Onshore Oil and Gas Operations; Federal and Indian Oil and Gas Leases; Measurement of Gas

DEPARTMENT OF THE INTERIOR

Bureau of Land Management

43 CFR Parts 3160 and 3170

[17X.LLWO310000.L13100000.PP0000]

RIN 1004-AE17

Onshore Oil and Gas Operations; Federal and Indian Oil and Gas Leases; Measurement of Gas

AGENCY:

Bureau of Land Management, Interior.

ACTION:

Final rule.

SUMMARY:

This final rule updates and replaces Onshore Oil and Gas Order No. 5 (Order 5) with a new regulation codified in the Code of Federal Regulations (CFR). Like Order 5, this rule establishes minimum standards for accurate measurement and proper reporting of all gas removed or sold from Federal and Indian (except the Osage Tribe) leases, units, unit participating areas (PAs), and areas subject to communitization agreements (CAs). It provides a system for production accountability by operators, lessees, purchasers, and transporters. This rule establishes overall gas measurement performance standards and includes, among other things, requirements for the hardware and software related to gas metering equipment and reporting and recordkeeping. This rule also identifies certain specific acts of noncompliance that may result in an immediate assessment and provides a process for the Bureau of Land Management (BLM) to consider variances from the requirements of this rule.

DATES:

The final rule is effective on January 17, 2017. The incorporation by reference of certain publications listed in the rule is approved by the Director of the Federal Register as of January 17, 2017.

FOR FURTHER INFORMATION CONTACT:

Richard Estabrook, Petroleum Engineer, Division of Fluid Minerals, 707-468-4052, or Steven Wells, Division Chief, Division of Fluid Minerals, 202-912-7143, for information regarding the BLM's Fluid Minerals Program. For questions relating to regulatory process issues, please contact Faith Bremner at 202-912-7441. 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 individual 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. Background and Overview

II. Discussion of Final Rule and Comments on the Proposed Rule

III. Overview of Public Involvement and Consistency With GAO Recommendations

IV. Procedural Matters

I. Background and Overview

Under applicable laws, royalties are owed on all production removed or sold from Federal and Indian oil and gas leases. The basis for those royalty payments is the measured volume and quality of the production from those leases. In fiscal year (FY) 2015, onshore Federal oil and gas lease holders sold 180 million barrels of oil,

1

2.5 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 billion. Nearly half of these revenues were distributed to the States in which the leases are located. Lease holders on tribal and Indian lands sold 59 million barrels of oil, 239 billion cubic feet of natural gas, and 182 million gallons of natural gas liquids, with a market value of over $3.6 billion, generating royalties of over $0.6 billion that were all distributed to the applicable tribes and individual allottment owners.

1

This figure includes 168 million barrels 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 oil losses, all of which are considered to be part of oil sales for accounting purposes.

2

This figure includes all processed and unprocessed volumes recovered on-lease, nitrogen, fuel gas, coalbed methane, and any volumes of gas lost due to venting or flaring.

As explained in the preamble for the proposed rule, 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, report, and account for that production. The final rule helps achieve that objective by updating and replacing Order 5's requirements with respect to the measurement of gas with regulations codified in the CFR that reflect changes in applicable laws, metering technology, and industry standards since Order 5 was first promulgated in 1989.

3

3

Order 5 has been in effect since March 27, 1989 (see 54

Federal Register

(FR) 8100).

The basis for this rule is the Secretary of the Interior's authority under various Federal and Indian mineral leasing laws to manage oil and gas operations, which authority has been delegated to the BLM. In implementing that authority, the BLM issued onshore oil and gas operating regulations that are codified at 43 CFR part 3160. The regulations at 43 CFR part 3160, Onshore Oil and Gas Operations, in § 3164.1, provide for the issuance of Onshore Oil and Gas Orders to “implement and supplement” the regulations in part 3160.

4

The table in § 3164.1(b) lists the existing Orders. This final rule updates and replaces Order 5 and will be codified in the CFR, primarily in new subpart 3175. Like Order 5, this final rule sets the requirements for the measurement of gas produced or sold from a lease; it does not address other circumstances in which the BLM requires royalty payment, such as for avoidably lost gas (

see

Notice to Lessees and Operators of Onshore Federal and Indian Oil and Gas Leases (NTL-4A), Royalty or Compensation for Oil and Gas Lost, 44 FR 76600 (Dec. 27, 1979);

see also

81 FR 6616 (February 8, 2016)).

4

Over the years, the BLM has issued seven Onshore Oil and Gas Orders that have dealt with different aspects of oil and gas production. These Orders were published in the FR, both for public comment and in final form, but they do not appear in the CFR. Although they are not codified in the CFR, all Onshore Orders have been issued consistent with Administrative Procedure Act (APA) notice and comment rulemaking procedures, and therefore have the effect of regulations and apply nationwide to all Federal and Indian (except the Osage Tribe) onshore oil and gas leases.

Consistent with updating and replacing Order 5, this rule also supersedes various statewide NTLs that have been issued from time-to-time to provide additional guidance regarding compliance with the requirements of Order 5, including:

• NM NTL 92-5, January 1, 1992;

• WY NTL 2004-1, April 23, 2004;

• CA NTL 2007-1, April 16, 2007;

• MT NTL 2007-1, May 4, 2007;

• UT NTL 2007-1, August 24, 2007;

• CO NTL 2007-1, December 21, 2007;

• NM NTL 2008-1, January 29, 2008;

• ES NTL 2008-1, September 17, 2008;

• AK NTL 2009-1, July 29, 2009; and

• CO NTL 2014-01, May 19, 2014.

Although this rule supersedes Order 5 and various statewide NTLs, the existing requirements of Order 5 and those NTLs remain in effect during the phase-in periods—specified in § 3175.60(b)—for the rule's new requirements.

The requirements in this rule help ensure that the Department of the Interior (DOI or the Department) meets it responsibility to collect royalties on gas extracted from Federal onshore and Indian (except the Osage Tribe) leases. The proper measurement of gas is essential to ensure that the American

public, as well as Indian tribes and individual allottees, receive the royalties to which they are entitled on oil and gas produced from Federal and Indian leases, respectively.

As explained in the preamble to the proposed rule, these changes were prompted by internal and external concerns about the adequacy of the BLM's existing gas measurement rules. Notably, these concerns were highlighted in several external reviews of the BLM's measurement program by three independent outside entities—the Secretary of the Interior's (Secretary's) Subcommittee on Royalty Management (the Subcommittee) in 2007, the DOI's Office of the Inspector General (OIG) in 2009, and the Government Accountability Office (GAO) in 2010, 2011, 2013, and 2015—all of which have repeatedly recommended that the BLM evaluate its gas measurement guidance and regulations to ensure that operators are properly accounting for production from Federal and Indian leases and are paying the proper royalties. Specifically, these groups found with respect to gas measurement that the DOI needed to provide Department-wide guidance on measurement technologies and processes not addressed in current regulations, including guidance on the process for approving variances in instances when new technologies or processes are developed that are not yet addressed by existing rules. As explained in the Section-by-Section analysis, the provisions of this final rule respond to these recommendations.

In 2007, the Secretary appointed an independent panel—the 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.

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In a report dated December 17, 2007, the Subcommittee determined that the BLM's guidance regarding production accountability and measurement 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 and measurement tasks and, ultimately, potential inaccuracies in royalty collections. The final rule in part results from the recommendations contained in the Subcommittee's report, which was issued on December 17, 2007.

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The Subcommittee was commissioned to report to the Royalty Policy Committee, which was chartered under the Federal Advisory Committee Act (FACA) 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.

Specifically, the Subcommittee report expressed concern that the applicable “BLM policy and guidance is outdated” and “some policy memoranda have expired” (Subcommittee report, p. 31). It also noted 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 NTLs 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.

). Of the 110 recommendations made in the 2007 Subcommittee report, 12 recommendations relate directly to improving the measurement and reporting of natural gas volume and heating value. For example, the Subcommittee paid particular attention to the measurement and reporting of heating value because it has a direct impact on royalties ultimately collected as heating value establishes the energy content of a particular volume of gas, a key component of its market value. Heating value is as important to calculating royalties due as measured volume. Currently, Order 5 requires only yearly measurement of natural gas heating value and there are no BLM standards for how operators should measure heating value, where they should measure it, how they should analyze it, or on what basis they should report it. The requirements in subpart 3175 of this final rule establish these standards.

This rule also addresses findings and recommendations made in two GAO reports and one OIG report: (1) GAO 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) GAO Report to Congressional Requesters,

Oil and Gas Resources, Interior's Production Verification Efforts and Royalty Data Have Improved, But Further Actions Needed,

GAO-15-39 (GAO Report 15-39); and (3) OIG Report,

Bureau of Land Management's Oil and Gas Inspection and Enforcement Program

(CR-EV-0001-2009) (OIG Report).

Consistent with the Subcommittee's findings, the GAO found that the Department's measurement regulations and policies do not provide reasonable assurances that oil and gas are accurately measured because, among other things, its policies for tracking where and how oil and gas are measured are not consistent and effective (GAO Report 10-313, p. 20). The report also found that the BLM's regulations do not reflect current industry-adopted measurement technologies and standards designed to improve oil and gas measurement (

ibid.

). The GAO recommended that the DOI provide Department-wide guidance on measurement technologies not addressed in current regulations and approve variances for measurement technologies in instances when the technologies are not addressed in current regulations or Department-wide guidance (see

ibid,

p. 80). The OIG Report made a similar recommendation that the BLM, “Ensure that oil and gas regulations are current by updating and issuing onshore orders . . .” (see OIG Report, p. 11). In its 2015 report, the GAO reiterated that “Interior's measurement regulations do not reflect current measurement technologies and standards,” and that this “hampers the agency's ability to have reasonable assurance that oil and gas production is being measured accurately and verified . . .” (GAO Report 15-39, p. 16). Among its recommendations were that the Secretary direct the BLM to “meet its established timeframe for issuing final regulations for gas measurement” (

ibid.,

p. 32).

In total, the GAO made 19 recommendations to improve the BLM's ability to ensure that oil and gas produced from Federal and Indian lands are accurately measured and properly reported (GAO Report 10-313), a number of which relate to gas measurement. For example, the report recommends that the BLM establish goals that would allow it to witness gas sample collections; however, it recognized that the BLM must first establish gas sampling standards as a basis for inspection and enforcement actions. This final rule establishes those standards. Similarly, the 2015 GAO report recommends, among other things, that the BLM issue new regulations pertaining to gas measurement, which this rule accomplishes.

It should also be noted that the GAO's recommendations regarding gas measurement are also one of the bases for the GAO's inclusion of the Department's oil and gas program on the GAO's High Risk List in 2011 (GAO-11-278) and for its continuing to keep the program on the list in the 2013 and 2015 updates (GAO-13-283 (2013) and GAO-

15-290 (2015)). Specifically, the GAO concluded with respect to the High Risk List that inclusion of the BLM's oil and gas program is justified because, among other things, the program's existing policies and regulations do not provide “reasonable assurance that . . . gas produced from federal leases is accurately measured and that the public is getting an appropriate share of oil and gas revenues” (GAO-11-278, p. 38).

In addition to these external reports and assessments, the provisions of this rule are also based on the BLM's own internal assessment of the adequacy of the existing requirements of Order 5. For example, because many improvements in technology and industry standards have occurred since Order 5 was issued, the BLM has had to develop a number of statewide NTLs and/or approve a number of site-specific variances. This final rule addresses these issues and supersedes the statewide NTLs.

The following summarizes and briefly explains the most significant provisions in this final rule. Each of these is discussed more fully in the Section-by-Section analysis below. For that reason, references to specific section and paragraph numbers are omitted in the body of this summary discussion.

1. Determining and Reporting Heating Value and Relative Density (§§ 3175.110 Through 3175.126)

The most significant requirements of the final rule are related to determining and reporting the heating value and relative density of all gas produced. Royalties on gas are calculated by multiplying the volume of the gas removed or sold from the lease (generally expressed in thousands of standard cubic feet (Mcf)) by the heating value of the gas in British thermal units (Btu) per unit volume, the value of the gas (expressed in dollars per million Btu (MMBtu)), and the fixed royalty rate. Therefore, a 10 percent error in the reported heating value would result in the same error in royalty as a 10 percent error in volume measurement. Relative density, which is a measure of the average mass of the molecules flowing through the meter, is used in the calculation of flow rate and volume. Because the flow equation uses the square root of relative density, a 10 percent error in relative density would only result in a 5 percent error in the volume calculation. Both heating value and relative density are determined from the same gas sample.

Currently, Order 5 requires a determination of heating value only once per year. Federal and Indian onshore gas producers can then use that value in the royalty calculations for an entire year. There are currently no requirements in Order 5 for determining relative density. Existing regulations do not have standards for how gas samples used in determining heating value and relative density should be taken and analyzed to avoid biasing the results. In addition, existing regulations do not prescribe when and how operators should report the results to the BLM.

In response to a Subcommittee recommendation that the BLM determine the potential heating-value variability of produced natural gas and estimate its implications for royalty payments, the BLM conducted a study of 180 gas facility measurement points (FMPs) that found significant sample-to-sample variability in heating value and relative density. The “BLM Gas Variability Study Final Report,” dated May 21, 2010, used 1,895 gas analyses gathered from 65 formations. In one example, the study found that heating values measured from samples taken at a gas meter in the Anderson Coal formation in the Powder River Basin varied ±31.41 percent, while relative density varied ±19.98 percent. In multiple samples collected at another gas meter in the same formation, heating values varied by only ±2.58 percent, while relative density varied by ±3.53 percent (p. 25). Overall, the uncertainty (statistical range of error that indicates the risk of measurement error) in heating value and relative density in this study was ±5.09 percent, which, across the board, could amount to ±$127 million in royalties based on 2008 total onshore Federal and Indian royalty payments of about $2.5 billion (p. 16).

The study concluded that heating value variability is unique to each gas meter and is not related to reservoir type, production type, age of the well, richness of the gas, flowing temperature, flow rate, or several other factors that were included in the study (p. 17). The study also concluded that more frequent sampling increases the accuracy of average annual heating value determinations (p. 11).

This rule strengthens the BLM's regulations on measuring heating value and relative density by requiring operators to sample all meters more frequently than required under Order 5, except very-low-volume meters (measuring 35 Mcf/day or less), for which annual sampling remains sufficient. Low-volume FMPs (measuring more than 35 Mcf/day, but less than or equal to 200 Mcf/day) must be sampled every 6 months; high-volume FMPs (measuring more than 200 Mcf/day, but less than or equal to 1,000 Mcf/day) must initially be sampled every 3 months; very-high-volume FMPs (measuring more than 1,000 Mcf/day) must initially be sampled every month. In developing this rule, the BLM realized that a fixed sampling frequency may not achieve a consistent level of uncertainty in heating value for high-volume and very-high-volume meters. For example, a 3-month sampling frequency may not adequately reduce average annual heating value uncertainty in a meter which has exhibited a high degree of variability in the past. On the other hand, a 3-month sampling frequency may be excessive for a meter that has very consistent heating values from one sample to the next. If a high- or very-high-volume FMP did not meet these heating-value uncertainty limits, the BLM will adjust the sampling frequency at that FMP until the heating value meets the uncertainty standards. If a very-high-volume FMP continues to exceed the uncertainty standards, the final rule includes a provision that allows the BLM to require the installation of composite samplers or on-line gas chromatographs (GCs), which automatically sample gas at frequent intervals.

