters in the first instance. One
commenter argued that the BLM had not
properly defined ‘‘any person directly
involved in producing, transporting,
purchasing, selling, or measuring oil

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and gas’’ under FOGRMA, and therefore
had improperly extended these
recordkeeping requirements to
purchasers and transporters.
The BLM disagrees with these
comments. Section 103(a) of FOGRMA,
30 U.S.C. 1713(a), requires a ‘‘lessee,
operator, or other person directly
involved in developing, producing,
transporting, purchasing, or selling oil
or gas . . . through the point of first sale
or the point of royalty computation,
whichever is later, [to] establish and
maintain any records, make any reports,
and provide any information that the
Secretary may, by rule, reasonably
require.’’ While FOGRMA does not
specifically define ‘‘any person directly
involved,’’ the intent of the provision is
clear. It authorizes the Secretary to
establish by rule requirements for
anyone involved ‘‘. . . in developing,
producing, transporting, purchasing, or
selling oil or gas,’’ which plainly
includes purchasers and transporters. 30
U.S.C. 1713(a) (emphasis added).
Based on its experience in the field,
the BLM believes it is appropriate to
implement this statutory authority and
have purchasers and transporters adhere
to the same recordkeeping and recordsretention requirements as lessees and
operators. This is because the BLM must
occasionally rely on purchasers’ and
transporters’ records to verify
production when operators do not
maintain their own records properly, or
go out of business, or are acquired by
other companies and their records are
destroyed. For this reason, the BLM
believes that it is important for everyone
involved in the production and sale of
oil and gas produced from Federal and
Indian leases to be responsible for
maintaining and providing the
necessary records to account for and
verify that production. The BLM did not
make any changes in response to these
comments.
Another commenter said the BLM did
not adequately analyze the economic
impact that this requirement would
have on purchasers and transporters.
The BLM does not agree with this
comment. As part of this rulemaking
process the BLM prepared an Economic
and Threshold Analysis For Final Rule
Onshore Oil and Gas Operations;
Federal and Indian Oil and Gas Leases;
Site Security (Economic and Threshold
Analysis). That analysis specifically
analyzed, among other things, the
impact of these proposed recordkeeping
requirements on purchasers and
transporters. Based on that analysis, the
BLM estimates that 200 to 300
purchasers and transporters will have to
comply with this final rule’s new
recordkeeping and records-retention

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requirements. However, it is likely that
many purchasers and transporters
already compile records that will, for
the most part, satisfy this rule’s
requirements, and therefore the
additional compliance costs imposed by
this rule should be minimal. For more
details, please see the Economic and
Threshold Analysis.
Several commenters said that some
transporters do not have space to store
records and would not be capable of
meeting the paragraph (a) requirements.
They said that transporters would create
inaccurate records, and that operators
would be held responsible. They asked
that the BLM not hold operators
responsible for transporters’
recordkeeping violations. Conversely,
some commenters said operators may
provide incorrect information to
purchasers and transporters, such as
incorrect FMP numbers, which could
subject purchasers and transporters to
recordkeeping penalties if they were to
use the inaccurate information in their
records. The BLM does not agree with
the concerns raised by these
commenters, as under the rules each
party will be responsible for the content
of their own records and must also bear
some responsibility for ensuring the
accuracy of the information they are
tracking. The BLM does not believe that
the provision should be modified to
account for the possibility that operators
might provide faulty information to a
purchaser or transporter. Parties bear
the responsibility to ensure the accuracy
of their own records, and the BLM
anticipates that provision of faulty
information to a purchaser or
transporter by an operator could be
handled on a case-by-case basis in the
enforcement context. The final rule was
not changed as a result of these
comments.
Some commenters said the BLM
should make the records-retention
requirements for both Federal and
Indian leases the same—6 years.
Paragraph (c) requires Federal-lease
operators to retain their records for 7
years (consistent with Congress’ 1996
amendments to FOGRMA), while
paragraph (d) requires Indian-lease
operators to retain theirs for 6 years.
One commenter said the 6-year
retention requirement for all records
under Order 3 has not been a problem
and questioned why Congress extended
the retention period for Federal-lease
operators from 6 years to 7 years. The
BLM understands these concerns, but
the retention period for records
maintained by Federal-lease operators is
7 years by statute. 30 U.S.C. 1724(f).
That statutory requirement has been in
place for 20 years. This final rule simply

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codifies that requirement. Thus, the
BLM did not change the final rule in
response to these comments.
Several commenters expressed
concern about the requirement in
paragraph (g) of the proposed rule that
lessees, operators, purchasers, and
transporters place FMP numbers on all
of their source records, particularly
records generated by flow computers.
They said that flow computers cannot
handle the 11-digit FMP numbers and
that it would take operators years to
modify their production accounting
systems to accommodate the new
numbers. The BLM agrees with these
commenters and changed the final rule
to allow lessees, operators, purchasers
and transporters, as an alternative, to
use the lease, unit PA, or CA number,
along with a unique equipment
identifier, on their records. The BLM
believes this change will simplify the
final rule’s record-keeping requirements
because in its experience lessees,
operators, purchasers and transporters
are already using a lease, unit PA, or CA
number, plus some unique equipment
identifier in connection with existing
operations, which means this
information is already reflected on
records being generated under existing
recordkeeping systems.
In addition to the preceding
comments on specific provisions of
§ 3170.7, the BLM received some
general comments on § 3170.7 that were
not directed to any specific paragraph.
Several commenters said the
recordkeeping requirements do not
address new production reporting
technology and practices that are used
by regulators outside of the U.S., such
as the Norwegian Petroleum Directorate.
These commenters did not suggest any
specific changes, and therefore the BLM
did not make any changes in the final
rule in response to these comments.
That said, it should be noted that the
BLM is currently updating its existing
database system (AFMSS) that it uses to
track Federal and Indian oil and gas
production. As part of this
comprehensive update, the BLM is
following data management models and
standards established by industry
organizations, such as the Professional
Petroleum Data Management
Association. These update efforts
respond to the concerns raised by
commenters.
Another commenter said the new
recordkeeping and records-retention
requirements would cause problems for
the BLM. This commenter said BLM
field offices do not have room for the
additional records that would be
generated under the final rule. The BLM
disagrees with this commenter. The

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BLM will not be storing or accepting all
of the records that a lessee, operator,
purchaser, or transporter will be
required to create and retain under this
final rule, rather records must be
available to the BLM if requested (see
§ 3170.7(h)). The BLM did not change
the final rule as a result of these
comments.
Several commenters suggested that
requiring purchasers and transporters to
keep and retain records would be
redundant because purchasers and
transporters already provide this
information to the operators, who use it
to fill out their own production records.
The BLM agrees that operators do often
base their production reporting on
information that purchasers and
transporters provide them, however, the
BLM cannot confirm that this happens
in all cases. Moreover, as noted,
operators’ records may sometimes be or
become unavailable. Requiring each
party involved in production from
Federal and Indian oil and gas leases to
maintain its own records allows the
BLM to compare the information and
make an independent determination
that production is being properly
accounted for and that the correct
royalties are being paid.
One commenter said this section’s
new recordkeeping and recordsretention requirements will be costly
and cause delays, and will discourage
oil and gas development on Federal
lands, as well as on adjacent State and
private lands. The commenter said this
in turn will result in lost royalties and
jobs. The BLM does not agree with this
comment. These recordkeeping
requirements are not substantially
different from the requirements that
operators are currently following (e.g.,
the records retention requirements have
only increased from 6 to 7 years). As
explained above, it is likely that most
purchasers and transporters are already
maintaining records that will, for the
most part, satisfy this final rule’s
requirements. No change was made to
the final rule as a result of this
comment.
Section 3170.8 Appeal Procedures
Section 3170.8 provides that BLM
decisions, orders, assessments, or other
actions under part 3170 are
administratively appealable (first to the
BLM State Director and then to the
Interior Board of Land Appeals) under
43 CFR 3165.3(b), 3165.4, and part 4.
The BLM did not receive any comments
on this section; however, in response to
comments received on provisions of the
proposed rules to replace Orders 4 and
5 the BLM made several changes to this
section.

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The language from the proposed rule
was moved to a new paragraph (a) and
a new paragraph (b) was added that
creates a separate appeal process for
decisions made by the BLM, based on a
recommendation from the PMT, for
approval or denial of specific
measurement equipment or procedures.
Under paragraph (b) a party may file a
request for discretionary review by the
ASLM. Paragraph (b) also provides that
the ASLM may delegate this review
function as he or she deems appropriate,
in which case the application for
discretionary review must be made to
the person or persons to whom the
review function has been delegated.
A specific appeals procedure for
recommendations from the PMT was
developed for two reasons. First, such a
procedure responds directly to
comments received on Orders 4 and 5
specifically requesting a procedure to
review decisions made by the PMT.
Second, the BLM determined that a
separate appeal process is necessary
because it determined that PMT reviews
did not fit under the existing appeals
procedure at 43 CFR 3170.8. As
explained in this preamble and the
preambles for the rules to replace
Orders 4 and 5, the PMT will review
new measurement technologies and
methods and then make
recommendations to the BLM as to
whether they should be approved. It is
the BLM’s intent that those approvals be
made at the national or Washington
Office level, as a result those decisions
would not properly be appealable to a
BLM State Director as contemplated in
paragraph (a). The new language under
paragraph (b) reads: ‘‘For any
recommendation made by the PMT, and
approved by the BLM, a party affected
by such decision may file a request for
discretionary review by the Assistant
Secretary for Land and Minerals
Management. Under paragraph (b), the
Assistant Secretary may delegate this
review function as he or she deems
appropriate, in which case the affected
party’s application for discretionary
review must be made to the person or
persons to whom the Assistant
Secretary’s review function has been
delegated.’’ 11
Section 3170.9

Enforcement

Section 3170.9 provides that
noncompliance with any requirements
of part 3170 or any order issued
thereunder may result in enforcement
actions under 43 CFR subpart 3163 or
11 It should be noted that decisions by the
Assistant Secretary would not be reviewable by the
Interior Board of Land Appeals.

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any other remedy available under
applicable law or regulation.
The BLM received numerous
comments regarding the BLM’s
proposal, in proposed § 3170.9, not to
include in this rule the enforcement,
corrective action, and abatement period
provisions that were in Order 3, and
instead to develop an internal
Inspection and Enforcement Handbook
that would provide direction to BLM
inspectors on how to classify a violation
as major or minor, and what the
corrective action and timeframes for
correction should be. These comments
and the BLM’s response are discussed
later in this preamble in connection
with § 3173.29.
Subpart 3173—Requirements for Site
Security and Production Handling and
Related Provisions
Section 3173.1
Acronyms

Definitions and

This section defines the terms used in
subpart 3173 that pertain to site security
and production handling. The BLM did
not receive any comments on a majority
of the definitions that appeared in
proposed § 3173.1. Those definitions,
for which we received no comment,
were carried forward into this final rule
and are not discussed further here. The
following discussion summarizes and
responds to comments that the BLM
received on a handful of proposed
definitions, describes modifications to
some of those definitions, and describes
five definitions that were added to
§ 3173.1 of the final rule: ‘‘Free water,’’
‘‘permanent measurement facility,’’
‘‘payout period,’’ ‘‘royalty net present
value (NPVR),’’ and ‘‘royalty-free use of
oil and gas.’’
At the outset it should be noted that
as explained in the preamble to the
proposed rule, a number of the
definitions in § 3173.1 are the same
definitions that were found in Order 3,
with only minor simplifications or
clarifications.
As noted in the Section-by-Section
discussion for § 3170.3, the acronym for
‘‘British thermal unit (Btu)’’ has been
moved from this section to § 3170.3 of
the final rule because it is used in more
than one subpart of § 3170. The
acronym BIA (Bureau of Indian Affairs)
was added to this final rule because it
is used in §§ 3173.14 and 3173.23.
Similarly, the acronym for ‘‘CAA
(commingling and allocation approval)’’
was provided in the proposed rule, but
the term was not otherwise defined. One
commenter suggested that a definition
for this term be provided. The BLM
agrees with this comment and has
provided a definition in the final rule

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for this commonly used term. The final
rule defines ‘‘commingling and
allocation approval (CAA)’’ to mean ‘‘a
formal allocation agreement to combine
production from two or more sources
(leases, unit PAs, CAs, or non-Federal or
non-Indian properties) before that
production reaches an FMP.’’ This
definition is consistent with the
commonly understood meaning of the
term and its use in the proposed rule.
The BLM also replaced the term ‘‘lowvolume property’’ with the term
‘‘economically marginal property’’ and
modified the definition based on
comments received. The term ‘‘lowvolume property’’ was intended to
identify category of leases, unit PAs,
and CAs for which commingled
measurement of production may be
justified, even though the property
would not meet the conditions of
proposed § 3173.14(a)(1) regarding
mineral interest ownership of
commingled production. In response to
comments, the BLM made a number of
changes to this definition, most notably
changing the term to ‘‘economically
marginal property’’ in the final rule.
The BLM believes this new term is
more reflective of the BLM’s intent,
which is to describe a type of property
that should be allowed to be part of a
CAA in order to avoid premature
plugging and abandonment. The
thresholds that the proposed and final
rules use to identify a property as at risk
of being shut-in are not exclusively
volume-based. The new name
recognizes that the thresholds are
actually based on production volume
and other economic considerations,
including commodity price, fixed and
variable operating costs, and taxes.
Specifically, under both the proposed
and final rules, the BLM can approve
commingling in two circumstances
relating to economics of well operations:
(1) When a prudent operator, for
economic reasons, would plug a well or
shut-in the lease, unit PA, or CA instead
of spending the money to achieve noncommingled measurement of
production; or (2) When the capital
expenditure on equipment necessary to
achieve non-commingled measurement
of production would exceed the net
present value of projected Federal or
Indian royalty over the life of the new
equipment. The BLM captured both of
these circumstances in the definition of
a ‘‘low-volume property’’ in the
proposed rule, and carried that structure
into the final rule’s definition of an
‘‘economically marginal property.’’
Under the final rule, a lease, unit PA,
or CA qualifies as an ‘‘economically
marginal property’’:

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(1) ‘‘If the operator demonstrates that the
expected revenue generated from crude oil or
nature gas production volumes on that
property (above the operating costs
associated with those production activities)
is not sufficient to cover the nominal costs
of the capital expenditures required to
achieve measurement of non-commingled
production of oil or gas from that property
over a payout period of 18 months,’’ or
(2) If the operator demonstrates that ‘‘its
royalty net present value, or the discounted
value of the Federal or Indian royalties
collected on revenue earned from crude oil
or natural gas production on the lease, unit
PA, or CA over the expected life of the
equipment that would need to be installed to
achieve non-commingled measurement
volumes, is less than the capital cost of
purchasing and installing this equipment.’’

The final rule takes a somewhat
different approach than the proposed
rule to define these two circumstances.
Specifically, the final rule:
• Changes the threshold for what
qualifies as an economically marginal
property from a 10 percent, before tax,
rate of return in the proposed rule to an
18-month, after-tax, payout period in
the final rule;
• States explicitly that the economic
analysis considers operating costs;
• Clarifies that the analyses for oil
and gas commodities are done
separately, based on the income streams
from the commodity and the expenses
required to achieve non-commingled
measurement of that commodity; and
• States explicitly that if economic
circumstances change, and a Federal or
Indian lease, unit PA, or CA ceases to
be an economically marginal property,
the lease, unit PA, or CA will no longer
qualify for a CAA.
The BLM changed the first economic
threshold test from a 10 percent, before
tax, rate of return in the proposed rule
to an 18-month, after-tax, payout in the
final rule, primarily based on comments
received. As explained in the preamble
to the proposed rule, the initial test was
developed based on the provisions of
Instruction Memorandum (IM) 2013–
152. The purpose of the economic
analysis in IM 2013–152, the proposed
rule, and the final rule is to simulate the
analysis that a prudent operator would
make in deciding whether or not to
invest money to achieve noncommingled measurement of
production. If that analysis concludes
that it would be uneconomic for the
operator to make the investment and
they would instead opt to shut in the
property, then the BLM will grant
commingling approval. In these
situations, the BLM believes that it is in
the public interest to sustain production
by allowing commingling, even if
commingled measurement may be

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somewhat less accurate and hard to
verify than non-commingled
measurement.
The only question is how best to
identify the point at which a prudent
operator would choose to shut in rather
than invest in equipment to achieve
non-commingled measurement. Several
commenters said the proposed 10
percent rate-of-return cutoff point
(calculated before Federal, State, and
local taxes) was too low, and that the
BLM, should instead use a 20 percent
rate of return. Other commenters
recommended replacing the 10 percent
rate of return threshold with a payout
period. The BLM agrees with the
commenters who recommended that the
BLM use a payout period method rather
than a rate-of-return method, because
the former provides a simpler and more
objective picture of whether a particular
course of action is economically viable,
and it is a method commonly used by
industry.
Under the rate-of-return method in
the proposed rule, the BLM would have
had to assume a rate of return on initial
investment that would be sufficient for
a prudent operator to install metering
equipment to achieve non-commingled
measurement of a lease, unit PA, or CA.
The payout method used in the final
rule uses a formula to determine
whether the production volumes at that
lease, unit PA, or CA are sufficient to
generate enough net revenue, after taxes
and operating costs, to cover the
nominal cost of equipment installation
within the payout period. Additionally
it was clear from the comments received
that different companies apply different
rates of return to evaluate their
investments. For these reasons, the BLM
felt it was appropriate to replace the
rate-of-return method with the payout
method.
One commenter stated that industry
typically uses a payout period of 6
months to 18 months as the criterion for
deciding whether or not to invest in a
new project. The commenter went on to
state that a 15 percent rate of return
(before tax) yields approximately the
same result as a 22-month payout. An
18-month payout would be
approximately the same as a 20 percent
(before tax) rate of return, which is a
threshold suggested by several
commenters. Based on these comments,
the BLM believes that an 18-month
payout period is reasonably
representative of the threshold a
prudent operator would use to
determine the economic viability of
achieving non-commingled
measurement of production.
Additionally, there were a few
comments that recommended that the

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BLM evaluate alternative cost-benefit
methodologies and definitions,
including those found in the Federal Oil
and Gas Royalty Simplification and
Fairness Act of 1996, and the Interstate
Oil and Gas Commission report, entitled
Marginal Wells: Fuel for Economic
Growth, (2012). The BLM agrees with
these comments, noting that the
proposed 10 percent rate of return was
a starting point, as the proposed rule
specifically asked for feedback on the
suitability of the BLM’s using this rate
of return for identifying a ‘‘low-volume
property.’’ The BLM believes the 18month payout threshold used in the
final rule is consistent with these
comments.
Also unlike the proposed definition of
‘‘low-volume property,’’ the definition
of ‘‘economically marginal property’’ in
the final rule specifically considers
taxes, fixed and variable operating costs,
and commodity prices. While the ‘‘lowvolume property’’ definition in the
proposed rule implicitly included
operating costs and commodity prices in
the rate-of-return calculation, it did not
include taxes. The BLM believes that
the addition of taxes and the explicit
addition of operating costs and
commodity price considerations help to
make the payout calculation more
representative of an economic analysis
that a prudent operator would perform.
Finally, in the final rule definition,
the BLM clarified that the economic
analyses are specific to the commodity
to which the commingling request
applies. For example, if a lease produces
a high volume of gas with small
amounts of associated condensate, and
the operator wishes to commingle the
condensate production with similar
volumes of condensate produced from
private leases, the economic analysis
performed under § 3173.14(b)(1) would
only consider the income, costs, and
payout period related to measuring the
condensate. The BLM made this
addition to the final rule to clarify that
neither operators nor BLM field offices
should include the income and costs
from a commodity which the operator is
not proposing to commingle. The
proposed rule was silent on whether the
economic analysis should be based on
total oil and gas production or just on
the commodity the operator requests for
commingling. However, it was always
the BLM’s intent that this analysis occur
on the basis of the commodity for which
commingled measurement is proposed.
This clarification in the final rule is
consistent with that intent.
In support of the new definition for
‘‘economically marginal property’’ the
BLM added two additional definitions—
‘‘payout period’’ and ‘‘royalty net

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present value (RNPV)’’—each of which
is discussed (in alphabetical order)
below.
In addition, in the final rule the BLM
added a definition for the term ‘‘free
water.’’ That term appeared multiple
times in the proposed rule but was not
defined because the BLM believes it is
commonly understood by the industry.
While the BLM did not receive any
comments on the use of this term, the
BLM determined that it should
nevertheless include a definition in the
final rule to clarify its intent with
respect to the use of the term in this
regulation. The final rule therefore
defines ‘‘free water’’ as ‘‘the measured
volume of water that is present in a
container and that is not in suspension
in the contained liquid at observed
temperature.’’ This definition tracks the
commonly understood definition of the
term used routinely by industry and the
BLM.
The final rule modifies the definition
of the term ‘‘land description’’ from the
proposed rule in § 3173.1, to clarify the
information needed by the BLM. The
purpose of defining the term ‘‘land
description’’ in both the proposed and
final rules is to ensure that the
geographic location information that
operators occasionally provide to the
BLM meets the applicable standards.
Under the proposed rule, the BLM
defined ‘‘land description’’ to mean ‘‘the
geographical coordinates referenced to
the National Spatial Reference System,
North American Datum 1983 or latest
edition, in feet and direction from the
nearest two adjacent section lines, or, if
not within the Rectangular Survey
System, the nearest two adjacent
property lines, generated from the
BLM’s current Geographic Coordinate
database (Public Land Survey System).’’
The final rule modifies this definition to
require operators to provide information
about location that is consistent with
the U.S. Department of the Interior’s
Manual of Surveying Instructions (2009)
and that includes information about the
quarter-quarter section, section,
township, range, and principal meridian
of the proposed location. This
definitional change was not suggested
by commenters, but was made to make
the definition in § 3173.1 consistent
with the existing geographic location
information requirements of 43 CFR.
3162.6, which requires operators to have
geographic location information on their
well- and facility-identification signs.
Subpart 3173 requires operators to
record land descriptions on their site
facility diagrams, FMP applications,
water draining and hot-oiling
paperwork, and reports of theft or
mishandling of production. By

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confirming the definitional provisions
of these two requirements, the final rule
ensures consistency and allows BLM
inspectors to cross-reference the land
description information on a site facility
diagram with the geographic location
information on a given facility sign and
confirm that they are inspecting the
correct measurement facility. It should
be noted that the definition of ‘‘land
description’’ does contemplate the use
of ‘‘other authorized survey
designations acceptable to the AO, such
as metes-and-bounds, or latitude and
longitude,’’ which accounts for
instances where the land may be
unsurveyed or another survey method is
necessary.
As noted in the discussion above, to
support the implementation of the
definition of ‘‘economically marginal
property’’ the BLM added a definition
for the term ‘‘payout period,’’ which is
defined as ‘‘the time required, in
months, for the cost of an investment in
an oil or gas FMP at a specific lease, unit
PA, or CA to equal the nominal revenue
earned from crude oil production for an
oil FMP, or natural gas production for
a gas FMP, minus taxes, royalties, and
any operating and variable costs.’’ This
definition is consistent with the intent
behind the definition of ‘‘economically
marginal property’’ established by this
final rule. The definition clarifies that
payout periods are determined
independently for each oil and gas FMP
at a given lease, unit PA, or CA.
The BLM included a definition for the
term ‘‘permanent measurement facility’’
to the final rule in response to a
commenter’s concern with § 3173.12(d)
of the proposed rule, which required
operators to obtain FMP approval before
any production leaves a measurement
facility. The commenter pointed out that
during well testing, and before initiating
production, operators send oil to a
temporary tank or send gas down the
sales line to determine the well’s
production rate. The test results help
the operator determine the size and type
of measurement facility needed. The
commenter said it would be overly
burdensome to require operators to
obtain FMP approvals for temporary
measurement equipment used during
well testing as well as for permanent
measurement facilities.
The BLM agrees in part with this
comment and has provided a definition
for the term ‘‘permanent measurement
facility,’’ which means ‘‘all equipment
constructed or installed and used onsite for 6 months or longer for the
purpose of determining the quantity,
quality, or storage of production that
meets the definition of FMP under
§ 3170.3.’’ In addition, the final rule also

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clarifies that paragraphs (d) and (e) of
§ 3173.12, which pertain to when
operators must apply for their FMP
numbers, apply only to permanent
measurement facilities. Therefore,
temporary equipment used during well
testing operations, including temporary
tanks to store oil, are not affected by the
FMP requirement. However, since a
‘‘sales line’’ by definition is a permanent
facility, and any gas that travels through
it is royalty bearing, the BLM added a
6-month timeframe to the definition of
permanent measurement facility to
make clear that the FMP requirement
does not apply during well testing. Six
months was chosen because that is
when the BLM typically performs its
first environmental inspection of
production facilities after a well is
completed, and after that point, the
continued use of temporary equipment
at the wellsite would raise concerns that
an operator is having difficulty
installing its permanent facilities.
The BLM added a definition of
‘‘royalty net present value (RNPV)’’ to
support implementation of the term
‘‘economically marginal property.’’ The
final rule defines RNPV as the ‘‘net
present value of all Federal or Indian
royalties paid on revenue earned from
crude oil production or natural gas
production from an oil or gas FMP at a
given lease, unit PA, or CA over the
expected life of the metering equipment
that must be installed for that lease, unit
PA, or CA to achieve non-commingled
measurement.’’ This definition is
consistent with the intent behind the
definition of ‘‘economically marginal
property’’ established by this final rule.
The BLM also received comments
concerning its use of the term ‘‘royaltyfree use.’’ Specifically, a commenter
expressed concern that the terms
‘‘beneficial use’’ and ‘‘royalty-free use’’
were used interchangeably multiple
times in the preamble discussion of the
proposed rule, without any definitions
being offered for either term. The
commenter also noted that only the term
‘‘royalty-free use’’ was used in the
proposed rule itself, and no definition
was provided. The commenter
suggested a definition of ‘‘royalty-free
uses,’’ which specifically included all
equipment and facilities serving
directionally or horizontally drilled
wells that may be located off the lease.
The BLM agrees with the commenter
that it should not have used the two
terms interchangeably. The BLM should
have used the term ‘‘royalty-free use’’
rather than ‘‘beneficial use,’’ because the
former is more specific and more
applicable in the context of this rule.
For example, the term ‘‘beneficial use’’
sometimes refers to using produced

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water for other purposes, such as a
water source for livestock or for
enhancing vegetation regrowth during
reclamation, both of which have nothing
to do with production verification and
accountability.
The BLM did not, however, feel it was
necessary to provide a definition for
royalty-free use at this time. First, the
royalty-free use of oil or gas from
onshore Federal and Indian leases,
units, and CAs is governed by the
longstanding Notice to Lessees and
Operators 4A (NTL–4A) and the BLM
believes the concept to be well
understood by operators. Second, the
BLM plans to update its regulations
pertaining to the royalty-free use of oil
and gas as part of a separate
rulemaking—Waste Prevention,
Production Subject to Royalties, and
Resource Conservation (81 FR 6616)
(Waste Prevention Rule)—that will
provide additional clarity on the
royalty-free use of oil and gas from
onshore Federal and Indian leases. Until
such time as the Waste Prevention Rule
is finalized, for the purpose of this final
rule, the meaning of the term ‘‘royaltyfree use of oil and gas’’ will be
consistent with the royalty-free use of
oil or gas as currently defined in NTL–
4A. No changes were made to proposed
rule in response to this comment.
Section 3173.2 Storage and Sales
Facilities—Seals
Paragraphs (a) and (b) of § 3173.2
require any lines entering or leaving any
oil storage tank or storage facility to
have valves capable of being effectively
sealed during specific operational
phases—production, sales, water
draining, or hot oiling.
Paragraph (c) identifies the specific
types of valves that are not considered
‘‘appropriate valves’’ (i.e., valves that
must be sealed during the production
phase or the sales phase) and, as such,
are not subject to the requirements of
subpart 3173. These valves include
valves on production equipment; valves
on water tanks, so long as there is no
possibility of access to production;
valves on tanks contains waste or slop
oil; sample cock valves; fill-line valves
on certain marginal production tanks;
gas line valves; heating system valves;
pump valves; tank vent-line valves; and
sales, equalizer or fill-line valves on
systems where production may only be
removed through an approved metering
system.
Paragraph (d) prohibits tampering
with an ‘‘appropriate valve,’’ and
specifies that tampering may result in
assessment of civil penalties for
knowingly or willfully preparing,
maintaining, or submitting false,

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inaccurate, or misleading information
under Section 109(d)(1) of FOGRMA, 30
U.S.C. 1719(d)(1), and 43 CFR
3163.2(f)(1), or for knowingly or
willfully taking, removing, transporting,
using, or diverting oil or gas from a lease
site without valid legal authority under
Section 109(d)(2) of FOGRMA, 30 U.S.C.
1719(d)(2), and 43 CFR 3163.2(f)(2).
The BLM received many comments
on proposed § 3173.2. Several
commenters expressed concern with the
relationship between the general
prohibition against tampering under
§ 3170.4 of the proposed rule and the
specific prohibition against tampering
with any appropriate valve under
proposed paragraph (d) of this section.
One commenter, in particular, was
concerned that under the new
requirements the commenter would not
be able to perform maintenance on
valves without the procedure being
considered tampering or unauthorized
seal removal. Two other commenters
stated that the criteria for determining
what qualifies as tampering were
overbroad and ambiguous. They also
questioned if an unintentional act or
human error would be considered
tampering.
The BLM believes these comments
have merit and, as discussed previously,
has added a definition of the term
‘‘tampering’’ to § 3170.3 of the final rule.
As previously noted, ‘‘tampering’’
means any deliberate adjustment or
alteration to the meter or measurement
device, appropriate valve, or
measurement processes that could
introduce bias into the measurement or
affect the BLM’s ability to
independently verify volumes or
qualities reported. This definition
should help the public understand how
the BLM will determine whether a
particular incident constitutes
tampering.
As for operator maintenance on
valves, such acts will not be considered
tampering as long as the maintenance
work does not alter the valve or
introduce bias into the measurement. If
the valve being worked on falls under
the seal requirements (i.e., it is used in
the process for determining the quantity
or quality of oil for royalty purposes), it
is permissible to remove the seal for
maintenance purposes as long as the
specific reason for removing the seal is
noted in the seal record. The BLM did
not change the final rule to address this
comment.
Another commenter stated that valves
would need to be changed out in
response to the requirements under this
section, making marginal wells
unprofitable. The BLM does not believe
that any valves will need to be changed

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out because these requirements are the
same as those in Order 3, which already
requires all appropriate valves capable
of being effectively sealed to be sealed.
Since this provision merely continues
existing requirements, no changes to the
final rule were made in response to this
comment.
Another commenter was concerned
that proposed § 3173.2(c)(3), which
exempts valves on tanks that contain oil
that the AO or authorized representative
(AR) has determined to be waste or slop,
would impose additional costs on
operators because of the time it could
take the AO or AR to make the
determination. While waiting for the AO
or AR determination, the commenter
said, operators would have to spend
money on additional tanks to store their
slop or waste oil. The BLM disagrees.
This requirement is very similar to the
existing requirements of Order 3, and
therefore will not impose any additional
burdens on operators. A company will
not need a new tank while waiting for
a determination from the AO or AR;
rather the company will have to
properly seal any tanks holding such oil
until it is determined to be slop oil or
waste oil. The cost to obtain a seal
should not present any sort of monetary
hardship for the operator. Thus, the
BLM did not make any changes in
response to this comment.
Section 3173.3 Oil Measurement
System Components—Seals
Section 3173.3 of the final rule
identifies a nonexclusive list of the
components used in LACT meters or
Coriolis oil measurement systems (CMS)
that must be effectively sealed to
indicate whether tampering may have
occurred. The BLM received a few
comments on this section of the
proposed rule.
One commenter stated that the
proposed seal requirements are much
more extensive than those in Order 3
and will create additional burden and
expense for the operator because seals
routinely break and the seal-reporting
requirements for these instances under
§ 3173.9 are fairly detailed. In addition,
the commenter said there is a risk of
delayed revenue while the operator
waits for the AO to approve removal of
a seal. The BLM disagrees that the seal
requirements are much more extensive
than those found in Order 3. This final
rule adds only four items to the Order
3 list of components that are used for
quantity or quality determination of oil
and that must therefore be effectively
sealed. Those four additional
components are the right-angle drive,
totalizer, prover connections, and valves
on diverter lines larger than 1 inch in

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nominal diameter. The BLM does not
believe seal requirements for these
components are particularly
burdensome, and, since they all are
points where tampering could occur, it
is important that they be subject to the
same sealing requirements as other
components of the measurement system.
As for the commenter’s concern about
revenue being delayed while an
operator waits for the AO to approve
removal of a seal—under normal
circumstances, there is no need to wait
for AO approval to remove a seal. Seals
may be taken off and put back on as
long as these events are recorded in the
seal record. In the event a Federal seal
is placed on a component, the AO must
provide approval prior to any removal;
however, an AO can provide verbal
approval to remove a Federal seal as
soon as the associated violation is
corrected. These comments did not
result in any changes to the final rule.
One commenter said they could not
determine what effect proposed § 3173.3
would have on their operations when
related requirements—contained in the
rulemaking that is replacing Order 4 (oil
measurement)—had not yet published
or been made available for public
comment. The additional requirements
cross referenced in proposed § 3173.3
can be found in proposed 43 CFR
3174.8(a) (for LACT systems) and
proposed 43 CFR 3174.9(e) (for Coriolis
systems). The BLM recognized the need
for both sets of requirements to be
available for public comment at the
same time, which is why the comment
period for this proposed rule was
extended from its original September
11, 2015, closure date until December
14, 2015, in order to ensure there was
sufficient overlap between the comment
periods for the proposed rules for
subparts 3173, 3174, and 3175. This
overlap gave operators an opportunity to
review the parts of proposed subpart
3174 that were referenced in § 3173.3.
This comment did not result in any
changes to the final rule.
Another commenter said that the seal
requirements for oil measurement
systems are only appropriate at those
points where theft or mishandling can
realistically occur, and the requirements
under this section are unnecessary. The
commenter suggested that the BLM
maintain the seal requirements in Order
3, which address the sealing of tanks
when oil is sold through a LACT. The
BLM did not make a change in response
to this comment. The BLM does not
believe that theft or mishandling, which
affects only the quantity of the oil being
measured, are the only factors that may
impact the determination of royalties
owed. The quality of the oil being

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produced will also influence royalty
determination. For this reason, the BLM
believes it is necessary to have a section
in the rule dedicated to ensuring that all
components of an oil measurement
system that are used to determine the
quality and quantity of oil must be
effectively sealed. The BLM does agree
with the commenter’s suggestion that
we maintain Order 3’s seal
requirements, which is why they were
incorporated into the list of components
that must be sealed under § 3173.3 of
this final rule.
The BLM also received several
comments stating that some components
of a LACT are not capable of being
sealed, such as flow computers and back
pressure valves. The commenters said
flow computers are not capable of
accepting a seal and back-pressure
valves cannot operate if they are sealed.
These commenters recommended that
the BLM not subject these two
components to the § 3173.3 sealing
requirements. A third commenter stated,
without providing specifics, that some
of the devices listed in this proposed
section are not constructed to be sealed.
The commenter suggested that sealable
components would have to be
purchased or a secondary device would
have to be built to allow for sealing.
Without more specific information, the
BLM cannot address this comment.
However, prior to issuing this final rule,
the BLM re-assessed the components
listed in this section and continues to
believe, except as noted below, that all
of the identified components can
reasonably be sealed, as all of them are
routinely sealed today.
With regards to requiring flow
computers to follow this final rule’s seal
requirements, commenters should be
aware that the intent of sealing the flow
computer is to have a log of when
someone accesses the software. Sealing
a flow computer could be accomplished
through a lead wire seal, adhesive
backed paper (sticker), or plastic seal, or
a password and an event log. However,
in response to this comment, the BLM
has changed the final rule. The BLM
removed flow computers from
paragraph (a)(5) of this section and
added a new item to the list—LACT or
CMS—in paragraph (a)(6), giving the
operator the opportunity to decide how
best to ensure that the flow computer is
sealed. As a result of these changes,
paragraphs § 3173.3(a)(6) through (12) in
the proposed rule are redesignated as
§ 3173.3(a)(7) through (13) in the final
rule.
As for concerns raised about the
inability to seal back-pressure valves,
the BLM has made a change in response
to this comment. In 3173.3(a)(7) of the

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final rule (§ 3173.3(a)(6) in the proposed
rule), the BLM has clarified that the
component that is subject to the seal
requirement is the back pressure valve
pressure adjustment. Sealing the
pressure adjustment on the backpressure valve was already required
under Order 3. The BLM believes it is
important to preserve this requirement
because if the pressure adjustment is
changed after a meter proving, it could
change the flow rate of hydrocarbons
through the meter, impacting the
accuracy of the measurement based on
the prior proving.

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Section 3173.4

Federal Seals

In the final rule, paragraph (a) of
§ 3173.4 codifies the authority in section
IV of Order 3, which calls for the BLM
to place a Federal seal on any
appropriate valve, sealing device, or oil
meter system component that does not
comply with the requirements of final
§§ 3173.2 or 3173.3. Paragraph (b)
clarifies that the placement of a Federal
seal does not relieve the operator of the
requirement to comply with §§ 3713.2
or 3173.3. Paragraph (c) prohibits the
removal of a Federal seal without BLM
approval.
The BLM received several comments
requesting that Federal seals not be
attached immediately upon discovery of
a violation that warrants placement of a
seal. Two commenters requested a 10day notice prior to the BLM placing a
Federal seal, and another commenter
requested that a reasonable time be
given to bring the component into
compliance prior to the BLM attaching
a Federal seal. Other commenters said
the BLM should not be sealing or
changing valves or any other production
components without an operator’s
representative being present to witness
the change. Commenters recommended
that the BLM give notice to the operator
as to why the seal was placed, and the
procedure for removing the seal.
The BLM did not change the final rule
in response to these comments because
the only violations that would cause the
BLM to place a Federal seal on valves
or production equipment would be
those that are considered major, as
defined in 43 CFR 3160.0–5—that is,
noncompliance actions that could cause
or threaten immediate, substantial, and
adverse impacts on health and safety,
the environment, production
accountability, or royalty income. Since
the seal requirements in §§ 3173.2 or
3173.3 of this final rule were put in
place to ensure that tampering does not
occur, the BLM generally believes these
incidents of noncompliance constitute
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However, the BLM believes that some
of the commenters’ concerns have merit,
and will ensure that its Inspection and
Enforcement Handbook provides clear
guidance to BLM inspectors that: They
must not change the position of a valve
or component; the Federal seal must be
attached to the valve or component as
found; and each Federal seal installed
must have a card attached that identifies
it as a Federal seal, and advises that the
removal or violation of the seal without
approval by the AO will result in an
immediate assessment of $1,000. The
name and telephone number of the AO
will be shown on the card. In addition,
the operator will also receive notice in
the form of an INC that will address all
the violations associated with the
Federal seal that the operator must
correct prior to removal of the seal. The
BLM did not make any changes to the
final rule in response to this comment.
Section 3173.5 Removing Production
From Tanks for Sale and Transportation
by Truck
Section 3173.5, paragraphs (a) and (b),
of the final rule make clear that, at the
completion of either a single or a
multiple truckload sale, the driver of the
load(s) must possess all the information
that is required in § 3174.12. Under
paragraph (c), once the seals are broken,
the purchaser or transporter is
responsible for the entire contents of a
tank until it is resealed.
The BLM received a comment asking
us to delay this final rule until we
publish and make available for public
comment two related rulemakings that
will replace Orders 4 (subpart 3174) and
5 (subpart 3175). The commenter noted
that § 3173.5(a) and (b) require truck
drivers to possess certain information
after oil sales, but the information will
be set forth in § 3174.12, which was
proposed in the separate Order 4. The
BLM recognizes the commenter’s
concern, at least as it relates to the
proposed rule to replace Order 4, which
is why the comment period for this
proposed rule was extended from its
original September 11, 2015, closure
date until December 14, 2015, to ensure
there was sufficient overlap between the
comment periods for the proposed rules
for subparts 3173, 3174, and 3175. This
overlap gave operators an opportunity to
review the parts of proposed subpart
3174 that were referenced in § 3173.5.
This comment did not result in any
changes to the final rule.
Several commenters expressed
concern with language in paragraph (c)
that makes the purchaser or transporter
responsible for the entire contents of the
oil tank from the time that the seals are
broken until it is resealed. The

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requirements in paragraph (c) are taken
directly from Order 3 with one minor
modification. Under section III.C.1.c of
Order 3, only the ‘‘purchaser’’ is
responsible for the entire contents of the
unsealed tank during a sale. The
commenters stated that § 3173.5(c)
would be a burden on transporters
because it will cost them time and
money to wait on-site for tanks to be
resealed by the facility’s operator after
an oil sale. The BLM disagrees with this
comment. It is standard practice for
transporters, whether or not they are the
purchasers, to remove and replace seals
without the operator’s representative
being on location. Transporters do this
because it protects them from liability if,
subsequently, produced oil cannot be
accounted for. No changes were made to
the final rule as a result of this
comment.
Section 3173.6 Water-Draining
Operations
Section 3173.6 of the final rule
requires the operator, purchaser, or
transporter, as appropriate, to record
specific information when water is
drained from tanks that hold
hydrocarbons, including the total
observed volume (TOV) and free water
that are in the tank before, and TOV
after, water is drained. Order 3 did not
require operators to record these
volumes, which could have led to
hydrocarbons being drained with the
water and removed without proper
measurement and accounting, and
without royalties being paid.
The BLM received many comments
regarding this section. Several
commenters stated that the
documentation requirements were
excessive and added little to no value to
accounting for production. The BLM
made several changes in response to
these comments, to reduce
documentation requirements and
eliminate any confusion over when
operators should document the FMP
number during water-draining
operations. Specifically, the BLM
reduced the overall amount of
information that operators must
document by eliminating from this
section the requirements that operators
record the opening and closing gauge
times, the name of the person and
company draining the tank, and the
FMP number associated with the tank.
Another commenter questioned
whether the requirement to identify the
FMP associated with a tank subject to
this provision would mean that an FMP
is required for each condensate tank in
the field. By way of clarification,
condensate tanks, just like oil storage
tanks, must have FMP numbers.

