The comments reflect interagency review of the draft rule under EOs 12866 and 13563. They are

subject to further policy review.

Page 1 of 30

Interagency comments on EPA/OAR rule, “Oil and Natural Gas Sector--New Source Performance 

Standards and National Emission Standards for Hazardous Air Pollutants” (July 8, 2011)

A. Compliance Dates

1. Can EPA clearly explain, perhaps in a table, when affected facilities will have to be in compliance

with the new requirements? The NESHAP requirements have a three-year deadline, but the NSPS

requirements are effective immediately, right? Further, has EPA thought about whether the

industry can be in compliance with the REC requirements by the publication of the final rule?

EPA RESPONSE: Unlike CAA section 112, section 111 does not provide for compliance at some future 

time after the effective date of a rule. For NSPS under section 111, the effective date is the date of 

publication of the final rule, plus 60 days for review of the final rule as provided for in the Congressional 

Review Act (CRA). Specifically, for the Oil and Natural Gas NSPS, our consent decree deadline for 

Administrator signature of the final action is February 28, 2012. Allowing for 2 to 4 weeks for 

publication of the final rule in the Federal Register, plus the statutory 60-day CRA review period, we 

anticipate that compliance would be required by approximately mid-May 2012. That would be 

approximately 9 months after our anticipated date for publication of the proposed rule in the Federal 

Register in late August, following our consent decree deadline for signature of the proposed action by 

July 28. We believe 9 months is sufficient lead time for REC equipment to be available and for owners 

and operators to arrange for services of REC providers to allow them to comply with the NSPS for well 

completions.
The comments reflect interagency review of the draft rule under EOs 12866 and 13563. They are

subject to further policy review.

Page 2 of 30

B. Derivation of Estimated Methane Recovery Cost Savings

1. The natural gas composition data used by EPA to estimate the emissions reductions for the new

reduced emission completion (REC) standard and assess the economic and environmental

impacts of the rule does not appear to be representative. This data is used to estimate the

majority of the emissions reductions claimed by the proposed NSPS and NESHAP rules. The

assumed composition of produced natural gas is based on an average of only twelve data points

from the 1995 GRI study, summarized in the EC/R Inc. July 25, 2011 memo. The variability of

those data points is significant and appears not to be taken into account in the analysis. For

example:

The average methane content of the twelve data points is 82.8mol% (Tables 1 and 3 of

the EC/R Inc. memo), but a statistical analysis of the GRI data on Table 3 for methane

yields a standard deviation of 10.2 mol%. 

Similarly, a statistical analysis of the GRI data on Table 3 yields an average BTEX content

of 428 ppmv, with a standard deviation of 278 ppmv.

2. Additionally, the data on Table 1 of the EC/R Inc. memo show that the composition of natural

gas produced in the Barnett and Marcellus shale formations, which is not taken into further

account in the analysis, deviates widely from the average of the GRI data. The Marcellus shale

formation has significantly higher methane content than the GRI average, but less than one third

of the VOC content. As hydraulically fractured wells are the focus of this REC standard, it is

possible that they may not be accurately characterized using the 1995 GRI data, which

assumedly focuses on conventional natural gas. These variations in methane, BTEX, and VOC

contents may invariably affect the results of the economic and environmental impacts shown in

the Regulatory Impact Analysis (RIA). Therefore, reviewers suggest this be further investigated

and explained to determine if that effect is significant. We request that EPA conduct a

sensitivity analysis and use a much larger sample size that includes data on hydraulically

fractured produced natural gas.

EPA RESPONSE (TO COMMENTS B1 and B2): An evaluation on the gas composition data variability was 

performed to determine whether the GRI-MACT data we used was representative of produced natural 

gas. For reference purposes, here is a copy of the table from the gas composition memo (NOTE: this has 

been updated from the one in the gas composition memo):
The comments reflect interagency review of the draft rule under EOs 12866 and 13563. They are

subject to further policy review.

Page 3 of 30

Production

Methane VOC HAP

CENRAP* Gas Wells 11 Basins: Louisiana Mississippi Salt, 

Southern Oklahoma, Nemaha Uplift, 

Arkoma, Cambridge Arch Central Kansas 

Uplift, Fort Worth, Cherokee Platform, 

Permian, East TExas, Western Gulf, and 

Anadarko

87.8 3.50 0.019

CENRAP* Oil Wells 11 Basins: Louisiana Mississippi Salt, 

Southern Oklahoma, Nemaha Uplift, 

Arkoma, Cambridge Arch Central Kansas 

Uplift, Fort Worth, Cherokee Platform, 

Permian, East TExas, Western Gulf, and 

Anadarko

46.7 11.62 0.02

1995 GRI Production Nationwide 82.8 6.98 0.155

GTI Database Gas Wells Nationwide, proven reserves, and 

undiscovered reserves data from 416 US and 

83 Canadian basins/formations

82.8 3.61 n/a

TX Barnett** Unprocessed Natural Gas Barnett Shale 74.0 8.20 0.20

INGAA Unprocessed Natural Gas Unknown 80.0 5.00 n/a

NREL LCA*** Gas Well Worldwide 65.7 5.66 n/a

MARCELLUS† Gas Well Marcellus 97.2 2.02 0.03345

WYOMING DEQ* Gas Well Wyoming 92.4 1.19 0.08

46.7 1.2 0.0

97.2 11.6 0.2

78.8 5.31 0.1

1995 GRI Production Nationwide 82.8 6.98 0.155

n/a = not available

* HAP data contains BTEX and n-Hexane

** HAP Speciation not provided

***Data provided were ranges for each pollutant (min and max). These values represent normalized averages of these

values and may not be valid representations

†HAP data only reported for hexane

Average

Volume %

Data Source Source of Natural Gas Area Covered

Minimum

Maximum

We believe that the gas composition for pneumatic controllers, equipment leaks, and compressors will 

be unchanged because these emissions units are associated with gas from oil wells and gas wells making 

the range of VOC composition widely varied. Since the 1995 GRI data (VOC = 6.98% by volume) is within 

the range of all the averages of each datapoint (range from 1.19 to 11.6% by volume, with an average of 

5.31%, the 95% conf interval ranges from 2.81% to 7.82%), it can be assumed that, for the purposes of

this proposal, it is representative of the range of VOC that would be emitted from these emissions 

points.

As requested by the reviewer, we performed a sensitivity analysis on compositions from the gas well 

data using a larger sample size and including data on hydraulically fractured wells. The results of this 

analysis are presented below.
The comments reflect interagency review of the draft rule under EOs 12866 and 13563. They are

subject to further policy review.

Page 4 of 30

Based on the information above we believe it is appropriate to revise the gas composition that we use 

for completions and recompletions. Therefore, as a result of this analysis and in response to the 

comments from the reviewer, we have developed develop a natural gas composition for use in 

determining the impacts of completions and recompletions based on the gas well composition sources 

above. The following is the gas composition that will be used.

In addition, we developed a composition for natural gas associated with oil wells based on the CENRAP 

data summarized in the first table. The composition developed is presented below.

Methane (C1) VOC

Mean 83.186 Mean 3.630

Standard Error 0.715 Standard Error 0.170

Median 86.561 Median 3.104

Mode 0.000 Mode 0.000

Standard Deviation 15.262 Standard Deviation 3.626

Sample Variance 232.930 Sample Variance 13.149

Kurtosis 12.810 Kurtosis 9.258

Skewness -3.065 Skewness 2.262

Range 99.748 Range 29.560

Minimum 0.000 Minimum 0.000

Maximum 99.748 Maximum 29.560

Sum 37933.039 Sum 1655.427

Count 456.000 Count 456.000

Confidence Level(95.0%) 1.405 Confidence Level(95.0%) 0.334

Volume Percent Volume Percent

(Lower of 95% conf interval) 81.782 (Lower of 95% conf interval) 3.297

Methane 83.186 VOC 3.630

(Higher of 95% conf interval) 84.591 (Higher of 95% conf interval) 3.964
The comments reflect interagency review of the draft rule under EOs 12866 and 13563. They are

subject to further policy review.

Page 5 of 30

3. A reviewer believes that a calculation error may have been made in calculating baseline

methane, VOC, and HAP emissions from uncontrolled hydraulically fractured gas wells, and the

emissions savings. The result is an overestimate of emissions and savings of about 26 percent.

The error is believed to be as follows: In the file "NSPS and RTR Options Costs and Emissions

06_08_2011_ECR_7pm.xlsx", Cell F6 calculates the tons of methane emitted from an

uncontrolled fractured gas well in tons per year to be 158.3 using the formula "190.98 * 0.829". 

