TO: Kate Cardamone, U.S. EPA

FROM: Hemant Mallya, Eric Stricklin, ICF International

DATE: August 18, 2011

SUBJECT: Mandatory Greenhouse Gas Reporting: Changes in National Cost Estimates 

Associated with the Notice of Revisions for Subpart W

On November 8, 2010, Administrator Jackson signed a rule that finalizes reporting requirements 

for the petroleum and natural gas industry under 40 CFR Part 98, the regulatory framework for 

the Greenhouse Gas (GHG) Reporting Program (11/30/10; 75 FR 74458).

This final rule requires petroleum and natural gas facilities that emit 25,000 metric tons or more 

of carbon dioxide (CO2) equivalent per year to report annual methane (CH4) and CO2 emissions 

from equipment leaks and venting, and emissions of CO2, CH4, and nitrous oxide (N2O) from gas 

flaring and from onshore petroleum and natural gas production stationary and portable 

combustion emissions and combustion emissions from stationary equipment involved in natural 

gas distribution.

EPA is amending specific provisions in Subpart W of the GHG rule to resolve issues and 

questions raised during implementation, and to correct technical and editorial errors that have 

been identified since publication. This memorandum documents how these proposed revisions 

would change the estimated compliance costs presented in the Economic Impact Analysis for the 

2010 final rule.1 

Proposed Amendment to Gas Well Completion Sampling Requirement: Estimated Change 

in Compliance Cost

EPA has proposed to change the methodology for onshore production facilities’ gas well venting 

during completions with hydraulic fracturing and workovers with hydraulic fracturing. Instead 

of requiring the sampling from at least one gas well completion and workover per field (“field 

method”), the proposed methodology would require sampling of the average flow rate of gas 

based on a graded scale within a sub-basin (“sub-basin method”). A sub-basin is proposed to be 

defined as:

a subdivision of a basin into the unique combination of wells with the surface 

coordinates within the boundaries of an individual county and subsurface completion 

in one or more of each of the following four formation types: conventional with >0.1 

millidarci permeability, and unconventional with ≤0.1 millidarci permeability shale, 

coal seam, and other tight reservoir rock. Wells producing from more than one 

formation type shall be classified into only one based on the formation type 

 

1

See http://www.epa.gov/climatechange/emissions/downloads10/Subpart-W_EIA.pdf for the Economic Impact 

Analysis. 
contributing the most production as determined by engineering knowledge. 

Unconventional wells producing from formations categorized in two or more types 

are considered shale for a combination of “shale and coal”, “shale and other tight”, 

or “shale, coal and other tight”; and are considered as coal for combinations of 

“coal and other tight".

While this proposed sub-basin method does not change the cost per sample estimated for the 

final rule, it decreases the total number of samples that will be reported from well completions 

and workovers. Specifically, the number of samples expected from reporters in the first year will 

decrease for completions and workovers from 1,970 to 1,670. Accordingly, the average 

compliance cost in the first year will decrease from $14,356 to $14,182 per onshore production 

facility. In addition, the compliance cost in subsequent years will decrease from $7,425 to 

$7,338 per facility. The table below summarizes the change in compliance costs associated with 

the proposed sub-basin method. 

Table 1. Summary of First Year Compliance Cost for Field and Sub-Basin 

Methods (Gas Well Completions and Workovers with Hydraulic Fracturing)

Costs and Samples for Reporters

Field Method

(Nov 2010 

Final Rule)

Sub-Basin 

Method

(2011 Proposed 

Rule)

Difference 

between Methods

First Year Cost per Facility ($) $14,356 $14,182 ($174)

Subsequent Year cost Per Facility ($) $7,425 $7,338 ($87)

Total National Cost ($ million) $10.7 $10.6 ($0.1)

Cost Effectiveness ($/tonneCO2e) 0.05 0.05 -

Number of Samples for Completions 

and Workovers with Hydraulic 

Fracturing (Count)

1,970 1,670 (300)

†The cost figures in this table include costs associated with reporting both process and combustion emissions. 

Other Amendments in Notice of Revisions

EPA is proposing to revise several other provisions in Subpart W. EPA has determined that

these revisions do not affect the compliance costs estimated in the Economic Impact Analysis for 

the 2010 final rule. These proposed revisions are categorized as follows:

1. Provide additional flexibility for reporters based on questions raised during 

implementation. 

2. Simplify existing monitoring methods. 

3. Clarify existing industry segment definitions.

4. Correct and clarify inconsistencies in monitoring methodologies.

5. Correct and clarify data reporting requirements.
6. Add and clarify other existing definitions.

See Appendix A for an elaboration on each of these changes and examples from the revisions.
Appendix A: Revisions that Do Not Affect Cost Estimates

1. Provided additional flexibility for reporters: Based on alternative monitoring methods 

requested by trade associations and through questions submitted from potential reporters, 

EPA has proposed additional flexibility in the monitoring methods for estimating emissions 

from the following sources:

 Gas well liquids unloading - measure the natural gas flow rate of a liquids 

unloading event for each sub-basin, pressure range, and unique tubing 

diameter, instead of measuring the natural gas flow rate of a liquids unloading 

event for each well tubing diameter and producing horizon/formation 

combination in each gas producing field.