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However, oil and condensate tanks that
are part of a tank battery share the same
FMP number.
Another commenter recommended
that the BLM exempt ‘‘low-volume
sources’’ from the requirements, to
reduce the paperwork and recordmaintenance costs for operators of such
sources. The BLM does not believe that
an exemption for small producers (or
operators of low-volume sources) is
appropriate and did not change the final
rule as a result of this comment. As
noted earlier, it is important for all
operators to ensure that hydrocarbons
are not being drained with the water
and removed without proper
measurement and accounting, and
without the royalties due being paid.
Having operators record the volume of
hydrocarbons that are in the tank before
and after water is drained helps ensure
that the proper royalties are paid. When
performing production accountability
inspections, the BLM will compare
these water-draining records, along with
other production and sales records, with
production reports that operators submit
to ONRR. These records will allow the
BLM to independently verify
production that is attributable to Federal
and Indian leases. The BLM did not
make any changes in response to this
comment.
One commenter said the existing
Order 3 seal requirements already
prevent theft of oil because they provide
a tracking mechanism for the transfer of
any liquids from production tanks, and
therefore the provisions of the proposed
rule were unnecessary. The BLM
disagrees that Order 3’s seal
requirements already prevent theft of
oil. Existing requirements related to seal
records do not provide any information
on how much TOV is in a tank before
and after water is drained. They merely
show when a tank is sealed and
unsealed, and by whom, not what was
drained, nor how much was removed
from the tank. No changes were made to
the final rule as a result of this
comment.
Other commenters stated that § 3173.6
would require the gauging of tanks prior
to and after a sale. They said that while
such a practice is necessary during
custody transfer, this requirement could
be hazardous to employees because it
would unnecessarily expose them to
benzene or volatile organic compounds
(VOC). In response to these comments,
the BLM added new language to
paragraphs (e) and (g) that allows either
manual or automatic gauging for the
opening and closing gauge, TOV, and
free-water measurements, all of which
must be to the nearest 1⁄2 inch. Giving
operators the option of conducting this

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measurements using automatic gauging
will provide an opportunity for
operators to reduce employees’
exposure in the field.
Finally, one commenter said the
color-cut measurement method
requirement in the proposed rule is not
accurate for indicating water oil contact
with heavy oils that are less than 30
degrees gravity. The commenter said
that an opening and closing gauge
would be a sufficient indicator to
determine the amount of water in the
tank. The BLM agrees with the comment
that color-cut measurements are not
accurate in some situations and has
removed this requirement from the final
rule. Instead, paragraph (e) has been
rewritten to require operators to simply
document ‘‘free-water measurements,’’
which allows operators to use any
reliable method for measuring free
water, including electronic equipment.
Section 3173.7 Hot Oiling, Clean-Up,
and Completion Operations
Section 3173.7(a) of the final rule
requires that specific information be
recorded when hydrocarbons are
removed from storage and used on the
lease, unit PA, or CA for hot oiling,
clean-up, and completion operations,
including the volume of hydrocarbons
removed from storage and expected to
be returned to storage. Paragraph (b)
requires operators to consider as sold,
and to measure following the
requirements of this final rule, any
production used from storage for hot
oiling, line flushing, or completion
operations on a different lease, unit PA,
or CA.
Under Order 3, the operator was
required to record only the date, seal
number removed, new seal number
installed, and the reason for removing
oil for hot-oiling, clean-up, or
completion operations. The operator
was not required to record the volume
of hydrocarbons that was removed from
storage and were expected to be
returned. This omission could have led
to the volume of produced
hydrocarbons being counted twice—first
when it was initially produced then
later after it was returned to storage.
The BLM received many comments
on this requirement. A few commenters
said that an operator’s field personnel
are on hand, closely monitoring these
types of operations, ensuring that the oil
is returned to the tank and that it is
counted just once. Commenters said
there is no reason for the BLM to require
operators to maintain records of these
volumes because operators only pay
royalties on oil that is sold, not oil that
is produced, and hot-oiling, clean-up,
and completion operations are unrelated

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to sales. The BLM agrees that having an
operator’s field personnel on hand,
closely monitoring these operations, is
ideal for ensuring that oil is not counted
twice during these operations. However,
the BLM’s experience has shown that in
many instances field personnel do not
monitor these operations because they
are called away for other duties. The
BLM did not change the final rule in
response to this comment, because the
BLM believes there is a need to address
inconsistent practices among operators
and to ensure there is proper
documentation of the volume of oil used
in these operations.
In response to the comment that hot
oiling, clean-up, and completion
operations have nothing to do with sales
volumes, the BLM notes that it is
required to verify not only sales
volumes but also production volumes
and to report on avoidably lost gas
under NTL–4A. Hot oiling, clean-up,
and completion all involve production
volumes, and therefore are properly
within the scope of the proposed rule.
Another commenter said the BLM
does not have the authority to impose
the requirements under this section,
requested that the BLM explain why
these new requirements are necessary,
and asked that we provide the legal
citation for the new law that justifies
this authority. The BLM’s authority to
impose site-security, record-keeping,
and production accountability
requirements for the production of
Federal and Indian oil and gas is not
‘‘new.’’ The statutes authorizing the
BLM to issue this rule have been in
place for decades and were identified
earlier in this preamble. These statutes
include the ones that were identified as
the basis for existing Order 3.
A few commenters said that the
requirement that operators gauge oil
level, maintain seals, track FMPs, gauge
tanks, etc., during completion
operations will add to the workload of
field personnel performing those tasks.
For example, an employee will need to
be onsite 24 hours a day, 7 days a week
to make sure the seal changes are
recorded on the run tickets and logged
properly for tracking purposes. Several
commenters said the documentation
requirements under this section were
excessive and added little to no value to
production accounting.
The BLM agrees with these
commenters that the proposed
documentation requirements were too
expansive and in response changed the
final rule to reduce the amount of
information that operators must
document during hot oiling, clean-up,
and completion operations. In the final
rule, the BLM removed requirements

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that operators document the opening
and closing gauge times; the name of
person and company removing
production from the tank; and the FMP
number associated with the tank or
group of tanks. The BLM has accounted
for the costs of these revised
recordkeeping requirements in its
Paperwork Reduction Act analysis,
which we discuss later in this preamble,
and concludes that they are not a
significant financial burden on
operators.
With respect to the general concern
that these requirements are unnecessary,
the BLM does not agree. These
requirements are important and
represent an important part of the final
rule, because in their absence, operators
could drain, transfer, or sell
hydrocarbons without measuring and
accounting for them during hot oiling,
clean-up, and completion operations,
resulting in incorrect royalties being
paid. The BLM will use these records
when performing production
accountability inspections. Specifically,
it will compare records from hot oiling,
clean-up and completion operations,
and other production and sales records,
with reports that operators submit to
ONRR. This will allow the BLM to
independently verify production that is
attributable to Federal and Indian
leases.
As for the commenter’s claim that
these recordkeeping requirements for
well completion operations would
necessitate an operator’s field personnel
to be present at the wellsite 24/7, the
BLM does not have enough information
to respond to this comment. While the
BLM agrees that, in general, operators
will now have to document more
information than they have been
documenting under Order 3, the BLM
does not believe that any of these
additional recordkeeping requirements
will require company personnel to be
onsite 24/7. The final rule was not
changed as a result of this comment.
The BLM did not receive any
comments on paragraph (b). However,
the BLM makes a clarification in the
final rule that the production reported
to ONRR as sold must be ‘‘for the period
covering the production in question.’’
Section 3173.8 Report of Theft or
Mishandling of Production
Section 3173.8 of the final rule
includes security provisions that are
intended to prevent theft or
mishandling of oil, complementing the
minimum standards for site security and
production handling established in this
rule. Paragraph (a) requires operators,
transporters, and purchasers to report
verbally all incidents of theft and

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mishandling of production to the BLM
no later than the next business day after
they or their employees discover them.
Paragraph (b) specifies the information
that must be included in a written
incident report, which is required
within 10 business days of any oral
report. Such reports must be made the
next business day after discovery and
may be made orally or through a
‘‘written incident report.’’ Oral reports
must be followed by written reports
within 10 business days. Adding
purchasers and transporters to these
requirements is a change from Order 3,
which required only operators to report
theft or production mishandling, but is
consistent with the overall approach to
these requirements in the proposed and
final rules.
Many commenters were concerned
about the requirement in paragraph (a)
that purchasers and transporters report
incidents of theft and mishandling to
the BLM, and questioned the BLM’s
authority to impose such a requirement
on them. Since the wells and facilities
belong to the operator, commenters said,
the operator should be the one reporting
all theft and production mishandling.
The commenters said it would be
redundant and unnecessary to have
purchasers and transporters reporting
theft and mishandling to the BLM, and
could lead to multiple reports and
confusion. A few commenters added
that this change could make operators
accountable for potentially arbitrary and
inaccurate third-party reports of theft or
production mishandling.
Finally, some commenters asked why
operators could be subject to an
immediate assessment when they fail to
report theft or mishandling to the BLM.
The BLM believes it is necessary to
require purchaser and transporters, in
addition to operators, to report instances
of theft or production mishandling
when they discover them because, as
noted in the proposed rule preamble,
purchases and transporters are
sometimes the first to discover such
instances or to recognize suspicious
activity. When transporters or
purchasers report theft or production
mishandling, the BLM intends to work
with transporters, purchasers, and
operators to verify the reports, with each
party being responsible for the
information it provides. The BLM’s
authority to require purchasers and
transporters to report theft or
production mishandling comes from
Section 103(a) of FOGRMA, which
provides that ‘‘a lessee, operator, or
other person directly involved in
developing, producing, transporting,
purchasing, or selling oil or gas . . .
shall establish and maintain any

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records, make any reports, and provide
any information that the Secretary may,
by rule, reasonably require for the
purposes of implementing this Act or
determining compliance with rules or
orders under this Act.’’ Sections
102(b)(2) and 301(a) of FOGRMA allow
the BLM to prescribe any rules,
regulations, or appropriate measures to
protect oil from theft. The final rule
simply places the same expectations on
purchasers, transporters, and operators,
which are all parties involved in
production, for reporting theft and
mishandling of production.
The BLM does not agree that requiring
purchasers and transporters to report
theft and production mishandling
creates confusion or is redundant and
unnecessary. Reports by purchasers and
transporters, together with information
provided by operators, will improve the
existing reporting system by giving the
BLM more facts faster to investigate
these situations. No changes were made
to the final rule as a result of these
comments.
Other commenters discussing the
provisions of the proposed rule related
to theft or mishandling did not agree
with the BLM’s decision to eliminate
the self-inspection requirements
contained in Order 3 section III.F,
which are related to Order 3’s
requirements for reporting theft or
mishandling of oil. The purpose of the
self-inspection requirement, according
to those commenters, was for operators
to periodically measure production
volumes to assure that they complied
with the BLM’s minimum site security
requirements. These commenters said
that self-inspection programs are a good
practice, and that it would not be
appropriate for the BLM to find an
operator in violation of this section if
they elect to implement a selfinspection program and report
incidences of theft and mishandling.
The commenters encouraged the BLM to
maintain the Order 3 requirements for a
self-inspection compliance program,
rather than eliminate them.
It has been impractical for the BLM to
enforce the Order 3 self-inspection
requirements because the requirements
were vague, and the BLM never
supplemented them with internal
guidance or enforcement policy. This
final rule replaces the Order 3 selfinspection program with stronger
recordkeeping and documentation
requirements, such as those in § 3173.9
(Required recordkeeping for inventory
and seal records). As explained in the
recordkeeping section of this preamble,
we believe this approach will ultimately
improve overall production verification
and accountability. That said, the BLM

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does not disagree with the notion that
self-inspection programs can help with
a company’s internal compliance efforts,
and nothing in the final rule would
prohibit a company from implementing
such a program on its own initiative. No
changes were made in response to this
comment.
As for the commenters’ suggestion
that the BLM not issue immediate
assessments or take enforcement actions
against those operators who are
implementing a self-inspection program,
the BLM does not agree with this
suggestion. The BLM takes enforcement
actions against operators that fail to
report theft or production mishandling.
The fact that an operator has a selfinspection plan in place does not and
should not immunize the operator from
enforcement for a failure to report.
Under the final rule, consistent with the
proposed rule, an operator that fails to
report is subject to an immediate
assessment under § 3173.29 (Immediate
Assessments) of the final rule. No
change was made in response to this
comment.
Finally, a number of commenters
suggested that the BLM should be told
whether incidents of theft or production
mishandling have also been reported to
law enforcement and company security
in addition to the BLM. The BLM agrees
that it needs to know if law enforcement
and company security have been
notified and added a new paragraph
(b)(8), which now includes this
requirement. This change will help the
BLM work with company security and
law enforcement to investigate and
prosecute alleged incidents of theft and
production mishandling in order to
prevent future occurrences.
Section 3173.9 Required
Recordkeeping for Inventory and Seal
Records
Paragraph (a) of this section of the
final rule requires operators to perform
an end-of-month inventory consisting of
the TOV in storage (measured to the
nearest 1⁄2 inch), subtracting free water,
and the volume not corrected for
temperature/S&W, as reported to ONRR
on the OGOR. Paragraph (b) specifies
the records that an operator must
maintain for each seal.
The BLM received several comments
on proposed § 3173.9. In the proposed
rule, operators were simply required to
measure and record the TOV in storage
at the end of each calendar month. A
few commenters said they did not have
the ability to measure inventory at all
sites on the actual last day of the month
due to the number of tanks they operate,
the volume corrections for temperature/
S&W, and the accuracy needed to meet

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the measurement standards of this
section.
The BLM agrees that operators may
not be able to measure all inventory on
the very last day of the month,
especially those operators who have
large numbers of storage tanks. In
response, the final rule provides two
options for an operator to perform an
end-of-month inventory. The operator
can either perform the measurements
within +/¥3 days of the end of the
month, or it can interpolate the values
based on daily production values and
gross sales volumes, using inventory
measurements taken before and after the
final day of the month. To help guide
operators on the interpolation of their
end-of-month inventories, the BLM
provides the following equation in
paragraph (b)(2) of this section, as well
as an example of how the equation is to
be applied:
{[(X + Y¥W)/Z1] * Z2} + X = A,
Where:
A = calculated end of month inventory;
W = first inventory measurement;
X = second inventory measurement;
Y = gross sales volume between the first and
second inventory;
Z1 = number of actual days produced
between the first and second inventory;
and
Z2 = number of actual days produced
between the second inventory and end of
calendar month for which the OGOR
report is due.

These alternate approaches to
maintaining inventories give operators
more flexibility to meet the BLM’s
recordkeeping requirements, but still
ensure monthly volume measurements
are recorded.
Other commenters interpreted the
proposed section to mean that operators
were required to gauge their storage
tanks manually, since at the time the
proposed rule was released the BLM’s
oil measurement regulations did not
allow operators to use automatic tank
gauging systems. As a result, these
commenters asserted that requiring
operators to manually gauge tanks
would unnecessarily expose their
employees to hazardous fumes. The
BLM understands this concern and has
added clarifying language to the final
rule that allows operators to measure
TOV either manually or with automated
systems. The BLM was able to make this
change because in the related
rulemaking that is replacing Order 4
with a new subpart 3174, operators now
have the ability to use automatic tank
gauging systems for oil sales, and thus
such a system will also be permissible
for inventory maintenance.
Other commenters said this section
was not necessary because recording the

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TOV in tanks is routine practice under
sales contracts, and the seal
requirements in paragraph (b) of this
section are unnecessary because they
are already covered in §§ 3173.2 and
3173.3 of the proposed rules. With
respect to those comments stating that
recording the tank TOV is routine
operator practice under sales contracts,
it should be noted that those
recordkeeping activities relate to
periodic tank sales. Those records do
not allow the BLM or the operator to
determine monthly production or to
detect theft or improper handling of
production like an end-of-month
inventory does. Additionally, operators
are already required to report end-ofmonth inventories to ONRR so this
requirement should not create an
additional burden for operators. The
BLM did not change the final rule in
response to this comment.
With respect to the concerns about
paragraph (b), the BLM disagrees that
the seal recordkeeping requirements are
already covered in §§ 3173.2 and
3173.3. Those two sections only identify
which valves or components must be
sealed. They do not address the
recordkeeping requirements associated
with such seals. The BLM did not
change the final rule in response to this
comment.
Finally, some commenters asserted
that paragraph (b) should not apply to
purchasers and transporters because
they are not responsible for installing or
maintaining such seals. The BLM agrees
that § 3173.9, particularly paragraph (b),
does not apply to purchasers and
transporters. However, the BLM did not
change the rule in response to this
comment because the text in § 3173.9
makes clear that its requirements apply
solely to operators.
Section 3173.10 Form 3160–5, Sundry
Notices and Reports on Wells
Section 3173.10, paragraphs (a) and
(b), require all parties involved in
Federal and Indian oil and gas
production to submit Sundry Notices,
Form 3160–5, electronically to the BLM
for their site facility diagrams, requests
for FMP designations, requests for
CAAs, requests for off-lease
measurement, and any amendments to
the diagrams or requests. As noted in
the preamble of the proposed rule,
requiring electronic submission will, in
the long run, increase efficiencies
throughout BLM field offices, for both
the BLM and operators, by making the
diagrams easier to track and more
accessible to inspectors in the field.
Paragraph (b) provides an exemption
from the electronic-filing requirement

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for small operators that do not have
access to the Internet.
Several commenters supported the
proposed requirements for online filing,
but were concerned with the BLM’s
ability to handle a significant increase
in electronic submissions ‘‘at one time,’’
and wanted the BLM to clarify what it
means when it says that this change
will, in the long run, increase BLM
efficiencies. Some of these same
commenters said they were concerned
with the ability of the BLM’s existing
WIS to handle this volume of
submissions.
Requiring electronic submission of
Sundry Notices and Reports on wells
provides both operators and the BLM
with an efficient chronological method
for tracking items submitted for
approval, rather than relying on hard
copies. The BLM is aware that the Well
Information System has had problems in
the past, and is working on an improved
version of its in-house database, known
as AFMSS II. As part of its transition to
AFMSS II, the BLM is evaluating
industry information technology
standards, such as XML, to develop a
system that will make data sharing and
management as seamless as possible
between the BLM and the public. That
said, even the existing system should
not prevent the BLM from realizing the
benefits of electronic filing of facility
diagrams.
One of the reasons the proposed rule
gave operators a phase-in period to
apply for an FMP on existing leases,
units, and CAs was to help the BLM
avoid having to process a flood of
Sundry Notices at one time. Under the
proposed rule, operators would have
applied for their FMP numbers over a 9to 27-month period, starting on the
effective date of the final rule, on a
tiered scheduled based on production
level, with the highest producing wells
having the earliest required application
date. As discussed later in this
preamble, the final rule extends the
phase-in periods for the FMP
application process to 12, 24, and 36
months, based on production level
thresholds that are similar to those in
the proposed rule. This will give some
operators up to 3 years after the effective
date of this final rule to apply for an
FMP for stand-alone leases, CAs, unit
PAs and CAAs. If a stand-alone lease,
unit PA, or CA has not produced for a
year or more before the effective date of
this final rule, the operator will not
need to apply for an FMP until
resuming production. The BLM believes
that these changes will substantially
reduce the number of electronic filings
the BLM must process at any one time,

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reducing the risk that its systems lack
the capacity to handle the submissions.
Similarly, and as explained below in
connection with § 3173.11(d) and (e),
the BLM has also modified the proposed
rule’s requirements for updated site
facility diagrams. Instead of requiring all
facilities to upgrade their diagrams with
30 days of receiving an FMP, as was
suggested in the proposed rule, under
the final rule site facility diagrams at
existing facilities will only have to be
updated when or if the existing facility
is modified (e.g., when equipment or
wells are added or removed, when colocated facilities are added, or when
there is a change in operator). This
change reduces the overall number of
Sundry Notice submissions associated
with site facility diagrams and helps
distribute notice submissions over time.
Some commenters wanted to know if
the BLM will send out electronic
notifications when it approves Sundry
Notices that have been filed
electronically. The BLM will provide
such notifications, just as it does now as
part of its new APD system.
One commenter suggested that the
BLM use off-the-shelf software common
to industry to handle its electronic data
submissions, saying it would reduce
reporting costs to industry since these
programs are already used industrywide. The BLM disagrees because the
BLM already has an existing e-filing
system up and running, and operators
are already familiar with using it. This
system allows operators to see the status
of their submissions and provides them
an electronic response of the AO’s
decision. The AFMSS II update builds
on this existing infrastructure. The BLM
did not change this final rule as a result
of these comments.
Section 3173.11 Site Facility Diagrams
As discussed in the proposed rule, the
requirements in § 3171.11 update and
replace Order 3’s Site Facility Diagram
requirements, which are currently found
in section III.I. Paragraphs (a) through
(c) of § 3171.11 set forth the
requirements for the content and format
of site facility diagrams, while
Appendix A to subpart 3173 provides
some basic examples of what these
diagrams should look like.
Under § 3173.11(a) through (c), a site
facility diagrams must include, in
addition to drawings that show the
relative locations of equipment, specific
information, such as FMP numbers; the
land description; unit PA, or CA
numbers; site equipment; and royaltyfree use information. Site facility
diagrams are one of the BLM’s primary
mechanisms for ensuring that operators
are complying with measurement

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regulations and policy, which is why it
is important that accurate diagrams are
submitted to the BLM in a timely
manner.
As explained in the preamble to the
proposed rule, under Order 3 the BLM
required operators to provide
generalized diagrams showing each
piece of equipment being used at a
facility, including connections between
each piece of equipment, valve
positions on production storage tanks
(sales valves, drain valves, equalizers,
and overflow valves), and their relative
positions to each other. While these
diagrams were useful to the BLM, they
did not provide all of the information
necessary for inspection and
enforcement activities. The more
detailed information required by this
final rule will provide the BLM with a
more useful tool to achieve improved
production accountability.
For example, the requirement in
paragraph (c)(9) of this final rule
(paragraph (c)(10) in the proposed rule)
will allow the BLM, for the first time, to
verify royalty-free-use volumes that
operators report on their OGORs. This
paragraph requires operators to specify
on their site facility diagrams which
equipment on the lease is using oil or
gas royalty-free and how they determine
the volumes of oil or gas used by that
equipment, if the volume is not
measured. This requirement will
provide greater consistency in how
operators determine the volumes of oil
and gas used royalty-free, and will
enable the BLM to more easily verify
those volumes, which enhances
production accountability. This
particular change also responds to the
GAO recommendations (Report 10–313)
that the BLM establish uniform systems
for collecting and tracking information
about royalty-free use in order to ensure
that such use can be properly verified.
Affirmatively requiring this information
to be reported on a site facility diagram
will ultimately save the BLM and
operator time because it will eliminate
the need for the BLM to obtain the
information in connection with a
production accountability review.
Paragraph (d) sets forth the timeframe
within which facilities that are required
to obtain an FMP under § 3173.12 must
submit a site facility diagram that
complies with this rule. It covers both
existing and new facilities. Paragraph
(d)(1) in this final rule (paragraph (c)(1)
in the proposed rule) requires operators,
whose facilities become operational on
or after the effective date of this rule to
submit their diagrams within 30 days
after the BLM assigns their FMP. For
operators of existing facilities that were
in operation on or before the effective

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date of this rule, paragraph (d)(2)
explains that such facilities are not
initially required to submit an updated
site facility diagram if they already have
one on file with the BLM that meets the
minimum requirements of Order 3.
These operators are only required to
submit an updated site facility diagram
consistent with the requirements of this
final rule if and when the operators
modify their facilities, construct or
modify a non-Federal facility located on
their Federal lease or federally approved
unit or communitized area, or if there is
a change in operator.
Paragraph (e) sets forth the timeframe
within which facilities that do not
require FMP numbers under § 3173.12
(e.g., facilities that dispose of produced
water) must submit a site facility
diagram that complies with this rule. It
covers both existing and new facilities.
Paragraph (e)(1) requires operators of
facilities that become operational after
this rule’s effective date to submit their
diagrams within 30 days after the
facilities become operational. For
operators of facilities in operation on or
before the effective date of this rule that
do not require an FMP, paragraph (e)(2)
in this final rule explains that such
facilities are not initially required to
submit an updated site facility diagram
if they already have one on file with the
BLM that meet the minimum
requirements of Order 3. These
operators are only required to submit an
updated site facility diagram consistent
with the requirements of this final rule
if and when the operators modify their
facilities, construct or modify a nonFederal facility located on their Federal
lease or federally approved unit or
communitized area, or if there is a
change in operator.
Paragraph (f) explains that operators
of facilities required to have a site
facility diagram have an ongoing
obligation to update those diagrams
within 30 days after the operator
modifies its facilities, constructs or
modifies a non-Federal facility located
on the Federal lease or federally
approved unit or communitized area, or
if there is a change in operator.
The BLM received many comments
on this section of the proposed rule.
One commenter suggested that the BLM
develop a database that allows operators
to submit the information needed for
site facility diagrams using a standard
form. The commenter said any changes
to a site facility diagram, along with
other information, could be
automatically and periodically
submitted by operators, thus making the
process of submitting and updating
diagram information to the BLM
effortless. The BLM recognizes the

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potential efficiencies provided by the
commenter, but did not make any
changes at this time because the BLM’s
WIS—which follows the Sundry Notice
format—is currently the only method for
electronic submission. At this time, that
system does not allow for submission
along the lines suggested by the
commenter. As result, the BLM will
accept electronic records that contain
the requested information on additional
pages as long as they are submitted with
the actual diagram on Form 3160–5
(Sundry Notices) and they follow the
prescribed numbering format. The BLM
did not change the final rule based on
this comment.
Many commenters expressed concern
that application of the proposed rule’s
site facility diagram requirements to
existing facilities is unnecessary, and
that the deadlines in the proposed rule
for submitting the diagrams would be
onerous. These commenters also said
the demands in this section are so
burdensome that they would cause
operators to reconsider future
development plans, after having
invested money in complying with
previous regulations.
Although the BLM believes the new
site facility diagrams for existing
facilities, including those that handle
waste water, will allow the BLM to
improve production accountability, the
BLM also believes that commenters’
concerns with the deadlines for
submitting the new diagrams have
merit. In response to these comments,
and in an effort to reduce the number of
diagrams that operators must initially
submit to the BLM, we have revised
paragraph (d)(2) (formerly paragraph (d)
in the proposed rule) and added a new
paragraph (e)(2) to the final rule which
specifies that operators of existing
facilities are not initially required to
submit updated site diagrams, so long as
they have a diagram on file that
complies with the requirements of
Order 3. As noted, these paragraphs
require updates to existing diagrams
only when facilities undergo changes.
The BLM believes that this change
addresses the identified concern, while
ensuring that as these existing facilities
undergo changes the agency will
eventually receive site facility diagrams
that meet the requirements of § 3173.11.
Although the existing site-facility
diagrams are not as detailed, the BLM
will continue to work off the diagrams
that it has on file to perform its
production accountability-related
inspections on existing facilities, until
such time as those diagrams are
updated.
Other commenters questioned why it
was necessary to provide a diagram for

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salt-water disposal facilities because,
they said, these facilities are unrelated
to actual oil and gas production
operations. The BLM does not agree
with this commenter. These diagrams
are not a new requirement. Operators
are already required to have site facility
diagrams on file with the BLM for their
water-disposal facilities; Order 3.III.I.1.
requires diagrams for ‘‘all facilities.’’
The BLM is responsible for accounting
for all production, including water, not
just oil and gas. No changes were made
to the final rule as a result of these
comments.
A few comments sought clarification
on how to legibly depict multiple wells
and headers, encompassing an area
several miles in size, on a single sheet
of 81⁄2 x 11 paper. The BLM did not
change the final rule based on these
comments because paragraph (b) in the
proposed and paragraph (c)(1) in the
final rule (paragraph (c)(2) in the
proposed) already state that, while
diagrams need to reflect equipment
locations, they need not be to scale, and
more than one page can be used, if
necessary. The Appendix to subpart
3173 provides examples of multi-well
submissions.
One commenter said the valvepositioning and labeling requirements
in paragraph (c) and the examples in the
Appendix would result in operators
putting redundant information on the
diagrams when multiple tanks, with
similar valves that are operated
similarly, are involved. The BLM did
not make a change in response to this
comment. The BLM cannot create a
single template that addresses how all
site facility diagrams, for a myriad of
field configurations, should be drawn.
The Appendix examples are meant to be
a starting point for operators. It is up to
the operator to determine how best to
identify valve positioning on paper, as
long as the valves and their positions
are identified, legible, and
comprehensible as required in
§ 3173.11.
The BLM received several comments
on the requirement in paragraph (c)(9)
of the final rule (paragraph (c)(10) of the
proposed rule) that operators identify on
their diagrams any equipment that uses
production royalty-free, and either the
calculated or measured volumes that are
used. Under the final rule, operators are
permitted to use any method they want
to determine their royalty-free use
volume, as long as they show on the
diagram how they determined it.
Several commenters pointed out that
royalty-free fuel use fluctuates monthly,
and one commenter even provided its
method for determining ‘‘on lease use
fuel gas.’’ The commenter recommended

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that the BLM consider letting operators
provide an average lease use fuel gas
estimate and questioned the need for
operators to report this information on
their diagrams since on-lease fuel gas is
already reported to the BLM. The BLM
did not change the final rule in response
to this comment. The commenter has
confused BLM and ONRR requirements.
Operators are required to report the
volumes of fuel used royalty-free to
power production equipment on a lease
to ONRR, not the BLM. In order to
enhance accountability, BLM field
inspectors need to be able to
independently verify royalty-free-use
volumes reported to the ONRR, using
the information in the diagrams
pertaining to the equipment that uses
the royalty-free oil and gas. Currently,
the BLM has no method for determining
whether the royalty-free use rate that
operators report on their OGORs is
accurate. This new requirement
enhances production accountability and
responds to key recommendations made
by the GAO (Report 10–313), as
explained above.
A few commenters questioned the
BLM’s rationale for creating the new
site-facility-diagram requirement, while
eliminating the Order 3 requirement for
site security plans, which some
operators had established. The BLM
agrees that these two requirements are
related. The site-facility diagram was
part of the larger site-security plan
required in Order 3. As discussed earlier
in this preamble, the Order 3 sitesecurity plan’s self-inspection
requirements are not in the final rule.
However, elements of the old site
security plan requirements have been
incorporated into this final rule at
§§ 3170.4 (Prohibitions against by-pass
and tampering), 3173.8 (Report of theft
or mishandling of production), 3173.9
(Required recordkeeping for inventory
and seal records), and 3173.11 (Site
facility diagrams); and into the final rule
that is replacing Order 4 at 43 CFR
3174.12 (Measurement tickets).
Many commenters questioned the
need for operators to provide
information and documentation on their
site facility diagrams, as required under
proposed § 3173.11, for what they
consider to be extraneous equipment
and components. Commenters offered to
work with the BLM to create a
pragmatic approach for allowing the
BLM to verify royalty-free volumes and
for operators to submit their diagrams
within a sensible time. However, as
proposed, many commenters saw this
section as unnecessary and
unreasonable overreach by the BLM,
and a drain on resources for both
operators and the agency, especially

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given that operators would need to track
information on multiple components on
numerous pieces of equipment across
several locations. For example, one
commenter did not understand how
putting equipment serial numbers, rated
fuel use, and manufacturer information
on a site facility diagram would help the
BLM verify whether a reasonable
determination was made on royalty-free
use volumes reported to ONRR.
Depending on their configuration,
production facilities can have an
extensive number of major components,
and requiring operators to track down
this information and report it on their
diagrams would cause a hardship on
many operators, commenters said.
Another commenter disagreed with
the requirement in proposed paragraph
(c)(11) that an operator or its
representative include a signed
certification statement on the diagram.
This requirement is redundant and
unnecessary, the commenter said,
because existing statutes—18 U.S.C.
1001 and 43 U.S.C. 1212—already make
it a crime for any person to knowingly
and willfully make a false statement to
the BLM.
The BLM agrees with these comments
and in response has made changes to
the final rule that reduce the
information that must be submitted and
expand the timeframe within which the
submission must occur, including
deleting paragraph (c)(11). The final rule
will not require operators to include a
signed certification statement as part of
their site facility diagrams, because, as
noted by a commenter, operators are
responsible by law for ensuring the
accuracy of the information in their
diagrams. In response to comments
questioning the requirement in
paragraph (c)(10)(i) of the proposed rule,
which directed operators to provide
equipment serial numbers, rated fuel
use, and manufacturer information on
their site-facility diagrams, the BLM
removed this requirement in paragraph
(c)(10)(i) of the proposed rule from the
final rule because the information,
although useful in verifying whether
equipment had been replaced, would
not help the BLM verify that the royaltyfree-use volumes reported to ONRR
were accurate.
One commenter said that the
requirement in paragraph (a), that
operators submit a site facility diagram
for each FMP, is cumbersome,
particularly in cases where the FMP for
oil facilities and gas facilities are on the
same site. The commenter
recommended that the BLM require a
single FMP number for an entire facility
at a single site in order make it simpler
for operators, while providing the

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necessary information to the BLM. The
BLM disagrees with this comment
because the BLM’s inspection
verification process is based, in large
part, on comparing production
information that is reported to ONRR
against information contained in a site
facility diagram, and operators report
their oil and gas production separately
to ONRR. Having information on both
types of facilities on one diagram could
complicate and undermine the BLM’s
verification process. No change has been
made to the rule based on this comment.
Many commenters were also very
concerned with the cost to operators to
comply with the proposed diagram
requirement, particularly the costs of resubmitting all site facility diagrams
within the proposed rule’s 30-day
submission deadline. However, as
discussed above and in greater detail in
the Economic and Threshold Analysis,
the final rule greatly scales back the
range of circumstances in which
operators of existing operations must
submit new site-facility diagrams. This
reduces the number of diagrams that
must be prepared and the amount of
information that operators need to
provide on those diagrams, which will
significantly reduce compliance costs.
The BLM estimated in the proposed rule
that it would take operators 8 hours to
prepare and submit a revised diagram.
The BLM now believes that with the
reduced workload, operators can
perform this task in 6 hours. The BLM
originally estimated in the proposed
rule that operators would submit
revised diagrams for 125,000 existing
facilities over a 27-month phase-in
period. After taking a more detailed look
at our computer data, the BLM has
revised downward its estimate of the
number of existing facilities to 83,116.
The BLM now estimates under this final
rule’s revised requirements that only 5
percent of existing facilities, or about
4,165 facilities, do not have accurate
and up-to-date site facility diagrams on
file with the BLM and will have to
submit revised diagrams to the BLM
over the 3-year phase-in period. The
BLM now estimates that the total onetime cost to industry to submit revised
site facility diagrams will be $1.6
million, spread over 3 years, down from
the BLM’s previous estimate in the
proposed rule of $63.6 million. On an
ongoing basis, the BLM estimates
operators will submit about 5,000 new
diagrams per year for a total annual cost
to the regulated community of $1.9
million.
Other commenters said they were
physically limited—by the sizes of their
staff and facilities—from submitting site
facility diagrams for multiple existing

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Federal Register / Vol. 81, No. 222 / Thursday, November 17, 2016 / Rules and Regulations
and new facilities within 30 days of
receiving their new FMP numbers.
Commenters said carrying out such a
labor-intensive effort within 30 days of
receiving an FMP number was
impractical, unreasonable, and a
burden. Some comments suggested that
a 60- to 90-day timeframe was more
realistic. One commenter suggested 180
days would be more reasonable, with a
couple of others suggesting that
operators have up to 1 year to complete
the diagrams. Another commenter
proposed that the BLM set a 30-day
deadline for new facilities to submit
their diagrams that would start from the
date of first production, while another
suggested a phase-in process, and still
another comment proposed diagrams for
new facilities only.
The BLM agrees that operators need
more time to submit diagrams for new
and existing facilities, and made
corresponding changes to the final rule.
The commenter misstated the
requirement of the proposed rule, which
would have required operators to
submit their diagrams much earlier—
within 30 days of completing
construction of their facilities. Under
the final rule, operators will need to
submit diagrams for new facilities (those
that become operational on or after the
effective date of this final rule) within
30 days after the BLM assigns an FMP
to those facilities. The BLM believes
these changes ensures that it will not
receive a site facility diagram for a new
facility prior to having assigned that
facility an FMP number, which means
operators will not have to go back and
subsequently revise their diagrams to
reflect the new FMP numbers. As
discussed earlier, under the final rule,
operators of existing facilities that
already have site facility diagrams on
file with the BLM that meet the
requirements of Order 3 do not have to
revise those diagrams unless they
modify their facilities or there is a
change in operator.
Finally, one commenter was
concerned about having to submit and
resubmit multiple site facility diagrams
for a facility with multiple FMPs, if the
FMPs were not approved within 30 days
of each other. The commenter said
compliance would be impossible under
these circumstances. The BLM believes
that this commenter was trying to
describe a well pad with multiple wells
that are coming in to production
consecutively. In this case, the FMP
numbers will not change, but a new sitefacility diagram will be required within
30 days from the onset of production
from each well to reflect the new facility
coming online. The BLM did not change
the final rule in response to this

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comment. With respect to the
commenter’s concern about facilities
having multiple FMPs, for the most part,
facilities will have no more than two
FMPs—one for oil and one for gas. Even
though the applications for each FMP
number will be submitted under a
separate Sundry Notices, there is no
reason an operator could not submit
them at the same time, nor for the BLM
to assign the FMP numbers at different
times, as it is unlikely that the
measurement system for oil would come
online later than the measurement
system for gas.
Section 3173.12 Applying for a
Facility Measurement Point
Section 3173.12 of the final rule
establishes a formal nationwide process
for designating and approving the point
at which oil or gas must be measured for
the purpose of determining royalty.
Prior to this final rule, the BLM did not
have a formal, written process for
designating measurement points on the
leases it manages. While some Field
Offices had their own internal policies
for establishing these points, this lack of
uniform guidance across Field Offices
resulted in instances of confusion about
the location of royalty measurement
points, which interfered with the BLM’s
production verification process. This
section now requires operators to obtain
BLM approval of FMPs for all
measurement points used to determine
royalties.
The BLM will approve an FMP that
meets the requirements of this final rule
(the most important elements of which
are the identification of the wells
associated with the FMP and the
measurement method). The BLM will
assign each FMP a unique identifying
number, which the operator,
transporter, or purchaser will use when
reporting production results to ONRR.
Each FMP number will be 11 digits
long. The first two digits (ranging from
52 to 99) will identify the product—oil
or gas—as well as other information,
such as whether the FMP is on-lease or
off-lease, whether it is part of a
commingling arrangement, and the
measurement method used at the FMP—
tank gauge, LACT, Coriolis, etc. The
next 5 digits will represent the
American Petroleum Institute (API) state
and county code, while the last 4 digits
will be a combination of letters or
numbers that will make each FMP
number unique.
The BSEE already assigns similar
FMP numbers for the offshore oil and
gas leases that it manages, which the
operator, transporter, or purchaser must
then use when reporting production
results to ONRR. The changes in this

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final rule will make BLM practices
consistent with existing BSEE and
ONRR practices for production
reporting.
Paragraph (a)(1) of this final section
provides that, unless otherwise
approved, the FMPs for all Federal or
Indian leases, unit PAs, or CAs must be
located within the boundaries of the
lease, unit PA, or communitized area
from which the production originated,
and must measure only production from
that lease, unit PA, or communitized
area, unless otherwise approved.
Paragraph (a)(2) provides that off-lease
measurement or commingling and
allocation of production requires prior
approval under 43 CFR 3162.7–2 and
3162.7–3, and §§ 3173.15, 3173.16,
3173.24, and 3173.25 of this final rule.
Paragraph (b) provides that the BLM
will not approve a meter at the tailgate
of a gas processing plant located off the
lease, unit, or communitized area as an
FMP. This paragraph codifies existing
BLM practice with respect to tailgate
meters.
Paragraph (c) provides that the
operator must submit separate
applications for approval of separate
FMP numbers for a measurement point
that measures oil produced from a
particular lease, unit PA, CA, or
pursuant to an approved CAA, and a
measurement point that measures gas
produced from the same lease, unit PA,
or CA, or pursuant to an approved CAA.
The requirements for a separate FMP
apply even if the measurement
equipment or facilities are at the same
location. As discussed earlier, the first
two numbers in the FMP number
specify whether the FMP measures oil
or gas. The BLM will not approve the
same FMP number for a facility that
measures oil and a facility that measures
gas.
Paragraph (d) requires the operator to
apply for approval of an FMP for a new
permanent measurement facility (i.e.,
one coming into service after the
effective date of the final rule) before
any production leaves the facility. In the
final rule, we clarify that this
requirement does not apply to
temporary measurement equipment
used during well-testing operations.
Until the BLM assigns the FMP number,
the operator must use the lease, unit PA,
or CA number for reporting production
to ONRR.
Paragraph (e) provides that for
existing permanent production
measurement facilities, an operator has
1 year, 2 years or 3 years from the
effective date of the final rule within
which to apply for BLM approval of its
FMP, depending on the production level
of the lease, unit PA, or CA that the

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measurement facility serves. The
prescribed application deadline applies
to both oil and gas measurement
facilities measuring production from
that lease, unit PA, and CA, whether or
not it is part of a CAA. The final rule
requires FMP applications for existing
measurement facilities that serve
operations with the highest production
volumes to be submitted first:
1. Under paragraph (e)(1), operators of
stand-alone leases, unit PAs, or CAs,
which produce 10,000 Mcf or more of
gas per month, or 100 bbl or more of oil
per month must, apply for FMP
approval within 1 year after the effective
date of the final rule.
2. Paragraph (e)(2) requires operators
of stand-alone leases, unit PAs, or CAs,
which produce 1,500 Mcf or more but
less than 10,000 Mcf of gas per month,
or 10 bbl or more but less than 100 bbl
of oil per month, to apply for FMP
approval within 2 years after the
effective date of the final rule.
3. Paragraph (e)(3) requires operators
of stand-alone leases, unit PAs, or CAs
that produce less than 1,500 Mcf of gas
per month, or less than 10 bbl of oil per
month, to apply for FMP approval
within 3 years after the effective date of
the final rule.
To determine which category a
facility is in, the final rule requires the
facility to calculate average production
over the 12 months preceding the
effective date of the final rule, or over
the period the lease, unit, CA, or CAA
has been in production, whichever is
shorter.
Paragraph (e)(4) explains that if a
stand-alone lease, unit PA, or CA has
not produced for a year or more before
the effective date of this final rule, the
operator is not required to apply for an
FMP immediately, but rather need only
apply prior to resuming production.
Under paragraph (e)(6), if an operator
applies for FMP approval by the date,
the operator may continue to use the
lease, unit PA, or CA number for
reporting production to ONRR while the
application is pending, until the
effective date of the BLM-assigned FMP
number, at which point the operator
must use the FMP number for such
reporting. If, however, an operator fails
to apply for an FMP approval by the
date required by the final rule,
paragraph (e)(7) explains that the
operator will be subject to an incident
of noncompliance and may also be
subject to an assessment of civil penalty
under 43 CFR subpart 3163, together
with any other remedy available under
applicable law or regulation.
Paragraph (f) identifies the
information that a request for FMP
approval must include. Under

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paragraph (f)(1), FMP requests must be
submitted on a Sundry Notice and
include information pertaining to the
equipment that will be used to measure
the oil and gas. Paragraph (f)(2) requires
the applicable Measurement Type Code
specified in WIS. Paragraph (f)(3)
requires information about the
equipment used for oil and gas
measurement: (i) For gas measurement,
specify unique station number, primary
element (meter tube) size or serial
number, and type of secondary device
(mechanical or electronic); (ii) For oil
measurement by tank gauge, specify oil
tank number or tank serial number and
size in barrels or gallons for all tanks
associated with measurement at an
FMP; and (iii) For oil measurement by
LACT or CMS, specify whether the
equipment is LACT or CMS and the
associated oil tank number or tank serial
number and size in barrels or gallons
(there may be more than one tank
associated with an FMP). Paragraph
(f)(4) requires operators to include a list
of the API well numbers that will flow
to the requested FMP if that FMP will
serve more than one well, and provide
a land description for the FMP location.
Under paragraph (f)(5), the FMP
location by land description must also
be included in the FMP application.
As explained below, the BLM in the
final rule has also reduced the quantity
of information that operators must
submit on their FMP number
applications. For consistency with
§ 3173.10(c)(10)(i), the BLM removed
requirements that operators provide
component names, manufacturer,
model, serial number, range limits for
electronic flow computers, transducer
(static, differential, and temperature),
chart recorders, LACT totalizer, and
Coriolis meter from § 3173.12(f)(3)(i),
(ii), (iii), (iv) and combined
subparagraphs (iii) and (iv) into (iii).
Paragraph (g) allows concurrent
requests for FMP approval and for
approval of off-lease measurement or
commingling and allocation.
Section 3173.12 is a key element of
the final rule as it implements one of the
GAO’s central recommendations: That
the Interior Department consistently
track where and how oil and gas are
measured, including information about
meter location, identification number,
and owner. By requiring operators to
obtain approval from the BLM for the
location of the FMP at which oil or gas
is measured, the final rule provides that
consistent tracking. The BLM will also
now tie the FMP numbers to other
appropriate approvals and
documentation that are part of its
production verification and
accountability efforts, such as site

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facility diagrams, off-lease measurement
approvals, commingling approvals, and
royalty-free use (if volumes used
royalty-free are measured).
In the final rule, operators,
purchasers, and transporters must
include on all records the FMP number
or until the BLM approves the FMP
number, the lease, unit PA, or CA
number, along with a unique equipment
identifier and the name of the company
that created the record.12 Records
include, but are not limited to,
calibration reports, gas analysis, sales
statements, manifests, seal records, and
related approvals. Once assigned, the
operator must use the FMP number for
production reporting to ONRR after the
effective date of the BLM’s FMP
approval.
The BLM estimates there are
approximately 83,116 existing oil and
gas facilities associated with Federal
and Indian leases. Many facilities have
one FMP for oil and one FMP for gas for
a total of approximately 166,232 FMPs
for existing facilities.
In connection with its creation of the
new FMP system in § 3173.12, the BLM
has also revised its existing well and
facility identification provisions at 43
CFR 3162.6(b) and (c) to include a
signage requirement for wells on
Federal or Indian lands and facilities at
which Federal or Indian oil or gas is
measured or processed. Additional
revisions to § 3162.6 include: (1) Making
the surveyed-location language in
paragraphs (b) and (c) consistent,
including a new reference to longitude
and latitude; and (2) Removing a
sentence in paragraph (b) that provided
a grace period for well signs that were
in existence on the effective date of the
rulemaking in which that section was
first promulgated.
The BLM received a comment
requesting that the definition of an FMP
in § 3173.1 include more details on how
to obtain an FMP, the deadlines for
operators to obtain an FMP, and the
economic impacts that the FMP
requirement would have on industry.
The BLM disagrees with this
commenter. Section 3173.12 of this final
rule provides all of the information
requested by the commenter related to
requests to apply for an FMP. It
addresses the deadlines—which are
based on average production volumes—
for operators to submit FMP
applications for facilities that are in
service on or before the effective date of
this rule, or that will come into service
after the effective date. It also specifies
12 Once an FMP number is approved, it must be
used on all subsequent reporting as outlined in this
rule.

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the three production thresholds on
which the FMP application deadlines
are based. As for the economic impacts,
the BLM carefully evaluated those as
part of the rulemaking process in both
a draft and a final regulatory impact
analysis for this rulemaking, both of
which are made available to the public.
The Procedural Matters section of this
preamble contains a short discussion of
this rule’s potential economic impact on
industry. We did not change the final
rule as a result of this comment.
A number of commenters were
concerned that they could not meet the
proposed rule’s deadlines in
§ 3173.12(e) for applying for and then
receiving an FMP number before
producing oil and gas. They said the
resources needed to prepare FMP
applications would be exorbitant,
especially for large producers that have
many thousands of wells, many of
which will likely have associated
commingling or off-lease measurement
approvals that the BLM will need to
review (see discussion of § 3173.16
below).
Many commenters also complained
about the proposed tiered volume
thresholds that figured into the
timelines for filing FMP applications.
Many operators said that most of their
wells’ production levels would require
them to submit their FMP applications
within 9 months of the final rule’s
effective date. Commenters said such
timeframes would be unreasonably
short for operators with large well
inventories, considering that they would
also be required to submit new site
facility diagrams and possibly update
existing commingling and off-lease
measurement approvals.
Under the proposed rule, operators
would have had to submit their FMP
application within:
• Twenty seven months from the
effective date of the final rule for leases,
unit PAs, and CAs that produced less
than 3,000 thousand cubic feet (Mcf) of
gas or 20 bbl of oil per month;
• Eighteen months from the effective
date of the final rule for leases, unit
PAs, and CAs that produced between
3,000 and 6,000 Mcf of gas or 20 and 40
bbl of oil per month; and
• Nine months from the effective date
of the final rule for leases, unit PAs, and
CAs that produced over 6,000 Mcf of gas
or 40 bbl of oil per month.
The BLM agrees with commenters
that the proposed deadlines were too
tight. In response, the BLM changed the
final rule to give operators additional
time to submit FMP applications for
facilities that are in service before the
effective date of the final rule. The
amount of additional time is based on

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the facility’s average reported monthly
oil and gas production volumes over the
previous 12 months. When establishing
the new thresholds, the BLM analyzed
lease production data in AFMSS to
determine the impacts on all currently
producing leases. In setting the FMP
application deadlines, the BLM
attempted to spread the impact evenly
across the three timeframes and across
all BLM-administered leases.
As discussed previously, the final rule
also allows operators to continue to
produce oil and gas while their FMP
applications are pending BLM approval,
provided that those applications are
submitted within the deadlines
specified in § 3173.12(e). While waiting
for their FMP approvals, operators may
continue to use the lease, unit PA, or CA
numbers that they have been using for
reporting their production to ONRR.
These changes should make it easier for
operators to meet the final rule’s FMP
application deadlines and give them
more time to plan and budget for this
new requirement, while continuing
their production operations. As
explained in connection with
§ 3173.11(d) and (e), this final rule
removes the proposed rule’s
requirement that all existing facilities
submit updated site facility diagrams
within 30 days of approval of an FMP,
further reducing requirements on
existing facilities.
In addition, as discussed previously,
the BLM changed the final rule to
eliminate some of the information
required in the FMP applications (e.g.,
equipment serial numbers and
manufacturer information).
Furthermore, the final rule exempts
leases, unit PAs, and CAs, which have
not produced any oil or gas within the
past 12 months. Only when operators
resume production from these idle
leases, unit PAs, and CAs must they
then apply for FMPs.
A number of commenters also
expressed concern that the BLM would
not have been able to handle the
number of FMP applications that the
agency would have received under the
proposed rule’s timeline and
requirements. However, the BLM now
anticipates having a much smaller
workload, spread more evenly over
time. For one thing, a review of AFMSS
data suggests that there are only 83,116
active facilities affected by this rule—
about 25 percent fewer than the BLM
had estimated in analyzing the proposed
rule. In addition, the final rule requires
operators to provide less information on
their FMP applications and site facility
diagrams than the proposed rule would
have required. We now estimate that it
will take BLM staff 2 hours to process

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each FMP application, instead of the 4
hours we anticipated under the
proposed rule’s information
requirements. Additionally, because of
the provisions allowing continued
production and reporting while an FMP
application is pending, operators should
no longer be concerned about potential
FMP application backlogs.
Several commenters said they were
concerned about delays in the FMP
approval process holding them up from
putting new wells online and removing
production from the lease. The
proposed rule at § 3173.12(d) required
operators to ‘‘obtain’’ FMP approval for
measurement facilities that came into
service after the rule’s effective date
before they could begin removing
production from a lease, unit PA, CA, or
CAA. The BLM agrees that proposed
paragraph (d) needed to be changed to
avoid production delays on new
facilities. To address these concerns, the
BLM has made several changes to
paragraph (d) in the final rule. First, the
BLM added language to the section to
clarify that operators must apply for
FMP approvals for permanent
measurement facilities only—not
temporary test facilities—as defined in
§ 3173.1 of this final rule. In addition,
the BLM added language to paragraph
(d) that requires operators of new
facilities to simply ‘‘apply for’’ FMP
approval before any production leaves
the permanent measurement facility.
This change allows operators to install
a new measurement facility, remove
production from that facility without
delay, and use the lease, unit PA, or CA
number for production reporting to
ONRR until the BLM assigned an FMP
number, as long as they apply for their
FMP approval before any production
leaves that permanent facility. While the
applications are pending, operators may
continue using their lease, unit PA, or
CA number for reporting production to
ONRR.
One commenter thought the BLM
should allow operators to file one
application on the facility as a whole,
and not be required to submit one
application for oil and another for gas.
The BLM did not revise the rule as a
result of this comment. One of the
purposes of an FMP is to be able to
consistently verify where and how oil or
gas is measured. The BLM does this by
comparing information that operators
report to the BLM against information
operators report to ONRR, which does,
in fact, collect the oil and gas
production information separately.
Using one FMP number to track oil and
gas measurement operations together
would compromise the BLM’s ability to
consistently verify production

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measurements for royalty purposes.
Such a system is also incompatible with
ONRR’s existing reporting systems, and
it would not meet the goals of
establishing an FMP.
Finally, one commenter said that BLM
staff should be given a deadline for
approving FMPs, since it is not fair to
hold operators to multiple deadlines,
making them subject to INCs for missing
those deadlines, while not holding the
BLM to the same standard. As discussed
above, the BLM’s new FMP approval
process will not interfere with
operators’ production. Once operators
file a timely request for an FMP
approval on existing facilities, they may
continue to operate and use their lease,
unit PA, or CA number for reporting
production to ONRR until the BLM
assigns an FMP number.
Once an FMP number is assigned to
a facility, § 3173.13(a) of this final rule
gives the operator several months before
it must use the FMP number when
reporting production to ONRR.
Specifically, for existing facilities, the
operator will have to begin using the
FMP number for reporting production to
ONRR on its OGOR for the fourth
production month after the FMP
number is assigned. For facilities that
come into service after the effective date
of this final rule, operators are required
to apply for FMP approval before any
production leaves the permanent
measurement facility and then use the
FMP number for reporting production to
ONRR on its OGOR for the first
production month after the FMP
number is assigned. As result of these
changes, we do not believe deadlines for
BLM review are necessary or
appropriate.
Section 3173.13 Requirements for
Approved Facility Measurement Points
Section 3173.13 of the final rule sets
forth the requirements that are
applicable to all approved FMPs.
Paragraph (a) requires the operator of an
existing facility to use assigned FMP
numbers in reporting production to
ONRR on its OGORs for the fourth
production month after an FMP is
assigned. For new facilities in service
after the effective date of this rule,
paragraph (a) requires the operator to
begin using its assigned FMP numbers
on its OGORs for the first production
month after the FMP number is
assigned.
Paragraph (b) requires an operator to
file, within 30 days after any changes or
modifications to an approved FMP, a
Sundry Notice notifying the BLM of the
change. It also describes the information
that operators must provide to the BLM
in the Sundry Notice, including any

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changes or modifications to the
equipment that is used for measuring oil
or gas at the FMP, or to the API well
numbers associated with the FMP.
The BLM received several comments
on this section of the proposed rule.
Unlike the final rule, the proposed rule
required operators to use their FMP
numbers for both recordkeeping
purposes and production reporting to
ONRR beginning on the first day of the
month after the FMP number was
assigned. A few commenters said they
needed more time to start using the
number for production reporting and
recordkeeping because an FMP could be
issued on the last day of the month,
thereby obligating the operator to use
the FMP on the next day. The
commenters said that this would not
give them enough time to take the steps
they need to comply with FMP
requirements, such as stenciling the
FMP number onto equipment, labeling
all records with the FMP number, and
making updates to their existing
database systems that track oil and gas
production operations.
The BLM agrees that requiring
operators to begin using their FMP
numbers for recordkeeping and
production reporting on the first day of
the month after the FMP number is
assigned may not be possible for some
operators. As discussed earlier, the BLM
changed § 3170.7(g) from requiring
operators to use FMP numbers on all
records, to allowing operators to use
either FMP numbers or lease, unit PA,
or CA numbers, along with unique
equipment identifiers, on their records.
In addition, the BLM changed final
§ 3173.13(a) to extend the effective date
that operators of existing facilities are
required to begin using their FMP
numbers in production reporting to
ONRR. Under the final § 3173.13(a),
operators must start using FMP numbers
for reporting production to ONRR on
their OGORs for the fourth production
month after the FMP number is
assigned. For example, if the BLM
assigns an existing facility an FMP
number on January 17, the operator
must begin using that FMP number on
its May production OGORs. Because
ONRR requires operators to submit their
electronic reports ‘‘on the 15th day of
the second month following the
production month being reported,’’ the
May production report must be
submitted by July 15, effectively giving
the operator 5-1⁄2 months of leeway
before having to submit a report using
the FMP number assigned on January
17. The BLM chose this new timeframe
because it believes that nearly six
months is ample time for operators of
existing facilities to start using their

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new FMP numbers for reporting
production to ONRR.
For new facilities, operators will be
required to begin using their FMP
numbers in reporting production to
ONRR on their OGORs for the first
production month after the FMP
number is assigned. For example, if the
BLM assigns the FMP number on April
30, the operator must begin using that
FMP number for its May production. As
noted, however, the May production
report is not due to ONRR until July 15,
effectively giving the operator 2-1⁄2
months leeway before having to submit
the report using the FMP number.
Some commenters asked why
proposed § 3173.13(d) required
operators to submit a Sundry Notice
detailing ‘‘any’’ modifications they
make to an approved FMP and why the
changes were made. Commenters said
the BLM does not need this information.
The BLM agrees that it does not need to
know why a change was made and has
removed this requirement from the final
rule. However, the BLM does need to
know when operators change out
measurement equipment at an approved
FMP, along with specific information
about the replacement equipment, and
when they add or remove wells served
by an FMP, along with the associated
API well numbers. The BLM needs this
information so that it can keep track of
these types of changes, which directly
impact the BLM’s efforts to verify
production. In addition, the BLM has
provided some additional context, by
clarifying that it does not need to be
notified when temporary modifications
(e.g., for maintenance purposes) are
made. With these clarifications, the final
rule in paragraph (b)(1) still requires
operators to file a Sundry Notice within
30 days notifying the BLM of changes in
measuring equipment at an approved
FMP or of the addition or subtraction of
wells served by an approved FMP.
These are essentially changes in the
information that operators submitted on
their FMP applications, as required
under § 3173.12(f)(3) and (4).
The BLM received several comments
on the requirement in proposed
§ 3173.13(a) that operators stamp or
stencil FMP numbers on specific pieces
of equipment within 30 days after an
FMP number assignment. Commenters
said this requirement was too expensive
and would take too much time. Several
commenters recommended that the
BLM, instead, cross-reference the FMP
number to a unique meter station
identifier supplied by the operator, such
as the meter station number, LACT ID
number, or tank number, all of which
are already available and visible to BLM
inspectors. The BLM agrees that the

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requirement to stamp or stencil FMP
numbers on equipment that is used to
measure for royalty is unnecessary and
has removed it from the final rule.
The BLM changed the final rule at
§ 3173.12(f) to require operators, when
they apply for a gas FMP number, to
identify the royalty measurement point
by specifying a unique station number;
primary element (meter tube) size or
serial number; type of secondary device
(mechanical or electronic); and
associated API well numbers where
production from more than one well
will flow to the requested FMP; along
with a land description of the FMP’s
location. On an oil FMP number
application, operators must supply the
tank number or tank serial number and
size in barrels or gallons; specify
whether LACT or CMS, if applicable;
associated API well numbers where
production from more than one well
will flow to the requested FMP; along
with a land description of the FMP’s
location.
One commenter said operators should
be exempt from the requirement that
they file a Sundry Notice when they
temporarily modify an FMP due to
changing out equipment for
maintenance. The commenter said the
replacement equipment, using the same
measurement methodology, would not
impact accuracy. The BLM agrees that
operators do not need to notify the BLM
when they install temporary
replacement equipment while
performing maintenance on the
permanent equipment. As noted, the
final rule clarifies in paragraph (b)(1)
that the BLM does not need to be
notified when temporary modifications
(e.g., for maintenance purposes) are
made.
Finally, one commenter objected to
the requirement in proposed paragraph
(b)(2) that operators file a Sundry Notice
whenever there is a change in the wells
or facilities served by an FMP. This
commenter said an operator may need
to transfer product to different meters
several times a day when the meters
freeze during the winter months. The
commenter said it would be impossible
to maintain a list of the wells going to
the FMPs under these conditions. The
BLM is not aware of situations where
operators direct their gas stream to
different sales meters because of line
freezing. This practice may be allowed
on State and private wells, but, such a
transfer is not allowed on Federal and
Indian wells. We did not change the
final rule as a result of this comment.

