A-27

ANNEX 2 Methodology and Data for Estimating CO2 

Emissions from Fossil Fuel Combustion 

2.1. Methodology for Estimating Emissions of CO2 from Fossil Fuel Combustion

Carbon dioxide (CO2) emissions from fossil fuel combustion were estimated using a “bottom-up” methodology 

characterized by seven steps. These steps are described below.

Step 1: Determine Total Fuel Consumption by Fuel Type and Sector

The bottom-up methodology used by the United States for estimating CO2 emissions from fossil fuel combustion 

is conceptually similar to the approach recommended by the Intergovernmental Panel on Climate Change (IPCC) for 

countries that intend to develop detailed, sectoral-based emission estimates in line with a Tier 2 method in the 2006 IPCC 

Guidelines for National Greenhouse Gas Inventories (IPCC 2006). Total consumption data and adjustments to 

consumption are presented in Columns 2 through 13 of Table A- 10.

Adjusted consumption data are presented in Columns 2 through 8 of Table A- 11 through Table A- 33 with totals 

by fuel type in Column 8 and totals by end-use sector in the last rows. Fuel consumption data for the bottom-up approach 

were obtained directly from the Energy Information Administration (EIA) of the U.S. Department of Energy. These data 

were first gathered in physical units, and then converted to their energy equivalents (see the Constants, Units, and 

Conversions Annex). The EIA data were collected through a variety of consumption surveys at the point of delivery or 

use and qualified with survey data on fuel production, imports, exports, and stock changes. Individual data elements were 

supplied by a variety of sources within EIA. Most information was taken from published reports, although some data were 

drawn from unpublished energy studies and databases maintained by EIA.

Energy consumption data were aggregated by sector (i.e., residential, commercial, industrial, transportation, 

electricity generation, and U.S. territories), primary fuel type (e.g., coal, natural gas, and petroleum), and secondary fuel 

type (e.g., motor gasoline, distillate fuel, etc.). The 2012 total adjusted energy consumption across all sectors, including

territories, and energy types was 71,607.7 trillion British thermal units (TBtu), as indicated in the last entry of Column 13 

in Table A- 10. This total excludes fuel used for non-energy purposes and fuel consumed as international bunkers, both of 

which were deducted in earlier steps.

Electricity consumption information was allocated to each sector based on EIA’s distribution of electricity retail 

sales to ultimate customers (i.e., residential, commercial, industrial, and other). Because the “other” fuel use includes sales 

to both the commercial and transportation sectors, EIA’s limited transportation electricity use data were subtracted from 

“other” electricity use and also reported separately. This total was consequently combined with the commercial electricity 

data. Further information on these electricity end uses is described in EIA’s Annual Energy Review (EIA 2012). 

There are also three basic differences between the consumption data presented in Table A- 10 through Table A33 and those recommended in the IPCC emission inventory methodology.

First, consumption data in the U.S. Inventory are presented using higher heating values (HHV)1rather than the 

lower heating values (LHV)2reflected in the IPCC emission inventory methodology. This convention is followed because 

data obtained from EIA are based on HHV. Of note, however, is that EIA renewable energy statistics are often published 

using LHV. The difference between the two conventions relates to the treatment of the heat energy that is consumed in the 

process of evaporating the water contained in the fuel. The simplified convention used by the International Energy 

Agency for converting from HHV to LHV is to multiply the energy content by 0.95 for petroleum and coal and by 0.9 for 

natural gas. 

 

1 Also referred to as Gross Calorific Values (GCV).

2 Also referred to as Net Calorific Values (NCV).
A-28 Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2012

Second, while EIA's energy use data for the United States includes only the 50 U.S. states and the District of 

Columbia, the data reported to the UNFCCC are to include energy consumption within U.S. territories. Therefore, 

consumption estimates for U.S. territories3 were added to domestic consumption of fossil fuels. Energy consumption data 

from U.S. territories are presented in Column 7 of Table A- 10 through Table A- 33. It is reported separately from 

domestic sectoral consumption, because it is collected separately by EIA with no sectoral disaggregation. 

Third, there were a number of modifications made in this report that may cause consumption information herein 

to differ from figures given in the cited literature. These are (1) the reallocation of select amounts of coking coal, 

petroleum coke, natural gas, residual fuel oil, and other oil (>401 F) for processes accounted for in the Industrial Processes 

chapter, (2) corrections for synthetic natural gas production, (3) subtraction of other fuels used for non-energy purposes, 

and (4) subtraction of international bunker fuels. These adjustments are described in the following steps.

Step 2: Subtract uses accounted for in the Industrial Processes chapter.

Portions of the fuel consumption data for seven fuel categories—coking coal, distillate fuel, industrial other coal, 

petroleum coke, natural gas, residual fuel oil, and other oil (>401 F)—were reallocated to the Industrial Processes chapter, 

as these portions were consumed as raw materials during non-energy related industrial processes. Emissions from these 

fuels used as raw materials are presented in the Industrial Processes chapter, and are removed from the energy and nonenergy consumption estimates within the Energy chapter. 

 Coking coal is used as a raw material (specifically as a reducing agent) in the blast furnace process to 

produce iron and steel, lead, and zinc and therefore is not used as a fuel for this process. 

 Similarly, petroleum coke is used in multiple processes as a raw material, and is thus not used as a fuel in 

those applications. The processes in which petroleum coke is used include (1) ferroalloy production, (2) 

aluminum production (for the production of C anodes and cathodes), (3) titanium dioxide production (in the 

chloride process), (4) ammonia production, and (5) silicon carbide.

 Natural gas consumption is used for the production of ammonia, and blast furnace and coke oven gas used in 

iron and steel production.

 Residual fuel oil and other oil (>401F) are both used in the production of C black. 

 Natural gas, distillate fuel, coal, and metallurgical coke are used to produce pig iron through the reduction of 

iron ore in the production of iron and steel.

Step 3: Adjust for Conversion of Fossil Fuels and Exports

First, a portion of industrial “other” coal that is accounted for in EIA coal combustion statistics is actually used to 

make “synthetic natural gas” via coal gasification at the Dakota Gasification Plant, a synthetic natural gas plant. The plant 

produces synthetic natural gas and by-product CO2. The synthetic natural gas enters the natural gas distribution system. 

Since October 2000, a portion of the CO2 produced by the coal gasification plant has been exported to Canada by pipeline. 

The remainder of the CO2 by-product from the plant is released to the atmosphere. The energy in this synthetic natural gas 

enters the natural gas distribution stream, and is accounted for in EIA natural gas combustion statistics. Because this 

energy of the synthetic natural gas is already accounted for as natural gas combustion, this amount of energy is deducted 

from the industrial coal consumption statistics to avoid double counting. The exported CO2 is not emitted to the 

atmosphere in the United States, and therefore the energy used to produce this amount of CO2 is subtracted from industrial 

other coal.

Step 4: Adjust Sectoral Allocation of Distillate Fuel Oil and Motor Gasoline

EPA conducted a separate bottom-up analysis of transportation fuel consumption based on data from the Federal 

Highway Administration (FHWA). The FHWA data indicated that the amount of distillate and motor gasoline 

consumption allocated to the transportation sector in the EIA statistics should be adjusted. Therefore, for the estimates

presented in the U.S. Inventory, the transportation sector’s distillate fuel and motor gasoline consumption was adjusted 

upward to match the value obtained from the bottom-up analysis. As the total distillate and motor gasoline consumption 

 

3 Fuel consumption by U.S. territories (i.e., American Samoa, Guam, Puerto Rico, U.S. Virgin Islands, Wake Island, and other U.S. 

Pacific Islands) is included in this report
A-29

estimate from EIA are considered to be accurate at the national level, the distillate and motor gasoline consumption totals 

for the residential, commercial, and industrial sectors were adjusted downward proportionately. 

Step 5: Subtract Consumption for Non-Energy Use 

U.S. aggregate energy statistics include consumption of fossil fuels for non-energy purposes. Depending on the 

end-use, non-energy uses of fossil fuels can result in long term storage of some or all of the C contained in the fuel. For 

example, asphalt made from petroleum can sequester up to 100 percent of the C contained in the petroleum feedstock for 

extended periods of time. Other non-energy fossil fuel products, such as lubricants or plastics also store C, but can lose or 

emit some of this C when they are used and/or burned as waste. As the emission pathways of C used for non-energy 

purposes are vastly different than fuel combustion, these emissions are estimated separately in the Carbon Emitted in 

Products from Non-Energy Uses of Fossil Fuels section in this chapter. Therefore, the amount of fuels used for nonenergy purposes, shown in Table A-34, was subtracted from total fuel consumption. 

Step 6: Subtract Consumption of International Bunker Fuels

Emissions from international transport activities, or international bunker fuel consumption, are not included in 

national totals and instead reported separately, as required by the IPCC (IPCC/UNEP/OECD/IEA 1997) and UNFCCC 

inventory reporting guidelines (UNFCCC, 2006). EIA energy statistics, however, include these bunker fuelsjet fuel for 

aircraft, and distillate fuel oil and residual fuel oil for marine shippingas part of fuel consumption by the transportation 

end-use sector. Therefore, the amount of consumption for international bunker fuels was estimated and subtracted from 

total fuel consumption (see Table A-35). Emissions from international bunker fuels have been estimated separately and 

not included in national totals.4 

Step 7: Determine the C Content of All Fuels

The C content of combusted fossil fuels was estimated by multiplying adjusted energy consumption (Columns 2 

through 8 of Table A- 11 through Table A- 33) by fuel-specific C content coefficients (see Table A- 36 and Table A- 37) 

that reflect the amount of C per unit of energy in each fuel. The C content coefficients used in the U.S. inventory were 

derived by EIA from detailed fuel information and are similar to the C content coefficients contained in the IPCC's default 

methodology (IPCC/UNEP/OECD/IEA 1997), with modifications reflecting fuel qualities specific to the United States.

Step 8: Estimate CO2 Emissions

Actual CO2 emissions in the United States were summarized by major fuel (i.e., coal, petroleum, natural gas, 

geothermal) and consuming sector (i.e., residential, commercial, industrial, transportation, electricity generation, and U.S. 

territories). Emission estimates are expressed in teragrams of carbon dioxide equivalents (Tg CO2 Eq.). To convert from 

C content to CO2 emissions, the fraction of C that is oxidized was applied. This fraction was 100 percent based on 

guidance in IPCC (2006). 

To determine total emissions by final end-use sector, emissions from electricity generation were distributed to 

each end-use sector according to its share of aggregate electricity consumption (see Table A-38). This pro-rated approach 

to allocating emissions from electricity generation may overestimate or underestimate emissions for particular sectors due 

to differences in the average C content of fuel mixes burned to generate electricity.

To provide a more detailed accounting of emissions from transportation, fuel consumption data by vehicle type 

and transportation mode were used to allocate emissions by fuel type calculated for the transportation end-use sector. 

Additional information on the allocation is available in Annex 3.2.

[BEGIN BOX]

Box 1. Uses of Greenhouse Gas Reporting Program Data in Reporting Emissions from Industrial Sector Fossil Fuel 

Combustion

 

4 Refer to the International Bunker Fuels section of the Energy chapter and Annex 3.3 for a description of the methodology for 

distinguishing between international and domestic fuel consumption.
A-30 Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2012

As described in the calculation methodology, total fossil fuel consumption for each year is based on aggregated 

end-use sector consumption published by the EIA. The availability of facility-level combustion emissions through EPA’s 

Greenhouse Gas Reporting Program (GHGRP) has provided an opportunity to better characterize the industrial sector’s 

energy consumption and emissions in the United States, through a disaggregation of EIA’s industrial sector fuel 

consumption data from select industries. 

For EPA’s GHGRP 2010, 2011, and 2012 reporting years, facility-level fossil fuel combustion emissions 

reported through the GHGRP were categorized and distributed to specific industry types by utilizing facility-reported 

NAICS codes (as published by the U.S. Census Bureau), and associated data available from EIA’s 2010 Manufacturing 

Energy Consumption Survey (MECS). As noted previously in this report, the definitions and provisions for reporting fuel 

types in EPA’s GHGRP include some differences from the inventory’s use of EIA national fuel statistics to meet the 

UNFCCC reporting guidelines. The IPCC has provided guidance on aligning facility-level reported fuels and fuel types 

published in national energy statistics, which guided this exercise.5

This year’s effort represents an attempt to align, reconcile, and coordinate the facility-level reporting of fossil 

fuel combustion emissions under EPA’s GHGRP with the national-level approach presented in this report. Consistent 

with recommendations for reporting the inventory to the UNFCCC, progress was made on certain fuel types for specific 

industries and has been included in the Common Reporting Format (CRF) tables that are submitted to the UNFCCC along 

with this report.6 However, a full mapping was not completed this year due to fuel category differences between national 

statistics published by EIA and facility-level reported GHGRP data. Furthermore, given that calendar year 2010 was the 

first year in which emissions data were reported to EPA’s GHGRP, the current inventory’s examination only focused on 

2010, 2011and, 2012. For the current exercise, the efforts in reconciling fuels focused on standard, common fuel types 

(e.g., natural gas, distillate fuel oil, etc.) where the fuels in EIA’s national statistics aligned well with facility-level 

GHGRP data. For these reasons, the current information presented in the CRF tables should be viewed as an initial attempt 

at this exercise. Additional efforts will be made for future inventory reports to improve the mapping of fuel types, and 

examine ways to reconcile and coordinate any differences between facility-level data and national statistics. Additionally, 

in order to expand this effort through the full time series presented in this report, further analyses will be conducted linking 

GHGRP facility-level reporting with the information published by EIA in its MECS data, other available MECS survey 

years , and any further informative sources of data. It is believed that the current analysis has led to improvements in the 

presentation of data in the Inventory, but further work will be conducted, and future improvements will be realized in 

subsequent Inventory reports.

Additionally, to assist in the disaggregation of industrial fuel consumption, EIA will now synthesize energy 

consumption data using the same procedure as is used for the last historical (benchmark) year of the Annual Energy 

Outlook (AEO). This procedure reorganizes the most recent data from the Manufacturing Energy Consumption Survey 

(MECS) (conducted every four years) into the nominal data submission year using the same energy-economy integrated 

model used to produce the AEO projections, the National Energy Modeling System (NEMS). EIA believes this 

“nowcasting” technique provides an appropriate estimate of energy consumption for the CRF.

To address gaps in the time series, EIA performs a NEMS model projection, using the MECS baseline sub-sector 

energy consumption. The NEMS model accounts for changes in factors that influence industrial sector energy 

consumption, and has access to data which may be more recent than MECS, such as industrial sub-sector macro industrial 

output (i.e., shipments) and fuel prices. By evaluating the impact of these factors on industrial subsector energy 

consumption, NEMS can anticipate changes to the energy shares occurring post-MECS and can provide a way to 

appropriately disaggregate the energy-related emissions data into the CRF.

While the fuel consumption values for the various manufacturing sub-sectors are not directly surveyed for all 

years, they represent EIA’s best estimate of historical consumption values for non-MECS years. Moreover, as an integral 

part of each AEO publication, this synthetic data series is likely to be maintained consistent with all available EIA and 

non-EIA data sources even as the underlying data sources evolve for both manufacturing and non-manufacturing 

industries alike.

 

5 See Section 4 “Use of Facility-Level Data in Good Practice National Greenhouse Gas Inventories” of the IPCC 

meeting report, and specifically the section on using facility-level data in conjunction with energy data, at <http://www.ipccnggip.iges.or.jp/meeting/pdfiles/1008_Model_and_Facility_Level_Data_Report.pdf>.

6 See < http://www.epa.gov/climatechange/ghgemissions/usinventoryreport.html>.
A-31

Other sectors’ fuel consumption (commercial, residential, transportation) will be benchmarked with the latest 

aggregate values from the Monthly Energy Review.7 EIA will work with the U.S. Environmental Protection Agency to 

back cast these values to 1990.

[END BOX]

 

7 http://www.eia.gov/totalenergy/data/monthly/.
A-32 Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2012

Table A-10: 2012 Energy Consumption Data by Fuel Type (TBtu) and Adjusted Energy Consumption Data

1 2 3 4 5 6 7 8 9 10 11 12 13

Total Consumption (TBtu)a Adjustments (TBtu)b

Fuel Type Res. Comm. Ind. Trans. Elec. Terr. Total

Unadjusted NEU Consumption

Total Adjusted 

Consumption

Bunker 

Fuel Ind. Trans. Terr.

Total Coal NE 43.6 917.4 NE 15,821.2 36.9 16,819.0 132.7 16,686.3 

Residential Coal NE

Commercial Coal 43.6 43.6 43.6 

Industrial Coking Coal 122.4 122.4 122.4 

Industrial Other Coal 795.0 795.0 10.3 784.7 

Transportation Coal NE NE

Electric Power Coal 15,821.2 15,821.2 15,821.2 

U.S. Territory Coal (bit) 36.9 36.9 36.9 

Natural Gas 4,241.5 2,960.0 8,512.5 777.2 9,286.8 27.1 25,805.0 311.8 25,493.2 

Total Petroleum 949.7 516.7 7,699.2 25,150.9 219.2 738.1 35,273.8 1,467.4 4,184.6 123.2 123.6 29,375.0 

Asphalt & Road Oil 826.7 826.7 826.7 

Aviation Gasoline 25.1 25.1 25.1 

Distillate Fuel Oil 438.9 323.2 1,154.3 5,978.3 52.9 132.9 8,080.5 91.7 17.5 7,971.4 

Jet Fuel 2,901.4 NA 56.4 2,957.8 916.3 2,041.5 

Kerosene 7.7 1.2 2.0 7.2 18.2 18.2 

LPG 503.1 145.5 2,229.4 33.7 11.9 2,923.7 2,003.9 919.8 

Lubricants 130.5 123.2 1.0 254.8 130.5 123.2 1.0 

Motor Gasoline 15.0 86.9 15,418.6 242.3 15,762.8 15,762.8 

Residual Fuel 31.4 7.0 670.5 76.7 163.8 949.4 459.5 490.0 

Other Petroleum

AvGas Blend Components (0.0) (0.0) (0.0)

Crude Oil

MoGas Blend Components

Misc. Products 161.6 122.6 284.2 161.6 122.6 

Naphtha (<401 deg. F) 453.9 453.9 453.9 

Other Oil (>401 deg. F) 287.2 287.2 287.2 

Pentanes Plus 84.4 84.4 45.9 38.5 

Petroleum Coke 0.4 704.3 89.6 794.3 66.3 728.0 

Still Gas 1,480.8 1,480.8 161.1 1,319.8 

Special Naphtha 14.7 14.7 14.7 

Unfinished Oils 60.1 60.1 60.1 

Waxes 15.3 15.3 15.3 

Geothermal 53.1 53.1 53.1 

TOTAL (All Fuels) 5,191.3 3,520.2 17,129.0 25,928.1 25,380.3 802.1 77,951.0 1,467.4 4,629.1 123.2 123.6 71,607.7 

a Expressed as gross calorific values (i.e., higher heating values). 

b Adjustments are subtracted from total consumption estimates and include biofuels, conversion of fossil fuels, non-energy use (see Table A-34), and international bunker fuel consumption (see Table A-35).

NE (Not Estimated)

NA (Not Available)
A-33

Table A-11: 2012 Energy Consumption Data and CO2 Emissions from Fossil Fuel Combustion by Fuel Type

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15

Adjusted Consumption (TBtu)a Emissionsb (Tg CO2 Eq.) from Energy Use

Fuel Type Res. Comm. Ind. Trans. Elec. Terr. Total Res. Comm. Ind. Trans. Elec. Terr. Total

Total Coal NE 43.6 784.7 NE 15,821.2 36.9 16,686.3 NE 4.1 74.3 NE 1,511.2 3.4 1,593.0 

Residential Coal NE NE

Commercial Coal 43.6 43.6 4.1 4.1 

Industrial Other Coal 784.7 784.7 74.3 74.3 

Transportation Coal NE NE NE

Electric Power Coal 15,821.2 15,821.2 1,511.2 1,511.2 

U.S. Territory Coal (bit) 36.9 36.9 3.4 3.4 

Natural Gas 4,241.5 2,960.0 8,200.7 777.2 9,286.8 27.1 25,493.2 224.8 156.9 434.7 41.2 492.2 1.4 1,351.2 

Total Petroleum 949.7 516.7 3,514.6 23,560.3 219.2 614.4 29,375.0 64.1 36.4 265.2 1,698.3 18.8 44.7 2,127.6 

Asphalt & Road Oil

Aviation Gasoline 25.1 25.1 1.7 1.7 

Distillate Fuel Oil 438.9 323.2 1,136.8 5,886.7 52.9 132.9 7,971.4 32.5 23.9 84.1 435.4 3.9 9.8 589.5 

Jet Fuel 1,985.2 NA 56.4 2,041.5 143.4 4.1 147.4 

Kerosene 7.7 1.2 2.0 7.2 18.2 0.6 0.1 0.1 0.5 1.3 

LPG 503.1 145.5 225.5 33.7 11.9 919.8 31.0 9.0 13.9 2.1 0.7 56.8 

Lubricants

Motor Gasoline 15.0 86.9 15,418.6 242.3 15,762.8 1.1 6.2 1,099.9 17.3 1,124.5 

Residual Fuel 31.4 7.0 211.1 76.7 163.8 490.0 2.4 0.5 15.8 5.8 12.3 36.8 

Other Petroleum

AvGas Blend Components (0.0) (0.0) (0.0) (0.0)

Crude Oil

MoGas Blend Components

Misc. Products

Naphtha (<401 deg. F)

Other Oil (>401 deg. F)

Pentanes Plus 38.5 38.5 2.7 2.7 

Petroleum Coke 0.4 638.0 89.6 728.0 (0.0) 65.1 9.1 74.3 

Still Gas 1,319.8 1,319.8 88.0 88.0 

Special Naphtha

Unfinished Oils 60.1 60.1 4.5 4.5 

Waxes

Geothermal 53.1 53.1 0.4 0.4 

TOTAL (All Fuels) 5,191.3 3,520.2 12,499.9 24,337.5 25,380.3 678.4 71,607.7 288.9 197.4 774.2 1,739.5 2,022.7 49.6 5,072.3 

a Expressed as gross calorific values (i.e., higher heating values). 

b Adjustments are subtracted from total consumption estimates and include biofuels, conversion of fossil fuels, non-energy use (see Table A-34), and international bunker fuel consumption (see Table A-35).

NE (Not Estimated)

NA (Not Available)
A-34 Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2012

Table A-12: 2011 Energy Consumption Data and CO2 Emissions from Fossil Fuel Combustion by Fuel Type

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15

Adjusted Consumption (TBtu)a Emissionsb (Tg CO2 Eq.) from Energy Use

Fuel Type Res. Comm. Ind. Trans. Elec. Terr. Total Res. Comm. Ind. Trans. Elec. Terr. Total

Total Coal NE 61.7 866.1 NE 18,035.2 36.9 18,999.9 NE 5.8 82.0 NE 1,722.7 3.4 1,813.9 

Residential Coal NE NE

Commercial Coal 61.7 61.7 5.8 5.8 

Industrial Other Coal 866.1 866.1 82.0 82.0 

Transportation Coal NE NE NE

Electric Power Coal 18,035.2 18,035.2 1,722.7 1,722.7 

U.S. Territory Coal (bit) 36.9 36.9 3.4 3.4 

Natural Gas 4,804.6 3,216.1 7,873.4 733.5 7,712.2 27.1 24,366.9 254.7 170.5 417.3 38.9 408.8 1.4 1,291.5 

Total Petroleum 1,031.8 635.1 3,583.1 23,706.1 303.0 614.4 29,873.5 70.3 45.2 269.4 1,709.0 26.6 44.7 2,165.3 

Asphalt & Road Oil

Aviation Gasoline 27.1 27.1 1.9 1.9 

Distillate Fuel Oil 521.9 414.2 1,213.2 5,899.3 64.2 132.9 8,245.7 38.6 30.6 89.7 436.3 4.7 9.8 609.8 

Jet Fuel 2,029.9 NA 56.4 2,086.3 146.6 4.1 150.7 

Kerosene 18.5 3.2 3.6 7.2 32.5 1.4 0.2 0.3 0.5 2.4 

LPG 491.3 142.1 176.5 32.9 11.9 854.8 30.3 8.8 10.9 2.0 0.7 52.8 

Lubricants

Motor Gasoline 21.6 125.0 15,459.0 242.2 15,847.8 1.5 8.9 1,102.8 17.3 1,130.6 

Residual Fuel 53.7 72.1 258.0 93.1 163.8 640.6 4.0 5.4 19.4 7.0 12.3 48.1 

Other Petroleum

AvGas Blend Components 0.0 0.0 0.0 0.0 

Crude Oil

MoGas Blend Components

Misc. Products

Naphtha (<401 deg. F)

Other Oil (>401 deg. F)

Pentanes Plus 27.3 27.3 1.9 1.9 

Petroleum Coke 0.2 585.9 145.7 731.8 0.0 59.8 14.9 74.7 

Still Gas 1,323.4 1,323.4 88.3 88.3 

Special Naphtha

Unfinished Oils 56.1 56.1 4.2 4.2 

Waxes

Geothermal 52.3 52.3 0.4 0.4 

TOTAL (All Fuels) 5,836.3 3,912.9 12,322.6 24,439.7 26,102.6 678.3 73,292.5 324.9 221.5 768.7 1,747.9 2,158.5 49.6 5,271.1 

a Expressed as gross calorific values (i.e., higher heating values). 

b Adjustments are subtracted from total consumption estimates and include biofuels, conversion of fossil fuels, non-energy use (see Table A-34), and international bunker fuel consumption (see Table A-35).

NE (Not Estimated)

NA (Not Available)
A-35

Table A-13: 2010 Energy Consumption Data and CO2 Emissions from Fossil Fuel Combustion by Fuel Type

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15

Adjusted Consumption (TBtu)a Emissionsb (Tg CO2 Eq.) from Energy Use

Fuel Type Res. Comm. Ind. Trans. Elec. Terr. Total Res. Comm. Ind. Trans. Elec. Terr. Total

Total Coal NE 69.7 951.6 NE 19,133.5 36.9 20,191.6 NE 6.6 90.1 NE 1,827.6 3.4 1,927.7 

Residential Coal NE NE

Commercial Coal 69.7 69.7 6.6 6.6 

Industrial Other Coal 951.6 951.6 90.1 90.1 

Transportation Coal NE NE NE

Electric Power Coal 19,133.5 19,133.5 1,827.6 1,827.6 

U.S. Territory Coal (bit) 36.9 36.9 3.4 3.4 

Natural Gas 4,878.1 3,164.7 7,683.2 719.0 7,527.6 27.8 24,000.4 258.6 167.7 407.2 38.1 399.0 1.5 1,272.1 

Total Petroleum 1,119.5 650.9 3,704.1 23,960.2 378.3 614.4 30,427.2 76.3 46.4 278.3 1,726.9 32.2 44.7 2,204.8 

Asphalt & Road Oil

Aviation Gasoline 27.0 27.0 1.9 1.9 

Distillate Fuel Oil 560.2 394.4 1,121.4 5,765.5 80.3 132.9 8,054.7 41.4 29.2 82.9 426.4 5.9 9.8 595.7 

Jet Fuel 2,097.5 NA 56.4 2,153.8 151.5 4.1 155.6 

Kerosene 29.1 4.8 7.3 7.2 48.5 2.1 0.4 0.5 0.5 3.5 

LPG 530.1 140.1 219.7 29.5 11.9 931.3 32.7 8.6 13.6 1.8 0.7 57.5 

Lubricants

Motor Gasoline 49.5 247.9 15,768.5 242.2 16,308.1 3.5 17.7 1,124.9 17.3 1,163.4 

Residual Fuel 61.7 57.3 272.2 154.1 163.8 709.0 4.6 4.3 20.4 11.6 12.3 53.2 

Other Petroleum

AvGas Blend Components (0.2) (0.2) (0.0) (0.0)

Crude Oil

MoGas Blend Components

Misc. Products

Naphtha (<401 deg. F)

Other Oil (>401 deg. F)

Pentanes Plus 77.8 77.8 5.4 5.4 

Petroleum Coke 0.4 620.9 143.9 765.2 0.0 63.4 14.7 78.1 

Still Gas 1,324.0 1,324.0 88.3 88.3 

Special Naphtha

Unfinished Oils 28.0 28.0 2.1 2.1 

Waxes

Geothermal 51.9 51.9 0.4 0.4 

TOTAL (All Fuels) 5,997.6 3,885.2 12,338.9 24,679.1 27,091.3 679.1 74,671.1 334.8 220.7 775.6 1,765.0 2,259.2 49.6 5,404.9 

a Expressed as gross calorific values (i.e., higher heating values). 

b Adjustments are subtracted from total consumption estimates and include biofuels, conversion of fossil fuels, non-energy use (see Table A-34), and international bunker fuel consumption (see Table A-35).

NE (Not Estimated)

NA (Not Available)
A-36 Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2012

Table A-14: 2009 Energy Consumption Data and CO2 Emissions from Fossil Fuel Combustion by Fuel Type

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15

Adjusted Consumption (TBtu)a Emissionsb (Tg CO2 Eq.) from Energy Use

Fuel Type Res. Comm. Ind. Trans. Elec. Terr. Total Res. Comm. Ind. Trans. Elec. Terr. Total

Total Coal NE 73.4 877.3 NE 18,225.3 36.9 19,212.8 NE 6.9 83.0 NE 1,740.9 3.4 1,834.2 

Residential Coal NE NE

Commercial Coal 73.4 73.4 6.9 6.9 

Industrial Other Coal 877.3 877.3 83.0 83.0 

Transportation Coal NE NE NE

Electric Power Coal 18,225.3 18,225.3 1,740.9 1,740.9 

U.S. Territory Coal (bit) 36.9 36.9 3.4 3.4 

Natural Gas 4,883.1 3,186.6 7,125.1 714.9 7,022.4 27.4 22,959.4 258.8 168.9 377.6 37.9 372.2 1.5 1,216.9 

Total Petroleum 1,139.4 675.2 3,549.9 23,732.2 389.9 535.5 30,022.1 77.5 48.1 266.8 1,709.8 33.0 39.0 2,174.2 

Asphalt & Road Oil

Aviation Gasoline 26.6 26.6 1.8 1.8 

Distillate Fuel Oil 564.7 387.8 1,018.4 5,539.3 70.1 83.4 7,663.6 41.8 28.7 75.3 409.7 5.2 6.2 566.8 

Jet Fuel 2,134.2 NA 61.5 2,195.7 154.1 4.4 158.6 

Kerosene 27.7 4.2 4.4 8.0 44.3 2.0 0.3 0.3 0.6 3.2 

LPG 547.1 138.9 201.7 28.0 15.0 930.7 33.8 8.6 12.4 1.7 0.9 57.4 

Lubricants

Motor Gasoline 72.8 333.8 15,818.3 202.0 16,426.9 5.2 23.8 1,128.5 14.4 1,171.9 

Residual Fuel 71.3 67.3 185.7 181.0 165.7 670.9 5.4 5.1 13.9 13.6 12.4 50.4 

Other Petroleum

AvGas Blend Components (0.8) (0.8) (0.1) (0.1)

Crude Oil

MoGas Blend Components

Misc. Products

Naphtha (<401 deg. F)

Other Oil (>401 deg. F)

Pentanes Plus 63.8 63.8 4.5 4.5 

Petroleum Coke 0.3 618.0 138.9 757.2 0.0 63.1 14.2 77.3 

Still Gas 1,321.1 1,321.1 88.1 88.1 

Special Naphtha

Unfinished Oils (77.8) (77.8) (5.8) (5.8)

Waxes

Geothermal 51.2 51.2 0.4 0.4 

TOTAL (All Fuels) 6,022.5 3,935.1 11,552.2 24,447.0 25,688.9 599.8 72,245.6 336.4 223.9 727.5 1,747.7 2,146.4 43.8 5,225.7 

a Expressed as gross calorific values (i.e., higher heating values). 

b Adjustments are subtracted from total consumption estimates and include biofuels, conversion of fossil fuels, non-energy use (see Table A-34), and international bunker fuel consumption (see Table A-35).

NE (Not Estimated)

NA (Not Available)
A-37

Table A-15: 2008 Energy Consumption Data and CO2 Emissions from Fossil Fuel Combustion by Fuel Type

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15

Adjusted Consumption (TBtu)a Emissionsb (Tg CO2 Eq.) from Energy Use

Fuel Type Res. Comm. Ind. Trans. Elec. Terr. Total Res. Comm. Ind. Trans. Elec. Terr. Total

Total Coal NE 80.8 1,081.5 NE 20,513.0 36.9 21,712.0 NE 7.6 102.4 NE 1,959.4 3.4 2,072.8 

Residential Coal NE NE

Commercial Coal 80.8 80.8 7.6 7.6 

Industrial Other Coal 1,081.5 1,081.5 102.4 102.4 

Transportation Coal NE NE NE

Electric Power Coal 20,513.0 20,513.0 1,959.4 1,959.4 

U.S. Territory Coal (bit) 36.9 36.9 3.4 3.4 

Natural Gas 5,010.1 3,228.4 7,571.4 692.1 6,828.9 29.3 23,360.2 265.5 171.1 401.3 36.7 361.9 1.6 1,238.1 

Total Petroleum 1,182.8 649.5 4,012.2 24,686.5 467.7 492.3 31,491.1 80.7 46.0 300.4 1,779.8 39.2 36.0 2,282.1 

Asphalt & Road Oil

Aviation Gasoline 28.3 28.3 2.0 2.0 

Distillate Fuel Oil 608.8 338.2 1,137.1 6,106.9 73.1 110.3 8,374.4 45.0 25.0 84.1 451.6 5.4 8.2 619.3 

Jet Fuel 2,396.1 NA 35.0 2,431.1 173.0 2.5 175.6 

Kerosene 21.3 4.4 3.8 5.9 35.4 1.6 0.3 0.3 0.4 2.6 

LPG 552.7 158.0 226.7 40.1 15.7 993.3 34.1 9.7 14.0 2.5 1.0 61.3 

Lubricants

Motor Gasoline 77.7 424.5 15,843.9 136.1 16,482.1 5.5 30.3 1,130.3 9.7 1,175.8 

Residual Fuel 71.0 131.5 271.3 240.4 189.3 903.5 5.3 9.9 20.4 18.1 14.2 67.8 

Other Petroleum

AvGas Blend Components 0.1 0.1 0.0 0.0 

Crude Oil

MoGas Blend Components

Misc. Products

Naphtha (<401 deg. F)

Other Oil (>401 deg. F)

Pentanes Plus 76.5 76.5 5.4 5.4 

Petroleum Coke 0.3 642.6 154.2 797.1 0.0 65.6 15.7 81.4 

Still Gas 1,423.0 1,423.0 94.9 94.9 

Special Naphtha

Unfinished Oils (53.7) (53.7) (4.0) (4.0)

Waxes

Geothermal 50.6 50.6 0.4 0.4 

TOTAL (All Fuels) 6,192.9 3,958.7 12,665.0 25,378.7 27,860.2 558.4 76,613.9 346.2 224.7 804.1 1,816.5 2,360.9 41.0 5,593.4 

a Expressed as gross calorific values (i.e., higher heating values). 

b Adjustments are subtracted from total consumption estimates and include biofuels, conversion of fossil fuels, non-energy use (seeTable A-34 ), and international bunker fuel consumption (see Table A-35).

NE (Not Estimated)

NA (Not Available)
A-38 Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2012

Table A-16: 2007 Energy Consumption Data and CO2 Emissions from Fossil Fuel Combustion by Fuel Type

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15

Adjusted Consumption (TBtu)a Emissionsb (Tg CO2 Eq.) from Energy Use

Fuel Type Res. Comm. Ind. Trans. Elec. Terr. Total Res. Comm. Ind. Trans. Elec. Terr. Total

Total Coal 7.8 70.0 1,130.8 NE 20,807.7 36.9 22,053.2 0.7 6.7 107.0 NE 1,987.3 3.4 2,105.1 

Residential Coal 7.8 7.8 0.7 0.7 

Commercial Coal 70.0 70.0 6.7 6.7 

Industrial Other Coal 1,130.8 1,130.8 107.0 107.0 

Transportation Coal NE NE NE

Electric Power Coal 20,807.7 20,807.7 1,987.3 1,987.3 

U.S. Territory Coal (bit) 36.9 36.9 3.4 3.4 

Natural Gas 4,835.4 3,085.1 7,521.3 663.5 7,005.2 26.7 23,137.2 256.3 163.5 398.6 35.2 371.3 1.4 1,226.3 

Total Petroleum 1,224.9 680.6 4,580.8 25,834.8 657.1 551.7 33,529.9 84.6 48.7 341.9 1,869.5 53.9 40.4 2,438.9 

Asphalt & Road Oil

Aviation Gasoline 31.6 31.6 2.2 2.2 

Distillate Fuel Oil 697.3 368.7 1,185.5 6,439.7 89.3 136.5 8,917.0 51.6 27.3 87.7 476.3 6.6 10.1 659.5 

Jet Fuel 2,485.0 NA 55.5 2,540.4 179.5 4.0 183.5 

Kerosene 43.9 9.2 13.4 5.2 71.8 3.2 0.7 1.0 0.4 5.3 

LPG 483.7 121.4 379.1 21.9 11.6 1,017.7 29.8 7.5 23.4 1.4 0.7 62.8 

Lubricants

Motor Gasoline 105.6 528.4 16,470.5 157.0 17,261.4 7.6 37.9 1,181.2 11.3 1,238.0 

Residual Fuel 75.4 130.4 386.1 396.6 185.9 1,174.4 5.7 9.8 29.0 29.8 14.0 88.2 

Other Petroleum

AvGas Blend Components 1.8 1.8 0.1 0.1 

Crude Oil

MoGas Blend Components

Misc. Products

Naphtha (<401 deg. F)

Other Oil (>401 deg. F)

Pentanes Plus 89.7 89.7 6.3 6.3 

Petroleum Coke 0.4 704.7 171.2 876.3 0.0 72.0 17.5 89.5 

Still Gas 1,482.6 1,482.6 98.9 98.9 

Special Naphtha

Unfinished Oils 65.2 65.2 4.8 4.8 

Waxes

Geothermal 49.9 49.9 0.4 0.4 

TOTAL (All Fuels) 6,068.1 3,835.7 13,232.9 26,498.2 28,520.0 615.3 78,770.2 341.6 218.9 847.5 1,904.7 2,412.8 45.2 5,770.8 

a Expressed as gross calorific values (i.e., higher heating values). Adjustments include biofuels, conversion of fossil fuels, non-energy use (see Table A-34), and international bunker fuel consumption (see Table A-35).

b Consumption and/or emissions of select fuels are shown as negative due to differences in EIA energy balancing accounting. These are designated with parentheses. 

NE (Not Estimated)

NA (Not Available)
A-39

Table A-17: 2006 Energy Consumption Data and CO2 Emissions from Fossil Fuel Combustion by Fuel Type

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15

Adjusted Consumption (TBtu)a Emissionsb (Tg CO2 Eq.) from Energy Use

Fuel Type Res. Comm. Ind. Trans. Elec. Terr. Total Res. Comm. Ind. Trans. Elec. Terr. Total

Total Coal 6.4 64.8 1,188.8 NE 20,461.9 36.9 21,758.7 0.6 6.2 112.6 NE 1,953.7 3.4 2,076.6 

Residential Coal 6.4 6.4 0.6 0.6 

Commercial Coal 64.8 64.8 6.2 6.2 

Industrial Other Coal 1,188.8 1,188.8 112.6 112.6 

Transportation Coal NE NE NE

Electric Power Coal 20,461.9 20,461.9 1,953.7 1,953.7 

U.S. Territory Coal (bit) 36.9 36.9 3.4 3.4 

Natural Gas 4,475.9 2,901.7 7,323.2 625.0 6,375.1 26.1 21,727.0 237.3 153.8 388.2 33.1 338.0 1.4 1,151.8 

Total Petroleum 1,204.9 677.7 4,699.4 25,766.7 648.1 620.9 33,617.7 83.6 48.5 350.9 1,857.8 54.4 45.5 2,440.7 

Asphalt & Road Oil

Aviation Gasoline 33.4 33.4 2.3 2.3 

Distillate Fuel Oil 693.0 390.5 1,199.4 6,358.6 73.7 90.2 8,805.3 51.3 28.9 88.7 470.3 5.4 6.7 651.2 

Jet Fuel 2,523.8 NA 76.1 2,599.9 182.3 5.5 187.8 

Kerosene 66.4 15.2 29.6 4.4 115.5 4.9 1.1 2.2 0.3 8.5 

LPG 445.5 123.2 369.7 27.5 6.6 972.5 27.5 7.6 22.8 1.7 0.4 60.0 

Lubricants

Motor Gasoline 73.3 566.7 16,517.0 188.8 17,345.9 5.2 40.4 1,178.2 13.5 1,237.4 

Residual Fuel 75.3 176.4 306.3 360.5 254.8 1,173.3 5.7 13.2 23.0 27.1 19.1 88.1 

Other Petroleum

AvGas Blend Components 0.6 0.6 0.0 0.0 

Crude Oil

MoGas Blend Components

Misc. Products

Naphtha (<401 deg. F)

Other Oil (>401 deg. F)

Pentanes Plus 70.0 70.0 4.9 4.9 

Petroleum Coke 0.3 720.5 213.9 934.6 0.0 73.6 21.8 95.4 

Still Gas 1,496.2 1,496.2 99.8 99.8 

Special Naphtha

Unfinished Oils 70.3 70.3 5.2 5.2 

Waxes

Geothermal 49.7 49.7 0.4 0.4 

TOTAL (All Fuels) 5,687.2 3,644.2 13,211.4 26,391.7 27,534.8 683.9 77,153.2 321.5 208.6 851.8 1,890.9 2,346.4 50.3 5,669.5 

a Expressed as gross calorific values (i.e., higher heating values). Adjustments include biofuels, conversion of fossil fuels, non-energy use (see Table A-34), and international bunker fuel consumption (see Table A-35).

b Consumption and/or emissions of select fuels are shown as negative due to differences in EIA energy balancing accounting. These are designated with parentheses. 

