Proposed Rule: Mandatory Reporting of Greenhouse Gas Emissions Subpart W 

Meeting Documentation: Gas Processors Association (GPA) and American Exploration and Prod

(AXPC) 4/27/10 

Date Staff Contact 

Information (Name, email, phone #) 

Name of Organization (Attach list of all attendees names and emails if possible) 

Summary of Discussion (e.g., applicability, reporting requirements, etc.) 

Written CommeProvideDid they also subto Dock

4/27/10 

Roger Fernandez Akachi Imegwu Kate Cardamone Sandy Seastream, ICF 

Bill Grygar Anadarko John Admire DCP Midstream Grover Campbell Chesapeake Craig Bock El Paso Energy Cal Cooper Apache Nina Hutton XTO Doug Jordon Southwestern Energy 

1. EPA should consider reporting frequency similar to the GOADS program See following pages for additional comments 

Written commentwere submprior to thmeeting, below 
Gas Processors Association 

Comments to EPA 

Proposed Part 98 Subpart W 

Docket EPA-HQ-OAR-2009-0923 

RIN Number 2060-AP99

April 27, 2010 

1) Defining natural gas gathering system compression facilities as part of a gas processing 

plant is inappropriate. 

The definition of a gas processing plant is well established in the context of the Clean Air Act 

and it does not incorporate stand alone gathering system compression facilities. Gas 

compression facilities, whether in the gathering systems upstream of gas processing or in the 

natural gas transmission sector, are discreet and easily identifiable facilities. These facilities 

have been treated as stand alone sites in all previous applications of the Clean Air Act, including 

all permitting programs and for GHG reporting under 40 CFR Part 98 Subpart C. Continuing 

this historical treatment of these facilities is not only the most appropriate action, it will also 

eliminate the certain confusion that will result from a new definition solely for use in Subpart W 

of Part 98. 

Even the EPA appropriately recognizes the treatment of gathering system compressor stations 

as stand alone facilities. On page 26 of the Background Technical Support Document for the 

Petroleum and Natural Gas Industry, the EPA states: 

“Both gathering/boosting stations and natural gas processing facilities have a well defined boundary 

within which all processes take place”. 

Further, on page 18613 of the Subpart W preamble the EPA states that, 

“For some segments of the industry (e.g., onshore natural gas processing facilities, natural gas 

transmission compression facilities, and offshore petroleum and natural gas facilities), identifying the 

facility is clear since there are physical boundaries and ownership structures that lend themselves to 

identifying scope of reporting and responsible reporting entities.” 

In direct conflict to the above statements, the proposed Subpart W definition of Onshore Natural 

Gas Processing in §98.230(3) appears to require GHG emissions from gathering compression 

facilities and the gathering pipelines be rolled-up with gas processing plant emissions by stating 

(emphasis added): 

“In addition, field gathering and/or boosting stations that gather and process natural gas from multiple 

wellheads, and compress and transport natural gas (including but not limited to flowlines or intrafacility gathering lines or compressors) as feed to the natural gas processing plants are considered a 

part of the processing plant. Gathering and boosting stations that send the natural gas to an 

onshore natural gas transmission compression facility, or natural gas distribution facility, or to an end 

user are considered stand alone natural gas processing facilities. All residue gas compression 

equipment operated by a processing plant, whether inside or outside the processing plant fence, are 

considered part of natural gas processing plant.” 
GPA strongly recommends the above text in §98.230(3) be deleted from the Onshore Natural 

Gas Processing source category definition and a new source category definition be included for 

“Onshore Natural Gas Gathering Compression”. Using the definition of Onshore Natural Gas 

Transmission as a template the source category definition for “Onshore Natural Gas Gathering 

Compression” should be: 

“Onshore natural gas gathering compression means any fixed combination of compressors that move 

natural gas from production fields or other compression facilities into natural gas processing facilities, 

other gathering compression facilities, transmission pipelines, storage facilities, or other end users. In 

addition, natural gas gathering compressor facilities may include equipment for liquids separation, 

natural gas dehydration, and tanks for the storage of water and hydrocarbon liquids. “ 

GPA also suggests that the same GHGs and sources reported by processing plants under 

§98.232(d) be reported by gathering compression facilities. 