The rule also sets new average annual heating value uncertainty standards of ±2 percent for high-volume FMPs and ±1 percent for very-high-volume FMPs. The BLM established these uncertainty thresholds by determining the uncertainty at which the cost of compliance equals the risk of royalty underpayment or overpayment.

In addition to prescribing uncertainty standards and more frequent sampling, this rule also improves measurement and reporting of heating values and relative density by setting standards for gas sampling and analysis. These standards specify sampling locations and methods, analysis methods, and the minimum number of components that must be analyzed. The standards also set requirements for how and when operators report the results to the BLM and the Office of Natural Resources Revenue (ONRR), and define the effective date of the heating value and relative density that is determined from the sample.

2. Meter Inspections (§ 3175.80)

This rule requires operators to periodically inspect the insides of meter tubes for pitting, scaling, and the buildup of foreign substances, which could bias measurement. Existing regulations do not address this issue. Under this rule, basic meter tube inspections are required once every 5 years at low-volume FMPs, once every 2 years at high-volume FMPs, and

yearly at very-high-volume FMPs. The BLM has the ability to increase this frequency if a basic inspection identifies any issues or if the meter tube operates in adverse conditions, such as with corrosive or erosive gas flow. If the basic inspection indicates the presence of pitting, obstructions, or a buildup of foreign substances, at low-volume FMPs the operator must clean the meter tube of obstructions and foreign substances; at high- and very-high-volume FMPs, the operator must conduct a detailed meter tube inspection. A detailed meter-tube inspection involves removing or disassembling the meter run. Operators must repair or replace meter tubes that no longer meet the requirements in this rule.

3. Meter Verification or Calibration (§§ 3175.92 and 3175.102)

The rule changes routine meter verification or calibration requirements from current requirements under Order 5. Verification frequency is decreased at all very-low-volume FMPs and low-volume FMPs using electronic gas measurement (EGM) systems. Verification frequency is unchanged from current regulations for low-volume FMPs using mechanical recorders and high- and very-high-volume FMPs. Currently, under Order 5, all meters are required to undergo routine verification every 3 months, regardless of the throughput volume.

The rule restricts the use of mechanical chart recorders to low- and very-low-volume FMPs because the accuracy and performance of mechanical chart recorders is not defined well enough for the BLM to quantify the overall measurement uncertainty. Between 80 and 90 percent of gas meters at Federal onshore and Indian FMPs use EGM systems.

4. Requirements for EGM Systems (§§ 3175.31, 3175.100 Through 3175.104 and §§ 3175.130 Through 3175.144)

Although industry has used EGM systems for about 30 years, Order 5 does not currently address them. Instead, the BLM has regulated their use through statewide NTLs, which do not address many aspects unique to EGMs, such as volume calculation and data-gathering and retention requirements. This rule includes many of the existing NTL requirements for EGM systems and adds some new requirements relating to onsite information, gauge lines, verification, test equipment, calculations, and information generated and retained by the EGM systems. The rule includes a significant change in those requirements by revising the maximum flow-rate uncertainty that is currently allowed under existing statewide NTLs. Under the NTLs, flow-rate equipment at FMPs that measure more than 100 Mcf/day is required to meet a ±3 percent uncertainty level. The rule maintains that level of uncertainty for high-volume FMPs although the threshold is raised to 200 Mcf/day. Under this rule, equipment at very-high-volume FMPs must comply with a new ±2 percent uncertainty requirement. Flow-rate equipment at FMPs that measure less than 200 Mcf/day is exempt from these uncertainty requirements. The BLM is maintaining this exemption because it believes that compliance costs for these FMPs could cause some operators to shut in their wells instead of making improvements. The BLM believes the royalties lost by such shut-ins would exceed any royalties that might be gained through upgrades at such facilities.

One area that this rule addresses, which is not addressed by existing NTLs, is the accuracy of transducers and flow-computer software used in EGM systems. Transducers send electronic data to flow computers, which use that data, along with other data that are programmed into the flow computers, to calculate volumes and flow rates. Currently, the BLM must accept transducer manufacturers' claimed performance specifications when calculating uncertainty. Neither the American Petroleum Institute (API) nor the Gas Processors Association (GPA) has standards for determining these performance specifications. For this reason, the rule requires operators or manufacturers to “type test” transducers at a qualified testing facility using a standard testing protocol defined in this rule or, for transducers that are already in use at FMPs, submit existing test data to the BLM for review. The purpose of this review is to quantify the uncertainty of the transducers using actual test data, rather than relying on the manufacturer's performance specifications. The BLM will then incorporate the test results into the calculation of overall measurement uncertainty based on each transducer tested. The rule also requires operators or manufacturers to test flow computers and flow-computer software at qualified testing facilities, using a standard testing protocol defined in this rule, to assess the ability of those flow-computers and software versions to accurately calculate flow rate, volume, and other values that are used in the BLM's verification process. Only those flow computers and flow computer software versions that demonstrate the ability to perform these calculations within the tolerances established by the BLM will be allowed for use on Federal and Indian leases.

An integral part of the BLM's evaluation process is the Production Measurement Team (PMT), made up of measurement experts designated by the BLM.

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The rule requires that the PMT review the results of type testing done on transducers and flow-computer software and make recommendations to the BLM. If approved, the BLM will post the make, model, and range of the transducer or software version on the BLM website as being appropriate for use. The BLM will also use the PMT to evaluate and make recommendations on the use of other new types of equipment, such as flow conditioners and primary devices, new measurement sampling, or analysis methods.

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The PMT will be distinguished from the DOI's Gas and Oil Measurement Team (GOMT), which consists of members with gas or oil measurement expertise from the BLM, the ONRR, and the Bureau of Safety and Environmental Enforcement (BSEE). BSEE handles production accountability for Federal offshore leases. The DOI GOMT is a coordinating body that enables the BLM and BSEE to consider measurement issues and track developments of common concern to both agencies. The BLM will not use a dual-agency approval process for the use of new measurement technologies for onshore leases. The BLM anticipates that members of the BLM PMT will participate as a part of the DOI GOMT.

II. Discussion of Final Rule and Comments on the Proposed Rule

A. General Overview of Final Rule

As discussed in the Background and Overview section of this preamble, the provisions of Order 5 have not kept pace with industry standards and practices, statutory requirements, or applicable measurement technology and practices. This final rule updates and replaces those requirements by establishing the minimum standards for accurate measurement and proper reporting of all gas sold from Federal and Indian (except the Osage Tribe) leases, units, unit PAs, and areas subject to CAs, by providing a system for production accountability by operators, lessees, purchasers, and transporters. 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 5 appears in the proposed rule at 80 FR 61650 (October 13, 2015).

ER17NO16.027

ER17NO16.028

ER17NO16.029

ER17NO16.030

ER17NO16.031

ER17NO16.032

ER17NO16.033

ER17NO16.034

ER17NO16.035

B. General Overview of Comments Received

This section presents and responds to general comments on the proposed rule received by the BLM. Comments on specific provisions of the proposed rule are addressed in the Section-by-Section analysis as part of the explanation of the provisions included in this final rule.

Administrative Delay

The BLM received numerous comments stating the new rule will cause additional delays and backlogs for both the BLM and industry because of all the additional paperwork and inspections required by the new rule. The BLM has analyzed and disclosed the burdens for industry in the Economic and Threshold Analysis prepared as part of this rulemaking process and in the Paperwork Reduction Act portion of this preamble. Some of the burdens are usual and customary, since they are required by gas sales contracts and/or industry standards. The BLM has determined that the remaining burdens are necessary in order to ensure accurate measurement and reporting.

The BLM also acknowledges that implementation of the rule will require additional BLM staff time. The BLM has analyzed and disclosed the Federal burdens that will result from this rule. The BLM is taking steps to address the issue of streamlining administrative processes, including strategic investments in technology and repeatedly requesting additional resources during the appropriations process. The BLM will continue to pay attention to this issue during the implementation period. The BLM did not make any changes to the rule in response to these comments.

Inspection and Enforcement Handbook

As was stated in the preamble of the proposed rule, this final rule removes the enforcement, corrective action, and abatement period provisions of Order 5. 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 Authorized Officer (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 explained in the proposed rule, this change allows the BLM to make a case-by-case determination of the severity of a particular violation, based on applicable definitions in the regulations.

Several comments objected, saying that this course of action was inconsistent with the APA. One such commenter stated its objection as follows:

BLM's proposal would completely eliminate the enforcement infrastructure prescribed in Onshore Order No. 5, including major and minor violations, corrective actions, and abatement periods. . . . Removing the enforcement provisions from the realm of transparent, publicly reviewable regulations that were promulgated with notice and comment, and concealing them in non-public policy documents that can be altered in the absence of public input, is inconsistent with the requirements of the APA. BLM-2015-0005-0058 (December 15, 2015).

In general, these comments misunderstand the nature of the Internal Inspection and Enforcement Handbook that the BLM will develop. The new Handbook will not establish new obligations to be imposed on the regulated community. Those obligations are spelled out in applicable regulations, orders, and permits, as well as the terms and conditions of leases and other agreements. Moreover, 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 Enforcement Handbook, that will provide the legal basis for the BLM's enforcement actions. Put another way, BLM's enforcement actions must be consistent with these regulations irrespective of what may be contained in its Inspection and Enforcement Handbook. It should also be noted, it is this rule and other duly promulgated regulations that establish these standards to which an operator will be held consistent with Administrative Procedure Act (APA) requirements.

As to the concern about public notice and comment processes, it should be noted that internal guidance documents that direct agency personnel on how to implement existing agency policies are not required to follow the public notice and comment process. No change to the rule resulted from these comments.

One commenter suggested that the BLM should retain discretionary case-by-case enforcement of requirements as is currently done under Order 5. Although the BLM disagrees with the premise of the comment regarding the existing requirements of Order 5, the intent of the Inspection and Enforcement Handbook is to provide guidance to BLM inspectors on how to apply the provisions of its oil and gas rules in a consistent manner. As noted above, it will not establish new requirements or obligations. It also will not alter the BLM's case-by-case discretion with respect to any particular enforcement action. The BLM did not make any changes to the rule based on this comment.

Several commenters suggested that the BLM should post the Inspection and Enforcement Handbook on the website. The BLM agrees with this comment and will post the enforcement handbook upon its completion, and will otherwise make it available to the public at any BLM office.

One commenter suggested that the BLM should develop the Inspection and Enforcement Handbook with input from industry. The BLM disagrees with this comment since the handbook is

intended to provide internal guidance to BLM inspectors. However, as the Handbook is developed, the BLM will determine the appropriate process to use, including consideration of appropriate opportunities to obtain input from stakeholders. The BLM did not make any changes to the rule as a result of this comment.

One commenter asked if the BLM will publish the Inspection and Enforcement Handbook at the same time as the final rule. For the preceding reasons, the BLM has determined that it is not necessary to release the handbook with this final rule. However, the BLM intends to develop the Handbook within 1 year of the effective date of the proposed rule, which is the earliest date by which the provisions of this rule will go into effect. The BLM did not make any changes to the rule as a result of this comment.

One commenter asked that the BLM provide the economic analysis of developing an Inspection and Enforcement Handbook instead of including enforcement actions in the rule and for moving away from the more discretionary enforcement approach to more immediate assessments. The BLM does not agree with the characterization of Order 5 and the current approach. Also, there have always been immediate assessments, and the BLM has simply expanded the list of actions potentially subject to an immediate assessment. With respect to the requested economic analysis, the BLM does not believe that there is any economic impact in removing enforcement guidance from the rule and placing it in an enforcement handbook. Additionally, because the BLM assumes compliance for purposes of assessing the impact of a rule, the BLM does not believe that it is appropriate to analyze the economic impacts of immediate assessments. The BLM did not make any changes to the rule as a result of this comment.

National Technology Transfer and Advancement Act of 1995

One commenter stated that, per the National Technology Transfer and Advancement Act (NTTAA), codified as a note to 15 U.S.C. 272, the BLM must adopt API standards in whole or justify to the Office of Management and Budget (OMB) why this does not meet the agency mission. The NTTAA directs agencies to utilize technical standards that are developed by voluntary consensus standards bodies. Some commenters argued that the NTTAA obligates the BLM to adopt all gas measurement standards developed by voluntary consensus standards bodies.

The commenters' assertion overstates the requirements of the NTTAA. The NTTAA does not require an agency to adopt voluntary consensus standards where it would be “impractical.” NTTAA section 12(d)(3). The OMB's guidance for implementing the NTTAA defines “impractical” to include circumstances in which use of certain standards “would fail to serve the agency's regulatory, procurement, or program needs; be infeasible; be inadequate, ineffectual, inefficient, . . . or impose more burdens, or be less useful, than those of another standard” (OMB Circular A-119, p. 20). Furthermore, the OMB has explained that the NTTAA “does not preempt or restrict agencies' authorities and responsibilities to make regulatory decisions authorized by statute . . . [including] determining the level of acceptable risk and risk-management, and due care; setting the level of protection; and balancing risk, cost, and availability of alternative approaches in establishing regulatory requirements” (OMB Circular A-119, p. 25). The BLM has studied the available voluntary consensus standards for gas measurement and has chosen to adopt a workable suite of these standards that will meet the BLM's regulatory needs in an effective and feasible manner. To adopt all available voluntary consensus standards would be “impractical” in that it would involve the adoption of standards the BLM has judged to be less effective, less feasible, or less useful. In addition, the commenters' reading of the NTTAA would, contrary to OMB guidance, inappropriately preempt the BLM's statutory authority to promulgate rules and regulations that it deems “necessary” to accomplish the purposes of the applicable statutory directives, including the Mineral Leasing Act (MLA) and the Federal Oil and Gas Royalty Management Act (FOGRMA).

Retroactivity

Several commenters argued that the rule is impermissibly “retroactive.” These comments argued that the rule is retroactive because it will apply to existing measurement systems that predate the rule's effective date. 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 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 final rule does not attach any new legal consequence to the use of existing measurements systems prior to the rule's effective date. As the U.S. Court of Appeals for the District of Columbia 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).

This rule does not impose liability for nor require changes to measurements made prior to the rule's enactment; rather the rule requires measurements taken as required by the rule after the effective date of the rule (that is, going forward) at both new and existing facilities to satisfy the performance standards established by the final rule. Thus, despite the fact that this rule may require operators to update or modify their existing measurement systems, the rule is prospective—not retroactive—in nature.