NE (Not Estimated)

NA (Not Available)
A-40 Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2012

Table A-18: 2005 Energy Consumption Data and CO2 Emissions from Fossil Fuel Combustion by Fuel Type

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15

Adjusted Consumption (TBtu)a Emissionsb (Tg CO2 Eq.) from Energy Use

Fuel Type Res. Comm. Ind. Trans. Elec. Terr. Total Res. Comm. Ind. Trans. Elec. Terr. Total

Total Coal 8.4 97.0 1,219.1 NE 20,737.2 32.7 22,094.5 0.8 9.3 115.3 NE 1,983.8 3.0 2,112.3 

Residential Coal 8.4 8.4 0.8 0.8 

Commercial Coal 97.0 97.0 9.3 9.3 

Industrial Other Coal 1,219.1 1,219.1 115.3 115.3 

Transportation Coal NE NE NE

Electric Power Coal 20,737.2 20,737.2 1,983.8 1,983.8 

U.S. Territory Coal (bit) 32.7 32.7 3.0 3.0 

Natural Gas 4,946.4 3,073.2 7,329.7 623.9 6,014.5 24.3 22,012.0 262.2 162.9 388.5 33.1 318.8 1.3 1,166.7 

Total Petroleum 1,369.2 716.0 4,324.0 25,865.2 1,234.5 623.2 34,132.2 94.9 51.3 323.8 1,858.7 99.2 45.7 2,473.5 

Asphalt & Road Oil

Aviation Gasoline 35.4 35.4 2.4 2.4 

Distillate Fuel Oil 772.6 404.7 1,128.9 6,193.8 114.6 121.3 8,735.9 57.1 29.9 83.5 458.1 8.5 9.0 646.1 

Jet Fuel 2,621.7 NA 66.0 2,687.7 189.3 4.8 194.1 

Kerosene 83.8 21.6 39.1 5.8 150.2 6.1 1.6 2.9 0.4 11.0 

LPG 512.9 131.4 349.6 28.2 0.8 1,022.8 31.7 8.1 21.6 1.7 0.0 63.1 

Lubricants

Motor Gasoline 42.2 328.2 16,729.7 194.2 17,294.3 3.0 23.3 1,187.8 13.8 1,227.9 

Residual Fuel 115.8 237.4 256.4 876.5 235.2 1,721.3 8.7 17.8 19.3 65.8 17.7 129.3 

Other Petroleum

AvGas Blend Components 8.3 8.3 0.6 0.6 

Crude Oil

MoGas Blend Components

Misc. Products

Naphtha (<401 deg. F)

Other Oil (>401 deg. F)

Pentanes Plus 98.1 98.1 6.9 6.9 

Petroleum Coke 0.3 702.1 243.5 945.9 0.0 71.7 24.9 96.6 

Still Gas 1,429.4 1,429.4 95.4 95.4 

Special Naphtha

Unfinished Oils 2.8 2.8 0.2 0.2 

Waxes

Geothermal 50.1 50.1 0.4 0.4 

TOTAL (All Fuels) 6,324.0 3,886.2 12,872.8 26,489.1 28,036.4 680.2 78,288.9 357.9 223.5 827.6 1,891.7 2,402.1 50.0 5,752.9 

a Expressed as gross calorific values (i.e., higher heating values). Adjustments include biofuels, conversion of fossil fuels, non-energy use (see Table A-34), and international bunker fuel consumption (see Table A-35).

b Consumption and/or emissions of select fuels are shown as negative due to differences in EIA energy balancing accounting. These are designated with parentheses. 

NE (Not Estimated)

NA (Not Available)
A-41

Table A-19: 2004 Energy Consumption Data and CO2 Emissions from Fossil Fuel Combustion by Fuel Type

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15

Adjusted Consumption (TBtu)a Emissionsb (Tg CO2 Eq.) from Energy Use

Fuel Type Res. Comm. Ind. Trans. Elec. Terr. Total Res. Comm. Ind. Trans. Elec. Terr. Total

Total Coal 11.4 102.9 1,262.0 NE 20,305.0 32.0 21,713.3 1.1 9.8 118.3 NE 1,943.1 2.9 2,075.1 

Residential Coal 11.4 11.4 1.1 1.1 

Commercial Coal 102.9 102.9 9.8 9.8 

Industrial Other Coal 1,262.0 1,262.0 118.3 118.3 

Transportation Coal NE NE NE

Electric Power Coal 20,305.0 20,305.0 1,943.1 1,943.1 

U.S. Territory Coal (bit) 32.0 32.0 2.9 2.9 

Natural Gas 4,980.8 3,201.0 7,913.5 602.0 5,594.9 24.6 22,316.9 264.1 169.7 419.6 31.9 296.7 1.3 1,183.4 

Total Petroleum 1,474.6 766.7 4,193.3 25,589.7 1,212.4 653.6 33,890.2 102.7 54.9 314.1 1,839.2 96.9 47.9 2,455.8 

Asphalt & Road Oil

Aviation Gasoline 31.2 31.2 2.2 2.2 

Distillate Fuel Oil 878.1 447.0 1,139.6 5,917.7 111.3 134.4 8,628.1 64.9 33.1 84.3 437.7 8.2 9.9 638.1 

Jet Fuel 2,584.8 NA 68.8 2,653.6 186.7 5.0 191.6 

Kerosene 84.8 20.5 28.2 6.0 139.5 6.2 1.5 2.1 0.4 10.2 

LPG 511.7 152.0 372.7 19.1 0.8 1,056.3 31.6 9.4 23.0 1.2 0.0 65.2 

Lubricants

Motor Gasoline 24.4 203.2 16,850.4 198.6 17,276.7 1.7 14.4 1,197.6 14.1 1,227.9 

Residual Fuel 122.5 204.7 186.4 879.0 245.0 1,637.6 9.2 15.4 14.0 66.0 18.4 123.0 

Other Petroleum

AvGas Blend Components 10.6 10.6 0.7 0.7 

Crude Oil

MoGas Blend Components

Misc. Products

Naphtha (<401 deg. F)

Other Oil (>401 deg. F)

Pentanes Plus 111.2 111.2 7.8 7.8 

Petroleum Coke 0.3 715.3 222.1 937.6 0.0 73.0 22.7 95.7 

Still Gas 1,483.3 1,483.3 99.0 99.0 

Special Naphtha

Unfinished Oils (75.6) (75.6) (5.6) (5.6)

Waxes

Geothermal 50.5 50.5 0.4 0.4 

TOTAL (All Fuels) 6,466.9 4,070.6 13,368.8 26,191.7 27,162.9 710.2 77,971.0 367.9 234.4 851.9 1,871.2 2,337.0 52.2 5,714.7 

a Expressed as gross calorific values (i.e., higher heating values). Adjustments include biofuels, conversion of fossil fuels, non-energy use (see Table A-34), and international bunker fuel consumption (see Table A-35).

b Consumption and/or emissions of select fuels are shown as negative due to differences in EIA energy balancing accounting. These are designated with parentheses. 

NE (Not Estimated)

NA (Not Available)
A-42 Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2012

Table A-20: 2003 Energy Consumption Data and CO2 Emissions from Fossil Fuel Combustion by Fuel Type

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15

Adjusted Consumption (TBtu)a Emissionsb (Tg CO2 Eq.) from Energy Use

Fuel Type Res. Comm. Ind. Trans. Elec. Terr. Total Res. Comm. Ind. Trans. Elec. Terr. Total

Total Coal 12.2 82.0 1,248.8 NE 20,184.7 33.9 21,561.7 1.2 7.8 117.0 NE 1,931.0 3.1 2,060.1 

Residential Coal 12.2 12.2 1.2 1.2 

Commercial Coal 82.0 82.0 7.8 7.8 

Industrial Other Coal 1,248.8 1,248.8 117.0 117.0 

Transportation Coal NE NE NE

Electric Power Coal 20,184.7 20,184.7 1,931.0 1,931.0 

U.S. Territory Coal (bit) 33.9 33.9 3.1 3.1 

Natural Gas 5,209.4 3,260.9 7,845.1 627.4 5,246.2 26.9 22,216.0 275.9 172.7 415.4 33.2 277.8 1.4 1,176.4 

Total Petroleum 1,466.1 762.0 3,948.6 24,940.9 1,205.0 621.8 32,944.5 101.8 54.5 296.5 1,790.6 95.0 45.3 2,383.7 

Asphalt & Road Oil

Aviation Gasoline 30.2 30.2 2.1 2.1 

Distillate Fuel Oil 851.3 453.1 1,055.5 5,710.9 161.0 120.5 8,352.3 63.0 33.5 78.1 422.4 11.9 8.9 617.7 

Jet Fuel 2,482.5 NA 76.1 2,558.5 179.3 5.5 184.8 

Kerosene 70.3 18.6 24.1 10.7 123.7 5.1 1.4 1.8 0.8 9.1 

LPG 544.5 156.9 326.8 17.9 10.5 1,056.6 33.7 9.7 20.2 1.1 0.7 65.3 

Lubricants

Motor Gasoline 22.0 119.1 16,600.4 210.1 16,951.6 1.6 8.5 1,178.3 14.9 1,203.2 

Residual Fuel 111.1 176.4 99.1 869.4 193.9 1,450.0 8.3 13.2 7.4 65.3 14.6 108.9 

Other Petroleum

AvGas Blend Components 7.5 7.5 0.5 0.5 

Crude Oil

MoGas Blend Components

Misc. Products

Naphtha (<401 deg. F)

Other Oil (>401 deg. F)

Pentanes Plus 110.4 110.4 7.7 7.7 

Petroleum Coke 0.3 701.9 174.7 876.8 0.0 71.7 17.8 89.5 

Still Gas 1,477.3 1,477.3 98.6 98.6 

Special Naphtha

Unfinished Oils (50.4) (50.4) (3.7) (3.7)

Waxes

Geothermal 49.2 49.2 0.4 0.4 

TOTAL (All Fuels) 6,687.8 4,104.9 13,042.5 25,568.4 26,685.2 682.6 76,771.4 378.8 235.0 828.9 1,823.8 2,304.2 49.9 5,620.5 

a Expressed as gross calorific values (i.e., higher heating values). Adjustments include biofuels, conversion of fossil fuels, non-energy use (see Table A-34), and international bunker fuel consumption (see Table A-35).

b Consumption and/or emissions of select fuels are shown as negative due to differences in EIA energy balancing accounting. These are designated with parentheses. 

NE (Not Estimated)

NA (Not Available)
A-43

Table A-21: 2002 Energy Consumption Data and CO2 Emissions from Fossil Fuel Combustion by Fuel Type

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15

Adjusted Consumption (TBtu)a Emissionsb (Tg CO2 Eq.) from Energy Use

Fuel Type Res. Comm. Ind. Trans. Elec. Terr. Total Res. Comm. Ind. Trans. Elec. Terr. Total

Total Coal 12.2 89.8 1,243.7 NE 19,782.8 10.8 21,139.3 1.2 8.6 116.6 NE 1,889.9 1.0 2,017.2 

Residential Coal 12.2 12.2 1.2 1.2 

Commercial Coal 89.8 89.8 8.6 8.6 

Industrial Other Coal 1,243.7 1,243.7 116.6 116.6 

Transportation Coal NE NE NE

Electric Power Coal 19,782.8 19,782.8 1,889.9 1,889.9 

U.S. Territory Coal (bit) 10.8 10.8 1.0 1.0 

Natural Gas 4,995.0 3,212.5 8,086.3 698.9 5,766.8 22.8 22,782.3 264.7 170.3 428.6 37.0 305.7 1.2 1,207.5 

Total Petroleum 1,358.9 645.4 3,785.2 24,961.1 961.3 556.8 32,268.7 93.9 46.1 283.9 1,793.6 76.8 40.6 2,334.9 

Asphalt & Road Oil

Aviation Gasoline 33.7 33.7 2.3 2.3 

Distillate Fuel Oil 761.8 393.4 1,048.4 5,595.9 127.4 92.8 8,019.7 56.3 29.1 77.5 413.9 9.4 6.9 593.1 

Jet Fuel 2,565.5 NA 61.8 2,627.3 185.3 4.5 189.7 

Kerosene 59.9 15.9 13.8 8.2 97.9 4.4 1.2 1.0 0.6 7.2 

LPG 537.1 140.8 393.3 14.3 11.2 1,096.7 33.2 8.7 24.3 0.9 0.7 67.8 

Lubricants

Motor Gasoline 15.2 104.1 16,523.8 189.4 16,832.5 1.1 7.4 1,174.1 13.5 1,196.0 

Residual Fuel 79.8 146.1 227.9 658.7 193.6 1,306.1 6.0 11.0 17.1 49.5 14.5 98.1 

Other Petroleum

AvGas Blend Components 7.5 7.5 0.5 0.5 

Crude Oil

MoGas Blend Components

Misc. Products

Naphtha (<401 deg. F)

Other Oil (>401 deg. F)

Pentanes Plus 111.9 111.9 7.8 7.8 

Petroleum Coke 0.2 696.3 175.2 871.7 0.0 71.1 17.9 89.0 

Still Gas 1,399.4 1,399.4 93.4 93.4 

Special Naphtha

Unfinished Oils (135.7) (135.7) (10.1) (10.1)

Waxes

Geothermal 49.4 49.4 0.4 0.4 

TOTAL (All Fuels) 6,366.1 3,947.7 13,115.1 25,660.0 26,560.4 590.4 76,239.7 359.8 224.9 829.1 1,830.6 2,272.7 42.8 5,559.9 

a Expressed as gross calorific values (i.e., higher heating values). Adjustments include biofuels, conversion of fossil fuels, non-energy use (see Table A-34), and international bunker fuel consumption (see Table A-35).

b Consumption and/or emissions of select fuels are shown as negative due to differences in EIA energy balancing accounting. These are designated with parentheses. 

NE (Not Estimated)

NA (Not Available)
A-44 Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2012

Table A-22: 2001 Energy Consumption Data and CO2 Emissions from Fossil Fuel Combustion by Fuel Type

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15

Adjusted Consumption (TBtu)a Emissionsb (Tg CO2 Eq.) from Energy Use

Fuel Type Res. Comm. Ind. Trans. Elec. Terr. Total Res. Comm. Ind. Trans. Elec. Terr. Total

Total Coal 12.0 96.9 1,358.4 NE 19,613.7 3.8 21,084.8 1.1 9.2 127.8 NE 1,869.8 0.4 2,008.4 

Residential Coal 12.0 12.0 1.1 1.1 

Commercial Coal 96.9 96.9 9.2 9.2 

Industrial Other Coal 1,358.4 1,358.4 127.8 127.8 

Transportation Coal NE NE NE

Electric Power Coal 19,613.7 19,613.7 1,869.8 1,869.8 

U.S. Territory Coal (bit) 3.8 3.8 0.4 0.4 

Natural Gas 4,889.0 3,097.3 7,949.0 658.0 5,458.1 22.9 22,074.3 259.1 164.2 421.3 34.9 289.3 1.2 1,170.0 

Total Petroleum 1,463.0 718.6 3,910.8 24,449.8 1,276.6 632.2 32,450.9 101.8 51.5 293.2 1,754.3 98.5 46.2 2,345.4 

Asphalt & Road Oil

Aviation Gasoline 34.9 34.9 2.4 2.4 

Distillate Fuel Oil 842.2 471.4 1,181.8 5,417.0 170.5 109.4 8,192.3 62.3 34.9 87.4 400.6 12.6 8.1 605.9 

Jet Fuel 2,626.3 NA 98.9 2,725.2 189.7 7.1 196.8 

Kerosene 95.1 31.4 23.2 0.9 150.6 7.0 2.3 1.7 0.1 11.0 

LPG 525.7 142.7 372.1 13.7 7.0 1,061.2 32.5 8.8 23.0 0.8 0.4 65.6 

Lubricants

Motor Gasoline 3.1 24.2 16,198.3 187.6 16,413.2 0.2 1.7 1,148.7 13.3 1,164.0 

Residual Fuel 69.9 146.7 159.5 1,002.8 228.4 1,607.2 5.2 11.0 12.0 75.3 17.2 120.7 

Other Petroleum

AvGas Blend Components 6.1 6.1 0.4 0.4 

Crude Oil

MoGas Blend Components

Misc. Products

Naphtha (<401 deg. F)

Other Oil (>401 deg. F)

Pentanes Plus 131.6 131.6 9.2 9.2 

Petroleum Coke 0.2 683.3 103.2 786.7 0.0 69.8 10.5 80.3 

Still Gas 1,417.3 1,417.3 94.6 94.6 

Special Naphtha

Unfinished Oils (75.4) (75.4) (5.6) (5.6)

Waxes

Geothermal 46.9 46.9 0.4 0.4 

TOTAL (All Fuels) 6,364.0 3,912.7 13,218.2 25,107.8 26,395.2 658.9 75,656.8 362.0 224.9 842.3 1,789.2 2,257.9 47.8 5,524.1 

a Expressed as gross calorific values (i.e., higher heating values). Adjustments include biofuels, conversion of fossil fuels, non-energy use (see Table A-34), and international bunker fuel consumption (see Table A-35).

b Consumption and/or emissions of select fuels are shown as negative due to differences in EIA energy balancing accounting. These are designated with parentheses. 

NE (Not Estimated)

NA (Not Available)
A-45

Table A-23: 2000 Energy Consumption Data and CO2 Emissions from Fossil Fuel Combustion by Fuel Type

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15

Adjusted Consumption (TBtu)a Emissionsb (Tg CO2 Eq.) from Energy Use

Fuel Type Res. Comm. Ind. Trans. Elec. Terr. Total Res. Comm. Ind. Trans. Elec. Terr. Total

Total Coal 11.4 91.9 1,348.8 NE 20,220.2 10.3 21,682.4 1.1 8.8 127.3 NE 1,927.4 0.9 2,065.5 

Residential Coal 11.4 11.4 1.1 1.1 

Commercial Coal 91.9 91.9 8.8 8.8 

Industrial Other Coal 1,348.8 1,348.8 127.3 127.3 

Transportation Coal NE NE NE

Electric Power Coal 20,220.2 20,220.2 1,927.4 1,927.4 

U.S. Territory Coal (bit) 10.3 10.3 0.9 0.9 

Natural Gas 5,104.6 3,251.5 8,656.0 672.0 5,293.4 12.7 22,990.2 270.7 172.5 459.1 35.6 280.8 0.7 1,219.4 

Total Petroleum 1,427.5 694.0 3,575.0 24,649.1 1,144.3 471.7 31,961.5 98.8 49.6 267.5 1,769.1 88.4 34.2 2,307.6 

Asphalt & Road Oil

Aviation Gasoline 36.3 36.3 2.5 2.5 

Distillate Fuel Oil 778.0 422.2 1,003.7 5,442.4 174.8 71.3 7,892.5 57.5 31.2 74.2 402.5 12.9 5.3 583.7 

Jet Fuel 2,700.3 NA 74.1 2,774.3 195.0 5.3 200.4 

Kerosene 94.6 29.7 15.6 2.4 142.2 6.9 2.2 1.1 0.2 10.4 

LPG 554.9 150.4 468.7 11.9 8.0 1,193.9 34.4 9.3 29.0 0.7 0.5 74.0 

Lubricants

Motor Gasoline 16,014.8 185.1 16,199.8 1,135.0 13.1 1,148.1 

Residual Fuel 91.6 184.1 443.5 870.8 130.9 1,720.8 6.9 13.8 33.3 65.4 9.8 129.2 

Other Petroleum

AvGas Blend Components 3.8 3.8 0.3 0.3 

Crude Oil

MoGas Blend Components

Misc. Products

Naphtha (<401 deg. F)

Other Oil (>401 deg. F)

Pentanes Plus 171.6 171.6 12.0 12.0 

Petroleum Coke 0.2 697.3 98.6 796.2 0.0 71.2 10.1 81.3 

Still Gas 1,431.2 1,431.2 95.5 95.5 

Special Naphtha

Unfinished Oils (401.2) (401.2) (29.7) (29.7)

Waxes

Geothermal 48.1 48.1 0.4 0.4 

TOTAL (All Fuels) 6,543.4 4,037.4 13,579.8 25,321.1 26,706.0 494.6 76,682.2 370.7 230.8 853.9 1,804.7 2,296.9 35.9 5,592.8 

a Expressed as gross calorific values (i.e., higher heating values). Adjustments include biofuels, conversion of fossil fuels, non-energy use (see Table A-34), and international bunker fuel consumption (see Table A-35).

b Consumption and/or emissions of select fuels are shown as negative due to differences in EIA energy balancing accounting. These are designated with parentheses. 

NE (Not Estimated)

NA (Not Available)
A-46 Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2012

Table A-24: 1999 Energy Consumption Data and CO2 Emissions from Fossil Fuel Combustion by Fuel Type

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15

Adjusted Consumption (TBtu)a Emissionsb (Tg CO2 Eq.) from Energy Use

Fuel Type Res. Comm. Ind. Trans. Elec. Terr. Total Res. Comm. Ind. Trans. Elec. Terr. Total

Total Coal 14.0 102.5 1,372.8 NE 19,279.5 10.2 20,779.0 1.3 9.8 129.9 NE 1,836.4 0.9 1,978.3 

Residential Coal 14.0 14.0 1.3 1.3 

Commercial Coal 102.5 102.5 9.8 9.8 

Industrial Other Coal 1,372.8 1,372.8 129.9 129.9 

Transportation Coal NE NE NE

Electric Power Coal 19,279.5 19,279.5 1,836.4 1,836.4 

U.S. Territory Coal (bit) 10.2 10.2 0.9 0.9 

Natural Gas 4,834.9 3,115.0 8,424.6 675.3 4,902.1 21,952.0 256.3 165.1 446.6 35.8 259.9 1,163.8 

Total Petroleum 1,342.1 613.9 3,577.9 24,058.4 1,211.4 461.0 31,264.7 92.8 43.8 269.2 1,725.0 93.8 33.5 2,258.2 

Asphalt & Road Oil

Aviation Gasoline 39.2 39.2 2.7 2.7 

Distillate Fuel Oil 705.0 373.4 983.4 5,251.3 140.1 79.4 7,532.6 52.1 27.6 72.7 388.4 10.4 5.9 557.1 

Jet Fuel 2,664.8 NA 59.5 2,724.4 192.5 4.3 196.8 

Kerosene 111.2 26.9 12.8 3.7 154.7 8.1 2.0 0.9 0.3 11.3 

LPG 526.0 140.2 395.9 14.3 8.3 1,084.6 32.5 8.7 24.5 0.9 0.5 67.1 

Lubricants

Motor Gasoline 15,913.1 164.0 16,077.2 1,127.4 11.6 1,139.0 

Residual Fuel 73.3 150.9 175.7 958.7 146.0 1,504.6 5.5 11.3 13.2 72.0 11.0 113.0 

Other Petroleum

AvGas Blend Components 6.4 6.4 0.4 0.4 

Crude Oil

MoGas Blend Components

Misc. Products

Naphtha (<401 deg. F)

Other Oil (>401 deg. F)

Pentanes Plus 182.5 182.5 12.8 12.8 

Petroleum Coke 0.1 719.8 112.5 832.4 0.0 73.5 11.5 85.0 

Still Gas 1,414.1 1,414.1 94.3 94.3 

Special Naphtha

Unfinished Oils (287.9) (287.9) (21.3) (21.3)

Waxes

Geothermal 50.6 50.6 0.4 0.4 

TOTAL (All Fuels) 6,191.0 3,831.5 13,375.3 24,733.8 25,443.6 471.2 74,046.3 350.5 218.7 845.7 1,760.8 2,190.5 34.5 5,400.7 

a Expressed as gross calorific values (i.e., higher heating values). Adjustments include biofuels, conversion of fossil fuels, non-energy use (see Table A-34), and international bunker fuel consumption (see Table A-35).

b Consumption and/or emissions of select fuels are shown as negative due to differences in EIA energy balancing accounting. These are designated with parentheses. 

NE (Not Estimated)

NA (Not Available)
A-47

Table A-25: 1998 Energy Consumption Data and CO2 Emissions from Fossil Fuel Combustion by Fuel Type

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15

Adjusted Consumption (TBtu)a Emissionsb (Tg CO2 Eq.) from Energy Use

Fuel Type Res. Comm. Ind. Trans. Elec. Terr. Total Res. Comm. Ind. Trans. Elec. Terr. Total

Total Coal 11.5 93.4 1,470.8 NE 19,215.7 10.5 20,802.0 1.1 8.9 139.1 NE 1,828.2 1.0 1,978.3 

Residential Coal 11.5 11.5 1.1 1.1 

Commercial Coal 93.4 93.4 8.9 8.9 

Industrial Other Coal 1,470.8 1,470.8 139.1 139.1 

Transportation Coal NE NE NE

Electric Power Coal 19,215.7 19,215.7 1,828.2 1,828.2 

U.S. Territory Coal (bit) 10.5 10.5 1.0 1.0 

Natural Gas 4,646.1 3,083.0 8,826.0 666.1 4,674.9 21,896.1 246.0 163.3 467.4 35.3 247.6 1,159.5 

Total Petroleum 1,207.3 609.1 3,470.7 23,278.6 1,306.2 445.4 30,317.4 84.0 43.7 262.4 1,670.9 101.3 32.4 2,194.7 

Asphalt & Road Oil

Aviation Gasoline 35.5 35.5 2.5 2.5 

Distillate Fuel Oil 675.1 375.1 1,027.9 4,955.2 135.7 71.9 7,240.8 49.9 27.7 76.0 366.5 10.0 5.3 535.5 

Jet Fuel 2,608.0 NA 59.9 2,667.8 188.4 4.3 192.7 

Kerosene 108.3 31.2 22.1 6.3 167.8 7.9 2.3 1.6 0.5 12.3 

LPG 423.9 117.6 271.6 17.6 5.9 836.7 26.1 7.2 16.7 1.1 0.4 51.6 

Lubricants

Motor Gasoline 15,583.4 160.3 15,743.8 1,106.6 11.4 1,118.0 

Residual Fuel 85.2 173.3 78.9 1,047.0 141.1 1,525.5 6.4 13.0 5.9 78.6 10.6 114.6 

Other Petroleum

AvGas Blend Components 4.0 4.0 0.3 0.3 

Crude Oil

MoGas Blend Components

Misc. Products

Naphtha (<401 deg. F)

Other Oil (>401 deg. F)

Pentanes Plus 147.0 147.0 10.3 10.3 

Petroleum Coke 0.1 707.7 123.6 831.4 0.0 72.3 12.6 84.9 

Still Gas 1,431.0 1,431.0 95.5 95.5 

Special Naphtha

Unfinished Oils (313.9) (313.9) (23.3) (23.3)

Waxes

Geothermal 50.4 50.4 0.4 0.4 

TOTAL (All Fuels) 5,865.0 3,785.5 13,767.5 23,944.7 25,247.2 456.0 73,065.9 331.1 215.9 868.9 1,706.2 2,177.4 33.4 5,332.8 

a Expressed as gross calorific values (i.e., higher heating values). Adjustments include biofuels, conversion of fossil fuels, non-energy use (see Table A-34), and international bunker fuel consumption (see Table A-35).

b Consumption and/or emissions of select fuels are shown as negative due to differences in EIA energy balancing accounting. These are designated with parentheses. 

NE (Not Estimated)

NA (Not Available)
A-48 Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2012

Table A-26: 1997 Energy Consumption Data and CO2 Emissions from Fossil Fuel Combustion by Fuel Type 

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15

Adjusted Consumption (TBtu)a Emissionsb (Tg CO2 Eq.) from Energy Use

Fuel Type Res. Comm. Ind. Trans. Elec. Terr. Total Res. Comm. Ind. Trans. Elec. Terr. Total

Total Coal 16.0 129.4 1,457.6 NE 18,904.5 10.4 20,518.0 1.5 12.3 137.6 NE 1,797.0 1.0 1,949.5 

Residential Coal 16.0 16.0 1.5 1.5 

Commercial Coal 129.4 129.4 12.3 12.3 

Industrial Other Coal 1,457.6 1,457.6 137.6 137.6 

Transportation Coal NE NE NE

Electric Power Coal 18,904.5 18,904.5 1,797.0 1,797.0 

U.S. Territory Coal (bit) 10.4 10.4 1.0 1.0 

Natural Gas 5,092.9 3,285.3 9,032.5 780.3 4,125.5 22,316.6 270.1 174.2 479.0 41.4 218.8 1,183.4 

Total Petroleum 1,333.5 655.1 3,896.2 22,693.8 926.8 445.3 29,950.8 93.0 47.1 290.1 1,628.5 72.2 32.4 2,163.3 

Asphalt & Road Oil

Aviation Gasoline 39.7 39.7 2.7 2.7 

Distillate Fuel Oil 785.9 398.9 1,057.3 4,802.2 110.6 81.6 7,236.4 58.1 29.5 78.2 355.2 8.2 6.0 535.2 

Jet Fuel 2,553.8 NA 62.1 2,615.9 184.4 4.5 188.9 

Kerosene 92.9 24.6 18.8 4.0 140.3 6.8 1.8 1.4 0.3 10.3 

LPG 454.8 120.2 429.9 14.2 6.5 1,025.7 28.1 7.4 26.5 0.9 0.4 63.3 

Lubricants

Motor Gasoline 15,147.5 160.0 15,307.5 1,075.0 11.4 1,086.4 

Residual Fuel 111.2 240.1 136.5 714.6 131.1 1,333.5 8.4 18.0 10.3 53.7 9.8 100.1 

Other Petroleum

AvGas Blend Components 9.1 9.1 0.6 0.6 

Crude Oil 4.6 4.6 0.3 0.3 

MoGas Blend Components

Misc. Products

Naphtha (<401 deg. F)

Other Oil (>401 deg. F)

Pentanes Plus 164.5 164.5 11.5 11.5 

Petroleum Coke 0.1 639.9 101.6 741.6 0.0 65.3 10.4 75.7 

Still Gas 1,435.0 1,435.0 95.7 95.7 

Special Naphtha

Unfinished Oils (102.9) (102.9) (7.6) (7.6)

Waxes

Geothermal 50.2 50.2 0.4 0.4 

TOTAL (All Fuels) 6,442.5 4,069.8 14,386.4 23,474.1 24,007.1 455.7 72,835.6 364.6 233.6 906.7 1,669.8 2,088.4 33.4 5,296.5 

a Expressed as gross calorific values (i.e., higher heating values). Adjustments include biofuels, conversion of fossil fuels, non-energy use (see Table A-34), and international bunker fuel consumption (see Table A-35).

b Consumption and/or emissions of select fuels are shown as negative due to differences in EIA energy balancing accounting. These are designated with parentheses. 

NE (Not Estimated)

NA (Not Available)
A-49

Table A-27: 1996 Energy Consumption Data and CO2 Emissions from Fossil Fuel Combustion by Fuel Type

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15

Adjusted Consumption (TBtu)a Emissionsb (Tg CO2 Eq.) from Energy Use

Fuel Type Res. Comm. Ind. Trans. Elec. Terr. Total Res. Comm. Ind. Trans. Elec. Terr. Total

Total Coal 16.6 121.6 1,454.9 NE 18,429.0 10.3 20,032.4 1.6 11.6 137.4 NE 1,752.4 1.0 1,903.9 

Residential Coal 16.6 16.6 1.6 1.6 

Commercial Coal 121.6 121.6 11.6 11.6 

Industrial Other Coal 1,454.9 1,454.9 137.4 137.4 

Transportation Coal NE NE NE

Electric Power Coal 18,429.0 18,429.0 1,752.4 1,752.4 

U.S. Territory Coal (bit) 10.3 10.3 1.0 1.0 

Natural Gas 5,354.4 3,226.3 9,020.3 736.9 3,862.4 22,200.4 283.9 171.1 478.3 39.1 204.8 1,177.2 

Total Petroleum 1,396.6 718.3 3,912.3 22,502.3 817.4 434.6 29,781.4 97.5 51.8 291.5 1,615.0 63.4 31.6 2,150.7 

Asphalt & Road Oil

Aviation Gasoline 37.4 37.4 2.6 2.6 

Distillate Fuel Oil 839.0 437.6 1,049.1 4,599.0 109.4 76.5 7,110.5 62.1 32.4 77.6 340.1 8.1 5.7 525.9 

Jet Fuel 2,556.0 NA 78.5 2,634.5 184.6 5.7 190.3 

Kerosene 88.8 21.0 18.3 3.0 131.1 6.5 1.5 1.3 0.2 9.6 

LPG 468.7 122.4 401.7 15.6 7.3 1,015.8 28.9 7.5 24.8 1.0 0.5 62.6 

Lubricants

Motor Gasoline 14,979.4 151.4 15,130.8 1,063.0 10.7 1,073.8 

Residual Fuel 137.2 284.7 314.9 628.4 118.0 1,483.1 10.3 21.4 23.6 47.2 8.9 111.4 

Other Petroleum

AvGas Blend Components 7.0 7.0 0.5 0.5 

Crude Oil 13.7 13.7 1.0 1.0 

MoGas Blend Components

Misc. Products

Naphtha (<401 deg. F)

Other Oil (>401 deg. F)

Pentanes Plus 177.5 177.5 12.4 12.4 

Petroleum Coke 0.1 638.2 79.6 717.9 0.0 65.2 8.1 73.3 

Still Gas 1,434.9 1,434.9 95.7 95.7 

Special Naphtha

Unfinished Oils (112.8) (112.8) (8.4) (8.4)

Waxes

Geothermal 48.9 48.9 0.4 0.4 

TOTAL (All Fuels) 6,767.5 4,066.2 14,387.5 23,239.2 23,157.7 445.0 72,063.1 383.0 234.5 907.2 1,654.0 2,021.0 32.5 5,232.2 

a Expressed as gross calorific values (i.e., higher heating values). Adjustments include biofuels, conversion of fossil fuels, non-energy use (see Table A-34), and international bunker fuel consumption (see Table A-35).

b Consumption and/or emissions of select fuels are shown as negative due to differences in EIA energy balancing accounting. These are designated with parentheses. 

NE (Not Estimated)

NA (Not Available)
A-50 Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2012

Table A-28: 1995 Energy Consumption Data and CO2 Emissions from Fossil Fuel Combustion by Fuel Type

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15

Adjusted Consumption (TBtu)a Emissionsb (Tg CO2 Eq.) from Energy Use

Fuel Type Res. Comm. Ind. Trans. Elec. Terr. Total Res. Comm. Ind. Trans. Elec. Terr. Total

Total Coal 17.5 116.8 1,526.9 NE 17,466.3 10.2 19,137.7 1.7 11.2 144.4 NE 1,660.7 0.9 1,819.0 

Residential Coal 17.5 17.5 1.7 1.7 

Commercial Coal 116.8 116.8 11.2 11.2 

Industrial Other Coal 1,526.9 1,526.9 144.4 144.4 

Transportation Coal NE NE NE

Electric Power Coal 17,466.3 17,466.3 1,660.7 1,660.7 

U.S. Territory Coal (bit) 10.2 10.2 0.9 0.9 

Natural Gas 4,954.2 3,096.0 8,722.5 724.0 4,302.0 21,798.6 262.7 164.2 462.5 38.4 228.1 1,155.9 

Total Petroleum 1,260.9 694.0 3,538.2 21,935.2 754.6 461.8 28,644.7 88.3 50.1 263.2 1,571.2 58.7 33.6 2,065.1 

Asphalt & Road Oil

Aviation Gasoline 39.6 39.6 2.7 2.7 

Distillate Fuel Oil 791.8 419.1 967.9 4,383.3 108.1 89.5 6,759.6 58.6 31.0 71.6 324.2 8.0 6.6 499.9 

Jet Fuel 2,428.8 NA 75.7 2,504.5 172.2 5.4 177.6 

Kerosene 74.3 22.1 15.4 3.6 115.4 5.4 1.6 1.1 0.3 8.4 

LPG 394.8 108.7 403.4 17.7 5.6 930.2 24.4 6.7 24.9 1.1 0.3 57.4 

Lubricants

Motor Gasoline 2.5 27.2 14,678.5 146.7 14,854.9 0.2 1.9 1,041.8 10.4 1,054.3 

Residual Fuel 141.5 286.2 387.3 566.0 140.7 1,521.6 10.6 21.5 29.1 42.5 10.6 114.3 

Other Petroleum

AvGas Blend Components 5.3 5.3 0.4 0.4 

Crude Oil 14.5 14.5 1.1 1.1 

MoGas Blend Components

Misc. Products

Naphtha (<401 deg. F)

Other Oil (>401 deg. F)

Pentanes Plus 169.0 169.0 11.8 11.8 

Petroleum Coke 0.1 600.7 80.6 681.4 0.0 61.3 8.2 69.6 

Still Gas 1,369.5 1,369.5 91.4 91.4 

Special Naphtha

Unfinished Oils (320.9) (320.9) (23.8) (23.8)

Waxes

Geothermal 45.6 45.6 0.3 0.3 

Total Coal 6,232.5 3,906.8 13,787.7 22,659.2 22,568.5 472.0 69,626.6 352.7 225.5 870.2 1,609.5 1,947.9 34.5 5,040.4 

a Expressed as gross calorific values (i.e., higher heating values). Adjustments include biofuels, conversion of fossil fuels, non-energy use (see Table A-34), and international bunker fuel consumption (see Table A-35).

b Consumption and/or emissions of select fuels are shown as negative due to differences in EIA energy balancing accounting. These are designated with parentheses. 

NE (Not Estimated)

NA (Not Available)
A-51

Table A-29: 1994 Energy Consumption Data and CO2 Emissions from Fossil Fuel Combustion by Fuel Type

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15

Adjusted Consumption (TBtu)a Emissionsb (Tg CO2 Eq.) from Energy Use

Fuel Type Res. Comm. Ind. Trans. Elec. Terr. Total Res. Comm. Ind. Trans. Elec. Terr. Total

Total Coal 20.8 118.1 1,594.9 NE 17,260.9 10.0 19,004.7 2.0 11.3 150.7 NE 1,638.8 0.9 1,803.7 

Residential Coal 20.8 20.8 2.0 2.0 

Commercial Coal 118.1 118.1 11.3 11.3 

Industrial Other Coal 1,594.9 1,594.9 150.7 150.7 

Transportation Coal NE NE NE

Electric Power Coal 17,260.9 17,260.9 1,638.8 1,638.8 

U.S. Territory Coal (bit) 10.0 10.0 0.9 0.9 

Natural Gas 4,959.8 2,962.0 8,290.3 708.5 3,977.3 20,897.9 262.9 157.0 439.4 37.6 210.8 1,107.6 

Total Petroleum 1,305.3 745.9 3,697.9 21,492.3 1,058.8 506.3 28,806.5 91.8 54.0 274.6 1,539.3 81.3 36.9 2,077.9 

Asphalt & Road Oil

Aviation Gasoline 38.1 38.1 2.6 2.6 

Distillate Fuel Oil 856.7 447.1 975.8 4,187.0 120.1 118.8 6,705.5 63.4 33.1 72.2 309.7 8.9 8.8 495.9 

Jet Fuel 2,473.8 NA 65.8 2,539.5 175.5 4.7 180.2 

Kerosene 64.9 19.5 16.9 3.0 104.3 4.8 1.4 1.2 0.2 7.6 

LPG 383.7 107.3 423.1 34.0 7.3 955.3 23.7 6.6 26.1 2.1 0.4 59.0 

Lubricants

Motor Gasoline 14,401.3 147.4 14,548.7 1,022.5 10.5 1,033.0 

Residual Fuel 171.9 368.4 358.1 869.0 164.1 1,931.5 12.9 27.7 26.9 65.3 12.3 145.0 

Other Petroleum

AvGas Blend Components 6.1 6.1 0.4 0.4 

Crude Oil 18.7 18.7 1.4 1.4 

MoGas Blend Components

Misc. Products

Naphtha (<401 deg. F)

Other Oil (>401 deg. F)

Pentanes Plus 169.4 169.4 11.9 11.9 

Petroleum Coke 0.1 594.9 69.7 664.7 0.0 60.7 7.1 67.9 

Still Gas 1,404.0 1,404.0 93.7 93.7 

Special Naphtha

Unfinished Oils (279.2) (279.2) (20.7) (20.7)

Waxes

Geothermal 53.0 53.0 0.4 0.4 

Total Coal 6,286.0 3,826.0 13,583.1 22,200.8 22,350.0 516.3 68,762.2 356.7 222.3 864.7 1,576.9 1,931.2 37.8 4,989.6 

a Expressed as gross calorific values (i.e., higher heating values). Adjustments include biofuels, conversion of fossil fuels, non-energy use (see Table A-34), and international bunker fuel consumption (see Table A-35).

b Consumption and/or emissions of select fuels are shown as negative due to differences in EIA energy balancing accounting. These are designated with parentheses. 