In addition to the conflicts created by the proposed definition in Part 98, Subpart W regarding 

applicability of gathering compression facilities, the following issues arise from the proposed 

Subpart W definition of Onshore Natural Gas Processing in §98.230(3). 

a) Increases the number of facilities subject to Subpart C for combustion GHG emissions by 

approximately 15 times, with no consideration for the size of each individual facility. This 

results from the fact that, numerically, there are typically 10-20 gathering compression 

facilities for every gas processing plant. 

b) Gathering compression facilities are often not uniquely associated with a single gas plant, 

many gathering compression facilities have connections to multiple gas plants and gas is 

routed to a plant based on business needs and conditions. Associating any one gathering 

compression facility to an individual processing plant is not always possible. 

c) Rolling-up gathering compression facility emissions with processing plant emissions is in 

conflict with EPA’s assessment of the impact of the proposed Subpart W. EPA inaccurately 

states in the proposed Subpart W preamble on page 18616, 

“... there are a reasonable number of reporters. Most natural gas processing facilities proposed 

for inclusion in this supplemental proposed rulemaking would already be required to report under 

subpart C and/or subpart NN of the Final MRR.” 

In fact, this proposal will increase the number of facilities subject to Subpart C for 

compression GHG emissions by approximately 15 times. One GPA member company that 

has about 45 facilities subject to Subpart C reporting for 2010 would have over 700 facilities 

subject to Subpart C as a result of this proposal. This level of reporting with no 

consideration for individual facility emission levels is neither reasonable nor appropriate. 

d) EPA makes the following conclusion on page 18619 in the preamble to the proposed 

Subpart W, 

“... requiring only a small fraction of total facilities to report.” 

The proposed Subpart W in fact increases coverage of gas gathering and processing 

facilities to nearly 100% regardless of facility size, which is unduly burdensome and neither 

reasonable nor appropriate. 
e) Gathering compression facilities are typically small facilities and widely dispersed, many of 

these compression facilities have only 1 or 2 compressors. Significantly sized facilities are 

already subject to Subpart C reporting if the combustion emissions exceed 25kTon/year and 

individual compression facilities that exceed 25kTons/year including Subpart W emissions 

would also begin reporting as required. The proposed Subpart W, however, treats these 

small and widely dispersed facilities as if they are the same size and complexity of a gas 

processing plant. Examples of proposed requirements that may be appropriate for 

processing plants but unduly burdensome for small and widely dispersed gathering 

compression facilities include: collecting extensive data and modeling tank emissions, 

compressor rod packing vents, leak detection using optical imaging or population factors, 

and quarterly sampling of gas streams. 

2) Proposed calculation for gathering pipelines is impractical. 

EPA is proposing to not include reporting of fugitive emissions from natural gas transmission 

pipelines due to the dispersed nature of the fugitive emissions and the fact that once leaks 

are found, the emissions are generally addressed quickly. EPA fails to use this same logic 

for natural gas gathering pipelines, which are significantly more dispersed than transmission 

pipelines. Gas gathering lines are generally much smaller diameter and typically operate at 

much lower pressures than transmissions lines, resulting in a lower potential for emissions. 

Some gathering pipelines even operate on a vacuum. It is also important to note that many 

gathering and processing companies have implemented robust programs to find and fix 

pipelines leaks. Contrary to the transmission pipelines, EPA appears to propose that gas 

processing plants and producers conduct a physical count of piping components on 

gathering lines and use population factors to determine emissions. Operators then apply 

another factor (scf/hour/mile) to calculate GHG emissions from the pipeline segments. 

GPA estimates that there are over 250,000 miles of gathering pipelines in the gathering & 

processing sector, and hundreds of thousands meter and valve settings, that would require 

physical component counts. Even more impractical, is the requirement to conduct 

compositional analysis at these sites to determine methane and CO2 concentrations. 

Further, operators would have to track blowdowns and changes in small meter runs and 

pipe segments in these hundreds of thousands of insignificant locations to report GHGs as 

required by proposed Subpart W. 

EPA has significantly underestimated the burden to industry to obtain the information to 

calculate the emission estimate for gathering pipelines. It is also noted that the emission 

factor for the gathering pipeline segments (2.81scf/hour/miles) is derived from an 

unexplained total pipeline emission estimate of 6.6 Bscf (see TSD page 147-148). GPA 

suggests that if EPA has already established this emission estimate, they should simply add 

it to the rolled-up GHG inventory for the natural gas industry rather than requiring operators 

to expend significant resources re-creating the exact same number. 

