MEMORANDUM 

TO: Docket ID No. EPA-HQ-OAR-2014-0831 

FROM: Alexis McKittrick and Mark de Figueiredo, EPA/CCD

DATE: November 10, 2014 

SUBJECT: Assessment of Impacts of the 2015 Proposed Revisions to Subpart W 

Introduction 

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

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

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

proposed amendments. 

The EPA estimated the cost of these proposed 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 these proposed 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 proposal are expressed as labor costs (i.e., the cost 

of labor by facility staff to meet the proposed amendments), capital costs for equipment and 

travel, and operation and maintenance (O&M) costs. 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 $121.72 for senior 

managers, $106.89 for middle managers, $78.29 for engineers and $66.57 for technicians.2

Summary of Proposed Amendments 

Oil Well Completions and Workovers with Hydraulic Fracturing within the Onshore 

Petroleum and Natural Gas Production Segment 

The EPA is proposing to amend subpart W to clarify the applicability of the current 

provisions for the reporting of GHG emissions from completions and workovers for wells in the 

Onshore Petroleum and Natural Gas Production segment, regardless of whether their primary 

 

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. 2300.15. 

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

Employment and Wage Estimates (http://www.bls.gov/oes/2011/may/oessrci.htm) and Employer Costs for 

Employee Compensation for June of 2011 (http://www.bls.gov/news.release/archives/ecec_09082011.pdf). 
2 

product is oil or natural gas, and to include provisions for the reporting of GHG emissions from 

completions and workovers from oil wells with hydraulic fracturing. The proposed provisions 

include the reporting of activity data on the number of oil wells with hydraulic fracturing and on 

the use of flaring and reduced emissions completions. These proposed revisions represent a 

potential increase to burden and cost because facilities with oil wells would be reporting 

emissions that they were not previously required to report. 

The addition of data elements related to completions and workovers from oil wells with 

hydraulic fracturing is expected to cause an increase in the number of facilities reporting in 

subpart W, because this additional emissions source may cause some facilities to cross the 

applicable 25,000 metric ton carbon dioxide equivalent (CO2e) threshold. We expect that most of 

the facilities that include this emission source already report under subpart W, because the 

owners/operators of these facilities typically own other oil and gas operations that fall within the 

Onshore Petroleum and Natural Gas Production segment. Therefore, we do not anticipate a large 

number of new reporters and assumed that the addition of oil wells with hydraulic fracturing 

would increase the number of new reporters in this segment by 5 percent (%). As documented in 

ICR number 2300.15, the number of existing reporters in the Onshore Petroleum and Natural 

Gas Production segment is 1,033. Therefore, the number of new reporters that are expected to 

exceed the reporting threshold as a result of these proposed changes to subpart W is 

approximately 50 per year. 

The proposed changes will also affect existing reporters. Based on RY2012 subpart W 

data, 322 of the existing facilities in the Onshore Petroleum and Natural Gas Production segment 

already reported sub-basins that are classified in the Oil sub-basin category.3 The number of 

completions and workovers for oil wells with hydraulic fracturing is not known. However, using 

oil well completions data from 2011, we can estimate the number of existing reporters expected 

to report completions and workovers for oil wells with hydraulic fracturing in the future. 

According to DI Desktop, a production database maintained by DrillingInfo, Inc., 6,169 of the 

39,262 conventional and unconventional well completions (for gas and oil) in 2011 were 

identified as oil well completions with hydraulic fracturing.4

 The white paper included a list of 

sub-basins where these oil well completions with hydraulic fracturing took place in 2011. By 

comparing the list of sub-basins identified in the white paper with the list of sub-basins reported 

under subpart W, a list of 246 overlapping facilities were identified. These 246 facilities in the 

Onshore Petroleum and Natural Gas Production segment are located in sub-basins where oil well 

completions with hydraulic fracturing have taken place. Assuming that oil well completions with 

 

3

 http://www.ccdsupport.com/confluence/display/help/Sub-Basin+Selection 

4

 U.S. EPA Office of Air Quality Planning and Standards (OAQPS). Oil and Natural Gas Sector Hydraulically 

Fractured Oil Well Completions and Associated Gas during Ongoing Production: Report for Oil and Natural Gas 

Sector, Oil Well Completions and Associated Gas during Ongoing Production Review Panel. April 2014. Available 

at http://www.epa.gov/airquality/oilandgas/pdfs/20140415completions.pdf. 
3 

hydraulic fracturing in those sub-basins are likely to continue in the future, the number of 

existing reporters that are expected to report completions and workovers for oil wells with 

hydraulic fracturing as a result of these proposed amendments is 246 per year. 

