MEMORANDUM

To: Docket # EPA-HQ-OAR-2011-0512

From: Mark de Figueiredo, EPA/CCD

Date: November 10, 2014

Subject: Assessment of Impacts of the 2014 Final Revisions to Subpart W

1. Introduction

The EPA is finalizing technical revisions and other clarifications to subpart W of the 

Greenhouse Gas Reporting Rule (40 CFR part 98, subpart W) (hereinafter referred to as 

“subpart W”). In this memorandum, we discuss the potential burden to reporters affected by 

these amendments.

The EPA estimated the cost of the amendments to subpart W as the incremental costs 

above the previously estimated costs of the requirements under subpart W.1 The EPA calculated 

this incremental cost based on the number of reporters in each segment that are likely to be 

affected by the amendments. The details for estimating this incremental cost (the potential 

burden to reporters) are included in the sections below.

Costs to reporters associated with this rulemaking are expressed as labor costs (i.e., the 

cost of labor by facility staff to meet the rule’s amendments). The EPA determined labor costs

using an approach consistent with previous impacts analyses associated with the Greenhouse Gas 

Reporting Program (GHGRP). For all industry segments the labor rates are $78.29 for engineers

and $66.57 for technicians.2, 3

2. Summary of Amendments

In this memorandum, we summarize the potential burden to reporters affected by the

substantive revisions in the rule. In addition to these substantive revisions, the EPA is also 

finalizing minor technical revisions to subpart W to improve readability, to create consistency in 

terminology, and/or to correct typographical or other errors. These minor technical revisions will 

not impart additional burden on reporters and are not discussed in this memorandum.4

The following sections detail the more substantive changes to subpart W that may or may 

not impact reporters.

1 The previously estimated costs of the requirements under subpart W are included in the Information Collection Request for the

Greenhouse Gas Reporting Program, OMB Control No. 2060-0629, EPA ICR No. 2300.10, May 2013 and EPA ICR No. 

2300.12, August 2013. 2 None of the amendments require an adjustment to middle and senior management labor hours. 

3 The engineering and technician labor rates are from the May 2011 National Industry-Specific Occupational Employment and 

Wage Estimates (http://www.bls.gov/oes/current/oessrci.htm) and Employer Costs for Employee Compensation for June of 2011 

(http://www.bls.gov/news.release/archives/ecec_09082011.pdf).

4 For explanation of the minor technical revisions refer to the memorandum, “Minor Technical Corrections to Subpart W, 

Greenhouse Gas Reporting Rule: 2014 Revisions and Confidentiality Determinations for Petroleum and Natural Gas Systems; 

Final Rule” in Docket ID No. EPA-HQ-OAR-2011-0512.

1

 
2.1 Gas Well Completions and Workovers

The EPA is revising reporting requirements for gas well completions and workovers to 

differentiate between completions and workovers with different well type combinations in each 

sub-basin category. The EPA is clarifying the number of measurements or calculations that must 

be taken to estimate the average ratio of flowback rate (FRM). Reporters may have to conduct 

more tests/measurements, because a separate FRM value is required for each well type

combination. This revision represents a potential increase to burden and cost. Using 2012 

subpart W data reported to EPA as of September 1, 2013, the EPA determined that 40% of 

onshore production facilities reported completion and workover emissions and 23% of these

facilities reported emissions from completions under more than one well type combination. It 

was estimated that these facilities with completions will have to take two additional 

measurements to determine additional FRM values and that an engineer will take approximately

8 hours to conduct each additional measurement. Therefore, engineering labor hours (at a cost of 

$78.29/hour) were adjusted upwards by 1.472 hours per reporter [16 * 0.40 * 0.23 = 1.472].

The EPA is modifying Equation W-10A (which is a calculation that determines annual 

volumetric total gas emissions from gas well venting during completions or workovers following 

hydraulic fracturing) in order to enable quantification of natural gas emitted during the initial 

flowback stage of a well when insufficient gas is present to enable separation and metering. In 

addition, the EPA is modifying Equation W-10A to ensure reporters account for sales gas 

volume only once in this calculation. The new method is similar in complexity as the previous 

method and uses measurements that are of similar complexity; therefore, these changes to 

Equation W-10A will not impose any additional (or reduced) burden and costs.

The EPA is revising Equation W-13 (which is a calculation that determines annual 

volumetric total gas emissions from gas well venting during completions or workovers without 

hydraulic fracturing) to separate the calculation of emissions from workovers and the calculation 

of emissions from completions into two equations. Reporters will have to perform two 

calculations as opposed to one; however, it is the same calculation that reporters are currently 

doing broken into two steps. Therefore, these changes to Equation W-13 will not impose any 

additional (or reduced) burden and costs.