GPA recommends that, consistent with treatment of transmission pipelines, gathering 

pipelines and flow lines be excluded from fugitive reporting due to the disperse nature of the 

emissions and the impracticality of the requirements of proposed Subpart W. 

3) Proposed effective date is impractical. 
It appears EPA is targeting publication of the finalized Subpart W in late 3rd quarter or early 

4th quarter 2010, with an effective date of January 1, 2011. If the rule is finalized as 

proposed, there will be certain monitoring that will not be practical to implement prior to 

January 1, 2011 and adequate time will not be allowed for the regulated community to do 

basic planning for implementation of the new rule. 

A specific example of the impracticality of a January 1, 2011 implementation date is related 

to the requirement to conduct an annual survey using as optical gas imaging instrument at 

each gas plant and gathering compressor station. Under the currently proposed Subpart W, 

many companies will have hundreds of individual facilities to survey, which will require they 

commence surveys in January 2011 in order to accomplish the work in 2011. Today few 

companies or consultants own optical imaging equipment, which can cost over $100,000 for 

one instrument. The result is companies and consultants will have to purchase the 

equipment, conduct training, and gain sufficient experience in a very short period prior to 

January 1, 2011. Not only is that impractical, but GPA questions the ability of suppliers to 

provide enough optical imaging cameras to conduct the required surveys in 2011. Another 

example is related to Acid Gas Removal Vents which are required to have gas meters into 

and out of AGR unit. Not all AGR units employ this metering today and it is impractical to 

expect meters to be specified, purchased and installed in a period of three months or less. 

Similar examples exist with compressor seal vents and rod packing vents, on which many 

operators will elect to install permanent meters; and on flares which some operators will 

elect to install additional metering. In both cases it is impractical to expect installation within 

a few months, by January 1, 2011. As a result, GPA recommends EPA allow use of best 

available data for the first half of 2011 for all sources subject to the new Subpart W. 

4) Screening Criteria and Levels are Necessary to Establish the Requirement to Report 

under Subpart W. 

Based on the currently proposed calculation methods in Subpart W, emissions from many of 

the GHG sources are unpredictable, which will make determining applicability relative to the 

25kTon/yr threshold impractical. In particular, emissions from the following sources cannot 

be predicted: blowdowns, flares, compressor vents & seal, and fugitive leaks. Due to the 

unpredictable nature of these sources, a facility will not be able to establish applicability to 

Subpart W reporting until well into a calendar year and perhaps not until the end of a 

calendar . Also, for compressor vents & seals and fugitive leaks, a facility will not be able to 

determine emissions from the sources until the direct detection and measurement is 

completed. In order for the regulated community to establish applicability of the GHG 

reporting rule, specifically for Subpart W, screening criteria need to be established that 

allows this determination to be made with certainty in January of each calendar year. 

5) Minimum thresholds should be applied for equipment level applicability and 

calculations. 

The EPA does not incorporate thresholds for applicability or for using simplified calculations 

at the equipment level. As a result, in many cases complex process models and simulations 

are required for equipment with minimal GHG emissions. 

The first example is related to tanks, for which the same annual calculation method is 

prescribed regardless of the tanks throughput, for example a tank that fills at a rate of 1 

barrel/day versus a tank that fills at a rate of 100 barrels/day. In this particular example, the 

prescribed method requires analysis of the separator liquid and collection of numerous 
operating parameters. The liquid analysis is expensive and often the sample is difficult or 

impossible to collect, even with higher liquid production rates, and should not be required for 

tanks with minimal throughput. Across the natural gas industry, there are thousands of 

tanks associated with very low liquid production rates and, therefore, minimal GHG 

emissions. GPA recommends that tanks with a throughput of less than 5 barrels/day be 

excluded from reporting under Subpart W. If an exclusion cannot be provided, GPA 

recommends tanks below the 5 barrel/day threshold be allowed to use the appropriate 

emission factor from the API Compendium of Greenhouse Gas Emission Methodologies for 

the Oil and Gas Industry (API Compendium) in place of conducting modeling using process 

simulations. 

The next example is related to gas dehydration units, which are required by the proposed 

Subpart W to estimate annual emissions using the GLYCalc processes simulator. As with 

tanks, there are thousands of very small dehydration units operating across the natural gas 

industry with minimal GHG emissions. GPA recommends that dehydration units with a 

throughput of less than 10 million scf/day be excluded from reporting under Subpart W. If 

an exclusion cannot be provided, GPA recommends dehydration units below the 10 million 

scf/day threshold be allowed to use the appropriate emission factor from the API 

Compendium in place of conducting modeling using process simulations. 