NE (Not Estimated)

NA (Not Available)
A-52 Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2012

Table A-30: 1993 Energy Consumption Data and CO2 Emissions from Fossil Fuel Combustion by Fuel Type

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15

Adjusted Consumption (TBtu)a Emissionsb (Tg CO2 Eq.) from Energy Use

Fuel Type Res. Comm. Ind. Trans. Elec. Terr. Total Res. Comm. Ind. Trans. Elec. Terr. Total

Total Coal 25.7 117.3 1,585.0 NE 17,195.9 9.6 18,933.5 2.5 11.3 149.8 NE 1,632.5 0.9 1,796.9 

Residential Coal 25.7 25.7 2.5 2.5 

Commercial Coal 117.3 117.3 11.3 11.3 

Industrial Other Coal 1,585.0 1,585.0 149.8 149.8 

Transportation Coal NE NE NE

Electric Power Coal 17,195.9 17,195.9 1,632.5 1,632.5 

U.S. Territory Coal (bit) 9.6 9.6 0.9 0.9 

Natural Gas 5,063.3 2,923.3 8,272.5 644.7 3,537.5 20,441.3 268.4 155.0 438.6 34.2 187.5 1,083.7 

Total Petroleum 1,348.5 743.4 3,588.7 20,921.0 1,123.8 459.9 28,185.1 94.9 53.8 267.4 1,502.1 86.4 33.6 2,038.2 

Asphalt & Road Oil

Aviation Gasoline 38.4 38.4 2.7 2.7 

Distillate Fuel Oil 883.3 447.2 989.9 3,889.4 86.5 104.9 6,401.1 65.3 33.1 73.2 287.6 6.4 7.8 473.4 

Jet Fuel 2,368.4 NA 62.1 2,430.5 168.2 4.4 172.6 

Kerosene 75.6 14.0 13.1 3.8 106.5 5.5 1.0 1.0 0.3 7.8 

LPG 389.6 109.2 412.2 20.2 4.9 936.2 24.0 6.7 25.4 1.2 0.3 57.8 

Lubricants

Motor Gasoline 14,237.0 128.3 14,365.3 1,014.8 9.1 1,023.9 

Residual Fuel 172.7 382.9 367.5 958.6 155.9 2,037.7 13.0 28.8 27.6 72.0 11.7 153.0 

Other Petroleum

AvGas Blend Components 0.2 0.2 0.0 0.0 

Crude Oil 21.2 21.2 1.6 1.6 

MoGas Blend Components

Misc. Products

Naphtha (<401 deg. F)

Other Oil (>401 deg. F)

Pentanes Plus 166.1 166.1 11.6 11.6 

Petroleum Coke 0.2 614.6 78.6 693.4 0.0 62.8 8.0 70.8 

Still Gas 1,384.6 1,384.6 92.4 92.4 

Special Naphtha

Unfinished Oils (396.0) (396.0) (29.3) (29.3)

Waxes

Geothermal 57.3 57.3 0.4 0.4 

Total Coal 6,437.5 3,783.9 13,446.1 21,565.7 21,914.5 469.5 67,617.2 365.8 220.1 855.7 1,536.3 1,906.9 34.5 4,919.2 

a Expressed as gross calorific values (i.e., higher heating values). Adjustments include biofuels, conversion of fossil fuels, non-energy use (see Table A-34), and international bunker fuel consumption (see Table A-35).

b Consumption and/or emissions of select fuels are shown as negative due to differences in EIA energy balancing accounting. These are designated with parentheses. 

NE (Not Estimated)

NA (Not Available)
A-53

Table A-31: 1992 Energy Consumption Data and CO2 Emissions from Fossil Fuel Combustion by Fuel Type

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15

Adjusted Consumption (TBtu)a Emissionsb (Tg CO2 Eq.) from Energy Use

Fuel Type Res. Comm. Ind. Trans. Elec. Terr. Total Res. Comm. Ind. Trans. Elec. Terr. Total

Total Coal 25.6 116.6 1,554.6 NE 16,465.6 8.8 18,171.1 2.5 11.3 147.4 NE 1,569.6 0.8 1,731.6 

Residential Coal 25.6 25.6 2.5 2.5 

Commercial Coal 116.6 116.6 11.3 11.3 

Industrial Other Coal 1,554.6 1,554.6 147.4 147.4 

Transportation Coal NE NE NE

Electric Power Coal 16,465.6 16,465.6 1,569.6 1,569.6 

U.S. Territory Coal (bit) 8.8 8.8 0.8 0.8 

Natural Gas 4,804.6 2,871.2 8,125.3 608.1 3,511.5 19,920.7 254.5 152.1 430.5 32.2 186.0 1,055.4 

Total Petroleum 1,365.8 788.9 3,758.7 20,442.6 990.7 444.9 27,791.7 96.5 57.3 279.5 1,470.4 75.5 32.5 2,011.6 

Asphalt & Road Oil

Aviation Gasoline 41.1 41.1 2.8 2.8 

Distillate Fuel Oil 931.4 481.7 1,028.5 3,665.7 73.5 91.8 6,272.6 68.9 35.6 76.1 271.1 5.4 6.8 463.9 

Jet Fuel 2,343.8 NA 61.3 2,405.1 166.6 4.4 171.0 

Kerosene 65.0 11.1 9.8 3.3 89.2 4.8 0.8 0.7 0.2 6.5 

LPG 369.4 106.9 441.8 19.4 11.9 949.4 22.8 6.6 27.3 1.2 0.7 58.7 

Lubricants

Motor Gasoline 13,972.5 122.1 14,094.7 998.6 8.7 1,007.4 

Residual Fuel 189.1 323.9 400.1 872.2 154.6 1,939.8 14.2 24.3 30.0 65.5 11.6 145.7 

Other Petroleum

AvGas Blend Components 0.2 0.2 0.0 0.0 

Crude Oil 27.4 27.4 2.0 2.0 

MoGas Blend Components 75.7 75.7 5.4 5.4 

Misc. Products

Naphtha (<401 deg. F)

Other Oil (>401 deg. F)

Pentanes Plus 161.3 161.3 11.3 11.3 

Petroleum Coke 0.1 626.7 45.0 671.8 0.0 64.0 4.6 68.6 

Still Gas 1,418.4 1,418.4 94.6 94.6 

Special Naphtha

Unfinished Oils (354.8) (354.8) (26.3) (26.3)

Waxes

Geothermal 55.1 55.1 0.4 0.4 

Total Coal 6,196.0 3,776.7 13,438.6 21,050.7 21,022.9 453.7 65,938.6 353.5 220.6 857.4 1,502.7 1,831.5 33.3 4,799.0 

a Expressed as gross calorific values (i.e., higher heating values). Adjustments include biofuels, conversion of fossil fuels, non-energy use (see Table A-34), and international bunker fuel consumption (see Table A-35).

b Consumption and/or emissions of select fuels are shown as negative due to differences in EIA energy balancing accounting. These are designated with parentheses. 

NE (Not Estimated)

NA (Not Available)
A-54 Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2012

Table A-32: 1991 Energy Consumption Data and CO2 Emissions from Fossil Fuel Combustion by Fuel Type

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15

Adjusted Consumption (TBtu)a Emissionsb (Tg CO2 Eq.) from Energy Use

Fuel Type Res. Comm. Ind. Trans. Elec. Terr. Total Res. Comm. Ind. Trans. Elec. Terr. Total

Total Coal 25.4 115.5 1,602.7 NE 16,249.7 7.7 18,001.0 2.4 11.1 152.1 NE 1,548.2 0.7 1,714.6 

Residential Coal 25.4 25.4 2.4 2.4 

Commercial Coal 115.5 115.5 11.1 11.1 

Industrial Other Coal 1,602.7 1,602.7 152.1 152.1 

Transportation Coal NE NE NE

Electric Power Coal 16,249.7 16,249.7 1,548.2 1,548.2 

U.S. Territory Coal (bit) 7.7 7.7 0.7 0.7 

Natural Gas 4,667.2 2,795.4 7,827.8 620.3 3,377.4 19,288.1 247.3 148.1 414.7 32.9 178.9 1,021.8 

Total Petroleum 1,381.5 903.6 3,480.5 19,715.8 1,198.3 425.4 27,105.1 97.5 65.6 259.2 1,414.7 90.7 30.9 1,958.6 

Asphalt & Road Oil

Aviation Gasoline 41.7 41.7 2.9 2.9 

Distillate Fuel Oil 931.0 517.7 1,050.8 3,449.7 83.6 71.4 6,104.1 68.9 38.3 77.7 255.1 6.2 5.3 451.4 

Jet Fuel 2,373.6 NA 78.2 2,451.8 168.8 5.6 174.4 

Kerosene 72.3 12.1 11.4 2.8 98.6 5.3 0.9 0.8 0.2 7.2 

LPG 378.1 108.2 342.2 21.1 13.8 863.5 23.3 6.7 21.1 1.3 0.9 53.3 

Lubricants

Motor Gasoline 53.7 122.0 13,605.3 124.7 13,905.6 3.8 8.7 969.7 8.9 991.1 

Residual Fuel 211.9 270.9 224.4 1,085.3 134.6 1,927.2 15.9 20.3 16.9 81.5 10.1 144.7 

Other Petroleum

AvGas Blend Components (0.1) (0.1) (0.0) (0.0)

Crude Oil 39.0 39.0 2.9 2.9 

MoGas Blend Components (25.9) (25.9) (1.8) (1.8)

Misc. Products

Naphtha (<401 deg. F)

Other Oil (>401 deg. F)

Pentanes Plus 147.0 147.0 10.3 10.3 

Petroleum Coke 587.6 29.3 616.9 60.0 3.0 63.0 

Still Gas 1,385.9 1,385.9 92.5 92.5 

Special Naphtha

Unfinished Oils (450.2) (450.2) (33.3) (33.3)

Waxes

Geothermal 54.5 54.5 0.4 0.4 

Total Coal 6,074.0 3,814.5 12,911.1 20,336.1 20,879.8 433.2 64,448.7 347.2 224.8 826.0 1,447.6 1,818.2 31.6 4,695.4 

a Expressed as gross calorific values (i.e., higher heating values). Adjustments include biofuels, conversion of fossil fuels, non-energy use (see Table A-34), and international bunker fuel consumption (see Table A-35).

b Consumption and/or emissions of select fuels are shown as negative due to differences in EIA energy balancing accounting. These are designated with parentheses. 

NE (Not Estimated)

NA (Not Available)
A-55

Table A- 33: 1990 Energy Consumption Data and CO2 Emissions from Fossil Fuel Combustion by Fuel Type

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15

Adjusted Consumption (TBtu)a Emissionsb (Tg CO2 Eq.) from Energy Use

Fuel Type Res. Comm. Ind. Trans. Elec. Terr. Total Res. Comm. Ind. Trans. Elec. Terr. Total

Total Coal 31.1 124.5 1,640.5 NE 16,261.0 7.0 18,064.0 3.0 12.0 155.3 NE 1,547.6 0.6 1,718.4 

Residential Coal 31.1 31.1 3.0 3.0 

Commercial Coal 124.5 124.5 12.0 12.0 

Industrial Other Coal 1,640.5 1,640.5 155.3 155.3 

Transportation Coal NE NE NE

Electric Power Coal 16,261.0 16,261.0 1,547.6 1,547.6 

U.S. Territory Coal (bit) 7.0 7.0 0.6 0.6 

Natural Gas 4,490.9 2,682.2 7,716.4 679.9 3,308.5 18,877.9 238.0 142.1 408.9 36.0 175.3 1,000.3 

Total Petroleum 1,375.2 891.4 3,780.5 20,326.1 1,289.4 374.8 28,037.5 97.4 64.9 280.9 1,457.9 97.5 27.2 2,025.9 

Asphalt & Road Oil

Aviation Gasoline 45.0 45.0 3.1 3.1 

Distillate Fuel Oil 959.2 525.4 1,098.5 3,554.8 96.5 74.0 6,308.4 70.9 38.9 81.2 262.9 7.1 5.5 466.5 

Jet Fuel 2,590.1 NA 61.0 2,651.1 184.2 4.3 188.6 

Kerosene 63.9 11.8 12.3 2.6 90.6 4.7 0.9 0.9 0.2 6.6 

LPG 352.1 102.3 380.2 22.9 14.4 871.9 21.8 6.3 23.5 1.4 0.9 53.9 

Lubricants

Motor Gasoline 22.1 36.7 13,813.0 101.0 13,972.8 1.6 2.6 983.7 7.2 995.1 

Residual Fuel 229.8 364.1 300.3 1,162.6 121.8 2,178.7 17.3 27.3 22.6 87.3 9.2 163.6 

Other Petroleum

AvGas Blend Components 0.2 0.2 0.0 0.0 

Crude Oil 50.9 50.9 3.8 3.8 

MoGas Blend Components 53.7 53.7 3.8 3.8 

Misc. Products

Naphtha (<401 deg. F)

Other Oil (>401 deg. F)

Pentanes Plus 125.2 125.2 8.8 8.8 

Petroleum Coke 591.2 30.4 621.5 60.4 3.1 63.5 

Still Gas 1,436.5 1,436.5 95.8 95.8 

Special Naphtha

Unfinished Oils (369.0) (369.0) (27.3) (27.3)

Waxes

Geothermal 52.7 52.7 0.4 0.4 

Total Coal 5,897.2 3,698.1 13,137.3 21,006.0 20,911.6 381.9 65,032.0 338.3 219.0 845.1 1,494.0 1,820.8 27.9 4,745.1 

a Expressed as gross calorific values (i.e., higher heating values). Adjustments include biofuels, conversion of fossil fuels, non-energy use (see Table A-34), and international bunker fuel consumption (see Table A-35).

b Consumption and/or emissions of select fuels are shown as negative due to differences in EIA energy balancing accounting. These are designated with parentheses. 

NE (Not Estimated)

NA (Not Available)
A-56 Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2012

Table A-34: Unadjusted Non-Energy Fuel Consumption (TBtu)

Sector/Fuel Type 1990 1995 1996 1997 1998 1999 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012

Industry 4,544.0 5,089.7 5,151.0 5,376.1 5,632.6 5,843.7 5,576.8 5,263.7 5,425.7 5,342.9 5,847.8 5,483.3 5,470.0 5,225.2 4,770.3 4,510.2 4,764.6 4,729.4 4,629.1

Industrial Coking Coal + 37.8 24.1 0.0 10.9 40.1 53.6 24.8 40.3 51.9 167.8 80.5 62.9 2.3 29.2 6.4 64.8 60.8 122.4

Industrial Other Coal 8.2 11.3 11.4 11.2 10.4 11.1 12.4 11.3 12.0 11.9 11.9 11.9 11.9 11.9 11.9 11.9 10.3 10.3 10.3

Natural Gas to Chemical 

Plants, Other Uses 305.9 371.0 388.7 406.4 426.6 413.5 401.7 391.8 380.7 345.3 306.6 270.4 233.4 233.6 233.6 233.6 311.8 311.8 311.8

Asphalt & Road Oil 1,170.2 1,178.2 1,175.9 1,223.6 1,262.6 1,324.4 1,275.7 1,256.9 1,240.0 1,219.5 1,303.8 1,323.2 1,261.2 1,197.0 1,012.0 873.1 877.8 859.5 826.7

LPG 1,201.4 1,586.9 1,652.0 1,670.4 1,744.4 1,820.7 1,759.3 1,642.3 1,766.3 1,701.6 1,768.5 1,659.5 1,734.6 1,726.7 1,596.6 1,748.0 1,901.6 1,996.1 2,003.9

Lubricants 186.3 177.8 172.5 182.3 190.8 192.8 189.9 174.0 171.9 159.0 161.0 160.2 156.1 161.2 149.6 134.5 149.5 141.8 130.5

Pentanes Plus 125.2 169.0 177.5 164.5 147.0 182.5 171.6 131.6 111.9 110.4 111.2 98.1 70.1 89.7 76.5 63.8 77.7 27.3 45.9

Naphtha (<401 deg. F) 347.8 373.0 479.3 536.4 584.0 502.1 613.5 493.7 582.6 613.0 749.4 698.7 628.9 562.5 477.2 471.9 490.6 487.3 453.9

Other Oil (>401 deg. F) 753.9 801.0 729.7 861.2 818.7 811.1 722.2 662.5 632.1 699.4 779.5 708.0 790.6 744.1 647.8 424.8 452.5 388.5 287.2

Still Gas 36.7 47.9 2.2 12.1 6.2 23.0 17.0 49.3 61.7 59.0 62.9 67.7 57.2 44.2 47.3 133.9 147.8 163.6 161.1

Petroleum Coke 123.1 120.6 118.6 87.5 150.8 216.0 98.7 174.3 145.8 122.8 218.3 186.9 213.6 201.2 225.1 180.7 61.0 62.4 66.3

Special Naphtha 107.1 70.8 74.5 72.3 107.3 145.4 97.4 78.5 102.4 80.5 51.0 62.5 70.1 78.0 84.9 46.2 26.1 22.6 14.7

Other (Wax/Misc.)

Distillate Fuel Oil 7.0 6.8 6.8 6.8 11.7 11.7 11.7 11.7 11.7 11.7 11.7 11.7 17.5 17.5 17.5 17.5 17.5 17.5 17.5

Waxes 33.3 40.6 48.7 43.7 42.4 37.4 33.1 36.3 32.2 31.1 30.8 31.4 26.2 21.9 19.1 12.2 17.1 15.1 15.3

Miscellaneous Products 137.8 97.1 89.0 97.8 119.0 111.9 119.2 124.9 134.2 126.0 113.4 112.8 136.0 133.5 142.0 151.8 158.7 164.7 161.6

Transportation 176.0 167.9 163.0 172.1 180.2 182.1 179.4 164.3 162.4 150.1 152.1 151.3 147.4 152.2 141.3 127.1 141.2 133.9 123.2

Lubricants 176.0 167.9 163.0 172.1 180.2 182.1 179.4 164.3 162.4 150.1 152.1 151.3 147.4 152.2 141.3 127.1 141.2 133.9 123.2

U.S. Territories 86.7 90.8 121.7 131.6 135.0 139.3 152.2 80.3 140.2 123.5 110.8 121.9 133.4 108.4 132.1 59.6 123.6 123.6 123.6

Lubricants 0.7 2.0 1.5 2.5 1.3 1.4 3.1 0.0 3.0 4.9 5.1 4.6 6.2 5.9 2.7 1.0 1.0 1.0 1.0

Other Petroleum (Misc. 

Prod.) 86.0 88.8 120.2 129.1 133.8 138.0 149.1 80.3 137.2 118.6 105.7 117.3 127.2 102.5 129.4 58.5 122.6 122.6 122.6

Total 4,806.7 5,348.5 5,435.7 5,679.8 5,947.9 6,165.1 5,908.3 5,508.4 5,728.3 5,616.5 6,110.7 5,756.6 5,750.8 5,485.9 5,043.7 4,696.8 5,029.4 4,987.0 4,876.0

Note: These values are unadjusted non-energy fuel use provided by EIA. They have not yet been adjusted to remove petroleum feedstock exports and processes accounted for in the Industrial Processes Chapter.

+ Does not exceed 0.05 TBtu.

Table A-35: International Bunker Fuel Consumption (TBtu)

Fuel Type 1990 1995 1996 1997 1998 1999 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012

Marine Residual Fuel Oil 715.7 523.2 536.4 575.2 594.8 489.7 444.1 426.0 448.9 471.8 553.1 581.0 599.4 607.5 654.6 604.8 619.8 518.4 459.5 

Marine Distillate Fuel Oil & 

Other 158.0 125.7 114.1 125.5 158.8 113.6 85.9 72.4 82.6 103.9 143.6 126.9 119.3 111.3 122.2 111.0 128.2 107.4 91.7 

Aviation Jet Fuel 539.4 703.4 718.3 754.4 748.8 796.9 880.1 799.7 774.8 783.0 797.7 853.1 855.6 872.7 796.8 749.1 865.4 919.9 916.3 

Total 1,413.1 1,352.3 1,368.8 1,455.1 1,502.4 1,400.3 1,410.0 1,298.1 1,306.3 1,358.7 1,494.4 1,561.0 1,574.2 1,591.5 1,573.6 1,464.9 1,613.4 1,545.7 1,467.4 

Note: Further information on the calculation of international bunker fuel consumption of aviation jet fuel is provided in Annex 3.3: Methodology for Estimating Emissions from Commercial Aircraft Jet Fuel Consumption.
A-57

Table A- 36: Key Assumptions for Estimating CO2 Emissions

Fuel Type

C Content Coefficient 

(Tg C/QBtu)

Coal

Residential Coal [a]

Commercial Coal [a]

Industrial Coking Coal [a]

Industrial Other Coal [a]

Electric Power Coal [a]

U.S. Territory Coal (bit) 25.14

Pipeline Natural Gas [a]

Flare Gas a 14.92

Petroleum

Asphalt & Road Oil 20.55

Aviation Gasoline 18.86

Distillate Fuel Oil No. 1 19.98

Distillate Fuel Oil No. 2b 20.17

Distillate Fuel Oil No. 4 20.47

Jet Fuel [a]

Kerosene 19.96

LPG (energy use) [a]

LPG (non-energy use) [a]

Lubricants 20.20

Motor Gasoline [a]

Residual Fuel Oil No. 5 19.89

Residual Fuel Oil No. 6 b 20.48

Other Petroleum

AvGas Blend Components 18.87

Crude Oil [a]

MoGas Blend Components [a]

Misc. Products [a]

Misc. Products (Territories) 20.00

Naphtha (<401 deg. F) 18.55

Other Oil (>401 deg. F) 20.17

Pentanes Plus 19.10

Petroleum Coke 27.85

Still Gas 18.20

Special Naphtha 19.74

Unfinished Oils [a]

Waxes 19.80

Geothermal 2.05

a Flare gas is not used in the CO2 from fossil fuel combustion calculations and is presented for informational purposes only.

b Distillate fuel oil No.2 and residual fuel oil No. 6 are used in the CO2 from fossil fuel combustion calculations, and other oil types are presented for informational 

purposes only. An additional discussion on the derivation of these carbon content coefficients is presented in Annex 2.2.

Sources: C coefficients from EIA (2009b) and EPA 2010a. 

[a] These coefficients vary annually due to fluctuations in fuel quality (see Table A- 37 )
A-58 Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2012

Table A- 37: Annually Variable C Content Coefficients by Year (Tg C/QBtu)

Fuel Type 1990 1995 1996 1997 1998 1999 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012

Residential Coal 26.20 26.13 26.04 25.90 26.07 25.98 26.01 26.00 25.98 26.04 25.91 26.09 26.29 25.94 25.71* 25.71* 25.71* 25.71* 25.71*

Commercial Coal 26.00 26.13 26.04 25.90 26.07 25.98 26.01 26.00 25.98 26.04 25.91 26.09 26.29 25.94 25.71 25.71 25.71 25.71 25.71 

Industrial Coking Coal 31.00 31.00 31.00 31.00 31.00 31.00 31.00 31.00 31.00 31.00 31.00 31.00 31.00 31.00 31.00 31.00 31.00 31.00 31.00

Industrial Other Coal 25.82 25.80 25.75 25.75 25.79 25.80 25.74 25.66 25.57 25.55 25.56 25.80 25.84 25.82 25.82 25.82 25.82 25.82 25.82 

Electric Power Coal 25.96 25.93 25.93 25.93 25.95 25.98 26.00 26.00 26.05 26.09 26.10 26.09 26.04 26.05 26.05 26.05 26.05 26.05 26.05 

Pipeline Natural Gas 14.45 14.46 14.46 14.46 14.44 14.46 14.47 14.46 14.46 14.44 14.46 14.46 14.46 14.46 14.46 14.46 14.46 14.46 14.46 

LPG (energy use) 16.86 16.82 16.82 16.84 16.81 16.86 16.89 16.87 16.85 16.86 16.84 16.84 16.83 16.82 16.83 16.83 16.83 16.83 16.83 

LPG (non-energy use) 17.06 17.09 17.10 17.08 17.08 17.07 17.09 17.10 17.09 17.09 17.07 17.06 17.06 17.05 17.06 17.06 17.06 17.06 17.06 

Motor Gasoline 19.42 19.36 19.35 19.36 19.37 19.32 19.33 19.34 19.38 19.36 19.38 19.36 19.45 19.56 19.46 19.46 19.46 19.46 19.46 

Jet Fuel 19.40 19.34 19.70 19.70 19.70 19.70 19.70 19.70 19.70 19.70 19.70 19.70 19.70 19.70 19.70 19.70 19.70 19.70 19.70 

MoGas Blend Components 19.42 19.36 19.35 19.36 19.37 19.32 19.33 19.34 19.38 19.36 19.38 19.36 19.45 19.56 19.46 19.46 19.46 19.46 19.46 

Misc. Products 20.15 20.21 20.23 20.22 20.22 20.17 20.22 20.27 20.28 20.25 20.31 20.31 20.28 20.28 20.31 20.31 20.31 20.31 20.31 

Unfinished Oils 20.15 20.21 20.23 20.22 20.22 20.17 20.22 20.27 20.28 20.25 20.31 20.31 20.28 20.28 20.31 20.31 20.31 20.31 20.31 

Crude Oil 20.15 20.21 20.23 20.22 20.22 20.17 20.22 20.27 20.28 20.25 20.31 20.31 20.28 20.28 20.31 20.31 20.31 20.31 20.31 

*U.S. EIA discontinued collection of residential sector coal consumption data in 2008, because consumption of coal in the residential sector is extremely limited. Therefore, the number cited here is developed from 

commercial/institutional consumption. 

Source: EPA (2010a)

Table A-38: Electricity Consumption by End-Use Sector (Billion Kilowatt-Hours)

End-Use Sector 1990 1995 1996 1997 1998 1999 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012

Residential 924 1,043 1,083 1,076 1,130 1,145 1,192 1,202 1,265 1,276 1,292 1,359 1,352 1,392 1,380 1,364 1,446 1,423 1,375 

Commercial 838 953 980 1,027 1,078 1,104 1,159 1,191 1,205 1,199 1,230 1,275 1,300 1,336 1,336 1,307 1,330 1,328 1,327 

Industrial 1,070 1,163 1,186 1,194 1,212 1,230 1,235 1,159 1,156 1,181 1,186 1,169 1,158 1,154 1,141 1,044 1,103 1,124 1,123 

Transportation 5 5 5 5 5 5 5 6 6 7 7 8 7 8 8 8 8 8 7 

Total 2,837 3,164 3,254 3,302 3,425 3,484 3,592 3,557 3,632 3,662 3,716 3,811 3,817 3,890 3,865 3,724 3,886 3,883 3,832 

Note: Does not include the U.S. territories.

Source: EIA (2014)
A-59

2.2. Methodology for Estimating the Carbon Content of Fossil Fuels

This sub-annex presents the background and methodology for estimating the carbon (C) content of fossil fuels 

combusted in the United States. The C content of a particular fossil fuel represents the maximum potential emissions to 

the atmosphere if all C in the fuel is oxidized during combustion. The C content coefficients used in past editions of this 

report were developed using methods first outlined in the U.S. Energy Information Administration’s (EIA) Emissions of 

Greenhouse Gases in the United States: 1987-1992 (1994) and were developed primarily by EIA. For this report, EPA 

has updated many of the C content coefficients based on carbon dioxide emission factors developed for the Mandatory 

Reporting of Greenhouse Gases Rule, signed in September 2009 (EPA, 2009b, 2010). This sub-annex describes an 

updated methodology for estimating the C content of natural gas, and presents a time-series analysis of changes in U.S. C 

content coefficients for coal, petroleum products and natural gas. A summary of C content coefficients used in this report 

appears in Table A- 39.

Though the methods for estimating C contents for coal, natural gas, and petroleum products differ in their 

details, they each follow the same basic approach. First, because C coefficients are presented in terms of mass per unit 

energy (i.e., teragrams C per quadrillion Btu or Tg C/QBtu), those fuels that are typically described in volumetric units 

(petroleum products and natural gas) are converted to units of mass using an estimated density. Second, C contents are 

derived from fuel sample data, using descriptive statistics to estimate the C share of the fuel by weight. The heat content 

of the fuel is then estimated based on the sample data, or where sample data are unavailable or unrepresentative, by default 

values that reflect the characteristics of the fuel as defined by market requirements. A discussion of each fuel appears 

below. 

The C content of coal is described first because approximately one-third of all U.S. C emissions from fossil fuel 

combustion are associated with coal consumption. The methods and sources for estimating the C content of natural gas 

are provided next. Approximately one-fifth of U.S. greenhouse gas emissions from fossil fuel combustion are attributable 

to natural gas consumption. Finally, this sub-annex examines C contents of petroleum products. U.S. energy consumption 

statistics account for more than 20 different petroleum products.
A-60 Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2012

Table A- 39: Carbon Content Coefficients Used in this Report (Tg Carbon/QBtu)

Fuel Type 1990 1995 1996 1997 1998 1999 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012

Coal

Residential Coala 26.20 26.13 26.04 25.90 26.07 25.98 26.01 26.00 25.98 26.04 25.91 26.09 26.29 25.94 25.71* 25.71* 25.71* 25.71* 25.71*

Commercial Coala 26.20 26.13 26.04 25.90 26.07 25.98 26.01 26.00 25.98 26.04 25.91 26.09 26.29 25.94 25.71 25.71 25.71 25.71 25.71

Industrial Coking Coala 25.53 25.57 25.56 25.59 25.62 25.59 25.63 25.63 25.65 25.63 25.63 25.60 25.60 25.61 25.61 25.61 25.61 25.61 25.61

Industrial Other Coala 25.82 25.80 25.75 25.75 25.79 25.80 25.74 25.66 25.57 25.55 25.56 25.80 25.84 25.82 25.82 25.82 25.82 25.82 25.82

Utility Coala,b 25.96 25.93 25.93 25.93 25.95 25.98 26.00 26.00 26.05 26.09 26.10 26.09 26.04 26.05 26.05 26.05 26.05 26.05 26.05

Pipeline Natural Gasc 14.45 14.46 14.46 14.46 14.44 14.46 14.47 14.46 14.46 14.44 14.46 14.46 14.46 14.46 14.46 14.46 14.46 14.46 14.46

Flare Gas 15.31 15.31 15.31 15.31 15.31 15.31 15.31 15.31 15.31 15.31 15.31 15.31 15.31 15.31 15.31 15.31 15.31 15.31 15.31

Petroleum

Asphalt and Road Oil 20.55 20.55 20.55 20.55 20.55 20.55 20.55 20.55 20.55 20.55 20.55 20.55 20.55 20.55 20.55 20.55 20.55 20.55 20.55

Aviation Gasoline 18.86 18.86 18.86 18.86 18.86 18.86 18.86 18.86 18.86 18.86 18.86 18.86 18.86 18.86 18.86 18.86 18.86 18.86 18.86

Distillate Fuel Oil No. 1 19.98 19.98 19.98 19.98 19.98 19.98 19.98 19.98 19.98 19.98 19.98 19.98 19.98 19.98 19.98 19.98 19.98 19.98 19.98

Distillate Fuel Oil No. 2 20.17 20.17 20.17 20.17 20.17 20.17 20.17 20.17 20.17 20.17 20.17 20.17 20.17 20.17 20.17 20.17 20.17 20.17 20.17

Distillate Fuel Oil No. 4 20.47 20.47 20.47 20.47 20.47 20.47 20.47 20.47 20.47 20.47 20.47 20.47 20.47 20.47 20.47 20.47 20.47 20.47 20.47

Jet Fuela 19.40 19.34 19.70 19.70 19.70 19.70 19.70 19.70 19.70 19.70 19.70 19.70 19.70 19.70 19.70 19.70 19.70 19.70 19.70

Kerosene 19.96 19.96 19.96 19.96 19.96 19.96 19.96 19.96 19.96 19.96 19.96 19.96 19.96 19.96 19.96 19.96 19.96 19.96 19.96

LPG (energy use)c 16.86 16.82 16.82 16.84 16.81 16.86 16.89 16.87 16.85 16.86 16.84 16.84 16.83 16.82 16.83 16.83 16.83 16.83 16.83

LPG (non-energy use)c 17.06 17.09 17.10 17.08 17.08 17.07 17.09 17.10 17.09 17.09 17.07 17.06 17.06 17.05 17.06 17.06 17.06 17.06 17.06

Lubricants 20.20 20.20 20.20 20.20 20.20 20.20 20.20 20.20 20.20 20.20 20.20 20.20 20.20 20.20 20.20 20.20 20.20 20.20 20.20

Motor Gasolinec 19.42 19.36 19.35 19.36 19.37 19.32 19.33 19.34 19.38 19.36 19.38 19.36 19.45 19.56 19.46 19.46 19.46 19.46 19.46

Residual Fuel No. 5 19.89 19.89 19.89 19.89 19.89 19.89 19.89 19.89 19.89 19.89 19.89 19.89 19.89 19.89 19.89 19.89 19.89 19.89 19.89

Residual Fuel No. 6 20.48 20.48 20.48 20.48 20.48 20.48 20.48 20.48 20.48 20.48 20.48 20.48 20.48 20.48 20.48 20.48 20.48 20.48 20.48

Other Petroleum

Av. Gas Blend Comp. 18.87 18.87 18.87 18.87 18.87 18.87 18.87 18.87 18.87 18.87 18.87 18.87 18.87 18.87 18.87 18.87 18.87 18.87 18.87

Mo. Gas Blend Compc 19.42 19.36 19.35 19.36 19.37 19.32 19.33 19.34 19.38 19.36 19.38 19.36 19.45 19.56 19.46 19.46 19.46 19.46 19.46

Crude Oilc 20.15 20.21 20.23 20.22 20.22 20.17 20.22 20.27 20.28 20.25 20.31 20.31 20.28 20.28 20.31 20.31 20.31 20.31 20.31

Misc. Productsc 20.15 20.21 20.23 20.22 20.22 20.17 20.22 20.27 20.28 20.25 20.31 20.31 20.28 20.28 20.31 20.31 20.31 20.31 20.31

Misc. Products (Terr.) 20.15 20.21 20.23 20.22 20.22 20.17 20.22 20.27 20.28 20.25 20.31 20.31 20.28 20.28 20.31 20.31 20.31 20.31 20.31

Naphtha (<401 deg. F) 18.55 18.55 18.55 18.55 18.55 18.55 18.55 18.55 18.55 18.55 18.55 18.55 18.55 18.55 18.55 18.55 18.55 18.55 18.55

Other oil (>401 deg. F) 20.17 20.17 20.17 20.17 20.17 20.17 20.17 20.17 20.17 20.17 20.17 20.17 20.17 20.17 20.17 20.17 20.17 20.17 20.17

Pentanes Plus 19.10 19.10 19.10 19.10 19.10 19.10 19.10 19.10 19.10 19.10 19.10 19.10 19.10 19.10 19.10 19.10 19.10 19.10 19.10

Petroleum Coke 27.85 27.85 27.85 27.85 27.85 27.85 27.85 27.85 27.85 27.85 27.85 27.85 27.85 27.85 27.85 27.85 27.85 27.85 27.85

Still Gas 18.20 18.20 18.20 18.20 18.20 18.20 18.20 18.20 18.20 18.20 18.20 18.20 18.20 18.20 18.20 18.20 18.20 18.20 18.20

Special Naphtha 19.74 19.74 19.74 19.74 19.74 19.74 19.74 19.74 19.74 19.74 19.74 19.74 19.74 19.74 19.74 19.74 19.74 19.74 19.74

Unfinished Oilsc 20.15 20.21 20.23 20.22 20.22 20.17 20.22 20.27 20.28 20.25 20.31 20.31 20.28 20.28 20.31 20.31 20.31 20.31 20.31

Waxes 19.80 19.80 19.80 19.80 19.80 19.80 19.80 19.80 19.80 19.80 19.80 19.80 19.80 19.80 19.80 19.80 19.80 19.80 19.80

Other Wax and Misc. 19.80 19.80 19.80 19.80 19.80 19.80 19.80 19.80 19.80 19.80 19.80 19.80 19.80 19.80 19.80 19.80 19.80 19.80 19.80

Geothermal 2.05 2.05 2.05 2.05 2.05 2.05 2.05 2.05 2.05 2.05 2.05 2.05 2.05 2.05 2.05 2.05 2.05 2.05 2.05

*U.S. EIA discontinued collection of residential sector coal consumption data in 2008, because consumption of coal in the residential sector is extremely limited. Therefore, the number cited here is developed from 

commercial/institutional consumption. 
A-61

a C contents vary annually based on changes in annual mix of production and end-use consumption of coal from each producing state. 

b C content for utility coal used in the electric power calculations. All coefficients based on higher heating value. Higher heating value (gross heating value) is the total amount of heat released when a fuel is burned. Coal, 

crude oil, and natural gas all include chemical compounds of carbon and hydrogen. When those fuels are burned, the carbon and hydrogen combine with oxygen in the air to produce CO2 and water. Some of the energy 

released in burning goes into transforming the water into steam and is usually lost. The amount of heat spent in transforming the water into steam is counted as part of gross heat content. Lower heating value (net heating 

value), in contrast, does not include the heat spent in transforming the water into steam. Using a simplified methodology based on International Energy Agency defaults, higher heating value can be converted to lower 

heating value for coal and petroleum products by multiplying by 0.95 and for natural gas by multiplying by 0.90. Carbon content coefficients are presented in higher heating value because U.S. energy statistics are reported 

by higher heating value.

c C contents vary annually based on changes in fuel composition. 
A-62 Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2012

Coal

Approximately one-third of all U.S. CO2 emissions from fossil fuel combustion are associated with coal 

consumption. Although the IPCC guidelines provide C contents for coal according to rank, it was necessary to develop C 

content coefficients by consuming sector to match the format in which coal consumption is reported by EIA. Because the 

C content of coal varies by the state in which it was mined and by coal rank, and because the sources of coal for each 

consuming sector vary by year, the weighted average C content for coal combusted in each consuming sector also varies 

over time. A time series of C contents by coal rank and consuming sector appears in Table A- 40.

8

Methodology

The methodology for developing C contents for coal by consuming sector consists of four steps. An additional 

step has been taken to calculate C contents by coal rank to facilitate comparison with IPCC default values.

Step 1. Determine carbon contents by rank and by state of origin

C contents by rank and state of origin are estimated on the basis of 7,092 coal samples, 6,588 of which were 

collected by the U.S. Geological Survey (USGS 1998) and 504 samples that come from the Pennsylvania State University 

database (PSU 2010). These coal samples are classified according to rank and state of origin. For each rank in each state, 

the average heat content and C content of the coal samples are calculated based on the proximate (heat) and ultimate 

(percent carbon) analyses of the samples. Dividing the C content (reported in pounds CO2) by the heat content (reported 

in million Btu or MMBtu) yields an average C content coefficient. This coefficient is then converted into units of Tg 

C/QBtu. 

Step 2. Determine weighted average carbon content by state

C contents by rank and origin calculated in Step 1 are then weighted by the annual share of state production 

that was each rank. State production by rank is obtained from the EIA. This step yields a single carbon content per 

state that varies annually based on production. However, most coal-producing states produce only one rank of coal. 

For these states the weighted factor equals the carbon content calculated in Step 1 and is constant across the time 

series. 