2.2 Flare Stack Emissions

The EPA is revising the calculation and reporting requirements for onshore natural gas 

transmission compression, underground natural gas storage, liquefied natural gas (LNG) storage, 

and LNG import and export to include emissions from flare stacks. This revision represents a

potential increase to burden and cost for reporters in these four industry segments. Facilities in 

these industry segments that have flares do not have to report flare stack emissions currently, but 

will need to collect flare data, calculate, and report these emissions under the revisions. 

However, because underground natural gas storage and LNG storage facilities do not report 

flared emissions for compressors, which is required under the current rule if these facilities have

flared emissions associated with their compressors, the EPA assumed that 0% of these facilities 

operate flares. Therefore, this revision will not impose any additional (or reduced) burden and 

costs on these two industry segments. 

In order to calculate the potential increase to reporters in the onshore natural gas 

transmission compression and LNG import and export industry segments, the EPA estimated that 

2
the percent of facilities that will report flare stack emissions was equal to the percent of facilities 

that reported flared emissions for compressors for each of these two industry segments. Using 

2012 subpart W data reported to EPA as of September 1, 2013, 1% of the onshore natural gas 

transmission compression facilities and 14% of LNG import and export facilities reported flared 

emissions from compressors. The incremental increase in hours per reporter was then determined 

by multiplying the percent of facilities that would report flare stack emissions in each industry 

segment (i.e., 1% and 14%, respectively) by 20 minutes (i.e., the amount of time the EPA 

estimated an engineer will need to collect data and estimate emissions). The result was an 

estimated increase in the engineering labor hours of 0.002 hours per reporter (at a rate of 

$78.29/hour) in the onshore natural gas transmission compression industry segment; and an 

increase of 0.05 hours per reporter (at a rate of $78.29/hour) in the LNG import and export 

industry segment.

2.3 Centrifugal and Reciprocating Compressor Venting

The EPA is revising the monitoring requirements so that, in cases where multiple 

compressor sources are manifolded together downstream, reporters can measure downstream of 

the manifold and will not have to measure the compressor sources individually. For manifolded 

compressors, reporters will also have to report activity data for the manifold (i.e., number of 

compressor sources manifolded together, mode of each compressor). Reporters will no longer be 

required to annually measure compressor sources that are manifolded individually. Instead, 

reporters will measure the manifolded group of compressor sources once per year. Therefore, 

this change is a burden reduction for reporters that have two or more compressor sources 

manifolded together. This revision is expected to affect only compressors at onshore natural gas 

processing facilities, onshore natural gas transmission compression facilities, underground 

natural gas storage facilities, LNG storage facilities, and LNG import and export equipment 

facilities.5 The EPA assumed that facilities with manifolded compressor sources will use the new 

option. Therefore, the EPA calculated the decrease in burden associated with this measurement 

option by adjusting engineering and technician labor hours downwards per reporter for each 

industry segment that could use the new option. This adjustment downward in labor hours was 

determined by first estimating the average number of compressors that are located at a facility in 

each affected industry segment,

6 and then multiplying the average number of compressors 

located at a facility by 10% (because it was assumed that 10% of the facilities will have 

manifolded compressor sources). The EPA then took the number of manifolded compressor 

sources and multiplied it by 10 minutes—the estimated time for a technician to take the 

measurement, and by 30 minutes—the estimated time for an engineer to perform the calculation. 

The calculation resulted in a decrease in 0.35 engineering labor hours (at a rate of 

$78.29/hour) and 0.12 technician labor hours (at a rate of $66.75/hour) per reporter for the 

onshore natural gas processing and underground natural gas storage industry segments, a 

5 The manifold measurement option would not impact onshore petroleum and natural gas production facilities 

because compressor emission calculation methods are different for this industry segment. It would not impact 

natural gas distribution facilities or offshore petroleum and natural gas production facilities because compressor 

emission calculation methods are not required for these industry segments.

6 The EPA determined the average number of compressors per facility using 2012 subpart W data reported to EPA 

as of September 1, 2013: 8 compressors at onshore natural gas processing facilities; 6 compressors at onshore 

natural gas transmission compression facilities; 8 compressors at underground natural gas storage facilities; and 

5 compressors at LNG import and export equipment facilities.

3

 
decrease in 0.25 engineering labor hours and 0.08 technician labor hours per reporter for the 

onshore natural gas transmission compression industry segment, a decrease in 0.05 engineering 

labor hours and 0.02 technician labor hours per reporter for the LNG storage industry segment,

and a decrease in 0.20 engineering labor hours and 0.07 technician labor hours per reporter for 

the LNG import and export equipment industry segment.