Gas Wells Oil Wells

Component Volume % Volume %

Carbon dioxide (CO2) 1.63 1.00

Nitrogen (N2) 4.45 29.19

Methane (C1) 83.08 46.73

Ethane (C2) 4.92 10.17

Propane (C3) 2.14 6.62

i-Butane (i-C4) 0.35 1.07

n-Butane (n-C4) 0.64 2.14

i-Pentane (iC5) 0.10 0.55

n-Pentane (nC5) 0.12 0.52

Cyclopentane 0.01 0.00

n-Hexane (n-C6) 0.15 0.01

Hexanes (C6) - -

Cyclohexane 1.31E-03 1.45E-03

Other Hexanes 0.01 0.01

Methylcyclohexane 1.82E-03 1.82E-03

C6+ Heavies 0.11 -

Heptanes (C7) 0.01 0.70

n- Heptanes (C7) - 1.91E-03

C8+ Heavies 3.80E-03 5.18E-03

Benzene 4.55E-03 6.18E-03

Toluene 3.35E-03 2.23E-04

Ethylbenzene 9.98E-05 4.45E-04

Xylenes 8.82E-04 -

2,2,4-Trimethylpentane 7.49E-05 2.23E-04

Helium 0.14 -

Oxygen 0.08 -

Hydrogen 1.31E-03 0.58

Hydrogen disulfide (H2S) 2.03 0.71

Total 100.00 100.00

Methane (C1) 83.08 46.73

VOC 3.66 11.62

HAP 0.16 0.01
The comments reflect interagency review of the draft rule under EOs 12866 and 13563. They are

subject to further policy review.

Page 6 of 30

Table 5 of the EC/R Gas Composition Memo shows 82.9 percent the normalized percentage of

methane in natural gas by volume. The spreadsheet does not explain what the number 190.98 is

and where it comes from. It is currently presumed to be the total natural gas emissions from an

uncontrolled fractured well in tons per year. If this is correct, then Cell F6 should have been

calculated using the weight percentage of methane in natural gas, which is shown as 65.7

percent in Table 5 of the EC/R Gas Composition Memo. This, therefore, would make Cell F6

calculation to be "190.98 * 0.657" which is equal to 125.5 instead of 158.3 shown in the

spreadsheet. Consequently, it means that EPA has overestimated the methane emissions by

about 26 percent. Similar errors are perceived to have occurred in Cells E6 and G6 of the

spreadsheet used in calculating the VOC and HAP emissions in tons per year , respectively since

they were obtained by multiplying Cell F6 by the VOC:Methane and HAP:Methane weight ratios

shown in Table 6 of the EC/R Gas Composition Memo. This potential error is then perceived to

have been repeated in rows 7, 8, and 9 of the spreadsheet. Consequently, the emissions savings

in the spreadsheet, which are used in the Regulatory Impact Analysis document, are perceived to

be overestimated since the baseline uncontrolled emissions were used to calculate them. 

Therefore, the reviewer urges EPA to recheck this set of calculations, as well as others within

the Regulatory Impact Analysis to ensure they are accurate.

EPA RESPONSE: While the internal calculation on the spreadsheet was not represented clearly, the 

outcome of the emissions estimate was correct. An explanation of the methodology and calculation is 

below. 

For all completion and recompletion emission estimations, the methane emissions per event by volume 

were converted to tons of methane per event. VOC and HAP weight ratios were then applied to 

determine these emissions. 

For completions and recompletions with hydraulic fracturing, the total gas volume per event was the 

best emission estimate available for these sources. Therefore, to be consistent with the other well 

completion categories, the total volume of natural gas was converted to the volume of methane based 

on a volume of methane of 82.9 percent. The volume of methane was then converted to tons of 

methane. The weight ratios of VOC and HAP were applied. The result of the calculation is the following:

However, in light of comments 1 and 2 the gas composition for wells has been split between oil and gas 

wells. The volume percent of methane for natural gas wells is now 83.081 percent and oil wells are 

estimated to have 46.732 percent of methane by volume. Therefore the following table summarizes the 

revised estimate for well completions.
The comments reflect interagency review of the draft rule under EOs 12866 and 13563. They are

subject to further policy review.

Page 7 of 30

Uncontrolled Emissions Estimates from Oil and Natural Gas Well 

Completions and Recompletions 

Well Completion Category

Emissions

(Mcf/event)

Emissions

(tons/event)

Methane Methane*

VOC** HAP‡

Natural Gas Well Completion 

without Hydraulic Fracturing 38.6 0.80 0.12 0.009

Natural Gas Well Completion with 

Hydraulic Fracturing 7,623 158.55 23.12 1.68

Oil Well Completions 0.34 0.007 0.006 0.0000007 

Natural Gas Well Recompletion 

without Hydraulic Fracturing 2.59 0.054 0.01 0.0006

Natural Gas Well Recompletion 

with Hydraulic Fracturing 7,623 158.55 23.12 1.68

Oil Well Recompletions 0.057 0.001 0.001 0.0000001 

Minor discrepancies may be due to rounding.

The conversion used to convert methane from volume to weight is 0.0208 tons methane is 

equal to 1 Mcf of methane. 

**Assumes 0.1459 lb VOC /lb methane for natural gas wells and 0.8374 lb VOC/lb methane for 

oil wells.

‡Assumes 0.0106 lb HAP/lb methane for natural gas wells and 0.0001 lb HAP/lb methane for 

oil wells.

4. Reviewers note that the EPA documents received so far provide very little insights about

methane emissions from hydraulic fracturing flow back water sources / activities, an area EPA

claims to be one of the leading drivers for expanding the rule to include methane emissions from

unconventional gas production. We request EPA provide detailed data/information supporting

their claim.

EPA RESPONSE: For further details on the source and magnitude of emissions from hydraulically 

fractured gas wells, Appendix B of Subpart W of the Greenhouse Gas Reporting Rule 

(http://www.epa.gov/climatechange/emissions/downloads10/Subpart-W_TSD.pdf) provides a detailed 

discussion of the methodology used to develop the natural gas emission factor for unconventional well 

completions and recompletions involving hydraulic fracture and references to the source data. The 

emission factor was developed using experiences presented at Natural Gas STAR technology transfer 

workshops on the source of the emissions, how the emissions occurred during the flowback process, 

and the magnitude of the emissions. We can provide further information or have a follow-up call to 

discuss this in more detail if that would be useful.

5. Reviewers further note that while there is ample information on the emissions profiles of the

wells, there is a lack of information regarding the flowback period length, and the volume of gas

expected during the flowback period. So far, all data provided have been the average of these

points.
The comments reflect interagency review of the draft rule under EOs 12866 and 13563. They are

subject to further policy review.

Page 8 of 30

It is easy to see a situation where a site with no installed equipment and a short flowback period

of 3 days will incur a large cost, whereas a site with an installed glycol dehydrator and longer

flowback period (say 10 days) will be profitable. Without detailed information behind the

distribution of flowback period and emission rates, it is difficult to analyze this further – most

importantly, reviewers would like to know the number of wells that are projected to be

profitable, and the number of wells expected to incur a cost as a result of this regulation. Can

EPA provide this breakdown? 

Background: EPA has provided the following information which indicates there is a distribution

that can be characterized:

The analysis states that many of the numbers are averaged across the industry, including:

Length of flowback period varies between 3 and 10 days

Cost of REC equipment per well (dependent on whether glycol dehydrators or 3-phase

separators are on site) varies between $700 / day and $6,500 per day

EPA RESPONSE: To address the question above, it is important to note that there are several key factors, 

in addition to the daily rate for REC services that affect the profitability of an individual REC. Those 

include: the hydrocarbon content in the flowback gas, the flow rate of the flowback gas, and the extent 

to which gas condensate is produced by the well during the flowback. While the Gas STAR Lessons 

Learned data provides a good representation of typical characteristics of RECs, there is not a 

comprehensive database of gas well completions with details about the duration of the flowback, 

flowback rate, gas composition, and condensate production to evaluate profitability for all completion 

operations throughout the nation. However as noted in the response to B6, EPA is amenable to 

evaluating a potential threshold and plans to seek comment in the preamble.

Further Background:

Based on Gas STAR Partner company field experience and expert opinion, the Gas STAR Lessons Learned 

document provides estimates that a typical flowback period is 3 to 10 days and costs range from $700 to 

$6,500 per well per day. The Lessons Learned study is based on data provided by several Natural Gas 

STAR Partners who have extensive field experience implementing RECs. In addition to the companies, 

vendors and service providers were also consulted in the development of the document to verify costs 

and other data. While the Gas STAR Lessons Learned data provides a good representation of typical 

characteristics of RECs, EPA recognizes that the actual REC costs and flowback period for hydraulically 

fractured gas wells will vary across specific operations. 

It is important to note that the low and high REC cost range are per day costs and are not directly 

correlated to the flowback period. As noted above, the low end of the range represents a situation 

where permanent equipment was over-sized. The high end of the range is based on Partner experiences 

where there was not existing equipment in place and therefore, all of the REC equipment was portable 

and leased. However, the presence of permanent equipment that can be used for the REC is not, by 

itself, a gauge for the profitability of the project. For example, it is possible to have a scenario in which a 

REC using permanent equipment is less profitable than a REC which requires the leasing of all portable 

equipment based on several factors: the volumetric flowrate, composition of the flowback gas, and 

condensate production, etc.

