Petroleum and Natural Gas Systems

2012 Data Summary

Greenhouse Gas Reporting Program

Introduction

In October 2013, the U.S. Environmental Protection Agency (EPA) released 2012 greenhouse gas (GHG) 

data for Petroleum and Natural Gas Systems1 collected under the Greenhouse Gas Reporting Program 

(GHGRP). The GHGRP, which was required by Congress in the FY2008 Consolidated Appropriations 

Act, requires facilities to report data from large emission sources across a range of industry sectors, as 

well as suppliers of certain greenhouse gases and products that would emit GHGs if released or 

combusted.

The data show 2012 GHG emissions from over 2,000 facilities conducting Petroleum and Natural Gas 

Systems activities, such as production, processing, transmission, and distribution. In total, these facilities 

accounted for GHG emissions of 217 million metric tons of carbon dioxide equivalent (CO2e). This is an 

increase of 3% compared to 2011 GHG emissions from this sector.

The data represent a significant step forward in better understanding GHG emissions from Petroleum and 

Natural Gas Systems. The EPA is working to improve the quality of data from this sector and expects that 

the GHGRP will be an important tool for the Agency and the public to analyze emissions, identify 

opportunities for improving the data, and understand emissions trends.

When reviewing this data and comparing it to other data sets or published literature, it is important to 

understand the GHGRP reporting requirements and the impacts of these requirements on the reported 

data. Facilities used uniform methods prescribed by the EPA to calculate GHG emissions, such as direct 

measurement, engineering calculations, or emission factors derived from direct measurement. In some 

cases, facilities had a choice of calculation methods for an emission source. In order to provide facilities 

with time to adjust to the requirements of the GHGRP, the EPA made available the optional use of Best 

Available Monitoring Methods (BAMM) for unique or unusual circumstances. Where a facility used 

BAMM, it was required to follow emission calculations specified by the EPA, but was allowed to use 

alternative methods for determining inputs to calculate emissions. 

Petroleum and Natural Gas Systems is one of the more complex source categories within the GHGRP 

because of the number of emission sources covered, technical complexity, and variability across facilities.

It is expected that there can be differences in reported emissions from one facility to another. It is not 

uncommon for a handful of facilities to contribute the majority of the national reported emissions total for 

a specific emission source. As described in more detail below, there is a reporting threshold and the data 

does not cover certain emission sources, and therefore the data does not represent the entire universe of 

emissions from Petroleum and Natural Gas Systems. There is also variability in the methods used which 

could impact cross-segment, cross-source, or cross-facility comparisons. Emission changes may not 

solely be due to the change in the number of facilities, and could be the result of a number of factors. It is 

important to be aware of these limitations and differences when using this data, particularly when 

attempting to draw broad conclusions about emissions from this sector.

1 The implementing regulations of the Petroleum and Natural Gas Systems source category of the GHGRP are located at 40 CFR 

Part 98 Subpart W.

October 2013 1

 
Petroleum and Natural Gas Systems in the GHG Reporting Program

The Petroleum and Natural Gas Systems source category of the GHGRP requires reporting from the 

following eight industry segments, which account for most of the largest emission sources:

• Onshore Production: Production of petroleum and natural gas associated with onshore production 

wells and related equipment.

• Offshore Production: Production of petroleum and natural gas from offshore production 

platforms.

• Natural Gas Processing: Processing of field quality gas to produce pipeline quality natural gas.

• Natural Gas Transmission: Compressor stations used to transfer natural gas through transmission 

pipelines.

• Underground Natural Gas Storage: Facilities that store natural gas in underground formations.

• Natural Gas Distribution: Distribution systems that deliver natural gas to customers.

• Liquified Natural Gas (LNG) Import/Export: Liquified Natural Gas import and export terminals.

• LNG Storage: Liquified Natural Gas storage equipment.

The diagram below illustrates the segments of the Petroleum and Natural Gas Systems source category

that are required to report under the GHGRP. 

Other segments of the petroleum and natural gas industry are covered by the GHGRP, but not included in 

the Petroleum and Natural Gas Systems source category, such as: Petroleum Refineries (Subpart Y), 

Figure adapted from AGA and Natural Gas STAR

Production and Processing

1. Onshore Production

2a, 2b. Offshore Production

3. Gathering and Boosting (not 

covered by Subpart W)

4. Natural Gas Processing

Transmission and Storage

5. Natural Gas Transmission 

6. Underground Natural Gas 

Storage

7. LNG Storage

8. LNG Import-Export 

Distribution

9, 10. Natural Gas Distribution

Not Covered

• Emissions below 25,000 metric ton CO2e threshold

• Process emissions from gathering and boosting

• Vented emissions from hydraulic fracturing of oil wells

• Process emissions from transmission lines between 

compressor stations

October 2013 2
Petrochemical Production (Subpart X), Suppliers of Petroleum Products (Subpart MM), and Suppliers of 

Natural Gas and Natural Gas Liquids (Subpart NN).