In addition, the EPA is removing vented compressor emissions routed to a flare from the 

compressor emissions total (clarifying that these emissions should be reported in the flared 

emissions total) and retain the requirement to report uncontrolled vented emissions from 

compressors. Reporters will no longer be required to perform individual compressor leak 

measurements or continuous measurements, but rather perform a single calculation under the 

flare stack emissions methodology. The latter will be less burdensome, because it only requires 

reporters to either continuously monitor total flow and composition to the flare or use 

engineering estimates. This amendment is expected to affect only compressors routed to a flare 

at onshore natural gas processing facilities, onshore natural gas transmission compression 

facilities, and LNG import and export equipment facilities.7 The EPA calculated the decrease in 

burden associated with this amendment by adjusting engineering and technician labor hours 

downwards per reporter for each affected industry segment. The first steps in adjusting the labor 

hours included the following: (1) estimating the average number of compressors that are located 

at a facility in each affected industry segment;

8 (2) estimating the average percent of facilities 

that report under the “other flare stacks” category in each affected industry segment;

9

and

(3) estimating the average percent of the compressors at facilities that report flared emissions for 

reciprocating or centrifugal compressors.

10 The downward adjustment in labor hours was 

determined by multiplying the three estimates by 10 minutes—the estimated time for a 

technician to take the measurement, and by 30 minutes—the estimated time for an engineer to 

perform the calculation. 

This calculation resulted in a decrease of 0.58 engineering labor hours (at a rate of 

$78.29/hour) and 0.19 technician labor hours (at a rate of $66.57/hour) per reporter for the 

onshore natural gas processing industry segment, a decrease in 0.02 engineering labor hours and 

0.01 technician labor hours per reporter for the onshore natural gas transmission compression 

7 This amendment would not impact onshore petroleum and natural gas production facilities because compressor 

flare emission calculation methods are different for this industry segment. It would not impact natural gas 

distribution facilities or offshore petroleum and natural gas production facilities because compressor flare emission 

calculation methods are not required for these industry segments. It would not impact underground natural gas 

storage and LNG storage facilities because underground natural gas storage and LNG storage facilities do not have 

compressors controlled by flares according to 2012 subpart W data reported to EPA as of September 1, 2013.

8 The EPA determined the average number of compressors per facility using 2012 subpart W data reported to EPA 

as of September 1, 2013: 8 compressors at onshore natural gas processing facilities; 6 compressors at onshore 

natural gas transmission compression facilities; and 5 compressors at LNG import and export equipment facilities. 9 The EPA determined the percent of facilities with flares using 2012 subpart W data reported to EPA as of 

September 1, 2013: 21% of facilities in onshore natural gas processing; <1% of facilities in onshore natural gas 

transmission compression; and 14% of facilities in LNG import and export equipment).

10 The EPA determined the percent of the compressors at facilities with flares that are actually venting to flares 

using 2012 subpart W data reported to EPA as of September 1, 2013: 69% of the compressors are venting to flares at

onshore natural gas processing facilities; 92% of the compressors at these facilities are venting to flares at onshore 

natural gas transmission compression facilities; and 100% of the compressors are venting to flares at LNG import 

and export facilities.

4

 
industry segment, and a decrease in 0.36 engineering labor hours and 0.12 technician labor hours 

per reporter for the LNG import and export equipment industry segment.

The EPA is also finalizing that compressors not measured in the “not-operatingdepressurized-mode” for over three years, must be measured in the “not-operatingdepressurized-mode” at the next scheduled shutdown. Regardless of when the “not-operatingdepressurized-mode” will be measured, the reporter will still be required to conduct an annual 

measurement in whatever mode the compressor is found. Therefore, the frequency of

measurements will be unchanged, and this change will not impose any additional (or reduced) 

burden and costs.

2.4 Pneumatic Devices

The EPA is simplifying the procedure for determining the counts of pneumatic devices 

operating each year as well as modifying Equation W-1 to calculate the volume of emissions 

instead of the mass. The mass still must be calculated using procedures in 98.233(u), but the 

approach is consistent with other emission source types. For the onshore petroleum and natural 

gas production industry segment, reporters continue to have the option in the first two reporting 

years to estimate counts of pneumatic devices using engineering estimates. These changes will

not impose any additional (or reduced) burden and costs.

2.5 Liquids Unloading

The EPA is modifying the liquids unloading calculation to annualize venting data for 

facilities that use Calculation Method 1. The EPA is also revising Calculation Method 1 at 

40 CFR 98.233(f)(1) to separate the calculation and reporting of emissions from wells that have 

plunger lifts and wells that do not have plunger lifts. The impacts assessment assumed that 

Calculation Method 2 and Calculation Method 3 are lower-burden options than Calculation 

Method 1 and that reporters will choose the lower-burden option. While the changes to 

Calculation Method 1 will increase facility flexibility, no changes were made to Calculation 

Method 2 or Calculation Method 3. Therefore, these changes will not impose any additional (or 

reduced) burden and costs.

2.6 Blowdown Vent Stacks

The EPA is revising the calculation for “unique physical volume” so reporters can report 

emissions from blowdown vent stacks by equipment type instead of by “unique physical 

volume.” Although reporters will no longer be required to report blowdown vent stack emissions 

by each “unique physical volume,” reporters still have to calculate blowdown vent stack 

emissions from each “unique physical volume.” Therefore, this change will not impose any 

additional (or reduced) burden and costs.