6. Has EPA considered including a cost-effective or profitability threshold to address this

potential problem? Colorado has dealt with this issue (Requiring RECs in situations where it
The comments reflect interagency review of the draft rule under EOs 12866 and 13563. They are

subject to further policy review.

Page 9 of 30

won’t be profitable) by including exemptions when they are not profitable, and requiring flares

instead (which does lead to significant HAP and VOC reductions):

Green completion practices are required on oil and gas wells where reservoir pressure,

formation productivity, and wellbore conditions, based upon offset well performance,

are likely to enable the well to be capable of naturally flowing hydrocarbon gas in

flammable or greater concentrations at a stabilized rate in excess of five hundred (500)

MCFD to the surface against an induced surface backpressure of five hundred (500) psig

or sales line pressure, whichever is greater.

Wyoming has similar exemptions. From the provided TSD:

In 2008, the state of Wyoming’s Air Quality Division (WAQD) required operators in the

Jonah-Pinedale Area to complete wells without flaring or venting where the following

criteria are met: (1) the flowback gas meets sales line specifications and (2) the pressure

of the reservoir is high enough to enable REC. If the above criteria are not met, then the

produced gas is to be flared. The WAQD requires that, “emissions of VOC and HAP

associated with the flaring and venting of hydrocarbon fluids (liquids and gas) associated

with well completion and re-completion activities shall be eliminated to the extent

practicable by routing the recovered liquids into storage tanks and routing the recovered

gas into a gas sales line or collection”

EPA RESPONSE: Although we have determined that RECs are cost-effective based on the low cost per 

ton of VOC reduced (without accounting for savings due to methane recovery during REC), there is no 

“profitability threshold” that we considered in developing our proposed requirements. However, we 

understand the interagency comment with regard to requiring RECs for only the most cost-effective well 

completions. 

We considered the Colorado threshold for green completions ( i.e., gas flow rate of 500 MCFD at a 

surface backpressure of 500 psi or sales line pressure, whichever is greater), but were unable to obtain 

suitable documentation for Colorado’s rationale supporting that threshold. As a result, we were not 

able to incorporate that threshold in our proposed NSPS. Although we are not able to support 

incorporating the 500 MCFD threshold as suggested, we are amenable to proposing that the REC portion 

of the well completions be performed only when pressure of the flowback gas is greater than sales line 

pressure, similar to the Wyoming criterion regarding reservoir pressure.

7. Oil and Gas Completions TSD 4.3.2 and 4.3.3: The estimation of the baseline for completions is

confusing. Can EPA explain if they looked at well types in NEMS, and assumed that they would

be subject to the hydraulic well completion criteria, or did they baseline to 2005 levels and keep

the same ratio? Both instances are reported in the TSD, and could be clarified:

“New well completion estimates are based on predictions from the NEMS Oil and Gas Supply

Model, drawing upon the same assumptions and model used in the Annual Energy Outlook 2011

Reference Case. New well completions estimates were based on total successful wells drilled in

2015 (the year of analysis for regulatory impacts) for the following well categories: natural gas

completions without hydraulic fracturing, natural gas recompletions without hydraulic

fracturing, natural gas recompletions with hydraulic fracturing, oil well completions, and oil well

recompletions. Successful wells are assumed to be equivalent to completed wells”
The comments reflect interagency review of the draft rule under EOs 12866 and 13563. They are

subject to further policy review.

Page 10 of 30

“The percentage of controlled recompletions with hydraulic fracturing was estimated based on

new producing wells in 2005 that were completed with hydraulic fracturing. This methodology

was chosen to be consistent with the methodologies used to determine the number of new well

completions and recompletions for 2015 (as described in Section 4.3.2)...”

EPA RESPONSE: This section of the TSD has been updated to explain more clearly how the number of 

completions and recompletions were estimated, in addition to the methodology used to determine 

existing controls in absence of Federal Regulation. The revision is provided below:

4.3.1 Overview of Approach

The first step in this analysis is to estimate nationwide emissions in absence of the proposed rulemaking, 

referred to as the baseline emissions estimate. In order to develop baseline emissions estimate, the 

number of completions and recompletions performed in a typical year was estimated and then 

multiplied by the expected uncontrolled emissions per well completion listed in Table 4-2. In addition, to 

ensure no emission reduction credit was attributed to sources already controlled under State 

regulations, it was necessary to account for the number of completions/recompletion already subject to 

State regulations as detailed below. In order to estimate the number of wells that are already controlled 

under State regulations, existing well data was analyzed to estimate the percentage of currently 

controlled wells. This percentage was assumed to also represent the wells that would have been 

controlled in absence of a federal regulation and applied to the number of well completions estimated 

for future years. 

4.3.2 Number of Completions and Recompletions

The number of new well completions was estimated using the National Energy Modeling System 

(NEMS). NEMS is a model of U.S. energy economy developed and maintained by the Energy Information 

Administration (EIA). NEMS is used to produce the Annual Energy Outlook, a reference publication that 

provides detailed forecasts of the energy economy from the current year to 2035. EIA is legally required 

to make the NEMS source code available and fully documented for the public. The source code and 

accompanying documentation is released annually when a new Annual Energy Outlook is produced. 

Because of the availability of NEMS, numerous agencies, national laboratories, research institutes, and 

academic and private-sector researchers have used NEMS to analyze a variety of issues. NEMS models 

the dynamics of energy markets and their interactions with the broader U.S. economy. The system 

projects the production of energy resources such as oil, natural gas, coal, and renewable fuels, the 

conversion of resources through processes such as refining and electricity generation, and the quantity 

and prices for final consumption across sectors and regions. 

New well completion estimates are based on predictions from the NEMS Oil and Gas Supply Model, 

drawing upon the same assumptions and model used in the Annual Energy Outlook 2011 Reference 

Case. New well completions estimates were based on total successful wells drilled in 2015 (the year of 

analysis for regulatory impacts) for the following well categories: natural gas completions without 

hydraulic fracturing, natural gas completions with hydraulic fracturing, oil well completions. Successful 

wells are assumed to be equivalent to completed wells. Meanwhile, it was assumed that new dry wells 

would be abandoned and shut in and would not be completed. Therefore estimates of the number of 

dry wells were not included in the activity projections or impacts discussion for exploratory and 

developmental wells. Completion estimates are based on successful developmental and exploratory 
The comments reflect interagency review of the draft rule under EOs 12866 and 13563. They are

subject to further policy review.

Page 11 of 30

wells for each category defined in NEMS that includes oil completions, conventional gas completions 

and unconventional gas completions. The NEMS database defines unconventional reservoirs as those in 

shale, tight sand, and coalbed methane formations and distinguishes those from wells drilled in 

conventional reservoirs. Since hydraulic fracturing is most common in unconventional formations, this 

analysis assumes new successful natural gas wells in shale, tight sand, and coalbed methane formations 

are completed with hydraulic fracturing. New successful natural gas wells in conventional formations are 

assumed to be completed without hydraulic fracturing.

The number of natural gas recompletions with hydraulic fracturing (also referred to as a re-fracture), 

natural gas recompletions without hydraulic fracturing and oil well recompletions was based on well 

count data found in the HPDI®database.1, 2The HPDI database consists of oil and natural gas well 

information maintained by a private organization that provides parameters describing the location, 

operator, and production characteristics. HPDI® collects information on a well basis such as the operator, 

state, basin, field, annual gas production, annual oil production, well depth, and shut-in pressure, all of 

which is aggregated from operator reports to state governments. HPDI was used to estimate the 

number of recompleted wells because the comprehensive historical well data from HPDI is a 

comprehensive resource describing existing wells. Well data from 2008 was used as a base year since it 

was the most recent available data at the time of this analysis and is assumed to represent the number 

of recompletions that would occur in a representative year. The number of hydraulically fractured 

natural gas recompletions was estimated by estimating each operator and field combination found in 

the HPDI database and multiplying by 0.1 to represent 10 percent of the wells being re-fractured 

annually (as assumed in Subpart W’s Technical Supporting Document Error! Bookmark not defined.). 

his results in 14,177 total natural gas recompletions with hydraulic fracturing in the U.S. for the year 

2008; which is assumed to depict a representative year. Non-fractured recompletions were based on 

well data for 2008 in HPDI. The number of estimated well completions and recompletions for each well 

source category is listed in Table 4-3. 

4.3.3 Level of Controlled Sources in Absence of Federal Regulation

As stated previously, to determine the impact of a regulation, it is first necessary to determine the 

current level of emissions from the sources being evaluated, or baseline emissions. To more accurately 

estimate baseline emissions for this analysis, and to ensure no emission reduction credit was attributed 

for sources already being controlled, it was necessary to evaluate the number of completions and 

recompletions already subject to regulation. Therefore, the number of completions and recompletions 

already being controlled in the absence of federal regulation was estimated based on the existing State 

regulations that require control measures for completions and recompletions. Although there may be 

regulations issued by other local ordinances for cities and counties throughout the U.S., wells impacted 

by these regulation were not included in this analysis because well count data are not available on a 

 

1

HPDI, LLC is a private organization specializing in oil and gas data and statistical analysis. The HPDI database is 

focused on historical oil and gas production data and drilling permit data. 