The final example is related to blowdown vent stacks. There are a limited number of tasks 

in the natural gas industry that result in blowing down significant volumes of natural gas to 

the atmosphere. These activities are limited to blowing down compressors, process vessels 

and piping. There are other tasks in the natural gas industry that result in blowing down 

very small and insignificant volumes of natural gas, such as blowdowns from sight glasses 

and small tubing. Without thresholds which limit the blowdowns that must be recorded, 

calculated, and reported, this portion of the proposed Subpart W will be unmanageable. 

GPA recommends that GHGs only from the following blowdowns be reported: 1) all 

compressor blowdowns and 2) blowdowns from process vessels & piping with a physical 

volume of 50 cubic feet and larger. 

 

6) Direct measurement is not appropriate for any sources. 

GPA feels that direct measurement is not appropriate for any sources for the purposes of 

GHG emission inventories, consistent with other emission inventory practices. Although 

EPA has reduced direct measurement requirements in the current proposal for Subpart W, 

EPA continues to employ methods that ignore longstanding and accepted international 

protocols for emission inventory calculations. The API Compendium in particular has been 

accepted as an international standard for estimating GHG emissions across the oil and gas 

industry. For example, Australia NGERS, EU-ETS, and Alberta emission inventories are all 

based on the API Compendium. EPA is assuming that a significant increase in overall 

accuracy will result by requiring more complex and costly estimation of GHG emissions from 

even the smallest sources within the natural gas gathering and processing industry. This 

assumption is made while overlooking the EPA’s own data that indicates the natural gas 

gathering and processing industry emits only a very small fraction of the total US GHG 

emissions annually. In addition, the currently proposed Subpart W ignores the standards of 

statistical averaging. 

While GPA supports the full use of the API Compendium to calculate GHG emissions for all 

sources covered by the proposed Subpart W, at a minimum we suggest the application of 
the API Compendium in place of any direct measurement methods. For the gas gathering 

and processing sector, direct measurement is generally proposed to be limited to 

compressor wet seal vents and rod packing venting. The current proposal potentially 

requires direct measurement of compressor rod packing vents from every cylinder of a 

compressor in cases where the vent lines are not tied to a common line, which is a common 

practice in gathering compression facilities and production facilities. The prescribed 

methods for these sources is flawed by assuming a snapshot measurement applied across 

an entire year is more accurate than an emission factor based on well documented and 

controlled studies. 

7) EPA’s estimated cost impact appears to be at least an order of magnitude low. 

GPA is evaluating the economic impact of the proposed Subpart W and will compare the 

results to the analysis provided by EPA. However, preliminary indications are that the EPA’s 

cost estimates are at least one order of magnitude low. EPA has failed to recognize the full 

impact of requiring reporting at all facilities and pipelines in the natural gas gathering and 

processing sector. 

To demonstrate the disparity in EPA’s cost estimate, the following cost estimates from one 

GPA member company are presented. These costs are only for this one company, an 

independent gathering and processing company with no production. Their estimated first 

year costs for initial implementation of the proposed Subpart W are approximately $80 

million and their ongoing annual costs for recording, measuring, calculating, and reporting 

are estimated to be $9.5 million. To emphasize, these are the estimated costs for only 

one GPA member company to comply with the proposed Subpart W. This compares to 

EPA’s estimate for all companies in all segments of the natural gas industry covered by 

Subpart W of $56 million for the first year costs and $21.4 million for ongoing annual costs. 

8) Additional engineering estimation methods should be included. 

EPA has specifically identified two process simulation models in the proposed Subpart W, 

GRI-GLYCalc for estimating dehydrator emissions and E&P Tanks for estimating production 

and processing tank emissions. Many companies use more sophisticated process 

simulation models for some facilities to estimate emissions from tanks and acid gas removal 

units (AGR unit). The two most common are AspenTech’s HYSYS process simulator and 

Bryan Research and Engineering’s ProMax process simulator. These process simulators 

are widely accepted as the gold standards for detailed process design and optimization in 

the gas processing, chemical and refining industries 

GPA recommends that HYSYS be identified as an acceptable method for calculating GHG 

emissions from tanks, in addition to E&P Tanks. The use of HYSYS for tank calculations is 

particularly important due to recognized difficulty in collecting acceptable separator liquid 

samples when using E&P Tanks. In some case, the success rate for collecting acceptable 

separator liquid samples can be as low as 10%. HYSYS provides the flexibility to use 

extend gas analysis to model tank emission. 