The EPA is allowing the optional use of a compressibility factor in Equations W-14A, 

W-14B, W-33 and W-34. As at proposal, the use of a default value is assumed to be the option 

with the lowest reporter burden and this change will not impose any additional (or reduced) 

burden and costs.

The EPA is allowing an option to directly measure blowdown emissions in lieu of 

performing “unique physical volume” calculations. Although this option may decrease burden 

for those reporters that currently measure blowdown emissions, because they could simply report 

5
these measured emissions (without the burden of performing calculations), the EPA 

conservatively assumed that facilities would not directly measure all of their “unique physical 

volumes” and therefore the EPA estimated that this change would not impose any additional (or 

reduced) burden and costs. The EPA is also adding an optional calculation method (40 CFR 

98.233(i)(3)) for blowdown emissions for situations where a flow meter is in place and including 

associated reporting requirements in 40 CFR 98.236. As this is an optional calculation, this 

change will not impose any additional (or reduced) burden and costs.

2.7 Associated Gas Venting and Flaring

The EPA is modifying the calculation method for associated gas venting and flaring to 

account for situations where part of the gas is going to the sales line. The reporter will still have 

to perform a similar calculation to what is currently being required. The calculation method 

modifies the current equation to include a new term for the volume of sales gas, which is already 

being calculated elsewhere and/or can be estimated. Therefore, this change will not impose any 

additional (or reduced) burden and costs.

The EPA is not finalizing the addition of the proposed term “EREp,q” for emissions 

reported under other sources. This change will not impose any additional (or reduced) burden 

and costs.

2.8 Above Grade Metering-Regulating Stations

The EPA is finalizing technical revisions to the natural gas distribution segment to clarify 

the calculation methodologies and reporting requirements for above grade metering-regulating 

stations. The rule clarifies that reporters calculate only two emission factors (one for CO2 and 

one for CH4) for meter/regulator runs instead of separate emission factors for all component 

types. These changes will not impose any additional (or reduced) burden and costs.

2.9 GHG Emissions from Natural Gas Volume Emissions 

The EPA is allowing for the use of either site-specific composition data or a default gas 

composition in the calculation of natural gas emissions for natural gas transmission compression, 

underground natural gas storage, LNG storage, LNG import and export, and natural gas 

distribution facilities. This allowance will not impose any additional (or reduced) burden and 

costs.

2.10 Best Available Monitoring Methods (BAMM)

As a change from proposal, the EPA is revising 40 CFR 98.234(f) to provide short-term 

transitional BAMM. BAMM was designed to be a temporary flexibility mechanism and not a 

permanent option in the rule. Reporters have the option of using BAMM from January 1, 2015 to 

March 31, 2015 without prior EPA approval for certain parameters that cannot reasonably be 

measured according to the monitoring and QA/QC requirements of 40 CFR 98.234. Reporters 

also have the opportunity to request an extension for the use of BAMM from April 1, 2015 

through December 31, 2015. Because BAMM is optional, the transitional BAMM provisions do

not change the burden associated with the methods of subpart W.

6
2.11 Reporting Provisions

Also part of this rule, the EPA is adding 247 new data elements, while substantially 

revising 13 data elements and deleting 34 data elements that were required to be reported under 

Part 98. The list of these data reporting elements are listed in Appendix A, as Table A-1, 

Table A-2, and Table A-3, respectively.

The new and revised data elements will impose additional burden and costs because, for 

each of the new and revised data elements required to be reported, reporters will be required to 

calculate the data element using readily available data, and report the value to the EPA via the 

EPA’s Electronic Greenhouse Gas Reporting Tool (e-GGRT) as part of the annual report 

currently required under Part 98. The deletion of data elements reduces burden for reporters.

The EPA calculated the increase in burden associated with new and revised data elements 

by adjusting engineering labor hours upwards per reporter for all industry segments. This 

increase in labor hours was determined by first adjusting the number of new and revised data 

elements for each industry segment using the percentage of facilities that reported emissions for 

each emission source, according to 2012 subpart W data reported to the EPA as of September 1, 

2013.

As shown in Appendix A, the new, revised, and deleted data reporting elements fall into 

28 separate categories and are not universally reported by all eight industry segments. Table 1, 

Table 2, and Table 3 show the estimated counts of data reporting elements by data element 

category and industry segment for new elements, revised elements, and deleted elements, 

respectively. The totals are shown at the bottom of each table and match the counts above:

247 new reporting elements, 13 revised reporting elements and 34 deleted reporting elements.