Step 3. Allocate sectoral consumption by state of origin

U.S. energy statistics9 through 2007 provide data on the origin of coal used in four areas: 1) the electric 

power industry, 2) industrial coking, 3) all other industrial uses, and 4) the residential and commercial end-use 

sectors.10 Because U.S. energy statistics do not provide the distribution of coal rank consumed by each consuming 

sector, it is assumed that each sector consumes a representative mixture of coal ranks from a particular state that 

matches the mixture of all coal produced in that state during the year. Thus, the weighted state-level factor 

developed in Step 2 is applied. 

Step 4. Weight sectoral carbon contents to reflect the rank and state of origin of coal consumed

Sectoral C contents are calculated by multiplying the share of coal purchased from each state by the state’s 

weighted C content estimated in Step 2. The resulting partial C contents are then totaled across all states to generate a 

national sectoral C content.

Csector = Sstate1×Cstate1 + Sstate2×Cstate2 +.... + Sstate50×Cstate50

where,

 

8 For a comparison to earlier estimated carbon contents please see Chronology and Explanation of Changes in Individual Carbon 

Content Coefficients of Fossil Fuels near the end of this annex.

9 U.S. Energy Information Administration (EIA). Coal Distribution – Annual (2001-2008); and Coal Industry Annual (1990-2000).

10 Beginning in 2008, the EIA collects and reports data on commercial and institutional coal consumption, rather than residential and 

commercial consumption. Thus, the residential / commercial coal coefficient reported in Table A- 39 for 2009 represents the mix of coal 

consumed by commercial and institutional users. Currently, only an extremely small amount of coal is consumed in the U.S. Residential 

Sector. 
A-63

Csector = The C content by consuming sector;

Sstate = The portion of consuming sector coal consumption attributed to production from a given state; 

Cstate = The estimated weighted C content of all ranks produced in a given state.
A-64 Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2012

Table A- 40: Carbon Content Coefficients for Coal by Consuming Sector and Coal Rank (Tg C/QBtu) (1990-2012)

Consuming Sector 1990 1995 1996 1997 1998 1999 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012

Electric Power 25.96 25.93 25.93 25.93 25.95 25.98 26.00 26.00 26.05 26.09 26.10 26.09 26.04 26.05 26.05 26.05 26.05 26.05 26.05

Industrial Coking 25.53 25.57 25.56 25.59 25.62 25.59 25.63 25.63 25.65 25.63 25.63 25.60 25.60 25.61 25.61 25.61 25.61 25.61 25.61

Other Industrial 25.82 25.80 25.75 25.75 25.79 25.80 25.74 25.66 25.57 25.55 25.56 25.80 25.84 25.82 25.82 25.82 25.82 25.82 25.82

Residential/ Commercial 26.20 26.13 26.04 25.90 26.07 25.98 26.01 26.00 25.98 26.04 25.91 26.09 26.29 25.94 25.71 25.71 25.71 25.71 25.71

Coal Rank

Anthracite 28.28 28.28 28.28 28.28 28.28 28.28 28.28 28.28 28.28 28.28 28.28 28.28 28.28 28.28 28.28 28.28 28.28 28.28 28.28

Bituminous 25.38 25.42 25.43 25.43 25.43 25.44 25.45 25.46 25.46 25.45 25.45 25.45 25.45 25.45 25.44 25.44 25.44 25.44 25.44

Sub-bituminous 26.50 26.50 26.50 26.50 26.50 26.50 26.49 26.50 26.50 26.50 26.50 26.50 26.50 26.50 26.50 26.50 26.50 26.50 26.50

Lignite 26.58 26.59 26.58 26.59 26.59 26.60 26.61 26.62 26.63 26.62 26.62 26.62 26.62 26.64 26.65 26.65 26.65 26.65 26.65

a

In 2008, the EIA began collecting consumption data for commercial and institutional consumption rather than commercial and residential consumption.

Sources: C content coefficients calculated from USGS (1998) and PSU (2010); data presented in EPA (2010b). 
A-65

Step 5. Develop national-level carbon contents by rank for comparison to IPCC defaults

Although not used to calculate emissions, national-level C contents by rank are more easily compared to C 

contents of other countries than are sectoral C contents. This step requires weighting the state-level C contents by rank 

developed under Step 1 by overall coal production by state and rank. Each state-level C content by rank is multiplied by 

the share of national production of that rank that each state represents. The resulting partial C contents are then summed 

across all states to generate an overall C content for each rank.

Nrank = Prank1 × Crank1 + Prank2 × Crank2 +...+ Prankn× Crankn

where,

Nrank = The national C content by rank; 

Prank = The portion of U.S. coal production of a given rank attributed to each state; and

Crank = The estimated C content of a given rank in each state.

Data Sources

The ultimate analysis of coal samples was based on the 7,092 coal samples, 6,588 of which are from USGS 

(1998) and 504 that come from the Pennsylvania State University Coal Database (PSU 2010). Data contained in the 

USGS’s CoalQual Database are derived primarily from samples taken between 1973 and 1989, and were largely reported 

in State Geological Surveys. Data in the PSU Coal Database are mainly from samples collected by PSU since 1967 and 

are housed at the PSU Sample Bank. Only the subset of PSU samples that are whole-seam channel samples are included 

in the development of carbon factors in order to increase data accuracy.

Data on coal consumption by sector and state of origin, as well as coal production by state and rank, were 

obtained from EIA. The EIA’s Annual Coal Report is the source for state coal production by rank from 2001-2008. In 

prior years, the EIA reported this data in its Coal Industry Annual. Data for coal consumption by state of origin and 

consuming sector for 2001 to 2008 was obtained from the EIA’s Coal Distribution – Annual. For 1990-2000, end-use data 

was obtained from the Coal Industry Annual.

Uncertainty 

C contents vary considerably by state. Bituminous coal production and sub-bituminous coal production 

represented 47.3 percent and 46.1 percent of total U.S. supply in 2008, respectively. State average C content coefficients 

for bituminous coal vary from a low of 85.59 kg CO2 per MMBtu in Texas to a high of 105.21 kg CO2 per MMBtu in 

Montana. However, Texas bituminous coal is considered anomalous,11 has not been produced since 2004 and production 

since 1990 peaked at just 446,000 short tons in 1996. The next lowest average emission factor for bituminous coal is 

found in Western Kentucky (91.36 kg CO2 per MMBtu). In 2000, Montana produced no bituminous coal and Western 

Kentucky production accounted for just 4.5 percent of overall bituminous production. In 2008, more than 60 percent of 

bituminous coal was produced in three states: West Virginia, Kentucky (predominantly from the Eastern production 

region), and Pennsylvania, and this share has remained fairly constant since 1990. These three states show a variation in C 

content for bituminous coals of 0.7 percent, based on more than 2,000 samples (see Table A-41).

Similarly, the C content coefficients for sub-bituminous coal range from 91.29 kg CO2 per MMBtu in Utah to 

98.10 kg CO2 per MMBtu in Alaska. However, Utah has no recorded production of sub-bituminous coal since 1990. 

Production of sub-bituminous coal in Alaska has made up less than 0.7 percent of total sub-bituminous production since 

1990, with even this small share declining over time. Wyoming has represented between 75 percent and 87 percent of 

total sub-bituminous coal production in the United States in each year since 1990. Thus, the C content coefficient for 

Wyoming (97.22 kg CO2 per MMBtu), based on 455 samples, dominates the national average. 

The interquartile range of C content coefficients among samples of sub-bituminous coal in Wyoming was 1.5 

percent from the mean. Similarly, this range among samples of bituminous coal from West Virginia, Kentucky, and 

Pennsylvania was 1.2 percent or less for each state. The large number of samples and the low variability within the 

sample set of the states that represent the predominant source of supply of U.S. coal suggest that the uncertainty in this 

factor is very low, on the order of 1.0 percent.

 

11 See, for example: San Filipo, 1999. USGS. (U.S. Geological Survey Open-File Report 99-301), Ch. 4.
A-66 Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2012

For comparison, J. Quick (2010) completed an analysis similar in methodology to that used here, in order to 

generate national average carbon emission factors as well as county-level factors. This study’s rank-based national 

average factors have a maximum deviation from the factors developed in this Inventory report of -0.55 percent, which is 

for lignite (range: -0.55 to +0.1 percent). This corroboration further supports the assertion of minimal uncertainty in the 

application of the rank-based factors derived for the purposes of this Inventory. 

Table A-41: Variability in Carbon Content Coefficients by Rank Across States (Kilograms CO2 Per MMBtu)

State

Number of 

Samples Bituminous

Subbituminous Anthracite Lignite

Alabama 951 92.84 - - 99.10

Alaska 91 98.33 98.10 - 98.65

Arizona 15 93.94 97.34 - -

Arkansas 80 96.36 - - 94.97

Colorado 318 94.37 96.52 - 101.10

Georgia 35 95.01 - - -

Idaho 1 - 94.90 - -

Illinois 57 92.33 - - -

Indiana 146 92.65 - - -

Iowa 100 91.87 - - -

Kansas 29 90.91 - - -

Kentucky 897 92.61 - - -

Louisiana 1 - - - 96.01

Maryland 47 94.29 - - -

Massachusetts 3 - - 114.82 -

Michigan 3 92.88 - - -

Mississippi 8 - - - 98.19

Missouri 111 91.71 - - -

Montana 309 105.21 97.73 103.60 99.40

Nevada 2 94.41 - - 99.86

New Mexico 185 94.29 94.89 103.92 -

North Dakota 202 - 93.97 - 99.48

Ohio 674 91.84 - - -

Oklahoma 63 92.33 - - -

Pennsylvania 861 93.33 - 103.68 -

Tennessee 61 92.82 - - -

Texas 64 85.59 94.19 - 94.47

Utah 169 95.75 91.29 - -

Virginia 470 93.51 - 98.54 -

Washington 18 94.53 97.36 102.53 106.55

West Virginia 612 93.84 - - -

Wyoming 503 94.80 97.22 - -

U.S. Average 7,092 93.13 96.94 104.29 98.63

Notes: - Indicates No Sample Data Available. 

Sources: Calculated from USGS (1998), and PSU (2010); data presented in EPA (2010). 

Natural Gas

Natural gas is predominantly composed of methane, which is 75 percent C by weight and contains 14.2 Tg 

C/QBtu (higher heating value), but it may also contain many other compounds that can lower or raise its overall C content. 

These other compounds may be divided into two classes: 1) natural gas liquids (NGLs), and 2) non-hydrocarbon gases. 

The most common NGLs are ethane (C2H6), propane (C3H8), butane (C4H10), and, to a lesser extent, pentane (C5H12) and 

hexane (C6H14). Because the NGLs have more C atoms than CH4 (which has only one), their presence increases the 

overall C content of natural gas. NGLs have a commercial value greater than that of CH4, and therefore are usually 

separated from raw natural gas at gas processing plants and sold as separate products. Ethane is typically used as a 
A-67

petrochemical feedstock, propane and butane have diverse uses, and natural gasoline12 contributes to the gasoline/naphtha 

"octane pool," used primarily to make motor gasoline. 

Raw natural gas can also contain varying amounts of non-hydrocarbon gases, such as CO2, nitrogen, helium and 

other noble gases, and hydrogen sulfide. The share of non-hydrocarbon gases is usually less than 5 percent of the total, 

but there are individual natural gas reservoirs where the share can be much larger. The treatment of non-hydrocarbon 

gases in raw gas varies. Hydrogen sulfide is always removed. Inert gases are removed if their presence is substantial 

enough to reduce the energy content of the gas below pipeline specifications (see Step 1, below). Otherwise, inert gases 

will usually be left in the natural gas. Because the raw gas that is usually flared (see Step 2, below) contains NGLs and 

CO2, it will typically have a higher overall C content than gas that has been processed and moved to end-use customers via 

transmission and distribution pipelines. 

Methodology

The methodology for estimating the C contents of pipeline and flared natural gas can be described in five steps.

Step 1. Define pipeline-quality natural gas

In the United States, pipeline-quality natural gas is required to have an energy content greater than 970 Btu per 

cubic foot, but less than 1,100 Btu per cubic foot. Hydrogen sulfide content must be negligible. Typical pipeline-quality 

natural gas is about 95 percent CH4, 3 percent NGLs, and 2 percent non-hydrocarbon gases, of which approximately half is 

CO2. 

However, there remains a range of gas compositions that are consistent with pipeline specifications. The 

minimum C content coefficient for natural gas would match that for pure CH4, which equates to an energy content of 

1,005 Btu per standard cubic foot. Gas compositions with higher or lower Btu content tend to have higher C emission 

factors, because the "low" Btu gas has a higher content of inert gases (including CO2 offset with more NGLs), while 

"high" Btu gas tends to have more NGLs. 

Step 2. Define flared gas

Every year, a certain amount of natural gas is flared in the United States. There are several reasons that gas is 

flared:

 There may be no market for some batches of natural gas, the amount may be too small or too variable, or the 

quality might be too poor to justify treating the gas and transporting it to market (such is the case when gas 

contains large shares of CO2). Most natural gas that is flared for these reasons is "rich" associated gas, with 

relatively high energy content, high NGL content, and a high C content. 

 Gas treatment plants may flare substantial volumes of natural gas because of "process upsets," because the gas is 

"off spec," or possibly as part of an emissions control system. Gas flared at processing plants may be of variable 

quality. 

Data on the energy content of flare gas, as reported by states to EIA, indicate an average energy content of 1,130 

Btu per standard cubic foot (EIA 1994). Flare gas may have an even higher energy content than reported by EIA since 

rich associated gas can have energy contents as high as 1,300 to 1,400 Btu per cubic foot.

Step 3. Determine a relationship between carbon content and heat content

A relationship between C content and heat content may be used to develop a C content coefficient for natural gas 

consumed in the United States. In 1994, EIA examined the composition (including C contents) of 6,743 samples of 

pipeline-quality natural gas from utilities and/or pipeline companies in 26 cities located in 19 states. To demonstrate that 

these samples were representative of actual natural gas "as consumed" in the United States, their heat content was 

compared to that of the national average. For the most recent year, the average heat content of natural gas consumed in the 

United States was 1,029 Btu per cubic foot, and has varied by less than 1 percent (1,027 to 1,029 Btu per cubic foot) over 

the past 5 years. Meanwhile, the average heat content of the 6,743 samples was 1,027 Btu per cubic foot, and the median 

heat content was 1,031 Btu per cubic foot. Thus, the average heat content of the sample set falls well within the typical 

 

12 A term used in the gas processing industry to refer to a mixture of liquid hydrocarbons (mostly pentanes and heavier hydrocarbons) 

extracted from natural gas. 
A-68 Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2012

range of natural gas consumed in the United States, suggesting that these samples continue to be representative of natural 

gas “as consumed” in the United States. The average and median composition of these samples appear in Table A-42.

Table A-42: Composition of Natural Gas (Percent)

Compound Average Median

Methane 93.07 95.00

Ethane 3.21 2.79

Propane 0.59 0.48

Higher Hydrocarbons 0.32 0.30

Non-hydrocarbons 2.81 1.43

Higher Heating Value (Btu per cubic foot) 1,027 1,031

Source: Gas Technology Institute (1992). 

Carbon contents were calculated for a series of sub-samples based on their CO2 content and heat content. Carbon 

contents were calculated for the groups of samples with less than 1.0 percent (n=5,181) and less than 1.5 percent CO2 only 

(n=6,522) and those with less than 1.0 or 1.5 percent CO2 and less than 1,050 Btu/cf (n=4,888 and 6,166, respectively). 

These stratifications were chosen to exclude samples with CO2 content and heat contents outside the range of pipelinequality natural gas. In addition, hexane was removed from the samples since it is usually stripped out of raw natural gas 

before delivery because it is a valuable natural gas liquid used as a feedstock for gasoline. The average carbon contents 

for the four separate sub-samples are shown below in Table A-43.

Table A-43: Carbon Content of Pipeline-Quality Natural Gas by CO2 and Heat Content (Tg C/QBtu)

Sample Average Carbon Content

Full Sample 14.48

< 1.0% CO2 14.43

< 1.5% CO2 14.47

< 1.0 % CO2 and <1,050 Btu/cf 14.42

< 1.5 % CO2 and <1,050 Btu/cf 14.47

Source: EPA (2010).

Step 4. Apply carbon content coefficients developed in Step 3 to pipeline natural gas

A regression analysis was performed on the sub-samples in to further examine the relationship between carbon 

content and heat content. The regression used carbon content as the dependent variable and heat content as the 

independent variable. The resulting R-squared values13 for each of the sub-samples ranged from 0.79 for samples with

less than 1.5 percent CO2 and under 1,050 Btu/cf to 0.91 for samples containing less than 1.0 percent CO2 only. However, 

the sub-sample with less than 1.5 percent CO2 and 1,050 Btu/cf was chosen as the representative sample for two reasons. 

First, it most accurately reflects the range of CO2 content and heat content of pipeline quality natural gas. Secondly, the Rsquared value, although it is the lowest of the sub-groups tested, remains relatively high. This high R-squared indicates a 

low percentage of variation in C content as related to heat content. The regression for this sub-sample resulted in the 

following equation:

C Content = (0.011 × Heat Content) + 3.5341

This equation was used to estimate the annual predicted carbon content of natural gas from 1990 to 2010 based 

on the EIA’s national average pipeline-quality gas heat content for each year. The table of average C contents for each 

year is shown below in Table A-44.

 Table A-44: Carbon Content Coefficients for Natural Gas (Tg Carbon/QBtu)

Fuel Type 1990 1995 1996 1997 1998 1999 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012

Natural Gas 14.45 14.46 14.46 14.46 14.44 14.46 14.47 14.46 14.46 14.44 14.46 14.46 14.46 14.46 14.46 14.46 14.46 14.46 14.46

Source: EPA (2010)

 

13 R-squared represents the percentage of variation in the dependent variable (in this case carbon content) explained by variation in the 

independent variables.
A-69

Step 5. Apply carbon content coefficients developed in Step 3 to flare gas

Selecting a C content coefficient for flare gas was much more difficult than for pipeline natural gas, because of 

the uncertainty of its composition and of the combustion efficiency of the flare. Because EIA estimates the heat content of 

flare gas at 1,130 Btu per cubic foot, the average C content for samples with more than 1,100 Btu per cubic foot (n=18) 

was chosen as the relevant sub-sample from which to calculate a flare gas carbon content. The sample dataset did not 

include any samples with more than 1,130 Btu per cubic foot.

Hexane was not removed from flare gas samples since it is assumed that natural gas liquids are present in 

samples with higher heat contents. Carbon contents were calculated for each sample with a heat content of more than 

1,100 Btu per cubic foot. The simple average C content for the sample sub-set representing flare gas is shown below in

Table A-45.

 Table A-45: Carbon Content of Flare Gas (Tg C/QBtu)

Relevant Sub-Sample Average Carbon Content

>1,100 Btu/cf 15.31

Source: EPA (2010)

Data Sources

Natural gas samples were obtained from the Gas Technology Institute (1992). Average heat content data for 

natural gas consumed in the United States was taken from EIA (2009a).

Uncertainty

The assignment of C content coefficients for natural gas, and particularly for flare gas, requires more subjective 

judgment than the methodology used for coal. This subjective judgment may introduce additional uncertainty. 

Figure A-1 shows the relationship between the calculated C content for each natural gas sample and its energy 

content. This figure illustrates the relatively restricted range of variation in both the energy content (which varies by about 

6 percent from average) and the C emission coefficient of natural gas (which varies by about 5 percent). Thus, the 

knowledge that gas has been sold via pipeline to an end-use consumer allows its C emission coefficient to be predicted 

with an accuracy of 5.0 percent.
A-70 Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2012

Figure A-1: Carbon Content for Samples of Pipeline-Quality Natural Gas Included in the Gas Technology Institute

Database

Natural gas suppliers may achieve the same overall energy content from a wide variety of methane, higher 

hydrocarbon, and non-hydrocarbon gas combinations. Thus, the plot reveals large variations in C content for a single Btu 

value. In fact, the variation in C content for a single Btu value may be nearly as great as the variation for the whole 

sample. As a result, while energy content has some predictive value, the specific energy content does not substantially 

improve the accuracy of an estimated C content coefficient beyond the 5.0 percent offered with the knowledge that it is 

of pipeline-quality. 

The plot of C content also reveals other interesting anomalies. Samples with the lowest emissions coefficients 

tend to have energy contents of about 1,000 Btu per cubic foot. They are composed of almost pure CH4. Samples with a 

greater proportion of NGLs (e.g., ethane, propane, and butane) tend to have energy contents greater than 1,000 Btu per 

cubic foot, along with higher emissions coefficients. Samples with a greater proportion of inert gases tend to have lower 

energy content, but they usually contain CO2 as one of the inert gases and, consequently, also tend to have higher emission 

coefficients (see left side of Figure A-1). 

For the full sample (n=6,743), the average C content of a cubic foot of gas was 14.48 Tg C/QBtu (see Table A44). Additionally, a regression analysis using the full sample produced a predicted C content of 14.49 Tg C/QBtu based 

on a heat content of 1,029 Btu/cf (the average heat content in the U.S. for the most recent year). However, these two 

values include an upward influence on the resulting carbon content that is caused by inclusion in the sample set of the 

samples that contain large amounts of inert carbon dioxide and those samples with more than 1,050 Btu per cubic foot that 

contain an unusually large amount of NGLs. Because typical gas consumed in the United States does not contain such a 

large amount of carbon dioxide or natural gas liquids, a carbon content of 14.47 Tg C/QBtu, based on samples with less 

than 1.5 percent carbon dioxide and less than 1,050 Btu per cubic foot, better represents the pipeline-quality fuels typically 

consumed.
A-71

Petroleum

There are four critical determinants of the C content coefficient for a petroleum-based fuel: 

 The density of the fuel (e.g., the weight in kilograms of one barrel of fuel);

 The fraction by mass of the product that consists of hydrocarbons, and the fraction of non-hydrocarbon 

impurities;

 The specific types of “families” of hydrocarbons that make up the hydrocarbon portion of the fuel; and

 The heat content of the fuel.

Cfuel = (Dfuel× Sfuel) / Efuel

where,

Cfuel = The C content coefficient of the fuel;

Dfuel = The density of the fuel;

Sfuel = The share of the fuel that is C; and

Efuel = The heat content of the fuel.

Most of the density, carbon share or heat contents applied to calculate the carbon coefficients for petroleum 

products that are described in this sub-Annex and applied to this emissions inventory have been updated for this edition of 

the report. These changes have been made where necessary to increase the accuracy of the underlying data or to align the 

petroleum properties data used in this report with that developed for use in the Mandatory Reporting of Greenhouse Gases 

Rule (EPA 2009b).

Petroleum products vary between 5.6 degrees API gravity (dense products such as asphalt and road oil) and 247 

degrees (ethane).14 This is a range in density of 60 to 150 kilograms per barrel, or 50 percent. The variation in C content, 

however, is much smaller (5 to 7 percent) for products produced by standard distillation refining: ethane is 80 percent C 

by weight, while petroleum coke is 90 to 92 percent C. This tightly bound range of C contents can be explained by basic 

petroleum chemistry (see below). Additional refining can increase carbon contents. Calcined coke, for example, is formed 

by heat treating petroleum coke to about 1600 degrees Kelvin (calcining), to expel volatile materials and increase the 

percentage of elemental C. This product can contain as much as 97 to 99 percent carbon. Calcined coke is mainly used in 

the aluminum and steel industry to produce C anodes. 

Petroleum Chemistry

Crude oil and petroleum products are typically mixtures of several hundred distinct compounds, predominantly 

hydrocarbons. All hydrocarbons contain hydrogen and C in various proportions. When crude oil is distilled into 

petroleum products, it is sorted into fractions by the boiling temperature of these hundreds of organic compounds. Boiling 

temperature is strongly correlated with the number of C atoms in each molecule. Petroleum products consisting of 

relatively simple molecules and few C atoms have low boiling temperatures, while larger molecules with more C atoms 

have higher boiling temperatures. 

Products that boil off at higher temperatures are usually more dense, which implies greater C content as well. 

Petroleum products with higher C contents, in general, have lower energy content per unit mass and higher energy content 

per unit volume than products with lower C contents. Empirical research led to the establishment of a set of quantitative 

relationships between density, energy content per unit weight and volume, and C and hydrogen content. Figure A-2

compares C content coefficients calculated on the basis of the derived formula with actual C content coefficients for a 

range of crude oils, fuel oils, petroleum products, and pure hydrocarbons. The actual fuel samples were drawn from the 

sources described below in the discussions of individual petroleum products. 

 

14 API gravity is an arbitrary scale expressing the gravity or density of liquid petroleum products, as established by the American 

Petroleum Institute (API). The measuring scale is calibrated in terms of degrees API. The higher the API gravity, the lighter the 

compound. Light crude oils generally exceed 38 degrees API and heavy crude oils are all crude oils with an API gravity of 22 degrees or 

below. Intermediate crude oils fall in the range of 22 degrees to 38 degrees API gravity. API gravity can be calculated with the 

following formula: API Gravity = (141.5/Specific Gravity) – 131.5. Specific gravity is the density of a material relative to that of water. 

At standard temperature and pressure, there are 62.36 pounds of water per cubic foot, or 8.337 pounds water per gallon. 
A-72 Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2012

Figure A-2: Estimated and Actual Relationships Between Petroleum Carbon Content Coefficients and Hydrocarbon 

Density 

The derived empirical relationship between C content per unit heat and density is based on the types of 

hydrocarbons most frequently encountered. Petroleum fuels can vary from this relationship due to non-hydrocarbon 

impurities and variations in molecular structure among classes of hydrocarbons. In the absence of more exact information, 

this empirical relationship offers a good indication of C content. 

Non-hydrocarbon Impurities

Most fuels contain a certain share of non-hydrocarbon material. This is also primarily true of crude oils and fuel 

oils. The most common impurity is sulfur, which typically accounts for between 0.5 and 4 percent of the mass of most 

crude oils, and can form an even higher percentage of heavy fuel oils. Some crude oils and fuel oils also contain 

appreciable quantities of oxygen and nitrogen, typically in the form of asphaltenes or various acids. The nitrogen and 

oxygen content of crude oils can range from near zero to a few percent by weight. Lighter petroleum products have much

lower levels of impurities, because the refining process tends to concentrate all of the non-hydrocarbons in the residual oil 

fraction. Light products usually contain less than 0.5 percent non-hydrocarbons by mass. Thus, the C content of heavy 

fuel oils can often be several percent lower than that of lighter fuels, due entirely to the presence of non-hydrocarbons. 
A-73

Variations in Hydrocarbon Classes

Hydrocarbons can be divided into five general categories, each with a distinctive relationship between density 

and C content and physical properties. Refiners tend to control the mix of hydrocarbon types in particular products in 

order to give petroleum products distinct properties. The main classes of hydrocarbons are described below. 

Paraffins. Paraffins are the most common constituent of crude oil, usually comprising 60 percent by mass. 

Paraffins are straight-chain hydrocarbons with the general formula CnH2n+2. Paraffins include ethane (C2H6), propane 

(C3H8), butane (C4H10), and octane (C8H18). As the chemical formula suggests, the C content of the paraffins increases 

with their C number: ethane is 79.89 percent C by weight, octane 84.12 percent. As the size of paraffin molecules 

increases, the C content approaches the limiting value of 85.7 percent asymptotical (see Figure A-3).

Cycloparaffins. Cycloparaffins are similar to paraffins, except that the C molecules form ring structures rather 

than straight chains, and consequently require two fewer hydrogen molecules than paraffins. Cycloparaffins always have 

the general formula CnH2n and are 85.63 percent C by mass, regardless of molecular size. 

Olefins. Olefins are a very reactive and unstable form of paraffin: a straight chain with two carbon atoms double 

bonded together (thus are unsaturated) compared to the carbon atoms in a paraffin (which are saturated with hydrogen). 

They are never found in crude oil but are created in moderate quantities by the refining process. Gasoline, for example, 

may contain between 2 and 20 percent olefins. They also have the general formula CnH2n, and hence are also always 85.63 

percent C by weight. Propylene (C3H6), a common intermediate petrochemical product, is an olefin. 

Aromatics. Aromatics are very reactive hydrocarbons that are relatively uncommon in crude oil (10 percent or 

less). Light aromatics increase the octane level in gasoline, and consequently are deliberately created by catalytic 

reforming of heavy naphtha. Aromatics also take the form of ring structures with some double bonds between C atoms. 

The most common aromatics are benzene (C6H6), toluene (C7H8), and xylene (C8H10). The general formula for aromatics 

is CnH2n-6. Benzene is 92.26 percent C by mass, while xylene is 90.51 percent C by mass and toluene is 91.25 percent C by 

mass. Unlike the other hydrocarbon families, the C content of aromatics declines asymptotically toward 85.7 percent with 

increasing C number and density (see Figure A-3).

Polynuclear Aromatics. Polynuclear aromatics are large molecules with a multiple ring structure and few 

hydrogen atoms, such as naphthalene (C10H8 and 93.71 percent C by mass) and anthracene (C14H10 and 97.7 percent C). 

They are relatively rare but do appear in heavier petroleum products. 

Figure A-3 illustrates the share of C by weight for each class of hydrocarbon. Hydrocarbon molecules containing 

2 to 4 C atoms are all natural gas liquids; hydrocarbons with 5 to 10 C atoms are predominantly found in naphtha and 

gasoline; and hydrocarbon compounds with 12 to 20 C atoms comprise "middle distillates," which are used to make diesel 

fuel, kerosene and jet fuel. Larger molecules which can be vacuum distilled may be used as lubricants, waxes, and residual 

fuel oil or cracked and blended into the gasoline or distillate pools.
A-74 Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2012

Figure A-3: Carbon Content of Pure Hydrocarbons as a Function of Carbon Number 

If nothing is known about the composition of a particular petroleum product, assuming that it is 85.7 percent C 

by mass is not an unreasonable first approximation. Since denser products have higher C numbers, this guess would be 

most likely to be correct for crude oils and fuel oils. The C content of lighter products is more affected by the shares of 

paraffins and aromatics in the blend. 

Energy Content of Petroleum Products

The exact energy content (gross heat of combustion) of petroleum products is not generally known. EIA 

estimates energy consumption in Btu on the basis of a set of industry-standard conversion factors. These conversion 

factors are generally accurate to within 3 to 5 percent. 

Individual Petroleum Products

The United States maintains data on the consumption of more than 20 separate petroleum products and product 

categories. The C contents, heat contents, and density for each product are provided below in Table A-46. A description 

of the methods and data sources for estimating the key parameters for each individual petroleum product appears below.
A-75

Table A-46: Carbon Content Coefficients and Underlying Data for Petroleum Products

Fuel

2008 Carbon Content

(Tg C/QBtu)

Gross Heat of Combustion

(MMBtu/Barrel)

Density

(API Gravity)

Percent 

Carbon

Motor Gasoline 19.46 (See a) (See a) (See a) 

LPG(total) 16.97 (See b) (See b) (See b)

LPG (energy use) 16.83 (See b) (See b) (See b)

LPG (non-energy use) 17.06 (See b) (See b) (See b)

Jet Fuel 19.70 5.670 42.0 86.30

Distillate Fuel No. 1 19.98 5.822 35.3 86.40

Distillate Fuel No. 2 20.17 5.809 35.8 87.30

Distillate Fuel No. 4 20.47 6.135 23.2 86.47

Residual Fuel No. 5 19.89 5.879 33.0 85.67

Residual Fuel No. 6 20.48 6.317 15.5 84.67

Asphalt and Road Oil 20.55 6.636 5.6 83.47

Lubricants 20.20 6.065 25.7 85.80

Naphtha (< 400 deg. F)a 18.55 5.248 62.4 84.11 

Other Oils (>400 deg. F)a 20.17 5.825 35.8 87.30

Aviation Gas 18.86 5.048 69.0 85.00

Kerosene 19.96 5.825 35.3 86.40

Petroleum Coke 27.85 6.024 - 92.28

Special Naphtha 19.74 5.248 52.0 84.75

Petroleum Waxes 19.80 5.537 43.3 85.30

Still Gas 18.20 6.000 - 77.70

Crude Oil 20.31 5.800 31.2 85.49

Unfinished Oils 20.31 5.825 31.2 85.49

Miscellaneous Products 20.31 5.796 31.2 85.49

Pentanes Plus 19.10 4.620 81.3 83.63

a = Calculation of the carbon content coefficient for motor gasoline in 2008 uses separate higher heating values for conventional and reformulated gasoline of 

5.253 and 5.150, respectively (EIA 2008a). Densities and carbon shares (percent carbon) are annually variable and separated by both fuel formulation and 

grade, see Motor Gasoline and Blending Components, below, for details. 

b = LPG is a blend of multiple paraffinic hydrocarbons: ethane, propane, isobutane, and normal butane, each with their own heat content, density and C content, 

see Table A-49.

a Petrochemical feedstocks have been split into naphthas and other oils for this inventory report. Parameters presented are for naphthas with a boiling temperature less 

than 400 degrees Fahrenheit. Other oils are petrochemical feedstocks with higher boiling points. They are assumed to have the same characteristics as distillate fuel oil no. 

2.

- No sample data available

Sources: EIA (1994), EIA (2009a), EPA (2009b), and EPA (2010). 

Motor Gasoline and Motor Gasoline Blending Components

Motor gasoline is a complex mixture of relatively volatile hydrocarbons with or without small quantities of 

additives, blended to form a fuel suitable for use in spark-ignition engines.15 “Motor Gasoline” includes conventional 

gasoline; all types of oxygenated gasoline, including gasohol; and reformulated gasoline; but excludes aviation gasoline. 

Gasoline is the most widely used petroleum product in the United States, and its combustion accounts for nearly 

20 percent of all U.S. CO2 emissions. EIA collects consumption data (i.e., "petroleum products supplied" to end-users) for 

several types of finished gasoline over the 1990 through 2008 time period: regular, mid-grade and premium conventional 

gasoline (all years) and regular, mid-grade and premium reformulated gasoline (November 1994 to 2008). Leaded and 

oxygenated gasoline are not separately included in the data used for this report.16

 

15 Motor gasoline, as defined in ASTM Specification D 4814 or Federal Specification VV-G-1690C, is characterized as having a boiling 

range of 122 degrees to 158 degrees Fahrenheit at the 10-percent recovery point to 365 degrees to 374 degrees Fahrenheit at the 90-

percent recovery point. 

16 Oxygenated gasoline volumes are included in the conventional gasoline data provided by EIA from 2007 onwards. Leaded gasoline 

was included in total gasoline by EIA until October 1993.
A-76 Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2012

The American Society for Testing and Materials (ASTM) standards permit a broad range of densities for 

gasoline, ranging from 50 to 70 degrees API gravity, or 111.52 to 112.65 kilograms per barrel (EIA 1994), which implies a 

range of possible C and energy contents per barrel. Table A- 47 reflects changes in the density of gasoline over time and 

across grades and formulations of gasoline through 2008. 

Table A- 47: Motor Gasoline Density, 1990 – 2012 (Degrees API)

Fuel Grade 1990 1995 1996 1997 1998 1999 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012

Conventional - Winter Grade

 Low Octane 62.0 59.8 60.6 61.5 61.8 61.6 61.6 61.7 61.6 61.8 62.4 62.6 62.7 63.1 63.0 63.0 63.0 63.0 63.0

 High Octane 59.0 58.0 58.5 59.3 60.0 60.3 59.7 59.1 59.0 59.9 60.7 60.9 60.0 60.3 60.9 60.9 60.9 60.9 60.9

Conventional - Summer Grade

 Low Octane 58.2 56.1 56.9 57.1 57.6 57.7 56.8 57.2 56.5 56.8 57.4 57.9 57.8 57.5 58.6 58.6 58.6 58.6 58.6

 High Octane 55.5 55.1 55.3 56.4 55.7 57.4 55.8 55.5 55.7 56.0 57.0 57.0 57.4 56.9 58.0 58.0 58.0 58.0 58.0

Reformulated - Winter Grade

 Low Octane NA 61.9 62.3 62.1 62.7 62.7 62.7 62.6 61.9 62.1 62.7 62.8 62.3 62.1 62.4 62.4 62.4 62.4 62.4

 High Octane NA 59.9 60.8 62.1 61.4 61.0 61.1 61.0 61.8 61.9 61.8 61.8 61.7 62.1 62.5 62.5 62.5 62.5 62.5

Reformulated - Summer Grade

 Low Octane NA 58.5 58.0 58.8 58.4 58.4 58.4 58.8 58.2 59.1 58.1 58.4 58.7 58.5 59.1 59.1 59.1 59.1 59.1

 High Octane NA 56.7 57.8 58.4 58.5 57.8 58.3 58.2 58.0 58.7 58.9 58.1 59.0 59.3 59.8 59.8 59.8 59.8 59.8

Notes: NA – Not Applicable, fuel type was not analyzed.

Source: National Institute of Petroleum and Energy Research (1990 through 2012). 

The density of motor gasoline increased across all grades through 1994, partly as a result of the leaded gasoline 

phase-out. In order to maintain the “anti-knock” quality and octane ratings of gasoline in the absence of lead, the portion 

of aromatic hydrocarbons blended into gasoline through the refining process was increased. As discussed above, aromatic 

hydrocarbons have a lower ratio of hydrogen to C than other hydrocarbons typically found in gasoline, and therefore 

increase fuel density.

The trend in gasoline density was reversed beginning in 1996 with the development of fuel additives that raised 

oxygen content. In 1995, a requirement for reformulated gasoline in non-attainment areas implemented under the Clean 

Air Act Amendments further changed the composition of gasoline consumed in the United States. Through 2005, methyl 

tertiary butyl ether (MTBE), ethanol, ethyl tertiary butyl ether (ETBE) and tertiary amyl methyl ether (TAME) were added 

to reformulated and sometimes to conventional gasoline to boost its oxygen content, reduce its toxics impacts and increase 

its octane. The increased oxygen reduced the emissions of carbon monoxide and unburned hydrocarbons. These oxygenrich blending components are also much lower in C than standard gasoline. The average gallon of reformulated gasoline 

consumed in 2005 contained over 10 percent MTBE and 0.6 percent TAME (by volume). The characteristics of 

reformulated fuel additives appear in Table A-48.

Table A-48: Characteristics of Major Reformulated Fuel Additives

Additive Density (Degrees API) Carbon Share (Percent)

MTBE 58.6 68.13

ETBE 58.5 70.53

TAME 51.2 70.53

DIPE 62.7 70.53

Ethanol (100%) 45.8 52.14

Source: EPA, 2009b. 

Since 2005, due to concerns about the potential environmental consequences of the use of MTBE in fuels, there 

has been a shift away from the addition of MTBE, TAME, ETBE and DIPE and towards the use of ethanol as a fuel 

oxygenate.17 Ethanol, also called ethyl alcohol, is an anhydrous alcohol with molecular formula C2H5OH. Ethanol has a 

 

17 The annual motor gasoline carbon contents that are applied for this inventory do not include the carbon contributed by the 

ethanol contained in reformulated fuels. Ethanol is a biofuel, and net carbon fluxes from changes in biogenic carbon reservoirs in 

croplands are accounted for in the estimates for Land Use, Land-Use Change and Forestry.
A-77

lower carbon share than other oxygenates, approximately 52 percent compared to about 70 percent for MTBE and TAME. 

The density of ethanol was calculated by fitting density data at 10 degree intervals to a polynomial of order two and then 

using the fit to interpolate the value of the density at 15 degrees Celsius. A common fuel mixture of 10 percent denatured 

ethanol (denatured by 2 percent hydrocarbons) and 90 percent gasoline, known as E10, is widely used in the United States 

and does not require any modification to vehicle engines or fuel systems. The average gallon of reformulated alcohol 

blend gasoline in 2008 contained 8.6 percent ethanol (by volume). As of 2010, ten States require the use of ethanolblended fuel.18 Ethanol blends up to E85 (85 percent ethanol, 15 percent gasoline) are in use in the United States but can 

only be used in specially designed vehicles called flexible fuel vehicles (FFVs). Most ethanol fuel in the United States is 

produced using corn as feedstock,19 although production pathways utilizing agricultural waste, woody biomass and other 

resources are in development.

Methodology

Step 1. Disaggregate U.S. gasoline consumption by grade and type

Separate monthly data for U.S. sales to end users of finished gasoline by product grade and season for both 

standard gasoline and reformulated gasoline were obtained from the EIA.