GPA further recommends that ProMax be identified as an acceptable method for calculating 

GHG emissions AGR units. In addition, GPA recommends that other mass balance 

calculations be allowed for AGR units. For example, an operator typically has metered 

volumes and composition analysis of gas entering an AGR unit and can conservatively 

assume 100% of the CO2 is removed (in some cases a few percent of the CO2 may not be 
removed). A simple calculation will provide accurate CO2 emissions from the AGR unit 

without the need for downstream metering or analysis. In other cases, operators may have 

meters and analysis on the AGR vent line and can provide a direct calculation of the CO2 

emissions, again without the need for downstream metering or analysis. Subpart W should 

provide flexibility for any of these methods to estimate the GHG emissions from AGR vents. 
American Exploration and Production Council (AXPC) 

Comments to EPA 

Proposed Part 98 Subpart W 

Docket EPA-HQ-OAR-2009-0923 

RIN Number 2060-AP99

April 27, 2010 

1. Aggregation of E&P Sites (Reporting Area)

A. Facility Definitions

Industry and regulators currently have a very good understanding of what the 

term “facility” means in the O&G upstream sector. Company representatives as 

well as state regulatory agencies have been using this term to apply current 

CAA requirements across the country. Our recommendation is that we rely on 

the current actively used definition of facility that EPA change their proposed 

language to refer to a “threshold reporting area” or “roll-up area threshold” to 

define a geographical area to which a threshold can be applied that is made up 

of oil and gas upstream facilities. This would help alleviate industry concerns 

that the reporting rule definition of “facility” might impact perception of the 

CAA definition. 

For example, 98.238 ‘Onshore petroleum and natural gas production facility’ 

would read: ‘Onshore petroleum and natural gas production reporting area 

means all petroleum or natural gas facilities and equipment associated with all 

petroleum or natural gas production under common ownership or common 

control by an onshore petroleum and natural gas production owner or operator 

located in a single hydrocarbon basin as defined...’ 

The term reporting area could then be referred to in the definition of the source 

category; i.e., 98.230(2) ‘Onshore petroleum and natural gas production’: 

Onshore petroleum and natural gas production reporting area means all 

facilities associated with wells the production of petroleum or natural gas 

including but not limited to... 

B. Upstream Production Sites Should Not Be Aggregated
EPA should not require aggregation of upstream production sites. This imposes 

a disproportionate burden on our industry by requiring data collection, 

recordkeeping, and reporting for hundreds of thousands of operated sites. As the 

rule is written, even very small operators will have to calculate and aggregate 

GHG emissions to determine if they must report or not report. 

EPA states in the preamble that the information gathered by this rule would 

inform and are relevant to EPA’s carrying out a wide variety of Clean Air Act 

(CAA) provisions. It is understood that the GHG emission inventory data will 

be used to define future permitting and compliance programs. For this reason, 

we do not agree with redefining the term “facility” in this part. If the 

information in this program will be used for other CAA programs, then it must 

be collected in a manner that is consistent with how it will be applied in those 

programs. 

Future GHG permitting and compliance programs under the CAA will still rely 

on the definition of facility as found in 40 C.F.R. 52.21(b)(6): 

Building, structure, facility, or installation means all of the pollutantemitting activities which belong to the same industrial grouping, are located 

on one or more contiguous or adjacent properties, and are under the control 

of the same person (or persons under common control) except the activities 

of any vessel. Pollutant-emitting activities shall be considered as part of the 

same industrial grouping if they belong to the same “Major Group” (i.e., 

which have the same first two digit code) as described in the Standard 

Industrial Classification Manual, 1972, as amended by the 1977 Supplement 

(U. S. Government Printing Office stock numbers 4101–0066 and 003–005–

00176–0, respectively). 

In accordance with this definition and multiple case-by-case aggregation 

determinations by EPA and the states, most production operations across a 

single hydrocarbon basin cannot be aggregated into one facility. If these 

production operations are not aggregated by basin, then each facility or well site 

must individually be assessed for applicability to the future permitting and 

compliance programs. At this time, an applicability threshold of 25,000 metric 

tons CO2e or more per year has been proposed for permitting, and that threshold 

will apply at the facility level. If the purpose of this rule is to inform future 

rule-making, there is no benefit to collecting information for an aggregation of 

many small facilities that will not be subject to the future rules. We request that 
this definition be modified to be consistent with the definition employed in 

other CAA programs. 

