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UNITED STATES ENVIRONMENTAL PROTECTION AGENCY

WASHINGTON, D.C. 20460 

OFFICE OF 

 AIR AND RADIATION 

Petroleum and Natural Gas Systems (Subpart W) of the Greenhouse Gas Reporting Rule 

Docket: EPA-HQ-OAR-2009-0923 

Title: Additional Analysis of Combustion Costs for Onshore Production 

Summary: This memo presents the additional analysis conducted to assess the costs for the 

onshore production segment to estimate and report incremental combustion emissions. 
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ADDITIONAL ANALYSIS OF COMBUSTION COSTS FOR ONSHORE PRODUCTION

Overview and Purpose 

This memo presents the additional analysis conducted to assess the costs for onshore production 

segment to estimate and report incremental combustion emissions. For the April 2010 proposed 

rule, the combustion cost estimates assumed that reporters would use the Subpart C Tier 1 

methodology or its equivalent and therefore incorporated labor assumptions that were not 

specific to a particular industry segment. In response to the comments and final rule changes, 

EPA used assumptions tailored to the onshore production segment to estimate the costs for them 

to determine fuel consumption at compressor engines and drilling rigs. As explained below, the 

tailored analysis demonstrates that estimates based on the Subpart C Tier 1 methodology are 

conservative high estimates of the costs for the onshore production segment to report 

incremental combustion emissions under Subpart W. 

Specifically, the tailored analysis shows that the cost to report combustion emissions under the 

final Subpart W rule is lower than the estimates based on the Tier 1 methodology. Therefore, 

EPA decided to retain the higher estimate (based on Tier 1 methodology) in the Economic 

Impact Analysis (EIA) for the final rule in order to provide a more conservative estimate of 

combustion-related costs. Table 1 shows the combustion costs from this analysis compared to 

those in the Economic Impact Analysis (EIA) to the final Subpart W rule. 

Table 1. Onshore Production Combustion Emissions Reporting Cost 

Comparison 

 Combustion Cost 

per Reporter 

Total Segment 

Combustion Costs 

Final Subpart W 

EIA Cost $2,200 $2.16 million

This Analysis $1,396 $1.36 million

Background 

In the April 2010 Subpart W proposal, EPA used a cost of $2,200 to report combustion 

emissions from onshore production using the Subpart C Tier 1 methodology.1 The Tier 1 

methodology bases estimates on a fuel-specific default CO2 emission factor, a default high 

heating value of the fuel, and the annual fuel consumption from company records. EPA 

received comments regarding the scope and burden of the combustion requirements under 

Subpart W (e.g., EPA-HQ-OAR-2009-0923-1151-104 and EPA-HQ-OAR-2009-0923-1151-

105). In response to the comments, EPA has provided an external combustion equipment 

 

1 See EPA-HQ-OAR-2008-0508-0004, U.S. EPA, Technical Support Document for Stationary Fuel Combustion 

Emissions: Proposed Rule for Mandatory Reporting of Greenhouse Gases, January 30, 2009, for more information 

about the IPCC Tier methodology (pgs 10-15). 
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threshold for onshore production. Any external combustion equipment below a 5 MMBtu per 

hour rated heat capacity threshold does not have to report emissions, but only provide a count 

by type of equipment. Furthermore, EPA conducted additional analysis (below) to estimate 

combustion costs tailored to the onshore production segment. 

Additional Cost Analysis for Combustion in Onshore Production 

EPA expects that onshore production reporters who combust fuels that are not listed in Table C1 (i.e., field gas and recovered products from vents), and therefore not eligible for the Tier 1 

methodology, to use the Subpart W combustion method (40 CFR 98.233(z)) to estimate and 

report emissions from combustion sources. The Subpart W combustion method is similar to the 

Tier 1 methodology and directs reporters to calculate emissions based on fuel volume and 

composition. The final Subpart W rule allows reporters to use existing company information or 

conduct an engineering estimate based on best available data for operating hours and gas 

composition. The key data required to estimate combustion emissions from equipment using 

produced natural gas that is not pipeline quality are rated heat capacity of the equipment, 

operating hours, and gas composition of produced gas. EPA expects most of the time (and 

therefore cost) spent using the Subpart W methodology to involve determining the rated heat 

capacity for each piece of equipment. The key data element required to estimate combustion 

emissions from equipment using natural gas that is pipeline quality or liquid fuels is the volume 

of fuel used; the emissions are then estimated using an emissions factor. 

The cost estimates from the detailed analysis are based on a labor cost per unit of combustion 

equipment and an estimate of the number of combustion equipment expected to report to the 

rule. EPA tailored its assumptions to the onshore production segment to estimate the labor hours 

and costs for reporters to determine fuel consumption at compressor engines and drilling rigs. 

EPA estimated labor hours for compressor engines and drilling rigs because they are the two 

largest sources of combustion emissions in the onshore production segment. Also, based on its 

analysis of annual emissions from onshore production operators, EPA assumed the external 

combustion equipment threshold would make reporting combustion emissions from fired 

separators, heaters, acid gas removal units and glycol dehydrator reboilers negligible. EPA 

discusses this combustion equipment threshold further in “Equipment Threshold for Small 

Combustion Units,” (EPA-HQ-OAR-2009-0923). 