2

For the State of Pennsylvania, the most recent drilling information available from HPDI was for 2003. Due to the 

growth of oil and gas operations occurring in the Marcellus region in Pennsylvania, this information would not 

accurately represent the size of the industry in Pennsylvania for 2006 through 2008. Therefore, information from 

the Pennsylvania’s Department of Environmental Protection was used to estimate well completion activities for 

this region. Well data from remaining states were based on available information from HPDI. From 

<http://www.marcellusreporting.state.pa.us/OGREReports/Modules/DataExports/DataExports.aspx
The comments reflect interagency review of the draft rule under EOs 12866 and 13563. They are

subject to further policy review.

Page 12 of 30

county or local ordinance level. Therefore, the percentage calculated based on State regulations should 

be considered conservative. 

In order to determine the number of completions and recompletions that are already controlled under 

State regulations, EIA historical well count data was analyzed to determine the percentage of new wells 

undergoing completion and recompletion in the States identified as having existing controls.3Colorado 

(CO) and Wyoming (WY) were the only States identified as requiring controls on completions prior to 

NSPS review. The State of Wyoming’s Air Quality Division (WAQD) requires operators to complete wells 

without flaring or venting where the following criteria are met: (1) the flowback gas meets sales line 

specifications and (2) the pressure of the reservoir is high enough to enable REC. If the above criteria are 

not met, then the produced gas is to be flared. 4The WAQD requires that, “emissions of VOC and HAP 

associated with the flaring and venting of hydrocarbon fluids (liquids and gas) associated with well 

completion and re-completion activities shall be eliminated to the extent practicable by routing the 

recovered liquids into storage tanks and routing the recovered gas into a gas sales line or collection 

system.” Similar to WY, the Colorado Oil and Gas Conservation Commission (COOGCC) requires REC for 

both oil and natural gas wells.5 ,6It was assumed for this analysis that the ratio of wells in CO and WY to 

the total number of wells in the U.S. represents the percentage of controlled wells for well completions 

and recompletions. The ratio of wells in WY to the number of total nationwide wells was assumed to 

represent the percentage of controlled well recompletions as it was the only State identified as having 

regulations directly regulated to recompletions. 

From this review it was estimated that 15 percent of completions and 15 percent of recompletions are 

controlled in absence of federal regulation. It is also assumed for this analysis that only natural gas wells 

undergoing completion or recompletion are controlled in these States. Completions and recompletions 

that are performed without hydraulic fracturing, in addition to oil well completions and recompletions 

were assumed to not be subject to State regulations and therefore, were assumed to not be regulated 

at baseline. Baseline emissions for the controlled completions and recompletions covered by regulations 

are assumed to be reduced by 95 percent from the use of both REC and combustion devices that may be 

used separately or in tandem, depending on the individual State regulation.7The final activity factors for 

uncontrolled completions and uncontrolled recompletions are also listed in Table 4-3.

 

3

See EIA’s The Number of Producing Wells, http://www.eia.gov/dnav/ng/ng_prod_wells_s1_a.htm

4

State of Wyoming Department of Environmental Quality, Air Quality Division. Well Completions/Re-completions 

Permit Application. Page 2. August 2010. http://deq.state.wy.us/aqd/Oil%20and%20Gas/AQDOG11_Green%20Completion%20Application.pdf

5

Colorado Oil and Gas Conservation Commission. 2 CCR-404-1. http://oilgas.state.co.us/RuleMaking/FinalDraftRules/COGCCFinalDraftRules_110708.pdf

6 Memorandum to Bruce Moore from Denise Grubert. Site Visit Report from Encana’s Mancreek Field in Parachute, 

Colorado. EC/R Incorporated. August 20, 2010.

7

Percentage of controls by flares versus REC were not determined, so therefore, the count of controlled wells with 

REC versus controlled wells with flares was not determined and no secondary baseline emission impacts were 

calculated.
The comments reflect interagency review of the draft rule under EOs 12866 and 13563. They are

subject to further policy review.

Page 13 of 30

Table 4-3: Estimated Number of Total Oil and 

Natural Gas Completions and Recompletions for a Typical Year

Well Completion Category

Estimated Number 

of Total 

Completions and 

Recompletions*

Estimated 

Number of 

Controlled 

Completions 

and 

Recompletions

Estimated 

Number of 

Uncontrolled 

Completions 

and 

Recompletions*

Natural Gas Well Completions without 

Hydraulic Fracturing* 7,694 7,694

Exploratory Natural Gas Well Completions 

with Hydraulic Fracturing** 446 446

Developmental Natural Gas Well 

Completions with Hydraulic Fracturing** 10,957 1,644 9,313

Oil Well Completions‡

12,193 12,193

Natural Gas Well Recompletions without 

Hydraulic Fracturing 42,342 42,342

Natural Gas Well Recompletions with 

Hydraulic Fracturing‡‡ 14,177 2,127 12,050

Oil Well Recompletions‡

39,375 39,375

*Natural gas completions and recompletions without hydraulic fracturing are assumed to be 

uncontrolled at baseline.

**Fifteen percent of natural gas well completions with hydraulic fracturing are assumed as controlled at 

baseline. 

‡Oil well completions and recompletions are assumed to be uncontrolled at baseline.

‡‡Fifteen percent of natural gas well recompletions with hydraulic fracturing are assumed to be 

controlled at baseline. 

8. EPA estimates a net positive impact on domestic natural gas production, due largely to the

increased recovery of vented gas offsetting some impacts from compliance costs. However, it

appears that the inputs to the NEMS runs used to determine the energy impacts include negative

cost numbers for well completions – accounting for the savings from recovered gas but not the

potential barriers of requiring additional capital needed for the reduced emission completions. 

Has EPA analyzed the potential impacts on production activities from the increased capital

requirements and does EPA have any sense of the scale of those impacts?

EPA RESPONSE: In general, potential barriers to obtaining additional capital should be reflected in the 

annualized cost via these barriers increasing the cost of capital. With this in mind, assuming the 

estimates of capital costs and product recovery are valid, the NEMS results will reflect barriers to 

obtaining the retired capital. A caveat to this is that the estimated unit-level capital costs of controls 

which are newly required at a national-level as a result of the proposed regulation—RECs, for example—

may not incorporate potential additional transitional costs as the supply of control equipment adjusts to 

new demand.
The comments reflect interagency review of the draft rule under EOs 12866 and 13563. They are

subject to further policy review.

Page 14 of 30

Two REC-specific side analyses are worth noting, however. First, to comply with the NSPS REC 

requirements firms are likely to choose between purchasing and performing RECs with their own 

equipment and labor and contracting to third parties who provide RECs as a service. Analysis from the 

EPA Natural gas Star program compares the costs and emissions reductions estimated based upon firms 

purchasing REC equipment and using across multiple wells within fields and basins as opposed to 

contracting service providers for RECs at individual wells. This Natural Gas Star REC Lessons Learned 

document (shared on 6/30/11) compares the incremental costs of contracting individuals RECs with a 

firm purchasing and employing their own REC equipment. The analysis shows purchasing equipment 

has a higher rate of return than contracting for REC services on an individual well basis (rates of return 

are positive in both cases). However, in practice, distances between well projects and timing of well 

completions are significant logistical challenges. Firms likely prefer contracting on an individual basis, 

despite higher costs, because of challenges in employing self-owned and operated equipment optimally 

across well drilling projects. Because of these challenges, we estimate REC-related capital and 

annualized costs based upon firms contracting for REC services on an individual basis. By using the 

higher contracted REC costs throughout the impacts analysis, we incorporate potential costs associated 

with employing capital efficiently. 

Second, we have also supplemented the small business analysis with an enriched discussion of REC 

requirements in the context of financing drilling projects, specifically, and overall capital and exploration 

expenditures, generally. We supplemented this analysis in order to alleviate concerns about small 

business access to RECs. Our results include the REC costs represent a small increment of the overall 

burden of a drilling project and that estimated NSPS engineering compliance costs (without revenues 

from product recovery) will be a small component of overall capital and exploration expenditures, again 

not presenting significant barriers in a very capital intensive industry.

9. In regards to the modeling of future emissions EPA lays out the reasons that NEMS is used, but

why is it used over in-house EPA tools such as IPM? Was it simply a time constraint?

EPA RESPONSE: We chose to use NEMS from the Department of Energy for four main reasons. First, 

NEMS is a well-regarded and publically available modeling platform. Second, we were able to target the 

costs associated with the proposed controls with the appropriate types of oil and natural gas wells and 

stages of production. Third, NEMS enables a detailed analysis of broad energy system impacts of a 

significant new regulation, such as impacts on supply and demand of other fuels (coal, for example) as 

well as detailed estimates of how price impacts of the regulatory shock transmit through the economy. 