7
Table 1. Count of Data Element Categories by Industry Segment for New Data Elements

Data Element Category

All Industry SegmentsOnshore Petroleum and Natural Gas ProductionOffshore Petroleum and Natural Gas ProductionOnshore Natural Gas ProcessingOnshore Natural Gas Transmission CompressionUnderground Natural Gas StorageNatural Gas DistributionLNG Import and ExportEquipmentLNG Storage

Natural Gas Pneumatic Device Venting 3 3 0 0 3 3 0 0 0

Natural Gas Pneumatic Pump Venting 2 2 0 0 0 0 0 0 0

Acid Gas Removal 16 16 0 16 0 0 0 0 0

Dehydrators 18 18 0 18 0 0 0 0 0

Well Venting for Liquids Unloading 12 12 0 0 0 0 0 0 0

Completions and Workovers with Hydraulic 

Fracturing

7 7 0 0 0 0 0 0 0

Completions and Workovers without 

Hydraulic Fracturing

9 9 0 0 0 0 0 0 0

Blowdown Vent Stacks 8 0 0 8 8 0 0 8 0

Onshore Production Storage Tanks 10 10 0 0 0 0 0 0 0

Transmission Storage Tanks 10 0 0 0 10 0 0 0 0

Well Testing Venting and Flaring 5 5 0 0 0 0 0 0 0

Associated Natural Gas Venting and Flaring 6 6 0 0 0 0 0 0 0

Flare Stack Emissions 3 3 0 3 3 3 0 3 3

Centrifugal Compressors 33 0 0 33 33 33 0 33 33

Reciprocating Compressors 33 0 0 33 33 33 0 33 33

Equipment Leaks by Leak Detection 9 0 0 3 3 3 9 3 3

Equipment Leaks by Population Counts 9 5 0 0 0 3 7 3 3

EOR Injection Pump Blowdown 5 5 0 0 0 0 0 0 0

EOR Hydrocarbon Liquid Dissolved CO2 2 2 0 0 0 0 0 0 0

Combustion 5 5 0 0 0 0 5 0 0

Natural Gas Distribution 7 0 0 0 0 0 7 0 0

Onshore Petroleum and Natural Gas 

Production

13 13 0 0 0 0 0 0 0

Offshore Petroleum and Natural Gas 

Production

2 0 2 0 0 0 0 0 0

Onshore Natural Gas Processing 7 0 0 7 0 0 0 0 0

Onshore Natural Gas Transmission 

Compression

5 0 0 0 5 0 0 0 0

Underground Natural Gas Storage 3 0 0 0 0 3 0 0 0

LNG Import and Export Equipment 2 0 0 0 0 0 0 2 0

LNG Storage 3 0 0 0 0 0 0 0 3

TOTAL 247 121 2 121 98 81 28 85 78

8
Table 2. Count of Data Element Categories by Industry Segment

for Revised Data Elements

Data Element Category

All Industry SegmentsOnshore Petroleum and Natural Gas ProductionOffshore Petroleum and Natural Gas ProductionOnshore Natural Gas ProcessingOnshore Natural Gas Transmission CompressionUnderground Natural Gas StorageNatural Gas DistributionLNG Import and Export EquipmentLNG Storage

Natural Gas Pneumatic Device Venting 0 0 0 0 0 0 0 0 0

Natural Gas Pneumatic Pump Venting 0 0 0 0 0 0 0 0 0

Acid Gas Removal 2 2 0 2 0 0 0 0 0

Dehydrators 0 0 0 0 0 0 0 0 0

Well Venting for Liquids Unloading 1 1 0 0 0 0 0 0 0

Completions and Workovers with Hydraulic 

Fracturing

1 1 0 0 0 0 0 0 0

Completions and Workovers without 

Hydraulic Fracturing

2 2 0 0 0 0 0 0 0

Blowdown Vent Stacks 0 0 0 0 0 0 0 0 0

Onshore Production Storage Tanks 1 1 0 0 0 0 0 0 0

Transmission Storage Tanks 0 0 0 0 0 0 0 0 0

Well Testing Venting and Flaring 0 0 0 0 0 0 0 0 0

Associated Natural Gas Venting and Flaring 0 0 0 0 0 0 0 0 0

Flare Stack Emissions 0 0 0 0 0 0 0 0 0

Centrifugal Compressors 1 0 0 1 1 1 0 1 1

Reciprocating Compressors 1 0 0 1 1 1 0 1 1

Equipment Leaks by Leak Detection 1 0 0 0 0 0 1 0 0

Equipment Leaks by Population Counts 0 0 0 0 0 0 0 0 0

EOR Injection Pump Blowdown 1 1 0 0 0 0 0 0 0

EOR Hydrocarbon Liquid Dissolved CO2 0 0 0 0 0 0 0 0 0

Combustion 2 0 0 0 0 0 2 0 0

Natural Gas Distribution 0 0 0 0 0 0 0 0 0

Onshore Petroleum and Natural Gas 

Production

0 0 0 0 0 0 0 0 0

Offshore Petroleum and Natural Gas 

Production

0 0 0 0 0 0 0 0 0

Onshore Natural Gas Processing 0 0 0 0 0 0 0 0 0

Onshore Natural Gas Transmission 

Compression

0 0 0 0 0 0 0 0 0

Underground Natural Gas Storage 0 0 0 0 0 0 0 0 0

LNG Import and Export Equipment 0 0 0 0 0 0 0 0 0

LNG Storage 0 0 0 0 0 0 0 0 0

TOTAL 13 8 0 4 2 2 3 2 2

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Table 3. Count of Data Element Categories by Industry Segment