Step 2. Develop carbon content coefficients for each grade and type

Annual C content coefficients for each gasoline grade, type and season are derived from four parameters for each 

constituent of the finished gasoline blend: the volumetric share of each constituent,20 the density of the constituent, share 

of the constituent21 that is C; and the energy content of a gallon of the relevant formulation of gasoline. The percent by 

mass of each constituent of each gasoline type was calculated using percent by volume data from NIPER and the density 

of each constituent. The ether additives listed in Table A-48 are accounted for in both reformulated fuels and conventional 

fuels, to the extent that they were present in the fuel. From 2006 onward, reformulated fuel mass percentages are 

calculated from their constituents, net of the share provided by ethanol. C content coefficients were then derived from the 

calculated percent by mass values by weighting the carbon share of each constituent by its contribution to the total mass of 

the finished motor gasoline product.

Step 3. Weight overall gasoline carbon content coefficient for consumption of each grade and type

The C content for each grade, type and season of fuel is multiplied by the share of annual consumption 

represented by the grade and fuel type during the relevant time period. Individual coefficients are then summed and 

totaled to yield an overall C content coefficient for each year.

Data Sources

Data for the density of motor gasoline were derived from the National Institute for Petroleum and Energy 

Research (NIPER) (1990 through 2009). Data on the characteristics of reformulated gasoline, including C share, were also 

taken from NIPER (1990 through 2009). 

Standard heat contents for motor gasoline of 5.253 MMBtu per barrel conventional gasoline and 5.150 MMBtu 

per barrel reformulated gasoline22 were adopted from EIA (2009a). 

Uncertainty

The uncertainty underlying the C content coefficients for motor gasoline has three underlying sources: the 

uncertainty in the averages published by NIPER, uncertainty in the C shares assumed in the EPA’s analysis to be 

representative of the constituent hydrocarbon classes within gasoline (aromatics, olefins and saturates) and uncertainty in 

the heat contents applied. 

 

18 Ethanol.org. http://www.ethanol.org/index.php?id=79&parentid=26. Retrieved 2-19-2010.

19 "Ethanol Market Penetration". Alternative Fuels and Advanced Vehicles Data Center, US DOE. 

http://www.afdc.energy.gov/afdc/ethanol/market.html. Retrieved 2-19-2010.

20 Calculations account for the properties of the individual constituents of gasoline, including, as applicable to the fuel grade and 

type: aromatics (excluding benzene), olefins, benzene, saturates, MTBE, TAME, ETBE, DIPE and ethanol.

21 Saturates are assumed to be octane and aromatics are assumed to be toluene.

22 The reformulated gasoline heat content is applied to both reformulated blends containing ethers and those containing ethanol.
A-78 Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2012

A variable number of samples are used each year to determine the average percent by volume share of each 

hydrocarbon within each grade, season and formulation of gasoline that are obtained from NIPER. The total number of 

samples analyzed for each seasonal NIPER report varies from approximately 730 to over 1,800 samples over the period 

from 1990 through 2008. The number of samples analyzed that underlie the calculation of the average make-up of each 

seasonal formulation and grade varies from approximately 50 to over 400, with the greatest number of samples each 

season being of conventional, regular or premium gasoline. Further, not all sample data submitted to NIPER contains data 

for each of the properties, such that the number of samples underlying each constituent average value for each season, 

grade and formulation may be variable within the single gasoline type (e.g., of the 1,073 samples for which some data was 

obtained for gasoline sold in Winter 1995 through 1996, benzene content was provided for all samples, while olefin, 

aromatic and saturate content was provided for just 736 of those samples). 

The distribution of sample origin collected for the NIPER report and the calculation of national averages are not 

reflective of sales volumes. The publication of simple, rather than sales-weighted averages to represent national average 

values increases the uncertainty in their application to the calculation of carbon content factors for the purposes of this 

inventory. Further, data for each sample is submitted voluntarily, which may also affect their representativeness. 

Additionally, because the simple average constituent shares are calculated based upon data that have been 

renormalized to account for the share of ethers and alcohols, total average volume shares may not equal 100 percent. 

The simple average for each hydrocarbon constituent is contained within a range of values that are as wide as -

63/+74.5 percent of the mean across the Winter 2007 through 2008 and -51.3/+49.6 percent across the Summer 2008 

samples of conventional, regular grade gasoline. However, these wide ranges exist for benzene, which generally accounts 

for only 1 percent, by volume, of each gallon. In contrast, saturates, the class of hydrocarbon that contribute the largest 

share, by volume, ranges only -6.5/+6.4 percent for the same set of Winter samples and -8.8/+15.7 percent for the Summer 

samples.

Secondly, EPA’s calculation of C content factors for each gasoline type includes the following assumptions: for 

the purposes of assigning a carbon share to each compound in the blend, aromatic content (other than benzene) is assumed 

to be toluene and saturated hydrocarbons are assumed to be octane. All olefins have the same carbon share because they 

all have a molecular formula in the form CnH2n, so the C share applied to the olefin portion of the total gasoline blend does 

not increase the level of uncertainty in the calculation. These assumptions are based upon the use of octane and octane 

isomers as the primary saturates and toluene as the primary non-benzene aromatic in U.S. motor gasoline blends. The 

octane rating of a particular blend is based upon the equivalent iso-octane to heptane ratio, which is achieved through 

significant octane content relative to the other saturates. Aside from benzene, U.S. gasolines will include toluene as a 

major aromatic component, so toluene may be assumed a reasonable representative of total non-benzene aromatic content 

(EPA 2009a).

For each hydrocarbon category, the assumed C content lies within a range of possible values for all such 

hydrocarbons. Among saturated hydrocarbons, the C share of octane (84.12 percent) is at the high end of the range while 

ethane is represents the low end of the range (79.89 percent C). Total saturates constitute from 40 to 95 percent by volume 

of a given gasoline blend. For aromatics, toluene (91.25 percent C) lies in the middle of the possible range. This range is 

bounded by cumene (89.94 percent C) and naphthalene (93.71 percent C). Total aromatics may make up between 3 and 

50 percent by volume of any given gasoline blend. The range of these potential values contributes to the uncertainty 

surrounding the final calculated C factors. 

However, as demonstrated above in Figure A-3, the amount of variation in C content of gasoline is restricted by 

the compounds in the fuel to 4 percent. Further, despite variation in sampling survey response, sample size and annually 

variable fuel formulation requirements, the observed variation in the annual weighted motor gasoline coefficients 

estimated for this inventory is 0.8 percent over 1990 through 2008. 

The third primary contributor to uncertainty is the assumed heat content. The heat contents are industry 

standards established many years ago. The heat contents are standard conversion factors used by EIA to convert 

volumetric energy data to energy units. Because the heat contents of fuels change over time, without necessarily and 

directly altering their volume, the conversion of known volumetric data to energy units may introduce bias. Thus, a more 

precise approach to estimating emissions factors would be to calculate C content per unit of volume, rather than per unit of 

energy. Adopting this approach, however, makes it difficult to compare U.S. C content coefficients with those of other 

nations. 

The changes in density of motor gasoline over the last decade suggest that the heat content of the fuels is also 

changing. However, that change within any season grade has been less than 1 percent over the decade. Of greater concern 
A-79

is the use of a standardized heat content across grades that show a variation in density of 1.5 percent from the mean for 

conventional gasoline and 1.0 percent for reformulated fuels.

Jet Fuel

Jet fuel is a refined petroleum product used in jet aircraft engines. There are two classes of jet fuel used in the 

United States: “naphtha-based” jet fuels and “kerosene-based” jet fuels. In 1989, 13 percent of U.S. consumption was 

naphtha-based fuel, with the remainder kerosene-based jet fuel. In 1993, the U.S. Department of Defense began a 

conversion from naphtha-based JP-4 jet fuel to kerosene-based jet fuel, because of the possibility of increased demand for 

reformulated motor gasoline limiting refinery production of naphtha-based jet fuel. By 1996, naphtha-based jet fuel 

represented less than one-half of one percent of all jet fuel consumption. The C content coefficient for jet fuel used in this 

report prior to 1996 represents a consumption-weighted combination of the naphtha-based and kerosene-based 

coefficients. From 1996 to 2008, only the kerosene-based portion of total consumption is considered significant.

Methodology

Step 1. Estimate the carbon content for naphtha-based jet fuels

Because naphtha-based jet fuels are used on a limited basis in the United States, sample data on its characteristics 

are limited. The density of naphtha-based jet fuel (49 degrees) was estimated as the central point of the acceptable API 

gravity range published by ASTM. The heat content of the fuel was assumed to be 5.355 MMBtu per barrel based on EIA 

industry standards. The C fraction was derived from an estimated hydrogen content of 14.1 percent (Martel and Angello 

1977), and an estimated content of sulfur and other non-hydrocarbons of 0.1 percent. 

Step 2. Estimate the carbon content for kerosene-based jet fuels

The density of kerosene-based jet fuels was estimated at 42 degrees API and the carbon share at 86.3 percent. 

The density estimate was based on 38 fuel samples examined by NIPER. Carbon share was estimated on the basis of a 

hydrogen content of 13.6 percent found in fuel samples taken in 1959 and reported by Martel and Angello, and on an 

assumed sulfur content of 0.1 percent. The EIA’s standard heat content of 5.670 MMBtu per barrel was adopted for 

kerosene-based jet fuel.

Step 3. Weight the overall jet fuel carbon content coefficient for consumption of each type of fuel (1990-1995 

only)

For years 1990 through 1995, the C content for each jet fuel type (naphtha-based, kerosene-based) is multiplied 

by the share of overall consumption of that fuel type, as reported by EIA (2009a). Individual coefficients are then summed 

and totaled to yield an overall C content coefficient. Only the kerosene-based C coefficient is reflected in the overall jet 

fuel coefficient for 1996 through 2008.

Data Sources

Data on the C content of naphtha-based jet fuel was taken from C.R. Martel and L.C. Angello (1977). Data on 

the density of naphtha-based jet fuel was taken from ASTM (1985). Standard heat contents for kerosene and naphthabased jet fuels were adopted from EIA (2009a). Data on the C content of kerosene-based jet fuel is based on C.R. Martel 

and L.C. Angello (1977) and the density is derived from NIPER (1993). 

Uncertainty

Variability in jet fuel is relatively small with the average C share of kerosene-based jet fuel varying by less than 

1 percent and the density varying by 1 percent. This is because the ratio of fuel mass to useful energy must be tightly 

bounded to maximize safety and range. There is more uncertainty associated with the density and C share of naphthabased jet fuel because sample data were unavailable and default values were used. This uncertainty has only a small 

impact on the overall uncertainty of the C content coefficient for jet fuels, however, because naphtha-based jet fuel 

represents a small and declining share of total jet fuel consumption in the United States and is treated as negligible when 

calculating carbon content factors for 1996 onwards.

Distillate Fuel

Distillate fuel is a general classification for diesel fuels and fuel oils. Products known as No. 1, No. 2, and No. 4 

diesel fuel are used in on-highway diesel engines, such as those in trucks and automobiles, as well as off-highway engines, 

such as those in railroad locomotives and agricultural machinery. No. 1, No. 2, and No. 4 fuel oils are also used for space 

heating and electric power generation. 
A-80 Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2012

Methodology

For this inventory, separate C coefficients have been estimated for each of the three distillates, although the level 

of aggregation of U.S. energy statistics requires that a single coefficient is used to represent all three grades in inventory 

calculations. In past inventories, the emission coefficient was only determined for distillate No. 2. Distillate No. 2 

remains the representative grade applied to the distillate class for calculation purposes. Coefficients developed for No. 1 

and No. 4 distillate are provided for informational purposes. The C share each distillate is drawn from Perry’s Chemical 

Engineers’ Handbook, 8th Ed. (Green & Perry 2008). Each C share was combined with individual heat contents of 5.822, 

5.809 and 6.135 MMBtu per barrel, respectively for distillates No. 1, No. 2 and No. 4, and densities of 35.3, 35.8 and 23.2 

degrees API to calculate C coefficients for each distillate type.

Data Sources

Densities for distillate Nos. 1 and 2 were derived from Alliance of Automobile Manufacturers, Diesel Survey –

Winter 2008 (AAM 2009). Densities are based on four, and 144 samples, respectively. The density of distillate fuel oil 

No. 4 is taken from Perry’s Chemical Engineer’s Handbook, 8th Ed. (Green & Perry, 2008), Table 24-6. 

Heat contents are adopted from EPA (2009b). And carbon shares for each distillate are from Perry’s Chemical 

Engineers’ Handbook (Green & Perry 2008), Table 24-6.

Uncertainty

The primary source of uncertainty for the estimated C content of distillate fuel is the selection of No. 2 distillate 

as the typical distillate fuel oil or diesel fuel. No.2 fuel oil is generally consumed for home heating. No.1 distillate is 

generally less dense and if it is consumed in large portions for mobile sources, the application of the C content estimated 

for No. 2 for this report is likely to be too high when applied to both No. 1 and No. 2 distillates. The opposite is true of the 

application of a coefficient based upon the properties of No. 2 to the consumption of No. 4 distillate, which is of a 

significantly higher density and thus, has a higher C coefficient despite its lower C share. The overall effect on 

uncertainty from applying a single factor will depend on the relative annual consumption of each distillate.

The densities applied to the calculation of each carbon factor are an underlying a source of uncertainty. While 

the density of No. 1 distillate is based upon just four samples, the factor applied to all distillates in the inventory estimates 

(that for No. 2 oil) is based on a much larger sample size (144). Given the range of densities for these three distillate fuel 

classes (0.1342 to 0.1452 MT/bbl at 60°F), the uncertainty associated with the assumed density of distillate fuels is 

predominately a result of the use of No. 2 to represent all distillate consumption. There is also a small amount of 

uncertainty in the No. 2 distillate density itself. This is due to the possible variation across seasonal diesel formulations

and fuel grades and between stationary and transport applications within the No. 2 distillate classification. The range of 

the density of the samples of No. 2 diesel (regular grade, 15ppm sulfur) is ±2.5 percent from the mean, while the range in 

density across the small sample set of No. 1 diesel is -2.1 to +1.6 percent of the mean. Samples from AAM (2009) of 

Premium No. 2 diesel (n=5) and higher sulfur (500 ppm S) regular diesel (n=2), which are also consumed in the U.S., each 

have nominally higher average densities (+1.3 percent and +0.6 percent, respectively) than do the low-sulfur regular diesel 

samples that underlie the density applied in this inventory. 

The use of the 144 AAM samples to define the density of No. 2 distillate (and those four samples used to define 

that of No. 1 distillate) may introduce additional uncertainty because the samples were collected from just one season of 

on-road fuel production (Winter 2008). Despite the limited sample frame, the average No. 2 density calculated from the 

samples is applied to the calculation of a uniform C coefficient applicable for all years of the inventory and for all types of 

distillate consumption. The ASTM standards for each grade of diesel fuel oil do not include a required range in which the 

density must lie, and the density (as well as heat content and carbon share) may vary according to the additives in each 

seasonal blend and the sulfur content of each sub-grade.

However, previous studies also show relatively low variation in density across samples of No. 2 and across all 

distillates, supporting the application of a single No. 2 density to all U.S. distillate consumption. The average density 

calculated from samples analyzed by the EIA in 1994 (n=7) differs only very slightly from the value applied for the 

purposes of this inventory (-0.12 percent for No. 2 distillate). Further, the difference between the mean density applied to 

this inventory (No. 2 only) and that calculated from EIA samples of all distillates, regardless of grade, is also near zero (-

0.06 percent, based on n=14, of distillates No. 1, No. 2 and No. 4 combined). 

A C share of 87.30 percent is applied to No. 2 distillate, while No. 1 and No. 4 have C shares estimated at 86.40 

and 86.47 percent, respectively. Again, the application of parameters specific to No. 2 to the consumption of all three 

distillates contributes to an increased level of uncertainty in the overall coefficient and emissions estimate and its broad 

application. For comparison, four No. 1 fuel oil samples obtained by EIA (1994) contained an average of 86.19 percent C, 
A-81

while seven samples No. 2 fuel oil from the same EIA analysis showed an average of 86.60 percent C. Additionally, three 

samples of No. 4 distillate indicate an average C share of 85.81 percent. The range of C share observed across the seven 

No. 2 samples is 86.1 to 87.5 percent, and across all samples (all three grades, n=14) the range is 85.3 to 87.5 percent C. 

There also exists an uncertainty of 1 percent in the share of C in No. 2 based on the limited sample size.

Residual Fuel

Residual fuel is a general classification for the heavier oils, known as No. 5 and No. 6 fuel oils, that remain after 

the distillate fuel oils and lighter hydrocarbons are distilled away in refinery operations. Residual fuel conforms to ASTM 

Specifications D 396 and D 975 and Federal Specification VV-F-815C. No. 5, a residual fuel oil of medium viscosity, is 

also known as Navy Special and is defined in Military Specification MIL-F-859E, including Amendment 2 (NATO 

Symbol F-770). It is used in steam-powered vessels in government service and inshore power plants. No. 6 fuel oil 

includes Bunker C fuel oil and is used for the production of electric power, space heating, vessel bunkering, and various 

industrial purposes.

In the United States, electric utilities purchase about one-third of the residual oil consumed. A somewhat larger 

share is used for vessel bunkering, and the balance is used in the commercial and industrial sectors. The residual oil 

(defined as No. 6 fuel oil) consumed by electric utilities has an energy content of 6.287 MMBtu per barrel (EIA 2008a) 

and an average sulfur content of 1 percent (EIA 2001). This implies a density of about 17 degrees API. 

Methodology

Because U.S. energy consumption statistics are available only as an aggregate of No. 5 and No. 6 residual oil, a 

single coefficient must be used to represent the full residual fuel category. As in earlier editions of this report, residual 

fuel oil has been defined as No. 6 fuel oil, due to the majority of residual consumed in the United States being No. 6. 

However, for this report, a separate coefficient for fuel oil No. 5 has also been developed for informational purposes. 

Densities of 33.0 and 15.5 degrees API were adopted when developing the C content coefficients for Nos. 5 and 6, 

respectively (Wauquier, J.-P., ed. 1995; Green & Perry, ed. 2008). 

The estimated C share of fuel oil No. 5 is 85.67 percent, based on an average of 12 ultimate analyses of samples 

of fuel oil (EIA 1994). An average share of C in No. 6 residual oil of 84.67 percent by mass was used, based on Perry’s, 

8

th Ed. (Green & Perry 2008).

Data Sources

Data on the C share and density of residual fuel oil No. 6 were obtained from Green & Perry, ed. (2008). 

Data on the C share of fuel oil No. 5 was adopted from EIA (1994), and the density of No. 5 was obtained from 

Wauquier, J.-P., ed. (1995).

Heat contents for both Nos. 5 and 6 fuel oil are adopted from EPA (2009b).

Uncertainty

Beyond the application of a C factor based upon No. 6 oil to all residual oil consumption, the largest source of 

uncertainty in estimating the C content of residual fuel centers on the estimates of density. Fuel oils are likely to differ 

depending on the application of the fuel (i.e., power generation or as a marine vessel fuel). Slight differences between the

density of residual fuel used by utilities and that used in mobile applications are likely attributable to non-sulfur impurities, 

which reduce the energy content of the fuel, but do not greatly affect the density of the product. Impurities of several 

percent are commonly observed in residual oil. The extent of the presence of impurities has a greater effect on the 

uncertainty of C share estimation than it does on density. This is because these impurities do provide some Btu content to 

the fuel, but they are absent of carbon. Fuel oils with significant sulfur, nitrogen and heavy metals contents would have a 

different total carbon share than a fuel oil that is closer to pure hydrocarbon. This contributes to the uncertainty of the 

estimation of an average C share and C coefficient for these varied fuels. 

The 12 samples of residual oil (EIA 1994) cover a density range from 4.3 percent below to 8.2 percent above the 

mean density. The observed range of C share in these samples is -2.5 to +1.8 percent of the mean. Overall, the 

uncertainty associated with the C content of residual fuel is probably 1 percent.

Liquefied Petroleum Gases (LPG) 

EIA identifies four categories of paraffinic hydrocarbons as LPG: ethane, propane, isobutane, and n-butane. 

Because each of these compounds is a pure paraffinic hydrocarbon, their C shares are easily derived by taking into account 
A-82 Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2012

the atomic weight of C (12.01) and the atomic weight of hydrogen (1.01). Thus, for example, the C share of propane, 

C3H8, is 81.71 percent. The densities and heat contents of the compounds are also well known, allowing C content 

coefficients to be calculated directly. Table A-49 summarizes the physical characteristic of LPG.

Table A-49: Physical Characteristics of Liquefied Petroleum Gases

Compound

Chemical 

Formula

Density (Barrels 

Per Metric Ton)

Carbon Content 

(Percent)

Energy Content 

(MMBtu/Barrel)

Carbon Content 

Coefficient (Tg 

C/QBtu)

Ethane C2H6 11.55 79.89 3.082 17.16

Propane C3H8 12.76 81.71 3.836 16.76

Isobutane C4H10 11.42 82.66 3.974 17.77

n-butane C4H10 10.98 82.66 4.326 17.75

Source: Densities – CRC Handbook of Chemistry and Physics (2008/09); Carbon Contents – derived from the atomic weights of the elements; Energy Contents 

– EPA (2009b). All values are for the compound in liquid form. The density and energy content of ethane are for refrigerated ethane (-89 degrees C). Values for 

n-butane are for pressurized butane (-25 degrees C). 

Methodology

Step 1. Assign carbon content coefficients to each pure paraffinic compound

Based on their known physical characteristics, a C content coefficient is assigned to each compound contained in 

the U.S. energy statistics category, Liquefied Petroleum Gases.

Step 2. Weight individual LPG coefficients for share of fuel use consumption

A C content coefficient for LPG used as fuel is developed based on the consumption mix of the individual 

compounds reported in U.S. energy statistics.

Step 3. Weight individual LPG coefficients for share of non-fuel use consumption 

The mix of LPG consumed for non-fuel use differs significantly from the mix of LPG that is combusted. While 

the majority of LPG consumed for fuel use is propane, ethane is the largest component of LPG used for non-fuel 

applications. A C content coefficient for LPG used for non-fuel applications is developed based on the consumption mix 

of the individual compounds reported in U.S. energy statistics.

Step 4. Weight the carbon content coefficients for fuel use and non-fuel use by their respective shares of 

consumption

The changing shares of LPG fuel use and non-fuel use consumption appear below in Table A- 50.

Data Sources

Data on C share was derived via calculations based on atomic weights of each element of the four individual 

compounds densities are from the CRC Handbook of Chemistry and Physics, 89th Education. The energy content of each 

LPG is from the EPA (2009b). LPG consumption was based on data obtained from API (1990 through 2008) and EIA 

(2009b). Non-fuel use of LPG was obtained from API (1990 through 2008). 

Uncertainty

Because LPG consists of pure paraffinic compounds whose density, heat content and C share are physical 

constants, there is limited uncertainty associated with the C content coefficient for this petroleum product. Any 

uncertainty is associated with the collection of data tabulating fuel- and non-fuel consumption in U.S. energy statistics. 

This uncertainty is likely less than 3 percent. 

Table A- 50: Consumption and Carbon Content Coefficients of Liquefied Petroleum Gases, 1990-2011 

1990 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012

Energy Consumption (QBtu)

Fuel Use 0.88 1.31 1.16 1.25 1.22 1.26 1.21 1.19 1.20 1.13 1.13 1.16 1.16 1.16

 Ethane 0.04 0.10 0.06 0.06 0.06 0.06 0.06 0.06 0.07 0.06 0.07 0.08 0.08 0.08

 Propane 0.77 1.07 1.00 1.10 1.07 1.12 1.08 1.07 1.09 1.02 1.02 1.02 1.02 1.02

 Butane 0.06 0.07 0.06 0.05 0.06 0.06 0.05 0.05 0.05 0.05 0.03 0.05 0.05 0.05

 Isobutane 0.01 0.06 0.04 0.04 0.03 0.01 0.01 0.01 0.00 0.00 0.01 0.01 0.01 0.01

Non-Fuel Use 1.35 1.90 1.77 1.85 1.75 1.80 1.70 1.74 1.78 1.67 1.80 1.96 1.96 1.96
A-83

 Ethane 0.71 1.04 0.96 1.00 0.92 0.97 0.91 0.98 1.03 0.95 1.12 1.22 1.22 1.22

 Propane 0.51 0.65 0.59 0.64 0.63 0.66 0.63 0.63 0.64 0.60 0.60 0.60 0.60 0.60

 Butane 0.11 0.11 0.13 0.12 0.13 0.13 0.12 0.12 0.11 0.12 0.08 0.12 0.12 0.12

 Isobutane 0.02 0.09 0.09 0.08 0.07 0.03 0.03 0.02 0.01 0.00 0.01 0.03 0.03 0.03

Carbon Content (Tg C/QBtu)

Fuel Use 16.86 16.89 16.87 16.85 16.86 16.84 16.84 16.83 16.82 16.83 16.82 16.82 16.82 16.82

Non-Fuel Use 17.06 17.09 17.10 17.09 17.09 17.07 17.06 17.06 17.05 17.06 17.06 17.06 17.06 17.06

Sources: Fuel use of LPG based on data from EIA (2009b) and API (1990 through 2007). Non-fuel use of LPG from API (1990 

through 2008). Volumes converted using the energy contents provided in Table A-49. C contents from EPA (2010).

Aviation Gasoline

Aviation gasoline is used in piston-powered airplane engines. It is a complex mixture of relatively volatile 

hydrocarbons with or without small quantities of additives, blended to form a fuel suitable for use in aviation reciprocating 

engines. Fuel specifications are provided in ASTM Specification D910 and Military Specification MIL-G-5572. Aviation 

gas is a relatively minor contributor to greenhouse gas emissions compared to other petroleum products, representing 

approximately 0.1 percent of all consumption. 

The ASTM standards for boiling and freezing points in aviation gasoline effectively limit the aromatics content 

to a maximum of 25 percent (ASTM D910). Because weight is critical in the operation of an airplane, aviation gas must 

have as many Btu per pound (implying a lower density) as possible, given other requirements of piston engines such as 

high anti-knock quality. 

Methodology

A C content coefficient for aviation gasoline was calculated on the basis of the EIA standard heat content of 

5.048 MMBtu per barrel. This implies a density of approximately 69 degrees API gravity or 5.884 pounds per gallon, 

based on the relationship between heat content and density of petroleum liquids, as described in Thermal Properties of 

Petroleum Products (DOC 1929). To estimate the share of C in the fuel, it was assumed that aviation gasoline is 87.5 

percent iso-octane, 9.0 percent toluene, and 3.5 percent xylene. The maximum allowable sulfur content in aviation 

gasoline is 0.05 percent, and the maximum allowable lead content is 0.1 percent. These amounts were judged negligible 

and excluded for the purposes of this analysis. This yielded a C share of 85.00 percent and a C content coefficient of 

18.86 Tg C/QBtu. 

Data Sources

Data sources include ASTM (1985). A standard heat content for aviation gas was adopted from EIA (2009a).

Uncertainty

The relationship used to calculate density from heat content has an accuracy of five percent at 1 atm. The 

uncertainty associated with the C content coefficient for aviation gasoline is larger than that for other liquid petroleum 

products examined because no ultimate analyses of samples are available. Given the requirements for safe operation of 

piston-powered aircraft the composition of aviation gas is well bounded and the uncertainty of the C content coefficient is 

likely to be 5 percent. 

Still Gas

Still gas, or refinery gas, is composed of light hydrocarbon gases that are released as petroleum is processed in a 

refinery. The composition of still gas is highly variable, depending primarily on the nature of the refining process and 

secondarily on the composition of the product being processed. Petroleum refineries produce still gas from many different 

processes. Still gas can be used as a fuel or feedstock within the refinery, sold as a petrochemical feedstock, or purified 

and sold as pipeline-quality natural gas. For the purposes of this inventory, the coefficient derived here is only applied to 

still gas that is consumed as a fuel. In general, still gas tends to include large amounts of free hydrogen and methane, as 

well as smaller amounts of heavier hydrocarbons. Because different refinery operations result in different gaseous byproducts, it is difficult to determine what represents typical still gas.

Methodology

The properties of still gas used to calculate the carbon content are taken from the literature. The carbon share of 

still gas was calculated from its net calorific value and carbon content from IPCC (2006). This calculation yields a carbon 

share of 77.7 percent. The density of still gas was estimated to be 0.1405 metric tons per barrel based on its heat content 
A-84 Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2012

(from EIA 2008a) and the relationship between heat content and density that is described by the U.S. Department of 

Commerce, Bureau of Standards (DOC 1929). 

Data Sources

The carbon share of still gas is calculated from data provided by IPCC (2006). Density is estimated at 0.1405 

metric tons per barrel, approximately 28.3 degrees API, based on the heat content of 6.00 MMbtu/barrel of still gas from 

EIA (2009a). 

Uncertainty

The EIA obtained data on four samples of still gas. Table A-51 below shows the composition of those samples. 

Table A-51: Composition, Energy Content, and Carbon Content Coefficient for Four Samples of Still Gas

Sample Hydrogen

(%)

Methane

(%)

Ethane

(%)

Propane

(%)

Btu Per Cubic 

Foot

Carbon Content

(Tg C/QBtu)

One 12.7 28.1 17.1 11.9 1,388 17.51

Two 34.7 20.5 20.5 6.7 1,143 14.33

Three 72.0 12.8 10.3 3.8 672 10.23

Four 17.0 31.0 16.2 2.4 1,100 15.99

Sources: EIA (2008b). 

Because the composition of still gas is highly heterogeneous, the C content coefficient for this product is highly 

uncertain. Gas streams with a large, free-hydrogen content are likely to be used as refinery or chemical feedstocks. 

Therefore, the sample cited above with the very high H content of 72 percent (and the lowest calculated C content) is less 

likely to be representative of the still gas streams to which the calculated coefficient is applied. The C content coefficient 

used for this report is probably at the high end of the plausible range given that it is higher than the greatest sample-based 

C content in Table A-51.

Asphalt

Asphalt is used to pave roads. Because most of its C is retained in those roads, it is a small source of carbon 

dioxide emissions. It is derived from a class of hydrocarbons called "asphaltenes," which are abundant in some crude oils 

but not in others. Asphaltenes have oxygen and nitrogen atoms bound into their molecular structure, so that they tend to 

have lower C contents than do other hydrocarbons.

Methodology

Ultimate analyses of twelve samples of asphalts showed an average C content of 83.47 percent. The EIA 

standard Btu content for asphalt of 6.636 MMBtu per barrel was assumed. The ASTM petroleum measurement tables 

show a density of 5.6 degrees API or 8.605 pounds per gallon for asphalt. Together, these variables generate C content 

coefficient of 20.55 Tg C/QBtu.

Data Sources

A standard heat content for asphalt was adopted from EIA (2009a). The density of asphalt was determined by 

the ASTM (1985). C share is adopted from analyses in EIA (2008b).

Uncertainty

The share of C in asphalt ranges from 79 to 88 percent by weight. Also present in the mixture are hydrogen and 

sulfur, with shares by weight ranging from seven to 13 percent for hydrogen, and from trace levels to eight percent for 

sulfur. Because C share and total heat content in asphalts do vary systematically, the overall C content coefficient is likely 

to be accurate to 5 percent.

Lubricants

Lubricants are substances used to reduce friction between bearing surfaces, or incorporated into processing 

materials used in the manufacture of other products, or used as carriers of other materials. Petroleum lubricants may be 

produced either from distillates or residues. Lubricants include all grades of lubricating oils, from spindle oil to cylinder 

oil to those used in greases. Lubricant consumption is dominated by motor oil for automobiles, but there is a large range 

of product compositions and end uses within this category.

Methodology
A-85

The ASTM Petroleum Measurement tables give the density of lubricants at 25.6 degrees API, or 0.1428 metric 

tons per barrel. Ultimate analysis of a single sample of motor oil yielded a C content of 85.80 percent. A standard heat 

content of 6.065 MMBtu per barrel was adopted from EIA. These factors produce a C content coefficient of 20.20 Tg 

C/QBtu.

Data Sources

A standard heat content was adopted from the EIA (2009a). The carbon content of lubricants is adopted from 

ultimate analysis of one sample of motor oil (EPA 2009a). The density of lubricating oils was determined by ASTM 

(1985).

Uncertainty

Uncertainty in the estimated C content coefficient for lubricants is driven by the large range of product 

compositions and end uses in this category combined with an inability to establish the shares of the various products 

captured under this category in U.S. energy statistics. Because lubricants may be produced from either the distillate or 

residual fractions during refineries, the possible C content coefficients range from 19.89 Tg C/QBtu to 21.48 Tg C/QBtu 

or an uncertainty band from –1.5 percent to +1.4 percent of the estimated value. 

Petrochemical Feedstocks

U.S. energy statistics distinguish between two different kinds of petrochemical feedstocks: those with a boiling 

temperature below 400 degrees Fahrenheit, generally called “naphtha,” and those with a boiling temperature 401 degrees 

Fahrenheit and above, referred to as “other oils” for the purposes of this inventory. 

Methodology

The C content of these petrochemical feedstocks are estimated independently according to the following steps. 

Step 1. Estimate the carbon content coefficient for naphtha

Because reformed naphtha is used to make motor gasoline (hydrogen is released to raise aromatics content and 

octane rating), “straight-run” naphtha is assumed to be used as a petrochemical feedstock. Ultimate analyses of five 

samples of naphtha were examined and showed an average C share of 84.11 percent. A density of 62.4 degrees API 

gravity was taken from the Handbook of Petroleum Refining Processes, 3rd ed. The standard EIA heat content of 5.248 

MMBtu per barrel is used to estimate a C content coefficient of 18.55 Tg C/QBtu. 

Step 2. Estimate the carbon content coefficient for petrochemical feedstocks with a boiling temperature 400 

degrees Fahrenheit and above (“other oils”)

The boiling temperature of this product places it into the “middle distillate” fraction in the refining process, and 

EIA estimates that these petrochemical feedstocks have the same heat content as distillate fuel No. 2. Thus, the C content 

coefficient of 20.17 Tg C/QBtu used for distillate fuel No. 2 is also adopted for this portion of the petrochemical 

feedstocks category.

Data Sources

Naphthas: Data on the C content was taken from Unzelman (1992). Density is from Meyers (2004). A standard 

heat content for naphthas was adopted from EIA (2009a). Other oils: See Distillate Fuel, Distillate No.2.

Uncertainty

Petrochemical feedstocks are not so much distinguished on the basis of chemical composition as on the identity 

of the purchaser, who are presumed to be a chemical company or a petrochemical unit co-located on the refinery grounds. 

Naphthas are defined, for the purposes of U.S. energy statistics, as those naphtha products destined for use as a 

petrochemical feedstock. Because naphthas are also commonly used to produce motor gasoline, there exists a 

considerable degree of uncertainty about the exact composition of petrochemical feedstocks. 

Different naphthas are distinguished by their density and by the share of paraffins, isoparaffins, olefins, 

naphthenes and aromatics contained in the oil. Naphtha from the same crude oil fraction may have vastly different 

properties depending on the source of the crude. Two different samples of Egyptian crude, for example, produced two 

straight run naphthas having naphthene and paraffin contents (percent volume) that differ by 18.1 and 17.5 percent, 

respectively (Matar and Hatch, 2000). 
A-86 Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2012

Naphthas are typically used either as a petrochemical feedstock or a gasoline feedstock, with lighter paraffinic 

naphthas going to petrochemical production. Naphthas that are rich in aromatics and naphthenes tend to be reformed or 

blended into gasoline. Thus, the product category encompasses a range of possible fuel compositions, creating a range of 

possible C shares and densities. The uncertainty associated with the calculated C content of naphthas is primarily a 

function of the uncertainty that underlies the average carbon share calculation, which is based on a limited number of 

samples. Two additional samples cited by the EIA (1994) have a range of 83.80 to 84.42 percent C.

The uncertainty of the carbon content for other oils is based upon the assumption of distillate oil No. 2 as a 

product representative of the ill-defined classification of “other oils,” and from the calculation of the C content of No. 2 

itself (see “Distillate Fuels,” above). While No. 2 distillate is used as a proxy for “other oils” for the purposes of this 

inventory’s carbon coefficient, important differences exist between these two petroleum products, contributing some 

uncertainty to the cross-application. Other oils are defined herein as those “oils with a boiling range equal to or greater 

than 401°F that are generally intended for use as a petrochemical feedstock and are not defined elsewhere.” For 

comparison, various material safety data sheets (MSDSs) published by producers of distillate No. 2 indicate a boiling 

range for this product of 320-700 degrees Fahrenheit. The relatively open definition of the classification “other oils” 

leaves room for potentially significant variation in the heating value, density and carbon share properties of each feedstock 

oil having a boiling point above 400 degrees Fahrenheit, creating a large band of uncertainty beyond that associated with 

the C factor for distillate No. 2.

Kerosene

A light petroleum distillate that is used in space heaters, cook stoves, and water heaters and is suitable for use as 

a light source when burned in wick-fed lamps, kerosene is drawn from the same petroleum fraction as jet fuel. Kerosene is 

generally comparable to No.1 distillate oil.

Methodology

The average density and C share of kerosene are assumed to be the same as those for distillate No. 1 since the 

physical characteristics of the products are very similar. Thus, a density of 35.3 degrees API and average C share of 86.40 

percent were applied to a standard heat content for distillate No. 1 of 5.825 MMBtu per barrel to yield a C content 

coefficient of 19.96 Tg C/QBtu.

Data Sources

A standard heat content for distillate No.1 was adopted from EIA (2009a).

Uncertainty

Uncertainty in the estimated C content for kerosene is driven by the selection of distillate No. 1 as a proxy for 

kerosene. If kerosene is more like kerosene-based jet fuel, the true C content coefficient is likely to be some 1.3 percent 

lower. If kerosene is more aptly compared to No. 2 distillate oil, then the true C content coefficient is likely to be about 

1.1 percent higher. While kerosene is a light petroleum distillate, like distillate No. 1, the two oil classes are do have some 

variation in their properties. For example, the boiling range of kerosene is 250-550 degrees Fahrenheit, whereas No. 1 oils 

typically boil over a range from 350-615 degrees Fahrenheit. The properties of individual kerosenes will vary with their 

use and particular crude origin, as well. Both kerosene and fuel oil No. 1 are primarily composed of hydrocarbons having 

9 to 16 carbon atoms per molecule. However, kerosene is a straight-run No. 1 fuel oil, additional cracking processes and 

additives contribute to the range of possible fuels that make up the broader distillate No. 1 oil category. 

Petroleum Coke

Petroleum coke is the solid residue by-product of the extensive processing of crude oil. It is a coal-like solid, 

usually has a C content greater than 90 percent, and is used as a boiler fuel and industrial raw material.

Methodology

Ultimate analyses of two samples of petroleum coke showed an average C share of 92.28 percent. The 

ASTM standard density of 9.543 pounds per gallon was adopted and the EIA standard energy content of 6.024 

MMBtu per barrel assumed. Together, these factors produced an estimated C content coefficient of 27.85 Tg 

C/QBtu.

Data Sources
A-87

C content was derived from two samples from Martin, S.W. (1960). The density of petroleum coke was taken 

from the ASTM (1985). A standard heat content for petroleum coke was adopted from EIA (2009a).

Uncertainty

The uncertainty associated with the estimated C content coefficient of petroleum coke can be traced to two 

factors: the use of only two samples to establish C contents and a standard heat content which may be too low. Together, 

these uncertainties are likely to bias the C content coefficient upwards by as much as 6 percent. 

Special Naphtha

Special naphtha is defined as a light petroleum product to be used for solvent applications, including commercial 

hexane and four classes of solvent: Stoddard solvent, used in dry cleaning; high flash point solvent, used as an industrial 

paint because of its slow evaporative characteristics; odorless solvent, most often used for residential paints; and high 

solvency mineral spirits, used for architectural finishes. These products differ in both density and C percentage, requiring 

the development of multiple coefficients. 

Methodology

The method for estimating the C content coefficient of special naphtha includes three steps.

Step 1. Estimate the carbon content coefficient for hexane

Hexane is a pure paraffin containing 6 C atoms and 14 hydrogen atoms; thus, it is 83.63 percent C. Its density is 

83.7 degrees API or 5.477 pounds per gallon and its derived C content coefficient is 21.40 Tg C/QBtu. 

Step 2. Estimate the carbon contents of non-hexane special naphthas

The hydrocarbon compounds in special naphthas are assumed to be either paraffinic or aromatic (see discussion 

above). The portion of aromatics in odorless solvents is estimated at less than 1 percent, Stoddard and high flash point 

solvents contain 15 percent aromatics and high solvency mineral spirits contain 30 percent aromatics (Boldt and Hall 

1977). These assumptions, when combined with the relevant densities, yield the C content factors contained in Table A52, below. 