Fourth, NEMS enables a detailed examination of secondary impacts of the rule, such as net change if 

CO2-equivalent GHG emission from energy related sources. IPM has many of these capabilities, but has 

primarily been used to examine regulatory impacts on the electricity sector, not on the crude oil and 

natural gas sector specifically. The IPM model version used to model the impacts the Cross-State Air 

Pollution treated natural gas supply endogenously based on simplified version of the Gas Market Model 

Hydrocarbon Supply Model (http://www.epa.gov/airmarkets/progsregs/epaipm/docs/v410/Chapter10.pdf). This IPM version may have many of the advantages of using NEMS for 

analysis of natural gas, but still may have a limited treatment of the crude oil sector, which is of 

relevance for this rulemaking.

10. In the preamble and RIA there is a discussion of the potential for recovered methane to lead to

cost savings for producers. The idea is that recovered methane can be input directly into natural

gas production system and sold. The text of the RIA implies that EPA treated this recovered
The comments reflect interagency review of the draft rule under EOs 12866 and 13563. They are

subject to further policy review.

Page 15 of 30

methane as an output and not an input. We suggest EPA makes sure that it is addressing this

distinction in the RIA and preamble.

More specifically, by treating recovered methane as an output the cost savings may be

misstated. The $4 per McF price used to value recovered methane seems to come from projected

natural gas prices – this appears to be the consumer price. While the value of the recovered

methane would be related to the revenue that it would yield this methane is not directly treated

as output that would be sold. Rather, the recovered methane represents an increase in

productivity for the producer. This control technology makes the producer’s equipment more cost

effective by getting the same output for a smaller cost.

It would be useful for EPA to value the recovered methane as the reduction in the cost to

producers to produce natural gas. As a result, viewing recovered methane as a direct output

could misstate its value to producers as a cost-saving measure (rather than a revenuegenerating one). If this recovery would increase supply for the firm then it would be helpful for

EPA to determine what the new profit-maximizing output would be and the cost savings. 

EPA RESPONSE: This comment was insightful and the following discussion is added to the RIA in Section 

3.3:

A brief conceptual discussion about our energy system impacts modeling approach is necessary before 

going into detail on NEMS, how we implemented the regulatory impacts, and results. Economically, it is 

possible to view the recovered natural gas as an explicit output or as contributing to an efficiency gain at 

the producer level. For example, the analysis for the proposed NSPS shows that about 97 percent of the 

natural gas captured by emissions controls suggested by the rule is captured by performing RECs on new 

and existing wells that are completed after being hydraulically fractured. The assumed $4/Mcf price for 

natural gas is the price paid to producers at the wellhead. In the natural gas industry, production is 

metered at or very near to the wellhead, and producers are paid based upon this metered production. 

Depending on the situation, the gas captured by RECs is sent through a temporary or permanent meter. 

Payments for the gas are typically made within 30 days.

To preview the energy systems modeling using NEMS, results show that after economic adjustments to 

the new regulations are made by producers, the captured natural gas represents both increased output 

(a slight increment in aggregate production) and increased efficiency (producing slightly more for less). 

However, because of differing objectives for the regulatory analysis we treat the associated savings 

differently in the engineering cost analysis (as an explicit output) and in NEMS (as an efficiency gain).

In the engineering cost analysis, it is necessary to estimate the expected costs and revenues from 

implementing emissions controls at the unit level. Because of this, we estimate the net costs as 

expected costs minus expected revenues for representative units. On the other hand, NEMS models the 

profit maximizing behavior of representative project developers at a drilling project level. The net costs 

of the regulation alter the expected discounted cash flow of drilling and implementing oil and gas 

projects, and the behavior of the representative drillers adjusts accordingly. While in the regulatory 

case natural gas drilling has become more efficient because of the gas recovery, project developers still 

interact with markets for which supply and demand are simultaneously adjusting. Consequently, project 

development adjusts to a new equilibrium. While we believe the cost savings as measured by revenues 

from selling recovered gas (engineering costs) and measured by cost savings from averted production 

through efficiency gains (energy economic modeling) are approximately the same, it is important to 
The comments reflect interagency review of the draft rule under EOs 12866 and 13563. They are

subject to further policy review.

Page 16 of 30

note that the engineering cost analysis and the national-level cost estimates do not incorporate 

economic feedbacks such as supply and demand adjustments.

11. RIA table 3-4 The RIA estimates that the total revenue to the industry will be $757 M (from the

well completion portion), vs. a net cost of $712 M. The $45 M in savings represents a 6% return

on investment. Error bars would help here (if only for reviewer information) to see how close

the regulation is to truly breaking even. More importantly, a sensitivity analysis with the price

of natural gas is warranted for this analysis. 

EPA RESPONSE: We have added two sensitivity analyses, including figures, with respect to the assumed 

price of natural gas in the RIA. The first sensitivity analysis is in Section 3 (Economic Impact Analysis) 

and examines the estimated annualized engineering compliance costs (after including estimated 

revenue from product recovery) as a function of assumed wellhead natural gas prices in 2015. The 

second sensitivity analysis is in Section 6 (Benefits and Cost Comparison) and examines the break-even 

point of the proposed NSPS in terms of VOC emissions reduction cost-effectiveness ($/ton reduced) as a 

function of assumed wellhead natural gas prices in 2015.
The comments reflect interagency review of the draft rule under EOs 12866 and 13563. They are

subject to further policy review.

Page 17 of 30

C. Requirement for REC v. Flaring

1. The purpose of the NSPS regulation is to achieve reductions of VOCs from various sources, and in

the case of well completions, VOCs. EPA is mandating the use of REC unless a well is too far from

a gathering line, in which case they can flare gases from well completions. However,there may

be situations where the well completion period is short (depending on the formation, fracking

process, and other factors), and the use of REC may yield a negative cost. In these cases, it

would not be economically attractive to use REC equipment, rather flaring would be the

preferred alternative. The TSD states that “...an average completion combustion device cost is

approximately $3,523“ whereas REC system costs “are projected to be between $700 and $6,500

per day”, or “an average incremental cost for a REC of $4,146 per day.” Thus, there are cases

were flaring would be more cost-effective.

Note that the emissions from the captured gas through the REC process are eventually burned in

commercial or industrial use, hence the only purpose of the REC requirement is to provide

revenue to offset the cost of the equipment. In many instances, this makes economic sense,

however there are bound to be situations where flaring is the economically preferred alternative. 

Since both flaring and REC systems have the ability to achieve a 95% VOC reduction, can EPA

consider a VOC mitigation requirement, i.e. a performance metric (95% VOC reduction), rather

than mandating the use of a technology (REC)? This approach would allow the production

facility to make the best business decision, while achieving the stated environmental goal

(reducing VOC emissions).

RESPONSE IN PROGRESS
The comments reflect interagency review of the draft rule under EOs 12866 and 13563. They are

subject to further policy review.

Page 18 of 30

D. Compliance with REC v. Flaring

1. How will regulated entities determine when flaring for well completions is safe and therefore

required? Is this explained in the proposal?

EPA RESPONSE: In our proposal, we require pit flaring in lieu of REC for exploratory wells, for 

delineation wells, and for portions of other fractured gas well completions when REC is not required due 

to gas quality being unsuitable for entering the sales line. However, we are aware that pit flaring 

sometimes can present a fire hazard or other hazard and provide an alternative of venting when such a 

condition makes pit flaring unacceptable from a safety perspective, or for other reason, such as when 

flaring is prohibited by local ordinance or other restriction. We do not decide for the operator when 

these conditions exist, but leave it to their discretion to make that call. They then can vent in lieu of pit 

flaring and must keep records of the duration of the portions of the completion that consists of REC, pit 

flaring, and venting. 

2. How are the two groups of facilities officially defined for purposes of well completion

requirements (within range of gathering lines vs. too far from gathering lines to require REC)? 

How will “too far” be determined? Is this explained in the proposal?

EPA RESPONSE: We have no criteria that specify distance to gathering lines, although the underlying 

basis for our two subcategories of fractured gas wells is whether gathering lines are available to convey 

the recovered gas to further processing or to market. We explain in the preamble that exploratory wells 

and delineation wells are generally not near existing gathering lines (this language has been revised and 

clarified in the preamble since it went up for interagency review). Here is the revised language:

We identified two subcategories of fractured gas wells: (1) Non-exploratory and non-delineation wells; 

and (2) exploratory and delineation wells. An exploratory well is the first well drilled to determine the 

presence of a producing reservoir and the well’s commercial viability. A delineation well is a well drilled 

to determine the boundary of a field or producing reservoir. Because exploratory and delineation wells 

are generally isolated from existing producing wells, there are no gathering lines available for collection 

of gas recovered during completion operations. In contrast, non-exploratory and non-delineation wells 

are located where existing, producing wells are connected to gathering lines and are, therefore, able to 

be connected to a gathering line to collect recovered salable natural gas product that would otherwise 

be vented to the atmosphere or combusted.
The comments reflect interagency review of the draft rule under EOs 12866 and 13563. They are

subject to further policy review.

Page 19 of 30

E. Impacts on Small Businesses

1. In view of the vital role small independent natural gas producers play in meeting the energy

requirements of the United States, DOE suggests that EPA conducts a more thorough and indepth analysis to accurately characterize the impacts of the proposed regulations on small

businesses.