for Deleted Data Elements

Data Element Category

All Industry SegmentsOnshore Petroleum and Natural Gas ProductionOffshore Petroleum and Natural Gas ProductionOnshore Natural Gas ProcessingOnshore Natural Gas Transmission CompressionUnderground Natural Gas StorageNatural Gas DistributionLNG Import and Export EquipmentLNG Storage

Natural Gas Pneumatic Device Venting 0 0 0 0 0 0 0 0 0

Natural Gas Pneumatic Pump Venting 0 0 0 0 0 0 0 0 0

Acid Gas Removal 0 0 0 0 0 0 0 0 0

Dehydrators 0 0 0 0 0 0 0 0 0

Well Venting for Liquids Unloading 0 0 0 0 0 0 0 0 0

Completions and Workovers with Hydraulic 

Fracturing

4 4 0 0 0 0 0 0 0

Completions and Workovers without 

Hydraulic Fracturing

0 0 0 0 0 0 0 0 0

Blowdown Vent Stacks 7 0 0 7 7 0 0 7 0

Onshore Production Storage Tanks 11 11 0 0 0 0 0 0 0

Transmission Storage Tanks 0 0 0 0 0 0 0 0 0

Well Testing Venting and Flaring 0 0 0 0 0 0 0 0 0

Associated Natural Gas Venting and Flaring 0 0 0 0 0 0 0 0 0

Flare Stack Emissions 0 0 0 0 0 0 0 0 0

Centrifugal Compressors 6 0 0 6 6 6 0 6 6

Reciprocating Compressors 3 0 0 3 3 3 0 3 3

Equipment Leaks by Leak Detection 2 0 0 2 0 0 0 0 0

Equipment Leaks by Population Counts 0 0 0 0 0 0 0 0 0

EOR Injection Pump Blowdown 0 0 0 0 0 0 0 0 0

EOR Hydrocarbon Liquid Dissolved CO2 0 0 0 0 0 0 0 0 0

Combustion 1 1 0 0 0 0 1 0 0

Natural Gas Distribution 0 0 0 0 0 0 0 0 0

Onshore Petroleum and Natural Gas 

Production

0 0 0 0 0 0 0 0 0

Offshore Petroleum and Natural Gas 

Production

0 0 0 0 0 0 0 0 0

Onshore Natural Gas Processing 0 0 0 0 0 0 0 0 0

Onshore Natural Gas Transmission 

Compression

0 0 0 0 0 0 0 0 0

Underground Natural Gas Storage 0 0 0 0 0 0 0 0 0

LNG Import and Export Equipment 0 0 0 0 0 0 0 0 0

LNG Storage 0 0 0 0 0 0 0 0 0

TOTAL 34 16 0 18 16 9 1 16 9

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Using 2012 subpart W data reported to EPA as of September 1, 2013, the number of 

reporters that reported each data element category was determined. Using the total number of 

reporters in each industry segment, the percentage of reporters by industry segment was 

calculated for each data element category. The percentages are shown in Table 4.

Table 4. Percentage of Facilities in Each Industry Segment Reporting Each Data Element

Type for the 2012 Calendar Year (as of September 1, 2013)a

Data Element Category b,c

Onshore Petroleum and Natural Gas ProductionOffshore Petroleum and Natural Gas ProductionOnshore Natural Gas ProcessingOnshore Natural Gas Transmission CompressionUnderground Natural Gas StorageNatural Gas DistributionLNG Import and ExportEquipmentLNG Storage

Natural Gas Pneumatic Device 

Venting

83.50% 0.00% 0.00% 70.84% 77.55% 0.00% 0.00% 0.00%

Natural Gas Pneumatic Pump 

Venting

69.38% 0.00% 0.00% 0.00% 0.00% 0.00% 0.00% 0.00%

Acid Gas Removal 5.57% 0.00% 55.56% 0.00% 0.00% 0.00% 0.00% 0.00%

Dehydrators 51.49% 0.00% 72.22% 0.00% 0.00% 0.00% 0.00% 0.00%

Well Venting for Liquids Unloading 50.30% 0.00% 0.00% 0.00% 0.00% 0.00% 0.00% 0.00%