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Sections 3173.14 through 3173.21
Commingling and Allocation Approvals
As explained in the Definitions
section of this preamble, commingling,
for production accounting and reporting
purposes, means the ‘‘combining, before
the point of royalty measurement,
production from more than one lease,
unit PA, or CA, or production from one
or more leases, unit PAs, or CAs with
production from State, local
governmental, or private properties that
are outside the boundaries of those
leases, unit Pas, or CAs.’’ Operators
apply for commingling approval for
several reasons, including:
(1) It can simplify accounting to have
the sales point be the same as the point
of royalty measurement;
(2) Lower operating costs can be
achieved by reducing the number of
meters required (such as when well
testing is an appropriate allocation
method); and
(3) Lower operating costs can also be
achieved by eliminating the need for
separate plumbing and surface
equipment (pipelines, separators,
dehydrators, compressors, tanks, etc.).
Commingling can also have some
advantages for the BLM:
(1) More accurate measurement can
sometimes be achieved from a meter
measuring combined flows, which can
be better-conditioned and, more
consistent, and have higher flow rates,
than from a single low-volume meter
measuring erratic flow with a higher
potential for multiple phases of fluid;
(2) The environmental footprint can
be reduced by reducing the need for
duplicate surface equipment; and
(3) Production accounting can be
simplified by reducing the number of
meters to inspect and verify.
However, in many situations the
advantages of commingling are offset by
increased measurement uncertainty,
increased potential for measurement
bias, and a decrease in the BLM’s ability
to verify reported production volumes.
This is especially true if the properties
proposed for commingling are of
different ownership, have different
royalty rates, or have different royalty
distributions.
As explained below, §§ 3173.14
through 3173.21 of the final rule restrict
the instances in which the BLM will
approve commingling and establish the
standards that an operator must meet to
obtain an approval. Existing regulations
at 43 CFR 3162.7–2 and 3162.7–3
require BLM approval before operators
commingle production from a Federal or
Indian lease with production from other
sources; however, prior to this rule,
there were no regulations addressing

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how or under what circumstance
commingling should be approved. The
requirements in this final rule are based
on and codify the policy outlined by the
BLM with respect to commingling
approvals in IM 2013–152 (2013),
‘‘Reviewing Requests for Surface and
Downhole Commingling of Oil and Gas
Produced from Federal and Indian
Leases.’’ The principal difference
between the provisions of this rule and
the BLM’s existing IM is that the final
rule establishes a new process for the
BLM to review existing CAAs when
operators apply for their FMP approvals.
In contrast, the IM focused solely on
new CAAs. Also, in response to public
comment and additional internal
reviews, the final rule expands the
number of exemptions under which an
existing or proposed CAA could be
commingled if the CAA does not meet
the criteria identified in § 3173.14 (a) of
the final rule.
Section 3173.14 Conditions for
Commingling and Allocation Approval
(Surface and Downhole)
Section 3174.14(a)
To ensure the accuracy and
verifiability of the volume and quality
measurements on which royalty is
based, § 3173.14(a) states that the BLM
‘‘may grant a CAA only if the proposed
allocation method used for any such
commingled measurement does not
have the potential to affect the
determination of the total volume or
quality of production on which royalty
owed is determined for all the Federal
or Indian leases, unit PAs, or CAs which
are proposed for commingling. . . .’’
Paragraph (a)(1) goes on to identify the
conditions under which this occurs.
The most common situation when
this occurs is when all the properties
proposed for commingling are 100
percent Federal or leased 100 percent by
the same Indian tribe, have the same
fixed royalty rate, and have the same
revenue distribution. In these situations,
the allocation method is irrelevant
because the total amount of royalty
received by the Federal Government or
tribal mineral interest owner will be the
same regardless of how it is allocated to
the individual leases, unit PAs, or CAs
that are part of the CAA. Consequently,
the BLM can ensure accurate
measurement and proper reporting by
inspecting and verifying only the
commingled point of royalty
measurement (i.e., the commingled
FMP). This would also apply in
situations where, for example, ‘‘leaseline’’ CAs proposed for commingling are
all 50 percent Federal and 50 percent
non-Federal.

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Based on comments received on the
proposed rule and additional internal
reviews, the BLM revised paragraph (a)
and its subparagraphs as outlined
below. In paragraph (a) itself, the BLM
added language which explicitly states
the criteria the BLM uses to approve a
commingling application. Paragraphs
(a)(1)(i) and (a)(1)(ii) were retained, with
modifications for clarity, from the
proposed rule. Those provisions
recognize that if the leases, unit PAs, or
CAs to be commingled are 100 percent
Federal or leased 100 percent by the
same Indian tribe, and at the same fixed
royalty rate, then commingling is
generally acceptable, assuming the other
requirements of this part are met. Indian
allotted leases are not included under
paragraph (a) because there would be
virtually no instances where the
revenue distribution to the allottees
would be identical in different leases,
unit PAs, or CAs.
Several commenters suggested that
commingling among unit PAs or CAs
that have less than 100 percent Federal
ownership should be recognized as
permissible, so long as they have the
same proportion of Federal interest. The
BLM agrees with this comment and
added paragraph (a)(1)(iii) to allow
commingling of Federal unit PAs or CAs
where each unit PA or CA proposed for
commingling has the same proportion of
Federal interest, which is subject to the
same fixed royalty rate and revenue
distribution. Under this provision, the
BLM could approve a commingling
request where an operator proposes to
commingle two Federal CAs of mixed
ownership where both are 50 percent
Federal/50 percent private, so long as
the Federal interests have the same
royalty rates and royalty distributions.
The BLM also added a new paragraph
(a)(1)(iv), which provides a parallel
provision for tribal interests, with the
key again being identical percentage of
tribal participation and royalty rates.
In paragraph (a)(2) of the final rule,
the BLM makes it clear that the operator
or group of operators that are part of a
CAA must provide the BLM with the
allocation methodology for the
properties from which production is to
be commingled, along with an
agreement signed by the operators that
are parties to the CAA if there is more
than one operator. Paragraphs (a)(3) and
(a)(4) remain unchanged from the
proposed rule.
Paragraph 3173.14(a)(3) requires
operators to demonstrate that each of
the leases, unit PAs, or CAs proposed
for inclusion in a CAA is producing in
paying quantities or, in the case of
Federal leases, capable of producing in
paying quantities. One commenter

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asked why the BLM wants to know that
wells involved in commingling are
capable of production in paying
quantities. The purpose of this
requirement is to ensure that CAAs are
not used to extend the terms of a
nonproducing lease, by allocating
production to it. The BLM did not
change the rule as a result of this
comment.
Paragraph (a)(4) requires that the
FMP(s) for the proposed CAA measure
production originating exclusively from
the leases, unit PAs, or communitized
areas in the proposed CAA. The BLM
received no comments on this
provision.
Section 3173.14(b)
Paragraph (b) of final § 3173.14 sets
forth the exceptional circumstances in
which the BLM will allow commingling
even when the circumstances outlined
in paragraph (a) are not met because, for
example, there is a combination of
Federal and non-Federal ownership,
Indian allotted leases are involved, or
the Federal or Indian leases have
different royalty rates. This paragraph
includes the two circumstances given in
the proposed rule: Economically
marginal properties (called low-volume
properties in the proposed rule) and
overriding considerations, such as
environmental impacts. The final rule
also adds three additional
circumstances where the BLM can
approve commingling:
• When the average monthly
production over the preceding 12
months for each Federal or Indian lease,
unit PA, or CA proposed for the CAA is
less than 1,000 Mcf of gas per month, or
100 bbl of oil per month;
• The CAA has been authorized
under tribal law or otherwise approved
by a tribe; or
• The CAA covers the downhole
commingling of production from
multiple formations that are covered by
separate leases, CAs, or unit PAs where
the BLM has deemed the commingling
of these formations to be an acceptable
practice for the purpose of achieving
maximum ultimate economic recovery
and resource conservation.
The BLM received numerous
comments on this paragraph in the
proposed rule, stating that the
exceptions granted in paragraph (b) of
the proposed rule were not adequate for
surface commingling approvals in cases
involving low production volumes. The
commenters said that this would result
in lost oil and gas production, revenue,
and royalties from operators forced to
shut-in thousands of wells covered by
existing CAAs where surface
commingling takes place and where the

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economics did not justify the cost of
installing new metering and
measurement equipment. In many of
these instances, the commenters stated
that production volumes have declined
to the point where the revenue from
continued operation would not be
sufficient to justify installing new
measurement equipment, particularly in
the current low-price environment.
The BLM disagrees with these
comments. The provisions for approving
a CAA for economically marginal
properties (low-volume properties in the
proposed rule) in both the proposed rule
and the final rule were designed
specifically to allow the BLM to
determine if a property would truly be
shut in if the only alternative was for
the operator to achieve non-commingled
measurement of production. The BLM
believes many of the worst case
scenarios flagged by commenters would
fit within the economically marginal
property exception. Unlike downhole
commingling, the costs for surface
commingling are relatively easy to
define. An operator on the edge of
profitability should be able to
demonstrate to the BLM under
paragraph (b)(1) that the properties
proposed for commingling qualify as
economically marginal properties. The
commenters did not submit any data to
substantiate that the existing provisions
under paragraph (b)(1) were inadequate
as they relate to surface commingling.
Although the BLM did not make any
changes to the rule based on these
comments, the BLM changed the
economic threshold in the final rule
based on comments on the definition of
low-volume property in the proposed
rule. As discussed in connection with
§ 3173.1, under the new definition of an
economically marginal property, the
BLM changed the threshold from a 10
percent before-tax rate of return in the
proposed rule to an 18-month after-tax
payout in the final rule. The BLM
believes this change will increase the
number of leases, unit PAs, or CAs that
would qualify as economically marginal
leases and, therefore, might qualify for
a CAA under this paragraph. The BLM
does not have any data to quantify this
increase, however.
Commenters also expressed concern
about the workload and timeframes
involved with obtaining a commingling
approval under paragraph (b). Because
the provisions of paragraph (b)(1) of
both the proposed and final rule are
very similar to the provisions of IM
2013–152, the BLM has experience with
the process of reviewing CAAs for
economically marginal properties.
Based on its experience processing
commingling requests under IM 2013–

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152, the BLM agrees that the process for
requesting and reviewing a CAA can
take time, especially for properties that
do not clearly fit within the economic
thresholds established in the final rule.
As a result, the BLM made two
changes in the final rule. The first
change was to grandfather any existing
surface commingling approval where
the average production rate over the
previous 12 months for each of the
Federal or Indian leases, unit PAs, or
CAs included in the approval is less
than 100 bbl of oil per month or 1,000
Mcf of gas per month (see
§ 3173.16(a)(1) and (2)). Second,
recognizing that such limited
production may also occur in
connection with new CAA approvals,
§ 3173.14(b)(2) now allows the BLM to
approve new CAAs if the average
production rate from the proposed CAA
satisfy the thresholds for grandfathering
of existing CAAs. The new CAA would
also have to comply with § 3173.14(a)(2)
through (4); however, under the final
rule, the BLM will not require any
additional economic analysis from the
operator.
The BLM chose these thresholds
because properties producing below
these thresholds would almost always
qualify as economically marginal
properties under this rule. Therefore,
the BLM can approve commingling
requests that qualify under this
paragraph with significantly less
paperwork burden on both the BLM and
industry, and without the in-depth
economic analysis that would have been
required in the proposed rule. The BLM
chose the oil threshold of 100 bbl per
month by assuming the cost of
achieving non-commingled
measurement of oil would be $50,000
(setting a small oil tank, for example).
The production rate required to achieve
an 18-month payout of this investment,
assuming a $60 per bbl oil price and
including taxes, royalty payments, and
fixed and variable operating costs,
would be about 3.5 bbl per day, or
approximately 100 bbl per month.
The BLM used a similar approach for
determining the gas threshold. The BLM
assumed that an operator would have to
invest $20,000 to achieve noncommingled measurement of gas (the
cost of installing a new meter). The
production rate required to achieve an
18-month payout of this investment,
assuming a $3 per MMBtu gas price, and
including taxes, royalty payments, and
operating costs, would be about 30 Mcf/
day, or roughly 1,000 Mcf per month.
The BLM added § 3173.14(b)(3) to the
final rule, which provides for CAAs that
have been authorized under tribal law
or otherwise approved by a tribe. The

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BLM included this provision in
response to tribal comments indicating
that tribal law or agreements may
independently identify circumstances
where commingling is appropriate. The
BLM added this provision because it
believes that tribes should have a say in
approving CAAs that involve
production from tribal leases.
The BLM received many comments
stating that the exceptions provided in
§ 3173.14(b) of the proposed rule did
not address downhole commingling
agreements in the New Mexico portions
of the San Juan and Permian Basins and
elsewhere that would not meet the
requirements § 3173.14(a). The
commenters said that this omission
would result in lost oil and gas
production, revenue, and royalties from
operators forced to shut-in thousands of
wells at existing CAAs where downhole
commingling takes place and where the
economics do not justify the cost of
drilling additional wells or segregating
downhole production. Many of the
wells, according to the commenters,
were drilled specifically to commingle
downhole production from multiple
leases, CAs, and unit PAs, including
combinations of Federal, Indian, fee,
and State ownership. The commenters
said downhole commingling allows
operators to reduce costs and
environmental impacts by reducing the
number of wellbores because multiple
zones can be produced out of a single
wellbore. In addition, commenters
stated that some individual zones do not
have enough production to justify the
drilling and completion costs for
separate wells. Other commenters
stressed that downhole commingling
increases the maximum ultimate
economic recovery because reservoir
energy from lower formations allows oil
and gas from highly-depleted upper
formations to be produced (i.e.,
production from the lower formation is
necessary to produce the upper
formation). In many of these instances,
production volumes have declined to
the point where the revenue from
continued operation would not be
sufficient to justify drilling new wells or
re-completing existing wells to avoid
downhole commingling, particularly in
the current price environment.
The BLM agrees with commenters
that the exceptions listed in the
proposed rule, need to be expanded to
account for downhole CAAs, to ensure
that improvements in measurement
accuracy and the BLM’s ability to verify
production made by this rule do not
unnecessarily result in operators
shutting in large numbers of existing
wells, particularly during times of low
commodity prices. The BLM believes

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that it is in the public interest to receive
royalty on a volume of oil or gas that
may have heightened levels of
uncertainty and may not be perfectly
verifiable by the BLM, rather than
receiving no royalty at all if the property
is shut in to avoid the cost of achieving
uncertainty and verifiability goals.
The low-volume exemption in the
proposed rule would have provided an
objective measure of the economic
viability of a lease, CA, or unit PA, as
it relates to downhole commingling.
However, this economic test has been
difficult to implement for downhole
commingling applications under IM
2013–152 because the costs associated
with achieving non-commingled
downhole production are highly
speculative and vary by facility and
formations. These costs could be in the
millions of dollars if an operator had to
drill multiple wells in lieu of downhole
commingling in one wellbore. It is also
difficult to predict or quantify the
benefits of increasing the maximum
ultimate economic recovery from a well
due to the ability to produce more oil
and gas from downhole commingling.
As a result of these comments, the
BLM made two changes in the final rule.
First, the BLM added an exception for
certain categories of downhole
commingling under paragraph (b)(4).
This new exception allows the BLM to
approve downhole commingling of
production from multiple leases, CAs,
and unit PAs if the BLM deems the
proposed operation to be an acceptable
practice for the purpose of achieving
maximum economic recovery and
conservation of the oil and gas resource.
This exception provides a means for the
BLM to recognize downhole
commingling practices that have
historically been approved in areas
where such practices provide the only
way to produce the Federal or Indian
interest, and therefore are necessary to
avoid having some operators
prematurely plug existing wells. The
addition of this provision gives Field
Offices flexibility to approve downhole
commingling requests based on local
knowledge and experience with the
characteristics of a particular oil or gas
reservoir. Second, for existing downhole
commingling approvals, the BLM added
§ 3173.16(a)(1), which will grandfather
all downhole commingling approvals in
existence prior to the effective date of
this rule (see discussion under
§ 3173.16(a)(1)).
Several commenters said that the final
regulations should state clearly how the
BLM will balance the Federal interest in
royalty measurement against competing
interests, such as environmental
concerns. One commenter

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recommended that the BLM include an
exemption from the commingling
requirements in situations where the
BLM’s denial of a request for a CAA
would increase a project’s
environmental impact. The BLM did not
make any changes to the rule in
response to these comments because
paragraph (b)(5) of the final rule already
expressly allows the BLM to consider
approving a CAA if there are overriding
conditions, such as topographic or other
environmental considerations,
notwithstanding potential negative
royalty impacts from commingled
measurement. Section 3173.14(b)(2) of
the proposed rule contained a similar
provision. The BLM has determined that
this language would allow the BLM to
grant new CAAs in instances where the
BLM determines that minimizing
environmental impacts takes
precedence over ensuring accurate and
verifiable measurement and proper
reporting of oil and gas removed or sold
from a lease, unit PA, or CA. The BLM
believes these situations will be rare and
CAA approval will only be considered
after exhausting all feasible alternatives,
including alternate measurement
techniques. The environmental analysis
for the final rule indicates that in most
cases where operators are required to
install new facilities, they will likely
place those facilities at sites where there
is existing surface disturbance and
where the environmental impact would
be minimal (see the Procedural Matters
section below for more discussion about
the environmental analysis). If new
equipment requirements result in new
surface disturbances, the BLM, under
the provisions of this rule, will evaluate
any potential environmental impacts
and require operators to mitigate them.
One commenter stated that the added
and unnecessary cost to industry to
have to build and maintain separate
pipelines and facilities without a
substantial benefit for the BLM in return
is unreasonable. The commenter said
that they have a few wells in a field that
are not in the unit, but use the same
facilities that service the unit. The
commenter is concerned that they
would not be able to continue
commingling in the future without
doing a substantial economic study to
quantify the cost to build separate
facilities including shipping facilities.
Another commenter asked the BLM to
consider exempting those properties
that are in close proximity to an existing
gathering system and allowing
production from those properties to be
commingled with other properties, even
if they are not considered to be lowvolume properties.

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The BLM disagrees with these
comments and did not make any
changes to the rule as a result.
Allocation methods that affect royalty
measurement and reporting have the
potential to increase measurement
uncertainty, introduce bias, and inhibit
the BLM’s ability to verify and account
for oil and gas production removed or
sold from a lease, unit PA, or CA. The
exceptions that allow for commingling
when allocation methods affect royalty
are included in paragraph (b) of the final
rule; they cover cases where the
requirement to achieve non-commingled
measurement of production would
cause a prudent operator to shut in
production or would cause significant
and unavoidable environmental
impacts. When demonstrating whether a
lease, unit PA, or CA is economically
marginal, operators can and should
include the cost of building additional
gathering lines, any new facilities, and
mitigating environmental impacts into
their capital cost calculations to see if
they would qualify for commingling
approval under paragraph (b)(1) of this
section. If they do not meet the
definition, or any of the other
exceptions in paragraph (b) of this
section, then the operator should be able
to construct the additional facilities
while still realizing a reasonable return
on that investment, rather than shutting
in production from a particular well.
One commenter was concerned that,
under the CAA requirements, operators
who currently commingle small
amounts of saleable liquids produced
from gas wells (e.g., condensate) would
have to install separate storage tanks for
that liquid, imposing a significant and
unjustified cost on operators. The BLM
agrees with this concern raised by the
commenter and made two changes to
the final rule as a result. First, the
definition of economically marginal
property (low volume property in the
proposed rule) was changed in the final
rule to clarify that the expected costs
and revenues for the economic analysis
need only take into consideration the
commodity for which the measurement
equipment would be built, whether it is
the oil or gas. In the example provided
by the commenter, the economic
analysis of condensate measurement
would only consider the income stream
from the sale of condensate and would
not include the income stream from the
sale of gas. Therefore, the small amounts
of condensate generated would likely
qualify for an exemption under
paragraph (b)(1). Second, the BLM
added paragraph (b)(2) to the final rule
which provides an automatic exemption
from the CAA restrictions and from

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performing an economic analysis for
leases, unit PAs, or CAs that produce
less than 100 bbl of oil per month or
1,000 Mcf of gas per month, averaged
over the previous 12 months. In this
example, if the small amount of saleable
condensate was less than 100 bbl per
month averaged over the previous 12
months, the BLM could grant
commingling approval for the
condensate without any further
analysis, assuming that the conditions
in paragraph (a)(2) through (a)(4) were
also met.
One commenter representing Native
Alaskan interests said it would not be
economically feasible to prevent
commingling of production from BLM
lands that are within a unit PA that has
an existing measurement system
approved by all parties, when the BLM
lands comprise only a small portion of
the production. The BLM did not make
any changes to the final rule in response
to this comment, for two reasons. First,
if the BLM portion of the unit PA is very
small or the production is low, it might
qualify as an ‘‘economically marginal
property’’ under the definition of an
economically marginal property in
§ 3173.1. In this case, the BLM could
approve commingling with other unit
PAs within the unit or other properties
outside of the unit. The BLM may also
be able to approve commingling under
§ 3173.14(b)(5) if achieving noncommingled measurement of
production addresses some overriding
consideration, such as avoiding undue
environmental impacts. If, on the other
hand, the properties that are proposed
for inclusion in a CAA do not meet the
definition of economically marginal
properties, do not present some other
overriding consideration, such as
environmental impacts, or otherwise
satisfy one of this rule’s criteria, then
the BLM will require the operator to
achieve non-commingled measurement
of that unit PA.
A couple of commenters suggested
that the BLM is creating new law by
establishing standards and requirements
for existing CAAs that were not in Order
3. The BLM does not understand the
comment. The purpose of the
rulemaking process that the BLM is
going through is to establish new
standards and requirements. By
following the BLM’s authorizing statues
and the procedures established by the
Administrative Procedure Act, 5 U.S.C.
551 et seq., the BLM is able to establish
new or different standards and
requirements than those found in
existing Order 3. As explained
elsewhere in this preamble, the final
rule is squarely within the scope of the
BLM’s authorizing statutes and the

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related delegations of authority from the
Secretary.
Several commenters also said the
BLM has not analyzed the impacts of
the rule on industry and the BLM, and
requested clarification on how the BLM
will balance the Federal interest in
royalty measurement against competing
interests. The BLM disagrees that it has
not analyzed the impacts on industry or
the BLM. As stated earlier in this
preamble, the BLM has rigorously
weighed and considered the economic
impacts that this final rule will have on
industry and prepared draft and final
regulatory impact analyses for this
rulemaking, which are available to the
public. The Procedural Matters section
of this preamble contains a short
discussion of this rule’s potential
economic impact on industry. The
analysis estimates that this rule’s CAA
requirements will have a one-time cost
to industry of $4.9 million to $7.6
million for operators to submit
documentation and respond to the
BLM’s informational requests for
existing leases, and $2.7 million to
install meters where the BLM rescinds
existing commingling agreements. The
analysis also estimates there will be an
annual paperwork cost to industry from
these provisions of $3 million to $4.6
million for new and modified
commingling agreements, and $1.6
million in new annual metering
installation costs for those FMPs where
a commingling agreement is rescinded.
The BLM believes that the final rule
provides clear guidance on how the
BLM will balance the Federal interest in
accurate measurement with competing
interests, such as not causing
production to be shut in or creating
additional environmental impacts. The
final rule includes numerous provisions
that allow commingling in cases where
the public interest is better served by
allowing commingling even if it results
in potential negative effects to royalty
measurement. These instances include
properties that the BLM determines to
be economically marginal, properties
that produce below set thresholds,
situations that involve downhole
commingling, and where unnecessary or
undue degradation or unavoidable
environmental impacts or other
overriding considerations would result
if commingling were denied. The BLM
did not make any changes to the rule
based on these comments.
Section 3173.15 Applying for a
Commingling and Allocation Approval
Section 3173.15 of the final rule
establishes the requirements operators
must follow when requesting a CAA,
and the information they need to

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include. Most of these requirements
were in the proposed rule, but the final
rule includes changes to the amount and
type of information operators must
include in their applications. The BLM
made these changes in response to many
comments it received on this section.
The following discussion describes
those comments and the changes that
were made.
One commenter suggested that
proposed paragraph (b) be changed to
require operators to submit as part of
their CAA applications an allocation
method, instead of an allocation
schedule, which is subject to frequent
changes. The BLM agrees that
information about a CAA’s allocation
method would be more useful, and as a
result changed the final rule to require
an allocation method instead of a
schedule.
Several commenters said they did not
believe the BLM has the authority to
require operators to submit site facility
diagrams as part of new CAA approvals
for existing facilities, as required in
paragraph (e) of the proposed rule. The
BLM agrees that it does not need a site
facility diagram to approve a CAA
application for existing facilities and
has eliminated that requirement in the
final rule in response to these
comments.
One of the commenters asked about
the purpose in § 3173.15(e), for
requiring operators to provide a map
showing the boundaries, FMPs, and
location of wellheads and production
facilities as part of their commingling
and allocation application. In response,
the BLM changed paragraph (e) of the
final rule to reduce the amount of
information that operators must include
in maps submitted as part of CAA
applications. The required maps need
only show the boundaries of any lease,
unit, unit PA, or CA from which
production is proposed to be
commingled and indicate the locations
of existing or planned facilities with the
relative location of all wellheads (with
API numbers), the piping, and existing
or proposed FMPs included as part of
the CAA request. The BLM needs this
information for several reasons, one of
which is to determine if all the
production flowing through the
proposed FMP originates from the
leases, unit PAs, or CAs proposed to be
part of the CAA. Another reason is to
obtain clarity on what leases, unit PAs,
or CAs are actually proposed for
commingling. This is especially
important when unit PAs or CAs are
included in the proposal. In these
situations, the location of a well or
facility in relation to lease, unit PA, or
CA boundaries, is critical for the BLM

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to understand when evaluating a
commingling application. For example,
one well may be physically located on
a Federal lease but only produce from
a CA that covers one of the formations
under that lease, while another well on
the same lease may only produce from
a portion of the lease that is not part of
the CA. In this case, the BLM would
have to understand that even though
both wells are physically located on the
same lease, a CAA is required to
combine their production because their
production originates from different
properties. The BLM did not make any
changes to the rule based on these
comments.
One commenter asked whether the
BLM planned to monitor which wells
are flowing to which FMP and make
operational recommendations. While
the BLM has no intention of making
operational recommendations, it will
monitor which wells are flowing to
which FMPs if that affects the CAA or
the underlying allocation of production.
The BLM did not make any changes to
the rule based on these comments.
Several commenters wanted to know
why, in § 3173.15(k), submission of up
to 6 years of gas analyses, including Btu
content and all oil gravities, is required
for CAA requests. They indicated that it
would be too burdensome for CAA
applicants to provide historical crude
oil gravity and natural gas heating value
data, as only current data is relevant for
trying to determine the prices received
for these products. A couple of other
commenters said this information
requirement is excessive and would not
improve the quality of the application.
The BLM does not believe this to be an
onerous requirement. First, 6 years’
worth of data would not necessarily
include a lot of data, especially for
lower producing leases, unit PAs, and
CAs for which the BLM would consider
approving a CAA. For example, under
43 CFR 3175.100, a very-low-volume
FMP (producing 35 Mcf per day or less),
is only required to have a gas analysis
taken once per year, so 6 years of data
for that well is only 6 gas analyses. For
oil, the API gravity is only determined
when an oil sale takes place. A lowproducing oil lease may only have an oil
sale several times per year, in which
case 6 years of API gravities would
include only one or two dozen API
gravities. Second, operators should
already have this information readily
available because they are currently
required to maintain records for at least
6 years under 43 CFR 3170.7, which
retention period has been increased to 7
years for Federal leases under this rule.
One of the reasons the BLM needs
historical Btu and API gravities is to

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assess the allocation methodology
proposed by the operator. If, for
example, the gas analysis data showed
statistically significant variations
between Federal and non-Federal
properties proposed for a CAA, the BLM
may require that the allocation method
account for the Btu differences. On the
other hand, if the gas analyses for the
properties proposed for commingling
were not significantly different, then the
allocation method could be purely
volume based. The BLM could also
analyze the historical trend of Btu
content or API gravity to determine if,
for example, increasing Btu content
could result in greater future royalty.
Without this data, it would be
impossible for the BLM to perform any
analysis on the allocation method or on
future revenue projections as part of an
economic analysis.
Another commenter noted that this
information has no royalty impact if the
properties are 100 percent Federal or
Indian mineral ownership with the
same fixed royalty rate and distribution.
The BLM agrees with this comment and
added a caveat to § 3173.15(k)
indicating that this information is
required only if the CAA is not
approved under § 3173.14(a)(1).
The BLM also determined it was
necessary to make other changes to
§ 3174.15 in the final rule to address
considerations related to the
administration of the rule. As part of the
final rule, the BLM clarifies in
paragraphs (f) through (i) which
additional approvals operators must
seek if their commingling proposals
entail new surface disturbance or take
place on Indian lands or on lands
administered by other Federal surface
management agencies, in case operators
are unaware of these requirements.
Finally, this section clarifies that if offlease measurement is part of a
commingling and allocation proposal,
then a separate Sundry Notice under
§ 3173.23 is not needed as long as the
information required under paragraphs
(b) through (e) and, where applicable,
paragraphs (f) through (i) of § 3173.23 is
included as part of the request for
approval for commingling and
allocation. This revision clarifies that an
applicant may submit both proposals in
one Sundry Notice request.
Section 3173.16 Existing Commingling
and Allocation Approvals
Under § 3173.16 of the final rule, the
BLM will review an existing CAA when
it receives an operator’s request for an
FMP number for a facility associated
with the CAA. The BLM made
numerous changes to both the structure

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and content of this section in the final
rule in response to comments.
Section 3173.16(a)
A new paragraph (a) was added to the
final rule that grandfathers existing
commingling approvals in some specific
situations. Paragraph (a)(1) grandfathers
all existing downhole commingling
approvals.
Based on the numerous comments the
BLM received on downhole
commingling approvals (see a
discussion of those comments under
§ 3173.14(b)), the BLM decided to
grandfather all existing downhole
commingling approvals. The BLM is
aware that there are large numbers of
wells in the San Juan basin and
elsewhere that are currently approved
for downhole commingling. The BLM
believes that the vast majority of these
wells are producing low volumes of oil
and gas and that continued production
of these wells increases the maximum
ultimate recovery of oil and gas. As a
result, the BLM has made a
determination that it is in the public
interest to ensure these wells continue
to produce even if the methods used to
allocate production to Federal and
Indian leases, unit PAs, and CAs
potentially result in higher levels of
uncertainty, bias, and make verification
of production more difficult. The BLM
also believes that most of these wells
would be approved by the BLM to
continue commingling even if the BLM
were to perform an evaluation on them
as would have been required under this
section of the proposed rule.
Grandfathering all existing downhole
commingling approvals will streamline
the review process and reduce the paper
work burden on both industry and the
BLM. When the BLM receives a request
for an FMP for a well that has an
existing downhole CAA, the BLM will
document that the existing downhole
CAA qualifies under § 3173.16(a)(1) of
the final rule. The BLM will address any
shortcomings of the existing approval,
such as the absence of a defined
allocation method, on a case-by-case
basis during inspections and production
audits. The BLM may issue written
orders to operators to correct these
deficiencies.
Paragraph (a)(2) grandfathers existing
surface commingling approvals where
each lease, unit PA, or CA that is part
of the approval produces less than 100
bbl of oil per month or 1,000 Mcf of gas
per month, averaged over the previous
12 months. See the discussion under
§ 3173.14(b) for an explanation of how
the BLM derived these thresholds. As
with downhole commingling, the BLM
decided to grandfather these existing

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commingling approvals based on
comments received on the proposed
rule. However, the BLM does not agree
with comments stating that the
economic exemptions in the proposed
rule were inadequate. The BLM believes
that the economic exemptions in both
the proposed and final rules are
adequate to address those operations
where achieving non-commingled
measurement of production would truly
be uneconomic. In addition, the
definition of an economically marginal
property in the final rule expands the
criteria in the proposed rule by
changing the threshold from a 10
percent before tax rate of return to an
18-month after tax payout. The BLM
believes this could significantly increase
the number of leases, unit PAs, and CAs
that would be able to qualify for the
economic exemption.
The BLM does, however, agree with
comments expressing concern over the
paperwork burden associated with
preparing and reviewing applications
involving lower volume leases, unit
PAs, and CAs. The BLM chose to
grandfather these existing surface
commingling approvals based on the
understanding that leases, CA, and unit
PAs producing below these thresholds
would almost certainly qualify under
the definition of an economically
marginal property. The purpose of
grandfathering these approvals,
therefore, was to reduce the paperwork
burden for both the BLM and industry.
Under this provision, the operator of
any lease, unit PA, or CA that is below
these thresholds would retain the
existing CAA from the BLM without any
further information or analysis required.
The BLM would only have to verify that
the average monthly production rates of
the leases, CAs, and unit PAs included
in the approval are below the thresholds
listed in this section.
Section 3173.16(b)
A new provision has been added to
paragraph (b), which clarifies that if the
grandfathering conditions in paragraph
(a) of this section are not met, then the
existing CAA must meet the minimum
standards and requirements for a CAA
under § 3173.14 of the final rule.
This section also sets out a process if
the AO identifies deficiencies.
Paragraph (b)(1) requires the AO to
notify the operator in writing of any
inconsistencies or deficiencies with an
existing CAA. The operator will then be
given 20 days after receipt of such
notice to correct any inconsistencies or
deficiencies, provide the additional
information requested, or request an
extension of time. When the AO is
satisfied that the operator has corrected

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any inconsistencies or deficiencies, the
AO will terminate the existing CAA and
grant a new CAA based on the
operator’s corrections.
Paragraph (b)(2) clarifies that the AO
may terminate an existing CAA and
grant a new CAA with new or amended
COAs to make the approval consistent
with the requirements for CAAs under
§ 3173.14 of the final rule. Under the
proposed rule the AO could simply
impose new or amended COAs to an
existing commingling approval.
Section 3173.16(c)
One of the primary goals of paragraph
(c) in the final rule (§ 3173.16(a) through
(d) of the proposed rule) is to ensure
that existing commingling approvals
that do not qualify for grandfathering
under paragraph (a) of this section, meet
the standards for commingling under
§ 3173.14. Another primary goal is to
ensure that, if the existing commingling
approval does meet the standards under
§ 3173.14, it also contains the
information required under § 3173.15, to
ensure that the BLM can verify the
volumes allocated to each lease, unit
PA, or CA that are part of the existing
CAA.
Under paragraph (c), the BLM will
review existing CAAs that do not
qualify for grandfathering under
paragraph (a), for their consistency with
the minimum standards and
requirements under § 3173.14 when the
operator submits a request for an FMP
number. If the BLM determines that the
existing CAA does not meet the
requirements under § 3173.14, the BLM
may take several courses of action.
Under paragraph (c)(1), the AO will
notify the operator in writing of any
inconsistencies or deficiencies that the
BLM identifies. The operator will have
20 business days to provide additional
information requested by the BLM,
request an extension of time in which to
reply to the AO, or correct any
inconsistencies or deficiencies. Under
paragraph (c)(2), the BLM can impose
new or amended COAs on an existing
CAA to make it compliant with the
requirements of this final rule.
Paragraph (c)(3) allows the AO to
terminate the CAA if the operator fails
to correct the deficiencies that the BLM
identifies.
The only significant change to
paragraph (c)(1) of the final rule relative
to paragraph (b) of the proposed rule is
that the BLM clarifies that when the
operator corrects any inconsistencies or
deficiencies, the BLM will terminate the
existing CAA and grant a new CAA in
its place. The BLM made a similar
change to paragraph (c)(2) of the final
rule (paragraph (c) of the proposed rule),

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which clarifies that the BLM will
impose new or amended COAs on an
existing CAA by terminating the
existing CAA and granting a new CAA
in its place that includes those COAs.
Under paragraph (d) of the final rule
(paragraph (e) of the proposed rule), if
the BLM approves a new CAA to replace
an existing agreement, it will be
effective on the first day of the month
following its approval. The BLM also
included a new sentence in this
paragraph that clarifies that any
resulting change in the allocation
method will only apply from the
effective date of the CAA forward. The
BLM added this clause to clarify that
changes in the allocation method will
not be applied retroactively. The BLM
believes that retroactive application of
new allocation percentages would
impose a large paperwork burden on
both industry and the BLM and would
not be necessary.
Numerous commenters requested that
the BLM consider grandfathering all
existing CAA approvals. One
commenter said the modifications to
their facilities will put up to 87 percent
of their production at risk of being shut
in and possibly lost forever, along with
the royalties to each of the mineral
owners. The BLM agrees that there are
instances where existing commingling
agreements do not need to meet the final
rule’s commingling standards outlined
in § 3173.14(a)(1), and has provided
exemptions in § 3173.16(a) that allow
operators to maintain existing
agreements. See the discussion under
§ 3173.16(a) for further discussion. In
addition, § 3173.14(c) includes three
additional circumstances, beyond the
three provided under the proposed rule,
in which the BLM can approve a CAA.
Given the grandfathering provisions and
the expanded number of situations
where the BLM can approve a CAA
under the final rule, the BLM does not
believe that any existing CAAs that are
truly on the edge of profitability will be
impacted by the final rule’s
requirements.
Other commenters did not like the
idea of being required to upgrade
existing wells and facilities that comply
with existing laws, regulations, and
policies. While the BLM notes that
standard terms and conditions found in
Federal oil and gas leases require
compliance with all applicable
requirements, including requirements
that might be subsequently promulgated
by the BLM, the BLM nevertheless
believes that this comment has some
merit. Most existing surface
commingling approvals are for leases,
unit PAs, and CAs where production
volumes are low enough, or other

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overriding considerations exist, such
that the CAA will comply with the
requirements of § 3173.14(a) or (b) of the
final rule with little or no changes
required. Similarly, any CAA granted
under IM 2013–152 should already meet
the requirements of the final rule,
especially considering that the final rule
adds four additional exemptions under
which the BLM may grant a CAA as
compared to the two exemptions
allowed under the IM (for low-volume
properties and overriding
considerations), and lowers the
threshold for leases, unit PAs, and CAs
to meet the definition of an
economically marginal property. For the
relatively few existing CAAs that do not
meet the requirements of the final rule,
some changes to plumbing or
measurement equipment may be
required. In these cases, the BLM will
determine that a CAA is not justified
because these leases, unit PAs, or CAs
do not meet the definition of an
economically marginal property and no
other overriding conditions exist that
would allow the BLM to grant a CAA.
One commenter said the proposed
rule would require operators to submit
all existing authorizations to the BLM
for re-approval, and added that many
operators and BLM staff spent countless
hours negotiating approvals of existing
CAAs to ensure they protect
environmentally sensitive areas while
providing accurate measurement of
production. Although the BLM did not
make any changes to the rule based on
this comment, the final rule includes
grandfathering provisions under
§ 3173.16(a), which would no longer
require operators to submit existing
downhole commingling authorizations
or surface commingling authorizations
that qualify under § 3173.16(a)(1) and
(2) when applying for an FMP. In
addition, for those existing CAAs that
do not meet the grandfathering criteria
of paragraph (a) of this section, but
comply with the requirements of the
new rule, the BLM will not require reapproval—these CAAs will be allowed
to continue as originally approved.
Several commenters disagreed with
the requirement in § 3173.16(c)(1) that
operators correct any inconsistencies or
deficiencies that the AO finds with an
existing CAA within 20 business days.
One commenter said North Slope
operators have significant weatherrelated challenges that would make it
difficult for them to meet the 20business-day deadline, while another
said that the required fixes could
involve installing new piping, which
would likely take longer than 20
business days. Several commenters said
this final rule will require every existing

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CAA to have some work done and
operators must be given flexibility if
they have multiple CAAs because 20
business days may not be enough time
to bring them all into compliance.
Another commenter said that they have
made substantial investments in their
gathering systems and would need a
reasonable amount of time to make the
changes to facilities that handle leases
with mixed ownerships that are not
already part of a unit PA or CA.
In response to these comments, the
BLM added language to the final rule at
§ 3173.16(c)(1) which allows an operator
to request an extension during the 20business-day timeframe. The operator
should justify the extension request by
explaining the factors that will not
allow it to comply within the 20business-day timeframe, and provide a
timeframe under which they can
comply. The BLM will consider the
request and grant an extension if the
justification is adequate. This final rule
will not require every existing CAA to
undergo significant work to bring it into
conformity with the new requirements
as one commenter suggested. In fact, the
BLM estimates that the majority of
existing CAAs will continue operating
as they have been because they are
exempt from the requirements due to
their low production volumes or other
factors.
Several commenters said it would be
unfair for the BLM to apply new COAs
that existing CAAs could not meet,
causing production to be shut in.
Another commenter said it would be
unreasonable for the BLM to impose
new or amended conditions of
approvals on existing commingling
agreements and recommended that
§ 3173.16(c) be deleted altogether. The
BLM does not agree with these
comments and did not make any
changes to the final rule as a result.
The BLM estimates that only a small
percentage of existing CAAs will require
new COAs and most of those COAs will
be for minor deficiencies such as
providing a better explanation of the
allocation process. For those new COAs
that require additional work to which
the operator may object, the BLM has
already included a provision in
paragraph (c)(2) of the final rule that
will allow the existing CAA to continue
in effect during the pendency of any
appeal of the decision that requires the
new COAs. The BLM did not make any
changes to the rule based on these
comments.
Lastly, some commenters expressed
concern that existing CAAs were at risk
of being terminated if the BLM did not
timely respond to their FMP
applications and review their CAA

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approvals. As stated earlier, operators
may continue to produce oil and gas
prior to FMP approval and CAA review
and may continue to use their lease,
unit PA, or CA numbers for reporting
production to ONRR as long as they
have applied for their FMP numbers
within the deadlines specified under
§ 3173.12. The BLM did not make any
changes to the rule based on these
comments.
Section 3173.17 Relationship of a
Commingling and Allocation Approval
to Royalty-Free Use of Production
Section 3173.17 clarifies that approval
of a CAA does not constitute approval
of off-lease royalty-free use of
production in facilities located at an offlease FMP approved under the CAA.
The BLM did not make any changes to
this section.
One commenter from the San Juan
Basin said the new CAA requirements
would reduce Federal royalties from
existing CAAs because operators would
have to install new compressors at each
well, resulting in more royalty-free
production used as fuel to power those
compressors. The commenter provided
a diagram that showed a compressor for
each lease that they believe would be
required if commingling was not
approved. For comparison, another
diagram showed one large compressor
located at an off-lease FMP in lieu of the
wellhead compressors, if commingling
was approved. The commenter stated
that with commingling approval,
operators must pay royalty on the fuel
used at the commingled off-lease
compressor because it does not qualify
as royalty-free use.
The BLM disagrees with the premise
of this comment because there is
nothing in the scenario presented by the
commenter that would compel them to
install separate lease compressors if the
BLM denied commingling. The small
amount of royalty the operator would
not have to pay if the compressors were
located on-lease would never offset the
additional capital and ongoing expense
of having to install, operate, and
maintain three lease compressors as
compared to one large compressor
located at a central delivery point.
Instead, if the BLM did not grant a CAA,
a prudent operator would simply use
the allocation meters already installed at
each property they were proposing to
commingle as FMPs, continue to use the
large off-lease compressor, and continue
to pay royalties on the fuel used to run
that compressor as they do now. The
BLM did not make any changes to the
rule based on this comment.
Another commenter stated that other
royalty owners will be burdened by all

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the downstream losses (fuel, etc.) if the
operator must install an on-lease FMP
rather than rely on measurements taken
at a downstream commingled
measurement point.
According to the commenter this
raises legal concerns with respect to
other agency regulations and contractual
agreements between operators. The BLM
disagrees with this comment and did
not make any changes as a result. The
requirement to install an FMP on the
lease, unit PA, or communitized area,
and pay royalty based on that FMP only
applies to Federal and Indian leases. It
would not preclude other royalty
owners to base their royalty distribution
on a down-stream commingled
measurement point that is different from
the FMP on which the Federal or Indian
royalties are based.
Section 3173.18 Modification of a
Commingling and Allocation Approval
Section 3173.18(a) of the final rule
identifies the circumstances under
which all operators who are parties to
a CAA must request a modification,
including: Modifications to the
allocation agreement; inclusion of
additional leases, unit PAs, or CAs into
a CAA; or termination of a lease, unit
PA, or CA within a CAA. Paragraph (b)
identifies the information that must be
submitted in connection with a
modification request. Paragraph (c) was
added to the final rule to clarify that a
CAA does not need to be modified when
there is a change in operator.
One commenter suggested that the
BLM change proposed § 3173.18(a)(1),
which allowed operators who are a
party to a CAA to modify the CAA when
there is a change in the allocation
schedule. The commenter said it was
not practical or beneficial to update the
CAA each time the allocation schedule
changes. The BLM agrees that requiring
an update to the CAA when the
allocation schedule changes is not
necessary. The intent of requiring
information on the allocation was to
ensure that the BLM can verify and recalculate the volumes reported on the
OGORs. Allocation schedules are often
based on periodic well testing and can
change each time a well test is
conducted. As long as the BLM
thoroughly understands the allocation
methodology, we can request the well
testing or other data from which the
operator determines the allocation
schedule and verify that the allocation
was done in accordance with the
allocation methodology and was
properly reported on the OGOR.
Paragraph (a)(1) has been modified to
require a CAA modification only when
there is a modification to an allocation

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agreement, which in the final rule must
include an allocation methodology
rather than an allocation schedule.
Thus, only if there is a change in the
methodology used to determine
allocation percentages would an
operator have to make changes to their
existing CAA. A change to the allocation
schedule itself would not require such
a modification.
One commenter did not like the idea
of having a CAA re-evaluated when new
leases are proposed to be added to the
CAA, as required under § 3173.18(a)(2).
The BLM disagrees with this comment
and did not make any changes to the
rule as a result. The addition of a lease,
unit PA, or CA to an existing CAA will
affect the allocation of production in a
CAA, and therefore the BLM will need
to review the addition to ensure that the
allocation method is verifiable and
provides a fair return to the Federal
Government or Indian tribes or allottees.
Finally, several commenters asked
whether submission of a ‘‘Successor of
Operator Sundry Notice’’ would
automatically change the operator of the
FMP and the CAA. A Sundry Notice for
a change in operator of a well(s) and a
facility on a lease, unit PA, or CA will
designate that new operator as being
responsible for reporting production
from the property, and therefore will
include the CAA agreement. In response
to this comment, the BLM has removed
one of the conditions under which a
CAA may be modified—when there is a
change in operator. Furthermore, a new
paragraph (c) has been added to the
final rule stating that a change in
operator will not trigger the need to
modify the CAA. The FMP will
automatically transfer since it is part of
the facility.