Availability of Material Incorporated by Reference

The BLM received comments arguing that the incorporated API and GPA standards were not adequately available to the public during the comment period. The BLM's obligation to make the incorporated standards available to the public derives from the Freedom of Information Act (FOIA), which requires agencies to publish “substantive rules of general applicability adopted as authorized by law” in the

Federal Register

(5 U.S.C. 552(a)(1)(D)). Under FOIA, “matter reasonably available to the class of persons affected thereby is deemed published in the

Federal Register

when incorporated by reference therein with the approval of the Director of the Federal Register” (

id.

section 552(a)(1)). For the following reasons, the industry standards incorporated by reference in the final rule are—and have been—“reasonably available” to the public as required by FOIA. As discussed in the notice of proposed rulemaking, all of the API and GPA standards incorporated by reference in the rule have been available for inspection at the BLM's Washington, DC office and at all BLM offices with jurisdiction over oil and gas activities

(80 FR 61646, 61655). All of the incorporated API standards have also been available for inspection at API's Washington, DC office; API has also provided free, read-only access to some of the incorporated standards online (

id.

). All of the incorporated GPA standards have also been available for inspection at GPA's Tulsa, Oklahoma office (

id.

). Finally, all of the incorporated API and GPA standards have been, and continue to be, available for purchase from API and GPA.

Some commenters stated that local BLM offices were unable to provide them with access to the incorporated standards. These occurrences resulted from the fact that, although all the local BLM offices have electronic access to the incorporated standards, not all local office personnel were aware of how to access the incorporated standards. The BLM plans to carry out a training program to ensure that personnel at local BLM offices can readily access the incorporated standards and provide them to interested members of the public when requested. Given the multiple avenues available for accessing the incorporated standards, we do not believe that the handful of reported occurrences in which staff were unable to access the standards prevented stakeholders from accessing and reviewing the documents as part of their review of the proposed rule. Therefore the BLM has met its obligations under FOIA and the APA with respect to those standards.

It should be noted that the BLM received numerous comments regarding the adoption of specific API and GPA standards in the proposed rule. Most of these comments are addressed in connection with the relevant sections of the rule (§§ 3175.30, 3175.40, 3175.110, 3175.130, and 3175.140; see section II. C of this preamble below).

Duplication of State Rules

The BLM received one comment stating that this rule is duplicative of State rules. During the development of this rule, the BLM researched existing State rules related to gas measurement and crafted the rule to avoid conflicts with applicable State standards. The commenter did not identify any inconsistencies.

Moreover, the BLM is issuing this rule in fulfillment of its fiduciary obligation to assure that Federal and Indian gas is properly measured and that all royalties due under Federal law are paid. The fact that some States may have similar requirements does not render this rule duplicative, as the BLM has an independent responsibility to meet its fiduciary obligations for the resources it manages.

Definitions Hard To Find

One commenter stated that separately publishing the proposed rules to update and replace Order 3 (site security), Order 4 (oil measurement), and Order 5 made the definitions hard to find. The BLM does not agree with this comment. The proposed rule to replace Order 3 also established a new part 3170 that will contain all three rules to replace Orders 3, 4, and 5, including a definitions section containing provisions common to all three rules. The proposed rules, in most instances, contained all of the key definitions unique to each subpart. For example, definitions specific to gas measurement are found in the definitions section of this rule. Definitions that are used in two or more subparts are found in the definitions section of subpart 3170 in order to reduce redundancy and ensure consistency. Additionally, the BLM extended the comment periods for all three proposed rules to ensure that they were all open and available for comments at the same time.

Moreover, since all three final rules to replace Orders 3, 4, and 5 will appear in the CFR in a new part 3170, this will ensure that the definitions will be easy to find during implementation. The BLM did not make any changes to the rule in response to this comment.

Not Enough Information

The BLM received several comments stating the proposed rule did not contain a description of all the calculations, assumptions, and enforcement actions, nor an explanation of why certain industry standards were or were not incorporated by reference. The BLM believes that a thorough description of the assumptions and rationale for the proposed changes was provided in the preamble to the proposed rule. The BLM also published heating value variability and uncertainty calculations in the BLM Gas Variability Study, which was referenced numerous times in the preamble and posted as a supporting document on the

www.regulations.gov

Web site, along with the proposed rule. The BLM has been enforcing flow-rate uncertainty standards since 2009 and the calculations that the BLM uses to determine uncertainty have been publicly available since that time. Additionally, all of the economic assumptions used in the proposed rule were also posted on the

www.regulations.gov

Web site in a supporting document, along with the proposed rule (“Proposed 3175 Economic Analysis”).

With respect to incorporated industry standards, the BLM incorporated the standards that are relevant and appropriate to the proposed rules. These include standards that directly relate to the measurement of volume and heating value typical of the technologies currently used at BLM points of royalty measurement (now called FMPs). To adopt all available voluntary consensus standards would be “impractical” in that it would involve the adoption of standards the BLM has judged to be less effective, feasible, or useful, or standards that cover equipment and processes that are very rarely used for gas measurement at the lease level, such as those covering Coriolis meters, turbine meters, or ultrasonic meters. That said, the PMT may, on a case-by-case basis, consider recommending for approval the use of such standards in lieu of compliance with the identified standards if and when it is asked to review such requests for approval to employ such standards in the field in the future. The commenters' questions regarding enforcement were addressed previously. The BLM did not make any changes to the rule based on these comments.

Only Use Performance Goals

Numerous comments objected to the equipment standards in the proposed rule and suggested that the BLM only rely on performance goals because the equipment standards will become obsolete as technology progresses. The BLM agrees that some of the equipment standards may become obsolete as technology progresses. As a result, the BLM included performance standards in § 3175.31 of the final rule (§ 3175.30 in the proposed rule), along with a process for the BLM—through the PMT—to assess and approve new technologies over time. The BLM also agrees that, with appropriate oversight, performance goals should be sufficient without the explicit equipment standards. The BLM fully supports the concept of allowing industry to determine the best and most cost-effective way to meet performance goals. As a result, this rule allows the BLM to approve technologies and processes that are different from the specific equipment standards in the rule as long as they meet or exceed the stated performance goals in § 3175.31. It should be noted that unlike the existing variance process, which requires local field office approval on a case-by-case basis, the PMT process outlined in the proposed and final rules is structured such that the PMT needs to review and approve technology only once on a

nation-wide basis; subsequently, facilities will be able to rely on those PMT reviews and approvals as long as they comply with any applicable conditions of approval.

While the BLM recognizes the value of performance-based standards, it is nevertheless providing equipment standards for two reasons. First, the BLM has over 4,000 operators of Federal and Indian leases and the vast majority of these operators are small companies without measurement personnel on staff. Requiring a small operator to achieve, for example, an overall meter measurement uncertainty of ±3 percent, without any equipment standards, would likely require the operator to hire measurement specialists to determine the equipment and operating conditions necessary to meet the uncertainty requirement on their leases. The BLM equipment standards provide a “cookbook” for how to achieve the performance goals established in the rule for operators that do not have the expertise, resources, or interest in innovating new technology or processes to meet a performance goal. In the BLM's experience, this cookbook approach is useful to smaller operators and is a feature of Order 5 that was retained in the final rule.

Second, it would be virtually impossible for the BLM to enforce a performance goal without a full understanding of the technology and process the operator is using to achieve that goal. In addition, this would require customized enforcement procedures for every meter installation. For the BLM to implement this approach, it would need to approve all new FMP installations on a case-by-case basis, which would include: (1) Conducting a detailed analysis on the operator's proposal regarding how they would achieve the performance goals in the rule; and (2) Developing the enforcement procedures specific to that approval. This would unnecessarily drive up costs for both the BLM and industry and could result in backlogs of new measurement applications, both of which the BLM (and likely industry as well) would prefer to avoid.

Under this rule, the BLM has to approve only those technologies and processes that are different from the equipment standards listed in the rule. The BLM did not make any changes to the rule based on these comments.

New Rule Not Needed

The BLM received several comments stating that Order 5 works well as written and a new rule is not needed. The BLM disagrees with these comments. Order 5 incorporates one industry standard—AGA Report No. 3 from 1985. This standard addresses the installation requirements for orifice meters and the calculation of flow rate from an orifice meter. Installing an orifice meter using this standard can cause significant bias in measurement. This standard has been revised numerous times since 1985 based on new data and better calculation techniques. In addition, Order 5 does not incorporate standards for the calculation of volume from orifice meters, the calculation of supercompressibility used in flow-rate calculations, or the collection and analysis of gas samples. Further, Order 5 does not state overall performance goals or include a process to analyze and apply new technology on a national basis. Lastly, Order 5 does not cover EGM systems that now make up approximately 90 percent of all gas meters in the field. These deficiencies are what led the Subcommittee, the OIG, and the GAO to conclude that the BLM's gas measurement regulations are outdated and in need of an update. Management of onshore Federal oil and gas resources is on the GAO's High Risk List, in large part due to its outdated measurement regulations. The BLM did not make any changes to the rule as a result of these comments. Further evidence regarding the inadequacy of Order 5 can be found in the fact that the BLM has had to issue NTLs supplementing its requirements.

One commenter stated that no third-party proof exists to demonstrate that the proposed changes would improve measurement. The BLM did not make any changes to the rule based on this comment. While the rulemaking process does not require third-party confirmation that the proposed changes would improve measurement, the BLM is confident that the rule will result in substantial improvements to both the accuracy and verifiability of measurement.

For example, existing Order 5 has only one requirement relating to the determination of heating value—that it be determined once per year. Order 5 has no requirements as to where the sample is taken, how it is taken, how it is analyzed, or how it is reported. Nor does Order 5 incorporate any industry standards relating to sampling and analysis, even though those have been developed. As illustrated in the Background Section of this preamble, inaccurate heating value determination has the same impact on royalty calculations as errors in volume determination. As explained in the preamble to the proposed rule, the BLM has shown that Order 5's existing requirement to sample once per year is inadequate. BLM's Gas Variability Study demonstrated significant variability in heating value for individual facilities that would not be captured by once per year sampling and that may be correlated to the lack of any BLM standards on how it is determined. This final rule, on the other hand, incorporates five consensus industry standards relating to the sampling and analysis of heating values and sets standards on heating value uncertainty, sample probes, sample cylinders, GCs, and reporting.

One commenter stated that the new rule will not aid in consistency. The BLM disagrees with this comment. Order 5 included a variance process to address new technology and to allow the BLM to approve alternate methodology that accomplished the goals of the Order. Unfortunately, Order 5 did not state what those goals were and left the review and approval process at the field office level. This resulted in inconsistent review of variances from office to office, an issue which was raised by industry, the GAO, and the OIG. This final rule establishes a new national process for the review and approval of new technology and/or alternate measurement methodologies through a centralized team, the PMT. Once approved, the BLM will post the device or process on the BLM website along with any conditions for its use developed by the PMT. Operators can rely on those approvals without seeking a subsequent authorization. This centralized review will dramatically improve consistency over the current process. The BLM did not make any changes to the rule as a result of this comment.

Use Variance Process for Small Operators

One commenter suggested a variance process for small operators who cannot comply with API standards. Consistent with the comment, the final rule includes a standard process for any operator to obtain BLM approval for an alternate methodology, as long as that methodology meets or exceeds the performance goals set out in § 3175.31. Recognizing the economics of lower-volume properties, the final rule adopts changes relative to the proposed rule that will reduce the requirements on those properties, which will reduce compliance costs for operators, many of which could be smaller operators. Those specific changes are discussed later in the preamble, in the Section-by-Section analysis. The BLM did not make any changes to the rule as a result of this comment.

Transporters

The BLM received numerous comments objecting to the provision in the proposed rule to require transporters to keep measurement records. It should be noted at the outset that this change was the result of statutory requirements imposed by Congress under FOGRMA and the changes in the proposed rule are consistent with that statutory direction. Commenters objected to the requirement that both the operator and the transporter keep duplicate records and noted that transporters will have to modify their computer systems to comply with BLM requirements, including the requirement to store the FMP number. Based on other comments (see the discussion of §§ 3175.101(b)(4) and 3175.104(a)(1) in section II.C. of this preamble), the BLM has decided that it will not require operators, purchasers, or transporters to include the FMP number as part of the flow-computer display or include it on audit trail records. Parties may continue to use unique meter station identifiers. The FMP number is now only required on the Oil and Gas Operations Reports (OGORs) that the operator submits to ONRR. The BLM realizes that this requirement could result in duplicate sets of records in some cases. However, when the BLM audits an FMP that is owned by a transporter or purchaser rather than the operator, the operator may not have access to the complete audit trail. In these cases, the records held by the transporter would not be duplicates.

A few commenters asked for clarification of which records the transporter or purchaser will be responsible for maintaining. The transporter or purchaser is responsible for maintaining all records required by this subpart for FMPs that are owned by the transporter or purchaser for the timeframes listed in 43 CFR 3170.7. The BLM did not make any changes to the rule based on these comments.

One commenter stated that there is no indication that the records currently maintained by the transporter or purchaser are inadequate. If the records owned by the transporter or purchaser are adequate, as implied by the comment, then this rule should not have any additional impact on the transporter or purchaser. The BLM did not make any changes to the rule based on this comment.

One commenter stated that transporters and purchasers should not be subject to immediate assessments. The BLM agrees with this comment and has removed purchasers and transporters from the immediate assessment section in § 3175.150 (see discussion under that section).

Will Deter Development and Reduce Royalty

The BLM received many comments stating that the proposed rule would deter development on Federal and Indian oil and gas leases and result in lower royalty due to operators shutting in their production rather than complying. The commenters stated that the cost, complexity, delays, and new reporting requirements are primary reasons. One commenter stated that the rule would be especially burdensome for small operators. In response to comments on specific parts of the proposed rule, the BLM made numerous changes in the final rule that should provide significant economic relief to operators on Federal and Indian leases. These changes include:

• The threshold between very-low- and low-volume is raised from 15 Mcf/day to 35 Mcf/day, and the threshold between low- and high-volume is raised from 100 Mcf/day to 200 Mcf/day;

• Existing meter tubes at low- and high-volume FMPs are grandfathered

7

from the construction, length, and eccentricity requirements in § 3175.80(f) and (k), and from API 14.3.2, Subsection 6.2, although they still must comply with the 1985 AGA Report No. 3 standards (very-low-volume FMPs are exempt from meter tube requirements altogether);

7

The term “grandfathered” means that meters in use prior to the effective date of the rule do not have to comply with those portions of the rule.

• Flow-computer software at very-low-, low-, and high-volume FMPs are grandfathered and flow computers no longer have to display the FMP number;

• Accounting systems no longer have to include the FMP number;

• Composite sampling systems or on-line GCs are no longer required on high-volume FMPs, and they were never required for very-low- and low-volume FMPs;

• Gauge lines with a

3/8

-inch nominal diameter are acceptable;

• Implementation of the requirement for PMT approval of existing equipment and gas analysis input into the Gas Analysis Reporting and Verification System (GARVS) is delayed for 2 years after the effective date of the final rule;

• Long-term stability tests for transducers is longer required;

• The PMT has the ability to approve existing transducers using existing data from manufacturers;

• Multiple analyses for laboratory GCs are no longer required; and

• C9+ analysis is only required periodically for high- and very-high-volume FMPs and only if the mole percentage for C6+ exceeds 0.5 percent.