 Blowdown vent stacks – track the volume of each blowdown occurrence 

instead of estimating the annual average for all blowdown occurrences.

 Flare stacks – measure emissions using continuous emission monitoring 

systems (CEMS), instead of not allowing reporters to determine flaring 

emissions using CEMS.

These methods do not replace any of the lowest cost methodologies that were modeled in the 

cost analysis for the final rule and therefore do not impact the final rule’s cost estimate. In

short, EPA expects only those reporters that already have high cost options in place to use 

them; other reporters have been assumed to use the low cost option as in the final rule.2EPA 

therefore expects that they will not incur the entire cost of even the low cost option. That is, 

the EPA cost assumption is conservatively higher for these reporters that already have the 

high cost options in place. 

2. Simplified existing monitoring methods: EPA is proposing several changes to the 

monitoring methods that will potentially simplify monitoring and reporting emissions, as 

follows:

 Pneumatic devices and pneumatic pumps – determine type of pneumatic 

device using engineering estimate based on best available data instead of not 

specifying how to determine the type of pneumatic device and pneumatic 

pump.

 Transmission storage tanks – measure emissions from vent stack without 

performing leak detection versus requiring the leak detection before 

measuring a leak. An additional option to use calibrated bags and high flow 

 

2

Potential reporters will still be able to determine emissions from liquids unloading and flare stacks using an 

engineering calculation, which EPA determined to be the lowest cost methodology. Potential reporters can also still 

use the low cost option to determine the annual average emissions from blowdown volumes.
samplers in addition to the existing options to use meters. Also, an additional 

option to use stethoscope type acoustic devices to detect leaks.

 GHG volumetric emissions – use default gas composition for CH4 and CO2 in 

natural gas for onshore natural gas transmission, underground natural gas 

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

distribution instead of requiring facilities to either use existing gas 

composition to estimate average annual values or sample gas to determine 

composition.

These simplifications do not impact the cost analysis for the final rule because they do not 

significantly change the assumptions made for how potential reporters will comply with the 

rule.

3. Clarification of existing industry segment category definitions: Based on questions and 

inputs received from potential reporters and trade associations during implementation, EPA 

is proposing to further clarify the definitions for the following industry segments: onshore 

petroleum and natural gas production; onshore natural gas processing; onshore natural gas 

transmission; and natural gas distribution. These proposed revisions do not change any of 

the segment boundaries and will not have any impact on who reports or the total number of 

reporters. Consequently, these revisions do not change the cost estimates. A list of these 

revisions is provided in the Background Technical Support Document for the proposed 

Subpart W Revisions Package.

4. Corrections and clarifications to equations and calculation methodologies: Based on 

input from potential reporters and EPA internal review, EPA has identified several 

inconsistencies and opportunities for clarification to the calculation methodologies in 

§98.233. EPA is proposing corrections and providing clarification to these equations. A 

detailed list of corrections to the Equations is available in the Background Technical Support 

Document for the proposed Subpart W Revisions Package. These equation changes provide 

clarity only and do not change the inputs required to perform the calculations. Therefore,

these revisions do not change the cost estimates. 

5. Corrections and clarifications to data reporting requirements: Potential reporters have 

raised questions and identified several inconsistencies in the reporting requirements in 

§98.236. EPA is proposing corrections and providing clarification as follows:

 CH4, CO2 and N2O emissions – Clarify that emissions for each gas must be 

reported separately.

 Flared and vented emissions – Clarify that flared and vented emissions must 

be reported separately.
 Recovered emissions – Clarify that any recovered emissions must be reported 

separately. 

 Level of reporting – Clarify whether a specific requirement is on a per 

equipment basis, facility level, annual average, or any other applicable level of

reporting in Subpart W. 

 Unique ID name or ID number – Addition of unique ID name or ID number 

for applicable source types. 

There is no change in the cost estimates from these proposed corrections and clarifications. 

Also, there is only one addition to the data reporting requirement. EPA has added an 

overarching requirement for each onshore production facility to report average API gravity, 

gas-to-oil ratio (GOR), and low pressure separator pressure for each sub-basin within the 

facility. However, EPA understands that this is information is already available to the 

facility operators because it is needed to conduct business. Oil and gas operators know the 

GOR and API gravity because they are determined at least once a year to pay taxes, royalties, 

and in general for selling oil and gas. Those operators who use method 1 in 98.233(j) to 

estimate emissions from tanks will already collect their low pressure separator pressure. 

Also, those who do not use method 1 for estimating tank emissions can still collect this 

information when they collect equipment counts for estimating fugitive emissions. Finally, 

the data documentation and report submission costs in the final rule already account for any

post processing of data collected and reporting. That is, the final rule already accounts for 

time to collect equipment count at each well pad; collecting one more piece of information at 

that stage does not increase the cost estimate. Therefore, EPA does not expect additional 

costs for reporting this data. A list of new definitions and changes to the reporting 

requirements is provided in the Background Technical Support Document for the Subpart W 

Revisions Package.

6. Added and clarified existing definitions: EPA provided new definitions and clarified

existing definitions. The proposed addition of these definitions are meant to help reporters 

understand the monitoring and reporting requirements finalized in the November 2010 rule; 

they do not add new requirements and therefore do not change the cost estimates.