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Section 3173.19 Effective Date of a
Commingling and Allocation Approval
Section 3173.19 (a) and (b) of the final
rule identifies the effective date of a
CAA after the approval of an application
or modification, respectively. Paragraph
(c) of this section clarifies that a CAA
does not modify any of the terms of any
leases, unit PAs, or CAs. The BLM did
not receive any public comments on this
section and did not change it in the final
rule, except to make minor
modifications for clarity.
Section 3173.20 Terminating a
Commingling and Allocation Approval
Paragraph (a) of § 3173.20 of this final
rule (paragraph (b) of the proposed rule)
authorizes the BLM to terminate an
approved CAA for any reason, including
changes in technology, regulation, or
policy, or where the operator has not
complied with the terms of the CAA.

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Paragraph (b) (paragraph (c) of the
proposed rule) provides for automatic
termination of a CAA if only one lease,
unit PA, or CA remains in the CAA.
Paragraph (c) (paragraph (a) of the
proposed rule) states that an operator
may terminate its participation in a
CAA by submitting a Sundry Notice to
the BLM. Unlike the provision in the
proposed rule, paragraph (c) of the final
rule clarifies that the termination by one
operator does not automatically
terminate the CAA as to all other
operators, so long as the requirements of
this part are met with respect to the
remaining participants in the CAA.
After termination of a CAA, paragraph
(d) requires the BLM to notify in writing
all operators who are a party to the CAA
of the effective date of the termination
and any inconsistencies or deficiencies
with their CAA approval that caused the
termination. The BLM modified this
provision from the proposed rule to
provide that upon receipt of the BLM’s
notice of termination, the operator has
20 business days to correct any
inconsistencies or deficiencies, or
provide additional information that the
AO has requested or that explains or
justifies the inconsistency or deficiency.
If the operator does not correct the
inconsistency or deficiency within 20
business days after receipt of the BLM’s
notice, the CAA is terminated as of the
effective date in the BLM’s notice. The
effective date of the termination will not
be earlier than the 20 business days
outlined in paragraph (d). Paragraph (e)
provides that upon termination, each
lease, unit PA, or CA may require a new
FMP number or a new CAA. Under the
final rule, operators will have up to 30
days to apply for a new FMP number or
CAA, whichever is applicable.
Following termination, while the BLM
is processing the application for a new
FMP number or CAA, the operator may
use the existing FMP number for
recordkeeping and production
reporting.
Several commenters were concerned
that paragraph (a) in the proposed rule
would have allowed a party to a CAA
to unilaterally terminate the CAA by
submitting a Sundry Notice to the BLM,
and that paragraph (b) in the proposed
rule, or paragraph (a) in the final rule,
allows the BLM to terminate a CAA for
any reason. One commenter said it
would be fine to allow a party to
terminate their participation in the
CAA, but the remaining operators
should have the opportunity to continue
with the CAA. One commenter asked
that the final rule be changed to allow
an existing CAA to continue after one of
the parties pulls out, as long as the

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remaining operator(s) follow the COAs
for the CAA.
The BLM agrees with the commenters
and believes that the continued
operation of a CAA when one operator
decides to pull out is in the public
interest. All the CAA requirements of
this rule are designed to ensure that the
CAA is in the public interest by, for
example, allowing continued
production of low volume properties,
addressing other overriding
considerations, or allowing the
maximum ultimate recovery of oil and
gas resources. The BLM does not believe
that the decision of one operator to pull
out of the CAA would change the BLM’s
public interest determination and
terminating the CAA as a result would
only result in additional paperwork for
both the BLM and industry. Instead, the
operator who wants to terminate its
own, individual participation in the
CAA should be able to do so. In
response to this comment, the BLM
removed proposed paragraph (a) in the
final rule and re-designated it with
modifications as paragraph (c). While
paragraph (c) still allows an operator to
terminate a CAA through submission of
a Sundry Notice, the BLM clarified that
paragraph in response to comments to
make clear that termination of
participation in a CAA by one operator
does not necessarily impact all
operators, so long as the other
requirements of this part are met with
respect to that CAA and the other
operators submit a Sundry Notice for a
new CAA as required by paragraph (e).
An operator who wishes to terminate
its participation will need to submit the
appropriate paperwork to the BLM as
outlined in 3173.20(c). Additionally, if
a CAA is terminated, paragraph (e) of
the final rule no longer requires separate
measurement. Rather, it gives operators
30 days to apply for a new FMP number
and/or CAA, if applicable. The old FMP
number may be used for recordkeeping
and production reporting until a new
FMP number is assigned or a new CAA
is approved. If more than one lease, unit
PA, or CA remains in a CAA, the
operator(s) of those leases, unit PAs, or
CAs will need to submit a Sundry
Notice for a new CAA under § 3173.18.
Another commenter stated that they
have established gathering systems that
are subject to the existence of CAAs. If
the CAA is terminated by the BLM, the
commenter states that operators could
no longer sell gas into the gathering
system, which could result in the shut
in of wells, lost production and lost
revenues. Instead, the operator suggests
that if an operator no longer wants their
lease to be part of a CAA, the CAA
could be easily modified to include only

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the remaining leases. The BLM agrees
with this comment and removed
paragraph (a) as discussed above.
Regarding comments that the BLM
should not have the authority to
terminate existing CAA approvals for
any reason, commenters already should
be aware that under the terms of all
existing CAAs, the BLM retains the right
to terminate a CAA for any reason.
Thus, the requirements found in
paragraph (a) are a codification of
existing practices. However, the reasons
listed under paragraphs (a)(1) through
(a)(3) of this final rule should cover the
majority of the situations that could lead
to termination of a CAA. If a CAA is not
in compliance with this rule’s
commingling requirements, the BLM
will work with the operators on a caseby-case basis to bring the CAA back into
compliance to avoid a termination. If a
CAA is terminated because of changes
in technology, regulation, or BLM
policy, operators will be given sufficient
time to make any necessary changes. In
the event that the BLM does take steps
to terminate a CAA, paragraph (c) of this
final section provides that the BLM’s
notice-of-termination letter will describe
the inconsistencies or deficiencies that
will lead to the CAA termination, along
with the effective date of the
termination. The parties to a CAA will
then have an opportunity to avoid
termination of the CAA by correcting
those inconsistencies or deficiencies
within 20 business days of their receipt
of notification.
Section 3173.21 Combining
Production Downhole in Certain
Circumstances
Section 3173.21 of this final rule
identifies certain circumstances in
which downhole combining of
production is subject to the
commingling requirements contained in
§§ 3173.14 through 3173.20. Under
paragraph (a)(1), the combination of
production from a single directional
well drilled into different hydrocarbon
pools or geologic formations under
separate adjacent properties, regardless
of ownership, where none of the pools
or formations are common to more than
one of the properties, constitutes
commingling under the final rule, and is
therefore subject to the requirements in
§§ 3173.14 through 3173.21 of this
subpart. If, on the other hand, the pools
or geologic formations are common to
more than one property, then under
paragraph (a)(2), the operator is required
to establish a unit PA or CA as opposed
to obtaining a CAA. Paragraph (b)
clarifies that combining production
downhole from different geologic
formations on the same lease from a

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single well, while requiring AO
approval, is not considered
commingling for purposes of this final
rule, unless those formations have
different ownership.
The BLM did not receive any public
comments on this section, but did make
one small change. In paragraph (b), the
final rule clarifies that the requirements
of §§ 3173.14 through 3173.20 do not
apply when operators combine
production downhole from different
geologic formations on the same lease in
a single well.
Sections 3173.22 through 3173.28 OffLease Measurement Approvals
Sections 3173.22 through 3173.28 of
this final rule establish the
circumstances in which the BLM will
approve measurement of production off
of the lease, unit, or CA (referred to as
‘‘off-lease measurement’’). Prior to this
rule, there were no national standards
that operators had to meet when
applying for off-lease measurement.
Neither Order 3 nor other regulations
addressed how or under what
circumstances the BLM would approve
off-lease measurement. This lack of
guidance led to much confusion over
the location of off-lease measurement
points. Off-lease measurement is also
often associated with commingling.
Meters that measure commingled
production are often referred to as
central delivery points. In most
situations, the meter at the central
delivery point is located off of at least
one of the Federal or Indian leases,
units, or CAs from which the
production originates. This
configuration requires the BLM to
approve both the commingling and the
off-lease location of the measurement
point.
In the absence of uniform national
standards governing off-lease
measurement, BLM State Offices created
their own policies for approving offlease measurement applications, which
were not necessarily consistent.
Sections 3173.22 through 3173.28 of
this final rule, discussed below, provide
such uniform national standards,
addressing the concerns identified by
the GAO, the OIG, and the
Subcommittee.
Some commenters said that this
section contains new record-keeping
requirements that are vague and that
could cause operators to submit
incorrect applications for off-lease
measurement. The commenters did not
specify the sections that they believe are
vague, nor did they provide any
explanation as to why they are vague.
The BLM did not make any changes to
the rule based on these comments. The

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BLM notes, however, that § 3173.23
contains a complete list all of the
information and documentation that
operators need to provide to the BLM
when applying for off-lease
measurement approvals.
Section 3173.22 Requirements for OffLease Measurement
Section 3173.22 of the final rule
establishes the conditions under which
the BLM will consider granting a
request for off-lease measurement. It
requires such requests to satisfy the
requirements of paragraphs (a) through
(d). Under paragraph (a), the BLM will
consider off-lease measurement of
production only from a single CAA or
a single Federal or Indian lease, unit PA,
or CA. Paragraph (b) requires that the
off-lease measurement provide for
accurate production accountability and
paragraph (c) requires that off-lease
measurement be in the public interest.
Paragraph (d) requires off-lease
measurement to occur at an approved
FMP.
Commenters asked that the BLM list
the conditions under which off-lease
measurement will be approved. The
BLM did not make any changes to the
rule based on this comment because this
section clearly lists the conditions
under which off-lease measurement will
be considered for approval. Requests
that meet the requirements of this
section will be approved, while requests
that do not will not be approved.
Another commenter requested that
the BLM provide exemptions from the
off-lease measurement requirements in
situations where topography or other
environmental issues prevent operators
from measuring on-lease. The BLM
agrees that there are circumstances
when it is physically impractical to
measure on-lease or where measuring
on-lease could cause additional
environmental impacts. Examples
include situations where well pads are
located at high altitudes that could be
inaccessible in the winter or when the
BLM has imposed seasonal access
restrictions due to environmental
concerns. In response to this comment,
final paragraph (c) has been changed to
allow off-lease measurement when onlease measurement is not practical due
to topographic or environmental
concerns. As with any of the
requirements in this subpart, an
operator may also request a variance to
the off-lease measurement requirements
on a case-by-case basis.
One commenter said its liquidsgathering system, which is within the
boundary of a CAA, should be exempt
from the off-lease measurement
requirements of § 3173.22 because this

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system has been in place for over 10
years, was approved by the BLM, and
works well. The BLM did not change
the final rule in response to this
comment. Instead, the BLM will review
existing off-lease measurement
approvals associated with CAAs, along
with the CAAs themselves, on a case-bycase basis as part of the FMP approval
process to ensure consistency with the
minimum standards and requirements
under § 3173.22 of the final rule.
Several commenters said that the new
off-lease measurement requirements
will result in more FMPs and that offlease measurement—because it requires
fewer FMPs—provides better accuracy
and reduces recordkeeping, allowing
multiple wells or pads (in a unit
operation) to commingle production at a
central tank battery. These commenters
asserted that this made it easier for the
BLM to track production and audit
facilities.
The BLM believes the commenters are
confused about the definition of offlease measurement. The operator can
locate an FMP, including a central tank
battery as mentioned by the
commenters, anywhere within the
boundary of a lease, a unit, or a CA from
which the production originates without
meeting the definition of off-lease
measurement and without needing
approval from the BLM. Although the
requirements for approving a CAA in
this rule may increase the number of
FMPs required, the BLM does not agree
that the off-lease measurement
requirements of this rule would have
any effect on the number of FMPs
required. As noted earlier in discussion
of § 3173.15(a) of the final rule, if offlease measurement is a feature of a
commingling and allocation proposal,
then a separate Sundry Notice
application for off-lease measurement is
not necessary and the off-lease
measurement proposal will be
considered as part of the CAA request.
The BLM expects that this final rule will
have a smaller impact than the proposed
rule would have had on existing offlease measurement approvals tied to
CAAs because §§ 3173.14(b) and
3173.16(a) of the final rule includes an
expanded list of exemptions that allow
commingling as well as grandfathering
provisions for some existing CAAs.
Finally, a few commenters said that
some existing off-lease measurement
approvals could be at risk if they do not
meet the BLM’s conditions for being ‘‘in
the public interest,’’ as outlined in
paragraph (c) of this section. We agree
that some existing off-lease
measurement approvals may not be in
the public interest, and they will
therefore be terminated. The public

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interest generally includes minimizing
environmental impacts, achieving
maximum ultimate economic recovery,
and allowing the BLM to verify volumes
and qualities of oil and gas reported on
the OGORs. Existing approvals that are
merely for the convenience of the
operator may not be in the public
interest. If, for example, an existing offlease measurement approval allows the
FMP to be located on private land that
makes BLM access difficult or
impossible, and the approval cannot be
justified based on environmental
circumstances or achieving maximum
ultimate economic recovery, it is likely
that the BLM will terminate the
approval. The BLM estimates that best
management practices and
environmental and topographic
considerations will outweigh the need
to terminate many existing off-lease
measurement approvals or to deny new
ones. The final rule was not changed in
response to these comments.
Section 3173.23 Applying for OffLease Measurement
Section 3173.23 of this final rule
establishes the requirements operators
must follow when applying for an offlease measurement approval or
amending an existing approval,
including required supporting
information and related documentation.
One commenter said that this section
of the rule is unnecessary and
redundant and that the off-lease
measurement application and approval
process should be part of the APD
process. The BLM does not agree that
this section is unnecessary and
redundant because it establishes the
process that operators will use to apply
for an off-lease measurement approval,
which is entirely separate from and
independent of the process the BLM
uses to process an APD. However,
§ 3173.23 does not prohibit operators
from submitting new off-lease
measurement applications with their
APDs. The BLM, in fact, would prefer to
receive comprehensive proposals
upfront from operators when they
submit their APDs because it
streamlines the BLM’s review process
by allowing BLM staff to look at a
project in its entirety early in the
permitting process.
Section 3173.23(a) requires operators
to submit their off-lease measurement
application via a Sundry Notice. That
Sundry Notice package may be
submitted at the same time as, but
separately from, an operator’s APD
package(s) and the BLM will process
both applications at the same time. The
final rule did not change as a result of
this comment.

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Several commenters said it would be
too burdensome to require operators,
whose off-lease measurement facilities
are located on non-federally owned
surface, to include in their off-lease
measurement applications written
concurrence from the surface owners,
including from future owners if the
ownership changes, as called for in
paragraph (e) of the final rule. The BLM
does not agree with these commenters.
Operators should already be obtaining
concurrences from surface owners as
part of the APD process as Onshore
Order 1 (Approval of Operations)
specifically requires operators to make a
good faith effort to obtain a Surface
Access Agreement from the surface
owner. Therefore, this requirement does
not place any additional burden on the
operator.
In addition, the BLM must have
guaranteed access to the off-lease
measurement location. Without this
guaranteed access, the BLM may not be
able to verify or account for the volumes
and qualities of oil and gas on which
royalty is due and would therefore deny
the off-lease measurement request or
terminate the existing off-lease
measurement approval. No change to
the rule was made in response to this
comment.
Finally, one commenter said that the
proposed rule did not specifically
require operators to obtain the written
consent of the owner and operator of
measurement facilities. As a result, the
commenter said, this rule would subject
owners and operators of the
measurement facility to the jurisdiction
of the BLM without its consent or
knowledge. The BLM believes that this
is a valid concern. However, the BLM
did not make a change to the rule in
response to this comment because
paragraph (e) (paragraph (f) in the
proposed rule) already requires
operators to obtain written concurrence
signed not only by the surface owner(s),
but also by the owner(s) of the
measurement facilities.
In addition to these changes, the BLM
made a few minor administrative
changes to final § 3173.23. These
clarifications were consistent with the
overall changes made to the final rule
and were not made in response to any
particular comments. The BLM added a
new paragraph (h) to the final rule to
clarify that operators, under existing
BLM regulations, must obtain approval
from the appropriate surfacemanagement agency, if new surface
disturbance is proposed for the FMP,
and its associated facilities are located
on Federal land managed by an agency
other than the BLM. The BLM also
clarified paragraph (f) to state that an

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operator needs to submit a right-of-way
grant application to the BLM along with
the off-lease measurement request only
when new surface disturbance is
proposed for the FMP and its associated
facilities are located on BLM-managed
land. If the proposed surface facilities
are on Indian land, then paragraph (g)
of the final rule requires that a right-ofway grant application must be filed with
the appropriate BIA office.
Other changes we made that were
unrelated to public comments include
modifications to the type of information
operators must submit as part of their
off-lease measurement application. In
paragraph (c)(2) of the final rule, the
BLM no longer requires the operator to
identify the land description of all
wells, pipelines, and other facilities
expected to be installed as part of their
proposal. Operators need only identify
the relative location of such facilities.
Paragraph (e) in the proposed rule
required submission of a schematic or
engineered drawing showing all new
facilities that are part of the off-lease
measurement proposal. This
requirement is no longer in the final
rule. Finally, the requirement in
paragraph (e) of the proposed rule that
called for the submission of a site
facility diagram for existing facilities if
changes are being proposed to the
facility is removed as unnecessary
because the requirements related to site
facility diagrams for existing facilities
are already addressed by § 3173.11. The
BLM elected to make these changes
consistent with the changes made to the
information-submission requirements
for commingling applications under
§ 3173.15 of the final rule. It is not
necessary for the information-collection
requirements for commingling
applications to be different than the
information-collection requirements for
off-lease measurement applications.

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Section 3173.24 Effective Date of an
Off-Lease Measurement Approval
Section 3173.24 provides that offlease measurement approvals are
effective on the date the BLM issues the
approval, unless the BLM specifies a
different effective date in the approval.
The BLM did not receive any public
comments on this provision and did not
make any changes to the final rule.
Section 3173.25 Existing Approved
Off-Lease Measurement
Under this section of the final rule, an
existing off-lease measurement approval
will be reviewed upon receipt of an
operator’s request for the assignment of
an FMP number to a facility associated
with the off-lease measurement
approval. Section 3173.25(a) states that

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the AO reviews the existing off-lease
measurement approval for consistency
with the minimum standards and
requirements in § 3173.22. The AO will
notify the operator in writing of any
inconsistencies or deficiencies. Under
paragraph (b), the operator will have to
correct the inconsistencies or
deficiencies, provide the additional
information that the AO has requested,
or request an extension from the AO
within 20 business days. If an operator
is requesting an extension, they must
justify the request by explaining the
factors that will not allow the operator
to comply within 20 days and provide
a timeframe under which the operator
can comply.
Under paragraph (c), in connection
with approving the requested FMP, the
AO may terminate an existing off-lease
measurement approval and grant a new
off-lease measurement approval with
new or amended COAs to make the
approval consistent with the
requirements of this rule. In addition,
paragraph (c) provides that the existing
off-lease measurement approval will
continue in effect during any pendency
of an appeal of the new off-lease
measurement approval. If the operator
fails to correct the deficiencies,
paragraph (d) provides that the AO may
terminate the off-lease measurement
approval. If the existing off-lease
measurement approval under this
section is consistent with the
requirements under § 3173.22(e) of the
final rule allows that existing off-lease
measurement be grandfathered and be
part of the operator’s FMP approval.
Under paragraph (f), if the BLM grants
a new off-lease measurement approval,
that new approval is effective on the
first day of the month following its
approval.
Several commenters had concerns
with the paragraph (a) requirement that
the AO review existing off-lease
measurement approvals to determine if
they comply with the new off-lease
measurement requirements in § 3173.22.
These commenters requested that the
BLM ‘‘grandfather in’’ existing off-lease
measurement approvals. Another
commenter said that operators spent
countless hours negotiating their
existing CAAs, along with their off-lease
measurement approvals, with BLM field
staff, which resulted in protections for
environmentally sensitive areas and
accurate measurement of production.
The BLM agrees with the comments
as they relate to grandfathered CAAs
and included language under
§ 3173.16(a) that also grandfathers
existing off-lease measurement
approvals that are included as part of

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those grandfathered CAAs under
§ 3173.16(a)(1) or (2).
The BLM does not, however, agree
that existing off-lease measurement
approvals that are not included in
§ 3173.16(a) should be grandfathered.
As we stated earlier in this preamble, a
major goal of this final rule is to ensure
that new and existing approvals—be
they for CAAs or off-lease
measurement—allow BLM staff to verify
that oil and gas are being measured and
reported accurately under these
approvals. Without the ability to
consistently track where and how oil
and gas are measured, the BLM cannot
be assured that production reporting is
accurate. Section 3173.25 sets up a
process for the BLM to review existing
non-grandfathered off-lease
measurement approvals that were
granted before the BLM established
guidance and standards that ensure
such approvals were structured so that
BLM staff can verify production
reporting.
For existing off-lease measurement
approvals that are associated with a
non-grandfathered CAA, the CAA
would provide the public interest
justification for the off-lease
measurement approval, whether that is
due to economics, protection of the
environment, or to achieve maximum
ultimate economic recovery. The BLM
estimates that more than 95 percent of
existing CAAs will be either
grandfathered or approved under the
provisions of the final rule. Therefore,
the only aspect of non-grandfathered
off-lease measurement approval that the
BLM will be concerned with is the
BLM’s access to the proposed off-lease
measurement location.
Another commenter said that the
proposed rule would have required
operators to submit all existing off-lease
measurement approvals to the BLM for
re-approval. The BLM disagrees. This
rule does not require operators to
submit all existing authorizations to the
BLM for re-approval. It does provide
that the AO, when an operator submits
an application for an FMP number
associated with an existing off-lease
measurement approval, the AO will
review that existing approval for
consistency with the minimum
standards and requirements for off-lease
measurement under § 3173.22 and
notify the operator in writing of any
inconsistency or deficiency, or request
additional information. No changes to
the final rule were made as a result of
this comment.
Several commenters were concerned
that paragraph (b) gives operators only
20 business days to correct any
inconsistencies or deficiencies that the

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AO identifies with existing off-lease
measurement approvals or to provide
any additional information the AO
requests. The commenters said 20
business days is not enough time to
make such corrections and
recommended that operators be given 60
to 90 days to fix any problems. One
commenter said some operators could
be required to reconfigure their pipes in
order to maintain their off-lease
measurement approvals, which would
likely take longer than 20 days to
accomplish. Several others said that
since this is the first time that the BLM
will be reviewing existing CAAs and offlease measurement approvals for
compliance with the new requirements,
every commingling facility with offlease measurement will need some
corrective work and operators must be
given more than 20 days to bring their
operations into compliance if they
receive multiple notices.
The BLM believes that some of the
commenters have confused the
requirements relating to the review of
existing off-lease measurement
approvals with those relating to the
review of existing CAAs under
§ 3173.16(b). The review of existing offlease measurement approvals will have
nothing to do with allocation methods
and will rarely involve any on-theground work. The BLM will be
concerned with only four issues when
reviewing existing off-lease
measurement approvals:
1. Does the existing off-lease
measurement point only measure
production from one lease, unit PA, CA,
or CAA?
2. Is the off-lease measurement point
reasonably accessible to the BLM for the
purpose of production accountability?
3. Is the off-lease measurement
approval in the public interest?
4. Does the off-lease measurement
occur at an approved FMP?
For the majority of existing off-lease
measurement approvals that are
associated with a CAA, items 1, 3, and
4 will already be addressed by the CAA.
Therefore, the only review the BLM will
do is to ensure the off-lease
measurement point is reasonably
accessible to the BLM. In the rare case
where it is not, the BLM may require
that the operator either modify the
location to make it more accessible to
the BLM or, in the most extreme cases,
move the measurement facility to a
location where it is accessible to the
BLM.
Second, in response to these
comments, the BLM added language to
the final rule that allows an operator to
request an extension of the 20-day
timeframe. The operator should justify

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the extension request by explaining the
factors that will not allow them to
comply within the 20-day timeframe
and provide a timeframe under which
they can comply.
One commenter objected to a
provision in paragraph (c) that allows
the AO to impose new or amended
COAs on an existing off-lease
measurement approval to make the
approval consistent with the off-lease
measurement requirements in § 3173.22.
The commenter was referring to an offlease measurement approval that is part
of an existing CAA. The commenter
stated that numerous sales contracts are
based on existing approvals and that by
changing the approval, gas sales
contracts may be at risk of termination.
Other commenters expressed concern
that new COAs could result in economic
burdens that would result in the shutin of production and loss of Federal or
Indian royalty. Other commenters said
the new off-lease measurement
requirements would force them to
reconfigure gathering lines at sites
where existing off-lease measurement
agreements were not approved, which
would be costly and cause additional
environmental impacts that may not be
necessary.
The BLM did not make any changes
to the rule based on this comment
because this has little do with the offlease measurement approval and much
more to do with the CAA approvals,
discussed previously in the preamble.
As discussed in the portion of this
preamble dealing with commingling, the
primary concern of the BLM when
reviewing existing off-lease
measurement approvals that are
associated with a CAA is to ensure that
the BLM has reasonable access to
inspect the off-lease measurement
facility. Generally, the only COAs that
the BLM would impose on an existing
off-lease measurement approval that is
associated with a CAA would relate to
ensuring BLM access to the FMP. These
COAs could include remedies such as
obtaining express authorization for the
BLM to access the facility in situations
where the facility is not located on land
managed by the BLM, or in rare cases,
moving the measurement facility to a
location that does provide the BLM
reasonable access. This paragraph
further provides that if the operator
appeals one or more of the new COAs,
the existing off-lease measurement
approval will continue during the
pendency of the appeal.
The BLM would like to reiterate that
most of the existing wells in the San
Juan Basin, where surface and
downhole commingling are occurring
together with off-lease measurement,

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may be exempt from having to meet the
new commingling and related off-lease
measurement requirements because they
qualify for grandfathering under
§ 3173.16(a). Section 3173.16(a)
grandfathers all existing downhole
commingling CAAs and any existing
surface CAAs if the average production
over the past 12 months is less than
1,000 Mcf of gas per month, or 100 bbl
of oil per month for each lease, unit PA,
or CA included in the CAA. In such
cases, the associated off-lease
measurement approval would also be
grandfathered under § 3173.16(a).
Section 3173.26 Relationship of OffLease Measurement Approval to
Royalty-Free Use of Production
Section 3173.26 of the final rule
clarifies that approval of off-lease
measurement does not constitute
approval of off-lease royalty-free use of
production as fuel in facilities located at
an approved off-lease FMP. Under NTL–
4A, the lessee or operator may claim
royalty-free use only for gas or oil used
on the same lease, on the unit for the
same unit PA, or on the same CA from
which the gas or oil was produced.
Thus, the lessee or operator may not
claim royalty-free use for any of the
production used as fuel at an off-lease
FMP, absent BLM approval.
One commenter asked that the BLM
define the term ‘‘royalty-free use’’ in
this rule. As explained in this preamble
with respect to § 3173.1, the BLM does
not believe such a change is necessary.
The definition of royalty-free use in
NTL–4A will control unless and until it
is replaced.
Section 3173.27 Termination of OffLease Measurement Approval
Section 3173.27(a) of the final rule
provides that the BLM may terminate an
off-lease measurement approval for any
reason. By way of illustration, this
paragraph identifies certain
circumstances under which the BLM
might exercise that authority—such as
changes in technology, regulation, or
BLM policy; operator non-compliance
with the terms or conditions of the offlease measurement approval; or operator
non-compliance with §§ 3173.22
through 3173.26. Under paragraph (b),
the BLM will notify the operator in
writing of the effective date of the
termination and any inconsistencies or
deficiencies with the operator’s
approval that serve as the reason(s) for
the termination. Upon receipt of the
BLM’s notice, the operator will have 20
business days to correct any
inconsistencies or deficiencies, or
provide any additional information the
AO requests. Paragraph (b) also provides

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an opportunity for an operator to
request an extension of time from the
AO within 20 business days after receipt
of the BLM’s notice, or the off lease
measurement approval terminates.
Paragraph (c) provides that an
operator may terminate an off-lease
measurement approval by submitting to
the BLM a Sundry Notice, which must
identify the new FMPs for the lease(s),
unit PA(s), or CA(s) previously subject
to the off-lease measurement approval.
Under paragraph (d), each lease, unit
PA, or CA that was subject to the offlease measurement approval may
require a new FMP number(s) or a new
off-lease measurement approval.
Operators will have up to 30 days to
apply for a new FMP number or offlease measurement approval, whichever
is applicable. While the BLM processes
the application for a new FMP number
or off-lease measurement approval, the
operator may continue to use the
existing FMP number.
The BLM received several comments
on this section of the proposed rule, one
of which expressed concern that
proposed § 3173.27 did not provide an
explicit timeframe or process for the
BLM to terminate off-lease measurement
approvals or for operators to correct the
inconsistencies or deficiencies that led
to the termination. This commenter
recommended that the BLM give
operators 9 months to correct their
inconsistencies or deficiencies before
terminating their approvals. Several
other commenters objected to paragraph
(a) of the final rule (paragraph (b) of the
proposed rule), which authorizes the
BLM to terminate an off-lease
measurement approval for any reason.
One commenter stated that some gas
sales contracts involving gathering
systems are based on having off-lease
measurement approvals and CAAs and
that if the BLM terminates the off-lease
measurement approval, the operator
will no longer be able to sell gas into the
gathering system. The commenter stated
that operators need to have some
confidence that the existing off-lease
measurement approval will allow
continued operations as long as the
operator follows the COA for the offlease measurement approval. If there are
issues to be resolved, the operator
should be given a reasonable time to
resolve the issues.
The BLM agrees in part with these
comments and made several changes to
the final rule in response. Under
revisions to final paragraph (b), the
BLM’s notification letter will describe
the inconsistencies or deficiencies in
the operator’s existing off-lease
measurement approval that will result
in the termination, and state the

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effective date of the termination. The
revisions also give the operator 20
business days from receipt of the letter
to correct the inconsistencies or
deficiencies identified by the BLM,
provide more information, or request an
extension of time from the AO in order
to avoid termination. The BLM does not
agree with a 9-month timeframe as
recommended by one commenter
because unique circumstances may
warrant different timeframes. If an
operator believes that correcting the
inconsistencies or deficiencies will take
longer than 20 days, it may request a
reasonable extension of time from the
AO in order to make any necessary
corrections.
The BLM received several comments
on paragraph (d) of the proposed rule.
Proposed paragraph (d) said that if an
off-lease measurement approval is
terminated, each lease, unit PA, or CA
subject to the approval reverts to
measurement on the respective lease,
unit, or communitized area.
Commenters said that this requirement
should not apply to gathering systems
that were installed with BLM approval
for the purpose of off-lease
measurement. If such an approval were
terminated, commenters said, the
gathering system could no longer
transport gas to the sales meter that is
off-lease and wells connected to the
gathering system would likely be shut in
or plugged as they could no longer sell
their gas. The new on-lease
measurement system would not be
connected to a gas sales line as well, the
commenter said. The commenter
recommended that the BLM delete the
whole section from the final rule.
The BLM disagrees with this
comment and did not make any changes
to the final rule as a result. The
commenter’s concern principally relates
to the underlying CAA approval, not to
the off-lease measurement approval
itself. The BLM’s primary concern with
off-lease measurement approvals that
are tied to a CAA is the BLM’s access
to the off-lease FMP for the purpose of
inspection and production accounting.
For off-lease measurement approvals
that are not tied to a CAA, § 3173.22(c)
allows the BLM to consider an
operator’s ability to achieve maximum
ultimate economic recovery from a
lease, unit PA, or CA in determining
whether it is in the public interest to
approve off-lease measurement. This
provision gives the BLM the leeway it
needs to exempt leases, unit PAs, or
CAs from the off-lease measurement
requirements in situations where denial
of off-lease measurement might result in
shut-ins.

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Section 3173.28 Instances Not
Constituting Off-Lease Measurement, for
Which No Approval Is Required
Section 3173.28 of the final rule
identifies two circumstances that will
not be considered off-lease
measurement for purposes of the rule.
The first is where an FMP is located on
a well pad of a directionally drilled well
that produces oil or gas from a lease,
unit, or CA on which the well pad is not
located. The second is where a lease,
unit, or CA is made up of separate noncontiguous tracts. If production is
moved from one tract to another tract
within the same lease, unit, or CA, and
the production is not diverted during
movement between the tracts before the
FMP (except for production used
royalty-free), measurement would not be
considered to be off-lease.
Several commenters were under the
impression that they would need offlease measurement approval for
horizontal and directionally drilled
wells where the well pad itself is
located off the lease, CA or unit. Under
paragraph (a), off-lease measurement
approval for such wells is not needed,
unless the FMP is also located off of the
well pad, regardless of distance. If any
of the facilities are located on nonfederally owned surface, the operator
will still need to obtain written
concurrence signed by the surface
owner(s), and the operator(s) of the
measurement facilities that grants the
BLM unrestricted access to the off-lease
measurement facility and the surface on
which it is located, in order to conduct
production verification inspections. The
BLM did not make any changes to the
rule based on this comment.
One commenter said that, in some
cases, there may by reasons to locate the
FMP near, but not actually on, the well
pad, triggering the need for the operator
to obtain off-lease measurement
approval. The commenter stated that if
the FMP is located a small distance off
the well pad, but clearly serves the
wells on the pad this should not require
an off-lease measurement approval. The
BLM disagrees with this comment and
did not make any changes to the rule as
a result. Paragraph (a) of this section
clearly states that the FMP must be
located on the well pad to avoid the
need for an off-lease measurement
approval. Normally, well pads are
clearly delineated in the field by a berm,
fence, or other easily-identifiable
feature. This makes the requirement
clear, objective, and enforceable.
Adding a provision that would, as
suggested by the commenter, include
FMPs that are only a short distance off
the well pad would render the provision

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for each applicable lease, unit PA, or
CA, since off-lease measurement or
commingling without approval is a
violation of this final rule and existing
BLM requirements under 43 CFR
3162.7–2 and 3162.7–3, both of which
require BLM approval before operators
store or measure production from a
Federal or Indian lease off-lease.
Some commenters argued that these
immediate assessments are inconsistent
with due process because there is no
opportunity for an operator to correct its
violations before an assessment is
imposed. To the contrary, the use of
immediate assessments for breaches of
the oil and gas operating regulations is
well established and is consistent with
the notice requirements of due process.
Section 3173.29 Immediate
Operators obligate themselves to fulfill
Assessments for Certain Violations
the terms and conditions of the Federal
Section 3173.29 expands the number
or Indian oil and gas leases under which
and types of violations that would be
they operate. These leases incorporate
subject to immediate assessments.
the BLM’s regulations by reference.
Immediate assessments are not civil
Thus, the immediate assessments
penalties and are separate from the civil contained in the regulations act as
penalties authorized under Section 109
‘‘liquidated damages’’ owed by
of FOGRMA, 30 U.S.C. 1719. Unlike the operators who have breached their
proposed rule, the final rule does not
leases by breaching the regulations. See,
subject purchasers and transporters to
e.g., M. John Kennedy, 102 IBLA 396,
immediate assessments—only operators. 400 (1988). Operators are expected to
For violation 7, non-retention of records know the obligations and requirements
necessary to determine quantity and
of the Federal or Indian oil and gas lease
quality of production, the final rule
under which they operate; additional
clarifies that the applicable regulation is notice is not required.
§ 3170.7, not § 3173.9(a)(1) and (2).
Several commenters said there could
Also, the final rule clarifies that
be instances when an operator is not
violation 8 could result in an immediate aware that a violation exists. One
assessment if operators fail to ‘‘apply
commenter said the assessment should
for,’’ rather than ‘‘obtain,’’ the required
be imposed only if the violation was a
FMP approval.
willful or knowing act of
With respect to violations 9, 10, and
noncompliance. Another commenter
11, which pertain to approvals for offsuggested the BLM place a Federal seal
lease measurement and surface or
and notify the operator of the violation
downhole commingling, respectively,
instead of issuing an immediate
the final rule clarifies that removing
assessment for something that they are
production from a facility that begins
not aware of or that might be beyond
operation after the effective date of the
their control. The BLM disagrees with
final rule, prior to receiving BLM
these comments. Operators have a
approval for off-lease measurement or
responsibility to inspect their properties
commingling, could result in an
to ensure site security, consistent with
immediate assessment. If the facility
all applicable regulations, including this
will be servicing new wells not yet
final rule. The violations outlined in
drilled, as well as existing wells already this section of the final rule all have
in production, then the existing wells
substantial adverse impacts on
must use their respective existing FMP
production accountability or royalty
numbers when reporting production to
income and, thus, the BLM believes the
ONRR’s OGOR until the BLM assigns
assessments are warranted. No changes
to the rule were made in response to
the new FMP number associated with
these comments.
its off-lease measurement or
Numerous commenters said that the
commingling approval.
An existing facility (i.e., one in service increases in the number of immediate
assessments related to producing
on or before the effective date of the
operations, from 1 to 11, and in the
final rule) would be subject to an
dollar amount of the assessments, from
immediate assessment if it engaged in
$250 to $1,000, are unreasonable. The
off-lease measurement or commingling
number of immediate assessments was
without an existing BLM approval.
expanded to include violations that
Under such circumstances, the BLM
pose particular threats to the integrity of
could issue an immediate assessment

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subjective and unenforceable. If the
operator can demonstrate that locating
the FMP a small distance off the well
pad is in the public interest and that the
BLM has guaranteed access to inspect
the FMP, then the BLM would approve
off-lease measurement.
Another commenter suggested that
the BLM add a paragraph to this section
that states gas used for fuel at locations
that are not considered to be ‘‘off lease’’
under paragraphs (a) and (b) of this
section qualifies as royalty-free usage.
The BLM did not make any changes to
the rule based on these comments
because what qualifies as royalty-free
use is outside the scope of this
rulemaking.

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81405

the BLM’s production accounting
system and that significantly increase
the BLM’s workload and enforcement
costs. The increase to $1,000 is justified
because it generally approximates what
it will cost the agency, on average, to
identify and document a violation and
verify remedial action and compliance.
Commenters objected to this section
of the proposed rule subjecting
purchasers and transporters to
immediate assessments. One said that
purchasers and transporters should not
be involved in retaining records
pertaining to the quality and quantity of
production. Another commenter said
that oil and gas lease agreements are a
contract between the government and
lessees and that purchasers and
transporters are not a party to those
agreements and, therefore, should not be
subject to these assessments. Other
commenters argued that the proposed
immediate assessments on purchasers
and transporters exceeded the BLM’s
statutory authority under FOGRMA.
Upon consideration of these arguments,
and further review and analysis of
FOGRMA and other authorities, the
BLM has removed the immediate
assessments on purchasers and
transporters from final § 3173.29.
Enforcement Actions
As explained in the proposed rule, the
final rule removes the enforcement,
corrective action, and abatement period
provisions of Order 3. In their place, the
BLM will develop an internal Inspection
and Enforcement Handbook that will
provide direction to BLM inspectors on
how to classify a violation—as either
major or minor—what the corrective
action should be, and what the
timeframes for correction should be.
The AO will use the Inspection and
Enforcement Handbook in conjunction
with 43 CFR subpart 3163, which
provides for assessments and civil
penalties when lessees and operators
fail to remedy their violations in a
timely fashion, and for immediate
assessments for certain violations.
As previously discussed in the
proposed rule, the final rule allows the
BLM to make a case-by-case
determination of the severity of a
violation, based on applicable
definitions in the regulations. In
deciding how severe a violation is, BLM
inspectors must take into account
whether a violation could result in
‘‘immediate, substantial, and adverse
impacts on public health and safety, the
environment, production accountability,
or royalty income.’’ (Definition of
‘‘major violation,’’ 43 CFR 3160.0–5.)
Under the existing definition of ‘‘major
violation,’’ which is not being revised as

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part of this rulemaking, the same
violation could be major or minor,
depending on the context.
Several commenters objected to the
BLM using internal guidance or the
Inspection and Enforcement Handbook
to address violations, assessments for
noncompliance, and corrective actions.
Commenters argued that the use of
internal enforcement guidance is
inconsistent with the APA and that
these guidance documents constitute
substantive rules that must be
developed through notice-and-comment
rulemaking. These comments
misunderstand the nature of the Internal
Inspection and Enforcement Handbook
that the BLM will develop. The
Handbook will not establish new
obligations to be imposed on the
regulated community in a manner that
will improve consistency in how those
BLM personnel excise there discretion
in applying existing regulations and
addressing instances of non-compliance.
Those obligations are spelled out in
applicable regulations, orders, and
permits, as well as the terms and
conditions of leases and other
agreements. Rather, the Handbook will
provide guidance to BLM personnel as
to how to apply the existing regulations
and address instances of noncompliance. The overarching
enforcement infrastructure of 43 CFR
subpart 3163 remains in effect, and the
definitions of ‘‘major violation’’ and
‘‘minor violation’’ in § 3160.0–5 remain
unchanged. It is these duly promulgated
regulations (among other authorities),
and not the Inspection and Enforcement
Handbook, that will provide the legal
basis for the BLM’s enforcement actions;
the BLM’s enforcement actions must be
consistent with these regulations
irrespective of what may be contained
in its Inspection and Enforcement
Handbook. It is not necessary for the
BLM to develop its Handbook—which
does not expand the BLM’s authorities
or impose binding obligations on the
regulated community—through noticeand-comment rulemaking.
The commenters requested that the
BLM use a transparent process to
develop this internal guidance and that
operators be given the opportunity to
comment on it. The BLM did not accept
these comments; however, the BLM will
post the Inspection and Enforcement
Handbook on the BLM Web site after it
is developed and finalized.
Elimination of Self Inspections
Consistent with the proposed rule,
this final rule eliminates the selfinspection provision of Order 3, section
III.F., because it has been impractical for
the BLM to enforce. Under the self-

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inspection program, operators were
supposed to establish a program for the
purpose of periodically measuring
production volumes and assuring they
were complying with the BLM’s
minimum site security requirements.
But, as discussed earlier in response to
comments on this topic during the
discussion of § 3173.8, the Order 3
requirements were vague and the BLM
never supplemented them with internal
guidance or enforcement policy. As a
result, the BLM determined that this
requirement was of limited utility.
Nonetheless, the BLM received a
comment that recommended that
instead of removing the requirement,
the language should be improved to
ensure that an inspection program is
established for periodically measuring
production volumes and ensuring
compliance with the BLM’s site security
requirements from Order 3. The BLM
disagrees with this comment and did
not make a change in response. In lieu
of reworking or updating this
requirement, the final rule strengthens
recordkeeping requirements for
operators, including for transporters and
purchasers, which the BLM believes
will ultimately accomplish the same
results and be more useful going
forward. It should also be noted that
although the self-inspection
requirement from Onshore Order 3 has
been eliminated, the actions that an
operator, transporter, or purchaser must
take to conduct periodic production
volume inspections and ensure site
security have been incorporated into
this final rule as required elements
under §§ 3173.2 through 3173.10 of the
final rule.
General Comments
The BLM received a few comments
that were general in nature and do not
necessarily relate to a specific provision
of the rule.
A number of comments argued that
the rule is impermissibly ‘‘retroactive.’’
These comments argued that the rule is
retroactive because it will apply to
wells, facilities, and authorizations that
existed before the rule’s effective date.
While the BLM agrees that retroactive
regulations raise special legal concerns,
those concerns are not implicated here
because this rule is not a retroactive
regulation. The comments
misunderstand the nature of the
‘‘retroactive’’ regulations that the law
disfavors. ‘‘A law does not operate
‘retrospectively’ merely because it is
applied in a case arising from conduct
antedating the statute’s enactment or
upsets expectations based in prior law.’’
Landgraf v. USI Film Prods., 511 U.S.
244, 269 (1994) (internal citations

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omitted). Rather, the test for
retroactivity is whether the new
regulation ‘‘attaches new legal
consequences to events completed
before its enactment.’’ Id. at 270. The
rule at hand does not attach any new
legal consequence to the operation of
existing wells and facilities prior to the
rule’s effective date. As the U.S. Court
of Appeals for the D.C. Circuit has
explained, the fact that a change in the
law adversely affects pre-existing
business arrangements does not render
that law ‘‘retroactive:’’
It is often the case that a business will
undertake a certain course of conduct based
on the current law, and will then find its
expectations frustrated when the law
changes. This has never been thought to
constitute retroactive lawmaking, and indeed
most economic regulation would be
unworkable if all laws disrupting prior
expectations were deemed suspect.