Instead of conducting measurements for each completion of an oil well with hydraulic 

fracturing, each affected reporter is assumed to take “representative” measurements from one oil 

well of each oil well type combination and apply to all wells with that combination (up to 25 

completions and workovers) using Equation W-10A. The oil well type characteristics are as 

follows: 

• Vertical or horizontal (directional drilling) 

• With flaring or without flaring 

• Reduced emission completion/workover or not reduced emission 

completion/workover 

The maximum number of oil well type combinations using the three well type 

characteristics above is eight, but a typical reporter is assumed to have three of these well type 

combinations per sub-basin, no more than 25 completions or workovers for each well type 

combination, and an average of two sub-basins per reporter. Thus, each reporter is assumed to 

perform six oil well measurements per year. 

After the initial flowback period when meters are not typically used, measurements are 

assumed to be made using a volumetric flow meter to measure the gas flow rate during flowback. 

The costs for these meters are included in the “Capital and Operations and Maintenance (O&M) 

Costs” section of this memo. 

These proposed measurements represent a potential increase in burden and cost. It was 

estimated that an engineer would take approximately 24 hours per well to conduct each 

measurement. While flowbacks generally occur over a three to seven-day period, the 

measurements are assumed to be conducted over a multiple-day period for a total of 24 hours per 

measurement per well. Therefore, engineering labor hours (at a cost of $78.29/hour) were 

adjusted upwards by 24 hours per reporter. Assuming 6 oil well measurements per reporter, the 

labor burden for each reporter is 144 hours per year. Assuming 246 existing reporters and 50 

new reporters, the total burden is estimated at 43,000 labor hours and $3.3 million per year to 

collect data and calculate emissions for oil wells with hydraulic fracturing. 

Onshore Petroleum and Natural Gas Gathering and Boosting Segment 

As part of these proposed amendments, the EPA is proposing to add a new industry 

segment to subpart W, Onshore Petroleum and Natural Gas Gathering and Boosting, that would 

cover emissions from equipment used by gathering and boosting systems that move petroleum 
4 

and natural gas from the well to either larger gathering and boosting systems, natural gas 

processing plants, natural gas transmission pipelines, or natural gas distribution pipelines. This 

proposed revision represents an increase in burden and cost for reporters with sources that would 

be covered by this new industry segment. These sources include venting from natural gas 

pneumatic devices, natural gas driven pneumatic pumps, storage tanks, reciprocating 

compressors, dehydrators, acid gas removal units, and centrifugal compressors; flare stacks; and 

leaks from gathering pipelines and components such as valves and connectors. Facilities in this 

industry segment are not currently required to report subpart W-related GHG emissions, but 

would be required to collect data, calculate, and report these emissions under the proposed 

revisions. 

According to the Office of Pipeline Safety (OPS), there are 400 natural gas gathering 

pipeline operators under regulation by OPS.5

 OPS estimated that 50% of these operators are 

potentially subject to the new regulation (depending upon proximity to population centers), 

resulting in approximately 200 reporters.6

Every producing field that is connected to a gathering and boosting system is assumed to 

have a compressor or a compression station at the connection point to the gathering and boosting 

system, and every compression station is assumed to have a separator and dehydrator to protect 

the compressors. Every separator/dehydration system installation is assumed to have at least one 

storage tank. In between compression points on the gathering line, there will be an 

isolation/blowdown valve. By definition, the Onshore Petroleum and Natural Gas Gathering and 

Boosting segment consists of large, basin-level facilities, so it follows that at least one standalone gas treatment site should be assumed per facility, the purpose of which is to remove 

impurities such as sulfur and carbon dioxide (CO2) from the gas. Each facility would, for safety 

purposes, have one or more flare stacks at various points in the system to avoid venting of gas 

during an upset. Each gas treatment site would likely have a flare stack, an acid gas removal unit 

vent, storage tank vents, gas-driven pneumatic pumps and other pneumatic controllers. The 

stand-alone gas treatment site would be a possible location for an emergency flare system. 

