MEMORANDUM 

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

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

DATE: September 23, 2015 

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

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) (hereafter 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 these 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 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 comply with the 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 subpart W 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 Amendments 

Oil Well Completions and Workovers with Hydraulic Fracturing within the Onshore 

Petroleum and Natural Gas Production Segment 

The EPA is amending 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 

 

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 

Petroleum and Natural Gas Production segment, regardless of whether their primary 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 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 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 changes to subpart W is approximately 50 per 

year. 

The 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. An EPA white 

paper from April 2014 included a list of sub-basins where oil well completions with hydraulic 

fracturing took place in 2011.4

 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 hydraulic fracturing in those sub-basins are likely to 

continue in the future, the number of existing reporters that are expected to report completions 

 

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 

and workovers for oil wells with hydraulic fracturing as a result of these 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 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 amendments, the EPA is adding 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 and natural gas from the 

well to either larger gathering and boosting systems, natural gas processing plants, natural gas 
4 

transmission pipelines, or natural gas distribution pipelines. This 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 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 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

• 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. 

 

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 

• 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 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 4,600 

labor hours and $360,000 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 amendments, the EPA is adding a new industry segment to subpart W, 

the Onshore Natural Gas Transmission Pipeline segment. For this new industry segment, the 

EPA is adding reporting requirements for emissions from blowdowns of natural gas transmission 

lines between compressor stations. The EPA is finalizing 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 

 

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 

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 change is a potential increase in burden for reporters 

that have natural gas transmission pipelines covered by the new segment. 

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

150 reporters. Due to the upward trend in transmission pipeline expansions, at proposal we 

assumed the larger estimate of 150 reporters per year. However, during the public comment 

period, INGAA asserted that there are 183 reporters regulated by the Pipeline and Hazardous 

Materials Safety Administration (PHMSA), basing the estimate on the number of operators 

required to complete a PHMSA annual report (PHMSA F-7100-2) or are regulated by Federal 

Energy Regulatory Commission (FERC) under Section 311 of the Natural Gas Policy Act 

(NGPA). As a result, the number of reporters in this industry segment was adjusted to 183 in the 

final analysis. 

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 measuring emissions using a flowmeter. This choice also 

results in lower burden to the reporters. 

These 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. At proposal, a 

value of 72 blowdown stacks was assumed for an average reporter. 

 During the public comment period, commenters requested that smaller ancillary 

equipment located along pipelines be excluded from the definition of blowdown for the Onshore 

Natural Gas Transmission Pipelines industry segment. One commenter further noted that the 
7 

number of blowdowns assumed at proposal should be adjusted based on whether or not ancillary 

equipment is included in the count of blowdowns. The commenter suggested that including small 

ancillary equipment results in a much higher number of blowdowns than proposed by EPA 

(approximately 315 blowdowns per respondent) and that excluding small ancillary equipment 

should result in a lower number of blowdowns than proposed by EPA (approximately 17 

blowdowns per respondent). 

 The EPA agrees that the emphasis for this reporting segment is on capturing and 

reporting emissions from pipeline segments so the final rule clarifies that the focus of this 

segment does not include blowdown emissions from small ancillary equipment. Therefore, the 

EPA has changed the estimated number of transmission pipeline blowdowns from 72 per 

respondent to 17 per respondent. 

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 is an estimate 

of 370 labor hours and $30,000 in labor costs (at a rate of $78.29/hour) to collect data and 

calculate emissions for the new Onshore Natural Gas Transmission Pipeline segment. 

Well Identification Numbers 

The EPA is adding reporting requirements for well identification numbers for 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. For reporters in the 

Onshore Petroleum and Natural Gas Production segment that report emissions using input data 

that are calculated from measurements at individual wells or equipment associated with 

individual wells, the reporter is required to report the well identification number for which those 

measurements were made and the well identification number(s) of other wells to which the 

measurements will be applied. The EPA is not finalizing the proposed requirement that reporters 

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

numbers associated with different emission sources for all wells in a sub-basin included in the 

reported emissions data. 

At proposal, the EPA assumed that well identification numbers were already collected. 

As a result of the comments received, the EPA reevaluated the proposal and agrees that the well 

ID requirements were more burdensome than initially intended. The final amendments represent 

numbers that are readily available and do not require any additional data gathering or calculation. 

Therefore, this change would not impose any change in burden and costs from proposal. 
8 

Reporting and Recordkeeping Provisions 

The EPA is adding 207 new data elements to the reporting requirements. The 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 amendments are expected to result in approximately 9,960 labor hours and 

$820,000 in labor costs per year to report data and maintain records. 

Capital and Operations and Maintenance (O&M) Costs 

These amendments to subpart W 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 approximately $25,000 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 

 

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 

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. The 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. 

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 

amendments to subpart W. 

Process-related costs. The 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 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 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 5,627 30.75 $474,065 $2,591 

Onshore Petroleum and 

Natural Gas Gathering 

and Boosting 9,147 45.73 $1,888,798 $9,444 

Onshore Petroleum and 

Natural Gas Production 57,963 195.82 $4,827,372 $16,309 

TOTAL 72,737 $7,190,235