Several commenters stated that the new rules could reduce royalty by increasing the costs of metering, which, in turn, operators could claim as a transportation deduction. The BLM consulted ONRR on this comment and ONRR confirmed that there are no circumstances in which an operator could claim the costs of metering as a transportation deduction even if the meter was owned by a transporter or purchaser. The BLM did not make any changes to the rule as a result of this comment.

Costs Underestimated

The BLM received a number of comments stating that the Economic and Threshold Analysis did not adequately account for all costs associated with the proposed rule. Several commenters said that the estimated cost of the rule should include the costs to the government of reduced royalty payments, as well as lost tax revenues that will result from reduced State and local employment. However, the premise of this argument is based upon the commenter's assumption that operators would have had to shut in wells as a result of the rule. The numerous revisions to reduce the cost of the final rule described above will significantly reduce costs from the requirements of the proposed rule. The BLM does not believe that a significant number of shut-ins will occur as a result of this rule. Although the BLM made significant changes to the rule based on concerns over cost, the BLM did not make any changes based on these specific comments.

Cost-Benefit Analysis

Several commenters stated that the BLM should have done a cost-benefit analysis of the rule in which the estimated costs are compared against the resultant improvement in expected royalty revenue. There are several flaws in this argument. Notably, commenters are presuming that the only purpose of the rule is to eliminate measurement bias, and that FMPs are currently biased to read low. Bias is mismeasurement that results in a measured quantity that is either predictably higher than or predictably lower than the actual value of the quantity. If the BLM were aware that FMPs were biased to read low, then the commenter's assertions would be correct. In other words, if the sole intent of the rule were to eliminate bias to the low side and the BLM were able to quantify that bias, then the BLM could perform a cost-benefit analysis comparing the cost of the rule to the

increase in royalty payments resulting from the elimination of the bias to the low side. However, the BLM has no data to support the proposition that FMPs are biased exclusively to the low side (with the exception of Btu reporting and potentially also gas sampling practices). In addition, the elimination of bias, either high or low, is only one of the performance goals of the rule. The other performance goals are to establish uncertainty limits for high- and very-high-volume FMPs and to require that all aspects of the measurement are independently verifiable by the BLM. Together, these performance goals are designed to ensure that the American public and Indian tribes and allottees are receiving a fair return for gas produced from their leases.

Whether the rule will result in an increase in royalty, a decrease in royalty, or no change in royalty was not a consideration in the rule-making process. The rule is intended to obtain accurate measurement of the gas produced from Federal and Indian leases. The BLM did not make any changes to the rule based on these comments.

Withdraw Rule

Two commenters recommended that the BLM withdraw the rule because it is incomplete and potentially devastating to the industry. The commenters did not elaborate as to why the rule is incomplete or why it would potentially be devastating to the industry. The BLM believes the proposed rule was complete and met all legal requirements of a proposed rule under the APA. The BLM also made significant changes to the proposed rule aimed at reducing costs, especially at low-volume facilities. These specific changes are discussed elsewhere. The BLM did not make any changes to the rule as a result of these comments.

Tone

One commenter objected to the tone of the rule stating that the rule implies that operators are intentionally trying to underpay royalty. The commenter did not provide any specific examples. The BLM does not agree with this comment and did not intend to make such an implication. The BLM recognizes that measurement error goes in both directions and, as result, it might result in either over- or under-reporting of production. The BLM did not make any changes to the proposed rule as a result of this comment.

Executive Order 13211

The BLM received several comments stating that no data were presented to support the assertion that the rules will not affect the energy supply, as required by Executive Order (E.O.) 13211. The commenters stated that the rule will result in delays in distribution due to the backlog of new equipment that the BLM is requiring for existing FMPs. One commenter stated that the BLM needs to study the effects of the rule on transportation.

E.O. 13211 requires an agency to prepare a “Statement of Energy Effects” when it undertakes a “significant energy action.” There are two ways in which an agency's action can constitute a significant energy action: (1) The action is a “significant regulatory action” under E.O. 12866 if it is “likely to have a significant adverse impact on the supply, distribution, or use of energy”; or, (2) The action is designated as a significant energy action by the Office of Information and Regulatory Affairs (OIRA). This rule is not a significant energy action because it will not have a significant adverse impact on the supply, distribution, or use of energy, and it has not been designated as a significant energy action by OIRA. The BLM's conclusion that this rule is not a significant energy action is based on its analysis of the economic impact of the proposed rule.

Additionally, in response to comments received, the BLM made numerous changes to the proposed rule that will reduce compliance costs and the potential for any approval backlogs for new equipment that may have resulted from the proposed rule. These changes include:

• The grandfathering of 98.7 percent of all meter tubes in place at FMPs as of January 17, 2017 from having to meet the construction and installation standards of API 14.3.2 (2000);

• The grandfathering of 88.7 percent of all flow computers in place at FMPs as of January 17, 2017 from having to use the latest flow-rate calculation methods of API 14.3.3 (2013);

• The grandfathering of 100 percent of all transducers in place as of January 17, 2017, from the testing protocol required in § 3175.43, if the manufacturers submit existing test data to the PMT and the BLM approves the transducer based on that existing data; and

• Elimination of the requirement for flow computers to display the FMP number, which may have required some older model flow computers to be replaced.

C. Section-by-Section Analysis and Comment Responses

This section describes the various regulatory changes made by this final rule. First, it describes the content of the specific sections of subpart 3175, explains any changes between the proposed and final rules, and responds to section-specific comments on the proposed rule received by the BLM during the comment period. Following that discussion, it describes changes and revisions being made to 43 CFR 3162.7-3, 3163.1, and 3164.1. The proposed rule to replace Order 5 also proposed changes to 43 CFR 3163.2 and 3165.3. The proposed revisions are addressed in the final rule to replace Order 3 (being released concurrently with this rule) and are not discussed further here.

§ 3175.10—Definitions and Acronyms

Section 3175.10 includes numerous new definitions unique to this rule because much of the terminology used in the rule is technical in nature and may not be readily understood by all readers or may have a specific meaning in the context of this rule. As explained in the preamble to the proposed rule, the BLM also added other definitions because their meanings, as used in the rule, may be different from what is commonly understood, or the definition includes a specific regulatory requirement.

Definitions of terms commonly used in gas measurement or which are already defined in 43 CFR parts 3000, 3100, 3160, or subpart 3170 are not discussed in this preamble.

The rule defines the terms “primary device,” “secondary device,” and “tertiary device,” which together measure the amount of natural gas flow. All differential types of gas meters consist of at least a primary device and a secondary device.

Primary Device

The “primary device” is the equipment that creates a measureable and predictable pressure drop in response to the flow rate of fluid through the pipeline. It includes the pressure-drop device, device holder, pressure taps, required lengths of pipe upstream and downstream of the pressure-drop device, and any flow conditioners that may be used to establish a fully developed symmetrical flow profile.

A flange-tapped orifice plate is the most common primary device found on Federal and Indian leases. It operates by accelerating the gas as it flows through the device, similar to placing one's thumb at the end of a garden hose. This acceleration creates a difference between the pressure upstream of the orifice and the pressure downstream of the orifice, which is known as differential pressure. It is the only

primary device that is approved in Order 5 and in this rule and would not require further specific approval. Other primary devices, such as cone-type meters, operate much like orifice plates and the BLM could consider them for approval under the requirements of § 3175.47.

One commenter recommended that the BLM include linear meters in the definition of “primary device.” The definition of primary device in the proposed rule was specific to differential-type meters. The BLM did not make any changes to the rule based on this comment. The rule allows the PMT to recommend approval of linear devices by make, model, and size. In its recommendation, the PMT can include requirements for a linear meter along with a definition of a linear-meter primary device, if needed. However, the performance standards in this rule are based around differential-type meters. As a result, there are many requirements pertaining specifically to the primary device of differential-type meters. A definition of “primary device” is in § 3175.10 of the rule to avoid having to describe what a primary device is every time it is mentioned in the rule. Adding linear meters to the definition would make the requirements in the rule confusing and cumbersome. For example, § 3175.47 requires operators or manufacturers to test primary devices other than orifice plates under API 22.2, which is specific to differential types of primary devices. If linear-meter primary devices were added to the definition, then the requirement in § 3175.47 would have to specify that it applies only to differential types of primary devices, largely defeating the purpose of having the definition, especially considering there are no current or proposed API testing protocols for linear meters.

Secondary Device

The “secondary device” measures the differential pressure along with static pressure and temperature. The “secondary device” consists of the differential-pressure, static-pressure, or temperature transducers in an EGM system or a mechanical recorder (including the differential pressure, static pressure, and temperature elements, and the clock, pens, pen linkages, and circular chart). The BLM did not receive any comments on this definition.

Tertiary Device

In the case of an EGM system, there is also a “tertiary device,” namely, the flow computer and associated memory, calculation, and display functions, which calculates volume and flow rate based on data received from the transducers and other data programmed into the flow computer. The BLM did not receive any comments on this definition.

Self-Contained Versus Component-Type EGM Systems

The rule adds definitions for “component-type” and “self-contained” EGM systems. The distinction is necessary for the determination of overall measurement uncertainty. To determine overall measurement uncertainty under § 3175.31(a), it is necessary to know the uncertainty, or risk of measurement error, of the transducers that are part of the EGM system. Therefore, the BLM needs to be able to identify the make, model, and upper range limit (URL) of each transducer because the uncertainty of the transducer varies among makes, models, and URLs.

Some EGM systems are sold as a complete package, defined as a self-contained EGM system, which includes the differential-pressure, static-pressure, and temperature transducers, as well as the flow computer. The EGM package is identified by one make and model number. The BLM can access the performance specifications of all three transducers through the one model number, as long as the transducers have not been replaced by different makes or models. The BLM did not receive any comments on this definition.

Other EGM systems are assembled using a variety of transducers and flow computers and cannot be identified by a single make and model number. Instead, the BLM would identify each transducer by its own make and model. These are defined as “component” EGM systems. Component systems include EGM systems that started out as self-contained systems, but one or more of whose transducers have been changed to a different make and model. The BLM did not receive any comments on this definition.

Hydrocarbon Dew Point

The rule adds a definition for “hydrocarbon dew point” (HCDP). The HCDP is the temperature at which liquids begin to form within a gas mixture. Because it is not common to determine HCDPs for wellhead metering applications on Federal and Indian leases, the BLM established a default value using the gas temperature at the meter. By definition, the gas in a separator (if one is used) is in equilibrium with the natural gas liquids, which are at the HCDP. Cooler temperatures between the outlet of the separator and the primary device can result in condensation of heavy gas components, in which case the lower temperature at the primary device would still represent the HCDP at the primary device because the liquid and gas phases would again be in equilibrium. The AO may approve a different HCDP if data from an equation-of-state, chilled mirror, or other approved method are submitted. The BLM did not receive any comments on the definition of HCDP.

Upper and Lower Calibrated Limit

The rule adopts the definitions of “lower calibrated limit” and “upper calibrated limit” from the API Manual of Petroleum Measurement Standards (MPMS) 21.1. The upper and lower calibrated limits are the maximum and minimum values, respectively, for which the transducer was calibrated using certified test equipment. These terms replace the term “span” as used in the statewide NTLs for EFCs. The BLM did not receive any comments on these definitions.

Redundancy Verification

The term “redundancy verification” is added to address verifications done by comparing the readings from two sets of transducers installed on the same primary device. The BLM did not receive any comments on this definition.

FMP Categories

The proposed rule defined four terms to describe categories of FMPs: “Marginal volume,” “low volume,” “high volume,” and “very high volume.” The BLM proposed these categories for purposes of delineating applicable requirements based on the average flow rate measured by an FMP. The proposed categories were as follows: A marginal-volume FMP would have had an average flow rate of 15 Mcf/day or less; a low-volume FMP would have had an average flow rate greater than 15 Mcf/day, but less than or equal to 100 Mcf/day; a high-volume FMP would have had an average flow rate greater than 100 Mcf/day, but less than or equal to 1,000 Mcf/day; and, a very-high-volume FMP would have had an average flow rate greater than 1,000 Mcf/day. Based on comments received on the proposed rule, changes in market conditions, and additional internal analysis, the BLM has modified two of the three thresholds separating the categories in the final rule. The revised definitions in the final rule are as follows: A very-low-volume FMP (marginal-volume FMP in the proposed rule) has an average flow rate of 35 Mcf/

day or less; a low-volume FMP has an average flow rate greater than 35 Mcf/day, but less than or equal to 200 Mcf/day; a high-volume FMP has an average flow rate greater than 200 Mcf/day, but less than or equal to 1,000 Mcf/day. Very-high-volume FMPs continue to have an average flow rate greater than 1,000 Mcf/day. Increasing the thresholds at which an FMP is considered low- or high-volume reduces the number of facilities that are in higher-volume categories, which reduces the overall cost of the rule, because the rule imposes stricter measurement requirements on higher-volume facilities.

The proposed rule defined “marginal-volume FMP” as an FMP that measures a default volume of 15 Mcf/day or less. The BLM replaced the term “marginal-volume FMP” with “very-low-volume FMP” in the final rule to avoid confusion with other rules that use the term “marginal well.” As with the proposed rule, “very-low-volume” FMPs are exempt from many of the requirements in this rule.

The proposed rule's 15 Mcf/day threshold for a very-low-volume FMP was derived by performing a discounted cash-flow analysis to account for the initial investment of equipment that may be required to comply with the proposed standards applicable to facilities classified as low-volume FMPs. Assumptions in the discounted cash-flow model included:

• $12,000/year/well operating cost (not including measurement-related expense);

• Verification, orifice-plate inspection, meter-tube inspection, and gas sampling expenditures as would be required for a low-volume FMP in the proposed rule;

• A before-tax rate of return (ROR) of 15 percent;

• An exponential production-rate decline of 10 percent per year; and

• A 10-year equipment life.

ER17NO16.036

The model calculated the minimum initial flow rate needed to achieve a 15 percent ROR for various levels of investment in measurement equipment that would be required of a low-volume FMP. The ROR would be from the continued sale of produced gas that would otherwise be lost if the lease, unit PA, or CA were shut in. Figure 1 shows the results of the modeling for assumed gas sales prices of $3/MMBtu, $4/MMBtu, and $5/MMBtu.

Both wellhead spot prices (Henry Hub) and New York Mercantile Exchange futures prices for natural gas averaged approximately $4/MMBtu for 2013 and 2014. At that time, the U.S. Energy Information Administration projected the price for natural gas to range between $5/MMBtu and $10/MMBtu through the end of 2040, depending on the rate at which new natural gas discoveries are made and projected economic growth. Assuming a $4/MMBtu gas price from Figure 1, a 15 percent ROR could be achieved for meters with initial flow rates of at least 15 Mcf/day, for an initial investment in metering equipment up to about $8,000. For wells with initial flow rates less than 15 Mcf/day, our analysis indicated that it may not have been profitable to invest in the necessary equipment to meet the proposed requirements for a low-volume FMP. Instead, it would have been more economic for an operator to shut in the FMP. Therefore, 15 Mcf/day was proposed as the default threshold for a very-low-volume FMP, with the AO permitted to approve a higher threshold where circumstances warrant.