The GHGRP also includes reporting of stationary fuel combustion emissions from facilities that are 

associated with the petroleum and natural gas industry, but that do not report process emissions from any 

of the above source categories, such as certain facilities that have a North American Industry 

Classification System (NAICS) code beginning with 211 (the general NAICS for oil and gas extraction). 

These facilities are referred to as “Other Oil and Gas Combustion” in this document.

The GHGRP covers a subset of national emissions from Petroleum and Natural Gas Systems. A facility in 

the Petroleum and Natural Gas Systems source category is required to submit annual reports if total 

emissions are 25,000 metric tons carbon dioxide equivalent (CO2e) or more. In addition, the Petroleum 

and Natural Gas Systems source category does not currently include process emissions from the gathering 

and boosting segment. It also does not include vented emissions from hydraulic fracturing of oil wells. In 

addition, the GHGRP does not cover process emissions from transmission lines between compressor 

stations. The petroleum and natural gas industry is growing and changing rapidly and there could be other 

sources of emissions that are not currently covered. The Agency will continue to review regulatory 

requirements to ensure the reporting of high quality data.

The EPA has a multi-step data verification process, including automatic checks during data-entry, 

statistical analyses on completed reports, and staff review of the reported data. Based on the results of the 

verification process, the EPA follows up with facilities to resolve mistakes that may have occurred. In 

addition, because of the nature of the petroleum and natural gas industry, there can be variation in 

emissions from facility to facility.

In order to provide facilities with time to adjust to the requirements of the GHGRP, the EPA made 

available the optional use of BAMM for unique or unusual circumstances. Where a facility used BAMM, 

it was required to follow emission calculations specified by the EPA, but was allowed to use alternative 

methods for determining inputs to calculate emissions. Inputs are the values used by facilities to calculate 

equation outputs. Examples of BAMM include monitoring methods used by the facility that do not meet 

the specifications of 40 CFR Part 98 Subpart W, supplier data, engineering calculations, and other 

company records. Facilities used BAMM in different ways and for different parameters depending on 

their unique or unusual circumstances.

In 2012, facilities were required to receive approval from the EPA prior to using BAMM for the 

Petroleum and Natural Gas Systems source category and these facilities were required to specify in their 

GHG annual reports when BAMM was used for an emission source. In 2012, 33% of facilities in the 

petroleum and natural gas source category reported using BAMM. The largest number of facilities in 

Petroleum and Natural Gas Systems was in the onshore production, natural gas transmission, and natural 

gas processing segments, and these three segments also represented the segments with the largest 

frequency of BAMM use. The onshore production segment had 44% of facilities reporting BAMM use, 

natural gas transmission had 46% of facilities reporting BAMM use, and natural gas processing had 53% 

of facilities reporting BAMM use. The remaining segments had a lower number of facilities and

proportionally lower BAMM use. Facilities in the other oil and gas combustion category were not 

permitted to use BAMM. For purposes of this document, facilities are recorded as using BAMM if they 

indicated the use of BAMM for any piece of equipment from any emission source. 

October 2013 3
Reported GHG Emissions from Petroleum and Natural Gas Systems

The following section provides information on reported GHG emissions by industry segment, by 

greenhouse gas, by combustion and process emissions, and by emission source for the 2012 calendar year. 

Reported Emissions by Industry Segment

The 2012 calendar year was the second year that GHG emissions from Petroleum and Natural Gas 

Systems activities were required to be collected. Annual reports were due to the EPA by April 1, 2013.

The EPA received reports from over 2,000 facilities2 with Petroleum and Natural Gas Systems activities, 

with total reported GHG emissions of 217 Million Metric Tons (MMT) CO2e.

The largest industry segment in terms of reported GHG emissions was onshore production, with a total of 

88 MMT CO2e, followed by natural gas processing, with reported emissions of 60 MMT CO2e. Other oil 

and gas combustion accounted for 24 MMT CO2e. The next largest segment was natural gas 

transmission, with reported emissions of 23 MMT CO2e. Reported emissions from natural gas 

distribution totaled 13 MMT CO2e. The remaining segments accounted for total reported emissions of 

less than 10 MMT CO2e.

2 In general, a “facility” for purposes of the GHGRP means all co-located emission sources that are commonly owned or 

operated. However, the GHGRP has developed specialized facility definitions for natural gas distribution and onshore 

production. For natural gas distribution, the “facility” is a local distribution company as regulated by a single state public utility

commission. For onshore production, the “facility” includes all emissions associated with wells owned or operated by a single

company in a specific hydrocarbon producing basin (as defined by the geologic provinces published by the American Association

of Petroleum Geologists).

21

17

212

210

219

381

153

32

250

184

102

278

0 100 200 300 400 500 600

Other Oil and Gas Combustion

LNG Storage

LNG Import/Export

Natural Gas Distribution

Underground Natural Gas Storage

Natural Gas Transmission

Natural Gas Processing

Offshore Production

Onshore Production

Facility Count

2012 BAMM Use

BAMM Used

No BAMM

October 2013 4

 
2012 Reported Emissions by Industry Segment

Segment Number of Facilities Reported Emissions

(Million Metric Tons CO2e)

Onshore Production 497 88

Offshore Production 106 7

Natural Gas Processing 394 60

Natural Gas Transmission 462 23

Underground Natural Gas Storage 49 1

Natural Gas Distribution 174 13

LNG Import/Export 8 1

LNG Storage 4 < 1

Other Oil and Gas Combustion 381 24

Total 2,058 217

Note: Total number of facilities is smaller than the sum of facilities from each segment because some facilities 

reported under multiple segments. A facility is included in the count of number of facilities if it reported non-zero 

emissions under any segment.