C. If Upstream Production Sites are Aggregated

If EPA rejects important financial burden and CAA definition of “facility” 

arguments and retains aggregation of upstream production sites, it should take 

reasonable steps to mitigate the adverse financial burden to industry, especially 

very small operators. This would include: 

• Exempting small sites using well defined screening thresholds such as (1) 

natural gas production sites with only wellhead fugitive emissions and 

produced water storage tank emissions, (2) any natural gas production 

site with less than 3 MMSCFD of production and less than 1 BOPD 

condensate production, and (3) oil stripper wells producing less than 10 

BOPD. 

• Allowing the use of the API Compendium for calculations of emissions 

from upstream production sites. (See Item 3 below). 

2. Reporting of Emissions from Onshore Petroleum and Natural Gas Facilities 

A. Basin Level Aggregation 

EPA is seeking comment on whether to use “basin level” for aggregation as 

proposed, or “field level”. If EPA goes forward with aggregation of upstream 

production sites, a “field level” approach would be much more practical for the 

following reasons: 

• Some basins are very large (the Permian Basin stretches from southeast New Mexico 

and southwest Texas nearly to Louisiana. Basins can typically cross state lines such 

that GHG reporting by basin would not allow states or the EPA to determine which 

state the emissions are from. In addition, basins can cross multiple regional and 

district operating boundaries for companies making gathering of emissions 

information data more difficult. 

• EPA has overestimated the reduction in emissions coverage for field level 

aggregation versus basin level aggregation. Most large and small operators 

concentrate in producing from certain fields within a basin. The Barnett Shale in 

Texas covers 24 counties. However, one large independent operates approximately 

2,000 wells, but with 95% of those in just three or four counties. 
• The quality of emission estimates would be greater for emissions estimates made on a 

field level rather than a basin level. Oil and gas characteristics and the method of 

separation and processing are directly related to the field from which the oil and gas 

is produced. Fields are well defined by state oil & gas commission rules. When wells 

are comingled, the percent of production from a particular field (sand or formation) 

can be assessed using royalty calculations to provide the percentage production from 

a particular field. The field which produces the majority of the oil and gas for a 

comingled well can be used as the field that a well reports under. 

• Aggregation by basin level would complicate efforts for simple auditing by EPA as it 

would be difficult to determine whether emissions reported are reasonable compared 

to emissions reported from other companies. EPA would not know how much 

production came from various fields within that basin. 

• For all the above reasons, we support the API’s proposed approach that 

would allow operators the flexibility to report at the basin level but allow 

them to identify rational “reporting units” within a basin that have similar 

operations, equipment, fluid properties, and physical properties, and 

enable the use of “population average” emission factors and approaches 

for emission quantification. This would allow calculation and reporting 

of emissions from reasonable “well groupings” such as known fields 

within a basin or even by county within a basin. 

B. Fugitive Emissions from Pipelines (such as flowlines or intra-facility gathering lines)

These emissions should be exempt from reporting for the same reasons that 

EPA exempted emissions from transmission lines. Gathering pipelines 

generally operate at much lower pressures than transmissions lines. The 

interconnecting pipelines consist mostly of welded connections and thousands 

of small metering stations. EPA has underestimated the burden to industry to 

obtain component counts on these pipeline facilities. In addition, many 

companies now have internal programs to find and fix leaks associated with 

these gathering pipelines as well as for the longer distance transmissions lines. 

C. Emissions from Portable Non-self-propelled Equipment (such as well drilling and 

completion equipment, workover equipment, gravity separation equipment, auxiliary 

non-transportation related equipment).