The proposed rule would have defined “low-volume FMP” as an FMP flowing at more than 15 Mcf/day, up to 100 Mcf/day. Low-volume FMPs must meet minimum requirements to ensure that measurements are not biased, but they are exempt from the rule's minimum uncertainty requirements. It was anticipated that this classification in the proposed rule would have encompassed many FMPs, such as those associated with plunger-lift operations, where attainment of minimum uncertainty requirements would be difficult due to the high fluctuation of flow rate and other factors. The costs to retrofit these FMPs to achieve minimum uncertainty levels could be significant, although no economic modeling was performed at the time the proposed rule was written because costs were highly variable and speculative. The exemptions that would be granted for low-volume FMPs are similar to the exemptions granted for meters measuring 100 Mcf/day or less in Order 5 and in the various statewide NTLs covering EFCs.

The proposed rule would have defined “high-volume FMP” as an FMP flowing more than 100 Mcf/day, but not more than 1,000 Mcf/day. Requirements for high-volume FMPs will ensure that there is no statistically significant bias in the measurement and it will achieve an overall volume measurement of uncertainty of ±3 percent or less and an annual average heating-value uncertainty of ±2 percent. The BLM anticipates that the higher flow rates would make retrofitting to achieve minimum uncertainty levels more

economically feasible. The requirements for high-volume FMPs are similar to current BLM requirements as stated in the statewide NTLs for EFCs.

Finally, the proposed rule would have defined “very-high-volume FMP” as an FMP flowing more than 1,000 Mcf/day. The BLM requires that very-high-volume FMPs achieve lower uncertainty than is required for high-volume FMPs (±2 percent, compared to ±3 percent for volume; and ±1 percent, compared to ±2 percent for average annual heating value) and would have increased the frequency of primary device inspections and secondary device verifications. Stricter measurement accuracy requirements for very-high-volume facilities are appropriate due to the risk that mismeasurement will have a significant impact on royalty calculation. The BLM anticipates that FMPs in this class operate under relatively ideal flowing conditions where lower levels of uncertainty are achievable and the economics for making necessary retrofits are favorable.

Many commenters questioned how the BLM determined the flow-rate ranges for the four categories of FMPs in the proposed rule (very-low-, low-, high-, and very-high-volume). Several of the commenters stated that the BLM used economics to determine the very-low-/low-volume threshold, but arbitrarily assigned the other thresholds. The BLM does not agree that the low-/high-volume and high-/very-high-volume thresholds in the proposed rule were “arbitrary.” The BLM did not have the same level of detail in its cost data to do the same level of detailed analysis on the thresholds for the higher-volume categories. The BLM nevertheless did consider existing thresholds in Order 5 and practical considerations for achieving lower uncertainties in setting those thresholds. Ultimately, though, the BLM determined that the cost estimates it had prepared were reasonable and formed a proper basis to set the thresholds used in the final rule. As explained elsewhere in this preamble, the thresholds were set at the point at which the cost of the additional requirements with respect to measurement equals the reduction in royalty risk achieved.

One commenter recommended that the BLM should determine all three thresholds on a cost-benefit basis, setting the thresholds at the level at which the cost of required meter improvements is offset by reduced uncertainty as a result of making the improvement. The commenter also recommended that the BLM should use a 1.5-year “payout” methodology instead of the rate-of-return methodology that the BLM used in the proposed rule. The BLM partially agrees with these comments and developed a Threshold Analysis to support the thresholds used in the final rule (see the discussion on thresholds below and the BLM Threshold Analysis). The requirements in the rule for low-volume FMPs represent the most lenient requirements the BLM can reasonably accept while also meeting its fiduciary obligations to ensure royalty-quality measurement. The only rationale for exempting very-low-volume FMPs from those requirements is to reduce costs to the point that operators truly on the edge of profitability will not shut in production as a result of the rule. The threshold for very-low-volume FMPs, therefore, is the flow rate below which a prudent operator can no longer afford to comply with the requirements for a low-volume FMP and would shut in production if the rule did not include the additional, very-low-volume category. Put differently, the BLM established the very-low-/low-volume threshold based on the minimum flow rate at which a prudent operator could afford to meet the standards for a low-volume FMP.

For the final rule, the BLM accepted the 1.5-year payout methodology suggested by the commenter in lieu of the rate-of-return methodology used in the proposed rule. Also, instead of using an assumed $8,000 investment required to meet the measurement standards for a low-volume FMP, the BLM re-examined the cost differences between the very-low-volume requirements and the low-volume requirements in the final rule. This cost difference was considered the “investment” in the payout methodology. The BLM does not agree that the reduction in uncertainty should be the basis for the “income” side of the payout method. While this may be useful for comparing uncertainty improvement as a function of cost, the BLM does not believe the overall premise is correct. First, the determination of uncertainty reduction between the very-low-volume and low-volume categories is highly speculative. Second, and perhaps more importantly, uncertainty indicates the risk of mismeasurement and does not denote whether that mismeasurement is high or low. The use of uncertainty to determine payout may be misleading to the reader who could incorrectly assume that uncertainty equates to under-measurement in all cases.

Instead of using the reduction in uncertainty as the “income,” the BLM used the total income from the well(s) flowing through the FMP. The premise of the payout method for the very-low/low-volume threshold was to simulate the decision-making process of a prudent operator, faced with a choice of either investing the money required to meet the standards of a low-volume FMP or of shutting-in the well(s). In this scenario, the prudent operator would consider the income provided by the continuation of production if they were able to meet the requirements of a low-volume FMP. All of this income would be lost if the well(s) were shut in.

The commenter recommended using the payout approach to set all of the thresholds. The BLM does not believe the payout approach is applicable to the low-/high-volume and high-/very-high-volume thresholds. Instead of using a payout method recommended by the commenter, the BLM used a royalty-risk methodology to determine the low-/high- and high-/very-high-volume thresholds. The BLM determined that it is fair and reasonable to set these thresholds for the higher-volume facilities at the point at which the cost of the additional requirements equals the reduction in royalty risk due to the additional requirements. This approach is appropriate for high-volume facilities because the costs of installing additional measurement equipment at these facilities do not impact their economic viability, since they are producing at a high-enough rate that they generate significant revenues, well in excess of operating costs. For example, a required $30,000 upgrade for a meter flowing at 1,000 Mcf/day would have a payout of 7 days, after operating costs, royalties, and taxes, well below the payout range of 6 to 18 months given by the commenter. A prudent operator would not shut in production in this scenario.

One commenter suggested that the BLM should incorporate the percent Federal or Indian ownership in the determination of flow-rate threshold categories. The BLM did not make any changes to the rule based on this comment because generally the accuracy of the FMP should be based on the flow rate it is measuring regardless of ownership. Implementing this suggestion would also be complex and cumbersome for both operators and the BLM. For example, a BLM inspector would have to multiply the average flow rate of the FMP by the Federal or Indian mineral interest in the agreement in order to determine which requirements the FMPs need to meet.

One commenter raised a concern about an FMP that is operating just over one of the volume thresholds because the operator would still have to spend the money to comply with the threshold, but the FMP would only be making slightly more money than if it

were in the next lower category. The BLM did not make any changes to the rule based on this comment because this situation will arise no matter where the thresholds are established. The BLM may provide guidance to its inspectors in the enforcement handbook on how to handle situations in which an FMP is operating just over a threshold.

The BLM received many comments suggesting alternative thresholds for the four categories of FMPs. The following table compares the Mcf/day thresholds from the proposed rule with the alternative suggestions received in the comments:

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Comments also included recommendations for removing the very-low-volume category in its entirety and extending the requirements for low-volume FMPs from zero Mcf/day to 100 Mcf/day. Another commenter suggested removing the very-high-volume category and extending the requirements for high-volume FMPs with no upper limit of flow rate. Based on all of the above comments, the BLM re-evaluated the economics of each category and developed new Mcf/day thresholds:

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The study used to determine these thresholds is available on the

regulations.gov

Web site (BLM Threshold Analysis).

One commenter stated that volume thresholds do not account for the fact that the economics of natural gas have changed with the Henry Hub wholesale price decreasing from $4 to $2/MMBtu, and therefore that the BLM's reliance on prices greater than $2/MMBtu is not reasonable. The BLM does not agree with this comment. First, natural gas prices are seasonal and $2/MMBtu gas is not permanent—for instance, the Henry Hub price can and does regularly exceed this level in response to cold weather under current market conditions. Second, it is unlikely that natural gas prices will remain at this $2/MMBtu level through the 3-year timeframe that the Threshold Analysis uses to determine the minimum payout volume for the very-low-/low-volume threshold or the 10-year timeframe that it uses to determine the low-/high-volume and high-/very-high-volume thresholds. The Energy Information Administration's (EIA's) Annual Energy Outlook for 2016

8

reference case projects average nominal Henry Hub wholesale prices of $3.79/MMBtu from 2016 to 2019, and $5.03/MMBtu from 2017 to 2026. Based on the foregoing, the BLM did not make any changes to the rule based on this comment.

8

U.S., Energy Information Administration, Annual Energy Outlook 2016,

available at

http://www.eia.gov/forecasts/aeo/

.

Determining the FMP Flow Rate Category

In the proposed rule, the BLM would have determined the FMP category by averaging the flow rate of that FMP over the previous 12 months or the life of the FMP, whichever was shorter. The BLM received several comments expressing concern about the proposed 12-month averaging period for FMPs that measure the flow rate from wells having high production-decline rates. Several of the commenters stated that as a result of the proposed 12-month averaging period, the operator would have to invest a lot of money to achieve the requirements for a high or very-high-volume FMP, only to have the volume drop to low- or even very-low-volume in a short period of time. One commenter recommended that the BLM should not include the first month of production in the average flow rate calculation.

The BLM agrees with the concept presented by the commenters and developed a definition for “averaging period” that applies to the category definitions in this rule and the uncertainty thresholds in the oil measurement rule (43 CFR subpart 3174). The definition, which appears in the subpart 3170 definitions section, retains a 12-month averaging period, but excludes any production from newly drilled wells prior to the second full month of production from the average calculation. In other words, if an FMP is installed to measure the production from a newly drilled well, and the well is put into production on May 10, the production reported in May and June would not be used in the calculation of average flow rate when determining the FMP's flow-rate category. In this example, May is not a full month of production; therefore, June is the first full month of production and July is the second full month of production. The 12-month averaging period starts with the July production figures.

The BLM received numerous comments asking for clarification on how an operator would determine the flow-rate category of an FMP. Some of the comments expressed confusion over the time period that the BLM would use to determine the average flow rate; whether this would be a 12-month average, a 6-month average, a daily rate, or based on previous-day flow rate available on the display of an EGM system. One commenter requested clarification on how an operator would determine the category if there were less than 12 months of data. The category definitions in the proposed rule and the new definition of “averaging period” in the final rule both specify that the average is taken over 12 months or the life of the FMP, whichever is shorter. The BLM did not make any further changes to the rule based on these comments. The BLM believes that the requirement for how the BLM will

determine average flow rate is sufficiently clear under the definition of “averaging period” in subpart 3170.

Bias

The proposed rule defined “bias” as a shift in the mean value of a set of measurements away from the true value of what is being measured. In the final rule the BLM changed the word “shift” to “systematic shift” to better match other statistical definitions. The word “systematic” was also added to stress that bias is present if a shift in mean value occurs even after averaging repeated measurements of the value across the entire measurement system.

One commenter stated that the term “bias” as used in the proposed rule implies that the operator is intentionally causing a meter to read high or low. The BLM did not make any changes to the rule based on this comment because neither the definition nor the use of the word “bias” in the rule implies that any bias is intentional. “Bias” is a term of art in the measurement context and does not refer to underlying intent.

Uncertainty

The proposed rule did not define the term “uncertainty” and used both the terms “certainty” and “uncertainty” interchangeably. One commenter stated that there is no definition of “certainty” or “uncertainty” in proposed § 3175.10. Based on this comment the BLM used only the term “uncertainty” in the final rule, and included a definition for that term. The BLM made this change because “uncertainty,” unlike the term “certainty,” is a term that is commonly used and understood within the oil and gas measurement context. “Uncertainty” is defined to mean the range of error that could occur between a measured value and the true value being measured, calculated at a 95 percent confidence level. The BLM selected a 95 percent confidence level because it is commonly used in oil and gas measurement. A 95 percent confidence level means that the calculated uncertainty indicates the maximum amount of error that is expected to occur between the measured value and the true value being measured 95 percent of the time. There is a 5 percent chance that the risk of mismeasurement is greater than the calculated uncertainty.

Significant Digit

The proposed rule defined “significant digit” as any digit of a number that is known with certainty. The definition was included in the proposed rule to support § 3175.104(a)(2), which required certain data in the QTR to be reported to five significant digits. Based on comments received, the requirement in the final rule was changed from five significant digits to a specified number of decimal places. Therefore, the definition of “significant digit” is no longer necessary and is deleted in the final rule.

Statistically Significant and Threshold of Significance

Section 3175.10 of the proposed rule included definitions for “statistically significant” and “threshold of significance.” Because the final oil measurement rule (43 CFR subpart 3174) also uses these terms, the BLM moved the definitions to subpart 3170. The BLM did not make any changes to the definitions.

Heating Value Variability

The BLM added a definition of “heating value variability” to the final rule in response to numerous comments expressing confusion over what this term means and how the BLM would determine it. These comments are discussed under § 3175.31(b).

Other Definitions

The BLM added a definition for “AGA Report No. (followed by a number)” to the final rule to be consistent with the definitions for GPA and API that pertain to standards incorporated by reference (see § 3175.30). The proposed rule did not incorporate any AGA (American Gas Association) standards; however, the final rule incorporates two AGA standards (AGA Report No. 3 (1985) and AGA Report No. 8 (1992)). As explained elsewhere in the preamble, the BLM incorporated standards from AGA Report No. 3 because the final rule includes grandfathering provisions (see § 3175.61) relating to meter tube construction that allow operators of grandfathered meters to meet the older standards in lieu of the latest API standards. AGA Report No. 8 was adopted because the BLM determined it was the more appropriate reference for the calculation of supercompressibility. In the proposed rule, the incorporation by reference was for API 14.2; both standards are identical in content.

There are numerous other terms that were defined in both the proposed rule and the final rule. These include, “as-found,” “as-left,” “atmospheric pressure,” “Beta ratio,” “British thermal unit,” “configuration log,” “discharge coefficient,” “effective date of a spot or composite sample,” “electronic gas measurement,” “element range,” “event log,” “heating value,” “integration,” “live input variable,” “mean,” “mole percent,” “normal flowing point,” “quantity transaction record,” “Reynolds number,” “senior fitting,” “standard cubic foot (scf),” “standard deviation,” “transducer,” “turndown,” “type test,” “upper range limit (URL),” and “verification.” The BLM did not receive any comments on these definitions and did not change any of these definitions from the proposed rule. One commenter stated that there is no definition of “AO,” “FMP,” “PA,” “PMT,” or “uncertainty” in proposed § 3175.10. The terms “AO,” “FMP,” “PA,” and “PMT” are defined under subpart 3170 because they apply to all the rules published under that part including subparts 3173, 3174, and 3175. Therefore, those definitions were not added to subpart 3175 in the final rule

§ 3175.20—General Requirements

Proposed § 3175.20 would have required measurement of all gas removed or sold from Federal or Indian leases and unit PAs or CAs that include one or more Federal or Indian leases to comply with the standards of the proposed rule (unless the BLM grants a variance under proposed § 3170.6). The BLM received a comment suggesting the requirements of § 3175 should only apply to those units or agreements above a set percentage of Federal interest. The BLM disagrees for the reasons discussed under the definition of the flow-rate categories and did not make any changes to this section based on this comment.