Chemical Waste Mgmt., Inc. v. EPA, 869
F.2d 1526, 1536 (D.C. Cir. 1989). Thus,
despite the fact that this rule may
require operators to update or modify
their existing wells, facilities, and
authorizations, the rule is nonetheless
prospective—not retroactive—in nature.
A couple of comments expressed that
the BLM was employing discriminatory
regulation, and gave as their examples
the inequality of producers, operators,
and transporters in regard to equity
interest in production. The proposed
rule would treat producers, operators,
and transporters equally even though
some of these parties (specifically
transporters) have no ownership interest
in the oil and gas product generated
from Federal or Indian lands. Because
they have no interest, it is most likely
that the costs they incur will be passed
directly on to equity holders,
commenters said. Over time, the
commenter asserted, because equity
holders may deduct transportation costs
from royalties owed, this may result in
reduced royalty payments for both the
government and the tribes. While the
BLM recognizes the possibility of some
pass through of compliance costs from
purchasers and transporters to
operators, based on its analysis of the
costs of this final rule, it does not
believe those costs will be significant.
Additionally, this change is consistent
with the provisions of FOGRMA, which
addresses responsibilities and duties of
operators, purchasers, and transporters.
By statute, Congress applied these legal
requirements to those parties equally.
One commenter pointed out that the
regulations fail to recognize the current
industry business models, as it pertains
to Master Limited Partnerships. Unlike
C Corporations, MLPs have no
mechanism for capitalizing the required

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Federal Register / Vol. 81, No. 222 / Thursday, November 17, 2016 / Rules and Regulations
changes and will be forced to expense
the cost. This passes the cost
immediately to unit holders. The
commenter recommended that the BLM
remove MLPs from the regulation. The
BLM did not understand this comment
in the context of this rule. Under the
applicable statutes and regulations
operators, purchasers, and transporters
are subject to the regulations governing
operations on a Federal or Indian
(except Osage Tribe) lease. The
underlying corporate structure of those
entities has no bearing on their duty to
comply with these requirements.
Many commenters questioned
whether the BLM has the resources to
implement this and other rules that it
has finalized, or will finalize in the
coming months, for example the new
hydraulic fracturing regulations, which
went into effect on June 24, 2015
(currently enjoined by order of the
District Court of Wyoming), and the
proposed Waste Prevention, Production
Subject to Royalties, and Resource
Conservation proposed rule, which
published on February 8, 2016 (85 FR
6616). Commenters stated that the BLM
does not have enough staff to enforce its
existing regulations, let alone new ones.
Commenters also said that the
cumulative economic impact of this
final rule should be analyzed together
with the economic impacts of the final
rules that are updating and replacing
Orders 4 and 5.
The BLM does not agree with these
comments. Most of the requirements in
this final rule are not new—they codify
existing requirements that are found in
Order 3 or they are standard industry
practices that most operators,
transporters, and purchasers already
follow. Those requirements that are new
have been added for two reasons: (1) To
give operators the flexibility to use new
technology, which could, in the long
run, reduce costs for both industry and
the BLM; and (2) To address production
accountability and site security
concerns raised by governmental
oversight bodies, such as the
Subcommittee, the GAO, and the OIG.
The BLM did not change the final rule
as a result of these comments.
One commenter stated that the
regulations should consider laws and
lease provisions that apply only in
Alaska, and should more clearly provide
for balancing measurement accuracy
and environmental considerations.
According to the commenter, these laws
and lease provisions impose heightened
restrictions on development in Alaska
with which the site security regulations,
in particular the requirements for
additional measurement facilities,
would conflict. The BLM does not agree

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with the commenter that changes to the
rule are necessary. To the extent tradeoffs between measurement accuracy and
environmental considerations are
appropriate, the BLM has already
addressed those issues in the rule—see
e.g., the discussion of considerations
that go into reviewing requests for offlease measurement or commingling
approvals. Additionally, whether the
final rule requires additional facilities is
facility-specific. Moreover, as explained
throughout this preamble and the
associated EA, the BLM expects that, to
the extent the final rule requires the
construction of new facilities on a lease,
the relocation of existing facilities onto
a lease, or the retrofitting of existing
facilities on a lease, it would likely be
done on surfaces that have already been
disturbed. Thus, the BLM does not
believe that this rule will result in the
significant ‘‘footprint’’ expansion the
commenter identified. Furthermore,
should compliance with a requirement
of this rule necessitate surface
disturbance inconsistent with
applicable laws or lease terms, the
operator may, through the PMT or under
§ 3170.6, as applicable, seek approval of
an alternative means of compliance that
would meet the objectives of that
requirement.
Miscellaneous Changes to Other BLM
Regulations in 43 CFR Part 3160
As noted at the beginning of this
Section-by-Section discussion, the BLM
has made other changes to provisions in
43 CFR part 3160. Some of those have
already been discussed above in
connection with provisions of this final
rule to which they relate. The remaining
revisions are those noted here.
1. The authority citation for part 3160
is corrected to include 25 U.S.C. 396,
the grant of rulemaking authority to the
Secretary for allotted Indian leases,
which does not appear in the current
print edition of the CFR. The BLM did
not receive any comments on this
change.
2. Section 3160.0–3, Authority, is
updated to include the amendments to
the Federal Oil and Gas Royalty
Management Act of 1982 enacted by the
Federal Oil and Gas Royalty
Simplification Act of 1996. The BLM
did not receive any comments on this
change.
3. Section 3161.1, Jurisdiction, is
updated to include references to FMPs,
the Indian Mineral Development Act,
and Tribal Energy Resource Agreements.
To see the BLM’s response to public
comment on these changes, please see
the discussion of related changes to
§ 3170.2 earlier in this preamble.

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81407

4. Section 3162.3–2 is revised by
adding a new paragraph (d), which
refers operators to provisions in subpart
3173 for details on how to apply for
approval of FMPs, surface or subsurface
commingling from different leases, unit
PAs and CAs, or off-lease measurement.
The BLM did not receive any comments
on this change.
5. Section 3162.4–1, Well records and
reports, is amended in a number of
respects by this final rule. Consistent
with the proposed rule, this final rule
revises paragraph (a) to make clear that
the new recordkeeping requirements
also apply to ‘‘source records’’ that are
relevant to ‘‘determining and verifying
the quality, quantity, and disposition of
production from or allocable to Federal
or Indian leases.’’ Similarly, paragraph
(d) has been revised to establish the new
records-retention period established by
the 1996 amendments to FOGRMA, and
mirror for part 3160 the provisions in
paragraphs (c) through (e) of § 3170.7 of
the final rule. A new paragraph (e) lists
those ‘‘record holders’’ who would be
subject to the new recordkeeping
requirements. This section also makes
clear that all record holders must
maintain their records when directed by
the Secretary, or his/her designee, in
cases where there is a judicial
proceeding or demand involving such
records. In this section of the previous
rule, the Secretary, or his/her designee,
could direct record holders to maintain
their records only in cases where there
was an audit or investigation.
6. Section 3162.4–3, the provisions
regarding the no-longer-used Form
3160–6 (the monthly report of
operations), is removed. The BLM did
not receive any comments on this
change.
7. Section 3162.6, Well and facility
identification, is revised to correct the
misspelled word ‘‘indentification’’ in
paragraph (a) to read ‘‘identification.’’
Paragraph (b) is revised to remove a
provision allowing abbreviated sign
designations and a ‘‘grandfathering’’
provision for old well signs. Paragraph
(c) is revised to extend signage
requirements to include facilities at
which oil or gas produced from Federal
or Indian leases is stored or processed.
The fifth sentence of the current
paragraph (c) becomes the new
paragraph (d), with its wording revised.
The current paragraph (d) is now
paragraph (e). The BLM did not receive
any comments on this change.
8. Section 3162.7–1, Disposition of
production. This final rule removes
paragraph (f), which currently refers to
a 6-year retention period, since the
initial statutory retention period for
records concerning Federal leases is

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now 7 years. The BLM opted not to
retain paragraph (f) because this
retention period is already prescribed
§§ 3162.4–1 and 3170.7 of the final rule.
The BLM received no comments on this

proposed change and did not make any
changes from the proposed rule to the
final rule.
9. Section 3162.7–5, Site security on
Federal and Indian (except Osage Tribe)
oil and gas leases, has been removed.

43 CFR 3162.7–5 paragraph

Final new provision

(a) Definitions ...........................................................................................
(b)(1) Lines and valves; effective sealing ................................................
(b)(2) LACT meters and effective sealing of components .......................

43 CFR 3173.1.
43 CFR 3173.2(a), 3173.9(b) and 3173.11(c)(7).
43 CFR 3170.4, 3173.3, and two sections in anticipated new subpart
3174.
43 CFR 3170.4.
43 CFR 3173.2(a) and (b).

(b)(3) By-passes around meters ..............................................................
(b)(4) Sealing of appropriate valves during oil measurement by hand
gauging.
(b)(5) Circulating lines with valves allowing access to remove oil from
storage tanks.
(b)(6) Records retention requirements .....................................................
(b)(7) Removal of oil for transportation by vehicle and required documentation.
(b)(8) Reporting theft or mishandling of oil ..............................................
(b)(9) Variances ........................................................................................
(c) Site security plans ...............................................................................
(d) Site facility diagrams ...........................................................................

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The provisions in the final rule that
correspond to, or cover the same subject
matter as, the several paragraphs in
§ 3162.7–5 are shown in the following
table:

10. Section 3163.2, Civil penalties, is
rewritten in several respects by this
final rule. The changes being made to
this section as part of this rule are a
combination of the changes proposed as
part of this rulemaking effort and the
proposed rule to update and replace
Order 5 (80 FR 61645). In addition,
following the publication of those
proposed rules, but prior to the
publication of this rule, the BLM
published an interim final rule—
Onshore Oil and Gas Operations—Civil
Penalties Inflation Adjustments (81 FR
41860)—that made adjustments for
inflation to all of the daily civil
monetary penalty maximums found in
§ 3163.2. The adjustments made by the
interim final rule were required by the
Federal Civil Penalties Inflation
Adjustment Act Improvements Act of
2015 (Sec. 701 of Pub. L. 114–74).
The BLM is making the following
additional changes to § 3163.2 in this
final rule. These changes are not a result
of the Federal Civil Penalties Inflation
Adjustment Act Improvements Act.
First, the BLM is amending the civil
penalty regulations to reflect the fact
that purchasers and transporters who
fail to maintain and submit records as
required by the BLM can be subject to
civil penalties under Section 109 of
FOGRMA (30 U.S.C. 1719). As
explained in the proposed rule, this
change is being made because the BLM’s
existing regulations do not reflect this
longstanding statutory authority. In
order to effectuate this change the BLM
is designating the first sentence of
paragraph (a) of the existing § 3163.2 as
paragraph (a)(1), and adding a new
paragraph (a)(2) that reads as follows:

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43 CFR 3173.1.
43 CFR 3170.7.
43 CFR 3173.5.
43 CFR 3173.8.
43 CFR 3170.6.
None (site security plans eliminated).
43 CFR 3173.11.

(2) Whenever a purchaser or
transporter who is not an operating
rights owner or operator fails or refuses
to comply with 30 U.S.C. 1713 or
applicable rules or regulations regarding
records relevant to determining the
quality, quantity, and disposition of oil
or gas produced from or allocable to a
Federal or Indian oil or gas lease, the
authorized officer will notify the
purchaser or transporter, as appropriate,
in writing of the violation. The second
sentence of the existing paragraph (a)
(pertaining to the maximum amount of
the penalty if the violation is not
corrected within 20 days of the date of
notice) is redesignated as paragraph
(b)(1). The existing paragraph (b)
(pertaining to the maximum amount of
the penalty if the violation is not
corrected within 40 days of the date of
notice) is redesignated as paragraph
(b)(2).
The BLM received a number of
comments asserting that it was unfair to
subject purchasers and transporters to
the civil penalties under the onshore oil
and gas regulations because purchasers
and transporters often do not have
control over the information provided
by operators. The BLM does not agree
with these comments. As explained
above, this change is being driven
primarily by longstanding statutory
requirements. Additionally, it should be
noted that there are instances where the
purchaser or transporter actually owns
the oil and gas delivery point, and
therefore has control of much of the
relevant information. With respect to
concerns about the accuracy of
information provided by an operator to
a purchaser or transporter, while

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entities are generally responsible for the
content of their records, the BLM
recognizes that such a situation (i.e.,
inaccurate information provided by an
operator) would be a factor that could be
considered in an enforcement action on
a case-by-case basis.
In addition to the changes identified
above, the BLM is also revising
paragraphs (a)(1) and (b)(1) to refer to
‘‘any person’’ and ‘‘the person,’’
respectively, rather than limiting the
applicability of civil penalties to an
operating rights owner or operator. This
change is consistent with the statutory
language found in Section 109(a) of
FOGRMA (30 U.S.C. 1719(a)). It also
clarifies that potential penalty liability
exists for parties who contract with
operating rights owners or operators to
perform activities on Federal or Indian
leases and who violate applicable
regulations, statutes, permits, or lease
terms in performing those activities.
While the operating rights owner or
operator is responsible (and liable for
penalties) for violations committed by
contractors, the contractors are also
themselves subject to the requirements
of certain statutes, regulations, permits,
and lease terms. The BLM is revising the
regulations in this manner in order to
enable the agency to hold contractors
directly responsible for violations they
commit.
In addition, this rule also removes the
regulatory caps on civil penalty
assessments found in the current
regulations paragraphs (b) (paragraph
(b)(2) in the final rule), (d), (e), and (f).
As explained in the proposed rule to
update and replace Order 5 (80 FR
61645), this change is based on

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comments received on an Advance
Notice of Proposed Rulemaking (ANPR)
(80 FR 22148) that sought input on a
variety of issues related to the onshore
oil and gas program, including whether
the regulatory civil penalty caps should
be removed. The ANPR explained that
these caps are not required by statute,
and that in the BLM’s view they impose
a limit on the total penalties that may
be assessed that do not seem reasonable
in the modern oil and gas context where
it can cost $5 to $10 million dollars to
drill a well.
As the BLM explained, it does not
believe that the existing regulatory caps
provide an adequate deterrence for
unlawful conduct, particularly drilling
on Federal onshore leases without
authorization and drilling into leased
parcels in knowing and willful trespass.
Similar concerns were expressed by the
Department’s OIG in a report, dated
September 29, 2014—Bureau of Land
Management, Federal Onshore Oil & Gas
Trespass and Drilling Without Approval
(No. CR–IS–BLM–0004–2014). In that
report, the OIG specifically questioned
the adequacy of the BLM’s policies to
deter such activities and recommended
that the BLM pursue increased
monetary fines. Based on the foregoing,
the final rule rewrites paragraphs (b)
(paragraph (b)(2) in the final rule), (d),
(e), and (f) accordingly, to remove the
regulatory caps, while maintaining the
statutory limits imposed on the amount
that may be assessed on a daily basis (30
U.S.C. 1719(a)–(d)), as amended by the
BLM’s recent interim final rule
adjusting those amounts for inflation.
Due to the removal of the regulatory
civil penalty caps, the BLM determined
that paragraph (j) is unnecessary given
that its requirements would have tiered
off the expiration of those caps. As a
result, this rule removes paragraph (j).
The BLM is also deleting all of
paragraph (g). The existing requirements
of paragraph (g)(1) and (g)(2)(iii), which
require initial proposed penalties to be
at the maximum rate, are being removed
because they are inconsistent with
subsequent judicial and administrative
decisions regarding the computation
and setting of penalties. The BLM also
determined that the requirements in
paragraph (g)(1) and (g)(2)(iii)
(establishing caps on a per operating
rights owner or operator per lease) are
inconsistent with the BLM’s removal of
regulatory caps on penalties found in
paragraphs (b) (paragraph (b)(2) in the
final rule), (d), (e), and (f). With respect
to paragraphs (g)(2)(i) and (g)(2)(ii), the
BLM is removing the additional notice
procedure and corrective period for
minor violations required under those
paragraphs because it does not believe

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those provisions are necessary. The
BLM’s regulations governing oil and gas
operations are clear, and provide more
than adequate notice of what is
required, making additional notification
requirements unnecessary and
administratively inefficient. As a result,
this rule removes all of paragraph (g)
and redesignates existing paragraph (i)
as (g). Existing paragraph (h) is
unaffected by this rule.
Finally, the BLM is moving the
substance of existing paragraph (k),
which requires the revocation of a
transporter’s authority to remove crude
oil produced from, or allocated to, any
Federal or Indian lease if it fails to
permit inspection for required
documentation under 43 CFR 3162.7–
1(c)), to paragraph (d) in order to
streamline the regulations. As a result,
paragraph (k) is removed as part of this
rule.
One commenter on the proposed rule
to replace Order 5 objected to the BLM’s
expansion of the civil penalty provision
to ‘‘purchasers and transporters’’ and to
the change to ‘‘any person,’’ instead of
retaining the existing language that
limited § 3163.2 to the operating rights
owner or operator. That commenter
contended that the BLM lacked
authority to impose liability on
contractors undertaking activities on a
Federal or Indian lease. The BLM
disagrees with this comment because
this change is consistent with Section
109(a) of FOGRMA (30 U.S.C. 1719(a)),
which states that ‘‘any person’’ who
violates the mineral leasing laws, any
rule or regulation issued under those
laws, or the terms of any lease or permit
shall be liable for civil penalties.
The BLM also heard a range of
opinions on the removal of the
regulatory civil penalty caps. Some
commenters contended that the
provisions would result in the
imposition of penalties that are
excessive, while others supported the
change. As explained early in this
section, the existing regulatory caps on
civil penalties result in maximum
penalties that are small relative to the
costs of drilling a modern oil and gas
well such that the potential deterrent
effect of civil penalties is limited. For
example, the maximum penalty that
could be assessed under existing
paragraph (b) is $600,000, which is only
10 percent of the cost of drilling a
typical well, which is potentially
insufficient to act as a deterrent to noncompliance.
Finally, several commenters suggested
that the BLM amend the proposed
regulations to require that any time a
purchaser, transporter, or contractor
receives an INC, a copy be provided to

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81409

the operating rights owner. The BLM
agrees with commenters that adequate
notice of potential violations is
important; however, it determined that
such changes are unnecessary. By
existing policy and practice, the BLM
addresses INCs to the party who is the
subject of the action and does not
believe it is appropriate to automatically
copy unrelated third parties.
Additionally, the regulations already
require that if a party is going to be
subject to such penalties, it has to
receive notice in writing first from the
BLM. Thus, under the scenarios
identified by the commenters, if they
were going to be penalized they would
have to first receive a written notice
from the BLM identifying the
violation(s) in question.
11. Section 3164.1, Onshore Oil and
Gas Orders, is revised to remove the
reference to Order No. 3, Site Security,
from the table in paragraph (b) because
the Order is now replaced by this
codified final rule.
12. Section 3165.3, Notice, State
Director review and hearing on the
record, is rewritten in several respects
by this final rule. Specifically,
consistent with the changes to § 3163.2
and the proposed rule, this rule amends
the notice requirements of the existing
regulations at 43 CFR 3165.3 to include
a provision regarding notice to a
purchaser or transporter (who is not an
operating rights owner or operator) of a
failure to comply with records
maintenance or production
requirements. This final rule also adopts
the changes proposed as part of the
Order 5 rulemaking to revise this
section to clarify that any person, not
just ‘‘an operating rights owner or
operator’’ (as previously provided for in
paragraph (a)(1)), is subject to a written
notice or order of they fail to comply
with any provisions of the lease, the
regulations in this part, applicable
orders or notices, or any other
appropriate order of the authorized
officer.
In addition, the BLM has also divided
the several sentences of the existing
paragraph (a) into numbered paragraphs
(a)(1) through (a)(7) and added
clarifying, nonsubstantive revisions
throughout the section. After the first
sentence, which has been redesignated
as paragraph (a)(1) (and rephrased into
active voice), the BLM has added a new
paragraph (a)(2) as set out in the
regulatory text of this final rule.
In addition, the second and third
sentences of existing paragraph (a) are
redesignated as paragraph (a)(3), and the
fourth, fifth and sixth and seventh
sentences are redesignated as
paragraphs (a)(4) through (a)(7). The

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BLM did not receive any comments on
these changes and as a result did not
make any further changes in this final
rule.
III. Overview of Public Involvement
and Consistency With GAO
Recommendations
Public Outreach
The BLM conducted extensive public
and tribal outreach on this rule both
prior to its publication as a proposed
rule and during the public comment
period on the proposed rule. Prior to the
publication of the proposed rule, the
BLM held both tribal and public forums
to discussion potential changes to the
rule. In 2011, the BLM held three tribal
meetings in Tulsa, Oklahoma (July 11,
2011); Farmington, New Mexico (July
13, 2011); and Billings, Montana
(August 24, 2011). On April 24 and 25,
2013, the BLM held a series of public
meetings in Washington, DC, to discuss
draft proposed revisions to Orders 3, 4,
and 5. The meetings were webcast so
tribal members, industry, and the public
across the country could participate and
ask questions either in person or over
the Internet. Following those meetings,
the BLM opened a 36-day informal
comment period, during which 13
comment letters were submitted. The
comments received during that
comment period were summarized in
the preamble for the proposed rule (80
FR 58952).
The proposed rule was made available
for public comment from September 30,
2015, through December 14, 2015.
During that period, the BLM held tribal
and public meetings on December 1
(Durango, Colorado), December 3
(Oklahoma City, Oklahoma), and
December 8 (Dickinson, North Dakota).
The BLM also held a tribal webinar on
November 19, 2015. In total, the BLM
received 106 comment letters on the
proposed rule, the substance of which
are addressed in the Section-by-Section
analysis of this preamble.

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Consistency With GAO
Recommendations
As explained in the background
section of this preamble, three outside
independent entities—the
Subcommittee, the OIG, and the GAO—
have repeatedly found that the BLM’s
oil and gas measurement rules do not
provide sufficient assurance that
operators pay the royalties due.
Specifically, these groups found that the
BLM needed updated guidance on oil
and gas measurement technologies, to
address existing technological advances,
as well as technologies that might be
developed in the future. These groups

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have all found that the BLM’s existing
guidance is ‘‘unconsolidated, outdated,
and sometimes insufficient,’’ and more
specifically with respect to Order 3,
that:
• There was no uniform means of
tracking all onshore meters, including
information about meter location,
identification number, and owner;
• Some BLM State offices have issued
their own guidance, which lacks a
national perspective; more specifically
there were concerns about the lack of
uniform national guidance with respect
to the review and approval of
commingling and off-lease
measurements requests; and
• There was insufficient information
collected with respect to on-lease
royalty-free use.
The final rule addresses these
recommendations by establishing
uniform national guidance governing
the review and approval of FMPs,
CAAs, and off-lease measurements. It
also requires operators to provide more
information about royalty-free use. The
provisions of the final rule specifically
address modern oil industry practices
with respect to each of these, while also
updating relevant documentation and
recordkeeping requirements in order to
ensure that all production is properly
accounted for.
IV. Procedural Matters
Executive Orders 12866 and 13563,
Regulatory Planning and Review
Executive Order 12866 provides that
the Office of Information and Regulatory
Affairs (OIRA) will review all significant
rules. The OIRA has determined that
this rule is not significant.
Executive Order 13563 reaffirms the
principles of E.O. 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. E.O. 13563 emphasizes
further 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. The BLM has
developed this rule in a manner
consistent with these requirements.
Regulatory Flexibility Act
The BLM certifies that this final rule
will not have a significant economic

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effect on a substantial number of small
entities as defined under the Regulatory
Flexibility Act (5 U.S.C. 601 et seq.).
The Small Business Administration
(SBA) has developed size standards to
carry out the purposes of the Small
Business Act and those size standards
can be found at 13 CFR 121.201. The
Small Business Act applies to oil and
gas extraction firms with fewer than
1,250 employees, oil and gas drilling
firms with fewer than 1,000 employees,
and firms providing oil and gas support
activities with annual receipts of no
more than $38.5 million. These small
entities must be considered as being at
‘‘arm’s length’’ from the control of any
parent companies.
Of the 6,460 domestic firms involved
in crude oil and gas extraction in 2013,
U.S. Census data show that 99 percent
(or 6,370) had fewer than 500
employees, which means that nearly all
U.S. firms involved in oil and gas
extraction in 2013 fell within the SBA’s
size standard of fewer than 1,250
employees. Of the 2,097 firms
participating in oil and gas drilling
activities in 2013, U.S. Census data
show that 2,044 (97 percent) had fewer
than 500 employees, which means that
nearly all U.S. firms involved in oil and
gas support activities in 2013 fell within
the SBA’s size standard of fewer than
1,000 employees. In 2012, there were
8,877 firms involved in drilling and
other support functions, of which 96
percent (8,561) had annual net receipts
of no more than $35 million, with a
greater number below the SBA’s $38.5
million threshold.
In addition to lessees and operators,
we must consider the size of the
purchaser and transporter firms. There
are multiple NAICS categories that
could include firms involved in the
purchasing and transporting of
petroleum from Federal and Indian
leases. For example, petroleum refiners
could be identified as purchasers. For
petroleum refiners (NAICS code
324110), the SBA standard says a small
business cannot have more than 1,500
employees or more than 200,000 bbl per
calendar day total operable atmospheric
crude oil distillation capacity. In that
context, capacity includes owned or
leased facilities as well as facilities
under a processing agreement or an
arrangement such as an exchange
agreement or a throughput agreement.
Purchasers could also be wholesalers,
truck transporters, or natural gas or
pipeline operators. For wholesalers,
including petroleum wholesalers
(NAICS codes 424710 and 424720), the
SBA standard for a small entity is one
that has fewer than 200 employees. For
truck transporters (NAICS subsector

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Federal Register / Vol. 81, No. 222 / Thursday, November 17, 2016 / Rules and Regulations
484), the SBA defines a small entity as
a firm with less than $27.5 million in
annual receipts. For natural gas pipeline
operators (NAICS code 486210), the
standard is a maximum of $27.5 million
in receipts per year. For crude oil
pipeline operators (NAICS code
486110), the standard is fewer than
1,500 employees.
As discussed above, national data,
including number of firms, number of
employees by firm, and annual receipts
by firm, is not discretely identified for
purchasers and transporters of
petroleum or natural gas. The
potentially affected purchasers and
transporters will likely be a minor
component in any number of the
relevant NAICS categories. Of the few
NAICS categories where reported
employment, receipt, and production
data matches up with the SBA size
standards, the preponderance of the
firms will be considered small entities
as defined by the SBA.
Based on the available national data,
the preponderance of firms involved in
developing, producing, purchasing, and
transporting oil and gas from Federal
and Indian lands are small entities as
defined by the SBA. As such, it appears
a substantial number of small entities
could be affected by this final rule.
Using the best available data, the BLM
estimates there are approximately 3,700
lessees and operators conducting oil and
gas operations on Federal and Indian
lands that could be affected by this final
rule. Additionally, the BLM estimates
there are approximately 200 to 300
purchasers and transporters operating
on Federal and Indian lands that
potentially could be affected by this
final rule.
In addition to determining whether a
substantial number of small entities are
likely to be affected by this rule, the
BLM must also determine whether the
rule is anticipated to have a significant
economic impact on those small
entities. Based on the Economic and
Threshold Analysis prepared for this
final rule, the BLM anticipates the cost
of implementing the provisions could
reduce the average annual net income of
impacted small entities by less than
0.001 percent. Except for the electronic
filing requirement, all of the provisions
apply to entities regardless of size.
However, entities with the greatest
activity will likely experience the
greatest increase in compliance costs.
As a general matter, smaller business
entities are more likely to operate a
smaller number of sites and FMPs for
which they will have to submit the
information and documentation that
this final rule requires. Copies of the
analysis can be obtained from the

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contact person listed earlier (see FOR
FURTHER INFORMATION CONTACT).

Based on the available information,
we conclude that the final rule will not
have a significant impact on a
substantial number of small entities.
Therefore, a final Regulatory Flexibility
Analysis is not required, and a Small
Entity Compliance Guide is not
required.
Small Business Regulatory Enforcement
Fairness Act
This final rule is not a major rule
under 5 U.S.C. (2), the Small Business
Regulatory Enforcement Fairness Act.
This rule will not have an annual effect
on the economy of $100 million or
more. As explained in the Economic
and Threshold Analysis, the final rule
will increase the estimated ongoing
costs associated with the development
of Federal and Indian oil and gas
resources by an estimated $11.7 million
annually for the regulated community.
In addition, there will be an estimated
one-time cost to the regulated
community to implement the new
provisions of $31.2 million. The onetime implementation costs will be
spread over 3 years, or about $10.4
million per year. As discussed in the
Economic and Threshold Analysis, the
BLM anticipates the cost of
implementing the provisions could
reduce the average annual net income of
impacted small entities by
approximately 0.01 percent.
This rule replaces Order 3 to ensure
that oil and gas produced from Federal
and Indian leases is properly and
securely handled so that these resources
are accurately accounted for.
This rule:
• Will not cause a major increase in
costs or prices for consumers,
individual industries, Federal, State,
tribal, or local government agencies, or
geographic regions; and
• Will not have significant adverse
effects on competition, employment,
investment, productivity, innovation, or
the ability of U.S.-based enterprises to
compete with foreign-based enterprises.
Unfunded Mandates Reform Act
In accordance with the Unfunded
Mandates Reform Act (2 U.S.C. 1501 et
seq.), the BLM finds that:
• This rule will not ‘‘significantly or
uniquely’’ affect small governments. A
Small Government Agency Plan is
unnecessary.
• This rule will not produce a Federal
mandate of $100 million or greater in
any single year.
The rule is not a ‘‘significant
regulatory action’’ under the Unfunded
Mandates Reform Act. The changes in

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this rule will not impose any
requirements on any non-Federal
Governmental entity.
Executive Order 12630, Governmental
Actions and Interference With
Constitutionally Protected Property
Rights (Takings)
Under Executive Order 12630, the
rule will not have significant takings
implications. A takings implication
assessment is not required. This rule
will set minimum standards for
ensuring that oil and gas produced from
Federal and Indian (except the Osage
Tribe) oil and gas leases are properly
and securely handled, so as to prevent
theft and loss and to enable accurate
measurement and production
accountability. All such actions are
subject to lease terms which expressly
require that subsequent lease activities
be conducted in compliance with
applicable Federal laws and regulations.
The rule conforms to the terms of those
Federal leases and applicable statutes,
and as such the rule is not a
governmental action capable of
interfering with constitutionally
protected property rights. Therefore, the
rule will not cause a taking of private
property or require further discussion of
takings implications under this
Executive Order.
Executive Order 13132, Federalism
In accordance with Executive Order
13132, the BLM finds that the rule
would not have significant Federalism
effects. A Federalism assessment is not
required. This rule will not change the
role of or responsibilities among
Federal, State, and local governmental
entities. It does not relate to the
structure and role of the States and will
not have direct, substantive, or
significant effects on States.
Executive Order 13175, Consultation
and Coordination With Indian Tribal
Governments
Under Executive order 13175, the
President’s memorandum of April 29,
1994, ‘‘Government-to-Government
Relations with Native American Tribal
Governments’’ (59 FR 22951), and 512
Departmental Manual 2, the BLM
evaluated possible effects of the final
rule on federally recognized Indian
tribes. The BLM approves proposed
operations on all Indian onshore oil and
gas leases (except Osage Tribe).
Therefore, the final rule has the
potential to affect Indian tribes. In
conformance with the Secretary’s policy
on tribal consultation, the BLM held
tribal consultation meetings to which
more than 175 tribal entities were
invited, both before the rule was

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proposed and during the public
comment period on the proposed rule.
The consultations were held in:
Pre-Publication Meetings
• Tulsa, Oklahoma on July 11, 2011;
• Farmington, New Mexico on July
13, 2011; and
• Billings, Montana on August 24,
2011.
• Tribal workshop and webcast in
Washington, DC, on April 24, 2013.

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Post-Publication Meetings
• The BLM hosted a webinar to
discuss the requirements of the
proposed rule and solicit feedback from
affected tribes on November 19, 2015;
and
• In-person meetings were held in:
Æ Durango Colorado, on December 1,
2015;
Æ Oklahoma City, Oklahoma, on
December 3, 2015; and
Æ Dickinson, North Dakota, on
December 8, 2015.
The BLM also met with interested
tribes on a one-on-one basis as
requested to address questions on the
proposed rule prior to the publication of
the final rule. In each instance, the
purpose of these meetings was to solicit
feedback and comments from the tribes.
The primary concerns expressed by
tribes related to the subordination of
tribal laws, rules, and regulations by the
proposed rule; tribal representation on
the Department’s Gas and Oil
Measurement Team; and the BLM’s
Inspection and Enforcement program’s
ability to enforce the terms of this rule.
In general, the tribes, as royalty
recipients, expressed support for the
goals of the rulemaking, namely
accurate measurement. With respect to
tribal representation on the
Department’s Gas and Oil Measurement
Team, it should be noted that the team
is internal only. That said, the BLM will
continue to consult with tribes on
measurement issues that impact them
and their resources. None of the tribal
comments received were directed
specifically at this rule’s oil
measurement requirements, and
therefore no changes were made as a
result of these comments. While the
BLM will continue to address these
concerns, none of the concerns affect
the substance of the proposed rule.
Executive Order 12988, Civil Justice
Reform
Under Executive Order 12988, the
Office of the Solicitor has determined
that the final rule will not unduly
burden the judicial system and meets
the requirements of Sections 3(a) and
3(b)(2) of the Executive Order. The

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Office of the Solicitor has reviewed the
final rule to eliminate drafting errors
and ambiguity. It has been written to
minimize litigation, provide clear legal
standards for affected conduct rather
than general standards, and promote
simplification and burden reduction.
Executive Order 13352, Facilitation of
Cooperative Conservation
Under Executive Order 13352, the
BLM has determined that this final rule
will not impede facilitating cooperative
conservation and will take appropriate
account of and consider the interests of
persons with ownership or other legally
recognized interests in land or other
natural resources. This rulemaking
process involved Federal, tribal, State,
and local governments, private for-profit
and nonprofit institutions, other
nongovernmental entities and
individuals in the decision-making via
the public comment process. That
process provides that the programs,
projects, and activities are consistent
with protecting public health and safety.
Paperwork Reduction Act
The Paperwork Reduction Act (PRA)
(44 U.S.C. 3501–3521) provides that an
agency may not conduct or sponsor, and
a person is not required to respond to,
a collection of information, unless it
displays a currently valid OMB control
number. Collections of information
include requests and requirements that
an individual, partnership, or
corporation obtain information, and
report it to a Federal agency. See 44
U.S.C. 3502(3); 5 CFR 1320.3(c) and (k).
This rule contains information
collection activities that require
approval by the OMB under the PRA.
The BLM included an information
collection request in the proposed rule.
OMB has approved the information
collection for the final rule under
control number 1004–0207.
Some of the information collection
activities in the rule will add new uses
and burdens for BLM Form 3160–5,
Sundry Notices and Reports on Wells.
Form 3160–5 has been approved by
OMB for uses enumerated at 43 CFR
3162.3–2, and is one of 17 information
collection activities that are included in
control number 1004–0137, Onshore Oil
and Gas Operations (43 CFR part 3160)
(expiration date January 31, 2018).
The information collection activities
in this rule are described below along
with estimates of the annual burdens.
Included in the burden estimates are the
time for reviewing instructions,
searching existing data sources,
gathering and maintaining the data
needed, and completing and reviewing

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each component of the information
collection.
Summary of Information Collection
Activities
Title: Oil and Gas Facility Site
Security (43 CFR Subparts 3170 and
3173).
Forms: Form 3160–5, Sundry Notices
and Reports on Wells.
OMB Control Number: 1004–0207.
Description of Respondents: Oil and
gas operators, lessees, operators,
purchasers, transporters, and any other
person directly involved in producing,
transporting, purchasing, selling, or
measuring oil or gas.
Abstract: This rule establishes
minimum security standards for Federal
and Indian (except Osage Tribe) oil and
gas leases.
Frequency of Collection: On occasion.
Obligation To Respond: Required to
obtain or retain benefits.
Estimated Annual Responses:
274,886.
Estimated Reporting and
Recordkeeping ‘‘Hour’’ Burden: 578,240
hours.
Estimated ‘‘Non-Hour’’ Burden:
$4,891.972.
Discussion of Information Collection
Activities
Some of the activities will be onetime-only, while others will be ongoing.
Similarly, the BLM recognizes that for
some of the activities, there will be both
an annual burden for some respondents,
and a one-time burden for virtually all
respondents in the initial
implementation. Because of the way the
rule is structured, the one-time burdens
that are applicable to all respondents are
phased-in over 3 years based on
production volumes.
The preamble to the proposed rule
solicited public comments on the
information collection. Those
comments, and responses of the BLM,
are discussed above in the preamble. All
comments—both those pertaining to
information collection and other
comments—are addressed in the final
rule. The comments and BLM responses
pertaining specifically to the collection
of information are discussed in the
Section-by-Section analysis of the
following sections of the final rule:
• 3170.7;
• 3173.6 through 3173.9;
• 3173.11 through 3173.13;
• 3173.15;
• 3173.23; and
• 3173.25.
The information-collection activities
in this rule are described below.

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Well and Facility Identification (43 CFR
3162.6)
The information-collection activity in
the current version of § 3162.6 has been
approved by OMB under control
number 1004–0137. The revisions
effected by this rule are not expected to
exceed the existing burden hours
authorized by control number 1004–
0137. This activity is not included in
the burdens for this rule.
Variance Requests (43 CFR 3170.6)
Section 3170.6, a new regulation,
authorizes any party that is subject to
the regulations in 43 CFR part 3170 to
request a variance from any of the
regulations in part 3170. While § 3170.6
states that a request for a variance
should be filed using the BLM’s
electronic system, it also allows the use
of paper copies of Form 3160–5 (Sundry
Notices). Thus, § 3170.6 represents a
new use of Form 3160–5, Sundry
Notices and Reports on Wells.

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Required Recordkeeping and Records
Submission (43 CFR 3170.7)
Section 3170.7 applies to lessees,
operators, purchasers, transporters, and
any other person directly involved in
producing, transporting, purchasing,
selling, or measuring oil or gas through
the point of royalty measurement or the
point of first sale, whichever is later.
This regulation applies to records
generated during or for the period for
which the lessee or operator has an
interest in or conducted operations on
the lease, or in which a person is
involved in transporting, purchasing, or
selling production from the lease. This
information collection activity assists
the BLM in accurate accounting of oil
and gas production.
In general, records from Federal leases
must be maintained for 7 years, and
records from Indian leases must be
maintained for 6 years. Additional
details and exceptions are explained
below.
For Federal leases, and units or
communitized areas that include
Federal leases but do not include Indian
leases, the record holder must maintain
records for 7 years after the records are
generated. If a judicial proceeding or
demand involving such records is
timely commenced, the record holder
must maintain such records until the
final nonappealable decision in such
judicial proceeding is made, or with
respect to that demand is rendered,
unless the Secretary, her designee, or
the applicable delegated State
authorizes in writing an earlier release
of the requirement to maintain such
records.

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For Indian leases, and units or
communitized areas that include Indian
leases but do not include Federal leases,
the record holder must maintain records
for 6 years after the records are
generated. If the Secretary or her
designee notifies the record holder that
the Department of the Interior has
initiated or is participating in an audit
or investigation involving such records,
the record holder must maintain such
records until the Secretary or his
designee releases the record holder from
the obligation to maintain the records.
For units and communitized areas
that include both Federal and Indian
leases, if the Secretary or his designee
has notified the record holder within 6
years after the records are generated that
an audit or investigation involving such
records has been initiated, but a judicial
proceeding or demand is not
commenced within 7 years after the
records are generated, the record holder
must retain all records regarding
production from the unit or
communitized area until the Secretary
or her designee releases the record
holder from the obligation to maintain
the records. If a judicial proceeding or
demand is commenced within 7 years
after the records are generated, the
record holder must retain all records
regarding production from the unit or
communitized area until the final
nonappealable decision in such judicial
proceeding is made, or with respect to
that demand is rendered, unless the
Secretary or her designee authorizes in
writing a release of the requirement to
maintain such records before a final
nonappealable decision is made or
rendered.
For all types of Federal and Indian
leases, the lessee, operator, purchaser,
and transporter must maintain an audit
trail that includes all records, including
source records that are used to
determine quality, quantity, disposition,
and verification of production
attributable to a Federal or Indian lease,
unit participating area (unit PA), or CA,
must include the FMP number or the
lease, unit PA, or CA number along with
a unique equipment identifier (e.g., a
unique tank identification number and
meter station number); and the name of
the company that created the record. For
existing measurement facilities, in the
interim period before the assignment of
an FMP number, all records must
include the following information:
• The name of the operator;
• The lease, unit PA, or CA number;
and
• The well or facility name and
number.
Section 3170.7(h) requires operators,
purchasers, and transporters to submit

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all records, including source records
that are relevant to determining the
quality, quantity, disposition, and
verification of production attributable to
Federal or Indian leases, upon request,
in accordance with a regulation, written
order, Onshore Order, NTL, or COA.
Water-Draining Operations—Data
Collection (43 CFR 3173.6); and
Water-Draining Operations—
Recordkeeping and Records Submission
(43 CFR 3170.7 and 3173.6)
Section 3173.6 requires submission of
information when water is drained from
a production storage tank. The
information is required from the
operator, purchaser, or transporter, as
appropriate. Previously, the operator
was not required to record the volume
of hydrocarbons that are in the tank
before and after water is drained. As a
result, hydrocarbons could be drained
with the water and removed without
proper measurement and accounting,
and without royalties being paid. This
information collection activity assists
the BLM in accurate accounting of oil
and gas produced from Federal and
Indian leases.
The following information is required:
• Federal or Indian lease, unit PA, or
CA number(s);
• The tank location by land
description;
• The unique tank number and
nominal capacity;
• Date for opening gauge;
• Opening gauge of the total oil
volume and free-water measurements;
• Unique identifying number of each
seal removed;
• Closing gauge of the total oil
volume measurement; and
• Unique identifying number of each
seal installed.
Hot Oiling, Clean-Up, and Completion
Operations—Data Collection (43 CFR
3173.7); and
Hot Oiling, Clean-Up, and Completion
Operations—Recordkeeping and
Records Submission (43 CFR 3170.7 and
3173.7)
Section 3173.7 requires the
submission of information during hot
oil, clean-up, or completion operations,
or any other situation where the
operator removes oil from storage,
temporarily uses it for operational
purposes, and then returns it to storage
on the same lease, unit PA, or CA.
Previously, the operator was not
required to record the volume of
hydrocarbons removed from storage
with the expectation that they will be
returned to storage. As a result, the
volume of produced hydrocarbons

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could be counted twice; first when it
was initially produced then later after it
is returned to storage. This information
collection activity assists the BLM in
accurate accounting of oil and gas
produced from Federal and Indian
leases.
The following information is required:
• Federal or Indian lease, unit PA, or
CA number(s);
• The tank location by land
description;
• The unique tank number and
nominal capacity;
• Date of the opening gauge;
• Opening gauge measurement;
• Closing gauge measurement;
• Unique identifying number of each
seal installed;
• How the oil was used; and
• Where the oil was used (i.e., well or
facility name and number).

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Report of Theft or Mishandling of
Production (43 CFR 3173.8)
Section 3173.8 requires operators,
transporters, or purchasers to submit a
report (either oral or written) no later
than the next business day after
discovery of an incident of apparent
theft or mishandling of production. All
oral reports must be followed up with
a written incident report within 10
business days of the oral report. By
applying not only to operators but also
to transporters and purchasers (who
often are the first ones to discover theft
and mishandling or to recognize
suspicious activity), this information
collection activity assists in prompt
disclosure of theft or mishandling. The
incident report must include the
following information:
• Company name and name of the
person reporting the incident;
• Lease, unit PA, or CA number, well
or facility name and number, and FMP
number, as appropriate;
• Land description of the facility
location where the incident occurred;
• The estimated volume of
production removed;
• The manner in which access was
obtained to the production or how the
mishandling occurred;
• The name of the person who
discovered the incident;
• The date and time of the discovery
of the incident; and
• Whether the incident was reported
to local law enforcement agencies and
company security
Required Recordkeeping for Inventory
and Seal Records (43 CFR 3173.9)
Section 3173.9 requires operators to
measure and record within ± 3 days of
the final day of each calendar month an
inventory consisting of TOV in storage

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(less free water). If the inventory is not
taken on the final day of each month, it
must be estimated based on two
measurements no less than 20 days and
no more than 31 days apart, based upon
the prorated difference between these
inventory levels and any sales that have
occurred between the two
measurements. This information
collection activity assists the BLM in
accurate accounting of oil and gas
production.
For each seal, the operator must
maintain a record that includes the
unique identifying number of each seal
and the valve or meter component on
which the seal is or was used; the date
of installation or removal of each seal;
for valves, the position (open or closed)
in which it was sealed; and the reason
the seal was removed.
Site Facility Diagrams for Existing
Facilities (43 CFR 3173.11(d)(2)); and
Site Facility Diagrams for Future
Facilities (43 CFR 3173.11(d)(1))
Section 3173.11 requires a site facility
diagram for all facilities. Section 3170.3
of the final rule defines ‘‘facility’’ as a
site and associated equipment used to:
• Process, treat, store, or measure oil
or gas production from or allocated to a
Federal or Indian lease, unit, or CA that
is located upstream of or at (and
including) the approved point of royalty
measurement; or
• Store, measure, or dispose of
produced water that is located on a
lease, unit, or CA.
A site facility diagram is one of the
BLM’s primary mechanisms for
monitoring operators’ compliance with
measurement regulations and policy.
These information collection activities
enable the BLM to verify, among other
things, royalty-free-use volumes
reported by the operator on its OGORs.
These activities also enhance
production accountability and respond
to key recommendations made by the
GAO and the OIG. In the long term, this
information collection request will
eliminate the need for the BLM to obtain
the information in connection with a
production verification and
accountability review.
Paragraphs (a) through (c) of § 3173.11
require that each site facility diagram be
submitted with a completed Sundry
Notice.13 The diagram itself should be
formatted to fit on an 81⁄2 x 11 sheet of
paper, if possible, and must be legible
and comprehensible to an individual
with an ordinary working knowledge of
oilfield operations. If more than one
13 Form 3160–3, which is approved under OMB
control number 1004–0137 for uses enumerated at
43 CFR 3162.3–2.