Completions and Workovers with 

Hydraulic Fracturing

39.36% 0.00% 0.00% 0.00% 0.00% 0.00% 0.00% 0.00%

Completions and Workovers 

without Hydraulic Fracturing

38.17% 0.00% 0.00% 0.00% 0.00% 0.00% 0.00% 0.00%

Blowdown Vent Stacks 0.00% 0.00% 66.92% 93.52% 0.00% 0.00% 87.50% 0.00%

Onshore Production Storage Tanks 83.70% 0.00% 0.00% 0.00% 0.00% 0.00% 0.00% 0.00%

Transmission Storage Tanks 0.00% 0.00% 0.00% 23.11% 0.00% 0.00% 0.00% 0.00%

Well Testing Venting and Flaring 2.19% 0.00% 0.00% 0.00% 0.00% 0.00% 0.00% 0.00%

Associated Natural Gas Venting and 

Flaring

29.82% 0.00% 0.00% 0.00% 0.00% 0.00% 0.00% 0.00%

Flare Stack Emissions 42.74% 0.00% 73.99% 0.00% 0.00% 0.00% 0.00% 0.00%

Centrifugal Compressors 0.00% 0.00% 29.04% 64.15% 18.37% 0.00% 37.50% 0.00%

Reciprocating Compressors 0.00% 0.00% 74.24% 60.69% 95.92% 0.00% 87.50% 40.00%

Equipment Leaks by Leak Detection 0.00% 0.00% 93.69% 93.52% 83.67% 56.04% 100.00% 60.00%

Equipment Leaks by Population 

Counts

94.63% 0.00% 0.00% 0.00% 79.59% 0.00% 62.50% 0.00%

EOR Injection Pump Blowdown 1.39% 0.00% 0.00% 0.00% 0.00% 0.00% 0.00% 0.00%

EOR Hydrocarbon Liquid Dissolved 

CO2

2.58% 0.00% 0.00% 0.00% 0.00% 0.00% 0.00% 0.00%

Combustion 91.25% 0.00% 0.00% 0.00% 0.00% 46.70% 0.00% 0.00%

(continued)

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Table 4. Percentage of Facilities in Each Industry Segment Reporting Each Data Element 

Type for the 2012 Calendar Year (as of September 1, 2013)a (continued)

Data Element Category b,c

Onshore Petroleum and Natural Gas ProductionOffshore Petroleum and Natural Gas ProductionOnshore Natural Gas ProcessingOnshore Natural Gas Transmission CompressionUnderground Natural Gas StorageNatural Gas DistributionLNG Import and Export EquipmentLNG Storage

Natural Gas Distribution 0.00% 0.00% 0.00% 0.00% 0.00% 100.00% 0.00% 0.00%

Onshore Petroleum and Natural Gas 

Production

100.00% 0.00% 0.00% 0.00% 0.00% 0.00% 0.00% 0.00%

Offshore Petroleum and Natural Gas 

Production

0.00% 100.00% 0.00% 0.00% 0.00% 0.00% 0.00% 0.00%

Onshore Natural Gas Processing 0.00% 0.00% 100.00% 0.00% 0.00% 0.00% 0.00% 0.00%

Onshore Natural Gas Transmission 

Compression

0.00% 0.00% 0.00% 100.00% 0.00% 0.00% 0.00% 0.00%

Underground Natural Gas Storage 0.00% 0.00% 0.00% 0.00% 100.00% 0.00% 0.00% 0.00%

LNG Import and Export Equipment 0.00% 0.00% 0.00% 0.00% 0.00% 0.00% 100.00% 0.00%

LNG Storage 0.00% 0.00% 0.00% 0.00% 0.00% 0.00% 0.00% 100.00%

a A value of 0.00% means either there are no new, revised, or deleted data elements in the particular data element category in 

Tables 1 through 3 or that none of the facilities in the particular industry segment have the type of equipment to which the 

particular data element category applies.

b Counts were based on facilities that indicated with a check box on their annual report that the equipment was present.

c For equipment without an associated checkbox, counts were based on emissions that were zero or higher, assuming that blank 

meant no equipment and zero meant no emissions at this time.

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Using the information from Table 1 through Table 4, the EPA developed “adjusted” 

counts of new and revised data elements per industry segment. The adjusted counts represent the 

average number of new and revised data elements that facilities in each industry will report. 

Some facilities will not report all of the data elements because they do not have the applicable 

equipment. The EPA then multiplied the adjusted number of new and revised data elements for 

each industry segment by 3 minutes per data element—the amount of time that the EPA 

estimated an engineer will need to access the data element from readily available data and submit 

the value via e-GGRT as part of the annual report currently required under Part 98. Table 5

shows the potential labor increase by industry segment associated with the new and revised data 

elements. Appendix B shows how the adjusted new and revised counts were developed.