The BLM received another comment objecting to the proposed requirement to measure all gas on leases, pointing out that many times leases are part of units or CAs, and may have combined measurement points for multiple leases within these agreements. The BLM believes the commenter has misinterpreted the requirement. The final rule requires all gas removed or sold from Federal and Indian leases, unit PAs, or CAs to comply with 43 CFR subpart 3175. If a lease is part of a unit PA or CA, the measurement requirements in subpart 3175 apply only to the FMP where gas is removed or sold from the unit PA or CA. This is because the BLM considers unit PAs and CAs to be individual cases—comparable to large “leases”—with regards to measurement. As a result, operators do not have to measure the gas produced from individual leases within a CA or unit PA. Internal measurement points, such as those flagged by the commenter, that combine production from individual leases or wells within a CA or unit PA are not subject to this subpart, assuming they are not used to measure gas that is removed or sold

from the unit PA or CA for purposes of royalty determinations. The BLM did not make any changes to the final rule based on this comment.

The BLM did make a change to this section based on an internal review of the wording in the proposed rule. The proposed rule stated that “Measurement of all gas removed or sold from Federal and Indian leases and unit PAs or CAs that include one or more Federal or Indian leases, must comply with the standards prescribed in this subpart, except as otherwise approved under § 3170.6 of this subpart.” The BLM realized that this language does not account for situations where the BLM has granted commingling and allocation approval (CAA) under 43 CFR part 3173. Where the BLM has granted a CAA, the allocation meters are not considered FMPs and, therefore, do not have to comply with the requirements of this rule (see the definition of FMP under subpart 3173). As a result, gas will be removed or sold from the lease, unit PA, or CA without being measured in accordance with the standards in this rule, which is contrary to the language of the proposed rule. To address this, the BLM changed the wording of this sentence to “Measurement of all gas at an FMP must comply with the standards of this subpart . . . . ” It should be noted that if a gas allocation meter were to become an FMP in the future, it would have to comply with the applicable requirements of this rule.

§ 3175.30—Incorporation by Reference

This section previously appeared as § 3175.31 in the proposed rule, but based on edits made to the final rule, this section and final § 3175.30 have swapped places.

This final rule incorporates a number of industry standards, either in whole or in part, without republishing the standards in their entirety in the CFR, a practice known as incorporation by reference. These standards were developed through a consensus process, facilitated by the American Petroleum Institute (API), the American Gas Association (AGA), the Gas Processors Association (GPA), and the Pipeline Research Council International (PRCI) with input from the oil and gas industry and Federal agencies with oil and gas operational oversight responsibilities.

The BLM has reviewed these standards and determined that they will achieve the intent of §§ 3175.31 through 3175.125 of this rule. The legal effect of incorporation by reference is that the incorporated standards become regulatory requirements. With the approval of the Director of the Federal Register, this rule generally incorporates the current versions of the standards listed below. However, the BLM is also incorporating older versions of several standards due to the “grandfathering” of some existing equipment in the final rule

Some of the standards referenced in this section have been incorporated in their entirety. For other standards, the BLM incorporates only those sections that are relevant to the rule, meet the intent of § 3175.31 of the rule, or do not need further clarification.

The incorporation of industry standards follows the requirements found in 1 CFR part 51. The industry standards in this final rule are eligible for incorporation under 1 CFR 51.7 because, among other things, they will substantially reduce the volume of material published in the

Federal Register

; the standards are published, bound, numbered, and organized; and the standards incorporated are readily available to the general public through purchase from the standards organization, or through inspection at any BLM office with oil and gas administrative responsibilities (1 CFR 51.7(a)(3) and (4)). The language of incorporation in 43 CFR 3175.30 meets the requirements of 1 CFR 51.9. Where appropriate, the BLM has incorporated industry standards governing a particular process by reference and then imposes requirements that are in addition to or modify the requirements imposed by that standard (

e.g.,

the BLM sets a specific value for a variable where the industry standard proposed a range of values or options).

All of the API, AGA, GPA, and PRCI materials that the BLM is incorporating by reference are available for inspection at the BLM, Division of Fluid Minerals; 20 M Street SE., Washington, DC 20003; 202-912-7162; and at all BLM offices with jurisdiction over oil and gas activities. The API materials are also available for inspection and purchase at the API, 1220 L Street NW., Washington, DC 20005; telephone 202-682-8000; API also offers free, read-only access to some of the material at

http://publications.api.org

. The GPA materials are available for inspection at the GPA, 6526 E. 60th Street, Tulsa, OK 74145; telephone 918-493-3872;

https://gpsa.gpaglobal.org/

. The AGA materials are available for inspection at the AGA, 400 North Capitol Street NW., Suite 450, Washington, DC 20001; telephone 202-824-7000. The PRCI material is available for inspection at the PRCI, 3141 Fairview Park Dr., Suite 525, Falls Church, VA 22042; telephone 703-205-1600.

The following describes the API, GPA, APA, and PRCI standards that the BLM is incorporating by reference into this rule:

• API Manual of Petroleum Measurement Standards (MPMS) Chapter 14—Natural Gas Fluids Measurement, Section 1, Collecting and Handling of Natural Gas Samples for Custody Transfer; Seventh Edition, May, 2016 (“API 14.1”). This standard provides comprehensive guidelines for properly collecting, conditioning, and handling representative samples of natural gas that are at or above their hydrocarbon dew point.

• API MPMS Chapter 14, Section 3, Orifice Metering of Natural Gas and Other Related Hydrocarbon Fluids—Concentric, Square-edged Orifice Meters, Part 1, General Equations and Uncertainty Guidelines; Fourth Edition, September 2012; Errata, July 2013 (“API 14.3.1”). This standard provides engineering equations and uncertainty estimations for the calculation of flow rate through concentric, square-edged, flange-tapped orifice meters.

• API MPMS Chapter 14, Section 3, Orifice Metering of Natural Gas and Other Related Hydrocarbon Fluids—Concentric, Square-edged Orifice Meters, Part 2, Specification and Installation Requirements; Fifth Edition, March 2016 (“API 14.3.2”). This standard provides construction and installation requirements, and standardized implementation recommendations for the calculation of flow rate through concentric, square-edged, flange-tapped orifice meters.

• API MPMS Chapter 14, Section 3, Orifice Metering of Natural Gas and Other Related Hydrocarbon Fluids—Concentric, Square-edged Orifice Meters, Part 3, Natural Gas Applications; Fourth Edition, November 2013 (“API 14.3.3”). This standard is an application guide for the calculation of natural gas flow through a flange-tapped, concentric orifice meter.

• API MPMS Chapter 14, Natural Gas Fluids Measurement, Section 3, Concentric, Square-Edged Orifice Meters, Part 3, Natural Gas Applications, Third Edition, August 1992 (“API 14.3.3 (1992)”). This standard is an application guide for the calculation of natural gas flow through a flange-tapped, concentric orifice meter.

• API MPMS, Chapter 14, Section 5, Calculation of Gross Heating Value, Relative Density, Compressibility and Theoretical Hydrocarbon Liquid Content for Natural Gas Mixtures for Custody Transfer; Third Edition, January 2009; Reaffirmed February 2014 (“API 14.5”). This standard presents procedures for calculating, at base conditions from composition, the

following properties of natural gas mixtures: Gross heating value, relative density (real and ideal), compressibility factor, and theoretical hydrocarbon liquid content.

• API MPMS Chapter 21, Section 1, Flow Measurement Using Electronic Metering Systems—Electronic Gas Measurement; Second Edition, February 2013 (“API 21.1”). This standard describes the minimum specifications for electronic gas measurement systems used in the measurement and recording of flow parameters of gaseous phase hydrocarbon and other related fluids for custody transfer applications utilizing industry recognized primary measurement devices.

• API MPMS Chapter 22—Testing Protocol, Section 2, Differential Pressure Flow Measurement Devices; First Edition, August 2005; Reaffirmed August 2012 (“API 22.2”). This standard is a testing protocol for any flow meter operating on the principle of a local change in flow velocity, caused by the meter geometry, giving a corresponding change of pressure between two reference locations.

• GPA Standard 2166-05, Obtaining Natural Gas Samples for Analysis by Gas Chromatography; Adopted as a Tentative Standard, 1966; Revised and Adopted as a Standard, 1968; Revised 1986, 2005 (“GPA 2166-05”). This standard recommends procedures for obtaining samples from flowing natural gas streams that represent the compositions of the vapor phase portion of the system being analyzed.

• GPA Standard 2261-13, Analysis for Natural Gas and Similar Gaseous Mixtures by Gas Chromatography; Adopted as a Tentative Standard, 1961; Revised and Adopted as a Standard, 1964; Revised 1972, 1986, 1989, 1990, 1995, 1999, 2000 and 2013 (“GPA 2261-13”). This standard establishes a method to determine the chemical composition of natural gas and similar gaseous mixtures within set ranges using a gas chromatograph (GC).

• GPA Standard 2198-03, Selection, Preparation, Validation, Care and Storage of Natural Gas and Natural Gas Liquids Reference Standard Blends; Adopted 1998; Revised 2003. (“GPA 2198-03”). This standard establishes procedures for selecting the proper natural gas and natural gas liquids reference standards, preparing the standards for use, verifying the accuracy of composition as reported by the manufacturer, and the proper care and storage of those standards to ensure their integrity as long as they are in use.

• GPA Standard 2286-14, Method for the Extended Analysis of Natural Gas and Similar Gaseous Mixtures by Temperature Program Gas Chromatography; Adopted as a Standard 1995; Revised 2014 (“GPA 2286-14”). This method is intended for the compositional analysis of natural gas and similar gaseous mixtures where precise physical property data of the hexanes and heavier fractions are required. The procedure is applicable for mixtures which may contain components of nitrogen, carbon dioxide, and/or hydrocarbon compounds C1-C14.

• AGA Report No. 3, Orifice Metering of Natural Gas and Other Related Hydrocarbon Fluids Second Edition, September 1985 (“AGA Report No. 3 (1985)”). This standard provides construction and installation requirements, and standardized implementation recommendations for the calculation of flow rate through concentric, square-edged, flange-tapped orifice meters.

• AGA Report No. 8, Compressibility Factors of Natural Gas and Other Related Hydrocarbon Gases; Second Edition, November 1992 (“AGA Report No. 8”). This standard presents detailed information for precise computations of compressibility factors and densities of natural gas and other hydrocarbon gases, calculation uncertainty estimations, and FORTRAN computer program listings.

• PRCI NX 19, Manual for the Determination of Supercompressibility Factors for Natural Gas; December 1962 (“PRCI NX 19”). This standard presents detailed information for computations of compressibility factors and densities of natural gas and other hydrocarbon gases.

Several commenters suggested that the BLM should adopt API and GPA standards in their entirety rather than incorporating only parts of them. Some of the commenters stated that the BLM should incorporate all of API MPMS Chapter 1 (Terms and Definitions), all of Chapter 14 (Natural Gas Fluids Measurement), all of Chapter 21 (Flow Measurement Using Electronic Metering Systems), and all of Chapter 22 (Testing Protocols).

The BLM did not make any changes as a result of these comments. The rule incorporates five industry standards in whole and seven industry standards in part. API and GPA standards are written for industry to use as guidelines in designing and operating measurement facilities, generally for custody-transfer applications, were not designed for the regulatory environment, and present potential enforcement challenges and limitations. As such, these standards are often difficult to adopt without modification as regulations. The BLM can only enforce requirements that are objective, clearly defined, and relevant to the BLM's goal of ensuring accurate and verifiable measurement. Many of the API and GPA standards referenced by the commenters do not meet this threshold. For example, API 21.1, Section 6, sets standards for data availability. API 21.1, Subsection 6.2, requires, among other things, that onsite data include at least 7 days of hourly QTRs. While this may be a useful requirement for industry, the BLM is not concerned in this rule with how long data are maintained onsite. The FOGRMA of 1982 (as amended by the Royalty Simplification and Fairness Act of 1996) requires all records for Federal leases to be maintained for a period of 7 years from the date they are generated. Whether they are maintained onsite or offsite is irrelevant to the BLM's goals. In addition, it would be very difficult for BLM inspectors to enforce such a provision and it would serve no purpose for them to do so.

The following table lists the API standards that the commenters suggested the BLM should adopt and our response.

ER17NO16.039

ER17NO16.040

Of the 22 standards in Chapters 1, 14, 21, and 22 that the commenters recommended for incorporation, the BLM is incorporating eight standards. Two of the remaining standards have not yet been published by API, four apply only to liquid measurement, and two are for informational uses only. The BLM did not incorporate the remaining six recommended standards because they are not relevant to royalty measurement, were not published in time to include in the final rule, or the BLM determined that they either had the potential to conflict with BLM requirements or did not help achieve the purposes of the rule or the underlying legal requirements.

One commenter stated that API 14.1 and GPA 2166 are clear and enforceable as written and should be incorporated in whole. The rule incorporates portions of these two standards. While there are portions of API 14.1 and GPA 2166 that are clear and enforceable as written, many parts of these standards are not. For example, API Chapter 14.1, Subsection 6.3.2.1 states: “Sample distortion due to chemical and physical adsorption can be minimized by prudent selection of sampling system materials. In general, materials and coatings that are chemically inert and of minimum porosity are the best choices.” While this statement has important educational value, it would be virtually impossible for a BLM inspector to ascertain whether a sampling system material is in accordance with the standard or to take an enforcement action against an operator for not making a “best choice.” The BLM did not make any changes to the rule based on this comment.

Several commenters suggested that the BLM should automatically incorporate the latest version of a standard rather than specifying a year and edition of the standard. The BLM did not make any changes to the rule based on these comments. To promulgate a rule, all Federal agencies must follow the APA, which establishes specific requirements for Federal agencies to follow. In general, the agency must provide notice to the

public that a new rule is under consideration, publish a draft of the rule in the

Federal Register

, and provide the public an opportunity to comment on the proposed rule (see 5 U.S.C. 553). When the BLM incorporates a standard by reference, the standard becomes part of the rule in which it is incorporated.

If the rule were structured to incorporate “the latest version” of a particular standard, the requirements of the rule would automatically change whenever a particular standard is updated in the future. Changing a substantive rule in this manner, without the opportunity for public input, would be inconsistent with the notice-and-comment requirements of the APA, and therefore would not be legally permissible. The BLM will, however, evaluate new standards as they are issued by API, GPA, and others, and will determine if it is appropriate to initiate a rulemaking process to update the reference in subpart 3175 to incorporate the then-current version of those standards. In the interim, an operator could request a variance to follow the more recent version of a particular standard in lieu of the one incorporated by reference in this rule. Such requests would be evaluated by the PMT as outlined in this rule.