Reported Emissions by Greenhouse Gas

For all segments combined, carbon dioxide (CO2) emissions accounted for 147 MMT CO2e of reported 

emissions and methane (CH4) emissions accounted for 70 MMT CO2e of reported emissions. Emissions 

from onshore production were primarily methane while emissions from natural gas transmission and 

natural gas processing were primarily carbon dioxide. 

Reported Combustion and Process Emissions

Each segment of Petroleum and Natural Gas Systems has unique emission sources. Emissions may result 

from the combustion of fossil fuels or from process sources that result in the direct emission of GHGs. 

Reported combustion emissions in Petroleum and Natural Gas Systems totaled 111 MMT CO2e and 

reported process emissions totaled 106 MMT CO2e. The majority of combustion emissions were reported 

by natural gas processing, natural gas transmission, onshore production, and other oil and gas 

combustion. The majority of process emissions were reported by onshore production, natural gas 

processing, and natural gas distribution. 

24

19

56

5

40

13

4

4

48

0 20 40 60 80 100

Other Oil and Gas Combustion

LNG Storage

LNG Import/Export

Natural Gas Distribution

Underground Natural Gas Storage

Natural Gas Transmission

Natural Gas Processing

Offshore Production

Onshore Production

Emissions, MMT CO2e

2012 Reported Emissions by Greenhouse Gas

CO2 Emissions

CH4 Emissions

N2O Emissions

October 2013 5
Process emissions may be further classified as vented emissions, equipment leaks, and flaring. Vented 

emissions totaled 57 MMT CO2e, equipment leaks totaled 27 MMT CO2e, and flaring emissions totaled 

22 MMT CO2e. Vented emissions in onshore production were primarily methane while vented emissions 

in natural gas processing were primarily carbon dioxide. Equipment leak emissions were primarily 

methane and flaring emissions were primarily carbon dioxide.

Reported Process Emission Sources

The Petroleum and Natural Gas Systems source category (Subpart W) specifies the methods that facilities 

must use to calculate emissions from applicable sources. 

The top reported process emission source in Petroleum and Natural Gas Systems was pneumatic devices 

with reported emissions of 18.4 MMT CO2e. Natural gas pneumatic devices are automated flow control 

24

19

37

5

24

13

4

23

2

64

0 20 40 60 80 100

Other Oil and Gas Combustion

LNG Storage

LNG Import/Export

Natural Gas Distribution

Underground Natural Gas Storage

Natural Gas Transmission

Natural Gas Processing

Offshore Production

Onshore Production

Emissions, MMT CO2e

2012 Reported Combustion and Process Emissions

Combustion Emissions

Process Emissions

1

17

39

13

2

2

9

5

17

0 10 20 30 40 50 60 70

LNG Storage

LNG Import/Export

Natural Gas Distribution

Underground Natural Gas Storage

Natural Gas Transmission

Natural Gas Processing

Offshore Production

Onshore Production

Emissions, MMT CO2e

2012 Reported Process Emissions by Vented Emissions, 

Equipment Leaks, and Flaring

Vented Emissions

Equipment Leaks

Flaring

October 2013 6
devices powered by pressurized natural gas and used for maintaining a process condition such as liquid 

level, pressure, delta-pressure and temperature. Emissions from natural gas pneumatic devices are 

calculated by applying a facility determined population count to a default emission factor.

Acid gas removal units were the top reported contributor to CO2 emissions from non-combustion sources 

and the top reported source of process emissions in the natural gas processing segment (15.4 MMT

CO2e). Acid gas removal units are process units that separate hydrogen sulfide, carbon dioxide or both 

hydrogen sulfide and carbon dioxide from sour natural gas using absorbents or membrane separators. The 

CO2 emitted from acid gas removal units is a part of the gas stream that is produced at the wellhead. 

3

2

8

7

15

1

1

1

2

2

3

3

4

3

6

8

7

1

8

2

18

0 5 10 15 20

Enhanced Oil Recovery Pumps

Enhanced Oil Recovery Liquids

Transmission Tanks

Gas Well Compl. and Work. without HF

Well Testing

Distribution M-R Stations

Dehydrators

Offshore Sources

Blowdown Vent Stacks

Centrifugal Compressors

Pneumatic Pumps

Reciprocating Compressors

Distribution Services

Atmospheric Tanks

Liquids Unloading

Distribution Mains

Gas Well Compl. and Work. with HF

Other Flare Stacks

Misc Equipment Leaks

Associated Gas Venting and Flaring

Acid Gas Removal Units

Pneumatic Devices

Emissions, MMT CO2e

2012 Reported Process Emission Sources

CO2 Emissions

CH4 Emissions

N2O Emissions

October 2013 7
Natural gas processing creates pipeline quality natural gas and removal of CO2 from the gas streams is a 

key step in this process.