EPA RESPONSE: Yes, we completely agree that small independent producers play a vital role in 

producing energy for the United States. Because of this suggestion and other discussions during the 

review process, EPA has deepened its examination of potential impacts of the proposed regulations. 

The reviewer may read the enriched discussion in the revised RIA (Section 3.5). We present more 

analysis of the sample of firms discussed in the Section 3.5, including details regarding capital and 

exploration expenditures and well drilling across small and large firms. A meeting is also planned for 

7/20 that we expect will be partially focused on discussing the small business analysis. Slides 

summarizing the additional analysis will be shared for that meeting.

2. How will the revised NSPS and NESHAP affect small and independent firms that may have limited

access to capital for up front control technologies? Has EPA done any analysis that would help

answer this question? 

EPA RESPONSE: Yes, our revised small business analysis (Section 3.5 of the RIA) investigates this 

question with the best data available to EPA. The reviewer may read the enriched discussion in the 

revised RIA (Section 3.5). A meeting is also planned for 7/20 that we expect will be partially focused on 

discussing the small business analysis. Slides summarizing the additional analysis will be shared for that 

meeting.

3. The proposed regulation seemingly does not account for age of equipment, especially important

to small producers. These producers would be anticipated to have older, less efficient and well

maintained equipment that is producing from assets that are lower volume hydrocarbon

producers. Has EPA considered this?

EPA RESPONSE: Yes, EPA has considered this issue, but it is important to provide different responses for 

the proposed NESHAP alternatives and the proposed NSPS. 

NESHAP is a risk and technology based standard and consideration of variables such as equipment age is 

not legitimate in considering regulatory alternatives. 

The NSPS is a standard that applies to new or modified sources. Because of this, NSPS requirements 

target new or modified affected facilities or equipment, such as processing plants and compressors. 

While the requirements may apply to modifications of existing facilities, it is important to discuss well 

completion-related requirements aside from other requirements in the NSPS distinctly. 

Excluding well completion requirements from the cost estimates, the non-completion NSPS 

requirements (related to equipment leaks at processing plants, reciprocating and centrifugal 

compressors, pneumatic controllers, and storage vessels) are estimated to require $27 million in 

annualized engineering costs. EPA also estimates that the annualized costs of these requirements will 

be mostly if not fully offset by revenues expected from natural gas recovery. EPA does not expect these 

requirements to disproportionately affect producers with older equipment.
The comments reflect interagency review of the draft rule under EOs 12866 and 13563. They are

subject to further policy review.

Page 20 of 30

Meanwhile, the REC and emissions combustion requirements in the proposed NSPS relate to well 

completion activities at new hydraulically fractured natural gas wells and existing wells which are 

recompleted after being fractured or re-fractured. These requirements constitute the bulk of the 

expected engineering compliance expenditures (about $710 million in annualized costs) and expected 

revenues from natural gas product recovery (about $760 million in revenues, annually). While age of the 

well and equipment may be an important factor for small and large producers in determining whether it 

is economical to fracture or refracture an existing well, this equipment is unlikely to be subject to the 

NSPS. To comply with completion-related requirements, producers are likely to rely heavily on portable 

and temporary completion equipment brought to the wellpad over a short period of time (a few days to 

a few weeks) to capture and combust emissions that are otherwise vented. The equipment at the 

wellhead—newly installed in the case of new well completions or already in place and operating in the 

case of existing wells—is not subject to the NSPS requirement. 
The comments reflect interagency review of the draft rule under EOs 12866 and 13563. They are

subject to further policy review.

Page 21 of 30

F. Estimate of Wells and Completions

1. Oil and Gas Completions TSD, 4.3.3: The modeled number of REC wells is limited to a simple

ratio of all wells to those in Colorado and Wyoming, stating that those are the only two states

that require REC equipment. Are there companies NOT in these states that are using REC

techniques? Partners of the EPA GAS STAR program are using them in some instances, especially

where profitable. In addition, if a natural gas sensitivity case is conducted, the higher price for

natural gas may make some REC systems economic, whereas they may not be at current gas

prices. Note: The Gas STAR website reports in cumulative BCF avoided, and not number of well

completions, or more useful, well completions per year.

EPA RESPONSE: Yes, companies outside of CO and WY are implementing RECs. The Natural Gas STAR 

Program is focused on voluntary reductions. Partners do not report reductions achieved from complying 

with federal, state, or local regulations. In 2009 there were 13 companies that reported voluntary 

emission reductions to the Natural Gas STAR Program from implementation of RECs. These companies 

implemented approximately 1,200 RECs in 2009. From 2006 through 2009, Natural Gas STAR companies 

performed an average of about 1,400 RECs per year. These RECs are in addition to the estimate of 2,127 

RECs required by State regulations in CO and WY, presented in the TSD. 

It is important to note that Gas STAR companies may be implementing RECs more broadly than they 

report to EPA, given some partners may only be reporting their reduction activities from certain regions 

and not company-wide. Also, there are likely companies outside of the Gas STAR Program that have 

implemented RECs that would not be represented in the Gas STAR data. Therefore, the number of 

companies implementing RECs voluntarily is likely even greater than demonstrated by the Gas STAR 

data. 

2. Oil and Gas Completions TSD Table 4-3 (inserted below): The number of completions that will

need to be controlled will jump from 2,127 to 14,177 per year. This is more than 5 times the

number of installed systems currently. Reviewers understand the completion process is very short

and that in many cases REC devices are mobile, but this is still a massive increase. Has EPA

conducted an analysis of the REC equipment vendors, as a reality/implementation check? This

would be helpful.

Well Completion Category

Estimated

Number of

Total

Completions

and

Recompletion

s*

Estimated

Number of

Controlled

Completions

and

Recompletio

ns

Estimated

Number of

Uncontrolled

Completions

and

Recompletion

s*

Natural Gas Well Recompletions with Hydraulic

Fracturing 14,177 2,127 12,050
The comments reflect interagency review of the draft rule under EOs 12866 and 13563. They are

subject to further policy review.

Page 22 of 30

EPA RESPONSE: Based on EPA knowledge and experience with the industry and service provider market 

through the Natural Gas STAR Program, Global Methane Initiative, and other activities8, EPA considered 

several key factors in evaluating whether future REC supply can meet the additional demand of the new 

rule:

As mentioned in the answer to F1 above, the number of RECs performed today is likely higher 

than 2,127. For the NSPS impacts analysis, we only considered State regulations since this is a new 

source rule and it is not possible to predict where companies would continue to implement mitigation 

activities voluntarily in absence of the rule. However, as outlined above, when taking into account 

companies implementing RECs on a voluntary basis in addition to what is required by State regulations, 

EPA estimates that the number of RECs performed on an annual basis is approximately 3300 or greater. 

Well development occurs in non-contiguous phases. We are aware that currently some 

operators have drilled new wells but not conducted the flowback step of completing the well (to 

produce it) right away. This may be done for various reasons including the availability of equipment and 

labor, competition between other types of hydraulic fraccing (e.g., oil wells), among other factors. 

REC equipment and services range in complexity and cost to address individual company 

operating characteristics, resources, and preferences. REC units that are less mechanically complex and 

with less features are likely to be relatively quick and easy to manufacture in large numbers. Simple, cost 

effective REC equipment is currently being used and there is no obvious technical barrier to more 

widespread deployment of such equipment during an initial ramp up in response to the proposal. 

EPA did not conduct a detailed vendor analysis. However based on the factors above, we feel there is 

adequate lead time between the proposal date and when the rule takes effect to satisfy the additional 

demand. 

 

8

The Natural Gas STAR Program has a vendor directory at www.epa.gov/gasstar/tools/service-providerdirectory.html and the Global Methane Initiative has a Project Network of private organizations and service 

providers at www.globalmethane.org/project-network/pnmSearch.aspx
The comments reflect interagency review of the draft rule under EOs 12866 and 13563. They are

subject to further policy review.

Page 23 of 30

G. Other Broad comments

1. The proposed regulation may discourage the use of LPG as fracturing fluid (as a replacement for

water as carrier for propant) in water sensitive formations. This may be one of few hydraulic

fracturing systems (CO2 or LPG) that can be utilized as an alternative due to water use

restrictions in states like New York or in arid areas that have imposed moratorium on hydraulic

fracturing.

EPA RESPONSE: We can find no reason that use of LPG as a fracturing fluid would affect whether a 

fractured gas well would be subject to the proposed requirements or would trigger any additional action 

on the part of the owner or operator. Any LPG fracturing fluid injected into the well during fracturing 

would likely be controlled, either through recovery by REC and/or by pit flaring, depending on 

requirements based on the type of well (exploratory/delineation or non-exploratory/non-delineation) 

being completed. As a result, we do not understand how the proposed regulation could discourage use 

of this technology. 
The comments reflect interagency review of the draft rule under EOs 12866 and 13563. They are

subject to further policy review.