Several commenters suggested incorporating the latest version of GPA 2261-13, instead of GPA 2261-00. The BLM agrees with this comment and has changed the incorporation by reference to refer to the latest version of this standard. See the portion of the preamble that describes § 3175.118 for further discussion of these comments.

Several commenters suggested incorporating GPA 2286-14, relating to taking extended analyses. The BLM agrees with this comment and incorporated this standard by reference because § 3175.119(b) requires operators to do extended analyses in some instances. See the portion of the preamble that discusses § 3175.117 for further discussion of these comments.

As discussed in connection with § 3175.10, the BLM did incorporate two AGA standards in the final rule: AGA Report No. 3 (1985) and AGA Report No. 8. The BLM incorporated AGA Report No. 3 because the final rule includes meter tube construction standards for certain grandfathered facilities (see § 3175.61) in lieu of the latest standards in API 14.3.2. The BLM also changed the incorporation by reference for the calculation of supercompressibility. In the proposed rule the incorporation by reference was for API 14.2; however, this was changed to AGA Report No. 8 in the final rule because the BLM determined this was a more appropriate reference. Both standards are identical in content.

§ 3175.31—Specific Performance Requirements

Note that the performance requirements appeared under § 3175.30 in the proposed rule. In the final rule, the BLM switched the provisions in §§ 3175.30 and 3175.31 for formatting purposes.

Section 3175.31 sets overall performance standards for measuring gas produced from Federal and Indian leases, regardless of the type of technology used. The performance standards provide specific objective criteria that the BLM can use to analyze meter systems not specifically allowed under the final rule. The performance standards also form the basis of determining the individual equipment standards that apply to each flow-rate class of meter (

i.e.,

very-low, low, high, and very-high volume).

Section 3175.31(a) establishes limits on the maximum allowable flow-rate measurement uncertainty. Uncertainty indicates the risk of measurement error. For high-volume FMPs (flow rate greater than 200 Mcf/day, but less than or equal to 1,000 Mcf/day), the maximum allowed overall flow-rate measurement uncertainty is ±3 percent. For very-high-volume FMPs (flow rate of more than 1,000 Mcf/day), the maximum allowable flow-rate uncertainty is reduced to ±2 percent, because uncertainty in higher-volume meters presents greater royalty risks than in lower-volume meters. In addition, upgrades necessary to achieve an uncertainty of ±2 percent for very-high-volume FMPs will be more economical given these FMPs' higher overall production levels. Not only do the higher flow rates make these necessary upgrades more economical, many of the measurement uncertainty problems associated with lower-volume FMPs, such as intermittent flow, are not as prevalent with higher-volume FMPs.

The ±3 percent uncertainty requirement for high-volume FMPs is the same as what is currently required in all of the statewide NTLs for EFCs. However, the ±3 percent uncertainty requirement in the statewide NTLs applies to all FMPs measuring more than 100 Mcf/day. Section 3175.31(a), by contrast, applies only to high- (±3 percent) and very-high- (±2 percent) volume FMPs. Under the new rule, therefore, meters measuring between 100 Mcf/day and 200 Mcf/day are no longer required to meet an uncertainty standard. Consistent with the existing requirements of the statewide NTLs, meters measuring less than 100 Mcf/day are not subject to uncertainty requirements.

Section 3175.31(a)(3) specifies the conditions under which flow-rate uncertainty must be calculated. Flow-rate uncertainty is a function of the uncertainty of each variable used to determine flow rate. The uncertainty of variables such as differential pressure, static pressure, and temperature is dynamic and depends on the magnitude of the variables at a point in time. This section lists two sources of data to use for uncertainty determinations. The best data source for average flowing conditions at the FMP would be the monthly averages typically available from a daily QTR. However, daily QTRs are not usually readily available to the AO at the time of inspection because they must usually be requested by the BLM and provided by the operator ahead of time. If the daily QTR is not available to the AO, the next best source for uncertainty determinations would be the average flowing parameters from the previous day, which will be required under § 3175.101(b)(4)(i) through (iii) of this final rule (§ 3175.101(b)(4)(i) through (iv) of the proposed rule).

The BLM received numerous comments on this section. One commenter stated that the new performance requirements would cause wells to be shut in, although no support for that claim was included in the comment. The BLM conducted a detailed economic analysis to support the new flow category thresholds discussed under proposed § 3175.10, which included the costs of any upgrades necessary to meet the new uncertainty requirements (see the BLM Threshold Analysis). The flow-rate uncertainty of ±3 percent for high-volume FMPs is actually less restrictive than the current uncertainty requirement in the statewide NTLs for EFCs. The NTLs require an overall uncertainty of ±3 percent or better for all meters measuring more than 100 Mcf/day. The final rule expands that limit to 200 Mcf/day. Therefore, FMPs measuring between 100 Mcf/day and 200 Mcf/day, which would have been subject to the ±3 percent uncertainty limit under the statewide NTLs, are now exempt from any uncertainty requirement. The new uncertainty limit of ±2 percent for very-high-volume FMPs is only required for FMPs measuring more than 1,000 Mcf/day, which applies to just over 1 percent of all FMPs, according to data maintained by the BLM about current production. The BLM believes that a ±2 percent uncertainty will not be difficult to achieve on very-high-volume FMPs because the flow tends to be more stable

and contain fewer liquids for wells producing at those levels. Additionally, for very-high-volume FMPs, any costs associated with achieving a ±2 percent uncertainty versus a ±3 percent uncertainty, such as the purchase of a new transducer, should not be significant given the overall magnitude of production. The BLM did not make any changes to the rule as a result of these comments.

Several commenters expressed a concern that reduced uncertainty will not necessarily increase revenue or royalty. Uncertainty is the risk of mismeasurement, and the goal of reducing uncertainty is to reduce that risk regardless of whether the end result is greater royalty, less royalty, or no change in royalty. Reducing the risk of mismeasurement ensures that the measurement is more accurate, which is one of the primary goals of this rule. As reflected in other provisions of this rule, the BLM has developed measurement standards that impose uncertainty requirements commensurate with the royalty risk posed by a particular facility. For these reasons, no changes to the rule were made.

One commenter stated that any increase in transportation costs, such as meter upgrades, would increase transportation allowances under the ONRR valuation regulations, thereby reducing royalty. The BLM has confirmed with ONRR that there are no circumstances under which an operator can claim expenses relating to measurement as a transportation allowance. The BLM did not make any changes to the rule based on this comment.

The BLM received several comments objecting to what they said is a lack of justification for the uncertainty limits in the proposed rule. The BLM does not agree with these comments. The preamble to the proposed rule provided a detailed explanation of how the BLM developed the uncertainty limits and why they were developed. The BLM did not make any changes to the final rule based on these comments.

The BLM will enforce flow-rate measurement uncertainty using standard calculations such as those found in API 14.3.1, which are incorporated into the BLM uncertainty calculator (

www.wy.blm.gov

), or other methods approved by the AO. BLM employees use the uncertainty calculator to determine the uncertainty of meters that are used in the field. However, existing and previous versions of the uncertainty calculator do not account for the effects of relative density uncertainty because these effects have not been quantified. The gas analysis data required in § 3175.120(e) and (f) of the final rule allow the BLM to quantify the relative density uncertainty by performing a statistical analysis of historical relative density variability and including it in the determination of overall measurement uncertainty, making these uncertainty calculations more robust.

The BLM received numerous comments stating that the BLM has not published the calculations used in the BLM uncertainty calculator, making it difficult to comment on the uncertainty calculation. The BLM disagrees with this comment. A user's manual and detailed description of every calculation used in the uncertainty calculator has been posted on both the BLM Web site (

www.blm.gov/wy

) and the Colorado Engineering and Experiment Station, Inc. Web site since December 2009. These are the only Web sites from which the BLM uncertainty calculator can be downloaded, and the link to download the documentation is immediately adjacent to the link to download the calculator. One commenter stated that these calculations must be published before mandating the use of the calculator. Neither the proposed rule nor the final rule mandates the use of the BLM uncertainty calculator. As discussed in the preamble, the BLM uncertainty calculator is a method by which BLM inspectors could enforce the uncertainty requirements; however, the calculator is not referred to anywhere in the regulation itself. The BLM did not make any changes to the rule in response to these comments.

The BLM received several comments stating that the BLM should have published the uncertainty calculations in the proposed rule and asked for clarification of what those calculations would be. The BLM agrees with this comment and incorporated by reference API 14.3.1, Section 12, which includes the uncertainty calculations that the BLM accepts and uses in the BLM uncertainty calculator. Section 3175.31(a)(4) was added to the final rule to reference the uncertainty calculations in API 14.3.1, Section 12.

Section 3175.31(b) establishes an uncertainty requirement for the measurement of heating value. This was included because both heating value and volume directly affect royalty calculation if gas is sold at arm's length on the basis of a per-MMBtu price. Virtually all of the gas sold domestically in the United States is priced on a $/MMBtu basis. The royalty is computed by the following equation:

R = V × HV × P × R

r

,

Where:

R = royalty owed, $;

V = volume of gas removed or sold from a lease, Mcf;

HV = heating value, MMBtu/Mcf;

P = gas value, $/MMBtu; and

R

r

= royalty rate.

Thus, a 5 percent error in heating value would result in the same error in royalty as a 5 percent error in volume measurement.

The BLM recognizes that the heating value determined from a spot sample only represents a snapshot in time, and the actual heating value at any point after the sample was taken may be different. The probable difference is a function of the degree of variability in heating values determined from previous samples. If, for example, the previous heating values for a meter are very consistent, then the BLM would expect that the difference between the heating value based on a spot sample and the actual heating value at any given time after the spot sample was taken would be relatively small. The opposite would be true if the previous heating values had a wide range of variability. Therefore, the uncertainty of the heating value calculated from spot sampling will be determined by performing a statistical analysis of the historical variability of heating values over the past year for high- and very-high-volume FMPs. If an operator installs a composite sampling system or an on-line GC, the BLM will consider that device as having met the heating-value uncertainty requirements of this section.

The uncertainty limits for heating value are based on the annualized cost of spot sampling and analysis as compared to the royalty risk from the resulting heating-value uncertainty. The BLM used the data collected for the Gas Variability Study (see the discussion of § 3175.115 below) as the basis of this analysis. For high-volume FMPs, the BLM determined that the cost to industry of achieving an average annual heating-value uncertainty of ±2 percent by using spot sampling methods would approximately equal the royalty risk resulting from the same ±2 percent uncertainty in the heating value. For very-high-volume FMPs, an average annual heating-value uncertainty of ±1 percent would result in a cost to industry that is approximately equal to the royalty risk of the uncertainty. The rule therefore prescribes these respective levels as the allowed average annual heating-value uncertainty for high- and very-high-volume FMPs.

The BLM received numerous comments on this section stating that the new performance requirements

would cause wells to be shut in, although no support for that claim was included in the comments. As with the volume uncertainties, the required heating-value uncertainties will only apply to FMPs measuring more than 200 Mcf/day. The BLM did not receive any data supporting the argument that meeting an average annual heating-value uncertainty of ±2 percent (high volume) or ±1 percent (very-high volume) would be so costly that an operator would shut in the well(s) flowing through the meter rather than complying with this requirement. Under the worst-case scenario for high-volume FMPs, where the heating value from the FMP is highly erratic from sample to sample, the maximum cost to the operator would be to take spot samples every 2 weeks, which represents a relaxation of requirements in the proposed rule that would have required weekly samples. The BLM Threshold Analysis included the cost of bi-weekly sampling in the determination of an appropriate threshold for the low-/high-volume categories. For very-high-volume FMPs, the worst-case scenario would require an operator to install a composite sampling system. The proposed rule would have also required on-line GCs or composite samplers for high-volume FMPs. The BLM Threshold Analysis includes this cost to determine the high-/very-high-volume threshold. The costs to comply with the heating-value uncertainties are not significant enough that a prudent operator would opt to shut in the well(s) flowing through FMPs producing at that level. Also, the operator has other means to reduce the heating-value variability from sample to sample, such as employing quality control measures in sampling and analysis.

Several commenters stated that there is no reason the heating-value uncertainty limits should be more restrictive than the flow-rate uncertainty limits. For flow rate, an uncertainty of ±3 percent for high-volume FMPs and ±2 percent for very-high-volume FMPs is required. For heating value, an average annual uncertainty of ±2 percent uncertainty for high-volume FMPs and ±1 percent uncertainty for very-high-volume FMPs is required. As described in the preamble and in the BLM Threshold Analysis, the BLM determined the uncertainties for volume and heating value separately based on cost of compliance versus royalty risk resulting from the uncertainty requirement. For example, the flow-rate uncertainty and costs associated with achieving that uncertainty are dependent on the size, quality, configuration, and operation of the primary, secondary, and tertiary devices. For heating value, the uncertainty and costs associated with achieving that uncertainty are a function of the heating-value variability and sampling frequency or sampling method (

i.e.

, composite versus spot). Because the determinants of flow-rate uncertainty and heating-value uncertainty are independent, the costs of achieving specified uncertainty levels are also independent. As a result, the uncertainty limits for volume and heating value were set independently based on the results of the BLM Threshold Analysis. Generally, flow-rate uncertainty targets are more difficult and expensive to achieve than uncertainty targets for average annual heating value. For example, an average annual heating-value uncertainty of ±1 percent is achievable in most cases by simply increasing the sample frequency, which typically costs a few hundred dollars per year. By contrast, achieving a volume uncertainty of ±1 percent would, in most cases, require operators to purchase the most expensive transducers available and install separation and other equipment that would maintain a very consistent flow rate. This could cost tens of thousands of dollars or more. The BLM did not make any changes to the final rule based on these comments.

The BLM received several comments suggesting other uncertainty limits from those listed in the proposed rule. One commenter suggested that both the flow rate and heating-value uncertainties should be reduced to ±1 percent for high- and very-high-volume FMPs and an uncertainty requirement of ±5 percent should be added for very-low and low-volume FMPs. Another commenter suggested that the heating-value uncertainty should be ±7.5 percent when the heating value is above 1,200 Btu/scf and ±5 percent when the heating value is below 1,200 Btu/scf. Another commenter suggested that the BLM establish uncertainty levels for heating values by working with trade groups. Commenters submitted little rationale to support any of these suggested uncertainty levels. The BLM believes that the uncertainty levels given in the proposed rule are fair, reasonable, and achievable based on its experience in the field. They were established by determining the point at which the cost of compliance equals the risk to royalty. The BLM did not make any changes to the proposed rule based on these comments.