In order to calculate the burden on reporters in the Onshore Petroleum and Natural Gas 

Gathering and Boosting segment, we created a model reporter loosely based on a description of a 

“typical” gathering and boosting system by the Colorado Oil and Gas Conservation 

Commission.7

 

5

 US DOT, Pipeline and Hazardous Materials Safety Administration, Draft Regulatory Evaluation, Regulated 

Natural Gas Gathering Lines, Docket Item No. PHMSA-RSPA-1998-4868-0181. 

6

Ibid. 

7 Who Regulates Pipelines?, Colorado Oil and Gas Conservation Commission Pipeline Safety Staff Presentation, 

July 17, 2013. 
5 

• An average reporter consists of two 40- to 60-mile gathering and boosting 

systems with the same owner/operator within a single basin. 

• Each of the two gathering and boosting systems that comprise the model reporter 

is connected to three producing fields, so six fields total. 

• There is a compression station associated with each connected field and each 

gathering and boosting system has a stand-alone gas treatment facility with a 

compressor station on the outlet side. 

• This “model” reporter would thus have a minimum of eight compression 

(“booster”) stations. 

• There would be an isolation valve/blowdown stack downstream of each booster 

station and downstream of the gas treatment site, so up to eight isolation valves. 

• We assume that two thirds of the “booster” stations would be protected with a 

dehydrator and a separator plus a waste tank. 

• We assume that half the booster stations would have four centrifugal compressors 

and half of the booster stations would be smaller with two reciprocating 

compressors. 

• Each compressor station would use natural gas as fuel and to drive pneumatic 

controllers and equipment. 

• We assume that each of the two gas treatment facilities would have an acid gas 

removal vent, dehydrator, and pneumatic controls. 

• Each of the two gathering and boosting systems that comprise the gathering and 

boosting facility would have at least one metering point, so two meter runs. 

For these proposed amendments, the reporters in the Onshore Petroleum and Natural Gas 

Gathering and Boosting segment will be able to use methods that are already included in subpart 

W. To be consistent with the monitoring and measurement levels of effort used for the existing 

industry segments, all monitoring and measurement levels of effort were estimated using the 

Economic Impact Analysis from November 2010.8

The number of hours per reporter was determined by multiplying the time needed to 

collect data and calculate emissions for each source type by the count of that source type at a 

gathering and boosting facility and then summing the results. The result was an estimate of 4,700 

labor hours and $370,000 in labor costs to collect data and calculate emissions for the new 

Onshore Petroleum and Natural Gas Gathering and Boosting segment. 

Onshore Natural Gas Transmission Pipeline Segment 

As part of these proposed amendments, the EPA is proposing to add a new industry 

segment to subpart W, the Onshore Natural Gas Transmission Pipeline segment. For this new 

 

8

Economic Impact Analysis for the Mandatory Reporting of Greenhouse Gas Emissions Under Subpart W Final

Rule (GHG Reporting); Final Report, U.S. Environmental Protection Agency Office of Atmospheric Programs. 

Climate Change Division. November 2010. Docket Item No. EPA-HQ-OAR-2009-0923-3601. Pages 4-23 through 

4-28.
6 

industry segment, the EPA is proposing to add reporting requirements for emissions from 

blowdowns of natural gas transmission lines between compressor stations. The EPA is proposing 

that reporters would use one of two methods to calculate or measure emissions from pipeline 

blowdown events. One method allows a reporter to calculate emissions based on the volume of 

the pipeline segment between isolation valves that is blown down and the pressure and 

temperature of the gas within the pipeline. This method uses information that should be readily 

available to the reporter (e.g., pipeline length, diameter, and operating pressure) and so should 

not be overly burdensome. The second method allows the reporter to measure the emissions from 

the blowdown using a flow meter on the blowdown vent stack. In both methods, the reporter 

would calculate both methane (CH4) and CO2 emissions from the volume of natural gas vented 

using either default gas composition or engineering estimates of composition. This proposed 

change is a potential increase in burden for reporters that have natural gas transmission pipelines 

covered by the proposed new segment. 