Page 24 of 30

H. Specific comments

Preamble

3. Reviewers suggest using the rule summary to provide a more plain-language explanation of 

what the rule would do. As written, the summary is hard to follow and doesn’t say much about

the most important changes being made. This also seems like to good place to introduce the

concept and benefits of the sector-based approach.

EPA RESPONSE: The Federal Register office has restrictions on what can be placed in the Summary 

section as well as restrictions on length of that discussion. As a result, our first priority is getting the 

required summary information inserted, which relates to the actions we are proposing. In this case, 

since this proposal contains reviews and amendments of several subparts, IN PROGRESS

4. Pg. 42 – Please define “sour gas.”

EPA RESPONSE: Sour gas is defined as natural gas with a maximum H2S content of 0.25 gr/100 scf

(4ppmv) along with the presence of CO2. We will add this definition to the preamble discussion where 

sour gas is mentioned.

5. Pg. 46 – It would be helpful to explain here why only completions after hydraulic fracturing will

be covered. The statistic that approximately 220 times more VOC is vented from completions

with fracking than completions without fracking (as explained later) is a compelling reason and

could be used here as well.

EPA RESPONSE: We appreciate the suggestion. Your comment pertains to section V.A., “What are the 

proposed revisions to the NSPS?” This section is designed to present only a summary of the proposed 

revisions; the rationale for the proposed NSPS requirements is presented in section VI.B. Because 

section V.A. had included some rationale along with the summary of some proposed provisions and was 

inconsistent in the level of detail presented, we have revised that section to simply summarize the 

proposed provisions and have tried to incorporate discussions with consistent levels of detail. As a 

result, we do not believe inserting the supporting language you suggested into section V.A. is 

appropriate.

6. Pg. 49 – This is a good place to briefly explain the health justification for prohibiting the use of

gas-driven pneumatic controllers at gas processing plants. We suggest EPA add such an

explanation.

EPA RESPONSE: This discussion is also in section V.A. (see response H5). As a result, we do not believe 

it is appropriate to include rationale in that section as suggested. However, we understand the 

comment to relate to further explanation of the health and safety reasons why we are proposing to 

require non-gas driven pneumatic controllers for most applications in gas processing plants. We believe 

that, in gas processing plant settings, having multiple gas-operated pneumatic devices in close proximity 

could cause a fire hazard due to the release of natural gas from these devices. Such concentrated 

releases could raise the concentrations of gas in some areas to the lower explosive limit, presenting a 

hazard. We are amenable to adding such language in section VI.B. where we present rationale for the 

proposed requirements for pneumatic controllers.
The comments reflect interagency review of the draft rule under EOs 12866 and 13563. They are

subject to further policy review.

Page 25 of 30

7. Pg. 105-106 – We had difficulty reading the paragraph about methane emissions under the

section “What pollutants are being evaluated...” Is methane being evaluated as a pollutant for

control in the NSPS and then being rejected? Or it is it just mentioned here because of the cobenefits associated with controlling VOCs? We recommend EPA clarify this discussion.

EPA RESPONSE: We agree that the discussion ends abruptly. As you know EPA is continuing to consider 

various sources of greenhouse gases, including methane. We continue to assess the oil and gas sector 

as a source of methane and will consider adding the language below:

Although this proposed rule does not include standards for regulating 

the GHG emissions discussed above, we continue to assess these 

significant emissions and evaluate appropriate actions for addressing 

these concerns.

8. Pg. 111-112 – Please cite or explain the source of the estimates of VOC emissions, including the

data used for the important conclusion that recompletions of refractured wells have similar

emissions to new wells.

EPA RESPONSE: Appendix B of Subpart W of the Greenhouse Gas Reporting Rule9provides a detailed 

discussion of the methodology used to develop the emission factor for new unconventional well 

completions involving hydraulic fracture, which is 9,175 Mcf of natural gas per completion. 

Subpart W and the latest Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2009 (published 

in April 2011) assumes the emission factor for unconventional well recompletions involving hydraulic refracture is the same as new unconventional well completions because the activities and sources of 

emissions during unconventional completions and unconventional recompletions are typically the same. 

EPA has based the NSPS impacts analysis on best available emission data. However, we recognize that 

there is uncertainty associated with our estimates. For both new completions and recompletions, there 

are a variety of factors that will determine the length of the flowback period and actual volume of 

emissions such as the number of zones, depth, pressure of the reservoir, gas composition, etc. This 

variability means there will be some wells which emit more than the estimated emission factor and 

some wells that emit less. With this in mind, EPA plans to seek comment on this assumption and the 

potential availability of new data sources that could allow EPA to further refine the emission factor for 

well completions and recompletions in the future. 

9. Pg. 119 – The explanation for why refracturing an existing well qualifies as a modification (and

therefore triggers NSPS) seems very short. Can the legal justification be fleshed out in greater 

detail here? Are there any similar NSPS that can be discussed for comparison?

 

9

Subpart W Background Technical Support Document available at 

http://www.epa.gov/climatechange/emissions/downloads10/Subpart-W_TSD.pdf. Also published in the latest 

Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2009 (April 2011).
The comments reflect interagency review of the draft rule under EOs 12866 and 13563. They are

subject to further policy review.

Page 26 of 30

EPA RESPONSE: We’ve added some language to the discussion below in section VI.B. to further explain 

what would constitute a modification for the purposes of well completions:

We propose that fracturing (or refracturing) and completion of an 

existing well [i.e., a well existing prior to (INSERT DATE OF 

PUBLICATION IN THE FEDERAL REGISTER)] is considered a modification 

under CAA section 111(a), because physical change occurs to the 

existing well, which includes the wellbore, casing and tubing, 

resulting in an emissions increase during the completion operation. 

The physical change in this case would be caused by the reperforation 

of the casing, along with the refracturing of the wellbore. The 

increased VOC emissions would occur during the flowback period 

following the refracturing operation. Therefore, the proposed 

standards for subcategory 1 and subcategory 2 wells would apply to 

completions at existing fractured or refractured wells.

10. Pg. 160 – Is the dataset EPA is using for the glycol dehydrators (from the original 1999 NESHAP)

is still representative of current emissions performance? If so, it would be helpful to explain that

here.

EPA RESPONSE: We believe the dataset is representative based on the broad range of sources in the 

dataset (i.e., different states, companies, BTEX varieties and types of controls used are represented). 

The technology has not changed significantly since these data were collected. The units considered in 

the development of the MACT floor are not subject to controls under the current MACT, so they were 

not required to have installed control devices since the data were collected. Further, the emissions 

profiles were considered without taking into account whether or not the unit was currently controlled.

11. Pg. 167-168 – The explanation of how EPA determined that the previous MACT floor was set

based on all storage vessels (by reviewing a document called “Recommendation of MACT Floor

Levels..”) seems out-of-place. It may be preferable to simply say that this is how the previous

MACT floor was set and cite the document as a reference. If possible, it would also be helpful to

say that agency confirmed this by looking at the original data.

RESPONSE IN PROGRESS
The comments reflect interagency review of the draft rule under EOs 12866 and 13563. They are

subject to further policy review.

Page 27 of 30

I. RIA

1. EPA has developed an inventory of compressors which breaks them out by type (i.e. reciprocating

and centrifugal) in Table 3-2 of the RIA, and uses that inventory to develop emissions savings

estimates for the new control measures. However, the fugitive emissions in the EPA national

emission inventory has a very high uncertainty, since they are mostly based on high level data

and outdated emission factors. Consequently, EPA included the oil and gas industry in the GHG

Mandatory Reporting Rule. Emission data, largely based on actual monitoring and/or detailed

facility level activity data will be reported to the EPA beginning in 2012. The new data may

significantly change the image of fugitive emissions from the natural gas industry. In the

absence of the Technical Support Document, the source of EPA data on compressors and their

breakdown by type is unclear. Therefore, some clarification (and possibly more information)

from EPA is required. Natural Gas Association of America (INGAA) maintains a database of

compressor units used in natural gas transmission service. The unit count would be more

accurate for a ratio of unit types instead of station. Compressor stations can and do have a mix

of compression units. So, it is thought that a better indication of the industry would be to use the

unit count. A publicly accessible file titled, “Impacts of National Standards to Control Emissions

of Hazardous Air Pollutants (HAPs) on Natural Gas Turbines and Compressor Engines” for

determining the compressor units, which was developed in 2003, is located

athttp://www.ingaa.org/File.aspx?id=154 . This paper indicates that the number of compressor

units is ~5,400 reciprocating units and 1,000 gas turbines units (ref: Section II.B BACKGROUND

ON INTERSTATE PIPELINE COMPRESSOR SYSTEMS on page 7).

EPA RESPONSE: The estimate of new reciprocating compressors was determined using data from the 

GHG inventory and data from industry. A summary of the estimates presented in the RIA is shown 

below.

Reciprocating Compressors

Well Pads 6,000

Gathering/Boosting Stations 210

Processing Plants 375

Transmission Compressor Stations 199

Underground Storage Facilities 9

Centrifugal Compressors

Processing Plants 16

Transmission Compressor Stations 14

The number of wellhead reciprocating compressors was estimated using data from industry comments 

on Subpart W. The 2010 U.S. Inventory reciprocating compressor activity data was not considered in the 

analysis because it does not distinguish between wellhead and gathering and boosting compressors. 