Table 5. Labor Change Associated with New and Revised Data Elements

Industry Segment

New Data 

Elements

Revised 

Data 

Elements

New Data 

Elements 

Adjusted

Revised 

Data 

Elements 

Adjusted

Adjusted 

Total

Total Change 

in Labor 

Hours per 

Reportera

Onshore Petroleum and 

Natural Gas Production

121 8 60 3 63 3.14b

Offshore Petroleum and 

Natural Gas Production

2 0 2 0 2 0.1

Onshore Natural Gas 

Processing

121 4 73 2 75 3.78

Onshore Natural Gas 

Transmission Compression

98 2 61 1 62 3.1

Underground Natural Gas 

Storage

81 2 48 1 49 2.45

Natural Gas Distribution 28 3 14 1 15 0.80

LNG Import and Export 

Equipment

85 2 55 1 56 2.82

LNG Storage 78 2 18 1 18 0.92

a Engineering labor hours at $78.29/hour

b Example calculation for onshore petroleum and natural gas production: (63 adjusted elements) x (3 minutes/element) x 

(1 hour/60 minutes) = 3.15 hours

The EPA calculated the decrease in burden associated with deletion of data elements by 

adjusting engineering labor hours downwards per reporter for all affected industry segments. 

This decrease in labor hours was determined by first adjusting the number of deleted data 

elements for each industry segment using the same procedure described above for developing 

adjusted counts of new and revised data elements. Table 6 shows the labor adjustment by 

industry segment associated with the deleted data elements. Appendix B shows how the adjusted 

deleted data element counts were developed.

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Table 6. Labor Change Associated with Deleted Data Elements

Industry Segment

Deleted Data 

Elements

Deleted Data 

Elements 

Adjusted

Total Change in Labor 

Hours per Reporter a

Onshore Petroleum and Natural Gas Production 16 12 −0.59b

Offshore Petroleum and Natural Gas Production 0 0 0.00

Onshore Natural Gas Processing 18 11 −0.53

Onshore Natural Gas Transmission Compression 16 12 −0.61

Underground Natural Gas Storage 9 4 −0.20

Natural Gas Distribution 1 0 0.00

LNG Import and Export Equipment 16 11 −0.55

LNG Storage 9 1 −0.06

a Engineering labor hours at $78.29/hour

b Example calculation for onshore petroleum and natural gas production: (12 adjusted elements) x (-3 minutes/element) x (1 

hour/60 minutes) = -0.59 hours

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4. Results of Analysis

The estimated change in burden (labor hours) and cost for the amendments to subpart W 

are summarized by industry segment in Table 7.

Table 7. Annual Average Change in Reporter Burden and Cost

for Subpart W of the GHGRP

Subpart W Industry Segment

Change In

Total Burden 

(Technical 

Labor Hours)

Change In 

Burden 

(Technical 

Labor Hours / 

Reporter)

Change In 

Total Cost

($)

Change In Cost

($ / Reporter)

Onshore Petroleum and Natural Gas 

Production a

4,171 4.04 $325,678 $315

Offshore Petroleum and Natural Gas 

Production b

7 0.10 $564 $8

Onshore Natural Gas Processing c 584 2.01 $46,766 $161

Onshore Natural Gas Transmission 

Compression d

2,465 2.14 $194,183 $169

Underground Natural Gas Storage e 248 1.78 $19,597 $141

Natural Gas Distribution f 122 0.77 $9,585 $60

LNG Import and Export Equipment g 6 1.57 $502 $125

LNG Storage h 74 2.12 $6,603 $189

TOTAL 7,677 --- $603,478 ---

a For Onshore Petroleum and Natural Gas Production, the technical labor hour burden increased from 97,754 hours to 101,924

hours, which increased the total cost from $8,334,208 to $8,659,886.

b For Offshore Petroleum and Natural Gas Production, the technical labor hour burden increased from 3,220 hours to 3,227 

hours, which increased the total cost from $285,215 to $285,779.

c For Onshore Natural Gas Processing, the technical labor hour burden increased from 25,495 hours to 26,078 hours, which 

increased the total cost from $2,346,157 to $2,392,924.

d For Onshore Natural Gas Transmission Compression, the technical labor hour burden increased from 75,506 hours to 77,971

hours, which increased the total cost from $7,307,654 to $7,501,838.

e For Underground Natural Gas Storage, the technical labor hour burden increased from 12,450 hours to 12,697 hours, which 

increased the total cost from $1,164,454 to $1,184,051.

f For Natural Gas Distribution, the technical labor hour burden increased from 18,986 hours to 19,109 hours, which increased 

the total cost from $1,658,624 to $1,668,209.

g For LNG Import and Export Equipment, the technical labor hour burden increased from 367 hours to 373 hours, which 

increased the total cost from $39,217 to $39,718.

h For LNG Storage, the technical labor hour burden increased from 2,954 hours to 3,029 hours, which increased the total cost 

from $285,799 to $292,401.

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