Table A-52: Characteristics of Non-hexane Special Naphthas

Special Naphtha

Aromatic Content 

(Percent)

Density

(Degrees API)

Carbon Share 

(Percent Mass)

Carbon Content (Tg 

C/QBtu)

Odorless Solvent 1 55.0 84.51 19.41

Stoddard Solvent 15 47.9 84.44 20.11

High Flash Point 15 47.6 84.70 20.17

Mineral Spirits 30 43.6 85.83 20.99

Sources: EIA (2008b) and Boldt and Hall (1977). 

Step 3. Develop weighted carbon content coefficient based on consumption of each special naphtha

EIA reports only a single consumption figure for special naphtha. The C contents of the five special naphthas are 

weighted according to the following formula: approximately 10 percent of all special naphtha consumed is hexane; the 

remaining 90 percent is assumed to be distributed evenly among the four other solvents. The resulting emissions 

coefficient for special naphthas is 19.74 Tg C/QBtu.

Data Sources

A standard heat content for special naphtha was adopted from EIA (2009a). Density and aromatic contents were 

adopted from Boldt and Hall (1977).

Uncertainty

The principal uncertainty associated with the estimated C content coefficient for special naphtha is the allocation 

of overall consumption across individual solvents. The overall uncertainty is bounded on the low end by the C content of 

odorless solvent and on the upper end by the C content of hexane. This implies an uncertainty band of –1.7 percent to 

+8.4 percent.
A-88 Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2012

Petroleum Waxes

The ASTM standards define petroleum wax as a product separated from petroleum that is solid or semi-solid at 

77 degrees Fahrenheit (25 degrees Celsius). The two classes of petroleum wax are paraffin waxes and microcrystalline 

waxes. They differ in the number of C atoms and the type of hydrocarbon compounds. Microcrystalline waxes have 

longer C chains and more variation in their chemical bonds than paraffin waxes.

Methodology

The method for estimating the C content coefficient for petroleum waxes includes three steps.

Step 1. Estimate the carbon content of paraffin waxes

For the purposes of this analysis, paraffin waxes are assumed to be composed of 100 percent paraffinic 

compounds with a chain of 25 C atoms. The resulting C share for paraffinic wax is 85.23 percent and the density is 

estimated at 45 degrees API or 6.684 pounds per gallon.

Step 2. Estimate the carbon content of microcrystalline waxes

Microcrystalline waxes are assumed to consist of 50 percent paraffinic and 50 percent cycloparaffinic 

compounds with a chain of 40 C atoms, yielding a C share of 85.56 percent. The density of microcrystalline waxes is 

estimated at 36.7 degrees API, based on a sample of 10 microcrystalline waxes found in the Petroleum Products 

Handbook. 

Step 3. Develop a carbon content coefficient for petroleum waxes by weighting the density and carbon content of 

paraffinic and microcrystalline waxes

A weighted average density and C content was calculated for petroleum waxes, assuming that wax consumption 

is 80 percent paraffin wax and 20 percent microcrystalline wax. The weighted average C content is 85.30 percent, and the 

weighted average density is 6.75 pounds per gallon. EIA’s standard heat content for waxes is 5.537 MMBtu per barrel. 

These inputs yield a C content coefficient for petroleum waxes of 19.80 Tg C/QBtu.

Data Sources

Density of paraffin wax was taken from ASTM (1985). Density of microcrystalline waxes was derived from 10 

samples found in Guthrie (1960). A standard heat content for petroleum waxes was adopted from EIA (2009a).

Uncertainty

Although there is considerable qualitative uncertainty associated with the allocation of petroleum waxes and 

microcrystalline waxes, the quantitative variation in the C contents for all waxes is limited to  1 percent because of the 

nearly uniform relationship between C and other elements in petroleum waxes broadly defined. 

Crude Oil, Unfinished Oils, and Miscellaneous Products 

U.S. energy statistics include several categories of petroleum products designed to ensure that reported refinery 

accounts “balance” and cover any “loopholes” in the taxonomy of petroleum products. These categories include crude oil, 

unfinished oils, and miscellaneous products. Crude oil is rarely consumed directly, miscellaneous products account for 

less than one percent of oil consumption, and unfinished oils are a balancing item that may show negative consumption. 

For C accounting purposes, it was assumed that all these products have the same C content as crude oil. 

Methodology

EIA reports on the average density and sulfur content of U.S. crude oil purchased by refineries. To develop a 

method of estimating C content based on this information, results of ultimate analyses of 182 crude oil samples were 

collected. Within the sample set, C content ranged from 82 to 88 percent C, but almost all samples fell between 84 percent 

and 86 percent C. The density and sulfur content of the crude oil data were regressed on the C content, producing the 

following equation: 

Percent C = 76.99 + (10.19 × Specific Gravity) + (-0.76 × Sulfur Content) 
A-89

Absent the term representing sulfur content, the equation had an R-squared of only 0.35.23 When C content was 

adjusted to exclude sulfur, the R-squared value rose to 0.65. While sulfur is the most important non-hydrocarbon 

impurity, nitrogen and oxygen can also be significant, but they do not seem to be correlated with either density or sulfur

content. Restating these results, density accounts for about 35 percent of the variation in C content, impurities account for 

about 30 percent of the variation, and the remaining 35 percent is accounted for by other factors, including (presumably) 

the degree to which aromatics and polynuclear aromatics are present in the crude oil. Applying this equation to the 2008 

crude oil quality data (30.21 degrees API and 1.47 percent sulfur) produces an estimated C content of 84.79 percent. 

Applying the density and C content to the EIA standard energy content for crude oil of 5.800 MMBtu per barrel produced 

an emissions coefficient of 20.31 Tg C/QBtu.

Data Sources

C content was derived from 182 crude oil samples, including 150 samples from U.S. National Research Council 

(1927). A standard heat content for crude oil was adopted from EIA (2009a).

Uncertainty

The uncertainty of the estimated C content for crude oil centers on the 35 percent of variation that cannot be 

explained by density and sulfur content. This variation is likely to alter the C content coefficient by 3 percent. Since 

unfinished oils and miscellaneous products are impossible to define, the uncertainty of applying a crude oil C content is 

likely to be bounded by the range of petroleum products described in this chapter at 10 percent. 

Chronology and Explanation of Changes in Individual Carbon Content Coefficients of Fossil Fuels

Coal

Original 1994 Analysis 

A set of 5,426 coal samples from the EIA coal analysis file were used to develop C content estimates. The results 

from that sample set appear below in Table A-53. The EIA Coal Analysis File was originally developed by the U.S. 

Bureau of Mines and contained over 60,000 coal samples obtained through numerous coal seams throughout the United 

States. Many of the samples were collected starting in the 1940s and 1950s through the 1980s and analyzed in U.S. 

government laboratories. 

Table A-53: Carbon Content Coefficients for Coal by Consuming Sector and Coal Rank, 1990 – 2000 (Tg C/QBtu)

1990 1991 1992 1993 1994 1995 1996 1997 1998 1999 2000

Consuming Sector

Electric Power 25.68 25.69 25.69 26.71 25.72 25.74 25.74 25.76 25.76 25.76 25.76

Industrial Coking 25.51 25.51 25.51 25.51 25.52 25.53 25.55 25.56 25.56 25.56 25.56

Other Industrial 25.58 25.59 25.62 25.61 25.63 25.63 25.61 25.63 25.63 25.63 25.63

Residential / Commercial 25.92 26.00 26.13 25.97 25.95 26.00 25.92 26.00 26.00 26.00 26.00

Coal Rank

Anthracite 28.13 28.13 28.13 28.13 28.13 28.13 28.13 28.13 28.13 28.13 28.13

Bituminous 25.37 25.37 25.37 25.37 25.37 25.37 25.37 25.37 25.37 25.37 25.37

Sub-bituminous 26.24 26.24 26.24 26.24 26.24 26.24 26.24 26.24 26.24 26.24 26.24

Lignite 26.62 26.62 26.62 26.62 26.62 26.62 26.62 26.62 26.62 26.62 26.62

Sources: Emission factors be consuming sector from B.D. Hong and E.R. Slatnick, “Carbon Dioxide Emission Factors for Coal, “ U.S. Energy Information 

Administration, Quarterly Coal Report, January-March 1994. (Washington, DC, 1994) and Emission factors by rank from Science Applications International 

Corporation, “Analysis of the Relationship Between Heat and Carbon Content of U.S. Fuels: Final Task Report,” Prepared for the U.S. Energy Information 

Administration, Office of Coal, Nuclear, Electric and Alternative Fuels (Washington, DC 1992). 

2002 Update

The methodology employed for these estimates was unchanged from previous years; however, the underlying 

coal data sample set was updated. A new database, CoalQual 2.0 (1998), compiled by the U.S. Geological Survey was 

adopted for the updated analysis. The updated sample set included 6,588 coal samples collected by the USGS and its state 

 

23 R-squared represents the percentage of variation in the dependent variable (in this case carbon content) explained by variation in the 

independent variables.
A-90 Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2012

affiliates between 1973 and 1989. The decision to switch to the sample data contained in the USGS CoalQual database 

from the EIA database was made because the samples contained in the USGS database were collected and analyzed more 

recently than those obtained by EIA from the Bureau of Mines. The new coefficients developed in the 2002 revision were 

in use through the 1990 through 2007 Inventory and are provided in Table A-54.
A-91

Table A-54: Carbon Content Coefficients for Coal by Consuming Sector and Coal Rank, 1990 – 2000 (Tg C/QBtu)

1990 1991 1992 1993 1994 1995 1996 1997 1998 1999 2000

Consuming Sector

Electric Power 25.68 25.69 25.69 25.71 25.72 25.74 25.74 25.76 25.76 25.76 25.76 

Industrial Coking 25.51 25.51 25.51 25.51 25.52 25.53 25.55 25.56 25.56 25.56 25.56 

Other Industrial 25.58 25.60 25.62 25.61 25.63 25.63 25.61 25.63 25.63 25.63 25.63 

Residential/ Commercial 25.92 26.00 26.13 25.97 25.95 26.00 25.92 26.00 26.00 26.00 26.00 

Coal Rank

Anthracite 28.26 28.26 28.26 28.26 28.26 28.26 28.26 28.26 28.26 28.26 28.26

Bituminous 25.43 25.45 25.44 25.45 25.46 25.47 25.47 25.48 25.47 25.48 25.49

Sub-bituminous 26.50 26.49 26.49 26.48 26.49 26.49 26.49 26.49 26.49 26.49 26.48

Lignite 26.19 26.21 26.22 26.21 26.24 26.22 26.17 26.20 26.23 26.26 26.30

Sources: Data from USGS, U.S. Coal Quality Database Version 2.0 (1998) and analysis prepared by SAIC 2007. 

2007 Update

The analysis of the USGS Coal Qual data was updated in 2007 to make a technical correction that affected the value for lignite and those sectors which consume 

lignite Table A-55 contains the annual coefficients that resulted from the 2007 analysis.

Table A-55: Carbon Content Coefficients for Coal by Consuming Sector and Coal Rank, 1990-2007 [Tg C/QBtu)

1990 1995 1996 1997 1998 1999 2000 2001 2002 2003 2004 2005 2006 2007

Consuming Sector

Electric Power 25.68 25.74 25.74 25.76 25.76 25.76 25.76 25.76 25.76 25.76 25.76 25.76 25.76 25.76 

Industrial Coking 25.51 25.53 25.55 25.56 25.56 25.56 25.56 25.56 25.56 25.56 25.56 25.56 25.56 25.56 

Other Industrial 25.58 25.63 25.61 25.63 25.63 25.63 25.63 25.63 25.63 25.63 25.63 25.63 25.63 25.63 

Residential/Commercial 25.92 26.00 25.92 26.00 26.00 26.00 26.00 26.00 26.00 26.00 26.00 26.00 26.00 26.00 

Coal Rank

Anthracite 28.26 28.26 28.26 28.26 28.26 28.26 28.26 28.26 28.26 28.26 28.26 28.26 28.26 28.26

Bituminous 25.43 25.47 25.47 25.48 25.47 25.48 25.49 25.49 25.49 25.49 25.49 25.49 25.49 25.49

Sub-bituminous 26.50 26.49 26.49 26.49 26.49 26.49 26.48 26.48 26.48 26.48 26.48 26.48 26.48 26.48

Lignite 26.19 26.22 26.17 26.20 26.23 26.26 26.30 26.30 26.30 26.30 26.30 26.30 26.30 26.57

Sources: Data from USGS, U.S. Coal Quality Database Version 2.0 (1998) and analysis prepared by (SAIC 2007). 
A-92 Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2012

2010 Update

The estimated annual C content coefficients for coal by rank and sector of consumption were updated again in 

2010. Sample data from the Energy Institute at Pennsylvania State University (504 samples) were added to the 6,588 

USGS samples to create a new database of 7,092 samples. The same analytical method used in the 2002 update was 

applied using these additional samples to calculate revised state-level carbon contents for each coal rank and then for 

national average consumption by end-use sector and by rank. 

Natural Gas

A revised analytical methodology underlies the natural gas coefficients used in this report. Prior to the current 

Inventory, descriptive statistics were used to stratify 6,743 samples of pipeline quality natural gas by heat content and then 

to determine the average C content of natural gas at the national average heat content (EIA 1994). The same coefficient 

was applied to all pipeline natural gas consumption for all years, because U.S. energy statistics showed a range of national 

average heat contents of pipeline gas of only 1,025 to 1,031 Btu per cubic foot (1 percent) from 1990 through 1994. A 

separate factor was developed in the same manner for all flared gas. In the previous Inventory, a weighted national 

average C content was calculated using the average C contents for each sub-sample of gas that conformed with an 

individual state’s typical cubic foot of natural gas since there is regional variation in energy content. The result was a 

weighted national average of 14.47 Tg C/QBtu. 

The current Inventory is revised to make use of the same set of samples, but utilizes a regression equation, as 

described above, of sample-based heat content and carbon content data in order to calculate annually-variable national 

average C content coefficients based on annual national average heat contents for pipeline natural gas and for flare gas. In 

addition, the revised analysis calculates an average C content from all samples with less than 1.5 percent CO2 and less than 

1,050 Btu/cf (samples most closely approximating the makeup of pipeline quality natural gas). The result was identical to 

the previous weighted national average of 14.47 Tg C/QBtu. The average C contents from the 1994 calculations are 

presented in Table A-56 below for comparison.

Table A-56: Carbon Content of Pipeline-Quality Natural Gas by Energy Content (Tg C/QBtu)

Sample Average Carbon Content

GRI Full Sample 14.51

Greater than 1,000 Btu 14.47

1,025 to 1,035 Btu 14.45

975 to 1,000 Btu 14.73

1,000 to 1,025 Btu 14.43

1,025 to 1,050 Btu 14.47

1,050 to 1,075 Btu 14.58

1,075 to 1,100 Btu 14.65

Greater than 1,100 Btu 14.92

Weighted National Average 14.47

Source: EIA (1994).

Petroleum Products

All of the petroleum product C coefficients except that for Aviation Gasoline Blending Components have been 

updated for the current Inventory. EPA is updating these factors to better align the fuel properties data that underlie the 

Inventory factors with those published in the Mandatory Reporting of Greenhouse Gases Rule (EPA 2009b), Suppliers of 

Petroleum Products (MM) and Stationary Combustion (C) subparts. The coefficients that were applied in the previous 

report are provided in Table A-57 below. Specifically, each of the coefficients used in this report have been calculated 

from updated density and C share data, largely adopted from analyses undertaken for the Rule (EPA 2009b). In some 

cases, the heat content applied to the conversion to a carbon-per-unit-energy basis has also been updated. Additionally, 

the category Misc. Products (Territories), which is based upon the coefficients calculated for crude oil, has been allowed to 

vary annually with the crude oil coefficient. The petrochemical feedstock category has been eliminated for this report 

because the constituent products—naphthas and other oils—are estimated independently. Further, although the level of 

aggregation of U.S. energy statistics currently limits the application of coefficients for residual and distillate fuels to these 

two generic classifications, individual coefficients for the five major types of fuel oil (Nos. 1, 2, 4, 5 and 6) have been 

estimated for the current report and are presented in Table A-46 above. Each of the C coefficients applied in the previous 

Inventory is provided below for comparison (Table A-57).
A-93

Table A-57: Carbon Content Coefficients and Underlying Data for Petroleum Products

Fuel

2007 Carbon Content

(Tg C/QBtu)

Gross Heat of Combustion

(MMBtu/Barrel)

Density

(API Gravity)

Percent 

Carbon

Motor Gasoline 19.33 5.219 59.1 86.60

LPG (total)a 16.99 (See a) (See a) (See a)

LPG (energy use) 17.18 (See a) (See a) (See a)

LPG (non-energy use) 16.76 (See a) (See a) (See a)

Jet Fuel 19.33 5.670 42.0 86.30

Distillate Fuel 19.95 5.825 35.5 86.34

Residual Fuel 21.49 6.287 11.0 85.68

Asphalt and Road Oil 20.62 6.636 5.6 83.47

Lubricants 20.24 6.065 25.6 85.80

Petrochemical Feedstocks 19.37 5.248b 67.1b 84.11b

Aviation Gas 18.87 5.048 69.0 85.00

Kerosene 19.72 5.670 41.4 86.01

Petroleum Coke 27.85 6.024 - 92.28

Special Naphtha 19.86 5.248 51.2 84.76

Petroleum Waxes 19.81 5.537 43.3 85.29

Still Gas 17.51 6.000 - -

Crude Oil 20.33 5.800 30.5 85.49

Unfinished Oils 20.33 5.825 30.5 85.49

Miscellaneous Products 20.33 5.796 30.5 85.49

Pentanes Plus 18.24 4.620 81.7 83.70

Natural Gasoline 18.24 4.620 81.7 83.70

a Heat, density and percent carbon values are provided separately for ethane, propane and isobutene. 

a LPG is a blend of multiple paraffinic hydrocarbons: ethane, propane, isobutane, and normal butane, each with their own heat content, density and C content, 

see Table A-49.

b Parameters presented are for naphthas with a boiling temperature less than 400 degrees Fahrenheit. Petrochemical feedstocks with higher boiling points are 

assumed to have the same characteristics as distillate fuel.

- No sample data available

Sources: EIA (1994), EIA (2008a), and SAIC (2007). 

Additional revisions to the inventory’s C coefficients since 1990 are detailed below.

Jet Fuel

1995 Update

Between 1994 and 1995, the C content coefficient for kerosene-based jet fuel was revised downward from 19.71 

Tg C/QBtu to 19.33 Tg C/QBtu. This downward revision was the result of a shift in the sample set used from one 

collected between 1959 and 1972 and reported on by Martel and Angello in 1977 to one collected by Boeing in 1989 and 

published by Hadaller and Momenthy in 1990. The downward revision was a result of a decrease in density, as well as 

slightly lower C shares than in the earlier samples. However, the assumed heat content is unchanged because it is based 

on an EIA standard and probably yields a downward bias in the revised C content coefficient. 

1990 through 2008 Inventory Update

The coefficient was revised again for the 1990 through 2008 Inventory, returning to Martel and Angello and 

NIPER as the source of the carbon share and density data, respectively, for kerosene-based fuels. This change was made in 

order to align the coefficients used for this report with the values used in the Mandatory Reporting of Greenhouse Gases 

Rule (EPA 2009b). The return to the use of the Martel and Angello and NIPER coefficients was deemed more appropriate 

for the Rule as it was considered a more conservative coefficient given the uncertainty and variability in coefficients 

across the types of jet fuel in use in the United States. The factor will be revisited in future Inventories in light of data 

received from reporting entities in response to the Rule.
A-94 Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2012

Liquefied Petroleum Gases (LPG)

The C content coefficient of LPG is updated annually to reflect changes in the consumption mix of the 

underlying compounds: ethane; propane; isobutane; and normal butane. In 1994, EIA included pentanes plus—assumed to 

have the characteristics of hexane—in the mix of compounds broadly described as LPG. In 1995, EIA removed pentanes 

plus from this fuel category. Because pentanes plus is relatively rich in C per unit of energy, its removal from the 

consumption mix lowered the C content coefficient for LPG from 17.26 Tg C/QBtu to 16.99 Tg C/QBtu. In 1998, EIA 

began separating LPG consumption into two categories: energy use and non-fuel use and providing individual coefficients 

for each. Because LPG for fuel use typically contains higher proportions of propane than LPG for non-fuel use, the C 

content coefficient for fuel use was 1.8 to 2.5 percent higher than the coefficient for non-fuel use in previous Inventories 

(see Table A-57). 

However, for the current update of the LPG coefficients, the assumptions that underlie the selection of density 

and heat content data for each pure LPG compound have been updated, leading to a significant revision of the assumed 

properties of ethane. For this report, the physical characteristics of ethane, which constitutes over 90 percent of LPG 

consumption for non-fuel uses, have been updated to reflect ethane that is in (refrigerated) liquid form. Previously, the 

share of ethane was included using the density and energy content of gaseous ethane. Table A-58, below, compares the 

values applied for each of the compounds under the two sets of coefficient calculations. The carbon share of each pure 

compound was also updated by using more precise values for each compound’s molecular weight. 

Due in large part to the revised assumptions for ethane, the weighted C content for non-fuel use is now higher 

than that of the weighted coefficient for fuel use, which is dominated by the consumption of more dense propane. Under 

the revised assumptions, each annual weighted coefficient for non-fuel LPG consumption is 1.2 to 1.7 percent higher each 

year than is that for LPGs consumed for fuel (energy) uses. 

Table A-58: Physical Characteristics of Liquefied Petroleum Gases

1990-2007 Updated 1990-2007 Updated 1990-2007 Updated

Compound Chemical 

Formula

Density

(bbl / MT)

Density

(bbl / MT)

Energy Content 

(MMBtu/bbl)

Energy Content 

(MMBtu/bbl)

C Content 

Coefficient (Tg 

C/QBtu)

C Content 

Coefficient (Tg 

C/QBtu)

Ethane C2H6 16.88 11.55 2.916 3.082 16.25 17.16

Propane C3H8 12.44 12.76 3.824 3.836 17.20 16.76

Isobutane C4H10 11.20 11.42 4.162 3.974 17.75 17.77

n-butane C4H10 10.79 10.98 4.328 4.326 17.72 17.75

Sources: Updated: Densities – CRC Handbook of Chemistry and Physics, 89th Ed. (2008/09); Energy Contents – EPA (2009b). All values are for the compound 

in liquid form. The density and energy content of ethane are for refrigerated ethane (-89 degrees C). Values for n-butane are for pressurized butane (-25 degrees 

C). Values in previous editions of this inventory: Gurthrie (1960).

Motor Gasoline

The C content coefficient for motor gasoline varies annually based on the density of and proportion of additives 

in a representative sample of motor gasoline examined each year. However, in 1997 EIA began incorporating the effects 

of the introduction of reformulated gasoline into its estimate of C content coefficients for motor gasoline. This change 

resulted in a downward step function in C content coefficients for gasoline of approximately 0.3 percent beginning in 

1995. In 2005-2006 reformulated fuels containing ethers began to be phased out nationally. Ethanol was added to 

gasoline blends as a replacement oxygenate, leading to another shift in gasoline density (see Table A- 47), in the list and 

proportion of constituents that form the blend and in the blended C share based on those constituents. 
A-95

Table A-59: Carbon Content Coefficients for Petroleum Products, 1990-2007 [Tg C/QBtu)

Fuel Type 1990 1995 1996 1997 1998 1999 2000 2001 2002 2003 2004 2005 2006 2007

Petroleum

Asphalt and Road Oil 20.62 20.62 20.62 20.62 20.62 20.62 20.62 20.62 20.62 20.62 20.62 20.62 20.62 20.62

Aviation Gasoline 18.87 18.87 18.87 18.87 18.87 18.87 18.87 18.87 18.87 18.87 18.87 18.87 18.87 18.87

Distillate Fuel Oil 19.95 19.95 19.95 19.95 19.95 19.95 19.95 19.95 19.95 19.95 19.95 19.95 19.95 19.95

Jet Fuela 19.40 19.34 19.33 19.33 19.33 19.33 19.33 19.33 19.33 19.33 19.33 19.33 19.33 19.33

Kerosene 19.72 19.72 19.72 19.72 19.72 19.72 19.72 19.72 19.72 19.72 19.72 19.72 19.72 19.72

LPG (energy use)a 17.21 17.20 17.20 17.18 17.23 17.25 17.20 17.21 17.20 17.21 17.20 17.19 17.19 17.18

LPG (non-energy use)a 16.83 16.87 16.86 16.88 16.88 16.84 16.81 16.83 16.82 16.84 16.81 16.81 16.78 16.76

Lubricants 20.24 20.24 20.24 20.24 20.24 20.24 20.24 20.24 20.24 20.24 20.24 20.24 20.24 20.24

Motor Gasolinea 19.41 19.38 19.36 19.35 19.33 19.33 19.34 19.34 19.35 19.33 19.33 19.33 19.33 19.33 

Residual Fuel 21.49 21.49 21.49 21.49 21.49 21.49 21.49 21.49 21.49 21.49 21.49 21.49 21.49 21.49

Other Petroleum

Av Gas Blend Comp. 18.87 18.87 18.87 18.87 18.87 18.87 18.87 18.87 18.87 18.87 18.87 18.87 18.87 18.87

Mo Gas Blend Compa 19.41 19.38 19.36 19.35 19.33 19.33 19.34 19.34 19.35 19.33 19.33 19.33 19.33 19.33

Crude Oila 20.16 20.23 20.25 20.24 20.24 20.19 20.23 20.29 20.30 20.28 20.33 20.33 20.33 20.33

Misc. Productsa 20.16 20.23 20.25 20.24 20.24 20.19 20.23 20.29 20.30 20.28 20.33 20.33 20.33 20.33

Misc. Products (Terr.) 20.00 20.00 20.00 20.00 20.00 20.00 20.00 20.00 20.00 20.00 20.00 20.00 20.00 20.00

Naphtha (<401 deg. F) 18.14 18.14 18.14 18.14 18.14 18.14 18.14 18.14 18.14 18.14 18.14 18.14 18.14 18.14

Other oil (>401 deg. F) 19.95 19.95 19.95 19.95 19.95 19.95 19.95 19.95 19.95 19.95 19.95 19.95 19.95 19.95

Pentanes Plus 18.24 18.24 18.24 18.24 18.24 18.24 18.24 18.24 18.24 18.24 18.24 18.24 18.24 18.24

Petrochemical Feed. 19.37 19.37 19.37 19.37 19.37 19.37 19.37 19.37 19.37 19.37 19.37 19.37 19.37 19.37

Petroleum Coke 27.85 27.85 27.85 27.85 27.85 27.85 27.85 27.85 27.85 27.85 27.85 27.85 27.85 27.85

Still Gas 17.51 17.51 17.51 17.51 17.51 17.51 17.51 17.51 17.51 17.51 17.51 17.51 17.51 17.51

Special Naphtha 19.86 19.86 19.86 19.86 19.86 19.86 19.86 19.86 19.86 19.86 19.86 19.86 19.86 19.86

Unfinished Oilsa 20.16 20.23 20.25 20.24 20.24 20.19 20.23 20.29 20.30 20.28 20.33 20.33 20.33 20.33

Waxes 19.81 19.81 19.81 19.81 19.81 19.81 19.81 19.81 19.81 19.81 19.81 19.81 19.81 19.81

Other Wax and Misc. 19.81 19.81 19.81 19.81 19.81 19.81 19.81 19.81 19.81 19.81 19.81 19.81 19.81 19.81

a C contents vary annually based on changes in fuel composition. 
A-96 Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2012

References

AAM (2009). Diesel Survey. Alliance of Automobile Manufacturers, Winter 2008.

American Gas Association (1974) Gas Engineer's Handbook, New York, NY, Industrial Press, pp. 3/71, 3.87. 

API (1990 through 2008) Sales of Natural Gas Liquids and Liquefied Refinery Gases, American Petroleum Institute. 

API (1988) Alcohols and Ethers: A Technical Assessment of Their Applications as Fuels and Fuel Components, American 

Petroleum Institute, API 4261.

ASTM (1985) ASTM and Other Specifications for Petroleum Products and Lubricants, American Society for Testing and 

Materials. Philadelphia, PA.

Black, F. and L. High (1979) “Methodology for Determining Particulate and Gaseous Diesel Emissions,” in, The 

Measurement and Control of Diesel Particulate Emissions, Society of Automotive Engineers, p. 128.

Boldt, K. and B.R. Hall (1977) Significance of Tests for Petroleum Products, Philadelphia, PA, American Society for 

Testing and Materials, p. 30.

Chemical Rubber Company (CRC), (2008/2009), Handbook of Chemistry and Physics, 89th Ed., editor D. Lide, 

Cleveland, OH: CRC Press.

DOC (1929) Thermal Properties of Petroleum Products, U.S. Department of Commerce, National Bureau of Standards. 

Washington, DC. pp.16-21.

EIA (2001-2009b) Coal Distribution - Annual, U.S. Department of Energy, Energy Information Administration. 

Washington, DC. DOE/EIA.

EIA (2008a) Monthly Energy Review, September 2007 and Published Supplemental Tables on Petroleum Product detail. 

Energy Information Administration, U.S. Department of Energy, Washington, DC. DOE/EIA-0035(2007/9).

EIA (2008b) Documentation for Emissions of Greenhouse Gases in the United States 2006. DOE/EIA-0638(2006). 

October 2008.

EIA (2009a) Annual Energy Review, Energy Information Administration, U.S. Department of Energy, Washington, DC. 

DOE/EIA-0384(2008).

EIA (2009b) Petroleum Supply Annual, Energy Information Administration, U.S. Department of Energy, Washington, 

DC. Available online at <

http://www.eia.doe.gov/oil_gas/petroleum/data_publications/petroleum_supply_annual/psa_volume1/psa_volume1.ht

ml >.

EIA (2001-2009a) Annual Coal Report, U.S. Department of Energy, Energy Information Administration. Washington, 

DC. DOE/EIA 0584.

EIA (2001) Cost and Quality of Fuels for Electric Utility Plants 2000, Energy Information Administration. Washington, 

DC. August 2001. Available online at <http://www.eia.doe.gov/cneaf/electricity/cq/cq_sum.html>.

EIA (1990-2001) Coal Industry Annual, U.S. Department of Energy, Energy Information Administration. Washington, 

DC. DOE/EIA 0584.

EIA (1994) Emissions of Greenhouse Gases in the United States 1987-1992, Energy Information Administration, U.S. 

Department of Energy. Washington, DC. November, 1994. DOE/EIA 0573.

EIA (1993) Btu Tax on Finished Petroleum Products, Energy Information Administration, Petroleum Supply Division 

(unpublished manuscript, April 1993).

EPA (2010) Carbon Content Coefficients Developed for EPA's Inventory of Greenhouse Gases and Sinks. Office of Air 

and Radiation, Office of Atmospheric Programs, U.S. Environmental Protection Agency, Washington, D.C.

EPA (2009a), “Industry Overview and Current Reporting Requirements for Petroleum Refining and Petroleum Imports,” 

Petroleum Product Suppliers Technical Support Document for the Proposed Mandatory Reporting Rule. Office of Air 

and Radiation. 30 January, 2009.

EPA (2009b). Mandatory Reporting of Greenhouse Gases Rule. Federal Register Docket ID EPA-HQ-OAR-2008-0508-

2278, 30 September, 2009.
A-97

Gas Technology Institute (1992) Database as documented in W.E. Liss, W.H. Thrasher, G.F. Steinmetz, P. Chowdiah, and 

A. Atari, Variability of Natural Gas Composition in Select Major Metropolitan Areas of the United States. GRI92/0123. March 1992.

Guthrie, V.B. (ed.) (1960) Characteristics of Compounds, Petroleum Products Handbook, p.3-3. New York, NY, 

McGraw-Hill.

Hadaller, O.J. and A.M. Momenthy (1990) The Characteristics of Future Fuels, Part 1, “Conventional Heat Fuels”. 

Seattle, WA, Boeing Corp. September 1990. pp. 46-50.

Intergovernmental Panel on Climate Change (IPCC), 2006 IPCC Guidelines for National Greenhouse Gas Inventories. 

Prepared by the National Greenhouse Gas Inventories Programme (Japan, 2006)

Matar, S. and L. Hatch (2000), Chemistry of Petrochemical Processes, 2nd Ed. Gulf Publishing Company: Houston.

Martel, C.R., and L.C. Angello (1977) “Hydrogen Content as a Measure of the Combustion Performance of Hydrocarbon 

Fuels,” in Current Research in Petroleum Fuels, Volume I. New York, NY, MSS Information Company, p. 116.

Martin, S.W. (1960) “Petroleum Coke,” in Virgil Guthrie (ed.), Petroleum Processing Handbook, New York, NY, 

McGraw-Hill, pp. 14-15. 

Meyers, (2004), Handbook of Petroleum Refining Processes, 3rd ed., NY, NY: McGraw Hill.

National Institute for Petroleum and Energy Research (1990 through 2009) Motor Gasolines, Summer and Motor 

Gasolines, Winter.

NIPER (1993). C. Dickson, Aviation Turbine Fuels, 1992, NIPER-179 PPS93/2 (Bartlesville, OK: National Institute for 

Petroleum and Energy Research, March 1993).

Pennsylvania State University (PSU) (2010). Coal Sample Bank and Database. Data received by SAIC 18 February 2010 

from Gareth Mitchell, The Energy Institute, Pennsylvania State University.

Quick, Jeffrey (2010). “Carbon Dioxide Emission Factors for U.S. Coal by Origin and Destination,” Environmental 

Science & Technology, Forthcoming.

SAIC (2007) Analysis prepared by Science Applications International Corporation for EPA, Office of Air and Radiation, 

Market Policies Branch.

U.S. National Research Council (1927) International Critical Tables of Numerical Data, Physics, Chemistry, and 

Technology, New York, NY, McGraw-Hill. 

Unzelman, G.H. (1992) “A Sticky Point for Refiners: FCC Gasoline and the Complex Model,” Fuel Reformulation, 

July/August 1992, p. 29. 

USGS (1998) CoalQual Database Version 2.0, U.S. Geological Survey.

Wauquier, J., ed. (1995). Petroleum Refining, Crude Oil, Petroleum Products and Process Flowsheets (Editions Technip -

Paris, 1995) pg.225, Table 5.16.

 

 
A-98 Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2012

2.3. Methodology for Estimating Carbon Emitted from Non-Energy Uses of Fossil 

Fuels

Carbon (C) storage associated with the non-energy use of fossil fuels was calculated by multiplying each fuel’s 

potential emissions (i.e., each fuel’s total C content) by a fuel-specific storage factor, as listed in Table A-60. The 

remaining C—i.e., that which is not stored—is emitted. This sub-annex explains the methods and data sources employed 

in developing the storage factors for petrochemical feedstocks (industrial other coal, natural gas for non-fertilizer uses, 

LPG, pentanes plus, naphthas, other oils, still gas, special naphtha), asphalt and road oil, lubricants, waxes, and 

miscellaneous products. The storage factors24 for the remaining non-energy fuel uses are either based on values 

recommended for use by IPCC (2006), or when these were not available, assumptions based on the potential fate of C in 

the respective NEU products.

Table A-60: Fuel Types and Percent of C Stored for Non-Energy Uses

Sector/Fuel Type Storage Factor (%)

Industry -

Industrial Coking Coal a 10 

Industrial Other Coal b 70 

Natural Gas to Chemical Plants b 70 

Asphalt & Road Oil 100 

LPG b 70 

Lubricants 9 

Pentanes Plus b 70 

Naphtha (<401 deg. F) b 70 

Other Oil (>401 deg. F) b 70 

Still Gas b 70 

Petroleum Coke c 30 

Special Naphtha b 70 

Distillate Fuel Oil 50 

Waxes 58 

Miscellaneous Products 0 

Transportation -

Lubricants 9 

U.S. Territories -

Lubricants 9 

Other Petroleum (Misc. Prod.) 10 

- Not applicable

a

Includes processes for which specific coking coal consumption and emission factor data are not available. Consumption of coking coal for production of iron 

and steel is covered in the Industrial Processes chapter.

b The storage factor listed is the value for 2012. As described in this annex, the factor varies over time.

c Assumes petroleum coke consumption is for pigments. Consumption of petroleum coke for production of primary aluminum anodes, electric arc furnace 

anodes, titanium dioxide, ammonia, urea, and ferroalloys is covered in the Industrial Processes chapter. 

The following sections describe the non-energy uses in greater detail, outlining the methods employed and data 

used in estimating each storage factor. Several of the fuel types tracked by EIA are used in organic chemical synthesis and 

in other manufacturing processes, and are referred to collectively as “petrochemical feedstocks.” Because the methods and 

data used to analyze them overlap, they are handled as a group and are discussed first. Discussions of the storage factors 

for asphalt and road oil, lubricants, waxes, and miscellaneous products follow.

 

24 Throughout this section, references to “storage factors” represent the proportion of carbon stored.
A-99

Petrochemical Feedstocks

Petrochemical feedstocks—industrial other coal, natural gas for non-fertilizer uses, LPG, pentanes plus, 

naphthas, other oils, still gas, special naphtha—are used in the manufacture of a wide variety of man-made chemicals and 

products. Plastics, rubber, synthetic fibers, solvents, paints, fertilizers, pharmaceuticals, and food additives are just a few 

of the derivatives of these fuel types. Chemically speaking, these fuels are diverse, ranging from simple natural gas (i.e., 

predominantly CH4) to heavier, more complex naphthas and other oils.25

After adjustments for (1) use in industrial processes and (2) net exports, these eight fuel categories constituted 

approximately 197.3 Tg CO2 Eq., or 62 percent, of the 315.8 Tg CO2 Eq. of non-energy fuel consumption in 2012. For 

2012, the storage factor for the eight fuel categories was 70 percent. In other words, of the net consumption, 70 percent 

was destined for long-term storage in products—including products subsequently combusted for waste disposal—while 

the remaining 30 percent was emitted to the atmosphere directly as CO2 (e.g., through combustion of industrial byproducts) or indirectly as CO2 precursors (e.g., through evaporative product use). The indirect emissions include a variety 

of organic gases such as volatile organic compounds (VOCs) and carbon monoxide (CO), which eventually oxidize into 

CO2 in the atmosphere. The derivation of the storage factor is described in the following sections. 

Methodology and Data Sources

The petrochemical feedstocks storage factor is equal to the ratio of C stored in the final products to total C 

content for the non-energy fossil fuel feedstocks used in industrial processes, after adjusting for net exports of feedstocks. 

One aggregate storage factor was calculated to represent all eight fuel feedstock types. The feedstocks were grouped 

because of the overlap of their derivative products. Due to the many reaction pathways involved in producing 

petrochemical products (or wastes), it becomes extraordinarily complex to link individual products (or wastes) to their 

parent fuel feedstocks.

Import and export data for feedstocks were obtained from the Energy Information Administration (EIA) for the 

major categories of petrochemical feedstocks. EIA’s Petroleum Supply Annual publication tracks imports and exports of 

petrochemical feedstocks, including butanes, butylenes, ethane, ethylene, propane, propylene, LPG, and naphthas (i.e., 

most of the large volume primary chemicals produced by petroleum refineries). These imports and exports are already 

factored into the U.S. fuel consumption statistics. However, EIA does not track imports and exports of chemical 

intermediates and products produced by the chemical industry (e.g., xylenes, vinyl chloride), which are derived from the 

primary chemicals produced by the refineries. These products represent very large flows of C derived from fossil fuels 

(i.e., fossil C), so estimates of net flows not already considered in EIA’s dataset were developed for the entire time series

from 1990 to 2012.

The approach to estimate imports and exports involves three steps, listed here and then described in more detail 

below:

Step 1. Identify commodities derived from petrochemical feedstocks, and calculate net import/export for each.

Step 2. Estimate the C content for each commodity.

Step 3. Sum the net C imports/exports across all commodities.

Step 1 relies heavily on information provided by the National Petrochemical and Refiners Association (NPRA) 

and U.S. Bureau of the Census (BoC) trade statistics published by the U.S. International Trade Commission (USITC). 

NPRA provided a spreadsheet of the ten-digit BoC Harmonized Tariff Schedule (HTS) Commodity Codes used to compile 

import-export data for periodic reports issued to NPRA’s membership on trade issues. Additional feedstock commodities 

were identified by HTS code in the BoC data system and included in the net import/export analysis.

One of the difficulties in analyzing trade data is that a large portion of the outputs from the refining industry are 

fuels and fuel components, and it was difficult to segregate these from the outputs used for non-energy uses. The NPRAsupplied codes identify fuels and fuel components, thus providing a sound basis for isolating net imports/exports of 

petrochemical feedstocks. Although MTBE and related ether imports are included in the published NPRA data, these 

commodities are not included in the total net imports/exports calculated here, because it is assumed that they are fuel 

additives and do not contribute to domestic petrochemical feedstocks. Net exports of MTBE and related ethers are also 

not included in the totals, as these commodities are considered to be refinery products that are already accounted for in the

 

25 Naphthas are compounds distilled from petroleum containing 4 to 12 carbon atoms per molecule and having a boiling point less than 

401° F. “Other oils” are distillates containing 12 to 25 carbon atoms per molecule and having a boiling point greater than 401° F.
A-100 Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2012

EIA data. Imports and exports of commodities for which production and consumption data are provided by EIA (e.g., 

butane, ethylene, and liquefied petroleum gases) are also not included in the totals, to avoid double-counting.