Associated gas and other flare stacks were the top reported sources of process emissions from flaring for 

Petroleum and Natural Gas Systems. Associated gas is natural gas that is produced out of petroleum 

wells, but due to proximity and pipeline limitations, may be vented or flared instead of being processed. 

The other flare stacks category is a catch-all category intended to cover all flares not otherwise reported in 

the onshore production and natural gas processing segments. For example, flaring for gas well 

completions and workovers with hydraulic fracturing would be reported under the gas well completions 

and workovers with hydraulic fracturing emission source rather than the other flare stacks emission 

source. The majority of emissions from other flare stacks were from natural gas processing and onshore 

production.

Reported GHG Emissions by Industry Segment and Source

The following section provides information on reported GHG emissions organized by industry segment. 

For each segment, the top reported emission sources are presented, as well as additional information on

emission sources for which stakeholders have expressed interest. Over time, we hope to provide 

additional information on other emission sources of interest to stakeholders.

Onshore Production

The EPA received annual reports from 497 facilities in the onshore production segment and reported 

emissions totaled 88.0 MMT CO2e. Methane emissions totaled 48.2 MMT CO2e and carbon dioxide 

emissions totaled 39.7 MMT CO2e. The top reported emission sources for onshore production were 

generally consistent with the top reported emission sources for Petroleum and Natural Gas Systems. 

Combustion equipment (24.3 MMT CO2e) and pneumatic devices (18.1 MMT CO2e) were the top 

reported emission sources, followed by associated gas venting and flaring (9.0 MMT CO2e), gas well 

completions and workovers with hydraulic fracturing (8.1 MMT CO2e), miscellaneous equipment leaks

(7.7 MMT CO2e), and liquids unloading (5.8 MMT CO2e).

4

3

2

7

24

3

3

6

8

7

2

18

0 5 10 15 20 25 30

Pneumatic Pumps

Other Flare Stacks

Atmospheric Tanks

Liquids Unloading

Misc Equipment Leaks

Gas Well Compl. and Work. with HF

Associated Gas Venting and Flaring

Pneumatic Devices

Combustion Equipment

Emissions, MMT CO2e

2012 Onshore Production: Top Reported Emission Sources

CO2 Emissions

CH4 Emissions

N2O Emissions

October 2013 8
The basins with the top reported emissions were the Gulf Coast Basin with 12.2 MMT CO2e, the Permian 

Basin with 9.3 MMT CO2e, the Williston Basin with 9.3 MMT CO2e, the San Juan Basin with 9.1 MMT 

CO2e, and the Anadarko Basin with 9.1 MMT CO2e.

Emission Source in Detail: Gas Well Completions and Workovers with Hydraulic Fracturing

The data reported to the GHGRP includes gas well completions and workovers with hydraulic fracturing. 

In the hydraulic fracturing process, a mixture of water, chemicals and a “proppant” (usually sand) is

pumped into a well at high pressures to fracture rock and allow natural gas to escape. During a stage of 

well completion known as “flowback,” fracturing fluids, water, and reservoir gas come to the surface at a 

high velocity and volume. Specialized equipment can be employed that separates natural gas from the 

backflow, known as a “Reduced Emission Completion” (REC) or “green completion”.

The GHGRP provides facilities options for calculating emissions for gas well completions and workovers

with hydraulic fracturing. Facilities may measure or estimate the backflow rate in order to report 

emissions using an engineering calculation. Alternatively, the backflow vent or flare volume may be 

measured directly.

The EPA received information on gas well completions and workovers with hydraulic fracturing from 

208 onshore production facilities. Of these facilities 85 reported using BAMM to calculate emissions. The 

total reported emissions for gas well completions and workovers with hydraulic fracturing were 8.1 MMT 

CO2e. Reported CO2 emissions were 1.5 MMT CO2e and reported CH4 emissions were 6.6 MMT CO2e.

Emissions were reported by GHG for flaring and venting activities. Facilities were also required to report 

the total count of completions and workovers. In addition, facilities provided a count of the number of 

completions or workovers employing purposely designed equipment that separates natural gas from the 

backflow (RECs). 

The table below shows reported activity data and emissions nationally for gas well completions and 

workovers with hydraulic fracturing. Data collected by the GHGRP also allows for county-level analysis 

of reported data. As noted earlier, when reviewing the data it is important to be aware of the GHGRP 

reporting requirements and the impacts of these requirements on the reported data. For example, the 

GHGRP covers a subset of national emissions and there is variability in the methods used in calculating 

emissions and use of BAMM.