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page is required, each page must be
numbered (in the format ‘‘N of X
pages’’). Paragraph (c) specifies that a
site facility diagram must:
• 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, but
need not be to scale;
• Commencing with the header,
identify all of the equipment, including,
but not limited to, the header, wellhead,
piping, tanks, and metering systems
located on the site, and include the
appropriate valves and any other
equipment used in the handling,
conditioning, or disposal of production
and water, and indicate the direction of
flow;
• Identify by API number the wells
flowing into headers;
• Indicate which valve(s) must be
sealed and in what position during the
production and sales phases and during
the conduct of other production
activities (e.g., circulating tanks or
drawing off water), which may be
shown by an attachment, if necessary;
• Clearly identify the lease, unit PA,
or CA to which the diagram applies and
the land description of the facility, and
the name of the company submitting the
diagram, with co-located facilities being
identified for each lease, unit PA, or CA;
and
• Clearly identify as an attachment all
meters and measurement equipment.
Specifically identify all approved and
assigned FMPs.
If another operator operates a colocated facility, the site facility diagram
must depict the co-located facilities on
the diagram or list them on an
attachment and identify them by
company name, facility name(s), lease,
unit PA, or CA number, and FMP
number(s). When describing co-located
facilities operated by one operator, the
site facility diagram must include a
skeleton diagram of the co-located
facility, showing equipment only. For
storage facilities common to co-located
facilities operated by one operator, one
diagram would be sufficient.
If the operator claims royalty-free use,
the site facility diagram must clearly
identify on the diagram or as an
attachment, the equipment for which
the operator claims royalty-free use.
Section 3173.11(d) specifies the
timing requirements for submission of
an updated site facility diagram for
facilities for which the BLM will assign
an FMP number under § 3173.12. This
section applies to both new and existing
facilities.
• For facilities that are in service on
or after the effective date of the final

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mstockstill on DSK3G9T082PROD with RULES3

rule, a site facility diagram must be
submitted within 30 days after the BLM
assigns an FMP number to the facility.
• For facilities that are in service
before the effective date of the final rule
and that have a site facility diagram on
file that meets the minimum
requirements of the previous rule (i.e.,
Order 3), operators must submit a new
site facility diagram within 30 days
after:
Æ Existing facilities are modified;
Æ A non-Federal facility located on a
Federal lease or federally approved unit
or communitized area is constructed or
modified; or
Æ There is a change in operator.
The submitted diagram must comply
with the requirements of paragraphs (a)
through (c) of § 3173.11. Those
requirements are described above.
Section 3173.11(e) specifies the
timing requirements for submission of
an updated site facility diagram for
facilities for which the BLM will not
assign an FMP number under § 3173.12.
This section applies to both new and
existing facilities.
• For facilities that are in service on
or after the effective date of the final
rule, a site facility diagram must be
submitted within 30 days after the BLM
assigns an FMP number to the facility.
• For facilities that are in service
before the effective date of the final rule
and that have a site facility diagram on
file that meets the minimum
requirements of the previous rule (i.e.,
Order 3), operators must submit a new
site facility diagram within 30 days
after:
Æ Existing facilities are modified;
Æ A non-Federal facility located on a
Federal lease or federally approved unit
or communitized area is constructed or
modified; or
Æ There is a change in operator.
Section 3173.11(f) specifies that after
a site facility diagram has been
submitted that complies with the
requirements of § 3173.11, operators
have an ongoing obligation to update
and amend them within 30 days after
such facilities are modified, a nonFederal facility located on a Federal
lease or federally approved unit or
communitized area is constructed or
modified, or there is a change in
operator.
Request for Approval of an FMP for
Existing Measurement Facilities (43 CFR
3173.12(e)); and
Request for Approval of an FMP for
Future Measurement Facilities (43 CFR
3173.12(d))
Section 3173.12 requires operators to
obtain BLM approval of FMPs for all

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measurement points that are used to
determine royalties. An FMP is a BLMapproved point where oil or gas
produced from a Federal or Indian lease,
unit, or CA is measured and the
measurement affects the calculation of
the volume or quality of production on
which royalty is owed. See 43 CFR
3170.3.
This information collection activity
provides the BLM with a formal
nationwide process for designating and
approving the point at which oil or gas
must be measured for the purpose of
determining royalty. This activity assists
the BLM in verifying production. Upon
receiving an initial request for an FMP,
the BLM will approve it if it meets the
requirements of this rule, and assign
each FMP a unique identifying number,
which the operator, transporter, or
purchaser will use when reporting
production results to the Office of
Natural Resources Revenue (ONRR).
All requests for an FMP must include
the following:
• A complete Sundry Notice;
• The applicable Measurement Type
Code specified in the BLM’s Well
Information System (WIS);
• For gas measurement, identification
of the operator/purchaser/transporter
unique station number, meter tube size
or serial number, and type of secondary
device;
• For oil measurement, identification
of the oil tank number(s) or tank serial
number(s) and size of each tank, and
whether the oil was measured by LACT
or CMS if not measured by tank gauge;
• Where production from more than
one well will flow to the requested
FMP, a list of the API well numbers
associated with the FMP; and
• FMP location by land description.
Section 3173.12(d) requires operators
to request a new FMP for new
permanent measurement facilities
before any production leaves the
facility. Each request must meet the
requirements listed above.
Modifications to an FMP (43 CFR
3173.13(b)(1))
Section 3173.13(b)(1) requires
operators with an approved FMP to
submit a Sundry Notice that details any
modifications to the FMP within 30
days after the change. These details
include, but are not limited to, tank
numbers or serial numbers and sizes for
oil FMPs, unique station numbers,
meter tube sizes or serial numbers, and
type of secondary devices for gas FMPs,
and for all FMPs with more than one
well, the API numbers for all wells
associated with the facility. The Sundry
Notice must specify what was changed,
the effective date, and include, if

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appropriate, an amended site facility
diagram. This information collection
activity assists the BLM in accurate
accounting of oil and gas production.
Request for Approval of an Existing
CAA (43 CFR 3173.15); and
Request for Approval of a Future CAA
(43 CFR 3173.15)
A CAA is a formal allocation
agreement to combine production from
two or more sources (leases, unit PAs,
CAs, or non-Federal or non-Indian
properties) before the FMP. See 43 CFR
3173.1. This information collection
activity helps the BLM obtain the
production data that is necessary to
verify production from Federal or
Indian leases covered by CAAs.
Section 3173.15 requires the
following information:
• A completed Sundry Notice seeking
approval of commingling and allocation,
and of off-lease measurement, if any of
the proposed FMPs are outside the
boundaries of any of the leases, units, or
CAs whose production would be
commingled;
• A proposed allocation agreement
and a proposed allocation methodology
with an example of how the
methodology is applied (including
allocation of produced water) signed by
each operator of each of the leases, unit
PAs, or CAs whose production would be
included in the CAA;
• A list of all Federal or Indian lease,
unit PA, or CA numbers in the proposed
CAA, specifying the type of production
(i.e., oil, gas, or both) for which
commingling is requested;
• A topographic map or maps
showing the boundaries of all the leases,
units, unit PAs, or communitized areas
whose production is proposed to be
commingled; the location of all existing
or planned facilities and relative
location of all wellheads and piping
included in the CAA, and FMPs existing
or proposed to be installed to the extent
known or anticipated;
• Documentation demonstrating that
each of the leases, unit PAs, or CAs
proposed for inclusion in the CAA is
producing in paying quantities (or, in
the case of Federal leases, is capable of
production in paying quantities)
pending approval of the CAA; and
• All gas analyses, including Btu
content (if the CAA request includes
gas) and all oil gravities (if the CAA
request includes oil) for previous
periods of production from the leases,
units, unit PAs, or CAs proposed for
inclusion in the CAA, up to 6 years
before the date of the application for
approval of the CAA. However, gas
analysis and oil gravity data is not

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needed if the CAA meets the
requirements and standards of
§ 3173.14(a) of the final rule.
If new surface disturbance is
proposed on one or more of the leases,
units, or CAs, and the surface is
managed by the BLM, the application
must include a proposed surface use
plan of operations for the proposed
surface disturbance.
If new surface disturbance is
proposed on BLM-managed land outside
any of the leases, units, or CAs whose
production would be commingled, the
application must include a right-of-way
grant application, under 43 CFR part
2880 if the FMP is on a pipeline, or
under 43 CFR part 2800, if the FMP is
a meter or storage tank. Applications for
right-of-way (i.e., on SF–299) are
authorized under OMB control number
0596–0082.
If new surface disturbance is
proposed on Federal land managed by
an agency other than the BLM, the
application must include written
approval from the appropriate surfacemanagement agency.
If a new surface disturbance is
proposed on Indian land outside the
lease, unit, or communitized area from
which the production would be
commingled, a right-of-way grant
application must be filed under 25 CFR
part 169, with the appropriate BIA
office.

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Request for Modification of a CAA (43
CFR 3173.18)
Section 3173.18 provides that a CAA
must be modified when there is
modification to the allocation
agreement, additional leases, unit PAs,
or CAs are proposed for inclusion in the
CAA, or any of the leases, unit PAs, or
CAs within the CAA terminate or
permanently cease production. The
following information would be
required in a request to modify a CAA:
• A completed Sundry Notice
describing the modification requested;
• A new allocation methodology, if
appropriate, and an example of how the
methodology is applied; and
• Certification by each operator that it
agrees to the CAA modification.
This information collection activity
helps the BLM obtain the production
data that is necessary to verify
production from Federal or Indian
leases covered by CAAs.
Response to Notice of Insufficient CAA
(43 CFR 3173.16)
Upon receipt of an operator’s request
for assignment of an FMP number to a
facility associated with a CAA existing
on the effective date of the final rule, (1)
The BLM may determine that the CAA

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meets the requirements (at 43 CFR
3173.16) for grandfathering the CAA; or
(2) If grandfathering is not appropriate,
the BLM will review the CAA for
consistency with the minimum
standards and requirements for a CAA
under 43 CFR 3173.14. The BLM will
notify the operator in writing of any
inconsistencies or deficiencies. The
operator must then correct any
inconsistencies or deficiencies that the
AO identifies, provide additional
information, or request an extension of
time, within 20 business days after
receipt of the BLM’s notice. When the
BLM is satisfied that the operator has
corrected any inconsistencies or
deficiencies, the BLM will terminate the
existing CAA and grant a new CAA
based on the operator’s corrections. If
the existing CAA does not meet the
applicable standards and the operator
does not correct the deficiencies, the
BLM may terminate the existing CAA
and deny the request for an FMP
number for the facility associated with
the existing CAA.
Request To Modify a CAA (43 CFR
3173.18)
A CAA must be modified when there
is a modification to the allocation
agreement; additional leases, unit PAs,
or CAs are proposed for inclusion in the
CAA; or any of the leases, unit PAs, or
CAs within the CAA terminate or
permanently cease production.
To request a modification of a CAA,
all operators must submit to the BLM:
• A completed Sundry Notice
describing the modification requested;
• A new allocation methodology,
including an allocation methodology
which includes allocation of produced
water and an example of how the
methodology is applied, if appropriate;
and
• Certification by each operator in the
CAA that it agrees to the CAA
modification.
A change in operator does not trigger
the need to modify a CAA.
Request To Terminate a CAA (43 CFR
3173.20)
Section 3173.20 authorizes the BLM
to terminate an approved CAA and
allows for the CAA to be terminated by
the operator at their request. The
operator must submit a Sundry Notice
to the BLM requesting the termination
in which the notice must identify the
FMP(s) for the lease(s), unit(s), or CA(s)
previously subject to the CAA.

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Request for Approval of Off-Lease
Measurement—General (43 CFR
3173.23);
Request for Approval of Off-Lease
Measurement—Amendment of an
Existing Approval (43 CFR 3173.23);
and
Response to Notice of Insufficient OffLease Measurement Approval (43 CFR
3173.25)
These information collection
activities assist the BLM in reducing
discrepancies between operatorallocated volumes, which operators
report to ONRR, and the volumes that
the BLM calculates during follow-up
audits. In accordance with this final
rule, the BLM will allow off-lease
measurement of production only from a
single Federal or Indian lease, unit PA,
CA, or CAA, and only at an approved
FMP.
Section 3173.23(a) through (j) requires
the following information in an
application for approval of off-lease
measurement:
• A completed Sundry Notice;
• Justification for off-lease
measurement;
• A topographic map of appropriate
scale showing the boundary of the
lease(s), unit(s), or CA(s) from which the
production originates, the location of
existing or planned facilities, the
relative location of all wellheads
(including the API number for each
well) and piping included in the offlease measurement proposal, and
existing FMPs or FMPs proposed to be
installed to the extent known or
anticipated;
• The surface ownership of all land
on which equipment is, or is proposed
to be, located; and
• A statement that indicates whether
the proposal includes all, or only a
portion of, the production from the
lease, unit, or CA and if the proposal
includes only a portion of the
production, the application would be
required to identify the FMP(s) where
the remainder of the production from
the lease, unit, or CA is measured or is
proposed to be measured.
If any of the proposed off-lease
measurement facilities are located on
non-federally owned surface, the
application must include a written
concurrence signed by the owner(s) of
the surface and the owner(s) of the
measurement facilities, including each
owner(s)’ name, address, and telephone
number, granting the BLM unrestricted
access to the off-lease measurement
facility and the surface on which it is
located, for the purpose of inspecting
any production, measurement, water

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handling, or transportation equipment
located on the non-Federal surface up to
and including the FMP, and for
otherwise verifying production
accountability. If the ownership of the
non-Federal surface or of the
measurement facility changes, the
operator must obtain and provide to the
AO the written concurrence required
under this paragraph from the new
owner(s) within 30 days of the change
in ownership.
If a proposed off-lease FMP with
facilities on BLM land would involve
new surface disturbance and consists of
a meter or storage tank, or is on a
pipeline, a right-of-way grant
application must be submitted.
Applications for rights-of-way (SF–299)
are authorized under control number
0596–0082, which is administered by
the U.S. Forest Service on behalf of
several Federal agencies. If new surface
disturbance if proposed for an FMP that
includes facilities on Federal land
managed by an agency other than the
BLM, written approval is required from
that agency. A right-of-way grant
application must also be submitted with
the appropriate BIA office if any of the
proposed facilities are on Indian lands
outside of the producing area.

If the operator proposes to use
production from the lease, unit or CA as
fuel at the off-lease measurement facility
without payment of royalty, the
application must include an application
for approval of off-lease royalty-free use
under applicable rules. The BLM is
developing the applicable rules and will
seek OMB clearance for the information
collection activities in those rules.
Section 3173.23(k) provides that to
apply for an amendment of an existing
approval of off-lease measurement, the
operator must submit a completed
Sundry Notice required under
paragraph (a), and information listed at
paragraphs (b) through (j) of § 3173.23 to
the extent the previously submitted
information has changed. This
information collection activity assists
the BLM in reducing discrepancies
between operator-allocated volumes,
which operators report to ONRR, and
the volumes that the BLM calculates
during follow-up audits.
Upon receipt of an operator’s request
for assignment of an FMP number for a
facility associated with an off-lease
measurement approval existing on the
effective date of the final rule, the BLM
will review the existing approval for
consistency with the requirements at 43
CFR 3173.22. The BLM will notify the

81417

operator of any inconsistencies or
deficiencies. The operator must correct
any of the identified flaws, provide
additional information, or request an
extension of time from the AO, within
20 business days after receiving the
notice. This information collection
activity assists the BLM in reducing
discrepancies between operatorallocated volumes, which operators
report to ONRR, and the volumes that
the BLM calculates during follow-up
audits.
Request To Terminate an Off-Lease
Measurement Approval (43 CFR
3173.27)
Section 3173.27 authorizes the BLM
to terminate an off-lease measurement
approval and allows for the off-lease
measurement approval to also be
terminated by the operator at their
request. The operator must submit a
Sundry Notice to the BLM requesting
the termination in which the notice
must identify the new FMP(s) for the
lease(s), unit(s), or CA(s) previously
subject to the off-lease measurement
approval.
The following table itemizes the
estimated hour and cost burdens for the
information collection activities.

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ESTIMATED HOUR BURDENS
Type of response

Number of
responses

Hours per
response

Total hours
(Column B ×
Column C)

A.

B.

C.

D.

Variance Requests (43 CFR 3170.6) Annual ..............................................................................
Required Recordkeeping and Records Submission (43 CFR 3170.7) Annual ...........................
Water-Draining Operations—Data Collection (43 CFR 3173.6) Annual .....................................
Water-Draining Operations —Recordkeeping and Records Submission (43 CFR 3173.6) Annual ...........................................................................................................................................
Hot Oiling, Clean-Up, and Completion Operations—Data Collection (43 CFR 3173.7) Annual
Hot Oiling, Clean-Up, and Completion Operations—Recordkeeping and Records Submission
(43 CFR 3173.6) Annual ..........................................................................................................
Report of Theft or Mishandling of Production (43 CFR 3173.8) Annual ....................................
Required Recordkeeping for Inventory and Seal Records (43 CFR 3173.9) Annual .................
Site Facility Diagrams for Existing Facilities) (43 CFR 3173.11(d)(2)) One-time .......................
Site Facility Diagrams for Future Facilities (43 CFR 3173.11(d)(1)) Annual ..............................
Request for Approval of an FMP for Existing Measurement Facilities (43 CFR 3173.12(e))
One-time ...................................................................................................................................
Request for Approval of an FMP for Future Measurement Facilities (43 CFR 3173.12(d)) Annual ...........................................................................................................................................
Modifications to an FMP (43 CFR 3173.13(b)(1)) Annual ..........................................................
Request for Approval of an Existing CAA (43 CFR 3173.15) One-time .....................................
Request for Approval of a Future CAA (43 CFR 3173.15) Annual ............................................
Response to Notice of Insufficient CAA (43 CFR 3173.16) Annual ...........................................
Request to Modify a CAA (43 CFR 3173.18) Annual .................................................................
Request for Approval of Off-Lease Measurement—General (43 CFR 3173.23) Annual ...........
Request for Approval of Off-Lease Measurement—Amendment of an Existing Approval (43
CFR 3173.23) One-time ...........................................................................................................
Response to Notice of Insufficient Off-Lease Measurement Approval (43 CFR 3173.25) Annual ...........................................................................................................................................
Totals ....................................................................................................................................

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100
4,300
5,000

8
5
2

800
21,500
10,000

60,000
5,000

0.25
2

15,000
10,000

15,000
5
5,000
4,156
5,000

0.25
10
2
6
6

3,750
50
10,000
24,935
30,000

166,232

2

332,464

1,000
1,000
1,662
500
150
500
100

2
2
40
40
40
40
10

2,000
2,000
66,480
20,000
6,000
20,000
1,000

166

10

1,662

15

40

600

274,886

........................

578,240

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17NOR3

mstockstill on DSK3G9T082PROD with RULES3

81418

Federal Register / Vol. 81, No. 222 / Thursday, November 17, 2016 / Rules and Regulations

National Environmental Policy Act
The BLM prepared an environmental
assessment (EA), a Finding of No
Significant Impact (FONSI), and
Decision Record (DR) that concludes
that the final rule will not constitute a
major Federal action significantly
affecting the quality of the human
environment under Section 102(2)(C) of
the National Environmental Policy Act
(NEPA), 42 U.S.C. 4332(2)(C). Therefore,
a detailed statement under NEPA is not
required. A copy of the EA, FONSI, and
DR are available for review and on file
in the BLM Administrative Record at
the address specified in the ADDRESSES
section.
As explained in the EA, FONSI, and
DR, the final rule will not have a
significant effect on the human
environment because, for the most part,
its requirements involve changes that
are of an administrative, technical, or
procedural nature that apply to the
BLM’s and the lessee’s or operator’s
management processes. For example,
operators are now required to maintain
records generated for Federal leases for
at least 7 years, consistent with statutory
requirements. Similarly, the final rule
requires more detailed information on
site facility diagrams such as
information about the equipment for
which an operator claims royalty-free
use. The submission of this additional
information will not result in any onthe-ground impacts. In contrast with
these provisions, compliance with some
of the rule’s other requirements may
result in additional surface-disturbing
activities (e.g., additional surface
disturbance might be required if an
operator with an existing off lease
measurement authorization has to move
those measurement facilities back on
lease because they did not comply with
the requirements of this final rule.) Such
surface-disturbing activities will be
subject to their own project-specific
NEPA analyses, as appropriate, and will
be conducted in accordance with
existing surface operating standards and
guidelines for oil and gas exploration
and development, including appropriate
Best Management Practices (BMP).
A draft of the EA was shared with the
public during the public comment
period on the proposed rule. During that
process the BLM received a handful of
comments on the EA. Some commenters
questioned the BLM’s level of NEPA
analysis, specifically whether the BLM
had met the ‘‘hard look’’ test of
describing the environmental
consequences of the proposed action,
and the BLM’s ability to reach a FONSI
based on the level of analysis prepared.
One commenter requested a complete

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NEPA revision with formal scoping on
the EA and a meaningful socioeconomic
analysis. Many commenters questioned
the use of three separate EAs to disclose
impacts of three separate orders. Those
commenters asserted that CEQ
regulations require connected actions to
be evaluated in a single document and
suggested a single EIS to address all
three rules.
CEQ’s NEPA regulations at 40 CFR
1508.18 identify new or revised agency
rules and regulations as an example of
a Federal action. Drafting new agency
regulations of a technical or
administrative nature is a Federal action
that is categorically excluded from
NEPA review pursuant to 43 CFR
46.210(i). Instead of relying on the
categorical exclusion, the BLM chose to
complete a more robust level of NEPA
documentation in the form of an EA for
each of the proposed rules to replace
Orders 3, 4, and 5. By preparing an EA
for each of the proposed regulations, the
BLM was able to disclose the potential
environmental effects of the Federal
agency decision on each of the
regulations. This analysis addressed the
impact of each rule individually, as well
as the impact of all three rules
cumulatively. With respect to socioeconomic impacts, the BLM completed
an Economic and Threshold Analyses
for each of the rules. These analyses
were not referenced in the Draft EAs for
the rules, but have been addressed in
the EAs for the final rules.
Other commenters stated that the
BLM understated the potential surface
impacts associated with the new rules
and did not: (i) Adequately address
potential surface impacts to private
land; (ii) Address a reasonable range of
alternatives; and (iii) Adequately
describe the affected environment. As
explained in the EA, the BLM
anticipates that in the majority of cases,
operators will use existing surface
disturbances such as existing well pad
locations in connection with activities
undertaken in compliance with the final
rule, which will minimize new surface
construction and surface impacts.
Similarly, the codification of BLM
regulations does not hinder or prevent
development of private minerals. The
likelihood of impacts to private surface
is low. It is unclear whether private
lands would be affected at all by the
denial of off-lease measurement
agreements and the resultant re-location
of measurement facilities on to a lease,
CA or unit PA. In the rare instances
when new pipelines or other facilities
were found to be necessary on private
surface, BLM authorization for activities
on split estate would include sitespecific NEPA documentation, with

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appropriate project-level mitigation and
BMPs. In short, the impact of these
provisions on private lands in terms of
surface disturbance is likely to be
minimal, and any attempt to estimate
these impacts would be speculative.
The BLM’s obligation under NEPA is
to analyze alternatives that would meet
the purpose and need for the proposed
action and allow for a reasoned choice
to be made. As described in the EA, a
number of alternatives were considered,
but eliminated from detailed study
because they did not meet the purpose
and need. Similarly, the discussion of
the affected environment should only
contain data and analysis commensurate
in detail with the importance of the
impacts, which the BLM anticipates to
be minimal. The EA, FONSI, and DR
were updated to address these
comments, but did not change the
BLM’s overall analysis of the potential
environmental impacts of the rule.
Executive Order 13211, Actions
Concerning Regulations That
Significantly Affect Energy Supply,
Distribution, or Use
This final rule will not have a
substantial direct effect on the nation’s
energy supply, distribution or use,
including a shortfall in supply or price
increase. The final rule strengthens the
BLM’s production accountability
requirements for operators of Federal
and Indian oil and gas leases. These
changes increase recordkeeping
requirements, place additional
restrictions on CAAs and on off-lease
measurement, and provide for
significant new immediate assessments
for violations of the regulations. All of
these changes in the final rule are
administrative in nature and will have
a one-time average transition cost of
about $8,400 per regulated entity and an
ongoing annual average cost of about
$3,200 per entity per year. Entities with
the greatest activity (e.g., numerous
FMPs) will incur higher costs, but they
will still be relatively minor. As a result,
the BLM does not expect that the final
rule will result in a net change in the
quantity of oil and gas that is produced
from oil and gas leases on Federal and
Indian lands.
Information Quality Act
In developing this rule, the BLM did
not conduct or use a study, experiment,
or survey requiring peer review under
the Information Quality Act (Pub. L.
106–554, Appendix C Title IV, 515, 114
Stat. 2763A–153).
Authors
The principal authors of this final rule
are Michael Wade, Senior Oil and Gas

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Federal Register / Vol. 81, No. 222 / Thursday, November 17, 2016 / Rules and Regulations
Compliance Specialist, BLM
Washington Office; Adrienne Brumley,
Petroleum Engineer, BLM New Mexico
State Office; Conan Donnelly, Petroleum
Engineering Technician, BLM Miles
City Field office; Kahindo Kamau,
Petroleum Engineer, BLM Great Falls
Field Office; Steve McCracken,
Petroleum Engineering Technician,
BLM Great Falls Field Office; Chris
Carey, ONRR Denver Office; Luke
Lundmark, ONRR Denver Office; and
Vicky Stafford, ONRR Denver Office.
The team was assisted by Rich
Estabrook, BLM Washington Office;
Faith Bremner, Jean Sonneman and Ian
Senio, Office of Regulatory Affairs, BLM
Washington Office; Michael Ford,
Economist, BLM Washington Office;
Barbara Sterling, Natural Resource
Specialist, BLM Colorado State Office;
Bryce Barlan, Senior Policy Analyst,
BLM Washington Office; and Dylan
Fuge, Counselor to the Director, BLM
Washington Office; Christopher
Rhymes, Attorney Advisor, Office of the
Solicitor, Department of the Interior;
and Leslie Peterson and Geoffrey Heath
(both now retired).
List of Subjects
43 CFR Part 3160
Administrative practice and
procedure, Government contracts,
Indians-lands, Mineral royalties, Oil and
gas exploration, Penalties, Public
lands—mineral resources, Reporting
and recordkeeping requirements.
43 CFR Part 3170
Administrative practice and
procedure, Immediate assessments,
Incorporation by reference, Indianslands, Mineral royalties, Oil and gas
measurement, Public lands—mineral
resources.
Dated: October 6, 2016.
Janice M. Schneider,
Assistant Secretary, Land and Minerals
Management.

1. Revise the authority citation for part
3160 to read as follows:

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■

Authority: 25 U.S.C. 396, 396d and 2107;
30 U.S.C. 189, 306, 359, and 1751; and 43
U.S.C. 1732(b), 1733, and 1740.
[Amended]

2. Amend § 3160.0–3 by removing the
words ‘‘the Federal Oil and Gas Royalty
Management Act of 1982 (30

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Jurisdiction.

(a) The regulations in this part apply
to all operations conducted on:
(1) All Federal and Indian (except
those of the Osage Tribe) onshore oil
and gas leases;
(2) All onshore facility measurement
points where Federal or Indian (except
those of the Osage Tribe) oil or gas is
measured;
(3) Indian Mineral Development Act
agreements for oil and gas, unless
specifically excluded in the agreement;
and
(4) Leases and other business
agreements for the development of tribal
energy resources under a Tribal Energy
Resource Agreement entered into with
the Secretary, unless specifically
excluded in the lease, other business
agreement, or Tribal Energy Resource
Agreement.
(b) The regulations in this part and 43
CFR part 3170, including subparts 3173,
3174, and 3175, relating to site security,
measurement of oil and gas, reporting of
production and operations, and
assessments or penalties for noncompliance with such requirements, are
applicable to all wells and facilities on
State or privately owned lands
committed to a unit or communitization
agreement, which include Federal or
Indian lease interests, notwithstanding
any provision of a unit or
communitization agreement to the
contrary.
■ 4. Amend § 3162.3–2 by adding
paragraph (d) to read as follows:
Subsequent well operations.

*

PART 3160—ONSHORE OIL AND GAS
OPERATIONS

■

§ 3161.1

§ 3162.3–2

For the reasons set out in the
preamble, the Bureau of Land
Management amends 43 CFR chapter II
as follows:

§ 3160.0–3

U.S.C.1701)’’ and adding in their place
the words ‘‘the Federal Oil and Gas
Royalty Management Act of 1982, as
amended by the Federal Oil and Gas
Royalty Simplification Act of 1996 (30
U.S.C. 1701 et seq.)’’.
■ 3. Revise § 3161.1 to read as follows:

*
*
*
*
(d) For details on how to apply for
approval of a facility measurement
point; approval for surface or subsurface
commingling from different leases, unit
participating areas and communitized
areas; or approval for off-lease
measurement, see 43 CFR 3173.12,
3173.15, and 3173.23, respectively.
■ 5. Amend § 3162.4–1 by revising
paragraphs (a) and (d) and adding
paragraph (e) to read as follows:
§ 3162.4–1

Well records and reports.

(a) The operator must keep accurate
and complete records with respect to:
(1) All lease operations, including, but
not limited to, drilling, producing,
redrilling, repairing, plugging back, and
abandonment operations;

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81419

(2) Production facilities and
equipment (including schematic
diagrams as required by applicable
orders and notices); and
(3) Determining and verifying the
quantity, quality, and disposition of
production from or allocable to Federal
or Indian leases (including source
records).
*
*
*
*
*
(d) All records and reports required
by this section must be maintained for
the following time periods:
(1) For Federal leases and units or
communitized areas that include
Federal leases, but do not include
Indian leases:
(i) Seven years after the records are
generated; unless,
(ii) A judicial proceeding or demand
involving such records is timely
commenced, in which case the record
holder must maintain such records until
the final nonappealable decision in such
judicial proceeding is made, or with
respect to that demand is rendered,
unless the Secretary or the applicable
delegated State authorizes in writing an
earlier release of the requirement to
maintain such records.
(2) For Indian leases, and units or
communitized areas that include Indian
leases, but do not include Federal
leases:
(i) Six years after the records are
generated; unless,
(ii) The Secretary or his/her designee
notifies the record holder that the
Department has initiated or is
participating in an audit or investigation
involving such records, in which case
the record holder must maintain such
records until the Secretary or his/her
designee releases the record holder from
the obligation to maintain the records.
(3) For units and communitized areas
that include both Federal and Indian
leases, 6 years after the records are
generated, unless the Secretary or his/
her designee has notified the record
holder within those 6 years that an audit
or investigation involving such records
has been initiated, then:
(i) If a judicial proceeding or demand
is commenced within 7 years after the
records are generated, the record holder
must retain all records regarding
production from the lease, unit or
communitization agreement until the
final nonappealable decision in such
judicial proceeding is made, or with
respect to that demand is rendered,
unless the Secretary or his/her designee
authorizes in writing a release of the
requirement to maintain such records
before a final nonappealable decision is
made or rendered;
(ii) If a judicial proceeding or demand
is not commenced within 7 years after

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Federal Register / Vol. 81, No. 222 / Thursday, November 17, 2016 / Rules and Regulations

the records are generated, the record
holder must retain all records regarding
production from the unit or
communitized area until the Secretary
or his/her designee releases the record
holder from the obligation to maintain
the records.
(e) Record holders include lessees,
operators, purchasers, transporters, and
any other person directly involved in
producing, transporting, purchasing, or
selling, including measuring, oil or gas
through the point of royalty
measurement or the point of first sale,
whichever is later. Record holders must
maintain records generated during or for
the period for which the lessee or
operator has an interest in or conducted
operations on the lease, or in which a
person is involved in transporting,
purchasing, or selling production from
the lease, for the period of time required
in paragraph (d) of this section.
§ 3162.4–3

[Removed]

6. Remove § 3162.4–3.
■ 7. Amend § 3162.6 as follows:
■ a. In paragraph (a), remove the word
‘‘indentification’’ and add in its place
‘‘identification’’; and
■ b. Revise paragraphs (b) and (c),
redesignate paragraph (d) as paragraph
(e), and add a new paragraph (d).
The revisions and addition read as
follows:
■

§ 3162.6

Well and facility identification.

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*

*
*
*
*
(b) For wells located on Federal and
Indian lands, the operator must properly
identify, by a sign in a conspicuous
place, each well, other than those
permanently abandoned. The well sign
must include the well number, the name
of the operator, the lease serial number,
and the surveyed location (the quarterquarter section, section, township and
range or other authorized survey
designation acceptable to the authorized
officer, such as metes and bounds or
longitude and latitude). When
specifically requested by the authorized
officer, the sign must include the unit or
communitization agreement name or
number. The authorized officer may also
require the sign to include the name of
the Indian allottee lessor(s) preceding
the lease serial number.
(c) All facilities at which oil or gas
produced from a Federal or Indian lease
is stored, measured, or processed must
be clearly identified with a sign that
contains the name of the operator, the
lease serial number or communitization
or unit agreement identification
number, as appropriate, and the
surveyed location (the quarter-quarter
section, section, township and range or
other authorized survey designation

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acceptable to the authorized officer,
such as metes and bounds or longitude
and latitude). On Indian leases, the sign
also must include the name of the
appropriate tribe and whether the lease
is tribal or allotted. For situations of one
tank battery servicing one well in the
same location, the requirements of this
paragraph and paragraph (b) of this
section may be met by one sign as long
as it includes the information required
by both paragraphs. In addition, each
storage tank must be clearly identified
by a unique number. With regard to the
quarter-quarter designation and the
unique tank number, any such
designation established by State law or
regulation satisfies this requirement.
(d) All signs must be maintained in
legible condition and must be clearly
apparent to any person at or
approaching the storage, measurement,
or transportation point.
*
*
*
*
*
§ 3162.7–1

[Amended]

8. Amend § 3162.7–1 by removing
paragraph (f).

■

§ 3162.7–5

[Removed]

9. Remove § 3162.7–5.
■ 10. Amend § 3163.2 by:
■ a. Revising paragraphs (a), (b), (d), (e)
introductory text, and (f) introductory
text;
■ b. Removing paragraph (g);
■ c. Redesignating paragraphs (h) and (i)
as paragraphs (g) and (h);
■ d. Revising newly redesignated
paragraphs (g) and (h); and
■ e. Removing paragraphs (j) and (k).
The revisions read as follows:
■

§ 3163.2

Civil penalties.

(a)(1) Whenever any person fails or
refuses to comply with any applicable
requirements of the Federal Oil and Gas
Royalty Management Act, any mineral
leasing law, any regulation thereunder,
or the terms of any lease or permit
issued thereunder, the authorized
officer will notify the person in writing
of the violation, unless the violation was
discovered and reported to the
authorized officer by the liable person
or the notice was previously issued
under § 3163.1.
(2) Whenever a purchaser or
transporter who is not an operating
rights owner or operator fails or refuses
to comply with 30 U.S.C. 1713 or
applicable rules or regulations regarding
records relevant to determining the
quality, quantity, and disposition of oil
or gas produced from or allocable to a
Federal or Indian oil and gas lease, the
authorized officer will notify the
purchaser or transporter, as appropriate,
in writing of the violation.

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(b)(1) If the violation specified in
paragraph (a) of this section is not
corrected within 20 days of such notice
or report, or such longer time as the
authorized officer may agree to in
writing, the person will be liable for a
civil penalty of up to $1,031 per
violation for each day such violation
continues, dating from the date of such
notice or report. Any amount imposed
and paid as assessments under
§ 3163.1(a)(1) will be deducted from
penalties under this section.
(2) If the violation specified in
paragraph (a) of this section is not
corrected within 40 days of such notice
or report, or a longer period as the
authorized officer may agree to in
writing, the person will be liable for a
civil penalty of up to $10,314 per
violation for each day the violation
continues, dating from the date of such
notice or report. Any amount imposed
and paid as assessments under
§ 3163.1(a)(1) will be deducted from
penalties under this section.
*
*
*
*
*
(d) Whenever a transporter fails to
permit inspection for proper
documentation by any authorized
representative, as provided in § 3162.7–
1(c) of this chapter, the transporter is
liable for a civil penalty of up to $1,031
per day for the violation, dating from
the date of notice of the failure to permit
inspection and continuing until the
proper documentation is provided. If
the violation continues beyond 20 days,
the authorized officer will revoke the
transporter’s authority to remove crude
oil produced from, or allocated to, any
Federal or Indian lease under the
authority of that authorized officer. This
revocation of the transporter’s authority
will continue until the transporter
provides proper documentation and
pays any related penalty.
(e) Any person is liable for a civil
penalty of up to $20,628 per violation
for each day such violation continues, if
the person:
*
*
*
*
*
(f) Any person is liable for a civil
penalty of up to $51,570 per violation
for each day such violation continues, if
the person:
*
*
*
*
*
(g) On a case-by-case basis, the
Secretary may compromise or reduce
civil penalties under this section. In
compromising or reducing the amount
of a civil penalty, the Secretary will
state on the record the reasons for such
determination.
(h) Civil penalties provided by this
section are supplemental to, and not in
derogation of, any other penalties or
assessments for noncompliance in any

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Federal Register / Vol. 81, No. 222 / Thursday, November 17, 2016 / Rules and Regulations
other provision of law, except as
provided in paragraphs (a) and (b) of
this section.
§ 3164.1

[Amended]

11. Amend § 3164.1, in paragraph (b),
by removing the third entry in the table
(the reference to Order No. 3, Site
Security).
■ 12. Amend § 3165.3 by revising
paragraphs (a) and (d) to read as follows:
■

mstockstill on DSK3G9T082PROD with RULES3

§ 3165.3 Notice, State Director review and
hearing on the record.

(a) Notice. (1) Whenever any person
fails to comply with any provisions of
the lease, the regulations in this part,
applicable orders or notices, or any
other appropriate order of the
authorized officer, the authorized officer
will issue a written notice or order to
the appropriate party and the lessee(s)
to remedy any defaults or violations.
(2) Whenever any purchaser or
transporter, who is not an operating
rights owner or operator, fails or refuses
to comply with 30 U.S.C. 1713 or
applicable rules or regulations regarding
records relevant to determining the
quality, quantity, and disposition of oil
or gas produced from or allocable to a
Federal or Indian oil and gas lease,
applicable orders or notices, or any
other appropriate orders of the
authorized officer, the authorized officer
will give written notice or order to the
purchaser or transporter to remedy any
violations.
(3) Written orders or a notice of
violation, assessment, or proposed
penalty will be issued and served by
personal service by the authorized
officer, or by certified mail, return
receipt requested. Service will be
deemed to occur when the document is
received or 7 business days after the
date it is mailed, whichever is earlier.
(4) Any person may designate a
representative to receive any notice of
violation, order, assessment, or
proposed penalty on that person’s
behalf.
(5) In the case of a major violation, the
authorized officer will make a good faith
effort to contact such designated
representative by telephone, to be
followed by a written notice or order.
Receipt of a notice or order will be
deemed to occur at the time of such
verbal communication, and the time of
notice and the name of the receiving
party will be documented in the file. If
the good faith effort to contact the
designated representative is
unsuccessful, notice of the major
violation or order may be given to any
person conducting or supervising
operations subject to the regulations in
this part.

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(6) In the case of a minor violation,
the authorized officer will only provide
a written notice or order to the
designated representative.
(7) A copy of all orders, notices, or
instructions served on any contractor or
field employee or designated
representative will also be mailed to the
operator. Any notice involving a civil
penalty against an operator will be
mailed to the operator, with a copy to
the operating rights owner.
*
*
*
*
*
(d) Action on request for State
Director review. The State Director will
issue a final decision within 10 business
days after the receipt of a complete
request for administrative review or,
where oral presentation has been made,
within 10 business days after the oral
presentation. The State Director’s
decision represents the final Bureau
decision from which further review may
be obtained as provided in paragraph (c)
of this section for proposed penalties,
and in § 3165.4 for all other decisions.
*
*
*
*
*
■ 13. Add part 3170 to read as follows:
PART 3170—ONSHORE OIL AND GAS
PRODUCTION
Subpart 3170—Onshore Oil and Gas
Production: General
Sec.
3170.1 Authority.
3170.2 Scope.
3170.3 Definitions and acronyms.
3170.4 Prohibitions against by-pass and
tampering.
3170.5 [Reserved]
3170.6 Variances.
3170.7 Required recordkeeping, records
retention, and records submission.
3170.8 Appeal procedures.
3170.9 Enforcement.
Subpart 3171—[Reserved]
Subpart 3172—[Reserved]
Subpart 3173—Requirements for Site
Security and Production Handling
3173.1 Definitions and acronyms.
3173.2 Storage and sales facilities—seals.
3173.3 Oil measurement system
components—seals.
3173.4 Federal seals.
3173.5 Removing production from tanks for
sale and transportation by truck.
3173.6 Water-draining operations.
3173.7 Hot oiling, clean-up, and completion
operations.
3173.8 Report of theft or mishandling of
production.
3173.9 Required recordkeeping for
inventory and seal records.
3173.10 Form 3160–5, Sundry Notices and
Reports on Wells.
3173.11 Site facility diagram.
3173.12 Applying for a facility
measurement point.
3173.13 Requirements for approved facility
measurement points.

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3173.14 Conditions for commingling and
allocation approval (surface and
downhole).
3173.15 Applying for a commingling and
allocation approval.
3173.16 Existing commingling and
allocation approvals.
3173.17 Relationship of a commingling and
allocation approval to royalty-free use of
production.
3173.18 Modification of a commingling and
allocation approval.
3173.19 Effective date of a commingling
and allocation approval.
3173.20 Terminating a commingling and
allocation approval.
3173.21 Combining production downhole
in certain circumstances.
3173.22 Requirements for off-lease
measurement.
3173.23 Applying for off-lease
measurement.
3173.24 Effective date of an off-lease
measurement approval.
3173.25 Existing approved off-lease
measurement.
3173.26 Relationship of off-lease
measurement approval to royalty-free
use of production.
3173.27 Termination of off-lease
measurement approval.
3173.28 Instances not constituting off-lease
measurement, for which no approval is
required.
3173.29 Immediate assessments for certain
violations.
Appendix A to Subpart 3173—Examples of
Site Facility Diagrams
Authority: 25 U.S.C. 396d and 2107; 30
U.S.C. 189, 306, 359, and 1751; and 43 U.S.C.
1732(b), 1733, and 1740.

Subpart 3170—Onshore Oil and Gas
Production: General
§ 3170.1

Authority.

The authorities for promulgating the
regulations in this part are the Mineral
Leasing Act, 30 U.S.C. 181 et seq.; the
Mineral Leasing Act for Acquired
Lands, 30 U.S.C. 351 et seq.; the Federal
Oil and Gas Royalty Management Act,
30 U.S.C. 1701 et seq.; the Indian
Mineral Leasing Act, 25 U.S.C. 396a et
seq.; the Act of March 3, 1909, 25 U.S.C.
396; the Indian Mineral Development
Act, 25 U.S.C. 2101 et seq.; and the
Federal Land Policy and Management
Act, 43 U.S.C. 1701 et seq. Each of these
statutes gives the Secretary the authority
to promulgate necessary and
appropriate rules and regulations
governing Federal and Indian (except
Osage Tribe) oil and gas leases. See 30
U.S.C. 189; 30 U.S.C. 359; 25 U.S.C.
396d; 25 U.S.C. 396; 25 U.S.C. 2107; and
43 U.S.C. 1740. Under Secretarial Order
Number 3087, dated December 3, 1982,
as amended on February 7, 1983 (48 FR
8983), and the Departmental Manual
(235 DM 1.1), the Secretary has
delegated regulatory authority over
onshore oil and gas development on

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Federal and Indian (except Osage Tribe)
lands to the BLM. For Indian leases, the
delegation of authority to the BLM is
reflected in 25 CFR parts 211, 212, 213,
225, and 227. In addition, as authorized
by 43 U.S.C. 1731(a), the Secretary has
delegated to the BLM regulatory
responsibility for oil and gas operations
on Indian lands. 235 DM 1.1.K.
§ 3170.2

Scope.

The regulations in this part apply to:
(a) All Federal onshore and Indian oil
and gas leases (other than those of the
Osage Tribe);
(b) Indian Mineral Development Act
(IMDA) agreements for oil and gas,
unless specifically excluded in the
agreement or unless the relevant
provisions of the rule are inconsistent
with the agreement;
(c) Leases and other business
agreements for the development of tribal
energy resources under a Tribal Energy
Resource Agreement entered into with
the Secretary, unless specifically
excluded in the lease, other business
agreement, or Tribal Energy Resource
Agreement;
(d) State or private tracts committed
to a federally approved unit or
communitization agreement (CA) as
defined by or established under 43 CFR
subpart 3105 or 43 CFR part 3180; and
(e) All onshore facility measurement
points where oil or gas produced from
the leases or agreements identified
earlier in this section is measured.

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§ 3170.3

Definitions and acronyms.