Another difficulty is that one must be careful to assure that there is not double-counting of imports and exports in 

the data set. Other parts of the mass balance (described later) provide information on C flows, in some cases based on 

production data and in other cases based on consumption data. Production data relates only to production within the 

country; consumption data incorporates information on imports and exports as well as production. Because many 

commodities are emissive in their use, but not necessarily their production, consumption data is appropriately used in 

calculations for emissive fates. For purposes of developing an overall mass balance on U.S. non-energy uses of C, for 

those materials that are non-emissive (e.g., plastics), production data is most applicable. And for purposes of adjusting the 

mass balance to incorporate C flows associated with imports and exports, it was necessary to carefully review whether or 

not the mass balance already incorporated cross-boundary flows (through the use of consumption data), and to adjust the 

import/export balance accordingly. 

The BoC trade statistics are publicly available26 and cover a complete time series from 1990 to 2012. These 

statistics include information on imports and exports of thousands of commodities. After collecting information on annual 

flows of the more than 100 commodities identified by NPRA, Step 2 involves calculating the C content for each 

commodity from its chemical formula. In cases where the imports and exports were expressed in units of volume, rather 

than mass, they were converted to mass based on the commodities’ densities. 

Step 3 involves summing the net C imports/exports across all commodities. The results of this step are shown in 

Table A-61. As shown in the table, the United States has been a net exporter of chemical intermediates and products 

throughout the 1990 to 2012 period.

Table A-61: Net Exports of Petrochemical Feedstocks, 1990 – 2012 (Tg CO2 Eq.)

1990 1995 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012

Net Exports 12.0 11.1 8.3 1.8 7.3 14.8 20.2 6.5 4.1 8.4 4.5 9.0 7.7 8.3 9.8

After adjusting for imports and exports, the C budget is adjusted for the quantity of C that is used in the 

Industrial Processes sector of the Inventory. Fossil fuels used for non-energy purposes in industrial processes—and for 

which C emissions and storage have been characterized through mass balance calculations and/or emission factors that 

directly link the non-energy use fossil fuel raw material and the industrial process product—are not included in the nonenergy use sector. These industrial processes (and their non-energy use fossil fuel raw materials) include iron and steel 

(coal coke), primary aluminum (petroleum coke), titanium oxide (petroleum coke), ferroalloys (petroleum coke), and 

ammonia and urea (petroleum coke and natural gas).

For each year of the Inventory, the total C content of non-energy uses was calculated by starting with the EIA 

estimate of non-energy use, and reducing it by the adjustment factor for net exports (see Table A-61) to yield net domestic 

fuel consumption for non-energy. The balance was apportioned to either stored C or emissive C, based on a storage factor. 

The overall storage factor for the feedstocks was determined by developing a mass balance on the C in 

feedstocks, and characterizing products, uses, and environmental releases as resulting in either storage or emissions. The 

total C in the system was estimated by multiplying net domestic consumption for non-energy by the C content of each of 

the feedstocks (i.e., industrial other coal, natural gas for non-fertilizer uses, LPG, pentanes plus, naphthas, other oils, still 

gas, special naphtha). C content values for the fuel feedstocks are discussed in the Estimating Emissions from Fossil Fuel 

Combustion and Estimating the Carbon Content from Fossil Fuel Combustion Annexes.

Next, C pools and releases in a variety of industrial releases, energy recovery processes, and products were 

characterized. The C fate categories are plastics, energy recovery, synthetic rubber, synthetic fibers, organic solvents, C 

black, detergents and personal cleansers, industrial non-methane volatile organic compound (NMVOC) emissions, 

hazardous waste incineration, industrial toxic chemical (i.e., TRI) releases, pesticides, food additives, antifreeze and 

deicers (glycols), and silicones.27 

 

26 See the U.S International Trade Commission (USITC) Trade Dataweb at <http://dataweb.usitc.gov/>. 

27 For the most part, the releases covered by the U.S. Toxic Release Inventory (TRI) represent air emissions or water discharges

associated with production facilities. Similarly, VOC emissions are generally associated with production facilities. These emissions 

could have been accounted for as part of the Waste chapter, but because they are not necessarily associated with waste management, they 

were included here. Toxic releases are not a “product” category, but they are referred to as such for ease of discussion. 
A-101

The C in each product or waste produced was categorized as either stored or emitted. The aggregate storage 

factor is the C-weighted average of storage across fuel types. As discussed later in the section on uncertainty, the sum of 

stored C and emitted C (i.e., the outputs of the system) exceeded total C consumption (i.e., the inputs to the system) for 

some years in the time series.28 To address this mass imbalance, the storage factor was calculated as C storage divided by 

total C outputs (rather than C storage divided by C inputs). 

Note that the system boundaries for the storage factor do not encompass the entire life-cycle of fossil-based C 

consumed in the United States insofar as emissions of CO2 from waste combustion are accounted for separately in the 

Inventory and are discussed in the Incineration of Waste section of the Energy chapter. 

The following sections provide details on the calculation steps, assumptions, and data sources employed in 

estimating and classifying the C in each product and waste shown in Table A-62. Summing the C stored and dividing it by 

total C outputs yields the overall storage factor, as shown in the following equation for 2012: 

Overall Storage Factor = C Stored / (C Stored + C Emitted) = 

136.7 Tg CO2 Eq. / (136.7 + 60.3) Tg CO2 Eq. = 70%

Table A-62: C Stored and Emitted by Products from Feedstocks in 2012 (Tg CO2 Eq.)

Product/Waste Type

C Stored

(Tg CO2 Eq.)

C Emitted

(Tg CO2 Eq.)

Industrial Releases 0.1 5.2 

 TRI Releases 0.1 1.0 

 Industrial VOCs - 3.4 

 Non-combustion CO - 0.5 

 Hazardous Waste Incin. - 0.4 

Energy Recovery - 41.3 

Products 136.7 13.8

 Plastics 118.4 -

 Synthetic Rubber 10.6 -

 Antifreeze and deicers - 0.7 

 Abraded tire rubber - 0.3 

 Food additives - 0.8 

 Silicones 0.5 -

 Synthetic Fiber 6.9 -

 Pesticides 0.2 0.2 

 Soaps, shampoos, detergents - 6.5 

 Solvent VOCs - 5.2

Total 136.7 60.3

- Not applicable

Note: Totals may not sum due to independent rounding.

The three categories of C accounted for in the table are industrial releases, energy recovery, and products. Each 

is discussed below.

Industrial Releases

Industrial releases include toxic chemicals reported through the Toxics Release Inventory, industrial emissions of 

volatile organic compounds (VOCs), CO emissions (other than those related to fuel combustion), and emissions from 

hazardous waste incineration.

 

28 Overall, there was fairly close agreement between inputs and outputs: for the entire 1990 through 2012 time series, inputs exceeded 

outputs by a time-weighted average of 0.2 percent. During the period 1990 through 2000, carbon inputs exceeded carbon outputs (i.e., 

the sum of carbon stored and carbon emitted) by a time-weighted average of 10 percent. For those years, the assumption was made that 

the “missing” carbon was lost through fates leading to emissions. This discrepancy shifted during the period from 2001 through 2012, in 

which carbon outputs exceeded carbon inputs by a time-weighted average of 12 percent.
A-102 Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2012

TRI Releases

Fossil-derived C is found in many toxic substances released by industrial facilities. The Toxics Release 

Inventory (TRI), maintained by EPA, tracks these releases by chemical and environmental release medium (i.e., land, air, 

or water) on a biennial basis (EPA 2000b). By examining the C contents and receiving media for the top 35 toxic 

chemicals released, which account for 90 percent of the total mass of chemicals, the quantity of C stored and emitted in the 

form of toxic releases can be estimated.

The TRI specifies releases by chemical, so C contents were assigned to each chemical based on molecular 

formula. The TRI also classifies releases by disposal location as either off-site or on-site. The on-site releases are further 

subdivided into air emissions, surface water discharges, underground injection, and releases to land; the latter is further 

broken down to disposal in a RCRA Subtitle C (i.e., hazardous waste) landfill or to “Other On-Site Land Disposal.”29 The 

C released in each disposal location is provided in Table A-63. 

Each on-site classification was assigned a storage factor. A 100 percent storage factor was applied to disposition 

of C to underground injection and to disposal to RCRA-permitted landfills, while the other disposition categories were 

assumed to result in an ultimate fate of emission as CO2 (i.e., a storage factor of zero was applied to these categories.) The 

release allocation is not reported for off-site releases; therefore, the approach was to develop a C-weighted average storage 

factor for the on-site C and apply it to the off-site releases. 

For the remaining 10 percent of the TRI releases, the weights of all chemicals were added and an average C 

content value, based upon the top 35 chemicals’ C contents, was applied. The storage and emission allocation for the 

remaining 10 percent of the TRI releases was carried out in the same fashion as for the 35 major chemicals.

Data on TRI releases for the full 1990 through 2012 time series were not readily available. Since this category is 

small (less than 1 Tg C emitted and stored), the 1998 value was applied for the entire time series. 

Table A-63: 1998 TRI Releases by Disposal Location (Gg CO2 Eq.)

Disposal Location

Carbon Stored

(Gg CO2 Eq.) 

Carbon Emitted

(Gg CO2 Eq.) 

Air Emissions - 924.0

Surface Water Discharges - 6.7

Underground Injection 89.4 -

RCRA Subtitle C Landfill Disposal 1.4 -

Other On-Site Land Releases - 15.9

Off-site Releases 6.4 36.0

Total 97.2 982.6

- Not applicable

Note: Totals may not sum due to independent rounding.

Volatile Organic Compound Emissions from Industrial Processes and Solvent Evaporation Emissions

Data on annual non-methane volatile organic compound (NMVOC) emissions were obtained from preliminary 

data (EPA 2013a), and disaggregated based on EPA (2003), which, in its final iteration, will be published on the National 

Emission Inventory (NEI) Air Pollutant Emission Trends web site. The 1990-2013 Trends data include information on 

NMVOC emissions by end-use category; some of these fall into the heading of “industrial releases” in Table A-63 above, 

and others are related to “product use”; for ease of discussion, both are covered here. The end-use categories that 

represent “Industrial NMVOC Emissions” include some chemical and allied products, certain petroleum related industries, 

and other industrial processes. NMVOC emissions from solvent utilization (product use) were considered to be a result of 

non-energy use of petrochemical feedstocks. These categories were used to distinguish non-energy uses from energy uses; 

other categories where VOCs could be emitted due to combustion of fossil fuels were excluded to avoid double counting. 

Data for 2012 are not yet available, so they have been set equal to 2011 values.

Because solvent evaporation and industrial NMVOC emission data are provided in tons of total NMVOCs, 

assumptions were made concerning the average C content of the NMVOCs for each category of emissions. The 

 

29 Only the top 9 chemicals had their land releases separated into RCRA Landfills and Other Land Disposal. For the remaining 

chemicals, it was assumed that the ratio of disposal in these two categories was equal to the carbon-weighted average of the land disposal 

fate of the top 9 chemicals (i.e., 8 percent attributed to RCRA Landfills and 92 percent in the “Other” category).
A-103

assumptions for calculating the C fraction of industrial and solvent utilization emissions were made separately and differ 

significantly. For industrial NMVOC emissions, a C content of 85 percent was assumed. This value was chosen to reflect 

the C content of an average volatile organic compound based on the list of the most abundant NMVOCs provided in the 

Trends Report. The list contains only pure hydrocarbons, including saturated alkanes (C contents ranging from 80 to 85 

percent based upon C number), alkenes (C contents approximately 85 percent), and some aromatics (C contents 

approximately 90 percent, depending upon substitution). 

An EPA solvent evaporation emissions dataset (Tooly 2001) was used to estimate the C content of solvent 

emissions. The dataset identifies solvent emissions by compound or compound category for six different solvent end-use 

categories: degreasing, graphic arts, dry cleaning, surface coating, other industrial processes, and non-industrial processes. 

The percent C of each compound identified in the dataset was calculated based on the molecular formula of the individual 

compound (e.g., the C content of methylene chloride is 14 percent; the C content of toluene is 91 percent). For solvent 

emissions that are identified in the EPA dataset only by chemical category (e.g., butanediol derivatives) a single individual 

compound was selected to represent each category, and the C content of the category was estimated based on the C content 

of the representative compound. The overall C content of the solvent evaporation emissions for 1998, estimated to be 56 

percent, is assumed to be constant across the entire time series.

The results of the industrial and solvent NMVOC emissions analysis are provided in Table A-64 for 1990 

through 2012. Industrial NMVOC emissions in 2012 were 3.4 Tg CO2 Eq. and solvent evaporation emissions in 2012

were 5.2 Tg CO2 Eq.

Table A-64: Industrial and Solvent NMVOC Emissions

1990 1995 2000 2005 2006 2007 2008 2009 2010 2011 2012

Industrial NMVOCsa

NMVOCs (‘000 Short Tons) 1,279 1,358 802 824 878 933 987 752 972 1,192 1,192

Carbon Content (%) 85% 85% 85% 85% 85% 85% 85% 85% 85% 85% 85%

Carbon Emitted (Tg CO2 Eq.) 3.6 3.8 2.3 2.3 2.5 2.6 2.8 2.1 2.7 3.4 3.4 

Solvent Evaporationb

Solvents (‘000 Short Tons) 5,750 6,183 4,832 4,245 3,930 3,614 3,298 3,129 2,959 2,790 2,790 

Carbon Content (%) 56% 56% 56% 56% 56% 56% 56% 56% 56% 56% 56%

Carbon Emitted (Tg CO2 Eq.) 10.8 11.6 9.0 7.9 7.4 6.8 6.2 5.9 5.5 5.2 5.2 

a Includes emissions from chemical and allied products, petroleum and related industries, and other industrial processes categories.

b Includes solvent usage and solvent evaporation emissions from degreasing, graphic arts, dry cleaning, surface coating, other industrial processes, and nonindustrial processes.

Non-Combustion Carbon Monoxide Emissions

Carbon monoxide (CO) emissions data were also obtained from the NEI preliminary data (EPA 2013a), and

disaggregated based on EPA (2003). There are three categories of CO emissions in the report that are classified as 

process-related emissions not related to fuel combustion. These include chemical and allied products manufacturing, 

metals processing, and other industrial processes. Some of these CO emissions are accounted for in the Industrial 

Processes section of this report, and are therefore not accounted for in this section. These include total C emissions from 

the primary aluminum, titanium dioxide, iron and steel, and ferroalloys production processes. The total C (CO and CO2) 

emissions from oil and gas production, petroleum refining, and asphalt manufacturing are also accounted for elsewhere in 

this Inventory. Biogenic emissions (e.g., pulp and paper process emissions) are accounted for in the Land Use, Land-Use 

Change and Forestry chapter and excluded from calculation of CO emissions in this section. Those CO emissions that are 

not accounted for elsewhere are considered to be by-products of non-fuel use of feedstocks, and are thus included in the 

calculation of the petrochemical feedstocks storage factor. Table A-65 lists the CO emissions that remain after taking into 

account the exclusions listed above. As data for 2012 are not yet available, they have been set equal to 2011 values. 

Table A-65: Non-Combustion Carbon Monoxide Emissions

1990 1995 2000 2005 2006 2007 2008 2009 2010 2011 2012

Thousand short tons CO 489 481 623 461 443 426 408 461 405 348 348

Carbon Emitted (Tg CO2 Eq.) 0.7 0.7 0.9 0.7 0.6 0.6 0.6 0.7 0.6 0.5 0.5 

Includes emissions from chemical and allied products, petroleum and related industries, metals processing, and other industrial processes categories.
A-104 Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2012

Hazardous Waste Incineration 

Hazardous wastes are defined by the EPA under the Resource Conservation and Recovery Act (RCRA).30 

Industrial wastes, such as rejected products, spent reagents, reaction by-products, and sludges from wastewater or air 

pollution control, are federally regulated as hazardous wastes if they are found to be ignitable, corrosive, reactive, or toxic 

according to standardized tests or studies conducted by the EPA. 

Hazardous wastes must be treated prior to disposal according to the federal regulations established under the 

authority of RCRA. Combustion is one of the most common techniques for hazardous waste treatment, particularly for 

those wastes that are primarily organic in composition or contain primarily organic contaminants. Generally speaking, 

combustion devices fall into two categories: incinerators that burn waste solely for the purpose of waste management, and 

boilers and industrial furnaces (BIFs) that burn waste in part to recover energy from the waste. More than half of the 

hazardous waste combusted in the United States is burned in BIFs; because these processes are included in the energy 

recovery calculations described below, they are not included as part of hazardous waste incineration. 

EPA’s Office of Solid Waste requires biennial reporting of hazardous waste management activities, and these 

reports provide estimates of the amount of hazardous waste burned for incineration or energy recovery. EPA stores this 

information in its Resource Conservation and Recovery Act (RCRA) Information system (EPA 2013b), formerly reported 

in its Biennial Reporting System (BRS) database (EPA 2000a, 2009). Combusted hazardous wastes are identified based 

on EPA-defined management system types M041 through M049 (incineration). Combusted quantities are grouped into 

four representative waste form categories based on the form codes reported in the BRS: aqueous liquids, organic liquids 

and sludges, organic solids, and inorganic solids. To relate hazardous waste quantities to C emissions, “fuel equivalent” 

factors were derived for hazardous waste by assuming that the hazardous wastes are simple mixtures of a common fuel, 

water, and noncombustible ash. For liquids and sludges, crude oil is used as the fuel equivalent and coal is used to 

represent solids. 

Fuel equivalent factors were multiplied by the tons of waste incinerated to obtain the tons of fuel equivalent. 

Multiplying the tons of fuel equivalent by the C content factors (discussed in the Estimating the Carbon Content from 

Fossil Fuel Combustion Annex) yields tons of C emitted. Implied C content is calculated by dividing the tons of C 

emitted by the associated tons of waste incinerated.

Waste quantity data for hazardous wastes were obtained from EPA’s RCRA Information/BRS database for 

reporting years 1989, 1991, 1993, 1995, 1997, 1999, 2001, 2003, 2005, 2007, 2009, and 2011 (EPA 2000a, 2009, 2013b). 

Combusted waste quantities were obtained from Form GM (Generation and Management) for wastes burned on site and 

Form WR (Wastes Received) for waste received from off-site for combustion. For each of the waste types, assumptions 

were developed on average waste composition (see Table A-66). Regulations require incinerators to achieve at least 99.99 

percent destruction of organics; this formed the basis for assuming the fraction of C oxidized. Emissions from hazardous 

waste incineration in 2012 were 0.4 Tg CO2 Eq. Table A-67 lists the CO2 emissions from hazardous waste incineration. 

Table A-66: Assumed Composition of Combusted Hazardous Waste by Weight (Percent)

Waste Type Water (%) Noncombustibles (%) Fuel Equivalent (%)

Aqueous Waste 90 5 5

Organic Liquids and Sludges 40 20 40

Organic Solids 20 40 40

Inorganic Solids 20 70 10

Table A-67: CO2 Emitted from Hazardous Waste Incineration (Tg CO2 Eq.)

1990 1995 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012

C Emissions 1.1 1.7 1.0 0.6 0.6 0.6 0.6 0.6 0.5 0.4 0.4 0.3 0.3 0.4 0.4

Energy Recovery

The amount of feedstocks combusted for energy recovery was estimated from data included in EIA’s 

Manufacturers Energy Consumption Survey (MECS) for 1991, 1994, 1998, 2002, and 2006 (EIA 1994, 1997, 2001, 2005, 

2010, 2013b). Some fraction of the fossil C exiting refineries and designated for use for feedstock purposes actually ends 

up being combusted for energy recovery (despite the designation of feedstocks as a “non-energy” use) because the 

chemical reactions in which fuel feedstocks are used are not 100 percent efficient. These chemical reactions may generate 

 

30 [42 U.S.C. §6924, SDWA §3004]
A-105

unreacted raw material feedstocks or generate by-products that have a high energy content. The chemical industry and 

many downstream industries are energy-intensive and often have boilers or other energy recovery units on-site, and thus 

these unreacted feedstocks or by-products are often combusted for energy recovery. Also, as noted above in the section on 

hazardous waste incineration, regulations provide a strong incentive—and in some cases require—burning of organic 

wastes generated from chemical production processes. 

Information available from the MECS include data on the consumption for energy recovery of “other” fuels in 

the petroleum and coal products, chemicals, primary metals, nonmetallic minerals, and other manufacturing sectors. These 

“other” fuels include refinery still gas; waste gas; waste oils, tars, and related materials; petroleum coke, coke oven and 

blast furnace gases; scrap tires; liquor or black liquor; woodchips and bark; and other uncharacterized fuels. Fuel use of 

petroleum coke is included separately in the fuel use data provided annually by EIA, and energy recovery of coke oven gas 

and blast furnace gas (i.e., by-products of the iron and steel production process) is addressed in the Iron and Steel 

production section in the Industrial Processes chapter. Consumption of refinery still gas in the refinery sector is also 

included separately in the fuel use data from EIA. The combustion of scrap tires in cement kilns, lime kilns, and electric 

arc furnaces is accounted for in the Waste Incineration chapter; data from the Rubber Manufacturers Association (RMA 

2009a) were used to difference out energy recovery from scrap tires in these industries. Consumption of net steam, 

assumed to be generated from fossil fuel combustion, is also included separately in the fuel use data from EIA. Therefore, 

these categories of “other” fuels are addressed elsewhere in the Inventory and not considered as part of the petrochemical 

feedstocks energy recovery analysis. Liquor or black liquor and woodchips and bark are assumed to be biogenic fuels, in 

accordance with IPCC (2006), and therefore are not included in the Inventory. The remaining categories of fuels, 

including waste gas; waste oils, tars, and related materials; and other uncharacterized fuels are assumed to be 

petrochemical feedstocks burned for energy recovery (see Table A-68). The conversion factors listed in the Estimating 

Emissions from Fossil Fuel Combustion Annex were used to convert the Btu values for each fuel feedstock to Tg CO2. 

Petrochemical feedstocks combusted for energy recovery corresponded to 42.5 Tg CO2 Eq. in 1991, 35.1 Tg CO2 Eq. in

1994, 58.0 Tg CO2 Eq. in 1998, 70.6 Tg CO2 Eq. in 2002, 74.8 Tg CO2 Eq. in 2006, and 41.3 Tg CO2 Eq. in 2010. Values 

for petrochemical feedstocks burned for energy recovery for years between 1991 and 1994, between 1994 and 1998, 

between 1998 and 2002, between 2002 and 2006, and between 2007 and 2010 have been estimated by linear interpolation. 

The value for 1990 is assumed to be the same as the value for 1991, and 2011 and 2012 are assumed to be the same as the 

value for 2010 (Table A-69).

Table A-68: Summary of 2010 MECS Data for Other Fuels Used in Manufacturing/Energy Recovery (Trillion Btu)

Subsector and Industry NAICS CODE Waste Gasa Waste Oils/Tarsb

Refinery Still 

Gasc Net Steamd Other Fuelse

Printing and Related Support 323 0 0 0 0 0

Petroleum and Coal Products 324 0 6 1349 153 54

Chemicals 325 376 7 0 266 110

Plastics and Rubber Products 326 0 0 0 0 0

Nonmetallic Mineral Products 327 1 7 0 0 5

Primary Metals 331 0 0 0 12 34

Fabricated Metal Products 332 0 0 0 0 0

Machinery 333 0 0 0 0 1

Computer and Electronic Products 334 0 0 0 0 0

Electrical Equip., Appliances, Components 335 0 0 0 0 0

Transportation Equipment 336 2 0 0 0 3

Furniture and Related Products 337 0 0 0 0 0

Miscellaneous 339 0 0 0 0 0

Total (Trillion Btu) 379 20 1349 432 205

Average C Content (Tg/QBtu) 18.14 20.62 17.51 0 19.37

Fraction Oxidized 1 1 1 0 1

Total C (Tg) 6.88 0.41 23.62 0.00 3.98

Total C (Tg) (ex. still gas from refining) 6.88 0.41 - - 3.98 

- Not applicable

a C content: Waste Gas is assumed to be same as naphtha <401 deg. F

b C content: Waste Oils/Tars is assumed to be same as asphalt/road oil

c Refinery "still gas" fuel consumption is reported elsewhere in the Inventory and is excluded from the total C content estimate

d Net steam fuel consumption is reported elsewhere in the Inventory and is excluded from the total C content estimate

e C content: "Other" is assumed to be the same as petrochemical feedstocks
A-106 Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2012

Table A-69: Carbon Emitted from Fuels Burned for Energy Recovery (Tg CO2 Eq.)

1990 1995 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012

C Emissions 42.5 40.8 64.3 67.4 70.6 71.6 72.7 73.7 74.8 66.4 58.1 49.7 41.3 41.3 41.3

Products

More C is found in products than in industrial releases or energy recovery. The principal types of products are 

plastics; synthetic rubber; synthetic fiber; C black; pesticides; soaps, detergents, and cleansers; food additives; antifreeze 

and deicers (glycols); silicones; and solvents. Solvent evaporation was discussed previously along with industrial releases 

of NMVOCs; the other product types are discussed below. 

Plastics

Data on annual production of plastics through 2005 were taken from the American Plastics Council (APC), as 

published in Chemical & Engineering News and on the APC and Society of Plastics Industry (SPI) websites, and through 

direct communication with the APC (APC 2000, 2001, 2003 through 2006; SPI 2000; Eldredge-Roebuck 2000). Data for

2006 through 2012 were taken directly or derived from the American Chemistry Council (ACC 2007 through 2010 

supplemented by Vallianos 2011, 2012, 2013). In 2009, the American Chemistry Council consolidated the resin 

categories for which it reports plastics production. Production numbers in the original categories were provided via 

personal correspondence for 2009, 2011, and 2012 (Vallianos 2011, 2012, 2013). Production figures for the consolidated 

resin categories in 2010 were linearly interpolated from 2009 and 2011 data. Production was organized by resin type (see 

Table A-70) and by year. 

Several of the resin categories included production from Canada and/or Mexico, in addition to the U.S. values for 

part of the time series. The production data for the affected resins and years were corrected using an economic adjustment 

factor, based on the percent of North American production value in this industry sector accounted for by the United States. 

A C content was then assigned for each resin. These C contents were based on molecular formulae and are listed in Table 

A-71 and Table A-72. In cases where the resin type is generic, referring to a group of chemicals and not a single polymer 

(e.g., phenolic resins, other styrenic resins), a representative compound was chosen. For other resins, a weighted C 

content of 68 percent was assumed (i.e., it was assumed that these resins had the same content as those for which a 

representative compound could be assigned).

There were no emissive uses of plastics identified, so 100 percent of the C was considered stored in products. As 

noted in the chapter, an estimate of emissions related to the combustion of these plastics in the municipal solid waste 

stream can be found in the Incineration of Waste section of the Energy chapter; those emissions are not incorporated in the 

mass balance for feedstocks (described in this annex) to avoid double-counting.
A-107

Table A-70: 2012 Plastic Resin Production (Tg dry weight) and C Stored (Tg CO2 Eq.)

Resin Type

2012 Productiona

(Tg dry weight)

Carbon Stored

(Tg CO2 Eq.)

Epoxy 0.3 0.8

Urea 0.5 0.6

Melamine 0.5 0.5

Phenolic 1.4 3.9

Low-Density Polyethylene (LDPE) 2.9 9.1

Linear Low-Density Polyethylene (LLDPE) 5.7 17.8

High Density Polyethylene (HDPE) 7.5 23.5

Polypropylene (PP) 6.7 21.1

Acrylonitrile-butadiene-styrene (ABS) 0.4 1.3

Other Styrenicsc 0.5 1.7

Polystyrene (PS) 2.3 7.8

Nylon 0.5 1.2

Polyvinyl chloride (PVC)b 6.5 9.1

Thermoplastic Polyester 3.5 8.0

All Other (including Polyester (unsaturated)) 5.7 14.5

Total 44.8 120.9

a Production estimates provided by the American Chemistry Council include Canadian production for Urea, Melamine, Phenolic, LDPE, LLDPE, HDPE, PP, ABS, 

SAN, Other Styrenics, PS, Nylon, PVC, and Thermoplastic Polyester, and Mexican production for PP, ABS, SAN, Other Styrenics, Nylon, and Thermoplastic 

Polyester. Values have been adjusted to account just for U.S. production.

b

Includes copolymers

c

Includes Styrene-acrylonitrile (SAN)

Note: Totals may not sum due to independent rounding.

Table A-71: Assigned C Contents of Plastic Resins (% by weight)

Resin Type C Content Source of C Content Assumption

Epoxy 76% Typical epoxy resin made from epichlorhydrin and bisphenol A

Polyester (Unsaturated) 63% Poly (ethylene terephthalate) (PET)

Urea 34% 50% carbamal, 50% N-(hydroxymethyl) urea *

Melamine 29% Trimethylol melamine *

Phenolic 77% Phenol

Low-Density Polyethylene (LDPE) 86% Polyethylene

Linear Low-Density Polyethylene (LLDPE) 86% Polyethylene

High Density Polyethylene (HDPE) 86% Polyethylene

Polypropylene (PP) 86% Polypropylene

Acrylonitrile-Butadiene-Styrene (ABS) 85% 50% styrene, 25% acrylonitrile, 25% butadiene

Styrene-Acrylonitrile (SAN) 80% 50% styrene, 50% acrylonitrile

Other Styrenics 92% Polystyrene

Polystyrene (PS) 92% Polystyrene

Nylon 65% Average of nylon resins (see Table A-72)

Polyvinyl Chloride (PVC) 38% Polyvinyl chloride

Thermoplastic Polyester 63% Polyethylene terephthalate

All Other 69% Weighted average of other resin production

*Does not include alcoholic hydrogens.
A-108 Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2012

Table A-72: Major Nylon Resins and their C Contents (% by weight)

Resin C Content

Nylon 6 64%

Nylon 6,6 64%

Nylon 4 52%

Nylon 6,10 68%

Nylon 6,11 69%

Nylon 6,12 70%

Nylon 11 72%

Synthetic Rubber

Data on synthetic rubber in tires were derived from data on the scrap tire market and the composition of scrap 

tires from the Rubber Manufacturers’ Association (RMA). The market information is presented in the report U.S. Scrap 

Tire Management Summary: 2005-2009 (RMA 2011), while the tire composition information is from the “Scrap Tires, 

Facts and Figures” section of the organization’s website (RMA 2009). Data on synthetic rubber in other products (durable 

goods, nondurable goods, and containers and packaging) were obtained from EPA’s Municipal Solid Waste in the United 

States reports (1996 through 2003a, 2005, 2007b, 2008, 2009a, 2011a, 2013c; 2014) and detailed unpublished backup data 

for some years not shown in the Characterization of Municipal Solid Waste in the United States reports (Schneider 2007). 

The abraded rubber from scrap passenger tires was assumed to be 2.5 lbs per scrap tire, while the abraded rubber from 

scrap commercial tires was assumed to be 10 lbs per scrap tire. Data on abraded rubber weight were obtained by 

calculating the average weight difference between new and scrap tires (RMA 20011). RMA data were not yet available 

for 2010 through 2012, so they were set equal to 2009 values. 

A C content for synthetic rubber (90 percent for tire synthetic rubber and 85 percent for non-tire synthetic 

rubber) was assigned based on the weighted average of C contents (based on molecular formula) by elastomer type 

consumed in 1998, 2001, and 2002 (see Table A-73). The 1998 consumption data were obtained from the International 

Institute of Synthetic Rubber Producers (IISRP) press release “Synthetic Rubber Use Growth to Continue Through 2004, 

Says IISRP and RMA” (IISRP 2000). The 2001 and 2002 consumption data were obtained from the IISRP press release, 

“IISRP Forecasts Moderate Growth in North America to 2007” (IISRP 2003).

The rubber in tires that is abraded during use (the difference between new tire and scrap tire rubber weight) was 

considered to be 100 percent emitted. Other than abraded rubber, there were no emissive uses of scrap tire and non-tire 

rubber identified, so 100 percent of the non-abraded amount was assumed stored. Emissions related to the combustion of 

rubber in scrap tires and consumer goods can be found in the Incineration of Waste section of the Energy chapter.

Table A-73: 2002 Rubber Consumption (Gg) and C Content (%)

Elastomer Type 2002 Consumption (Gg)* C Content

SBR Solid 768 91%

Polybutadiene 583 89%

Ethylene Propylene 301 86%

Polychloroprene 54 59%

NBR Solid 84 77%

Polyisoprene 58 88%

Others 367 88%

Weighted Average - 90%

Total 2,215 -

* Includes consumption in Canada.

- Not applicable

Note: Totals may not sum due to independent rounding.

Synthetic Fibers

Annual synthetic fiber production data were obtained from the Fiber Economics Bureau, as published in 

Chemical & Engineering News (FEB 2001, 2003, 2005, 2007, 2009, 2010, 2011, 2012, 2013). These data are organized 

by year and fiber type. For each fiber, a C content was assigned based on molecular formula (see Table A-74). For 

polyester, the C content for poly (ethylene terephthalate) (PET) was used as a representative compound. For nylon, the 

average C content of nylon 6 and nylon 6.6 was used, since these are the most widely produced nylon fibers. Cellulosic 

fibers, such as acetate and rayon, have been omitted from the synthetic fibers’ C accounting displayed here because much 
A-109

of their C is of biogenic origin and carbon fluxes from biogenic compounds are accounted for in the Land Use, Land-Use 

Change and Forestry chapter. These fibers account for only 4 percent of overall fiber production by weight.

There were no emissive uses of fibers identified, so 100 percent of the C was considered stored. Note that 

emissions related to the combustion of textiles in municipal solid waste are accounted for under the Incineration of Waste 

section of the Energy chapter.

Table A-74: 2012 Fiber Production (Tg), C Content (%), and C Stored (Tg CO2 Eq.)

Fiber Type

Production

(Tg) C Content

C Stored

(Tg CO2 Eq.)

Polyester 1.2 63% 2.8

Nylon 0.6 64% 1.3

Olefin 1.0 86% 3.2

Acrylic + 68% 0.1

Total 2.8 - 7.3

+ Less than 0.05 Tg 

- Not applicable

Note: Totals may not sum due to independent rounding

Pesticides

Pesticide consumption data were obtained from the 1994/1995, 1996/1997, 1998/1999, 2000/2001, 2006/2007 

Pesticides Industry Sales and Usage Market Estimates (EPA 1998, 1999, 2002, 2004, 2011b) reports. The most recent 

data available were for 2007, so it was assumed that the 2008 through 2012 consumption was equal to that of 2007. 

Active ingredient compound names and consumption weights were available for the top 25 agriculturally-used pesticides 

and top 10 pesticides used in the home and garden and the industry/commercial/government categories. The report 

provides a range of consumption for each active ingredient; the midpoint was used to represent actual consumption. Each 

of these compounds was assigned a C content value based on molecular formula. If the compound contained aromatic 

rings substituted with chlorine or other halogens, then the compound was considered persistent and the C in the compound 

was assumed to be stored. All other pesticides were assumed to release their C to the atmosphere. Over one-third of 2007 

total pesticide active ingredient consumption was not specified by chemical type in the Sales and Usage report (EPA 

2011b). This unspecified portion of the active ingredient consumption was treated as a single chemical and assigned a C 

content and a storage factor based on the weighted average of the known chemicals’ values. 

Table A-75: Active Ingredient Consumption in Pesticides (Million lbs.) and C Emitted and Stored (Tg CO2 Eq.) in 2007

Pesticide Use*

Active Ingredient 

(Million lbs.)

C Emitted 

(Tg CO2 Eq.)

C Stored 

(Tg CO2 Eq.)

Agricultural Uses 473.5 0.1 0.1 

Non-Agricultural Uses 76.8 + +

 Home & Garden 30.3 + +

 Industry/Gov't/Commercial 46.5 + +

Other 337.7 0.1 0.1 

Total 888.0 0.2 0.2 

+ Less than 0.05 Tg CO2 Eq.

* 2007 estimates (EPA 2011b).

Note: Totals may not sum due to independent rounding.

Soaps, Shampoos, and Detergents

Cleansers—soaps, shampoos, and detergentsare among the major consumer products that may contain fossil 

C. All of the C in cleansers was assumed to be fossil-derived, and, as cleansers eventually biodegrade, all of the C was 

assumed to be emitted. The first step in estimating C flows was to characterize the “ingredients” in a sample of cleansers. 

For this analysis, cleansers were limited to the following personal household cleaning products: bar soap, shampoo, 

laundry detergent (liquid and granular), dishwasher detergent, and dishwashing liquid. Data on the annual consumption of 

household personal cleansers were obtained from the U.S. Census Bureau 1992, 1997, 2002, and 2007 Economic Census 

(U.S. Bureau of the Census 1994, 1999, 2004, 2009). Consumption values for 1990 and 1991 were assumed to be the 

same as the 1992 value; consumption was interpolated between 1992 and 1997, 1997 and 2002, and 2002 and 2007; 

consumption for 2008 through 2012 was assumed to equal the 2007 value. Cleanser consumption values were adjusted by 

import and export data to develop US consumption estimates. 
A-110 Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2012

Chemical formulae were used to determine C contents (as percentages) of the ingredients in the cleansers. Each 

product’s overall C content was then derived from the composition and contents of its ingredients. From these values the 

mean C content for cleansers was calculated to be 21.9 percent. 

The Census Bureau presents consumption data in terms of quantity (in units of million gallons or million pounds) 

and/or terms of value (thousands of dollars) for eight specific categories, such as “household liquid laundry detergents, 

heavy duty” and “household dry alkaline automatic dishwashing detergents.” Additionally, the report provides dollar 

values for the total consumption of “soaps, detergents, etc.—dry” and “soaps, detergents, etc.—liquid.” The categories for 

which both quantity and value data are available is a subset of total production. Those categories that presented both 

quantity and value data were used to derive pounds per dollar and gallons per dollar conversion rates, and they were 

extrapolated (based on the Census Bureau estimate of total value) to estimate the total quantity of dry and liquid31 cleanser 

categories, respectively. 

Next, the total tonnage of cleansers was calculated (wet and dry combined) for 1997. Multiplying the mean C 

content (21.9 percent) by this value yielded an estimate of 4.6 Tg CO2 Eq. in cleansers for 1997. For all subsequent years, 

it was assumed that the ratio of value of shipments to total carbon content remained constant. For 1998 through 2012, 

value of shipments was adjusted to 1997 dollars using the producer price index for soap and other detergent manufacturing 

(Bureau of Labor Statistics 2013). The ratio of value of shipments to carbon content was then applied to arrive at total 

carbon content of cleansers. For 1992, 2002, and 2007 the estimates are 3.6 Tg CO2 Eq., 5.1 Tg CO2 Eq., 7.6 Tg CO2 Eq., 

respectively. Estimates for other years are based on these values as described above, and are shown in Table A-76. 

Table A-76: C Emitted from Utilization of Soaps, Shampoos, and Detergents (Tg CO2 Eq.)

1990 1995 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012

C Emissions 3.6 4.2 4.5 4.8 5.1 5.7 6.2 6.7 7.0 7.6 7.1 6.7 6.7 6.5 6.1

Antifreeze and Deicers

Glycol compounds, including ethylene glycol, propylene glycol, diethylene glycol, and triethylene glycol, are 

used as antifreeze in motor vehicles, deicing fluids for commercial aircraft, and other similar uses. These glycol 

compounds are assumed to ultimately enter wastewater treatment plants where they are degraded by the wastewater 

treatment process to CO2 or to otherwise biodegrade to CO2. Glycols are water soluble and degrade rapidly in the 

environment (Howard 1993).

Annual production data for each glycol compound used as antifreeze and deicers were obtained from the Guide 

to the Business of Chemistry (ACC 2012). Import and export data were used to adjust annual production data to annual 

consumption data. The percentage of the annual consumption of each glycol compound used for antifreeze and deicing 

applications was estimated from Chemical Profiles data published on The Innovation Group website32 and from similar 

data published in the Chemical Market Reporter, which became ICIS Chemical Business in 2005.33 Production data for 

propylene glycol, diethylene glycol, and triethylene glycol are no longer reported in the Guide to the Business of 

Chemistry, so data from ICIS Chemical Business on total demand was used with import and export data to estimate 

production of these chemicals.