Labor Hour Estimates for Onshore Production Emission Sources 

EPA assigned the labor hours to determine combustion emissions for compressors and drilling 

rigs based on its engineering knowledge of the industry obtained through its voluntary 

greenhouse gas programs. For these labor hours, EPA assumed a Junior Engineer labor rate of 

$71.03. Please see Table 4-10 in the EIA (EPA-HQ-OAR-2009-0923) for more details 

regarding labor rates. 
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Estimating the Number of Reporting Drilling Events 

EPA estimated 28,800 well drilling events will be reported using the drilled well count from the 

U.S. Inventory of Greenhouse Gas Emissions and Sinks: 1990 – 2006 for Natural Gas Systems 

and Petroleum Systems, the Baker Hughes’ drilling rig count by state, and HPDI® database. 

The U.S. Inventory estimates that in 2006, 35,600 natural gas wells were drilled and 13,907 

petroleum gas wells were drilled, including dry wells in the United States. Baker Hughes 

provides drilling rig counts for each state, which are shown in Exhibit A. The HPDI® database 

provides real well property data such as well counts, oil or condensate throughput, and gas 

throughput by state, AAPG basin, and operator. EPA allocated the drilled events from the U.S. 

Inventory to each state using the percentage of drilling rigs in each state provided by Baker 

Hughes. EPA then determined the number of drilling events per well for each state using the 

well counts from the HPDI® oil and gas database. Finally, EPA determined the number of wells 

drilled for each reporting onshore production facility by multiplying the number of wells in that 

facility by the average number of drilling events for the state in which that facility is located. 

This calculation was done for each reporter using Equation 1 below. 

S

US S

R R well

d p d = well Equation 1 

where, 

dR = the number of wells drilled for reporter, R. 

wellR = the number of wells operated by reporter, R; provided by HPDI® 

wellS = the total wells in the state from which the reporter, R, is operating; provided by 

HPDI® 

dUS = the total wells drilled in the U.S.; provided by the DOE Energy Information 

Administration. 

pS = the percentage of drilling rigs in the state that the reporter, R, is operating from; 

provided by Baker Hughes. 

Estimating the Number of Reporting Compressors 

EPA estimated that combustion emissions from 28,450 compressors in the onshore production 

segment will be reported using the U.S. Inventory of Greenhouse Gas Emissions and Sinks: 

1990 – 2006 and the HPDI® database. EPA determined the compressors for each onshore 

production facility by apportioning the compressors from the U.S. Inventory by the gas 

throughputs (for natural gas systems compressors) and oil throughputs (for petroleum systems 

compressors) provided by the HPDI® database for each facility. EPA summed the compressors 

belonging to reporting onshore production facilities to determine the total compressors that will 

report combustion emissions. 

Revised Onshore Production Total Cost to Report Combustion Emissions 

EPA estimates onshore production reporters will incur labor costs of about $35.52 per drilling 
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event and $11.84 per compressor to determine the majority of combustion emissions from their 

facilities. EPA multiplied the labor costs by the number of reporting drilling events (28,800) 

and compressors (28,450) to yield $1.36 million, the total cost to report combustion emissions 

in the onshore production segment. EPA also divided the total combustion cost by the 981 

reporting onshore production facilities to determine an average combustion emissions reporting 

cost of about $1,396. Given that the tailored onshore production combustion cost estimate is 

less than the estimate based on Tier 1 ($2,200 per reporter), EPA retained the higher estimate in 

the Economic Impact Analysis (EIA) for the final rule in order to provide a more conservative 

estimate of combustion-related costs. 

Table 2 presents the labor activities and costs for a junior engineer to report combustion 

emissions from drilling rigs and compressors. 

Table 2. Responsibilities, Labor Hours, and Costs to Monitor Onshore Production 

Combustion Emissions 

Element 

Onshore Production Labor Activities and Cost 

Labor Activities and 

Hours Cost per Event 

Events Reported to 

Subpart W 

Total Reporting 

Cost per Year 

Onshore Production Drilling Rig Combustion Emissions 

Junior Engineer 

($71.03/hr) 

Gather data from drilling 

contractor that monitors rig 

fuel use (30 minutes / 

drilled well) 

$35.52 per drilled 

well 

28,800 petroleum and 

natural gas drilled 

wells in year 2006 

$1.02 million 

Onshore Production Compressor Combustion Emissions 

Junior Engineer 

($71.03/hr) 

Gather parameters to 

estimate and calculated 

compressor fuel 

consumption (10 minutes / 

compressor) 

$11.84 per 

compressor 

28,450 compressors $337,000 

Total 

(entire onshore 

production 

segment) 

­­­ ­­­ ­­­ $1.36 million 

Average 

combustion cost 

per reporter 

 $1,396 
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Exhibit A. Baker Hughes 2006 Drilling Rig Distribution by State 

State Percentage Rig Breakdown 

TX 49% 

LA 8% 

MS 1% 

AR 2% 

WY 7% 

CO 6% 

UT 3% 

MT 1% 

NM 6% 

CA 2% 

OK 12% 

KS 1% 

WV 2% 

PA 1% 

OH 1%