EPA should delete the reporting of emissions from these non-stationary and 

portable sources. EPA should simply use its own updated total emissions 

estimates for these sources. The huge added expense for industry to calculate, 
keep records, and report emissions from thousands of these sources is not 

justified by the small incremental emissions reporting accuracy EPA many be 

expecting from this approach. More specifically: 

• Most wells are drilled and completed using contract service companies. EPA 

underestimates the difficulty of tracking equipment and estimating emissions from 

field portable equipment that are operated by third parties even when stationed at a 

well site for more than 30 days. Complying with this requirement as proposed would 

be very resource intensive and complex since this equipment is often moved from 

well to well and between operators. In many cases, site operators would not have the 

operational data to perform the needed calculations and/or the necessary records to 

certify the accuracy of GHG emissions data. When the well site operator does not 

control the operation or maintenance of the equipment, it is not appropriate to require 

reporting and compliance tasks of the well site operator because they do not 

participate in engine maintenance or the collection of fuel use data. All other Clean 

Air Act programs establish applicability based on whether a party owns and/or 

operates a source because it is not feasible for someone who does not control the dayto-day operation of a source to collect the required information or monitor the 

source’s usage. Is any other industry sector required to report contractor’s emissions 

for this reporting rule? 

• All of these activities are non-stationary source and temporary construction activities 

that should be excluded just as other construction activities (housing, commercial 

building, roadways, etc) are excluded. Requiring estimates of these emissions greatly 

increases the reporting burden on the oil and gas industry without a corresponding 

increase in emissions reporting coverage. For instance, even using updated 

methodology from its Natural Gas Star work, EPA estimated that emissions from well 

completions would only represent 0.0004% and that emissions from well workovers 

would only represent 0.04% of the 80% of fugitive and vented emissions from the 

onshore production sector (see Appendix A & B: Greenhouse Gas Emissions 

Reporting from the Petroleum and Natural Gas Industry). As noted in Appendix A, 

EPA over rode its own decision tree process when including these sources that 

amount to such a miniscule part of emissions. 

• The total number and type of wells completed in the U.S. is well known; therefore, 

EPA could easily obtain a reasonable estimate of those GHG emissions using the 

Natural Gas STAR data mentioned above. EPA could then add-on the emissions 

estimates for drilling and completing wells to the inventory. 

• The vast majority of engines included in this category are fired by diesel fuel. 

Emissions from these non-road engines are exempt from reporting under Subpart C. 

Reporting GHG emissions from these engines under Subpart W would result in 

double counting of emissions since emissions from the combustion of diesel fuel are 

reported by suppliers of petroleum products under Subpart MM. 
3. Direct Measurement

Although EPA has reduced some direct measurement requirements from the first 

Subpart W proposal, EPA still chooses to ignore longstanding and accepted 

international protocols for emissions calculations that other countries have adopted 

and currently use to calculate their oil and gas sector emissions. This includes 

Australia NGERS, EU-ETS, and Alberta for which all emissions are based on the 

API Compendium-IPIECA standards. EPA is assuming that better data will result 

from documenting and calculating emissions from every single small component 

related to oil and gas production instead of using carefully documented emissions 

factors applied across larger units. This procedure ignores the rules of probability 

and statistics and rejects average values in favor of counting every bean. There is 

no reason to believe that this burdensome method of data collection will produce 

an emissions number of greater value or validity than other accepted and proven 

techniques. The proposed rule is considerably more burdensome for onshore 

facilities than offshore facilities where MMS GOADS reporting standards are 

acceptable. 

4. Economic Impact Analysis 

We are in the process of evaluating the economic impact analysis provided by EPA. 

At this point it appears that EPA’s cost estimates for impact on the industry are low 

by one to several magnitudes. EPA fails to realize the massive amount of data 

collection and recordkeeping required to calculate emissions from the vast majority 

of some 700,000 well sites in the U.S. The only feasible alternative is to adopt 

simple threshold exemptions and simplify the data gathering requirements and 

calculations by use of widely accepted methodologies such as the API 

Compendium. Industry and the EPA would be much better served by spending 

resources to improve any emission factor methods that EPA feels is not 

representative of actual emissions (e.g., well blowdowns). 

We are particularly concerned with the requirement to count all fugitive 

components on every well site and small production facility that we operate. This 

requirement is very significant in terms of effort and cost. Thus, it is critical to us 

to receive relief on fugitive component inventory. 

5. Minority Owners

Has the requirement for minority owners to sign-off on reported emissions been 

removed? 
6. Annual Reporting 

What is the rationale for annual reporting when experience with the U.S. Inventory 

of GHG emissions show very gradually changes in the total inventory on a year to 

year basis? For instance, even with the recent recession total inventory was only 

down about 2 to 3%. Has EPA given any thought to whether the large financial 

burden on industry should be required each and every year when a biannual report 

could suffice?