The addition of this new industry segment is expected to affect approximately 100 to 150 

reporters. Due to the upward trend in transmission pipeline expansions, we assumed the larger 

estimate of 150 reporters per year. 

Due to the fact that transmission pipeline compressor stations are unmanned, the pipeline 

throughput and characteristics are continuously monitored. The resulting data would be readily 

available to reporters, so it was assumed that reporters would choose to calculate emissions from 

pipeline blowdown events rather than directly measuring emissions using a flowmeter. This 

choice also results in lower burden to the reporters. 

These proposed measurements represent a potential increase in burden and cost. It was 

estimated that an engineer would spend approximately 8 minutes per calculation per blowdown 

vent stack to estimate emissions for this new industry segment. 

In order to estimate the average number of blowdown stacks, it was assumed that there 

are 25 to 50 miles between isolation valves and approximately 1,600 miles of pipeline are needed 

to exceed the reporting threshold. For a relatively small reporter, the average number of isolation 

valves ranges from 32 to 64 per reporter. For a larger reporter, it was assumed the facility would 

average at least 3,200 miles of pipeline. Using the same assumptions above, the average number 

of isolation valves were assumed to range from 64 to 128 for larger reporters. A value of 72 

blowdown stacks was assumed for an average reporter. 

The number of hours per reporter was determined by multiplying the time needed to 

collect data and calculate emissions by the number of blowdown stacks. The result was an 

estimate of 2,300 labor hours and $180,000 in labor costs per reporter (at a rate of $78.29/hour) 
7 

to collect data and calculate emissions for the new Onshore Natural Gas Transmission Pipeline 

segment. 

Well Identification Numbers 

The EPA is proposing to add reporting requirements for well identification numbers for 

wells in the Onshore Petroleum and Natural Gas Production segment. The well identification 

number is either the US Well Number (formerly called the API Well Number), or if a US Well 

Number has not been assigned, a unique number assigned by the permitting authority. The EPA 

is proposing to require the reporting of well identification numbers for the Onshore Petroleum 

and Natural Gas Production segment in two general cases. First, the EPA proposes to require 

reporters in the Onshore Petroleum and Natural Gas Production segment to report a list of well 

identification numbers for all wells in a sub-basin represented by the reported emissions data. 

Second, for reporters that report emissions using input data that are calculated from 

measurements at individual wells or equipment associated with individual wells the EPA 

proposes to require the reporter to report the well identification number for which those 

measurements were made, or for which the equipment is associated. 

These numbers are readily available and do not require any additional data gathering or 

calculation. Therefore, this proposed change would not impose any additional burden and costs 

(beyond the additional reporting burden, which is discussed in the next section). 

Reporting and Recordkeeping Provisions 

The EPA is proposing that 232 new data elements be reported. The proposed new data 

elements would impose additional burden and costs because, for each of the new data elements 

that would be required to be reported, reporters would 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 EPA calculated the increase in reporting and recordkeeping burden associated with 

new data elements by adjusting labor hours upwards per reporter for all affected industry 

segments. For all three segments, an estimate of 10 hours per year per reporter was allotted for 

reporting via e-GGRT and 10 hours per year per reporter was allotted for recordkeeping. 

These proposed amendments are expected to result in approximately 9,200 labor hours 

and $760,000 in labor costs per year to report data and maintain records. 
8 

Capital and Operations and Maintenance (O&M) Costs 

These proposed amendments to subpart W affect all three industry segments and require 

an inclusion of process- and combustion-related capital and O&M costs for recordkeeping 

equipment, travel, and monitoring equipment. 

Recordkeeping. Assuming the purchase of a 4-drawer vertical file cabinet for storing 

documents and an external hard drive for storing electronic data, the annualized capital cost for 

each reporter in each of the three industry segments is $57.9

For all three affected industry segments, the total annualized capital cost for 

recordkeeping is $22,800 per year. 