2012 Reported Emissions from Gas Well Completions and Workovers with Hydraulic Fracturing

Activity

Total 

Number

Number 

of RECs

Reported 

Venting CO2

Emissions 

(MT CO2e)

Reported 

Venting CH4

Emissions 

(MT CO2e)

Reported 

Flaring CO2

Emissions 

(MT CO2e)

Reported 

Flaring CH4

Emissions 

(MT CO2e)

Total Reported 

Emissions

(MT CO2e)

Gas Well 

Completions 

with Hydraulic 

Fracturing

9,466 5,059 9,078 6,225,393 1,478,340 176,052 7,889,716

Gas Well 

Workovers with 

Hydraulic 

Fracturing

1,198 147 985 238,267 17,758 2,964 259,988

Total 10,664 5,206 10,063 6,463,659 1,496,098 179,016 8,149,704

October 2013 9
Emission Source in Detail: Liquids Unloading

In mature gas wells, the accumulation of fluids in the well can impede and sometimes halt gas production. 

Liquids unloading is the process by which liquids are removed from the well through venting, the use of 

plunger lift systems, or other remedial treatments. The liquids unloading source within the GHGRP

covers emissions from facilities that have wells that are venting or using plunger lifts. 

A total of 251 facilities reported emissions for well venting for liquids unloading in onshore production. 

Of these facilities 120 reported using BAMM to calculate emissions. Total reported emissions for liquids 

unloading were 5.8 MMT CO2e. A total of 0.04 MMT CO2e reported emissions were from carbon 

dioxide and 5.8 MMT CO2e were from methane.

Facilities were given the option between three methods for calculating emissions from liquids unloading. 

The first calculation method involved using a representative well sample to calculate emissions for both 

wells with and without plunger lifts. The second and third calculation methods provided engineering 

equations for wells with plunger lifts and without plunger lifts. The following table shows total activity 

count and reported emissions for the different calculation methods.

2012 Reported Emissions from Liquids Unloading

Calculation Method

Number of 

Wells Venting 

During Liquids 

Unloading

Number of 

Wells Equipped 

With Plunger 

Lifts

Reported 

CO2 Emissions 

(MT CO2e)

Reported 

CH4 Emissions 

(MT CO2e)

Total Reported 

Emissions 

(MT CO2e)

Method 1: Direct 

Measurement of 

Representative Well Sample

10,024 7,149 29,767 2,362,423 2,392,190

Method 2: Engineering 

Calculation for Wells without 

Plunger Lifts 

23,536 0 6,523 1,503,451 1,509,974

Method 3: Engineering 

Calculation for Wells with 

Plunger Lifts

25,103 25,103 6,400 1,938,071 1,944,471

Total 58,663 32,252 42,689 5,803,946 5,846,634

Offshore Production

The EPA received annual reports from 106 facilities in the offshore production segment and reported 

emissions totaled 6.5 MMT CO2e. Methane emissions totaled 1.3 MMT CO2e and carbon dioxide 

emissions totaled 5.2 MMT CO2e. For offshore production, facilities calculate process emissions using 

requirements that were established by the Bureau of Ocean Energy Management (BOEM). In addition, 

the GHGRP collects data on combustion emissions. The full list of process emission sources is extensive, 

but can generally be categorized into vented emissions, flaring and equipment leaks. The top reported

source of emissions for offshore production was from combustion (4.7 MMT CO2e), followed by venting

(0.9 MMT CO2e), flaring (0.5 MMT CO2e), and equipment leaks (0.4 MMT CO2e).

October 2013 10
Natural Gas Processing

The EPA received annual reports from 394 facilities in the natural gas processing segment and reported 

emissions totaled 60.1 MMT CO2e. Methane emissions totaled 3.5 MMT CO2e and carbon dioxide 

emissions totaled 56.3 MMT CO2e. The top reported emission sources were combustion equipment (36.7

MMT CO2e), acid gas removal units (15.3 MMT CO2e), and other flare stacks (4.4 MMT CO2e).

Emissions from the three top reported sources were primarily in the form of CO2. Emissions from 

compressors were the top reported source of methane emissions, but reported emissions from 

reciprocating compressors (1.2 MMT CO2e) and centrifugal compressors (0.8 MMT CO2e) were smaller 

than the three top reported sources from this segment.

Natural Gas Transmission

The EPA received annual reports from 462 facilities in the natural gas transmission segment and reported 

emissions totaled 33.0 MMT CO2e. Methane emissions totaled 3.7 MMT CO2e and carbon dioxide 

emissions totaled 19.2 MMT CO2e. Combustion emissions (19.2 MMT CO2e) were larger than process 

emissions. Following combustion equipment, the top reported emission sources were reciprocating 

compressors (1.6 MMT CO2e) and blowdown vent stacks (1.1 MMT CO2e).

5

1

0 1 2 3 4 5

Equipment Leaks

Flaring

Venting

Combustion

Emissions, MMT CO2e

2012 Offshore Production: Top Reported Emission Sources

CO2 Emissions

CH4 Emissions

N2O Emissions

4

15

37

0 5 10 15 20 25 30 35 40

Misc Equipment Leaks

Dehydrators

Centrifugal Compressors

Blowdown Vent Stacks

Reciprocating Compressors

Other Flare Stacks

Acid Gas Removal Units

Combustion Equipment

Emissions, MMT CO2e

2012 Natural Gas Processing: Top Reported Emission Sources

CO2 Emissions

CH4 Emissions

N2O Emissions

October 2013 11
Underground Natural Gas Storage

The EPA received annual reports from 49 facilities in the underground natural gas storage segment and 

reported emissions totaled 1.3 MMT CO2e. Methane emissions totaled 0.5 MMT CO2e and carbon 

dioxide emissions totaled 0.9 MMT CO2e. Combustion equipment (0.9 MMT CO2e) was the top reported

source of emissions for underground natural gas storage, followed by reciprocating compressors (0.2

MMT CO2e). 