Several commenters stated that the BLM is confusing variability with uncertainty when establishing an uncertainty limit for average annual heating value. The BLM disagrees with these comments. The commenters appear to be assuming that the BLM used the term “uncertainty” interchangeably with “variability.” This is not the case, as described in detail in the BLM Gas Variability Study and as used in this rule. With respect to heating value, the term “variability” refers to the statistical variation from the mean heating value based on a certain number of previous gas analyses. For example, the heating values from five previous gas samples are shown in the table below, and the mean value of those five heating values is 1,256 Btu/scf. The variability of these five samples is the standard deviation of the five heating values (±14.3 Btu/scf) multiplied by the “student-t” function that yields a 95 percent confidence. For the five samples, the student-t function is 2.78, and the variability of this FMP is ±40 Btu/scf (±14.3 Btu/scf × 2.78), or ±3.2 percent of the average heating value. The BLM considers the variability a quasi-static property of the meter. The cause of the variability could be actual changes in gas composition over the time period analyzed, sampling technique, analysis technique, or other factors such as temperature at the time of sampling. Whatever the cause, this particular FMP has a variability of ±3.2 percent and will most likely continue to have a variability of approximately ±3.2 percent, unless something significant changes, such as the gas sampling or analysis technique or, for example, a new well is connected to the meter. When the BLM refers to heating-value uncertainty, it is specific to the average annual heating value uncertainty, not the uncertainty of an individual sample. The average annual heating value uncertainty is how close the average heating value from an FMP, as determined from gas samples taken over a 1-year time span, will be to the true average heating value of that FMP over the same time span. The true average annual heating value is a hypothetical value assuming the heating value was measured continuously over that year by an instrument with no uncertainty.

ER17NO16.041

In the BLM Gas Variability Study, the BLM determined the relationship between variability and uncertainty in the average annual heating value. The relationship is defined by the following equation:

ER17NO16.042

Although the variability of this FMP is ±3.2 percent, the average annual heating-value uncertainty is reduced by taking more samples over the year. In this example, the samples were taken twice per year, or roughly once every 180 days. Using the equation directly above, the uncertainty of the average annual heating value at this sampling frequency is reduced to ±2.1 percent. Sampling four times per year (every 90 days) would reduce the average annual heating-value uncertainty to ±1.5 percent. In summary, the average annual heating-value uncertainty requirement in the final rule governs uncertainty not variability. While variability is a factor in determining uncertainty, uncertainty can be reduced for a given level of variability by taking more frequent samples. The BLM added § 3175.31(b)(3) to the final rule as a result of these comments, in order to clarify and define the relationship between average annual heating-value uncertainty and variability. The equations presented in § 3175.31(b)(3) are the same equations that were presented in the heating value variability study repeatedly referenced in the preamble to the proposed rule. The study was also included in the supporting documentation posted on

www.regulations.gov

concurrently with the release of the proposed rule. In addition, § 3175.31(b)(3) allows the BLM to approve other methods of calculating average annual heating value uncertainty that operators or industry groups may develop.

One commenter asked that the BLM exempt central delivery point (CDP) meters from the heating-value uncertainty limits because achieving these limits would be difficult due to the constantly changing gas composition as different wells produce through the meter. The commenter provided an example of where a CDP meter, which would qualify as a very-high-volume FMP under the proposed rule, has a heating-value variability of ±3.5 percent. Assuming that the commenter determined the variability in the same manner as the BLM does, and took monthly samples at a very-high volume as required in the rule for the initial 1-year timeframe, the average annual heating-value uncertainty would be ±0.87 percent, based on the equation directly above, which is well within the uncertainty of ±1 percent required for very-high-volume FMPs. The BLM did not make any changes to the rule based on this comment.

Several commenters requested that the BLM provide the calculation methodology for average annual heating-value uncertainty. The BLM agrees with this comment and included the methodology in the final rule, under § 3175.31(b)(3). The methodology was also included in the BLM Gas Variability Study, which was posted as a supporting document on

www.regulations.gov

, along with the proposed rule.

One commenter stated that the cost of compliance for existing FMPs outweighs any measurable benefit. However, the volume cutoff points between low- and high-volume and between high- and very-high-volume FMPs in the final rule were established to represent the point at which the cost of compliance is equal to or less than the resulting reduction in royalty risk resulting from the improvements required by the rule. Royalty risk is the measurement uncertainty expressed in royalty dollars. The BLM did not make any changes to the rule based on this comment.

One commenter stated that the data used in the BLM Gas Variability study were not vetted or scrubbed to control for the conditions under which the samples were taken. The implication of the comment is that the BLM study is not statistically valid. While the BLM acknowledges that that the data were not controlled for the conditions under which they were taken, the data

represent samples taken under real-life conditions and, in every case, the heating values used in the study were used as the basis for royalty payment. The BLM also believes that reliance on the study is appropriate without controlling for conditions because field sampling is typically not controlled to ensure that samples are taken at, for example, the same time of year or at the same ambient temperature—

i.e.,

the study as used by the BLM for purposes of this rule is an accurate reflection of sampling results that occur in the field. The fact that the data showed no correlation existed between heating-value variability and pressure, temperature, or any of the other attributes analyzed demonstrates that other factors—perhaps poor sampling practices—are masking any correlation that theoretically should exist. Again, the BLM does not believe that scrubbing the data was necessary because the BLM does not intend to require the same conditions every time a sample is taken. In the field, it is impossible to control conditions, such as temperature, pressure, flow rate, separator efficiency, and other factors. The final rule establishes a uniform uncertainty value that reflects actual field practice. Based on the foregoing, the BLM did not make any changes to the rule based on this comment.

One commenter stated that the BLM Gas Variability Study does not reflect the accuracy of custody-transfer meters because most of the measurement points from which the BLM obtained the analyses were on-lease meters. The BLM believes that the commenter misunderstands the purpose of the study, which was to assess the variability of meters on which Federal and Indian royalty is based. These meters are often on-lease meters rather than custody-transfer meters on which the operator is paid. The BLM is not concerned with sales or custody-transfer meters that are not used in the determination of royalty. Therefore, the data used in the study are directly applicable to meters used for royalty determination, which are generally the on-lease meters. The BLM did not make any changes to the rule based on this comment.

Several commenters stated that composite samplers and on-line GCs are not economical on location because they do not work well with rich gas. The commenters did not supply any data to support this claim. Based on this comment and on the BLM Threshold Analysis, the BLM eliminated the provision in the proposed rule that would have required composite samplers or on-line GCs on high-volume FMPs, if the required ±2 percent average annual heating-value uncertainty could not be achieved by spot sampling. The BLM made this change for economic reasons, not because it accepts that these devices do not work well with rich gas. The BLM did not remove the provision in the rule that requires composite samplers on very-high-volume FMPs when the required ±1 percent average annual heating-value uncertainty cannot be achieved through spot sampling.

One commenter suggested that the determination of heating-value uncertainty should be on a field-wide basis rather than on a well or FMP basis. The commenter did not provide any data to substantiate this suggestion. The BLM does not agree with this comment. While the determination of heating-value uncertainty on a regional or formation-wide basis may seem like a reasonable approach, the data analyzed by the BLM (BLM Gas Variability Study) showed that heating-value variability is not correlated by region or formation. One possible reason for this is that the heating-value variability is not only dependent on the formation, but also on human factors, such as gas sampling and analysis techniques. The BLM did not make any changes to the rule in response to this comment.

Section 3175.31(c) establishes the degree of allowable bias in a measurement. Bias, unlike uncertainty, results in systematic measurement error; uncertainty only indicates the risk of measurement error. For all FMPs, except very-low-volume FMPs, no statistically significant bias is allowed. The BLM acknowledges that it is virtually impossible to completely remove all bias in measurement. When a measurement device is tested against a laboratory device, there is often slight disagreement, or apparent bias, between the two. However, both the measurement device being tested and the laboratory device have some inherent level of uncertainty. If the disagreement between the measurement device being tested and the laboratory device is less than the uncertainty of the two devices combined, then it is not possible to distinguish apparent bias in the measurement device being tested from inherent uncertainty in the devices (sometimes referred to as “noise” in the data). Therefore, apparent bias that is less than the uncertainty of the two devices combined is not considered to be statistically significant. This approach is consistent with existing BLM policy. Although bias is not specifically addressed in Order 5 or the statewide NTLs, the intent of those standards is to reduce bias.

The bias requirement does not apply to very-low-volume FMPs because very-low-volume FMPs are measuring such low volumes that any bias, even if it is statistically significant, results in little impact to royalty. The small amount of royalty loss (or gain) resulting from bias would be much less than the royalty lost if production were to cease altogether—a possible outcome if the operator were to decide that it is uneconomic to upgrade a meter to eliminate bias. Therefore, the BLM has determined that it is in the public interest to accept some risk of measurement bias in very-low-volume FMPs in order to maintain gas production. The BLM did not receive any comments on this section.

Section 3175.31(d) requires that all measurement equipment must allow for independent verification by the BLM. For example, if a new meter were developed that did not record the raw data used to derive a volume, that meter could not be used at an FMP because, without the raw data, the BLM would be unable to independently verify the volume. Similarly, if a meter were developed that used proprietary methods that precluded the ability to recalculate volumes or heating values, or made it impossible for the BLM to verify its accuracy, its use would also be prohibited. As explained in the preamble to the proposed rule, this is not a change from existing policy. Order 5 and the statewide NTLs for EFCs only allow meters that can be independently verified by the BLM.

One commenter stated that the performance goal of verifiability will restrict new technology. As an example, the commenter suggested that a verifiability requirement could have prevented the development of EGM systems. The BLM disagrees with this comment and did not make any changes to the rule as result. Contrary to the suggestion by the commenter, the BLM believes that verifiability is essential to making EGM systems universally accepted by both industry and regulators. For example, over 20 percent of the main body of API 21.1 is devoted to the audit trail, reporting, and data integrity required of EGM systems, all of which encompass verifiability.

One commenter expressed concern that the provisions of the proposed rule would cause the BLM to continually re-evaluate the quantity, rate, or heating value uncertainty of particular equipment. The BLM does not agree with this comment and did not make any changes to the rule as a result. The rule is designed to minimize required testing. The PMT will establish the uncertainty of each new piece of equipment one time, and operators can

then rely on that determination in making the uncertainty calculations.

§ 3175.40—Measurement Equipment Approved by Standard or Make and Model

Section 3175.40 establishes the types, makes, and models of equipment and software versions that can be used at FMPs. All makes of flange-tapped orifice plates (§ 3175.41), all makes and models of mechanical recorders (§ 3175.42), and all makes and models of GCs (§ 3175.45) are automatically approved under this rule without any additional BLM review. This section also explains that for specific makes, models, and sizes of other types of equipment including transducers (§ 3175.43), flow-computer software (§ 3175.44), flow conditioners (§ 3175.46), differential primary devices other than flange-tapped orifice plates (§ 3175.47), linear measurement devices (§ 3175.48), and accounting systems (§ 3175.49) are approved for use at FMPs under the conditions and circumstances stated in those sections.

For the specified types of equipment requiring BLM approval, as explained in the section-specific discussions of this preamble, this rule requires that equipment must be reviewed by the PMT and approved by the BLM. The PMT, which consists of a team of measurement experts, will base its review of such equipment on data submitted by individual operators, companies, or equipment manufacturers. Unlike the variance process under Order 5, which limits approvals to specific facilities, and requires that operators submit separate requests to use the same equipment at different facilities, this final rule provides that once the PMT reviews and the BLM approves a piece of equipment or measurement process, that approval will be posted to the BLM website (

www.blm.gov

), and any operator may rely on that approval at any facility, provided the operator follows any attached conditions of use. The PMT process provides a way for the BLM to approve new technology without having to update its regulations, issue other forms of guidance (such as NTLs) or grant approvals on a case-by-case basis.

While the final rule provides that the PMT will review requests and make recommendations to the BLM for approval, it is the BLM's intent that such approvals will be issued by a BLM AO with authority over the oil and gas program nationally (

e.g.

, the Director, a Deputy Director, or an Assistant Director), as opposed to that authority being delegated to a local level. This is consistent with recommendations from the RPC, GAO, and OIG that decisions on variances be granted at the national level to ensure they are consistent and have the appropriate perspective, as opposed to more local levels, which can result in inconsistencies among BLM field offices.

The BLM received many comments that expressed concerns over the role, authority, staffing, process, and approval timeframes relating to the PMT. Several comments stated that the PMT should include industry members, academia, tribal members, and State Government representatives. Comments also stated that the PMT should be chartered under the Federal Advisory Committee Act (FACA) and that all meetings should be open to the public. The BLM finds formalizing the PMT and requiring a FACA-chartered committee to be inconsistent with expediting the approval of new and existing technology. As described in the final rule, the PMT will consist of measurement experts within the BLM whose primary job function is to review test data for new and existing technology and recommend approval or denial of that technology to the BLM. While the team has not yet been assembled, the BLM believes that once the PMT is fully staffed, reviews will take 30 to 60 days, assuming that the proper testing has been done and all pertinent data have been submitted to the PMT.

Under a FACA charter, as favored by some commenters, reviews would take much longer, possibly even years. A FACA charter first requires all members to be vetted and approved by the Secretary. The BLM would then have to publish a notice in the

Federal Register

of all meetings at least 30 days in advance. The BLM does not believe that this is an appropriate forum to review large amounts of test data and perform specialized analysis to determine if a device can meet the performance goals of the rule.

Substantively, the PMT's role in reviewing specific makes and models of equipment and making recommendations to the BLM for approval of particular equipment under this rule is similar to the authority for a BLM field office to issue variances under the existing Onshore Orders. The only difference between the existing variance process and the PMT is that under the existing variance process reviews are performed at the field-office level on a case-by-case basis; under this final rule these reviews will be performed once by a single entity at the Washington-Office level. Ultimately, the PMT makes recommendations for approval, and the BLM retains full discretion to concur with or reject such recommendations. In the final rule to update and replace Order 3, § 3170.8 has been revised to add a new paragraph (b) that addresses the appeals procedure for PMT recommendations that are approved by the BLM. The BLM did not make any changes to the rule based on these comments.

Other commenters stated that the rule should provide for administrative review of all recommendations made by the PMT. The BLM agrees with this comment and has added an administrative review to the PMT process as part of the final rule updating and replacing Order 3 (see 43 CFR 3170.8(b)). Under this process, any approval or denial made by the BLM based on a PMT recommendation can be administratively appealed to the Assistant Secretary for Lands and Minerals, or their designee. Using the analogy of the existing field office variance review process discussed earlier, the approval or denial of a variance for new technology under the current process could be appealed by anyone adversely affected by that approval or denial. Likewise, any decision made by the BLM regarding technology reviewed by the PMT is also subject to appeal by anyone adversely affected by that decision.

Several commenters said that the PMT would favor large companies that could afford elaborate “Cadillac” proposals. The BLM disagrees with this comment and did not make any changes as a result. The reviews performed by the PMT are not exclusive. In other words, if a large operator submitted a “Cadillac” proposal to the PMT and a small operator submitted a “Chevy” proposal (simple and inexpensive) to the PMT, the PMT would review both proposals on their merits. If the PMT and then, ultimately, the BLM determined that both proposals met the performance goals in this rule, then both proposals would be approved and posted on the BLM website. Once posted, any operator could use either the “Cadillac” or “Chevy” technology without any further approval needed.

One commenter stated that the PMT should develop testing manuals that the industry could follow. While the BLM did not make any changes to the rule based on this comment, the BLM agrees that manuals could provide useful guidance. Once formed, the PMT will consider developing nonbinding te

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