(a) As used in this part, the term:
Allocated or allocation means a
method or process by which production
is measured at a central point and
apportioned to the individual lease, or
unit Participating Area (PA), or CA from
which the production originated.
API (followed by a number) means the
American Petroleum Institute Manual of
Petroleum Measurement Standards,
with the number referring to the Chapter
and Section in that manual.
Audit trail means all source records
necessary to verify and recalculate the
volume and quality of oil or gas
production measured at a facility
measurement point (FMP) and reported
to the Office of Natural Resources
Revenue (ONRR).
Authorized officer (AO) has the same
meaning as defined in 43 CFR 3000.0–
5.
Averaging period means the previous
12 months or the life of the meter,
whichever is shorter. For FMPs that
measure production from a newly
drilled well, the averaging period
excludes production from that well that
occurred in or before the first full month

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of production. (For example, if an oil
FMP and a gas FMP were installed to
measure only the production from a
new well that first produced on April
10, the averaging period for this FMP
would not include the production that
occurred in April (partial month) and
May (full month) of that year.)
Bias means a shift in the mean value
of a set of measurements away from the
true value of what is being measured.
By-pass means any piping or other
arrangement around or avoiding a meter
or other measuring device or method (or
component thereof) at an FMP that
allows oil or gas to flow without
measurement. Equipment that permits
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 considered to be a by-pass.
Commingling, for production
accounting and reporting purposes,
means combining, before the point of
royalty measurement, production from
more than one lease, unit PA, or CA, or
production from one or more leases,
unit PAs, or CAs with production from
State, local governmental, or private
properties that are outside the
boundaries of those leases, unit PAs, or
CAs. Combining production from
multiple wells within a single lease,
unit PA, or CA, or combining
production downhole from different
geologic formations within the same
lease, unit PA, or CA, is not considered
commingling for production accounting
purposes.
Communitized area means the area
committed to a BLM approved
communitization agreement.
Communitization agreement (CA)
means an agreement to combine a lease
or a portion of a lease that cannot
otherwise be independently developed
and operated in conformity with an
established well spacing or well
development program, with other tracts
for purposes of cooperative
development and operations.
Condition of Approval (COA) means a
site-specific requirement included in
the approval of an application that may
limit or modify the specific actions
covered by the application. Conditions
of approval may minimize, mitigate, or
prevent impacts to public lands or
resources.
Days means consecutive calendar
days, unless otherwise indicated.
Facility means:
(i) A site and associated equipment
used to process, treat, store, or measure
production from or allocated to a
Federal or Indian lease, unit PA, or CA
that is located upstream of or at (and
including) the approved point of royalty
measurement; and

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(ii) A site and associated equipment
used to store, measure, or dispose of
produced water that is located on a
lease, unit, or communitized area.
Facility measurement point (FMP)
means a BLM-approved point where oil
or gas produced from a Federal or
Indian lease, unit PA, or CA is measured
and the measurement affects the
calculation of the volume or quality of
production on which royalty is owed.
FMP includes, but is not limited to, the
approved point of royalty measurement
and measurement points relevant to
determining the allocation of
production to Federal or Indian leases,
unit PAs, or CAs. However, allocation
facilities that are part of a commingling
and allocation approval under § 3173.15
or that are part of a commingling and
allocation approval approved after July
9, 2013, are not FMPs. An FMP also
includes a meter or measurement
facility used in the determination of the
volume or quality of royalty-bearing oil
or gas produced before BLM approval of
an FMP under § 3173.12. An FMP must
be located on the lease, unit, or
communitized area unless the BLM
approves measurement off the lease,
unit, or CA. The BLM will not approve
a gas processing plant tailgate meter
located off the lease, unit, or CA, as an
FMP.
Gas means any fluid, either
combustible or noncombustible,
hydrocarbon or non-hydrocarbon, that
has neither independent shape nor
volume, but tends to expand
indefinitely and exists in a gaseous state
under metered temperature and
pressure conditions.
Incident of Noncompliance (INC)
means documentation that the BLM
issues that identifies violations and
notifies the recipient of the notice of
required corrective actions.
Lease has the same meaning as
defined in 43 CFR 3160.0–5.
Lessee has the same meaning as
defined in 43 CFR 3160.0–5.
NIST traceable means an unbroken
and documented chain of comparisons
relating measurements from field or
laboratory instruments to a known
standard maintained by the National
Institute of Standards and Technology
(NIST).
Notice to lessees and operators (NTL)
has the same meaning as defined in 43
CFR 3160.0–5.
Off-lease measurement means
measurement at an FMP that is not
located on the lease, unit, or
communitized area from which the
production came.
Oil means a mixture of hydrocarbons
that exists in the liquid phase at the
temperature and pressure at which it is

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measured. Condensate is considered to
be oil for purposes of this part. Gas
liquids extracted from a gas stream
upstream of the approved point of
royalty measurement are considered to
be oil for purposes of this part.
(i) Clean oil or Pipeline oil means oil
that is of such quality that it is
acceptable to normal purchasers.
(ii) 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 that can be
economically provided at existing or
modified facilities or using portable
equipment at or upstream of the FMP is
not slop oil.
(iii) Waste oil means oil that has been
determined by the AO or authorized
representative to be 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 been determined by
the AO to have no economic value.
Operator has the same meaning as
defined in 43 CFR 3160.0–5.
Participating area (PA) has the same
meaning as defined in 43 CFR 3180.0–
5.
Point of royalty measurement means a
BLM-approved FMP at which the
volume and quality of oil or gas which
is subject to royalty is measured. The
point of royalty measurement is to be
distinguished from meters that
determine only the allocation of
production to particular leases, unit
PAs, CAs, or non-Federal and nonIndian properties. The point of royalty
measurement is also known as the point
of royalty settlement.
Production means oil or gas removed
from a well bore and any products
derived therefrom.
Production Measurement Team (PMT)
means a panel of members from the
BLM (which may include BLMcontracted experts) that reviews changes
in industry measurement technology,
methods, and standards to determine
whether regulations should be updated,
and provides guidance on measurement
technologies and methods not addressed
in current regulation. The purpose of
the PMT is to act as a central advisory
body to ensure that oil and gas
produced from Federal and Indian
leases is accurately measured and
properly reported.
Purchaser means any person or entity
who legally takes ownership of oil or
gas in exchange for financial or other
consideration.
Source record means any unedited
and original record, document, or data

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that is used to determine volume and
quality of production, regardless of
format or how it was created or stored
(e.g., paper or electronic). It 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; measurement tickets;
calibration, verification, prover, and
configuration reports; pumper and
gauger field logs; volume statements;
event logs; seal records; and gas
analyses.
Statistically significant describes a
difference between two data sets that
exceeds the threshold of significance.
Tampering means any deliberate
adjustment or alteration to a meter or
measurement device, appropriate valve,
or measurement process that could
introduce bias into the measurement or
affect the BLM’s ability to
independently verify volumes or
qualities reported.
Threshold of significance means the
maximum difference between two data
sets (a and b) that can be attributed to
uncertainty effects. The threshold of
significance is determined 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

Total observed volume (TOV) means
the total measured volume of all oil,
sludges, sediment and water, and free
water at the measured or observed
temperature and pressure.
Transporter means any person or
entity who legally moves or transports
oil or gas from an FMP.
Uncertainty means the statistical
range of error that can be expected
between a measured value and the true
value of what is being measured.
Uncertainty is determined at a 95
percent confidence level for the
purposes of this part.
Unit means the land within a unit
area as defined in 43 CFR 3180.0–5.
Unit PA means the unit participating
area, if one is in effect, the exploratory
unit if there is no associated
participating area, or an enhanced
recovery unit.
Variance means an approved
alternative to a provision or standard of
a regulation, Onshore Oil and Gas
Order, or NTL.
(b) As used in this part, the following
additional acronyms apply:
API means American Petroleum
Institute.

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BLM means the Bureau of Land
Management.
Btu means British thermal unit.
CMS means Coriolis Measurement
System.
LACT means lease automatic custody
transfer.
OGOR means Oil and Gas Operations
Report (Form ONRR–4054 or any
successor report).
ONRR means the Office of Natural
Resources Revenue, U.S. Department of
the Interior, and includes any successor
agency.
S&W means sediment and water.
WIS means Well Information System
or any successor electronic filing
system.
§ 3170.4 Prohibitions against by-pass and
tampering.

(a) All by-passes are prohibited.
(b) Tampering with any measurement
device, component of a measurement
device, or measurement process is
prohibited.
(c) Any by-pass or tampering with a
measurement device, component of a
measurement device, or measurement
process may, together with any other
remedies provided by law, result in an
assessment of civil penalties for
knowingly or willfully:
(1) Taking, removing, transporting,
using, or diverting oil or gas from a lease
site without valid legal authority under
30 U.S.C. 1719(d)(2) and 43 CFR
3163.2(f)(2); or
(2) Preparing, maintaining, or
submitting false, inaccurate, or
misleading reports, records, or
information under 30 U.S.C. 1719(d)(1)
and 43 CFR 3163.2(f)(1).
§ 3170.5

[Reserved]

§ 3170.6

Variances.

(a) Any party subject to a requirement
of a regulation in this part may request
a variance from that requirement.
(1) A request for a variance must
include the following:
(i) Identification of the specific
requirement from which the variance is
requested;
(ii) Identification of the length of time
for which the variance is requested, if
applicable;
(iii) An explanation of the need for
the variance;
(iv) A detailed description of the
proposed alternative means of
compliance;
(v) A showing that the proposed
alternative means of compliance will
produce a result that meets or exceeds
the objectives of the applicable
requirement for which the variance is
requested; and
(vi) The FMP number(s) for which the
variance is requested, if applicable.

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(2) A request for a variance must be
submitted as a separate document from
any plans or applications. A request for
a variance that is submitted as part of a
master development plan, application
for permit to drill, right-of-way
application, or application for approval
of other types of operations, rather than
submitted separately, will not be
considered. Approval of a plan or
application that contains a request for a
variance does not constitute approval of
the variance. A separate request for a
variance may be submitted
simultaneously with a plan or
application. For plans or applications
that are contingent upon the approval of
the variance request, the BLM
encourages the simultaneous
submission of the variance request and
the plan or application.
(3) The party requesting the variance
must file the request and any supporting
documents using WIS. If electronic
filing is not possible or practical, the
operator may submit a request for
variance on the Form 3160–5, Sundry
Notices and Reports on Wells (Sundry
Notice) to the BLM Field Office having
jurisdiction over the lands described in
the application.
(4) The AO, after considering all
relevant factors, may approve the
variance, or approve it with COAs, only
if the AO determines that:
(i) The proposed alternative means of
compliance meets or exceeds the
objectives of the applicable
requirement(s) of the regulation;
(ii) Approving the variance will not
adversely affect royalty income and
production accountability; and
(iii) Issuing the variance is consistent
with maximum ultimate economic
recovery, as defined in 43 CFR 3160.0–
5.
(5) The decision whether to grant or
deny the variance request is entirely
within the BLM’s discretion.
(6) A variance from the requirements
of a regulation in this part does not
constitute a variance from provisions of
other regulations, including Onshore Oil
and Gas Orders.
(b) The BLM reserves the right to
rescind a variance or modify any COA
of a variance due to changes in Federal
law, technology, regulation, BLM
policy, field operations, noncompliance,
or other reasons. The BLM will provide
a written justification if it rescinds a
variance or modifies a COA.
§ 3170.7 Required recordkeeping, records
retention, and records submission.

(a) Lessees, operators, purchasers,
transporters, and any other person
directly involved in producing,
transporting, purchasing, selling, or

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measuring oil or gas through the point
of royalty measurement or the point of
first sale, whichever is later, must retain
all records, including source records,
that are relevant to determining the
quality, quantity, disposition, and
verification of production attributable to
Federal or Indian leases for the periods
prescribed in paragraphs (c) through (e)
of this section.
(b) This retention requirement applies
to records generated during or for the
period for which the lessee or operator
has an interest in or conducted
operations on the lease, or in which a
person is involved in transporting,
purchasing, or selling production from
the lease.
(c) For Federal leases, and units or
CAs that include Federal leases, but do
not include Indian leases, the record
holder must maintain records for:
(1) Seven years after the records are
generated; unless,
(2) A judicial proceeding or demand
involving such records is timely
commenced, in which case the record
holder must maintain such records until
the final nonappealable decision in such
judicial proceeding is made, or with
respect to that demand is rendered,
unless the Secretary or his/her designee
or the applicable delegated State
authorizes in writing an earlier release
of the requirement to maintain such
records.
(d) For Indian leases, and units or CAs
that include Indian leases, but do not
include Federal leases, the record
holder must maintain records for:
(1) Six years after the records are
generated; unless,
(2) The Secretary or his/her designee
notifies the record holder that the
Department of the Interior has initiated
or is participating in an audit or
investigation involving such records, in
which case the record holder must
maintain such records until the
Secretary or his/her designee releases
the record holder from the obligation to
maintain the records.
(e) For units and communitized areas
that include both Federal and Indian
leases, 6 years after the records are
generated. If the Secretary or his/her
designee has notified the record holder
within those 6 years that an audit or
investigation involving such records has
been initiated, then:
(1) If a judicial proceeding or demand
is commenced within 7 years after the
records are generated, the record holder
must retain all records regarding
production from the lease, unit PA, or
CA until the final nonappealable
decision in such judicial proceeding is
made, or with respect to that demand is
rendered, unless the Secretary or his/her

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designee authorizes in writing a release
of the requirement to maintain such
records before a final nonappealable
decision is made or rendered.
(2) If a judicial proceeding or demand
is not commenced within 7 years after
the records are generated, the record
holder must retain all records regarding
production from the unit or
communitized area until the Secretary
or his/her designee releases the record
holder from the obligation to maintain
the records;
(f) The lessee, operator, purchaser, or
transporter must maintain an audit trail.
(g) All records, including source
records, that are used to determine
quality, quantity, disposition, and
verification of production attributable to
a Federal or Indian lease, unit PA, or
CA, must include the FMP number or
the lease, unit PA, or CA number, along
with a unique equipment identifier (e.g.,
a unique tank identification number and
meter station number), and the name of
the company that created the record. For
all facilities existing prior to the
assignment of an FMP number, all
records must include the following
information:
(1) The name of the operator;
(2) The lease, unit PA, or CA number;
and
(3) The well or facility name and
number.
(h) Upon request of the AO, the
operator, purchaser, or transporter must
provide such records to the AO as may
be required by regulation, written order,
Onshore Order, NTL, or COA.
(i) All records must be legible.
(j) All records requiring a signature
must also have the signer’s printed
name.
§ 3170.8

Appeal procedures.

(a) BLM decisions, orders,
assessments, or other actions under the
regulations in this part are
administratively appealable under the
procedures prescribed in 43 CFR
3165.3(b), 3165.4, and part 4.
(b) For any recommendation made by
the PMT, and approved by the BLM, a
party affected by such recommendation
may file a request for discretionary
review by the Assistant Secretary for
Land and Minerals Management. The
Assistant Secretary may delegate this
review function as he or she deems
appropriate, in which case the affected
party’s application for discretionary
review must be made to the person or
persons to whom the Assistant
Secretary’s review function has been
delegated.
§ 3170.9

Enforcement.

Noncompliance with any of the
requirements of this part or any order

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issued under this part may result in
enforcement actions under 43 CFR
subpart 3163 or any other remedy
available under applicable law or
regulation.
Subpart 3171—[Reserved]
Subpart 3172—[Reserved]
Subpart 3173—Requirements for Site
Security and Production Handling

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§ 3173.1

Definitions and acronyms.

(a) As used in this subpart, the term:
Access means the ability to:
(i) Add liquids to or remove liquids
from any tank or piping system, through
a valve or combination of valves or by
moving liquids from one tank to another
tank; or
(ii) Enter any component in a
measuring system affecting the accuracy
of the measurement of the quality or
quantity of the liquid being measured.
Appropriate valves means those
valves that must be sealed during the
production or sales phase (e.g., fill lines,
equalizer, overflow lines, sales lines,
circulating lines, or drain lines).
Authorized representative (AR) has
the same meaning as defined in 43 CFR
3160.0–5.
Business day means any day Monday
through Friday, excluding Federal
holidays.
Commingling and allocation approval
(CAA) means a formal allocation
agreement to combine production from
two or more sources (leases, unit PAs,
CAs, or non-Federal or non-Indian
properties) before that product reaches
an FMP.
Economically marginal property
means a lease, unit PA, or CA that does
not generate sufficient revenue above
operating costs, such that a prudent
operator would opt to plug a well or
shut-in the lease, unit PA, or CA instead
of making the investments needed to
achieve non-commingled measurement
of production from that lease, unit PA,
or CA. A lease, unit PA, or CA may be
regarded as economically marginal if the
operator demonstrates that the expected
revenue (net any associated operating
costs) generated from crude oil or
natural gas production volumes on that
property is not sufficient to cover the
nominal cost of the capital expenditures
required to achieve measurement of
non-commingled production of oil or
gas from that property over a payout
period of 18 months. A lease, unit PA,
or CA can also be considered
economically marginal if the operator
demonstrates that its royalty net present
value (RNPV), or the discounted value
of the Federal or Indian royalties

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collected on revenue earned from crude
oil or natural gas production on the
lease, unit PA, or CA, over the expected
life of the equipment that would need
to be installed to achieve noncommingled measurement volumes, is
less than the capital cost of purchasing
and installing this equipment. Both the
payout period and the RNPV are
determined separately for each lease,
unit PA, or CA oil or gas FMP.
Additionally, oil FMPs are evaluated
using estimated revenue (net of taxes
and operating costs) from crude oil
production, as defined in this section,
while gas FMPs are evaluated using
estimated revenue (net of taxes and
operating costs) from natural gas
production, as defined in this section.
Effectively sealed means the
placement of a seal in such a manner
that the sealed component cannot be
accessed, moved, or altered without
breaking the seal.
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.
Land description means a location
surveyed in accordance with the U.S.
Department of the Interior’s Manual of
Surveying Instructions (2009), that
includes the quarter-quarter section,
section, township, range, and principal
meridian, or other authorized survey
designation acceptable to the AO, such
as metes-and-bounds, or latitude and
longitude.
Maximum ultimate economic
recovery has the same meaning as
defined in 43 CFR 3160.0–5.
Mishandling means failing to measure
or account for removal of production
from a facility.
Payout period means the time
required, in months, for the cost of an
investment in an oil or gas FMP for a
specific lease, unit PA, or CA to be
covered by the nominal revenue earned
from crude oil production, for an oil
FMP, or natural gas production, for a gas
FMP, minus taxes, royalties, and any
operating and variable costs. The payout
period is determined separately for each
oil or gas FMP for a given lease, unit PA,
or CA.
Permanent measurement facility
means all equipment constructed or
installed and used on-site for 6 months
or longer, for the purpose of
determining the quantity, quality, or
storage of production, and which meets
the definition of FMP under § 3170.3.
Piping means a tubular system (e.g.,
metallic, plastic, fiberglass, or rubber)
used to move fluids (liquids and gases).
Production phase means that event
during which oil is delivered directly to

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81425

or through production equipment to the
storage facilities and includes all
operations at the facility other than
those defined by the sales phase.
Royalty Net Present Value (RNPV)
means the net present value of all
Federal or Indian royalties paid on
revenue earned from crude oil
production or natural gas production
from an oil or gas FMP for a given lease,
unit PA, or CA over the expected life of
metering equipment that must be
installed for that lease, unit PA, or CA
to achieve non-commingled
measurement.
Sales phase means that event during
which oil is removed from storage
facilities for sale at an FMP.
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.
(b) As used in this subpart, the
following additional acronyms apply:
BIA means the Bureau of Indian
Affairs.
BMP means Best Management
Practice.
§ 3173.2
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 under this
subpart. 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 (sales, water drain, or hot oiling),
and prior to taking the top tank gauge
measurement, all appropriate valves
that allow unmeasured production to
enter or leave the sales tank must be
effectively sealed in the closed position
(see Appendix A to subpart 3173). Each
unsealed or ineffectively sealed
appropriate valve is a separate violation.
(b) Valves or combinations of valves
and tanks that provide access to the
production before it is measured for
sales are considered appropriate valves
and are subject to the seal requirements
of this subpart (see Appendix A to
subpart 3173). If there is more than one
valve on a line from a tank, the valve
closest to the tank must be sealed. All
appropriate valves must be in an
operable condition and accurately
reflect whether the valve is open or
closed.
(c) The following are not considered
appropriate valves and are not subject to
the sealing requirements of this subpart:

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Federal Register / Vol. 81, No. 222 / Thursday, November 17, 2016 / Rules and Regulations

(1) Valves on production equipment
(e.g., separator, 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 oil
that has been determined by the AO or
AR to be waste or slop oil;
(4) Sample cock valves used on piping
or tanks with a Nominal Pipe Size of 1
inch or less in diameter;
(5) Fill-line valves during shipment
when a single tank with a nominal
capacity of 500 barrels (bbl) or less is
used for collecting marginal production
of oil produced from a single well (i.e.,
production that is less than 3 bbl per
day). All other seal requirements of this
subpart apply;
(6) Gas line valves used on piping
with a Nominal Pipe Size of 1 inch or
less used as tank bottom ‘‘roll’’ lines,
provided 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, or
glycol);
(8) Valves used on piping with a
Nominal Pipe Size of 1 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).
However, any valve that allows access
for removing oil before it is measured
through the metering system must be
effectively sealed (see Appendix A to
subpart 3173).
(d) Tampering with any appropriate
valve is prohibited. Tampering with an
appropriate valve may result in an
assessment of civil penalties for
knowingly or willfully preparing,
maintaining, or submitting false,
inaccurate, or misleading reports,
records, or written information under 30
U.S.C. 1719(d)(1) and 43 CFR
3163.2(f)(1), or knowingly or willfully
taking, removing, transporting, using, or
diverting oil or gas from a lease site
without valid legal authority under 30
U.S.C. 1719(d)(2) and 43 CFR
3163.2(f)(2), together with any other
remedies provided by law.
§ 3173.3 Oil measurement system
components—seals.

(a) Components used for quantity or
quality determination of oil must be
effectively sealed to indicate tampering,

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including, but not limited to, the
following components of LACT meters
(see § 3174.8(a)) and CMSs (see
§ 3174.9(e)):
(1) Sample probe;
(2) Sampler volume control;
(3) All valves on lines entering or
leaving the sample container, excluding
the safety pop-off valve (if so equipped).
Each valve must be sealed in the open
or closed position, as appropriate;
(4) Meter assembly, including the
counter head and meter head;
(5) Temperature averager;
(6) LACT meters or CMS;
(7) Back pressure valve pressure
adjustment downstream of the meter;
(8) Any drain valves in the system;
(9) Manual-sampling valves (if so
equipped);
(10) Valves on diverter lines larger
than 1 inch in nominal diameter;
(11) Right-angle drive;
(12) Totalizer; and
(13) Prover connections.
(b) Each missing or ineffectively
sealed component is a separate
violation.
§ 3173.4

Federal seals.

(a) In addition to any INC issued for
a seal violation, the AO or AR may place
one or more Federal seals on any
appropriate valve, sealing device, or oilmetering-system component that does
not comply with the requirements in
§§ 3173.2 and 3173.3 if the operator is
not present, refuses to cooperate with
the AO or AR, or is unable to correct the
noncompliance.
(b) The placement of a Federal seal
does not constitute compliance with the
requirements of §§ 3173.2 and 3173.3.
(c) A Federal seal may not be removed
without the approval of the AO or AR.
§ 3173.5 Removing production from tanks
for sale and transportation by truck.

(a) When a single truck load
constitutes a completed sale, the driver
must possess documentation containing
the information required in § 3174.12.
(b) When multiple truckloads 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
containing the information required in
§ 3174.12. 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.
§ 3173.6

Water-draining operations.

When water is drained from a
production storage tank, the operator,

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purchaser, or transporter, as
appropriate, must document the
following information:
(a) Federal or Indian lease, unit PA, or
CA number(s);
(b) The tank location by land
description;
(c) The unique tank number and
nominal capacity;
(d) Date of the opening gauge;
(e) Opening gauge (gauged manually
or automatically), TOV, and free-water
measurements, all to the nearest 1⁄2 inch;
(f) Unique identifying number of each
seal removed;
(g) Closing gauge (gauged manually or
automatically) and TOV measurement to
the nearest 1⁄2 inch; and
(h) Unique identifying number of each
seal installed.
§ 3173.7 Hot oiling, clean-up, and
completion operations.

(a) During hot oil, clean-up, or
completion operations, or any other
situation where the operator removes oil
from storage, temporarily uses it for
operational purposes, and then returns
it to storage on the same lease, unit PA,
or communitized area, the operator
must document the following
information:
(1) Federal or Indian lease, unit PA,
or CA number(s);
(2) Tank location by land description;
(3) Unique tank number and nominal
capacity;
(4) Date of the opening gauge;
(5) Opening gauge measurement
(gauged manually or automatically) to
the nearest 1⁄2 inch;
(6) Unique identifying number of each
seal removed;
(7) Closing gauge measurement
(gauged manually or automatically) to
the nearest 1⁄2 inch;
(8) Unique identifying number of each
seal installed;
(9) How the oil was used; and
(10) Where the oil was used (i.e., well
or facility name and number).
(b) During hot oiling, line flushing, or
completion operations or any other
situation where the operator removes
production from storage for use on a
different lease, unit PA, or
communtized area, the production is
considered sold and must be measured
in accordance with the applicable
requirements of this subpart and
reported as sold to ONRR on the OGOR
under 30 CFR part 1210 subpart C for
the period covering the production in
question.
§ 3173.8 Report of theft or mishandling of
production.

(a) No later than the next business day
after discovery of an incident of

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Federal Register / Vol. 81, No. 222 / Thursday, November 17, 2016 / Rules and Regulations
apparent theft or mishandling of
production, the operator, purchaser, or
transporter must report the incident to
the AO. All oral reports must be
followed up with a written incident
report within 10 business days of the
oral report.
(b) The incident report must include
the following information:
(1) Company name and name of the
person reporting the incident;
(2) Lease, unit PA, or CA number,
well or facility name and number, and
FMP number, as appropriate;
(3) Land description of the facility
location where the incident occurred;
(4) The estimated volume of
production removed;
(5) The manner in which access was
obtained to the production or how the
mishandling occurred;
(6) The name of the person who
discovered the incident;
(7) The date and time of the discovery
of the incident; and
(8) Whether the incident was reported
to local law enforcement agencies and/
or company security.

is 150 bbl, the gross sales volume
between the first and second inventory
is 198 bbl, and February is the calendar
month for which the report is due. For
purposes of this example, we assume
February had 28 days and that the well
was non-producing for two of those
days.
{[(150 bbl + 198 bbl ¥ 125 bbl)/29 days]
* 16 days} + 150 bbl = 273 bbl for
the February end-of-month
inventory.
(b) For each seal, the operator must
maintain a record that includes:
(1) The unique identifying number of
each seal and the valve or meter
component on which the seal is or was
used;
(2) The date of installation or removal
of each seal;
(3) For valves, the position (open or
closed) in which it was sealed; and
(4) The reason the seal was removed.
§ 3173.10 Form 3160–5, Sundry Notices
and Reports on Wells.

mstockstill on DSK3G9T082PROD with RULES3

(a) The operator must submit a Form
3160–5, Sundry Notices and Reports on
Wells (Sundry Notice) for the following:
§ 3173.9 Required recordkeeping for
(1) Site facility diagrams (see
inventory and seal records.
§ 3173.11);
(a) The operator must perform an end(2) Request for an FMP number (see
of-month inventory (gauged manually or § 3173.12);
automatically) that records: TOV in
(3) Request for FMP amendments (see
storage (measured to the nearest 1⁄2 inch) § 3173.13(b));
subtracting free water, the volume not
(4) Requests for approval of off-lease
corrected for temperature/S&W, and the measurement (see § 3173.23);
volume as reported to ONRR on the
(5) Request to amend an approval of
OGOR;
off-lease measurement (see
(1) The end-of-month inventory must
§ 3173.23(k));
be completed within +/¥ 3 days of the
(6) Requests for approval of CAAs (see
last day of the calendar month; or
§ 3173.15); and
(2) The end of month inventory must
(7) Request to modify a CAA (see
be a calculated ‘‘end of month’’
§ 3173.18).
inventory based on daily production
(b) The operator must submit all
that takes place between two measured
Sundry Notices electronically to the
inventories that are not more than 31,
BLM office having jurisdiction over the
nor fewer than 20, days apart. The
lease, unit, or CA using WIS, unless the
calculated monthly inventory is
submitter:
determined based on the following
(1) Is a small business, as defined by
equation:
the U.S. Small Business Administration;
and
{[(X + Y ¥ W)/Z1] * Z2} + X = A,
(2) Does not have access to the
Where:
Internet.
A = calculated end of month inventory;
W = first inventory measurement;
X = second inventory measurement;
Y = gross sales volume between the first and
second inventory;
Z1 = number of actual days produced
between the first and second inventory;
and
Z2 = number of actual days produced
between the second inventory and end of
calendar month for which the OGOR
report is due.

For example: If the first inventory
measurement performed on January 12
is 125 bbl, the second inventory
measurement performed on February 10

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§ 3173.11

Site facility diagram.

(a) A site facility diagram is required
for all facilities.
(b) Except for the requirement to
submit a Form 3160–5, Sundry Notice,
with the site facility diagram, no format
is prescribed for site facility diagrams.
The diagram should be formatted to fit
on an 81⁄2 x 11 sheet of paper, if
possible, and must be legible and
comprehensible to an individual with
an ordinary working knowledge of oil
field operations (see Appendix A to
subpart 3173). If more than one page is

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81427

required, each page must be numbered
(in the format ‘‘N of X pages’’).
(c) The diagram must:
(1) 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, but
need not be to scale;
(2) Commencing with the header,
identify all of the equipment, including,
but not limited to, the header, wellhead,
piping, tanks, and metering systems
located on the site, and include the
appropriate valves and any other
equipment used in the handling,
conditioning, or disposal of production
and water, and indicate the direction of
flow;
(3) Identify by API number the wells
flowing into headers;
(4) If another operator operates a colocated facility, depict the co-located
facility(ies) on the diagram or list them
as an attachment and identify them by
company name, facility name(s), lease,
unit PA, or CA number(s), and FMP
number(s);
(5) Indicate which valve(s) must be
sealed and in what position during the
production and sales phases and during
the conduct of other production
activities (e.g., circulating tanks or
drawing off water), which may be
shown by an attachment, if necessary;
(6) When describing co-located
facilities operated by one operator,
include a skeleton diagram of the colocated facility(ies), showing equipment
only. For storage facilities common to
co-located facilities operated by one
operator, one diagram is sufficient;
(7) Clearly identify the lease, unit PA,
or CA to which the diagram applies, the
land description of the facility, and the
name of the company submitting the
diagram, with co-located facilities being
identified for each lease, unit PA, or CA;
(8) Clearly identify, on the diagram or
as an attachment, all meters and
measurement equipment. Specifically
identify all approved and assigned
FMPs; and
(9) If the operator claims royalty-free
use, clearly identify the equipment for
which the operator claims royalty-free
use. The operator must either:
(i) For each engine, motor, or major
component (e.g., compressor, separator,
dehydrator, heater-treater, or tank
heater) powered by production from the
lease, unit PA, or CA, state the volume
(oil or gas) consumed (per day or per
month) and how the volume is
determined; or
(ii) Measure the volume used, by
meter or tank gauge.
(d) At facilities for which the BLM
will assign an FMP number under

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Federal Register / Vol. 81, No. 222 / Thursday, November 17, 2016 / Rules and Regulations

§ 3173.12, the operator must submit a
new site facility diagram as follows:
(1) For facilities that become
operational after January 17, 2017,
within 30 days after the BLM assigns an
FMP; or
(2) For a facility that is in service on
or before January 17, 2017, and that has
a site facility diagram on file with the
BLM that meets the minimum
requirements of Onshore Oil and Gas
Order 3, Site Security, an amended site
facility diagram meeting the
requirements of this section is not due
until 30 days after the existing facility
is modified, a non-Federal facility
located on a Federal lease or federally
approved unit or communitized area is
constructed or modified, or there is a
change in operator.
(e) At facilities for which an FMP
number is not required under § 3173.12
(e.g., facilities that dispose of produced
water), the operator must submit a new
site facility diagram as follows:
(1) For new facilities in service after
January 17, 2017, the new site facility
diagram must be submitted within 30
days after the facility becomes
operational; or
(2) For a facility that is in service on
or before January 17, 2017, and that has
a site facility diagram on file with the
BLM that meets the minimum
requirements of Onshore Oil and Gas
Order 3, Site Security, an amended site
facility diagram meeting the
requirements of this section is not due
until 30 days after the existing facility
is modified, a non-Federal facility
located on a Federal lease or federally
approved unit or communitized area is
constructed or modified, or there is a
change in operator.
(f) After a site facility diagram has
been submitted that complies with the
requirements of this part, the operator
has an ongoing obligation to update and
amend the diagram within 30 days after
such facility is modified, a non-Federal
facility located on a Federal lease or
federally approved unit or
communitized area is constructed or
modified, or there is a change in
operator.

mstockstill on DSK3G9T082PROD with RULES3

§ 3173.12 Applying for a facility
measurement point.

(a)(1) Unless otherwise approved, the
FMP(s) for all Federal and Indian leases,
unit PAs, or CAs must be located within
the boundaries of the lease, unit, or
communitized area from which the
production originated and must
measure only production from that
lease, unit PA, or CA.
(2) Off-lease measurement or
commingling and allocation of Federal
or Indian production requires prior

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approval (see 43 CFR 3162.7–2, 3162.7–
3, 3173.15, 3173.16, 3173.24, and
3173.25).
(b) The BLM will not approve as an
FMP a gas processing plant tailgate
meter located off the lease, unit, or
communitized area.
(c) The operator must submit separate
applications for approval of an FMP that
measures oil produced from a lease, unit
PA, or CA, or under a CAA that
complies with the requirements of this
subpart, and an FMP that measures gas
produced from the same lease, unit PA,
or CA, or under a CAA that complies
with the requirements of this subpart.
This requirement applies even if the
measurement equipment or facilities are
at the same location.
(d) For a permanent measurement
facility that comes into service after
January 17, 2017, the operator must
apply for approval of the FMP before
any production leaves the permanent
measurement facility. This requirement
does not apply to temporary
measurement equipment used during
well testing operations. After timely
submission and prior to approval of an
FMP request, an operator must use the
lease, unit PA, or CA number for
reporting production to ONRR, until the
BLM assigns an FMP number, at which
point the operator must use the FMP
number for all reporting to ONRR as set
forth in § 3173.13.
(e) For a permanent measurement
facility in service on or before January
17, 2017, the operator must apply for
BLM approval of an FMP within the
time prescribed in this paragraph, based
on the production level of any one of
the leases, unit PAs, or CAs, whether or
not they are part of a CAA. The deadline
to apply for an FMP approval applies to
both oil and gas measurement facilities
measuring production from that lease,
unit PA, or CA.
(1) For a stand-alone lease, unit PA,
or CA that produced 10,000 Mcf or more
of gas per month or 100 bbl or more of
oil per month, by January 17, 2018.
(2) For a stand-alone lease, unit PA,
or CA that produced 1,500 Mcf or more,
but less than 10,000 Mcf of gas per
month, or 10 bbl or more, but less than
100 bbl of oil per month, by January 17,
2019.
(3) For a stand-alone lease, unit PA,
or CA that produced less than 1,500 Mcf
of gas per month or less than 10 bbl of
oil per month, January 17, 2020.
(4) For a stand-alone lease, unit PA,
or CA that has not produced for a year
or more before January 17, 2017, the
operator must apply for an FMP prior to
the resumption of production.
(5) The production levels identified in
paragraphs (e)(1) through (3) of this

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section should be calculated using the
average production of oil or gas over the
12 months preceding the effective date
of this section or over the period the
lease, unit PA, or CA has been in
production, whichever is shorter.
(6) If the operator of any facility
covered by this section applies for an
FMP approval by the deadline in this
paragraph, the operator may continue
using the lease, unit PA, or CA number
for reporting production to ONRR, until
the BLM’s assigns an FMP number, at
which point the operator must use the
FMP number for all reporting to ONRR
as set forth in § 3173.13.
(7) If the operator fails to apply for an
FMP approval by the deadline in this
paragraph, the operator will be subject
to an INC and may also be subject to an
assessment of a civil penalty under 43
CFR part 3160, subpart 3163, together
with any other remedy available under
applicable law or regulation.
(f) All requests for FMP approval must
include the following:
(1) A complete Sundry Notice
requesting approval of each FMP;
(2) The applicable Measurement Type
Code specified in WIS;
(3) Information about the equipment
used for oil and gas measurement,
including, for:
(i) ‘‘Gas measurement,’’ specify
operator/purchaser/transporter unique
station number, primary element (meter
tube) size or serial number, and type of
secondary device (mechanical or
electronic);
(ii) ‘‘Oil measurement by tank gauge,’’
specify oil tank number or tank serial
number and size in barrels or gallons for
all tanks associated with measurement
at an FMP; and
(iii) ‘‘Oil measurement by LACT or
CMS,’’ specify whether the equipment is
LACT or CMS and the associated oil
tank number or tank serial number and
size in barrels or gallons (there may be
more than one tank associated with an
FMP);
(4) Where production from more than
one well will flow to the requested
FMP, list the API well numbers
associated with the FMP; and
(5) FMP location by land description.
(g) Request for approval of an FMP
may be submitted concurrently with
separate requests for off-lease
measurement and/or CAA.
§ 3173.13 Requirements for approved
facility measurement points.

(a) For an existing facility in service
on or before January 17, 2017, an
operator must start using an FMP
number for reporting production to
ONRR on its OGOR for the fourth
production month after the BLM assigns

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the FMP number(s), and every month
thereafter. (For example, for a facility
that is assigned an FMP number on
January 15, 2016, the effective date of
the FMP is the May production report.)
For a new facility in service after
January 17, 2017, an operator must start
using an FMP number for reporting
production to ONRR on its OGOR for
the first production month after the
BLM assigns the FMP number(s), and
every month thereafter. (For example,
for a facility that is assigned an FMP
number on January 15, 2016, the
effective date of the FMP is the February
production report.)
(b)(1) The operator must file a Sundry
Notice that describes any changes or
modifications made to the FMP within
30 days after the change. This
requirement does not apply to
temporary modifications (e.g., for
maintenance purposes). These include
any changes and modifications to the
information listed on an application
submitted under § 3173.12.
(2) The description must include
details such as the primary element,
secondary element, LACT/CMS meter,
tank number(s), and wells or facilities
using the FMP.
(3) The Sundry Notice must specify
what was changed and the effective
date, and include, if appropriate, an
amended site facility diagram (see
§ 3173.11).

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§ 3173.14 Conditions for commingling and
allocation approval (surface and downhole).

(a) Subject to the exceptions provided
in paragraph (b) of this section, the BLM
may grant a CAA only if the proposed
allocation method used for any such
commingled measurement does not
have the potential to affect the
determination of the total volume or
quality of production on which royalty
owed is determined for all the Federal
or Indian leases, unit PAs, or CAs which
are proposed for commingling, and only
if the following criteria are met:
(1) The proposed commingling
includes production from more than
one:
(i) Federal lease, unit PA, or CA,
where each lease, unit PA, or CA
proposed for commingling has 100
percent Federal mineral interest, the
same fixed royalty rate and, and the
same revenue distribution;
(ii) Indian tribal lease, unit PA, or CA,
where each lease, unit PA, or CA
proposed for commingling is wholly
owned by the same tribe and has the
same fixed royalty rate;
(iii) Federal unit PA or CA where each
unit PA or CA proposed for
commingling has the same proportion of
Federal interest, and which interest is

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subject to the same fixed royalty rate
and revenue distribution. (For example,
the BLM could approve a commingling
request under this paragraph where an
operator proposes to commingle two
Federal CAs of mixed ownership and
both CAs are 50 percent Federal/50
percent private, so long as the Federal
interests have the same royalty rates and
royalty distributions.); or
(iv) Indian unit PA or CA where each
unit PA or CA proposed for
commingling has the same proportion of
Indian interests, and which interest is
held by the same tribe and has the same
fixed royalty rate; and
(2) The operator or operators provide
a methodology acceptable to BLM for
allocation among the properties from
which production is to be commingled
(including a method for allocating
produced water), with a signed
agreement if there is more than one
operator;
(3) For each of the leases, unit PAs, or
CAs proposed for inclusion in the CAA,
the applicant demonstrates to the AO
that a lease, unit PA, or CA proposed for
inclusion is producing in paying
quantities (or, in the case of Federal
leases, capable of production in paying
quantities) pending approval of the
CAA; and
(4) The FMP(s) for the proposed CAA
measure production originating only
from the leases, unit PAs, or CAs in the
CAA.
(b) The BLM may also approve a CAA
in instances where the proposed
commingling of production involves
production from Federal or Indian
leases, unit PAs, or CAs that do not
meet the criteria of paragraph (a)(1) of
this section (e.g., the commingling of
leases, unit PAs, or CAs with different
royalty rates or different distributions of
revenue, or where the commingling
involves multiple mineral ownerships).
In order to be approved, a CAA under
this subparagraph must meet the
requirements of paragraphs (a)(2)
through (4) of this section and at least
one of the following conditions:
(1) The Federal or Indian lease, unit
PA, or CA meets the definition of an
economically marginal property.
However, if the BLM determines that a
Federal or Indian lease, unit PA, or CA
included in a CAA ceases to be an
economically marginal property, then
this condition is no longer met;
(2) The average monthly production
over the preceding 12 months for each
Federal or Indian lease, unit PA, or CA
proposed for the CAA on an individual
basis is less than 1,000 Mcf of gas per
month, or 100 bbl of oil per month;
(3) A CAA that includes Indian leases,
unit PAs, or CAs has been authorized

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81429

under tribal law or otherwise approved
by a tribe;
(4) The CAA covers the downhole
commingling of production from
multiple formations that are covered by
separate leases, unit PAs, or CAs, where
the BLM has determined that the
proposed commingling from those
formations is an acceptable practice for
the purpose of achieving maximum
ultimate economic recovery and
resource conservation; or
(5) There are overriding
considerations that indicate the BLM
should approve a commingling
application in the public interest
notwithstanding potential negative
royalty impacts from the allocation
method. Such considerations could
include topographic or other
environmental considerations that make
non-commingled measurement
physically impractical or undesirable, in
view of where additional measurement
and related equipment necessary to
achieve non-commingled measurement
would have to be located.
§ 3173.15 Applying for a commingling and
allocation approval.

To apply for a CAA, the operator(s)
must submit the following, if applicable,
to the BLM office having jurisdiction
over the leases, unit PAs, or CAs from
which production is proposed to be
commingled:
(a) A completed Sundry Notice for
approval of commingling and allocation
(if off-lease measurement is a feature of
the commingling and allocation
proposal, then a separate Sundry Notice
under § 3173.23 is not necessary as long
as the information required under
§ 3173.23(b) through (e) and, where
applicable, § 3173.23(f) through (i) is
included as part of the request for
approval of commingling and
allocation);
(b) A completed Sundry Notice for
approval of off-lease measurement
under § 3173.23, if any of the proposed
FMPs are outside the boundaries of any
of the leases, units, or CAs from which
production would be commingled
(which may be included in the same
Sundry Notice as the request for
approval of commingling and
allocation), except as provided in
paragraph (a) of this section;
(c) A proposed allocation agreement,
including an allocation methodology
(including allocation of produced
water), with an example of how the
methodology is applied, signed by each
operator of each of the leases, unit PAs,
or CAs from which production would be
included in the CAA;
(d) A list of all Federal or Indian
lease, unit PA, or CA numbers in the

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proposed CAA, specifying the type of
production (i.e., oil, gas, or both) for
which commingling is requested;
(e) A topographic map or maps of
appropriate scale showing the
following:
(1) The boundaries of all the leases,
units, unit PAs, or communitized areas
whose production is proposed to be
commingled; and
(2) The location of existing or planned
facilities and the relative location of all
wellheads (including the API number)
and piping included in the CAA, and
existing FMPs or FMPs proposed to be
installed to the extent known or
anticipated;
(f) A surface use plan of operations
(which may be included in the same
Sundry Notice as the request for
approval of commingling and
allocation) if new surface disturbance is
proposed for the FMP and its associated
facilities are located on BLM-managed
land within the boundaries of the lease,
units, and communitized areas from
which production would be
commingled;
(g) A right-of-way grant application
(Standard Form 299), filed under 43
CFR part 2880, if the proposed FMP is
on a pipeline, or under 43 CFR part
2800, if the proposed FMP is a meter or
storage tank. This requirement applies
only when new surface disturbance is
proposed for the FMP, and its associated
facilities are located on BLM-managed
land outside any of the leases, units, or
communitized areas whose production
would be commingled;
(h) Written approval from the
appropriate surface-management
agency, if new surface disturbance is
proposed for the FMP and its associated
facilities are located on Federal land
managed by an agency other than the
BLM;
(i) A right-of-way grant application for
the proposed FMP, filed under 25 CFR
part 169, with the appropriate BIA
office, if any of the proposed surface
facilities are on Indian land outside the
lease, unit, or communitized area from
which the production would be
commingled;
(j) Documentation demonstrating that
each of the leases, unit PAs, or CAs
proposed for inclusion in the CAA is
producing in paying quantities (or, in
the case of Federal leases, is capable of
production in paying quantities)
pending approval of the CAA; and
(k) All gas analyses, including Btu
content (if the CAA request includes
gas) and all oil gravities (if the CAA
request includes oil) for previous
periods of production from the leases,
units, unit PAs, or communitized areas
proposed for inclusion in the CAA, up

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to 6 years before the date of the
application for approval of the CAA.
Gas analysis and oil gravity data is not
needed if the CAA falls under
§ 3173.14(a)(1).
§ 3173.16 Existing commingling and
allocation approvals.

Upon receipt of an operator’s request
for assignment of an FMP number to a
facility associated with a CAA existing
on January 17, 2017, the AO will review
the existing CAA and take the following
action:
(a) The AO will grandfather the
existing CAA and associated off-lease
measurement, where applicable, if the
existing CAA meets one of the following
conditions:
(1) The existing CAA involves
downhole commingling that includes
Federal or Indian leases, unit PAs, or
CAs; or
(2) The existing CAA is for surface
commingling and the average
production rate over the previous 12
months for each Federal or Indian lease,
unit PA, and CA included in the CAA
is:
(i) Less than 1,000 Mcf per month for
gas; or
(ii) Less than 100 bbl per month for
oil.
(b) If the existing CAA does not meet
the conditions of paragraphs (a)(1) or
(a)(2) of this section, the AO will review
the CAA for consistency with the
minimum standards and requirements
for a CAA under § 3173.14.
(1) The AO will notify the operator in
writing of any inconsistencies or
deficiencies with an existing CAA. The
operator must correct any
inconsistencies or deficiencies that the
AO identifies, provide the additional
information that the AO has requested,
or request an extension of time from the
AO, within 20 business days after
receipt of the AO’s notice. When the AO
is satisfied that the operator has
corrected any inconsistencies or
deficiencies, the AO will terminate the
existing CAA and grant a new CAA
based on the operator’s corrections.
(2) The AO may terminate the existing
CAA and grant a new CAA with new or
amended COAs to make the approval
consistent with the requirements under
§ 3173.14 in connection with approving
the requested FMP. If the operator
appeals any COAs of the new CAA, the
existing CAA approval will continue in
effect during the pendency of the
appeal.
(3) If the existing CAA does not meet
the standards and requirements of
§ 3173.14 and the operator does not
correct the deficiencies, the AO may
terminate the existing CAA under

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§ 3173.20 and deny the request for an
FMP number for the facility associated
with the existing CAA.
(c) If the AO grants a new CAA to
replace an existing CAA under
paragraph (b) of this section, the new
CAA is effective on the first day of the
month following its approval. Any new
allocation percentages resulting from
the new CAA will apply from the
effective date of the CAA forward.
§ 3173.17 Relationship of a commingling
and allocation approval to royalty-free use
of production.

A CAA does not constitute approval
of off-lease royalty-free use of
production as fuel in facilities located at
an FMP approved under the CAA.
§ 3173.18 Modification of a commingling
and allocation approval.

(a) A CAA must be modified when
there is:
(1) A modification to the allocation
agreement;
(2) Inclusion of additional leases, unit
PAs, or CAs are proposed in the CAA;
or
(3) Termination of or permanent
production cessation from any of the
leases, unit PAs, or CAs within the
CAA.
(b) To request a modification of a
CAA, all operators must submit to the
AO:
(1) A completed Sundry Notice
describing the modification requested;
(2) A new allocation methodology,
including an allocation methodology
which includes allocation of produced
water and an example of how the
methodology is applied, if appropriate;
and
(3) Certification by each operator in
the CAA that it agrees to the CAA
modification.
(c) A change in operator does not
trigger the need to modify a CAA.
§ 3173.19 Effective date of a commingling
and allocation approval.

(a) If the BLM approves a CAA, the
effective date of the CAA is the first day
of the month following first production
through the FMPs for the CAA.
(b) If the BLM approves a
modification, the effective date is the
first day of the month following
approval of the modification.
(c) A CAA does not modify any of the
terms of the leases, units, or CAs
covered by the CAA.
§ 3173.20 Terminating a commingling and
allocation approval.

(a) The AO may terminate a CAA for
any reason, including, but not limited
to, the following:
(1) Changes in technology, regulation,
or BLM policy;

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(2) Operator non-compliance with the
terms or COAs of the CAA or this
subpart; or
(3) The AO determines that a lease,
unit, or CA subject to the CAA has
terminated, or a unit PA subject to the
CAA has ceased production.
(b) If only one lease, unit PA, or CA
remains subject to the CAA, the CAA
terminates automatically.
(c) An operator may terminate its
participation in a CAA by submitting a
Sundry Notice to the BLM. The Sundry
Notice must identify the FMP(s) for the
lease(s), unit PA(s), or CA(s) previously
subject to the CAA. Termination by one
operator does not mean the CAA
terminates as to all other participating
operators, so long as one of the other
provisions of this subpart is met and the
remaining operators submit a Sundry
Notice requesting a new CAA as
outlined in paragraph (e) of this section.
(d) The AO will notify in writing all
operators who are a party to the CAA of
the effective date of the termination and
any inconsistencies or deficiencies with
their CAA approval that serve as the
reason(s) for termination. The operator
must correct any inconsistencies or
deficiencies that the AO identifies,
provide the additional information that
the AO has requested, or request an
extension of time from the AO, within
20 business days after receipt of the
BLM’s notice, or the CAA is terminated.
(e) If a CAA is terminated, each lease,
unit PA, or CA that was included in the
CAA may require a new FMP number(s)
or a new CAA. Operators will have 30
days to apply for a new FMP number
(§ 3173.12) or CAA (§ 3173.15), if
applicable. The existing FMP number
may be used for production reporting
until a new FMP number is assigned or
CAA is approved.

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§ 3173.21 Combining production downhole
in certain circumstances.

(a)(1) Combining production from a
single well drilled into different
hydrocarbon pools or geologic
formations (e.g., a directional well)
underlying separate adjacent properties
(whether Federal, Indian, State, or
private), where none of the hydrocarbon
pools or geologic formations underlie or
are common to more than one of the
respective properties, constitutes
commingling for purposes of §§ 3173.14
through 3173.20.
(2) If any of the hydrocarbon pools or
geologic formations underlie or are
common to more than one of the
properties, the operator must establish a
unit PA (see 43 CFR part 3180) or CA
(see 43 CFR 3105.2–1–3105.2–3), as
applicable, rather than applying for a
CAA.