Emission Source in Detail: Compressors

Compressors are used in the production, processing, transmission, and storage segments to keep pipelines 

at a high enough pressure so natural gas will continue flowing through the pipelines. The two primary 

types of compressors in use in the petroleum and natural gas industry are reciprocating compressors and 

centrifugal compressors.

Compressors are a large source of combustion emissions in Petroleum and Natural Gas Systems, and 

combustion emissions for Petroleum and Natural Gas Systems were presented earlier in this document. 

19

1

2

0 5 10 15 20 25

Transmission Tanks

Pneumatic Devices

Misc Equipment Leaks

Centrifugal Compressors

Blowdown Vent Stacks

Reciprocating Compressors

Combustion Equipment

Emissions, MMT CO2e

2012 Natural Gas Transmission: Top Reported Emission 

Sources

CO2 Emissions

CH4 Emissions

N2O Emissions

0.0 0.2 0.4 0.6 0.8 1.0

Misc Equipment Leaks

Pneumatic Devices

Centrifugal Compressors

Reciprocating Compressors

Combustion Equipment

Emissions, MMT CO2e

2012 Underground Natural Gas Storage: Top Reported 

Emission Sources

CO2 Emissions

CH4 Emissions

N2O Emissions

October 2013 12
Compressors can also be a source of process emissions. The primary source of process emissions from 

compressors are from leaks in rod packing (reciprocating compressors), emissions from wet or dry seals 

(centrifugal compressors), emissions from blowdown vents, and emissions from isolation valve leakage. 

The source of emissions may vary based on the mode of operation that the compressor is in. A 

compressor in operating mode may have different emissions from a compressor in a shutdown 

depressurized mode. Because the emissions are from seal leakage, even compressors of the same 

manufacture can have different emissions based on the quality of the compressor seals. Emissions can be 

mitigated through rigorous maintenance practices and leak surveys, routing emissions to a flare, or 

capturing emissions.

Total reported compressor emissions from all industry segments were 5.1 MMT CO2e. Reported carbon 

dioxide emissions were 0.2 MMT CO2e and reported methane emissions were 4.9 MMT CO2e. The 

calculation method varied by industry segment. Emissions from compressors in onshore production were 

calculated by using population counts multiplied by an emission factor and accounted for 0.9 MMT CO2e 

of reported emissions. Emissions from compressors in the other industry segment were calculated by the 

use of direct measurement.

The table below shows activity data and emissions for reciprocating compressors by industry segment 

(excluding onshore production which used population counts). The EPA received data from 4,493 

reciprocating compressors, including 2,149 reciprocating compressors in natural gas processing, 2,008 

reciprocating compressors in natural gas transmission, and 309 reciprocating compressors in underground 

natural gas storage. Of these reciprocating compressors, 1,854 reported using BAMM to calculate 

emissions, including 993 in natural gas processing, 790 in natural gas transmission, and 64 in 

underground natural gas storage. 

2012 Reported Process Emissions from Reciprocating Compressors

Industry Segment

Total Number of 

Reciprocating 

Compressors

Number of 

Reciprocating 

Compressors that 

used BAMM

Reported 

CO2

Emissions 

(MT CO2e)

Reported 

CH4

Emissions 

(MT CO2e)

Total Reported 

Process 

Emissions 

(MT CO2e)

Natural Gas 

Processing 2,149 993 107,777 1,009,045 1,117,065

Natural Gas 

Transmission 2,008 790 3,270 1,591,990 1,595,261

Underground Natural 

Gas Storage 309 64 290 160,809 161,192

LNG Import/Export 23 7 10.9 7477.7 7,950

LNG Storage 4 0 8.3 90.4 99

Total 4,493 1,854 111,356 2,769,412 2,881,568

The table below shows activity data and emissions for centrifugal compressors by industry segment. For 

centrifugal compressors the number of compressors with wet seals is also shown. Overall emissions from 

centrifugal compressors were lower than those for reciprocating compressors, but the total number of 

reported compressors was lower as well. The EPA received data from 1,203 centrifugal compressors, 

including 428 centrifugal compressors in natural gas processing, 724 centrifugal compressors in natural 

gas transmission, and 39 centrifugal compressors in underground natural gas storage. Of these centrifugal 

compressors, 547 reported using BAMM to calculate emissions, including 234 in natural gas processing, 

292 in natural gas transmission, and 12 in underground natural gas storage. 