Travel. For Onshore Petroleum and Natural Gas Gathering and Boosting facilities, the 

size of a facility was assumed to encompass a much larger geographic area than a relatively 

compact producing field or a gas processing plant. In order to account for emissions 

measurement across a larger area, travel costs were included and assumed to consist of 14 

overnight trips per reporter per year. Assuming $150 per night and $100 per diem,10 a cost of 

$3,500 per reporter per year was assumed. 

No travel costs were assumed for the Onshore Natural Gas Transmission Pipeline 

segment. Due to the fact that compressor stations are unmanned, pipeline throughput is 

continuously monitored and controlled and the engineering data would be readily available to the 

reporters in the Onshore Natural Gas Transmission Pipeline segment. Therefore, reporters are 

assumed to perform engineering calculations based on pressure, temperature, and volume of the 

pipeline segment rather than traveling to the compressor stations to take measurements. 

To be consistent with past ICR analyses, no travel costs were assumed for the Onshore 

Petroleum and Natural Gas Production segment. 

The total annual cost for travel is $700,000 per year. 

Combustion-related costs. These proposed amendments to subpart W that are included in 

this information collection affect the combustion-related capital and O&M costs for the Onshore 

Petroleum and Natural Gas Production segment and the Onshore Petroleum and Natural Gas 

Gathering and Boosting segment. For all other segments, the capital and O&M costs have not 

changed from ICR Number 2300.15. 

 

9

Ibid. Page 4-29. 

10 Economic Impact Analysis for the Mandatory Reporting of Greenhouse Gas Emissions Under Subpart W Final

Rule (GHG Reporting); Final Report, U.S. Environmental Protection Agency Office of Atmospheric Programs. 

Climate Change Division. November 2010. Docket Item No. EPA-HQ-OAR-2009-0923-3601. Page 4-29. 
9 

For Onshore Petroleum and Natural Gas Gathering and Boosting and Onshore Petroleum 

and Natural Gas Production segments, the capital and O&M costs associated with combustion 

emissions were based on the assumptions in ICR Number 2376.02, which assumed the use of 

Tier 1 methodology and included capital equipment costs of $3,500 (annualized over 10 years at 

7% interest to $500 per year) and O&M costs of $1,700 per year.11 The total cost to the two 

industry segments is approximately $550,000 per year. 

There are no combustion sources at Onshore Natural Gas Transmission Pipeline facilities, 

so there are no increases to combustion-related capital and O&M costs as a result of these 

proposed amendments to subpart W. 

Process-related costs. These proposed amendments to subpart W included in this 

information collection affect reporters in the Onshore Petroleum and Natural Gas Production 

segment with completions or workovers of oil wells with hydraulic fracturing. During flowback, 

the natural gas flow rate is monitored using a volumetric flow meter. The capital equipment costs 

were estimated at $2,400 (annualized over 5 years at 7% interest to $585 per year).12 The total 

cost to the 246 existing reporters and 50 new reporters is approximately $170,000 per year. 

 

 

11 Ibid. Page 4-11 

12 Based on an average cost of five volumetric gas flow meters from Omega Engineering, FLO-CORP, Sierra 

Instruments, and Instrumart. 
10 

Results of Analysis 

The estimated change in burden (labor hours) and cost for these proposed amendments to 

subpart W are summarized by industry segment in Table 1. There are no changes in burden to 

these industry segments: Onshore Natural Gas Processing, Onshore Natural Gas Transmission 

Compression, Underground Natural Gas Storage, LNG import and Export Equipment, Natural 

Gas Distribution, LNG Storage, and Offshore Petroleum and Natural Gas Production. 

Table 1. Annual Average Change in Reporter Burden and Cost for Proposed Changes to 

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 Natural Gas 

Transmission Pipeline 5,753 38.35 $477,828 $3,186 

Onshore Petroleum and 

Natural Gas Gathering 

and Boosting 9,297 46.48 $1,899,839 $9,499 

Onshore Petroleum and 

Natural Gas Production 57,963 53.52 $4,827,372 $4,457 

TOTAL 73,012 $7,205,039