Using the Subpart W comment data from nine basins supplied by the El Paso Corporation, the average 

number of new wellhead compressors was calculated (315 new compressors/3,606 new wells). The 

average wellhead compressors per well was multiplied by the total well completions determined from 

the HPDI® database between 2007 and 2008 (68,000 new well completions) to get 6,000 new 

compressors for 2008.
The comments reflect interagency review of the draft rule under EOs 12866 and 13563. They are

subject to further policy review.

Page 28 of 30

The number of gathering & boosting reciprocating compressors was also estimated using data from 

industry comments on Subpart W. DCP Midstream stated on page 3 of its 2010 Subpart W comments 

that it operates 48 natural gas processing plants and treaters and 700 gathering system compressor 

stations. Using this data, there were an average of 14.583 gathering and boosting compressor stations 

per processing plant. The new gathering and boosting compressors was determined by taking the 

average difference between the number of processing plants for each year in the 2010 U.S Inventory, 

which references the total processing plants in the Oil and Gas Journal. This was done for each year up 

to 2008. An average was taken of only the years with an increase in processing plants, up to 2008. The 

resulting average was multiplied by the 14.583 ratio of gathering and boosting compressor stations to 

processing plants and the 1.5 gathering and boosting compressors per station yielding 210 new source 

gathering and boosting compressor stations.

The number of new reciprocating compressors at processing facilities was estimated by averaging the 

increase of reciprocating engines at processing plants in the GHG inventory data for 2007, 2008, and 

2009. The number of existing reciprocating compressors was 4,458, 4,781, and 4,876 for the Years 

2007, 2008, and 2009 respectively. This calculated to be 323 new reciprocating compressors between 

2007 and 2008, and 95 new reciprocating compressors between 2008and 2009. The average difference 

was calculated to be 209 reciprocating compressors and was used to estimate the number of new 

sources. Note that this value is different from the value that is presented in the RIA. An update of the 

2007 inventory data was received in June after the RIA had been completed, and was unable to be 

included in the draft version.

The number of new transmission and storage reciprocating compressors was estimated using the 

differences in the greenhouse gas inventory data for 2007, 2008, and 2009 and calculating an average of 

those differences. The number of existing reciprocating compressors at transmission stations was 7,158, 

7,028, and 7,197 for the Years 2007, 2008, and 2009 respectively. This calculated to be -130 new 

reciprocating compressors between 2007 and 2008, and 169 new reciprocating compressors between 

2008 and 2009. The average difference was calculated to be 20 reciprocating compressors and was 

used to estimate the number of new sources at transmission stations. The number of existing 

reciprocating compressors at storage stations was 1,144, 1,178, and 1,152 for the Years 2007, 2008, and 

2009 respectively. This calculated to be 34 new reciprocating compressors between 2007 and 2008, and 

-26 new reciprocating compressors between 2008 and 2009. The average difference was calculated to 

be 4 reciprocating compressors and was used to estimate the number of new sources at storage 

stations. Again please note that these values are different from the values that are presented in the RIA. 

An update of the 2007 inventory data was received in June after the RIA had been completed, and were 

unable to be included in the draft version.

The number of new centrifugal compressors in 2008 for the processing and transmission/storage 

segments was determined by taking the average difference between the centrifugal compressor activity 

data for each year in the 2008 U.S. Inventory . For example, the number of compressors in 1992 was 

subtracted from the number of compressors in 1993 to determine the number of new centrifugal 

compressors in 1993. This was done for each year up to 2008. An average was taken of only the years 

with an increase in centrifugal compressors, up to 2008, to determine the number of new centrifugal 

compressors in 2008. The result was 16 and 14 new centrifugal compressors in the processing and 

transmission segments respectively.
The comments reflect interagency review of the draft rule under EOs 12866 and 13563. They are

subject to further policy review.

Page 29 of 30

The reciprocating methane emission factors and the average number of cylinders used to estimate 

baseline emissions were obtained from the EPA/GRI report10 for each of the oil and gas industry 

segments. The centrifugal compressor methane emission factors were obtained from the 2009 

Greenhouse Gas inventory report and are based on the average of 48 different wet seal centrifugal 

compressors. The conversion of the methane volumetric emission rate to a mass emission rate was 

done using a methane conversion factor of 0.02082 tons of methane per 1000 standard cubic feet of 

methane (tons/100 scf). This conversion factor was developed assuming that methane is an ideal gas 

and using the ideal gas law to calculate the density. These emission factors are the same factors that 

are used in the Subpart W emission calculations for reciprocating and centrifugal compressors, and 

provide the best estimate of methane emissions from reciprocating and centrifugal compressors.

2. While some sense on the estimated burden cost of complying with the proposed NSPS and

NESHAP rules could be made from paragraphs 2 and 3, page 5-2 of the RIA, it would be helpful if

EPA could clarify exactly what they mean in that section of RIA. The text appears to be confusing

the way it is currently worded.

EPA RESPONSE: Based on the reviewer’s suggestion, we revised the paragraphs within the Paperwork 

Reduction Act write-up so the discussion would be clear for readers. The revised language for the 

relevant paragraphs (which appear in the RIA and Preamble) is included here:

Paperwork Reduction Act

The information collection requirements in this proposed action have been submitted for approval to 

OMB under the PRA, 44 U.S.C. 3501, et seq. The ICR document prepared by the EPA has been assigned 

EPA ICR Numbers 1716.07 (40 CFR part 60, subpart OOOO), 1788.10 (40 CFR part 63, subpart HH), 

1789.07 (40 CFR part 63, subpart HHH), and 1086.10 (40 CFR part 60, subparts KKK and subpart LLL).

The information to be collected for the proposed NSPS and the proposed NESHAP amendments are 

based on notification, recordkeeping, and reporting requirements in the NESHAP General Provisions (40 

CFR part 63, subpart A), which are mandatory for all operators subject to national emission standards. 

These recordkeeping and reporting requirements are specifically authorized by section 114 of the CAA 

(42 U.S.C. 7414). All information submitted to the EPA pursuant to the recordkeeping and reporting 

requirements for which a claim of confidentiality is made is safeguarded according to Agency policies set 

forth in 40 CFR part 2, subpart B.

These proposed rules would require maintenance inspections of the control devices, but would not 

require any notifications or reports beyond those required by the General Provisions. The recordkeeping 

requirements require only the specific information needed to determine compliance.

For sources subject to the proposed NSPS, the burden represents labor hours and costs associated from 

the annual reporting and recordkeeping for each affected operator owner of affected facilities. The 

estimated burden is based on the annual expected number of affected operators for the first three years 

following the effective date of the standards. The burden is estimated to be 560,000 labor hours at a 

cost of around$18 million per year. This includes the labor and cost estimates previously estimated for 

sources subject to 40 CFR part 60, subpart KKK and subpart LLL (which is being incorporated into 40 

CFR part 60, subpart OOOO). The average hours and cost per regulated entity, which is assumed to be 

on a per operator basis except for natural gas processing plants (which are estimated on a per facility 

 

10 U.S. Environmental Protection Agency and Gas Research Institute, Methane Emissions from the Natural Gas 

Industry, Volume 8: Equipment Leaks, June 1996. (EPA-600/R-96-080h)
The comments reflect interagency review of the draft rule under EOs 12866 and 13563. They are

subject to further policy review.

Page 30 of 30

basis) subject to the NSPS for oil and natural gas production and natural gas transmissions and 

distribution facilities would be 110 hours per response and $3,693 per response based on an average of 

1,459 operators responding per year with 16 responses per year. The majority of responses are 

expected to be notifications of construction. One annual report is required that may include all affected 

facilities owned per each operator. Burden for the proposed NSPS was based on EPA ICR Number 

1716.07.

The estimated recordkeeping and reporting burden after the effective date of the proposed 

amendments is estimated for all affected major and area sources subject to the oil and natural gas 

production NESHAP (40 CFR 63, subpart HH) to be approximately 63,000 labor hours per year at a cost 

of $2.1 million per year. For the natural gas transmission and storage NESHAP, the recordkeeping and 

reporting burden is estimated to be 2,500 labor hours per year at a cost of $86,800 per year. This 

estimate includes the cost of reporting, including reading instructions, and information gathering. 

Recordkeeping cost estimates include reading instructions, planning activities, and conducting 

compliance monitoring. The average hours and cost per regulated entity subject to the oil and natural 

gas production NESHAP would be 72 hours per year and $2,500 per year based on an average of 

846 facilities per year and three responses per facility. For the natural gas transmission and storage 

NESHAP, the average hours and cost per regulated entity would be 50 hours per year and $1,600 per 

year based on an average of 53 facilities per year and three responses per facility. Burden is defined at 

5 CFR 1320.3(b). Burden for the oil and natural gas production NESHAP is estimated under EPA ICR 

Number 1788.10. Burden for the natural gas transmission and storage NESHAP is estimated under EPA 

ICR Number 1789.07.