October 2013 13
2012 Reported Process Emissions from Centrifugal Compressors

Industry 

Segment

Total Number 

of Centrifugal

Compressors

Number of 

Centrifugal

Compressors that 

used BAMM

Number of 

Centrifugal 

Compressors 

with Wet Seals

Reported 

CO2

Emissions 

(MT CO2e)

Reported 

CH4

Emissions 

(MT CO2e)

Total Reported 

Process 

Emissions

(MT CO2e)

Natural Gas 

Processing 428 234 274 13,775 752,054 766,100

Natural Gas 

Transmission 724 292 291 661 439,714 440,375

Underground 

Natural Gas 

Storage

39 12 23 166 118,500 118,666

LNG 

Import/Export 10 9 5 51 37031.9 37,083

LNG Storage 2 0 2 0 0 0

Total 1,203 547 595 14,653 1,347,300 1,362,224

Natural Gas Distribution

The EPA received annual reports from 174 facilities in the natural gas distribution segment and reported 

emissions totaled 13.0 MMT CO2e. Methane emissions totaled 12.7 MMT CO2e and carbon dioxide 

emissions totaled 0.3 MMT CO2e. For the natural gas distribution segment, combustion emissions (0.3 

MMT CO2e) were relatively lower compared to other industry segments. The primary sources of 

emission for natural gas distribution were distribution mains (7.9 MMT CO2e) and distribution services

(4.0 MMT CO2e), which are caused by natural gas equipment leaks and calculated by multiplying 

population counts by default emission factors that are specific to pipe material.

1

4

8

0 2 4 6 8 10

Misc Equipment Leaks

Combustion Equipment

Distribution Metering-Regulating ...

Distribution Services

Distribution Mains

Emissions, MMT CO2e

2012 Natural Gas Distribution: Top Reported Emission Sources

CO2 Emissions

CH4 Emissions

N2O Emissions

October 2013 14
LNG Import/Export

The EPA received emission reports from 8 LNG import/export terminals and reported emissions totaled 

0.6 MMT CO2e. Methane emissions totaled 0.1 MMT CO2e and carbon dioxide emissions totaled 0.5

MMT CO2e. The top reported source of emissions was combustion equipment (0.5 MMT CO2e), 

followed by centrifugal compressors (0.04 MMT CO2e), blowdown vent stacks (0.03 MMT CO2e), and 

reciprocating compressors (0.01 MMT CO2e).

LNG Storage

LNG storage had the fewest number of facilities of the industry segments that comprise Petroleum and 

Natural Gas Systems, with 4 facilities reporting. Total reported emissions from LNG storage were 0.02 

MMT CO2e. Equipment leaks (0.01 MMT CO2e) was the top reported source of emissions, followed by 

combustion equipment (0.01 MMT CO2e).

0.0 0.1 0.2 0.3 0.4 0.5 0.6

Misc Equipment Leaks

Reciprocating Compressors

Blowdown Vent Stacks

Centrifugal Compressors

Combustion Equipment

Emissions, MMT CO2e

2012 LNG Import/Export: Top Reported Emission Sources

CO2 Emissions

CH4 Emissions

N2O Emissions

0.00 0.01 0.02

Reciprocating Compressors

Combustion Equipment

Misc Equipment Leaks

Emissions, MMT CO2e

2012 LNG Storage: Top Reported Emission Sources

CO2 Emissions

CH4 Emissions

N2O Emissions

October 2013 15
Changes from 2011 to 2012

The following section describes changes between the reported data for the 2011 and 2012 calendar years 

for Petroleum and Natural Gas Systems. The EPA received resubmissions of 2011 data from certain 

facilities and the resubmitted 2011 data is reflected below.

Changes in Number of Facilities

In 2012, the number of facilities in Petroleum and Natural Gas Systems increased from 1,904 facilities to 

2,052 facilities. The largest increases occurred in onshore production (42), natural gas transmission (34), 

and natural gas processing (20).

The increased number of facilities is primarily a result of facilities triggering the 25,000 metric ton CO2e

reporting threshold. Emissions can be variable in the Petroleum and Natural Gas Systems sector and it is 

not unexpected that emissions for a facility may go above 25,000 metric tons CO2e in a given year. Once 

the reporting threshold is triggered, facilities must report to the GHGRP until emissions are below the 

threshold for a period of time specified in the regulations, or until all emission sources at a facility cease 

operation. As a result, the number of facilities reporting to the GHGRP may vary from year to year. 

Changes in Number of Facilities by Industry Segment: 2011 to 2012

Segment Number of Facilities

2011

Number of Facilities 

2012

Change in Number 

of Facilities

Onshore Production 455 497 42

Offshore Production 99 106 7

Natural Gas Processing 374 394 20

Natural Gas Transmission 428 462 34

Underground Natural Gas 

Storage 45 49 4

Natural Gas Distribution 173 174 1

LNG Import/Export 8 8 0

LNG Storage 4 4 0

Other Oil and Gas 

Combustion 338 381 43

Total 1,904 2,058 154

In addition to the increase in number of facilities, an increase was also seen in total reported emissions as 

discussed below. This does not necessarily indicate that total national emissions increased; rather it may 

indicate a larger percentage of total Petroleum and Natural Gas Systems emissions are covered by the 

GHGRP.