The glycol compounds consumed in antifreeze and deicing applications is assumed to be 100 percent emitted as 

CO2. Emissions of CO2 from utilization of antifreeze and deicers are summarized in Table A-77. 

Table A-77: C Emitted from Utilization of Antifreeze and Deicers (Tg CO2 Eq.)

1990 1995 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012

C Emissions 1.2 1.4 1.5 1.3 1.3 1.3 1.4 1.2 1.3 1.2 1.0 0.9 0.8 0.7 0.7

Food Additives

Petrochemical feedstocks are used to manufacture synthetic food additives, including preservatives, flavoring 

agents, and processing agents. These compounds include glycerin, propylene glycol, benzoic acid, and other compounds. 

These compounds are incorporated into food products, and are assumed to ultimately enter wastewater treatment plants 

 

31 A density of 1.05 g/mL—slightly denser than water—was assumed for liquid cleansers.

32 See <http://www.the-innovation-group.com/ChemProfiles>

33See < http://www.icis.com/home/default.aspx>
A-111

where they are degraded by the wastewater treatment processes to CO2 or to otherwise biodegrade to CO2. Certain food 

additives, e.g., glycerin, are manufactured both from petrochemical feedstocks and from biogenic feedstocks. Food 

additives that are derived from biogenic feedstocks are accounted for in the Land Use, Land-Use Change and Forestry 

chapter.

Annual production data for food additive compounds were obtained from the Guide to the Business of Chemistry 

(ACC 2012). Import and export data were used to adjust annual production data to annual consumption data. The 

percentage of the annual consumption of food additive compounds was estimated from Chemical Profiles data published 

on The Innovation Group website34 and from similar data published in the Chemical Market Reporter, which became ICIS

Chemical Business in 2005.35 Production data for several food additive compounds are no longer reported in the Guide to 

the Business of Chemistry, so data from ICIS Chemical Business on total demand was used with import and export data to 

estimate production of these chemicals. The consumption of synthetic food additives is assumed to be 100 percent emitted 

as CO2. Emissions of CO2 from utilization of synthetic food additives are summarized in Table A-78. 

Table A-78: C Emitted from Utilization of Food Additives (Tg CO2 Eq.)

1990 1995 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012

C Emissions 0.6 0.7 0.7 0.6 0.7 0.7 0.7 0.8 0.8 0.8 0.8 0.8 0.8 0.8 0.8

Silicones

Silicone compounds (e.g., polymethyl siloxane) are used as sealants and in manufactured products. Silicone 

compounds are manufactured from petrochemical feedstocks including methyl chloride. It is assumed that petrochemical 

feedstocks used to manufacture silicones are incorporated into the silicone products and not emitted as CO2 in the 

manufacturing process. It is also assumed that the C contained in the silicone products is stored, and not emitted as CO2. 

Annual production data for each silicone manufacturing compound were obtained from the Guide to the Business 

of Chemistry (ACC 2012). Import and export data were used to adjust annual production data to annual consumption data. 

The percentage of the annual consumption of each silicone manufacturing compound was estimated from Chemical 

Profiles data published on The Innovation Group website and from similar data published in the Chemical Market 

Reporter, which became ICIS Chemical Business in 200536. The consumption of silicone manufacturing compounds is 

assumed to be 100 percent stored, and not emitted as CO2. Storage of silicone manufacturing compounds is summarized 

in Table A-79.

Table A-79: C Stored in Silicone Products (Tg CO2 Eq.)

1990 1995 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012

C Storage 0.3 0.4 0.4 0.4 0.5 0.5 0.5 0.4 0.5 0.5 0.5 0.5 0.5 0.5 0.5

Uncertainty 

A Tier 2 Monte Carlo analysis was performed using @RISK software to determine the level of uncertainty 

surrounding the estimates of the feedstocks C storage factor and the quantity of C emitted from feedstocks in 2012. The 

Tier 2 analysis was performed to allow the specification of probability density functions for key variables, within a 

computational structure that mirrors the calculation of the Inventory estimate. Statistical analyses or expert judgments of 

uncertainty were not available directly from the information sources for the activity variables; thus, uncertainty estimates 

were determined using assumptions based on source category knowledge. Uncertainty estimates for production data (the 

majority of the variables) were assumed to exhibit a normal distribution with a relative error of ±20 percent in the 

underlying EIA estimates, plus an additional ±15 percent to account for uncertainty in the assignment of imports and 

exports. An additional 10 percent (for a total of ±45 percent) was applied to the production of other oils (>401 deg. F) to 

reflect the additional uncertainty in the assignment of part of the production quantity to industrial processes. A relatively 

narrow uniform distribution ±1 percent to ±15 percent, depending on the fuel type) was applied to each C coefficient.

The Monte Carlo analysis produced a storage factor distribution with a mean of 67 percent, a standard deviation 

of 4.2 percent, and the 95 percent confidence interval of 56 percent and 72 percent. This compares to the calculated 

Inventory estimate of 70 percent. The analysis produced a C emission distribution with a mean of 65.4 Tg CO2 Eq., 

 

34 See <http://www.the-innovation-group.com/ChemProfiles>

35 See <http://www.icis.com/home/default.aspx>

36 Ibid.
A-112 Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2012

standard deviation of 15.5 Tg CO2 Eq., and 95 percent confidence limits of 45.8 and 104.0 Tg CO2 Eq. This compares 

with a calculated Inventory estimate of 59.2 Tg CO2 Eq. 

The apparently tight confidence limits for the storage factor and C storage probably understate uncertainty, as a 

result of the way this initial analysis was structured. As discussed above, the storage factor for feedstocks is based on an 

analysis of six fates that result in long-term storage (e.g., plastics production), and eleven that result in emissions (e.g., 

volatile organic compound emissions). Rather than modeling the total uncertainty around all 17 of these fate processes, 

the current analysis addresses only the storage fates, and assumes that all C that is not stored is emitted. As the production 

statistics that drive the storage factors are relatively well-characterized, this approach yields a result that is probably biased 

toward understating uncertainty.

As far as specific sources of uncertainty, there are several cross-cutting factors that pervade the characterization 

of C flows for feedstocks. The aggregate storage factor for petrochemical feedstocks (industrial other coal, natural gas for 

non-fertilizer uses, LPG, pentanes plus, naphthas, other oils, still gas, special naphtha) is based on assuming that the 

ultimate fates of all of these fuel types—in terms of storage and emissions—are similar. In addition, there are 

uncertainties associated with the simplifying assumptions made for each end use category C estimate. Generally, the 

estimate for a product is subject to one or more of the following uncertainties:

 The value used for estimating the C content has been assumed or assigned based upon a representative 

compound. 

 The split between C storage and emission has been assumed based on an examination of the environmental fate 

of the products in each end use category.

 Environmental fates leading to emissions are assumed to operate rapidly, i.e., emissions are assumed to occur 

within one year of when the fossil C enters the non-energy mass balance. Some of the pathways that lead to 

emissions as CO2 may actually take place on a time-scale of several years or decades. By attributing the 

emissions to the year in which the C enters the mass balance (i.e., the year in which it leaves refineries as a nonenergy fuel use and thus starts being tracked by EIA), this approach has the effect of “front-end loading” the 

emission profile. 

Another cross-cutting source of uncertainty is that for several sources the amount of C stored or emitted was 

calculated based on data for only a single year. This specific year may not be representative of storage for the entire 

Inventory period. Sources of uncertainty associated with specific elements of the analysis are discussed below.

Import and export data for petrochemical feedstocks were obtained from EIA, the National Petroleum Refiners 

Association, and the U.S. BoC for the major categories of petrochemical feedstocks (EIA 2001, NPRA 2001, and U.S. 

BoC 2006). The complexity of the organic chemical industry, with multiple feedstocks, intermediates, and subtle 

differences in nomenclature, makes it difficult to ensure that the adjustments to the EIA data for imports and exports is 

accurate and the approach used here may underestimate or overestimate net exports of C.

Oxidation factors have been applied to non-energy uses of petrochemical feedstocks in the same manner as for 

energy uses. However, for those fuels where IPCC storage factors are used, this “oxidation factor” may be inherent in the 

storage factor applied when calculating emissions from non-energy consumption, which would result in a double-counting 

of the unoxidized C. Oxidation factors are small corrections, on the order of 1 percent, and therefore application of 

oxidation factors to non-energy uses may result in a slight underestimation of C emissions from non-energy uses.

The major uncertainty in using the TRI data is the possibility of double counting emissions that are already 

accounted for in the NMVOC data (see above) and in the storage and emission assumptions used. The approach for 

predicting environmental fate simplifies some complex processes, and the balance between storage and emissions is very 

sensitive to the assumptions on fate. Extrapolating from known to unknown characteristics also introduces uncertainty. 

The two extrapolations with the greatest uncertainty are: 1) that the release media and fate of the off-site releases were 

assumed to be the same as for on-site releases, and 2) that the C content of the least frequent 10 percent of TRI releases 

was assumed to be the same as for the chemicals comprising 90 percent of the releases. However, the contribution of 

these chemicals to the overall estimate is small. The off-site releases only account for 3 percent of the total releases, by 

weight, and, by definition, the less frequent compounds only account for 10 percent of the total releases.

The principal sources of uncertainty in estimating CO2 emissions from solvent evaporation and industrial 

NMVOC emissions are in the estimates of (a) total emissions and (b) their C content. Solvent evaporation and industrial 

NMVOC emissions reported by EPA are based on a number of data sources and emission factors, and may underestimate 

or overestimate emissions. The C content for solvent evaporation emissions is calculated directly from the specific solvent 

compounds identified by EPA as being emitted, and is thought to have relatively low uncertainty. The C content for 
A-113

industrial emissions has more uncertainty, however, as it is calculated from the average C content of an average volatile 

organic compound based on the list of the most abundant measured NMVOCs provided in EPA (2002a).

Uncertainty in the hazardous waste combustion analysis is introduced by the assumptions about the composition 

of combusted hazardous wastes, including the characterization that hazardous wastes are similar to mixtures of water, 

noncombustibles, and fuel equivalent materials. Another limitation is the assumption that all of the C that enters 

hazardous waste combustion is emitted—some small fraction is likely to be sequestered in combustion ash—but given that 

the destruction and removal efficiency for hazardous organics is required to meet or exceed 99.99 percent, this is a very 

minor source of uncertainty. C emission estimates from hazardous waste should be considered central value estimates that 

are likely to be accurate to within 50 percent.

The amount of feedstocks combusted for energy recovery was estimated from data included in the Manufacturers 

Energy Consumption Surveys (MECS) for 1991, 1994, 1998, 2002, and 2006 (EIA 1994, 1997, 2001, 2005, 2010; 2013b). 

MECS is a comprehensive survey that is conducted every four years and intended to represent U.S. industry as a whole, 

but because EIA does not receive data from all manufacturers (i.e., it is a sample rather than a census), EIA must 

extrapolate from the sample. Also, the “other” fuels are identified in the MECS data in broad categories, including 

refinery still gas; waste gas; waste oils, tars, and related materials; petroleum coke, coke oven and blast furnace gases; and 

other uncharacterized fuels. Moreover, the industries using these “other” fuels are also identified only in broad categories, 

including the petroleum and coal products, chemicals, primary metals, nonmetallic minerals, and other manufacturing 

sectors. The “other” fuel consumption data are reported in BTUs (energy units) and there is uncertainty concerning the 

selection of a specific conversion factor for each broad “other” fuel category to convert energy units to mass units. Taken 

as a whole, the estimate of energy recovery emissions probably introduces more uncertainty than any other element of the 

non-energy analysis.

Uncertainty in the C storage estimate for plastics arises primarily from four factors. First, production of some 

plastic resins is not tracked directly and must be estimated based on other market data. Second, the raw data on 

production for several resins include Canadian and/or Mexican production and may overestimate the amount of plastic 

produced from U.S. fuel feedstocks; this analysis includes adjustments to “back out” the Canadian and Mexican values, 

but these adjustments are approximate. Third, the assumed C content values are estimates for representative compounds, 

and thus do not account for the many formulations of resins available. This uncertainty is greater for resin categories that 

are generic (e.g., phenolics, other styrenics, nylon) than for resins with more specific formulations (e.g., polypropylene, 

polyethylene). Fourth, the assumption that all of the C contained in plastics is stored ignores certain end uses (e.g., 

adhesives and coatings) where the resin may be released to the atmosphere; however, these end-uses are likely to be small 

relative to use in plastics.

The quantity of C stored in synthetic rubber only accounts for the C stored in scrap tire synthetic rubber. The 

value does not take into account the rubber stored in other durable goods, clothing, footwear, and other non-durable goods, 

or containers and packaging. This adds uncertainty to the total mass balance of C stored. There are also uncertainties as to 

the assignment of C content values; however, they are much smaller than in the case of plastics. There are probably fewer 

variations in rubber formulations than in plastics, and the range of potential C content values is much narrower. Lastly, 

assuming that all of the C contained in rubber is stored ignores the possibility of volatilization or degradation during 

product lifetimes. However, the proportion of the total C that is released to the atmosphere during use is probably 

negligible.

A small degree of uncertainty arises from the assignment of C content values in textiles; however, the magnitude 

of this uncertainty is less than that for plastics or rubber. Although there is considerable variation in final textile products, 

the stock fiber formulations are standardized and proscribed explicitly by the Federal Trade Commission.

For pesticides, the largest source of uncertainty involves the assumption that an active ingredient’s C is either 0 

percent stored or 100 percent stored. This split is a generalization of chemical behavior, based upon active-ingredient 

molecular structure, and not on compound-specific environmental data. The mechanism by which a compound is bound 

or released from soils is very complicated and can be affected by many variables, including the type of crop, temperature, 

application method, and harvesting practice. Another smaller source of uncertainty arises from the C content values 

applied to the unaccounted for portion of active ingredient. C contents vary widely among pesticides, from 7 to 72 

percent, and the remaining pesticides may have a chemical make-up that is very different from the 32 pesticides that have 

been examined. Additionally, pesticide consumption data were only available for 1987, 1993, 1995, 1997, 1999, and 2001 

and 2007; the majority of the time series data were interpolated or held constant at the latest (2007) value. Another source 

of uncertainty is that only the “active” ingredients of pesticides are considered in the calculations; the “inactive” 

ingredients may also be derived from petrochemical feedstocks. 
A-114 Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2012

It is important to note that development of this uncertainty analysis is a multi-year process. The current 

feedstocks analysis examines NEU fuels that end in storage fates Thus only C stored in pesticides, plastics, synthetic 

fibers, synthetic rubbers, silicones, and TRI releases to underground injection and Subtitle C landfills is accounted for in 

the uncertainty estimate above. In the future this analysis will be expanded to include the uncertainty surrounding emitted 

fates in addition to the storage fates. Estimates of variable uncertainty will also be refined where possible to include fewer 

assumptions. With these major changes in future Inventories, the uncertainty estimate is expected to change, and likely 

increase. An increase in the uncertainty estimate in the coming years will not indicate that the Inventory calculations have

become less certain, but rather that the methods for estimating uncertainty have become more comprehensive; thus, 

potential future changes in the results of this analysis will reflect a change in the uncertainty analysis, not a change in the 

Inventory quality.

Asphalt and Road Oil 

Asphalt is one of the principal non-energy uses of fossil fuels. The term “asphalt” generally refers to a mixture 

of asphalt cement and a rock material aggregate, a volatile petroleum distillate, or water. For the purposes of this analysis, 

“asphalt” is used interchangeably with asphalt cement, a residue of crude oil. Though minor amounts of C are emitted 

during production, asphalt has an overall C storage factor of almost 100 percent, as discussed below. 

Paving is the primary application of asphalt cement, comprising 86 percent of production. The three types of 

asphalt paving produced in the United States are hot mix asphalt (HMA), cut-backs, and emulsified asphalt. HMA, which 

makes up 90 percent of total asphalt paving (EPA 2001), contains asphalt cement mixed with an aggregate of rock 

materials. Cut-back asphalt is composed of asphalt cement thinned with a volatile petroleum distillate (e.g., naphtha). 

Emulsified asphalt contains only asphalt cement and water. Roofing products are the other significant end use of asphalt 

cement, accounting for approximately 14 percent of U.S. production (Kelly 2000). No data were available on the fate of C 

in asphalt roofing; it was assumed that it has the same fate as C in asphalt paving applications.

Methodology and Data Sources 

A C storage factor was calculated for each type of asphalt paving. The fraction of C emitted by each asphalt type 

was multiplied by consumption data for asphalt paving (EPA 2001) to estimate a weighted average C storage factor for 

asphalt as a whole. 

The fraction of C emitted by HMA was determined by first calculating the organic emissions (volatile organic 

compounds [VOCs], carbon monoxide [CO], polycyclic aromatic hydrocarbons [PAHs], hazardous air pollutants [HAPs], 

and phenol) from HMA paving, using emission factors reported in EPA (2001) and total HMA production.37 The next 

step was to estimate the C content of the organic emissions. This calculation was based on the C content of CO and 

phenol, and an assumption of 85 percent C content for PAHs and HAPs. The C content of asphalt paving is a function of 

(1) the proportion of asphalt cement in asphalt paving, assumed to be 8 percent asphalt cement content based on EPA 

(2001), and (2) the proportion of C in asphalt cement. For the latter factor, all paving types were characterized as having a 

mass fraction of 85 percent C in asphalt cement, based on the assumption that asphalt is primarily composed of saturated 

paraffinic hydrocarbons. By combining these estimates, the result is that over 99.56 percent of the C in asphalt cement 

was retained (i.e., stored), and less than 0.44 percent was emitted.

Cut-back asphalt is produced in three forms: rapid, medium, and slow cure. The production processes for all 

three forms emit C primarily from the volatile petroleum distillate used in the process as a diluent to thin the asphalt 

cement so that it can be applied more readily (EPA 2001).

A mass balance on C losses from asphalt was constructed by first estimating the amount of carbon emitted as 

VOCs. Values for medium cure asphalt are used to represent all cut-back asphalt. The average weight of distillates used in 

medium cure cut-back asphalt (35 percent) is multiplied by the loss rate (as emissions of VOCs) of 70 percent from the 

Emissions Inventory Guidebook to arrive at an estimate that 25 percent of the diluent is emitted (Environment Canada 

2006). Next, the fraction of C in the asphalt/ diluent mix that is emitted was estimated, assuming 85 percent C content; 

this yields an overall storage factor of 93.5 percent for cut-back asphalt.

One caveat associated with this calculation is that it is possible that the carbon flows for asphalt and diluent 

(volatile petroleum distillate) are accounted for separately in the EIA statistics on fossil fuel flows, and thus the mass 

 

37 The emission factors are expressed as a function of asphalt paving tonnage (i.e., including the rock aggregate as well as the asphalt 

cement).
A-115

balance calculation may need to re-map the system boundaries to correctly account for carbon flows. EPA plans to reevaluate this calculation in the future. 

It was assumed that there was no loss of C from emulsified asphalt (i.e., the storage factor is 100 percent) based 

on personal communication with an expert from Akzo Nobel Coatings, Inc. (James 2000). 

Data on asphalt and road oil consumption and C content factors were supplied by EIA. Hot mix asphalt 

production and emissions factors, and the asphalt cement content of HMA were obtained from “Hot Mix Asphalt Plants 

Emissions Assessment Report” from EPA’s AP-42 (EPA 2001) publication. The consumption data for cut-back and 

emulsified asphalts were taken from a Moulthrop, et al. study used as guidance for estimating air pollutant emissions from 

paving processes (EIIP 2001). “Asphalt Paving Operation” AP-42 (EPA 2001) provided the emissions source information 

used in the calculation of the C storage factor for cut-back asphalt. The storage factor for emulsified asphalt was provided 

by Alan James of Akzo Nobel Coatings, Inc. (James 2000). 

Uncertainty 

A Tier 2 Monte Carlo analysis was performed using @RISK software to determine the level of uncertainty 

surrounding the estimates of the asphalt C storage factor and the quantity of C stored in asphalt in 2012. The Tier 2 

analysis was performed to allow the specification of probability density functions for key variables, within a 

computational structure that mirrors the calculation of the Inventory estimate. Statistical analyses or expert judgments of 

uncertainty were not available directly from the information sources for the activity variables; thus, uncertainty estimates 

were determined using assumptions based on source category knowledge. Uncertainty estimates for asphalt production 

were assumed to be ±20 percent, while the asphalt property variables were assumed to have narrower distributions. A 

narrow uniform distribution, with maximum 5 percent uncertainty (± 5 percent) around the mean, was applied to the C 

content coefficient. 

The Monte Carlo analysis produced a tight distribution of storage factor values, with the 95 percent confidence 

interval of 99.1 percent and 99.8 percent, with the mean value of 99.6 percent. This compares to the storage factor value 

used in the Inventory of 99.5 percent. The analysis produced a C emission distribution with a mean of 0.30 Tg CO2 Eq., 

standard deviation of 0.13 and 95 percent confidence limits of 0.12 Tg CO2 Eq. and 0.61 Tg CO2 Eq. This compares to an 

Inventory calculated estimate of 0.27 Tg CO2 Eq.

The principal source of uncertainty is that the available data are from short-term studies of emissions associated 

with the production and application of asphalt. As a practical matter, the cement in asphalt deteriorates over time, 

contributing to the need for periodic re-paving. Whether this deterioration is due to physical erosion of the cement and 

continued storage of C in a refractory form or physicochemical degradation and eventual release of CO2 is uncertain. 

Long-term studies may reveal higher lifetime emissions rates associated with degradation.

Many of the values used in the analysis are also uncertain and are based on estimates and professional judgment. 

For example, the asphalt cement input for hot mix asphalt was based on expert advice indicating that the range is 

variable—from about 3 to 5 percent—with actual content based on climate and geographical factors (Connolly 2000). 

Over this range, the effect on the calculated C storage factor is minimal (on the order of 0.1 percent). Similarly, changes 

in the assumed C content of asphalt cement would have only a minor effect.

The consumption figures for cut-back and emulsified asphalts are based on information reported for 1994. More 

recent trends indicate a decrease in cut-back use due to high VOC emission levels and a related increase in emulsified 

asphalt use as a substitute. This change in trend would indicate an overestimate of emissions from asphalt.

Future improvements to this uncertainty analysis, and to the overall estimation of a storage factor for asphalt, 

include characterizing the long-term fate of asphalt.

Lubricants 

Lubricants are used in industrial and transportation applications. They can be subdivided into oils and greases, 

which differ in terms of physical characteristics (e.g., viscosity), commercial applications, and environmental fate. 

According to EIA (2013a), the C content from U.S. production of lubricants in 2012 was approximately 5.6 Tg C. Based 

on apportioning oils and greases to various environmental fates, and characterizing those fates as resulting in either longterm storage or emissions, the overall C storage factor was estimated to be 9.2 percent; thus, emissions in 2012 were about 

5.1 Tg C, or 18.6 Tg CO2 Eq. EIA data were not available for 2012, so it was set equal to the 2011 value.
A-116 Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2012

Methodology and Data Sources

For each lubricant category, a storage factor was derived by identifying disposal fates and applying assumptions 

as to the disposition of the C for each practice. An overall lubricant C storage factor was calculated by taking a 

production-weighted average of the oil and grease storage factors. 

Oils

Regulation of used oil in the United States has changed dramatically over the past 20 years.38 The effect of these 

regulations and policies has been to restrict landfilling and dumping, and to encourage collection of used oil. The 

economics of the petroleum industry have generally not favored re-refining—instead, most of the used oil that has been 

collected has been combusted.

Table A-80 provides an estimated allocation of the fates of lubricant oils (Rinehart 2000), along with an estimate 

of the proportion of C stored in each fate. The ultimate fate of the majority of oils (about 84 percent) is combustion, either 

during initial use or after collection as used oil. Combustion results in 99 percent oxidation to CO2 (EIIP 1999), with 

correspondingly little long-term storage of C in the form of ash. Dumping onto the ground or into storm sewers, primarily 

by “do-it-yourselfers” who change their own oil, is another fate that results in conversion to CO2 given that the releases are 

generally small and most of the oil is biodegraded (based on the observation that land farming—application to soil—is one 

of the most frequently used methods for degrading refinery wastes). In the landfill environment, which tends to be 

anaerobic within municipal landfills, it is assumed that 90 percent of the oil persists in an undegraded form, based on 

analogy with the persistence of petroleum in native petroleum-bearing strata, which is also anaerobic. Re-refining adds a 

recycling loop to the fate of oil. Re-refined oil was assumed to have a storage factor equal to the weighted average for the 

other fates (i.e., after re-refining, the oil would have the same probability of combustion, landfilling, or dumping as virgin 

oil), that is, it was assumed that about 97 percent of the C in re-refined oil is ultimately oxidized. Because of the 

dominance of fates that result in eventual release as CO2, only about 3 percent of the C in oil lubricants goes into longterm storage.

Table A-80: Commercial and Environmental Fate of Oil Lubricants (Percent)

Fate of Oil Portion of Total Oil C Stored

Combusted During Use 20% 0.2%

Not Combusted During Use 80% 2.7%

Combusted as Used Oil * 64% 0.6%

Dumped on the ground or in storm sewers 6% -

Landfilled 2% 1.8%

Re-refined into lube oil base stock and other products 8% 0.2%

Weighted Average 2.9%

*(e.g., in boilers or space heaters)

- Not applicable

Greases

Table A-81 provides analogous estimates for lubricant greases. Unlike oils, grease is generally not combusted 

during use, and combustion for energy recovery and re-refining is thought to be negligible. Although little is known about 

the fate of waste grease, it was assumed that 90 percent of the non-combusted portion is landfilled, and the remainder is 

dumped onto the ground or storm sewers. Because much of the waste grease will be in containers that render it relatively 

inaccessible to biodegradation, and because greases contain longer chain paraffins, which are more persistent than oils, it 

was assumed that 90 percent and 50 percent of the C in landfilled and dumped grease, respectively, would be stored. The 

overall storage factor is 82 percent for grease. 

 

38 For example, the U.S. EPA “RCRA (Resource Conservation and Recovery Act) On-line” web site (<http://www.epa.gov/rcraonline/>) 

has over 50 entries on used oil regulation and policy for 1994 through 2000.
A-117

Table A-81: Commercial and Environmental Fate of Grease Lubricants (Percent)

Fate of Grease Portion of Total Grease C Stored

Combusted During Use 5% 0.1%

Not Combusted During Use 95% 81.7%

Landfilled 86% 77.0%

Dumped on the ground or in storm sewers 10% 4.8%

Weighted Average - 81.8%

- Not applicable

Having derived separate storage factors for oil and grease, the last step was to estimate the weighted average for 

lubricants as a whole. No data were found apportioning the mass of lubricants into these two categories, but the U.S. 

Census Bureau does maintain records of the value of production of lubricating oils and lubricating greases. These were 

retrieved from the relevant industry series summaries from the 1997 Economic Census (U.S. Bureau of the Census 1999). 

Assuming that the mass of lubricants can be allocated according to the proportion of value of production (92 percent oil, 8 

percent grease), applying these weights to the storage factors for oils and greases (3 percent and 82 percent) yields an 

overall storage factor of 9.2 percent.

Uncertainty

A Tier 2 Monte Carlo analysis was performed using @RISK software to determine the level of uncertainty 

surrounding the estimates of the lubricants weighted average C storage factor and the quantity of C emitted from 

lubricants in 2012. The Tier 2 analysis was performed to allow the specification of probability density functions for key 

variables, within a computational structure that mirrors the calculation of the Inventory estimate. Statistical analyses or 

expert judgments of uncertainty were not available directly from the information sources for the activity variables; thus, 

uncertainty estimates were determined using assumptions based on source category knowledge. Uncertainty estimates for 

oil and grease variables were assumed to have a moderate variance, in triangular or uniform distribution. Uncertainty 

estimates for lubricants production were assumed to be rather high (±20 percent). A narrow uniform distribution, with 6 

percent uncertainty (± 6 percent) around the mean, was applied to the lubricant C content coefficient. 

The Monte Carlo analysis produced a storage factor distribution with the 95 percent confidence interval of 4 

percent and 17 percent around a mean value of 10 percent. This compares to the calculated Inventory estimate of 9 

percent. The analysis produced a C emission distribution approximating a normal curve with a mean of 16.9 Tg CO2 Eq., 

standard deviation of 1.5 and 95 percent confidence limits of 14.2 Tg CO2 Eq. and 19.8 Tg CO2 Eq. This compares to an 

Inventory calculated estimate of 17.1 Tg CO2 Eq. 

The principal sources of uncertainty for the disposition of lubricants are the estimates of the commercial use, 

post-use, and environmental fate of lubricants, which, as noted above, are largely based on assumptions and judgment. 

There is no comprehensive system to track used oil and greases, which makes it difficult to develop a verifiable estimate 

of the commercial fates of oil and grease. The environmental fate estimates for percent of C stored are less uncertain, but 

also introduce uncertainty in the estimate.

The assumption that the mass of oil and grease can be divided according to their value also introduces 

uncertainty. Given the large difference between the storage factors for oil and grease, changes in their share of total 

lubricant production have a large effect on the weighted storage factor.

Future improvements to the analysis of uncertainty surrounding the lubricants C storage factor and C stored 

include further refinement of the uncertainty estimates for the individual activity variables.

Waxes

Waxes are organic substances that are solid at ambient temperature, but whose viscosity decreases as temperature 

increases. Most commercial waxes are produced from petroleum refining, though “mineral” waxes derived from animals, 

plants, and lignite [coal] are also used. An analysis of wax end uses in the United States, and the fate of C in these uses, 

suggests that about 42 percent of C in waxes is emitted, and 58 percent is stored.

Methodology and Data Sources 

The National Petroleum Refiners Association (NPRA) considers the exact amount of wax consumed each year 

by end use to be proprietary (Maguire 2004). In general, about thirty percent of the wax consumed each year is used in 

packaging materials, though this percentage has declined in recent years. The next highest wax end use, and fastest 

growing end use, is candles, followed by construction materials and firelogs. Table A-82 categorizes some of the wax end 
A-118 Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2012

uses, which the NPRA generally classifies into cosmetics, plastics, tires and rubber, hot melt (adhesives), chemically 

modified wax substances, and other miscellaneous wax uses (NPRA 2002).

Table A-82: Emissive and Non-emissive (Storage) Fates of Waxes: Uses by Fate and Percent of Total Mass

Use Emissive Non-emissive

Packaging 6% 24%

Non-packaging 36% 34%

Candles 18% 2%

Construction Materials 4% 14%

Firelogs 7% +

Cosmetics 1% 2%

Plastics 1% 2%

Tires/Rubber 1% 1%

Hot Melts 1% 1%

Chemically Modified 0% 1%

Other 2% 9%

Total 42% 58%

+ Does not exceed 0.5 percent

A C storage factor for each wax end use was estimated and then summed across all end uses to provide an overall 

C storage factor for wax. Because no specific data on C contents of wax used in each end use were available, all wax 

products are assumed to have the same C content. Table A-83 categorizes wax end uses identified by the NPRA, and lists 

each end use’s estimated C storage factor. 

Table A-83: Wax End-Uses by Fate, Percent of Total Mass, Percent C Stored, and Percent of Total C Mass Stored

Use

Percent of Total 

Wax Mass

Percent of C 

Stored

Percent of Total C 

Mass Stored

Packaging 30% 79% 24%

Non-Packaging

Candles 20% 10% 2%

Construction Materials 18% 79% 14%

Firelogs 7% 1% +

Cosmetics 3% 79% 2%

Plastics 3% 79% 2%

Tires/Rubber 3% 47% 1%

Hot Melts 3% 50% 1%

Chemically Modified 1% 79% 1%

Other 12% 79% 9%

Total 100% NA 58%

+ Does not exceed 0.5 percent

Source, mass percentages: NPRA 2002. Estimates of percent stored are based on professional judgment, ICF International.

Note: Totals may not sum due to independent rounding.

Emissive wax end-uses include candles, firelogs (synthetic fireplace logs), hotmelts (adhesives), matches, and 

explosives. At about 20 percent, candles consume the greatest portion of wax among emissive end uses. As candles 

combust during use, they release emissions to the atmosphere. For the purposes of the Inventory, it is assumed that 90 

percent of C contained in candles is emitted as CO2. In firelogs, petroleum wax is used as a binder and as a fuel, and is 

combusted during product use, likely resulting in the emission of nearly all C contained in the product. Similarly, C 

contained in hotmelts is assumed to be emitted as CO2 as heat is applied to these products during use. It is estimated that 

50 percent of the C contained in hot melts is stored. Together, candles, firelogs, and hotmelts constitute approximately 30 

percent of annual wax production (NPRA 2002). 

All of the wax utilized in the production of packaging, cosmetics, plastics, tires and rubber, and other products is 

assumed to remain in the product (i.e., it is assumed that there are no emissions of CO2 from wax during the production of 

the product). Wax is used in many different packaging materials including wrappers, cartons, papers, paperboard, and 

corrugated products (NPRA 2002). Davie (1993) and Davie et al. (1995) suggest that wax coatings in packaging products 

degrade rapidly in an aerobic environment, producing CO2; however, because packaging products ultimately enter landfills 

typically having an anaerobic environment, most of the C from this end use is assumed to be stored in the landfill. 
A-119

In construction materials, petroleum wax is used as a water repellent on wood-based composite boards, such as 

particle board (IGI 2002). Wax used for this end-use should follow the life-cycle of the harvested wood used in product, 

which is classified into one of 21 categories, evaluated by life-cycle, and ultimately assumed to either be disposed of in 

landfills or be combusted (EPA 2003). 

The fate of wax used for packaging, in construction materials, and for most remaining end uses is ultimately to 

enter the municipal solid waste (MSW) stream, where it is either combusted or sent to landfill for disposal. Most of the C 

contained in these wax products will be stored. It is assumed that approximately 21 percent of the C contained in these 

products will be emitted through combustion or at landfill. With the exception of tires and rubber, these end-uses are 

assigned a C storage factor of 79 percent.

Waxes used in tires and rubber follow the life cycle of the tire and rubber products. Used tires are ultimately 

recycled, landfilled, or combusted. The life-cycle of tires is addressed elsewhere in this annex as part of the discussion of 

rubber products derived from petrochemical feedstocks. For the purposes of the estimation of the C storage factor for 

waxes, wax contained in tires and rubber products is assigned a C storage factor of 47 percent. 

Uncertainty

A Tier 2 Monte Carlo analysis was performed using @RISK software to determine the level of uncertainty 

surrounding the estimates of the wax C storage factor and the quantity of C emitted from wax in 2011. A Tier 2 analysis 

was performed to allow the specification of probability density functions for key variables, within a computational 

structure that mirrors the calculation of the Inventory estimate. Statistical analyses or expert judgments of uncertainty 

were not available directly from the information sources for the activity variables; thus, uncertainty estimates were 

determined using assumptions based on source category knowledge. Uncertainty estimates for wax variables were 

assumed to have a moderate variance, in normal, uniform, or triangular distribution; uniform distributions were applied to 

total consumption of waxes and the C content coefficients. 

The Monte Carlo analysis produced a storage factor distribution, whose 95 percent confidence interval values fell 

within the range of 49 percent and 71 percent, around the mean value of about 60 percent. This compares to the calculated 

Inventory estimate of 58 percent. The analysis produced an emission distribution, with the 95 percent confidence interval 

values of 0.3 Tg CO2 Eq. and 0.8 Tg CO2 Eq., with a mean value of 0.5 Tg CO2 Eq. This compares with a calculated 

Inventory estimate of 0.5 Tg CO2 Eq., which falls within the range of 95 percent confidence limits established by this 

quantitative uncertainty analysis. Uncertainty associated with the wax storage factor is considerable due to several 

assumptions pertaining to wax imports/exports, consumption, and fates. 

Miscellaneous Products 

Miscellaneous products are defined by the U.S. Energy Information Administration as: “all finished [petroleum] 

products not classified elsewhere, e.g., petrolatum; lube refining by-products (e.g., aromatic extracts and tars); absorption 

oils; ram-jet fuel; petroleum rocket fuel; synthetic natural gas feedstocks; and specialty oils."

Methodology and Data Sources

Data are not available concerning the distribution of each of the above-listed subcategories within the 

"miscellaneous products" category. However, based on the anticipated disposition of the products in each subcategory, it is 

assumed that all of the C content of miscellaneous products is emitted rather than stored. Petrolatum and specialty oils 

(which include greases) are likely to end up in solid waste or wastewater streams rather than in durable products, and 

would be emitted through waste treatment. Absorption oil is used in natural gas processing and is not a feedstock for 

manufacture of durable products Jet fuel and rocket fuel are assumed to be combusted in use, and synthetic natural gas 

feedstocks are assumed to be converted to synthetic natural gas that is also combusted in use. Lube refining by-products 

could potentially be used as feedstocks for manufacture of durable goods, but such by-products are more likely to be used 

in emissive uses. Lube refining by-products and absorption oils are liquids and are precluded from disposal in landfills. 

Because no sequestering end uses of any of the miscellaneous products subcategories have been identified, a zero percent 

storage factor is assigned to miscellaneous products. According to EIA (2013a), the C content of miscellaneous petroleum 

products in 2012 was approximately 20.3 Tg C/QBtu. EIA data were not available for 2012, so it was set equal to the 

2011 value. One hundred percent of the C content is assumed to be emitted to the atmosphere, where it is oxidized to CO2.

Uncertainty

A separate uncertainty analysis was not conducted for miscellaneous products, though this category was included 

in the uncertainty analysis of other non-energy uses discussed in the following section.
A-120 Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2012

Other Non-Energy Uses

The remaining fuel types use storage factors that are not based on U.S.-specific analysis. For industrial coking 

coal and distillate fuel oil, storage factors were taken from IPCC (2006), which in turn draws from Marland and Rotty 

(1984). These factors are 0.1 and 0.5, respectively.

IPCC does not provide guidance on storage factors for the remaining fuel types (petroleum coke, miscellaneous 

products, and other petroleum), and assumptions were made based on the potential fate of C in the respective NEUs. 

Specifically, the storage factor for petroleum coke is 0.3, based on information from Huurman (2006) indicating that 

petroleum coke is used in the Netherlands for production of pigments, with 30% being stored long-term. EIA (2013a) 

defines “miscellaneous products” as “all finished products not classified elsewhere (e.g., petrolatum, lube refining byproducts (aromatic extracts and tars), absorption oils, ram-jet fuel, petroleum rocket fuels, synthetic natural gas feedstocks, 

and specialty oils).” All of these uses are emissive, and therefore the storage factor for miscellaneous products is set at 

zero. The “other petroleum” category is reported by U.S. territories and accounts mostly for the same products as 

miscellaneous products, but probably also includes some asphalt, known to be non-emissive. The exact amount of asphalt 

or any of the other miscellaneous products is confidential business information, but based on judgment the storage factor 

for this category was estimated at 0.1.

For all these fuel types, the overall methodology simply involves multiplying C content by a storage factor, 

yielding an estimate of the mass of C stored. To provide a complete analysis of uncertainty for the entire NEU 

subcategory, the uncertainty around the estimate of “other” NEUs was characterized, as discussed below.

Uncertainty

A Tier 2 Monte Carlo analysis was performed using @RISK software to determine the level of uncertainty 

surrounding the weighted average of the remaining fuels’ C storage factors and the total quantity of C emitted from these 

other fuels in 2012. A Tier 2 analysis was performed to allow the specification of probability density functions for key 

variables, within a computational structure that mirrors the calculation of the Inventory estimate. Statistical analyses or 

expert judgments of uncertainty were not available directly from the information sources for some of the activity variables; 

thus, uncertainty estimates were determined using assumptions based on source category knowledge. A uniform 

distribution was applied to coking coal consumption, while the remaining consumption inputs were assumed to be 

normally distributed. The C content coefficients were assumed to have a uniform distribution; the greatest uncertainty 

range of 10 percent (±10%) around the inventory value, was applied to coking coal and miscellaneous products. C 

coefficients for distillate fuel oil ranged from 18.5 to 21.1 Tg C/QBtu. The fuel-specific storage factors were assigned 

wide triangular distributions indicating greater uncertainty.

The Monte Carlo analysis produced a storage factor distribution with 95 percent confidence limits of 8 percent 

and 47 percent, with a mean of 25 percent. This compares to the Inventory calculation of weighted average (across the 

various fuels) storage factor of about 8 percent. The analysis produced an emission distribution, with the 95 percent 

confidence limit of 18.8 Tg CO2 Eq. and 35.0 Tg CO2 Eq., and a mean of 27.2 Tg CO2 Eq. This compares with the 

Inventory estimate of 33.3 Tg CO2 Eq., which falls closer to the upper boundary of the 95 percent confidence limit. The 

uncertainty analysis results are driven primarily by the very broad uncertainty inputs for the storage factors.

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