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(b) Combining production downhole
from different geologic formations on
the same lease, unit PA, or CA in a
single well requires approval of the AO
(see 43 CFR 3162.3–2), but it is not
considered commingling for production
accounting purposes.
§ 3173.22 Requirements for off-lease
measurement.

The BLM will consider granting a
request for off-lease measurement if the
request:
(a) Involves only production from a
single lease, unit PA, CA, or CAA;
(b) Provides for accurate production
accountability;
(c) Is in the public interest
(considering factors such as BMPs,
topographic and environmental
conditions that make on-lease
measurement physically impractical,
and maximum ultimate economic
recovery); and
(d) Occurs at an approved FMP. A
request for approval of an FMP (see
§ 3173.12) may be filed concurrently
with the request for off-lease
measurement.
§ 3173.23 Applying for off-lease
measurement.

To apply for approval of off-lease
measurement, the operator must submit
the following to the BLM office having
jurisdiction over the leases, units, or
communitized areas:
(a) A completed Sundry Notice;
(b) Justification for off-lease
measurement (considering factors such
as BMPs, topographic and
environmental issues, and maximum
ultimate economic recovery);
(c) A topographic map or maps of
appropriate scale showing the
following:
(1) The boundary of the lease, unit,
unit PA, or communitized area from
which the production originates; and
(2) The location of existing or planned
facilities and the relative location of all
wellheads (including the API number
for each well) and piping included in
the off-lease measurement proposal, and
existing FMPs or FMPs proposed to be
installed to the extent known or
anticipated;
(d) The surface ownership of all land
on which equipment is, or is proposed
to be, located;
(e) If any of the proposed off-lease
measurement facilities are located on
non-federally owned surface, a written
concurrence signed by the owner(s) of
the surface and the owner(s) of the
measurement facilities, including each
owner’s name, address, and telephone
number, granting the BLM unrestricted
access to the off-lease measurement

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facility and the surface on which it is
located, for the purpose of inspecting
any production, measurement, water
handling, or transportation equipment
located on the non-Federal surface up to
and including the FMP, and for
otherwise verifying production
accountability. If the ownership of the
non-Federal surface or of the
measurement facility changes, the
operator must obtain and provide to the
AO the written concurrence required
under this paragraph from the new
owner(s) within 30 days of the change
in ownership;
(f) A right-of-way grant application
(Standard Form 299), filed under 43
CFR part 2880, if the proposed off-lease
FMP is on a pipeline, or under 43 CFR
part 2800, if the proposed off-lease FMP
is a meter or storage tank. This
requirement applies only when new
surface disturbance is proposed for the
FMP and its associated facilities are
located on BLM-managed land;
(g) A right-of-way grant application,
filed under 25 CFR part 169 with the
appropriate BIA office, if any of the
proposed surface facilities are on Indian
land outside the lease, unit, or
communitized area from which the
production originated;
(h) Written approval from the
appropriate surface-management
agency, if new surface disturbance is
proposed for the FMP and its associated
facilities are located on Federal land
managed by an agency other than the
BLM;
(i) An application for approval of offlease royalty-free use (if required under
applicable rules), if the operator
proposes to use production from the
lease, unit, or CA as fuel at the off-lease
measurement facility without payment
of royalty;
(j) A statement that indicates whether
the proposal includes all, or only a
portion of, the production from the
lease, unit, or CA. (For example, gas, but
not oil, could be proposed for off-lease
measurement.) If the proposal includes
only a portion of the production,
identify the FMP(s) where the
remainder of the production from the
lease, unit, or CA is measured or is
proposed to be measured; and
(k) If the operator is applying for an
amendment of an existing approval of
off-lease measurement, the operator
must submit a completed Sundry Notice
required under paragraph (a) of this
section, and information required under
paragraphs (b) through (j) of this section
to the extent the information previously
submitted has changed.

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§ 3173.24 Effective date of an off-lease
measurement approval.

If the BLM approves off-lease
measurement, the approval is effective
on the date that the approval is issued,
unless the approval specifies a different
effective date.
§ 3173.25 Existing approved off-lease
measurement.

(a) Upon receipt of an operator’s
request for assignment of an FMP
number to a facility associated with an
off-lease measurement approval existing
on January 17, 2017, the AO will review
the existing approved off-lease
measurement for consistency with the
minimum standards and requirements
for an off-lease measurement approval
under § 3173.22. The AO will notify the
operator in writing of any
inconsistencies or deficiencies.
(b) The operator must correct any
inconsistencies or deficiencies that the
AO identifies, provide any additional
information the AO requests, or request
an extension of time from the AO,
within 20 business days after receipt of
the AO’s notice. The extension request
must explain the factors that will
prevent the operator from complying
within 20 days and provide a timeframe
under which the operator can comply.
(c) The AO may terminate the existing
off-lease measurement approval and
grant a new off-lease measurement
approval with new or amended COAs to
make the approval consistent with the
requirements for off-lease measurement
under § 3173.22 in connection with
approving the requested FMP. If the
operator appeals the new off-lease
measurement approval, the existing offlease measurement approval will
continue in effect during the pendency
of the appeal.
(d) If the existing off-lease
measurement approval does not meet
the standards and requirements of
§ 3173.22 and the operator does not
correct the deficiencies, the AO may
terminate the existing off-lease
measurement approval under § 3173.27
and deny the request for an FMP
number for the facility associated with
the existing off-lease measurement
approval.

(e) If the existing off-lease
measurement approval under this
section is consistent with the
requirements under § 3173.22, then that
existing off-lease measurement is
grandfathered and will be part of its
FMP approval.
(f) If the BLM grants a new off-lease
measurement approval to replace an
existing off-lease measurement
approval, the new approval is effective
on the first day of the month following
its approval.

(d) If off-lease measurement is
terminated, each lease, unit PA, or CA
that was subject to the off-lease
measurement approval may require a
new FMP number(s) or a new off-lease
measurement approval. Operators will
have 30 days to apply for a new FMP
number or off-lease measurement
approval, whichever is applicable. The
existing FMP number may be used for
production reporting until a new FMP
number is assigned or off-lease
measurement is approved.

§ 3173.26 Relationship of off-lease
measurement approval to royalty-free use
of production.

§ 3173.28 Instances not constituting offlease measurement, for which no approval
is required.

Approval of off-lease measurement
does not constitute approval of off-lease
royalty-free use of production as fuel in
facilities located at an FMP approved
under the off-lease measurement
approval.

(a) If the approved FMP is located on
the well pad of a directionally or
horizontally drilled well that produces
oil and gas from a lease, unit, or
communitized area on which the well
pad is not located, measurement at the
FMP does not constitute off-lease
measurement. However, if the FMP is
located off of the well pad, regardless of
distance, measurement at the FMP
constitutes off-lease measurement, and
BLM approval is required under
§§ 3173.22 through 3173.26.
(b) If a lease, unit, or CA consists of
more than one separate tract whose
boundaries are not contiguous (e.g., a
single lease comprises two or more
separate tracts), measurement of
production at an FMP located on one of
the tracts is not considered to be offlease measurement if:
(1) The production is moved from one
tract within the same lease, unit, or
communitized area to another area of
the lease, unit, or communitized area on
which the FMP is located; and
(2) Production is not diverted during
the movement between the tracts before
the FMP, except for production used
royalty free.

§ 3173.27 Termination of off-lease
measurement approval.

(a) The BLM may terminate off-lease
measurement approval for any reason,
including, but not limited to, the
following:
(1) Changes in technology, regulation,
or BLM policy; or
(2) Operator non-compliance with the
terms or conditions of approval of the
off-lease measurement approval or
§§ 3173.22 through 3173.26.
(b) The BLM will notify the operator
in writing of the effective date of the
termination and any inconsistencies or
deficiencies with its off-lease
measurement approval that serve as the
reason(s) for termination. The operator
must correct any inconsistencies or
deficiencies that the BLM identifies,
provide any additional information the
AO requests, or request an extension of
time from the AO within 20 business
days after receipt of the BLM’s notice,
or the off lease measurement approval
terminates on the effective date.
(c) The operator may terminate the
off-lease measurement by submitting a
Sundry Notice to the BLM. The Sundry
Notice must identify the new FMP(s) for
the lease(s), unit(s), or CA(s) previously
subject to the off-lease measurement
approval.

§ 3173.29 Immediate assessments for
certain violations.

Certain instances of noncompliance
warrant the imposition of immediate
assessments upon discovery, as
prescribed in the following table.
Imposition of these assessments does
not preclude other appropriate
enforcement actions:

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TABLE 1 TO § 3173.29—VIOLATIONS SUBJECT TO AN IMMEDIATE ASSESSMENT
Assessment
amount per
violation
($)

Violation

1.
2.
3.
4.

An appropriate valve on an oil storage tank was not sealed, as required by § 3173.2 .................................................................
An appropriate valve or component on an oil metering system was not sealed, as required by § 3173.3 ...................................
A Federal seal is removed without prior approval of the AO or AR, as required by § 3173.4 .......................................................
Oil was not properly measured before removal from storage for use on a different lease, unit, or CA, as required by
§ 3173.7(b) .......................................................................................................................................................................................

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1,000
1,000
1,000
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81433

TABLE 1 TO § 3173.29—VIOLATIONS SUBJECT TO AN IMMEDIATE ASSESSMENT—Continued
Assessment
amount per
violation
($)

Violation

5.
6.
7.
8.
9.

An FMP was bypassed, in violation of § 3170.4 .............................................................................................................................
Theft or mishandling of production was not reported to the BLM, as required by § 3173.8 ..........................................................
Records necessary to determine quantity and quality of production were not retained, as required by § 3170.7 ........................
FMP application was not submitted, as required by § 3173.12 ......................................................................................................
(i) For facilities that begin operation after January 17, 2017, BLM approval for off-lease measurement was not obtained before removing production, as required by § 3173.23 .......................................................................................................................
(ii) Facilities that were in operation on or before January 17, 2017, are subject to an assessment if they do not have an existing
BLM approval for off-lease measurement.
10. (i) For facilities that begin operation after January 17, 2017, BLM approval for surface commingling was not obtained before
removing production, as required by § 3173.15 ..............................................................................................................................
(ii) Facilities that were in operation on or before January 17, 2017, are subject to an assessment if they do not have an existing
BLM approval for surface commingling.
11. (i) For facilities that begin operation after January 17, 2017, BLM approval for downhole commingling was not obtained before removing production, as required by § 3173.15 .......................................................................................................................
(ii) Facilities that were in operation on or before January 17, 2017, are subject to an assessment if they do not have an existing
BLM approval for downhole commingling.

1,000
1,000
1,000
1,000
1,000

1,000

1,000

2. Diagrams

Appendix A to Subpart 3173—
Examples of Site Facility Diagrams
I. Diagrams
1. Site Facility Diagrams and Sealing of Valve
Introduction
Diagrams
I–A
I–B
I–C
I–D
I–E

............
............
............
............
............

I–F ............
I–G ...........
I–H ............
I–I .............
I–J ............

Description
Gas well without separation equipment.
Gas well with separation equipment.
Single operator with co-located facilities single oil tank, gas, and water storage.
Oil sales with multiple oil tanks, gas, and water storage.
Co-located facilities with multiple operators, oil sales by liquid meter (Lease Automatic Custody Transfer or Coriolis Measurement
System), gas, and water storage.
On-lease gas plant, with oil sales by liquid meter, Liquefied Petroleum Gas (LPG)/Natural Gas Liquids (NGL) sales by liquid meter,
inlet gas, tailgate gas, flared or vented and plant process gas used.
Enhanced recovery water injection or other water disposal facility.
Pod Facility.
On-lease with gas measurement after the Joule–Thomson Plant (JT-Skid), oil sales by liquid meter, Liquefied Petroleum Gas
(LPG)/Natural Gas Liquids (NGL) sales by liquid meter.
On-lease with gas measurement before the Joule–Thomson Plant (JT-Skid) and oil sales by liquid meter.

Note: No FMP number required for Liquefied Petroleum Gas (LPG)/Natural Gas Liquids (NGL) liquid meter.

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1. Site Facility Diagrams and Sealing of
Valves Introduction
Introduction
Appendix A is provided not as a
requirement but solely as an example to aid
operators, purchasers and transporters in

VerDate Sep<11>2014

22:18 Nov 16, 2016

Jkt 241001

determining what valves are considered
‘‘appropriate valves’’ subject to the seal
requirements of this rule, and to aid in the
preparation of facility diagrams. It is
impossible to include every type of
equipment that could be used or situation
that could occur in production activities. In

PO 00000

Frm 00079

Fmt 4701

Sfmt 4700

making the determination of what is an
‘‘appropriate valve,’’ the entire facility must
be considered as a whole, including the
facility size, the equipment type, and the ongoing activities at the facility.
BILLING CODE 4310–4–P

E:\FR\FM\17NOR3.SGM

17NOR3

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81434

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Jkt 241001
PO 00000
Frm 00080

Gas meter:
FMP No. 72300451234

Fmt 4701

Well Fed 10

Sfmt 4725
E:\FR\FM\17NOR3.SGM
17NOR3

I
ER17NO16.001

N

I-A
Federal/Indian Lease, unit PA, orCA Number: NMNM12345
Page 1 of 1

Federal Register / Vol. 81, No. 222 / Thursday, November 17, 2016 / Rules and Regulations

22:18 Nov 16, 2016

Facility Operator/Owner Name: ABC Oil and Gas
Land Description: As defined in § 3170.3

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VerDate Sep<11>2014
22:18 Nov 16, 2016

Facility Operator/Owner Name: ABC Oil and Gas
Land Description: As defined in § 3170.3

Federal/Indian Lease, unit PA, orCA Number: NMNM12345
Page 1 of 1

Jkt 241001
PO 00000
Frm 00081

Gas meter:
FMP No. 72300451234

Fmt 4701
Sfmt 4725
E:\FR\FM\17NOR3.SGM

Free Water
Knockout
Gas
Water

17NOR3

Water Trucked

Fiberglass Pit
Tank

I

N

Free Water Knockout
Gas Usage 0.1 Mcf/day X days produced= Mcfper month.

Federal Register / Vol. 81, No. 222 / Thursday, November 17, 2016 / Rules and Regulations

I-B

81435

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81436

VerDate Sep<11>2014

Facility Operator/Owner Name: ABC Oil and Gas

Federal/Indian Lease, unit PA, orCA Number: NMNM12345 and NMNM54321

Land Description: As defined in § 3170.3

Jkt 241001

Page 1 of3

PO 00000

Gas meter
FMP No. 7230045AZ12
Well Fed lOA
NMNM12345

Gas meter
FMP No. 72300451234

Well Fed lOB
NMNM54321

Frm 00082
Fmt 4701

Oil
FMP No. 52300451234
Water Trucked

Separator

Sfmt 4725

Gas

E:\FR\FM\17NOR3.SGM

Water Trucked
Water

17NOR3

Fiberglass Pit
Tank

I

N

X

Sealable Valve

'l_s_e_e_a_tt_a_c_hm_e_n_t_fo_r_V_al_v_e_P_o_s_it-io_m_·_ng_d_un_·_n_g---.,1
Production, Sales, and Draining Phases

ER17NO16.003

Fiberglass Pit
Tank

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22:18 Nov 16, 2016

1-C

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VerDate Sep<11>2014

Facility Operator/Owner Name: ABC Oil and Gas
Land Description: As defined in § 3170.3

Jkt 241001
PO 00000

Diagram #I-C:
F1 is the Fill Valve
S 1 is the Sales Valve
D1 is the Drain Valve

Frm 00083
Fmt 4701

Valve Positioning in the Production Phase
Production into T5678
S 1 is Sealed Closed
F1 is Open
D 1 is Sealed Closed

Sfmt 4725
E:\FR\FM\17NOR3.SGM

Valve Positioning in the Sales Phase
Sales from T5678
S1 is Open
F1 is Open
D 1 is Sealed Closed

17NOR3

Valve Positioning in the Drain Phase
Draining from T5678
S 1 is Sealed Closed
F1 is Open
D1 is Open
Free Water Knockout
Gas Usage 0.1 Mcf/day X days produced= Mcfper month.

Federal/Indian Lease, unit PA, orCA Number: NMNM12345

Federal Register / Vol. 81, No. 222 / Thursday, November 17, 2016 / Rules and Regulations

22:18 Nov 16, 2016

I-C
Page 2 of3

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81438

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Jkt 241001
PO 00000

Facility Operator/Owner Name: ABC Oil and Gas
Land Description: As defined in§ 3170.3

Federal/Indian Lease, unit PA, orCA Number: NMNM12345

Frm 00084

Separator
Fire box rated at 150,000 btu/hour (btu/hr) operated, 20 hours/day (hrs/day)
150,000 btu/hr 7 1157 btu/cubic foot (btu/ft3) X 20 hrs/d 7 1000 = 2.51 Mcf/day

Fmt 4701
Sfmt 4725

Pump Jack
Manufacturer fuel use when operated at 75% of rated maximum RPM, 5.87 Mcflhr X hours operating 12 hrs. = 70.44 Mcf/day

E:\FR\FM\17NOR3.SGM

Water Tank
Tank Heater rated at 200,000 btu/hr operated 4 mo/yr (November, December, January, February), 10 hrs/week,
200,000 btu/hr 7 1157 btu/ft3 X 40 hrs/mo 7 1000 = 6.91 MCF/mo.

17NOR3

Oil Tank
Tank No.: 5678
Tank Heater rated at 200,000 btu/hr operated 4 mo/yr (November, December, January, February), 5 hrs/week
200,000 btu/hr 7 1157 btu/ft3 X 20 hrs/mo 7 1,000 = 3.46 Mcf/mo.
1157 btu/ft3 as dry determined by gas analysis taken at FMP No. 7230045AZ12 on MM/DD/YYY

ER17NO16.005

Federal Register / Vol. 81, No. 222 / Thursday, November 17, 2016 / Rules and Regulations

22:18 Nov 16, 2016

I-C
Page 3 of3

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VerDate Sep<11>2014

1-D

22:18 Nov 16, 2016

Facility Operator/Owner Name: ABC Oil and Gas
Land Description: As defined in § 3170.3

Jkt 241001

t

Federal/Indian Lease, unit PA, orCA Number: NMNM12345
Page 1 of3

Gas meter
FMP No. 72300451234

PO 00000
Frm 00085

N

Fmt 4701

I
Dehydrator

Sfmt 4725

Water Trucked
Separator

Oil
FMP No. 52300451234

E:\FR\FM\17NOR3.SGM

Oil

Gas
Water

17NOR3

Lined
Emergency Pit

See (diagram) attachment for Valve
Positioning during Production, Sales, and
Draining Phases

Equalizer
Sealable Valve

X

81439

ER17NO16.006

Fiberglass Pit
Tank

Federal Register / Vol. 81, No. 222 / Thursday, November 17, 2016 / Rules and Regulations

Page 1 of3

mstockstill on DSK3G9T082PROD with RULES3

Federal/Indian Lease, unit PA, orCA Number: NMNM12345

Jkt 241001
PO 00000

Diagram #I-D:
F1 and F2 are Fill Valves
S1 and S2 and Sales Valves
D 1 and D2 are Drain Valves

Frm 00086
Fmt 4701

Valve Positioning in the Production Phase
Production into T5678
Production into T1234
S2 and D2 are Sealed Closed
S 1 and D 1 are Sealed Closed
Overflow/Equalizer is Open
Overflow/Equalizer is Open
F2 is Open and F 1 is Closed
F 1 is open and F2 is Closed

Sfmt 4725
E:\FR\FM\17NOR3.SGM

Valve Positioning in the Sales Phase
Sales from T5678 through S1:
D 1 and F 1 are Sealed Closed
Overflow/Equalizer is Sealed Closed
S1 is Open
S2 Sealed closed
F2 open
D2 open or closed

Sales from T1234 through S2:
D2 and F2 are Sealed Closed
Overflow/Equalizer is Sealed Closed
S2 is Open
S 1 sealed closed
F1 open
D 1 open or closed

17NOR3

Valve Positioning in the Drain Phase
Draining from T5678
Draining from T1234
S1 and F1 are Sealed Closed
S2 and F2 are Sealed Closed
Overflow/Equalizer is Sealed Closed
Overflow/Equalizer is Sealed Closed
D1 is Open
D2 is Open
S-2 sealed close
S 1 sealed close
F1 open
F2 open
D2 open or closed
D 1 open or closed

Federal Register / Vol. 81, No. 222 / Thursday, November 17, 2016 / Rules and Regulations

22:18 Nov 16, 2016

Facility Operator/Owner Name: ABC Oil and Gas
Land Description: As defined in § 3170.3

81440

VerDate Sep<11>2014
ER17NO16.007

I-D
Page 2 of3

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VerDate Sep<11>2014
Jkt 241001

Facility Operator/Owner Name: ABC Oil and Gas
Land Description: As defined in § 3170.3

Federal/Indian Lease, unit PA, orCA Number: NMNM12345

PO 00000

Compressor
Manufacturer fuel use when operated at 80% of rated maximum, 24.87 Mcf/hr X 24 hrs. = 596.88 Mcf/day

Frm 00087

Dehydrator
Fire box rated at 75,000 btulhr operated, 20 hrs/day
75,000 btulhr 7 1,157 btu/ft3 X 20 hrs/day 4 7 1,000 = 1.30 Mcf/day

Fmt 4701
Sfmt 4725

Separator
Fire box rated at 150,000 btulhr operated 4 mo/yr, 20 hrs/day
150,000 btulhr 7 1,157 btu/ft3 X 20 hrs/day 71,000 = 2.59 Mcf/day

E:\FR\FM\17NOR3.SGM

Water Tank
Tank Heater rated at 200,000 btu/hr operated 4 mo/yr, 10 hrs/week, 70% efficiency
200,000 btulhr 7 1,157 btu/ft3 X 40 hrs/mo 7 1,000 = 6.91 Mcf/mo.

17NOR3

Oil Tank No.: 5678
Tank Heater rated at 200,000 btu/hr operated 4 mo/yr, 5 hrs/week
200,000 btulhr 7 1,157 btu/ft3 X 20 hrs/mo 7 1,000 = 3.46 Mcf/mo.
Oil Tank No.: 1234
Tank Heater rated at 200,000 btu/hr operated 4 mo/yr, 5 hrs/week
200,000 btulhr 7 1,157 btu/ft3 (see current gas analysis) X 20 hrs/mo 7 1,000 = 3.46 Mcf/mo.
1157 btu/ft3 as dry determined by gas analysis taken at FMP No. 72300451234 on MM/DD/YYY

Federal Register / Vol. 81, No. 222 / Thursday, November 17, 2016 / Rules and Regulations

22:18 Nov 16, 2016

I-D
Page 3 of3

81441

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81442

VerDate Sep<11>2014

1-E

Jkt 241001

Co-located Facility Operated by:
Oil & Gas Major LTD.,
NMNM54321

PO 00000

Gas meter
FMP No. 72300451234
Bad Oil Recirculation System

Frm 00088

Oil
FMP No. 62300451234
Dehydrator
Bad Oil Return

Fmt 4701

Water Pumped

Separator

Sfmt 4725

Gas

Oil
Water

E:\FR\FM\17NOR3.SGM
17NOR3

I

N

Steel Pit
Tank

Unlined
Emergency Pit

z

Sealable Valve

Header

f

Weill
API No.

ER17NO16.009

f

Well2
API No.

f

Well3
API No.

See (diagram) attachment for Valve
Positioning during Production, Sales, and
Draining Phases

Federal Register / Vol. 81, No. 222 / Thursday, November 17, 2016 / Rules and Regulations

22:18 Nov 16, 2016

Page 1 of3
Federal/Indian Lease, unit PA, or CA Number: NMNM12345

Facility Operator/Owner Name: ABC Oil and Gas
Land Description: As defined in § 3170.3

mstockstill on DSK3G9T082PROD with RULES3

VerDate Sep<11>2014
22:18 Nov 16, 2016

Facility Operator/Owner Name: ABC Oil and Gas
Land Description: As defined in § 3170.3

Jkt 241001
PO 00000

Diagram #I-E:
F1, F2 and F3 are Fill Valves
S 1 and S2 are Sales Valves
D1, D2 and D3 are Drain Valves
R1 is a Recirculation Valve

Frm 00089
Fmt 4701

Valve Positioning in the Production Phase for FMP No. 62300451234
Production into 5678, 1234 and 6851
S1, F1, F2, F3 and R1 are Open
D 1 and D2 are Sealed Closed
Equalizer is open

Sfmt 4725
E:\FR\FM\17NOR3.SGM

Valve Positioning in the Sales Phase
Production into 5678, 1234 and 6851
S1, F1, F2, F3 and R1 are Open
D 1 and D2 are Sealed Closed
Equalizer is open

17NOR3

Valve Positioning in the Drain Phase
Draining from 5678
Draining from 1234
S1 and F1 are Sealed Closed
S2 and F2 are Sealed Closed
Equalizer is Sealed Closed
Equalizer is Sealed Closed
D2 and S 1 are Open
D 1 and S2 are Open
D2 Sealed Closed
D1 Sealed Closed

Draining from 6851
R1 is Sealed Closed
F3 is Sealed Closed
D3 Open

81443

Dehydrator
Fire box rated at 75,000 btu/hr operated 24 hrs/day, 20 hrs/day
75,000 btu/hr 7 1,157 btu/ft3 X 20 7 1,000 = 1.30 Mcf/day

ER17NO16.010

Federal/Indian Lease, unit PA, orCA Number: NMNM12345

Federal Register / Vol. 81, No. 222 / Thursday, November 17, 2016 / Rules and Regulations

I-E
Page 2 of3

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81444

VerDate Sep<11>2014
Jkt 241001

Facility Operator/Owner Name: ABC Oil and Gas
Land Description: As defined in § 3170.3

PO 00000

Separator
Fire box rated at 150,000 btu!hr operated 4 mo/yr, 20 hrs/day
150,000 btu!hr -c- 1,157 btu/ft3 X 20 -c- 1,000 = 2.59 Mcf/day

Frm 00090
Fmt 4701
Sfmt 4725
E:\FR\FM\17NOR3.SGM
17NOR3
ER17NO16.011

Federal/Indian Lease, unit PA, orCA Number: NMNM12345

1157 btu/ft3 as dry determined by gas analysis taken at FMP No. 72300451234 on MM/DD/YYY
Charge pump, water pump and oil recirculation pump are electric motor/gasoline engine powered and not subject to royalty-free.
The following components on liquid measurement metering system will be effectively sealed (list as appropriate) for FMP No.: 62300451234
1. Sample probe;
2. Sampler volume control;
3. All valves on lines entering or leaving the sample container excluding the safety pop-offvalve (if so equipped). Each valve must be
sealed in the open or closed position, as appropriate;
4. Meter assembly, including the counter head and meter head;
5. Temperature averager/recorder;
6. Pressure adjustment on the back-pressure valve downstream of the meter;
7. CMS or LACT;
8. Any drain valves in the system;
9. Manual sampling valves (if so equipped);
10. Valves larger than 1 inch on the diverter lines;
11. Right-angle;
12. Totalizer; and
13. Prover connections.

Federal Register / Vol. 81, No. 222 / Thursday, November 17, 2016 / Rules and Regulations

22:18 Nov 16, 2016

1-E
Page3of3

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VerDate Sep<11>2014

1-F

Well 1, API No.

Well2, API No.

Jkt 241001
PO 00000

Gas Plant FlareNenting
Meter

Gas Plant Process/Used
Meter

Gas Plant Tailgate
Meter
FMP No. 72300391234

Frm 00091

Gas Plant Inlet Meter
To Separator 1111

1

Oil/Drip/Condensate

Fmt 4701

Lease, Unit PA, or CA Gas Plant
Processes/Processing

N

I
FMP No. 62300391234

Sfmt 4725
E:\FR\FM\17NOR3.SGM

t:ti

Pl

0..

.so:s
.....
Q

Lffl T~-~0~2w

0

IPressurized
LPG/NGLto
Storage

~

Vessels

I~

17NOR3

LACT/CMS
FMP No. 62300391235

z

Sealable Valve

Federal Register / Vol. 81, No. 222 / Thursday, November 17, 2016 / Rules and Regulations

22:18 Nov 16, 2016

Facility Operator/Owner Name: Oil and Gas Plant Operations Inc.
Federal/Indian Lease, unit PA, orCA Number: NMNM12345
Land Description: As defined in § 3170.3
Page 1 of 3

81445

ER17NO16.012

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81446

VerDate Sep<11>2014

Facility Operator/Owner Name: ABC Oil and Gas
Land Description: As defined in § 3170.3

Federal/Indian Lease, unit PA, orCA Number: NMNM12345
Page 2 of3

Jkt 241001
PO 00000
Frm 00092

Diagram #I-F:
F1, F2, F3, F4, F5, and F6 are Fill Valves
S1, S2, S3, S4, S5, and S6 are Sales Valves
D1, D2, D3, D4, D5 and D6 are Drain Valves

Fmt 4701
Sfmt 4725
E:\FR\FM\17NOR3.SGM
17NOR3

Valve Positioning in the Production Phase
Production into T5676
Production into T5677:
D 1 is Sealed Closed
D2 is Sealed Closed

Production into T5678
D3 is Sealed Closed

Valve Positioning in the Sales Phase
Sales from T5677 through S2:
Sales from T5676 through S 1:
D 1 is Sealed Closed
D2 is Sealed Closed

Sales from T5678 through S3:
D3 is Sealed Closed

Valve Positioning in the Drain Phase
Draining from T5676
Draining from T5677:
S2 is Sealed Closed
S 1 is Sealed Closed
F1 is Sealed Closed
F2 is Sealed Closed
Overflow is Sealed Closed
Overflow is Sealed Closed
D2 is Open
D1 is Open

Draining from T5678
S3 is Sealed Closed
F3 is Sealed Closed
Overflow is Sealed Closed
D3 is Open

Valve Positioning in the Production Phase
Production into T5680
Production into T5681:
D5 is Sealed Closed
D4 is Sealed Closed

Production into T5682
D6 is Sealed Closed

Federal Register / Vol. 81, No. 222 / Thursday, November 17, 2016 / Rules and Regulations

22:18 Nov 16, 2016
ER17NO16.013

I-F

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VerDate Sep<11>2014

I-F
Federal/Indian Lease, unit PA, orCA Number: NMNM12345
Page 3 of3

Jkt 241001
PO 00000
Frm 00093
Fmt 4701

Valve Positioning in the Sales Phase
Sales from T5681 through S5:
Sales from T5680 through S4:
D5 is Sealed Closed
D4 is Sealed Closed

Sales from T5682 through S6:
D6 is Sealed Closed

Valve Positioning in the Drain Phase
Draining from T5680
Draining from T5681:
S4 is Sealed Closed
S5 is Sealed Closed
F5 is Sealed Closed
F4 is Sealed Closed
Overflow is Sealed Closed
Overflow is Sealed Closed
D4 is Open
D5 is Open

Draining from T5682
S6 is Sealed Closed
F6 is Sealed Closed
Overflow is Sealed Closed
D6 is Open

Sfmt 4725
E:\FR\FM\17NOR3.SGM
17NOR3

The following components on liquid measurement metering system will be effectively sealed (list as appropriate) for tanks numbered 5676, 5677,
and 5678.
1. Sample probe;
2. Sampler volume control;
3. All valves on lines entering or leaving the sample container excluding the safety pop-off valve (if so equipped). Each valve must be
sealed in the open or closed position, as appropriate;
4. Meter assembly, including the counter head and meter head;
5. Temperature averager/recorder;
6. Pressure adjustment on the back-pressure valve downstream of the meter;
7. CMS or LACT;
8. Any drain valves in the system;
9. Manual sampling valves (if so equipped);
10. Valves larger than 1 inch on the diverter lines;
11. Right-angle;
12. Totalizer; and
13. Prover connections.

Federal Register / Vol. 81, No. 222 / Thursday, November 17, 2016 / Rules and Regulations

22:18 Nov 16, 2016

Facility Operator/Owner Name: ABC Oil and Gas
Land Description: As defined in § 3170.3

81447

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81448

VerDate Sep<11>2014

I-G
Federal/Indian Lease, unit PA, or CA Number: NMNM98765
Page 1 of2

Jkt 241001

Water from
Producing Wells by
Pipeline

Enhanced Recovery Water
Injection or other Water
Disposal Facility

Water from
Producing Wells by

Water

PO 00000
Frm 00094

Water Supply
Well No 200

Equalize
r

Fmt 4701
Sfmt 4725
E:\FR\FM\17NOR3.SGM
17NOR3

Injection Pump,
Filter Building and
Chemical Treatment

I

All Royalty-Free gas is first measured
through the "Fuel Gas Supply Meter"

I

Injection Header

~

Well1 API

ER17NO16.015

~Fuel Gas Supply Meter

~

We112 API

~

Wel13 API

I

Federal Register / Vol. 81, No. 222 / Thursday, November 17, 2016 / Rules and Regulations

22:18 Nov 16, 2016

Facility Operator/Owner Name: ABC Oil and Gas
Land Description: As defined in § 3170.3

mstockstill on DSK3G9T082PROD with RULES3

VerDate Sep<11>2014

Attachment

Jkt 241001

Facility Operator/Owner Name: ABC Oil and Gas
Land Description: As defined in§ 3170.3

PO 00000
Frm 00095

Diagram #I -G:
Fl is the Fill Valve
S 1 is the Sales Valve
D1 is the Drain Valve

Fmt 4701
Sfmt 4725

Valve Positioning in the Production Phase
Production into T5555
S 1 is Sealed Closed
Fl is Open
D 1 is Sealed Closed

E:\FR\FM\17NOR3.SGM

Valve Positioning in the Sales Phase
Sales form T5555
S1 is Open
Fl is Open
D 1 is Sealed Closed

17NOR3

Valve Positioning in the Drain Phase for
Draining from T5555
S 1 is Sealed Closed
Fl is Open
D1 is Open

Federal/Indian Lease, unit PA, or CA Number: NMNM98765
Page 2 of2

Federal Register / Vol. 81, No. 222 / Thursday, November 17, 2016 / Rules and Regulations

22:18 Nov 16, 2016

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81449

ER17NO16.016

mstockstill on DSK3G9T082PROD with RULES3

81450

VerDate Sep<11>2014

Facility Operator/Owner Name: ABC Oil and Gas
Land Description: As defined in§ 3170.3

Federal/Indian Lease, unit PA, orCA Number: NMNM98765
Page 1 of3

Jkt 241001
PO 00000

Pod 1

0

Frm 00096

Pod2
FMP No. 230045A24E

Fmt 4701
Sfmt 4725
E:\FR\FM\17NOR3.SGM

Free Water
Knockout
Gas
Water

17NOR3

Water Trucked

Fiberglass Pit
Tank

I
ER17NO16.017

N

Free Water Knockout
Gas Usage 0.1 Mcf/day

Federal Register / Vol. 81, No. 222 / Thursday, November 17, 2016 / Rules and Regulations

22:18 Nov 16, 2016

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VerDate Sep<11>2014
Jkt 241001

1-H
FederaVIndian Lease, unit PA, orCA Number: NMNM98765
Page 2 of3

PO 00000

POD Facility
2

Frm 00097

r----------------------------------------1

Fmt 4701

POD Master Meter

Sfmt 4725

FMP No. 7230045A24E

FMP No. 7230045AD44

POD Facility
1

r----------------------------------------1
·

POD Master Meter

FMP No. 74300459029Z
-------...[

E:\FR\FM\17NOR3.SGM

F~Ql23

)

FMP No. 733004537NM

FMP No. 7430045S5G9

FMP Ne. 733QQ45'38FG

FMP No. 7430045MI89
-------...[

)

•I

FMP No. 7430045VM34

•I

17NOR3

Federal Register / Vol. 81, No. 222 / Thursday, November 17, 2016 / Rules and Regulations

22:18 Nov 16, 2016

Facility Operator/Owner Name: ABC Oil and Gas
Land Description: As defined in § 3170.3

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PO 00000
Frm 00098
Fmt 4701
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E:\FR\FM\17NOR3.SGM
17NOR3
ER17NO16.019

I-H
Federal/Indian Lease, unit PA, orCA Number: NMNM98765
Page 3 of3

POD 1
FMP No. 743004590292
Federal/Indian Lease, unit PA, orCA Number: NMNM98765

FMP No. 7430045K5L8
Federal/Indian Lease, unit PA, orCA Number: NMNM98765

FMP No. 7430045S5G9
Federal/Indian Lease, unit PA, orCA Number: NMNM1234A

FMP No. 7430045VM34
Federal/Indian Lease, unit PA, orCA Number: NMNM56789D

FMP No. 7430045MI89
Federal/Indian Lease, unit PA, orCA Number: NMSF10254

FMP No. 7430045NX30
Federal/Indian Lease, unit PA, orCA Number: NMSF10254

POD2

FMP No. 7230045A24E
Federal/Indian Lease, unit PA, orCA Number: NMNM56789

FMP No. 7230045AD44
Federal/Indian Lease, unit PA, orCA Number: NMNM54321A

FMP No. 7230045Z4GB
Federal/Indian Lease, unit PA, orCA Number: NMNM1234C

FMP No. 733004537NM
Federal/Indian Lease, unit PA, orCA Number: NMNM56789B

FMP No. 73300450123
Federal/Indian Lease, unit PA, orCA Number: NMSF10983

FMP No. 733004538FG
Federal/Indian Lease, unit PA, orCA Number: NMSF10254

Federal Register / Vol. 81, No. 222 / Thursday, November 17, 2016 / Rules and Regulations

22:18 Nov 16, 2016

Facility Operator/Owner Name: ABC Oil and Gas
Land Description: As defined in§ 3170.3,

mstockstill on DSK3G9T082PROD with RULES3

VerDate Sep<11>2014

I-I

Well 1, API No.

+

Federal/Indian Lease, unit PA, orCA Number: NMNM12345
Page 1 of4

Well2, APINo.

Jkt 241001

Header

+
Gas Meter
FMP No. 72300391234

PO 00000

Gas

Frm 00099

N
Oil/Drip/Condensate

Fmt 4701

Joule-Thomson Plant (JT -Skid)

I
FMP No. 62300391234

Sfmt 4725
E:\FR\FM\17NOR3.SGM

t:ti

Pl

0..

.s

"'....
Ci

Lffl T~-~0~2w

0

I~
~

IPressurized
LPG/NGLto
Storage
Vessels

17NOR3

LACT/CMS

z

Sealable Valve

Federal Register / Vol. 81, No. 222 / Thursday, November 17, 2016 / Rules and Regulations

22:18 Nov 16, 2016

Facility Operator/Owner Name: ABC Oil and Gas
Land Description: As defined in § 3170.3

81453

ER17NO16.020

mstockstill on DSK3G9T082PROD with RULES3

81454

VerDate Sep<11>2014

Facility Operator/Owner Name: ABC Oil and Gas
Land Description: As defined in § 3170.3

Federal/Indian Lease, unit PA, orCA Number: NMNM12345
Page 2 of4

Jkt 241001
PO 00000
Frm 00100

Diagram #I-I:
F1, F2, F3, F4, F5, and F6 are Fill Valves
S1, S2, S3, S4, S5, and S6 are Sales Valves
D1, D2, D3, D4, D5 and D6 are Drain Valves

Fmt 4701
Sfmt 4725
E:\FR\FM\17NOR3.SGM
17NOR3

Valve Positioning in the Production Phase
Production into T5676
Production into T5677:
D 1 is Sealed Closed
D2 is Sealed Closed

Production into T5678
D3 is Sealed Closed

Valve Positioning in the Sales Phase
Sales from T5677 through S2:
Sales from T5676 through S 1:
D 1 is Sealed Closed
D2 is Sealed Closed

Sales from T5678 through S3:
D3 is Sealed Closed

Valve Positioning in the Drain Phase
Draining from T5676
Draining from T5677:
S2 is Sealed Closed
S 1 is Sealed Closed
F1 is Sealed Closed
F2 is Sealed Closed
Overflow is Sealed Closed
Overflow is Sealed Closed
D2 is Open
D1 is Open

Draining from T5678
S3 is Sealed Closed
F3 is Sealed Closed
Overflow is Sealed Closed
D3 is Open

Valve Positioning in the Production Phase
Production into T5680
Production into T5681:
D5 is Sealed Closed
D4 is Sealed Closed

Production into T5682
D6 is Sealed Closed

Federal Register / Vol. 81, No. 222 / Thursday, November 17, 2016 / Rules and Regulations

22:18 Nov 16, 2016
ER17NO16.021

I-I

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VerDate Sep<11>2014

Facility Operator/Owner Name: ABC Oil and Gas
Land Description: As defined in § 3170.3

Federal/Indian Lease, unit PA, orCA Number: NMNM12345
Page 3 of4

Jkt 241001
PO 00000
Frm 00101
Fmt 4701

Valve Positioning in the Sales Phase
Sales from T5680 through S4:
Sales from T5681 through S5:
D4 is Sealed Closed
D5 is Sealed Closed

Sales from T5682 through S6:
D6 is Sealed Closed

Valve Positioning in the Drain Phase
Draining from T5680
Draining from T5681:
S4 is Sealed Closed
S5 is Sealed Closed
F5 is Sealed Closed
F4 is Sealed Closed
Overflow is Sealed Closed
Overflow is Sealed Closed
D5 is Open
D4 is Open

Draining from T5682
S6 is Sealed Closed
F6 is Sealed Closed
Overflow is Sealed Closed
D6 is Open

Sfmt 4725
E:\FR\FM\17NOR3.SGM
17NOR3

The following components on liquid measurement metering system will be effectively sealed (list as appropriate) for tanks numbered 5676, 5677,
and 5678.
1. Sample probe;
2. Sampler volume control;
3. All valves on lines entering or leaving the sample container excluding the safety pop-offvalve (if so equipped). Each valve must be
sealed in the open or closed position, as appropriate;
4. Meter assembly, including the counter head and meter head;
5. Temperature averager/recorder;
6. Pressure adjustment on the back-pressure valve downstream of the meter;
7. CMS or LACT;
8. Any drain valves in the system;
9. Manual sampling valves (if so equipped);
10. Valves larger than 1 inch on the diverter lines;
11. Right-angle;
12. Totalizer, manufacturer; and
13. Prover connections.

Federal Register / Vol. 81, No. 222 / Thursday, November 17, 2016 / Rules and Regulations

22:18 Nov 16, 2016

I-I

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VerDate Sep<11>2014
Jkt 241001

Facility Operator/Owner Name: ABC Oil and Gas
Land Description: As defined in § 3170.3

Federal/Indian Lease, unit PA, orCA Number: NMNM12345
Page 4 of4

PO 00000
Frm 00102
Fmt 4701
Sfmt 4725
E:\FR\FM\17NOR3.SGM

The following components on liquid measurement metering system will be effectively sealed (list as appropriate) for tanks numbered 5680, 5681,
and 5682.
1. Sample probe;
2. Sampler volume control;
3. All valves on lines entering or leaving the sample container excluding the safety pop-off valve (if so equipped). Each valve must be
sealed in the open or closed position, as appropriate;
4. Meter assembly, including the counter head and meter head;
5. Temperature averager/recorder;
6. Pressure adjustment on the back-pressure valve downstream of the meter;
7. CMS or LACT;
8. Any drain valves in the system;
9. Manual sampling valves (if so equipped);
10. Valves larger than 1 inch on the diverter lines;
11. Right-angle;
12. Totalizer, manufacturer; and
13. Prover connections.

17NOR3

Separator
Fire box rated at 150,000 btu/hr operated, 20 hrs/day
150,000 btu/hr -o- 1,450 btu/ft3 (estimated) X 20 -o- 1,000 = 2.07 Mcf/day

Federal Register / Vol. 81, No. 222 / Thursday, November 17, 2016 / Rules and Regulations

22:18 Nov 16, 2016
ER17NO16.023

I-I

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VerDate Sep<11>2014

We112, .APT No.

Well 1, tPI No.

Header

Jkt 241001

Gas Meter
FMP No. 72300391234

Separator

PO 00000
Frm 00103

OiliDrip/Condensate

Joule-Thomson Plant (JT -Skid)

I

N

Fmt 4701
Sfmt 4725

Note: No FMP number required for Liquefied
Petroleum Gas (LPG)/Natural Gas Liquids (NGL)
liquid meter.

E:\FR\FM\17NOR3.SGM

ttl

~

~

g

I

LPG/NGLto
Pressurized Storage
Vessels

17NOR3

LACT/CMS
FMP No. 62300391235

X

Sealable Valve

Federal Register / Vol. 81, No. 222 / Thursday, November 17, 2016 / Rules and Regulations

22:18 Nov 16, 2016

1-J
Federal/Indian Lease, unit PA, orCA Number: NMNM12345
Page 1 of3

Facility Operator/Owner Name: ABC Oil and Gas
Land Description: As defined in§ 3170.3

81457

ER17NO16.024

mstockstill on DSK3G9T082PROD with RULES3

81458

VerDate Sep<11>2014
Jkt 241001

Facility Operator/Owner Name: ABC Oil and Gas
Land Description: As defined in § 3170.3

Federal/Indian Lease, unit PA, orCA Number: NMNM12345
Page 2 of3

PO 00000
Frm 00104

Diagram #I -J:
F1, F2, and F3, are Fill Valves
S1, S2, and S3 are Sales Valves
D1, D2, and D3 Drain Valves

Fmt 4701
Sfmt 4725
E:\FR\FM\17NOR3.SGM
17NOR3

Valve Positioning in the Production Phase
Production into T5676
Production into T5677:
D 1 is Sealed Closed
D2 is Sealed Closed

Production into T5678
D3 is Sealed Closed

Valve Positioning in the Sales Phase
Sales from T5676 through S 1:
Sales from T5677 through S2:
D 1 is Sealed Closed
D2 is Sealed Closed

Sales from T5678 through S3:
D3 is Sealed Closed

Valve Positioning in the Drain Phase
Draining from T5676
Draining from T5677:
S2 is Sealed Closed
S 1 is Sealed Closed
F2 is Sealed Closed
F1 is Sealed Closed
Overflow is Sealed Closed
Overflow is Sealed Closed
D1 is Open
D2 is Open

Draining from T5678
S3 is Sealed Closed
F3 is Sealed Closed
Overflow is Sealed Closed
D3 is Open

Federal Register / Vol. 81, No. 222 / Thursday, November 17, 2016 / Rules and Regulations

22:18 Nov 16, 2016
ER17NO16.025

I-J

mstockstill on DSK3G9T082PROD with RULES3

Facility Operator/Owner Name: ABC Oil and Gas
Land Description: As defined in § 3170.3

Federal/Indian Lease, unit PA, orCA Number: NMNM12345
Page 3 of3

PO 00000

The following components on liquid measurement metering system will be effectively sealed (list as appropriate) for tanks numbered 5676, 5677,
and 5678.

Frm 00105
Fmt 4701
Sfmt 9990
E:\FR\FM\17NOR3.SGM

1. Sample probe;
2. Sampler volume control;
3. All valves on lines entering or leaving the sample container excluding the safety pop-off valve (if so equipped). Each valve must be
sealed in the open or closed position, as appropriate;
4. Meter assembly, including the counter head and meter head;
5. Temperature averager/recorder;
6. Pressure adjustment on the back-pressure valve downstream of the meter;
7. CMS or LACT;
8. Any drain valves in the system;
9. Manual sampling valves (if so equipped);
10. Valves larger than 1 inch on the diverter lines;
11. Right-angle;
12. Totalizer, manufacturer; and
13. Prover connections.

17NOR3

Separator
Fire box rated at 150,000 btu/hr operated, 20 hrs/day
150,000 btu/hr -o- 1,450 btu/ft3 (estimated) X 20 -o- 1,000 = 2.07 Mcf/day
1450 btu/ft3 as dry determined by gas analysis taken at FMP No. 72300451234 on MMIDD/YYY

Federal Register / Vol. 81, No. 222 / Thursday, November 17, 2016 / Rules and Regulations

Jkt 241001

[FR Doc. 2016–25407 Filed 11–16–16; 8:45 am]

22:18 Nov 16, 2016

BILLING CODE 4310–84–C

VerDate Sep<11>2014

1-J

81459

ER17NO16.026