Changes in Reported Emissions

Total reported emissions increased by 7.1 MMT CO2e from 2011 to 2012. The largest increases occurred 

in onshore production (5.4 MMT CO2e), natural gas processing (1.9 MMT CO2e), and other oil and gas 

combustion (1.5 MMT CO2e). The largest decreases were seen in natural gas distribution (-0.9 MMT 

CO2e) and natural gas transmission (-0.8 MMT CO2e). The emission changes correspond to a reduction 

in reported methane emissions of 0.5 MMT CO2e and increase in reported carbon dioxide emissions of 

7.7 MMT CO2e.

October 2013 16
Changes in Reported Emissions by Industry Segment: 2011 to 2012

Segment

2011 Reported 

Emissions 

(MMT CO2e)

2012 Reported 

Emissions

(MMT CO2e)

Change in Reported 

Emissions

(MMT CO2e)

Onshore Production 83 88 5.4

Offshore Production 6 7 0.2

Natural Gas Processing 58 60 1.9

Natural Gas Transmission 24 23 -0.8

Underground Natural Gas 

Storage 1 1 -0.1

Natural Gas Distribution 14 13 -0.9

LNG Import/Export 1 1 -0.1

LNG Storage < 1 < 1 0.0

Other Oil and Gas 

Combustion 23 24 1.5

Total 210 217 7.1

Emission changes may not solely be due to the change in the number of facilities, and could be the result 

of a number of factors, such as operational changes (e.g. increased flaring), calculation method changes 

(e.g. reduced BAMM use or increased direct measurement), and changes in the regulatory landscape.

Changes in BAMM Use

There was a decrease in the number of facilities using BAMM between 2011 and 2012. The number of 

facilities reporting BAMM use decreased from 1,055 facilities in 2011 to 685 facilities in 2012, with 

reductions seen across Petroleum and Natural Gas Systems industry segments. 

Changes in BAMM Use by Industry Segment: 2011 to 2012

Segment 2011 BAMM Use 2012 BAMM Use Change in BAMM Use

Onshore Production 73% 44% -40%

Offshore Production 15% 4% -75%

Natural Gas Processing 84% 53% -37%

Natural Gas Transmission 71% 46% -35%

Underground Natural Gas 

Storage 56% 35% -38%

Natural Gas Distribution 36% 12% -66%

LNG Import/Export 50% 25% -50%

LNG Storage 75% 25% -67%

Other Oil and Gas 

Combustion 0% 0% 0%

Total 55% 33% -40%

October 2013 17
Changes in Reported Emissions by Emission Source

The increase in emissions between 2011 and 2012 is not attributable to any individual emission source. 

Several sources saw increased emissions, including combustion equipment (2.7 MMT CO2e), other flare 

stacks (2.3 MMT CO2e), atmospheric tanks (1.4 MMT CO2e), and associated gas venting and flaring (1.2 

MMT CO2e). The sources with the largest changes occurred in the onshore production segment. 

Changes in Reported Emissions by Emission Source: 2011 to 2012

Emission Source

2011 Reported 

Emissions

(MMT CO2e)

2012 Reported 

Emissions

(MMT CO2e)

Changes in 

Reported Emissions

(MMT CO2e)

Combustion Equipment 108.4 111.1 2.7

Pneumatic Devices 17.9 18.4 0.5

Acid Gas Removal Units 15.9 15.4 -0.5

Associated Gas Venting and Flaring 7.8 9.0 1.2

Misc Equipment Leaks 9.0 8.4 -0.6

Other Flare Stacks 6.0 8.4 2.3

Gas Well Completions and Workovers

with Hydraulic Fracturing 7.2 8.1 0.9

Distribution Mains 8.6 7.9 -0.6

Liquids Unloading 6.2 5.8 -0.4

Atmospheric Tanks 3.8 5.2 1.4

Distribution Services 4.4 4.0 -0.3

Reciprocating Compressors 2.3 3.1 -0.1

Pneumatic Pumps 2.5 2.9 0.4

Centrifugal Compressors 1.8 2.1 0.3

Blowdown Vent Stacks 1.3 2.0 0.7

Offshore Sources 1.9 1.8 -0.1

Dehydrators 1.7 1.6 -0.1

Distribution Meter-Regulating Stations 0.7 0.8 0.1

Well Testing 0.7 0.6 -0.1

Gas Well Completions and Workovers 

without Hydraulic Fracturing 0.7 0.1 -0.6

Transmission Tanks 0.1 0.1 0.0

Enhanced Oil Recovery Liquids <0.1 <0.1 0.0

Enhanced Oil Recovery Pumps <0.1 <0.1 0.0

Total 209.9 217.0 7.1

Additional Information

Access GHGRP data: http://www.epa.gov/ghgreporting/

Additional information about Petroleum and Natural Gas Systems in the GHGRP, including reporting 

requirements and calculation methods: http://www.epa.gov/ghgreporting/reporters/subpart/w.html. 

Data shown in this document reflect the most recent report submissions from facilities as of September 1, 

2013.

October 2013 18