UNITED STATES ENVIRONMENTAL PROTECTION AGENCY 

ANN ARBOR, MI 48105 

 OFFICE OF

 AIR AND RADIATION 

Date: September 14, 2009 

Subject: Calculation of Upstream Emissions for the GHG Vehicle Rule 

From: Craig A. Harvey, Mechanical Engineer 

 U.S. EPA, Office of Transportation and Air Quality

To: Docket EPA-HQ-OAR-2009-0472 

This memo documents the assumptions, data sources, and calculations used to 

estimate the emission impacts related to changes in fuel production and distribution (i.e., 

"upstream emissions") associated with the proposed rule: Proposed Rulemaking to 

Establish Light-Duty Vehicle Greenhouse Gas Emission Standards and Corporate 

Average Fuel Economy Standards. 

1.0 Introduction 

As used here, the term "upstream emissions" refers to air pollutant emissions 

generated from all crude oil extraction, transport, refining, and finished fuel transport, 

storage, and distribution. As shown in Table 1 this includes all the stages prior to the 

final filling of vehicle fuel tanks at retail service stations. Included in each of these 

processes are the lifecycle emissions and energy use associated with that operation as 

well as upstream components that feed into it. For example, the crude oil transport stage 

includes emissions from production of the fuel used by oil tankers. Electricity production 

emissions are included in many of the stages shown. These impacts include operationrelated activities, but not infrastructure-related activities. Thus, while we include the 

emissions associated with the operation of trucks used for gasoline distribution, we do not 

include the emissions associated with the production of the vehicles themselves or with 

the construction of refineries or oil tankers. 

Table 1 - Stages of Fuel Processing and Emissions 

PROCESS UPSTREAM / 

DOWNSTREAM

Crude Oil Extraction Upstream 

Crude Oil Transport Upstream 

Oil Refining Upstream 

Fuel Transport, Storage and Distribution Upstream 

Vehicle Tailpipe Emissions Downstream 

Air Conditioning System Leakage Downstream 
2

To estimate the upstream emission changes associated with the decreased fuel 

consumption that would result from the proposed rule we based our analysis on the 

GREET model.1

 Emission factors for GHGs and criteria emissions from certain sources 

are taken directly from GREET 1.8, while emission factors for criteria pollutants from 

mobile sourcs and all toxic emissions were provided by EPA. Lifecycle energy use and 

associated emissions for petroleum-based fuels in GREET are calculated based on energy 

efficiency metrics for the different processes involved in petroleum-based fuels 

production. The energy efficiency metric is a measure of how many BTUs1 of input 

energy are needed to make a BTU of output product. GREET has assumptions on energy 

efficiency for different finished petroleum products as well as for different types of crude 

oil. 

GREET also has assumptions on the mix of energy sources used to provide the 

energy input which determine GHG emissions. The emissions associated with petroleum 

fuels are based on the emissions from producing and combusting the input energy sources 

(with non-combustion sources included where applicable). The following sections 

describe the GREET assumptions for different petroleum-based fuels production 

processes and final products. 

For GHGs the emission impacts include both international and domestic 

reductions, since reduced imports of foreign finished gasoline and crude oil would make 

up a significant share of fuel savings. Thus significant upstream GHG emission 

reductions would occur outside of the U.S. For non-GHG pollutants the emission 

impacts only include reductions in domestic U.S. emissions, thus excluding overseas 

crude oil extraction and refining as well as ocean transport of crude or finished gasoline 

to the U.S. 

Unlike the analysis done for EPA's Renewable Fuel Standard (RFS2) proposed 

rulemaking package2

, the analysis done for this proposal assumes no effects on 

production volumes of biofuels, so there are no emission impacts related to agricultural or 

land use changes. 

2.0 GREET Energy-Based Analysis 

2.1 Crude Oil Extraction 

GREET has assumptions for different types of crude oil extraction, conventional 

crude and oil sands crude.2

 The values for conventional crude oil are assumed to 

represent average crude oil extraction, including domestic and foreign production, and 

onshore, offshore and enhanced oil recovery processes. Oil sands recovery was used in 

this analysis to represent Canadian oil sands recovery. The assumptions for each type of 

crude oil extraction are shown here. 

 

1

 British Thermal Unit 

2

 Oil sands crude is also commonly referred to as tar sands. 
3

Conventional crude oil extraction is assumed to have an energy efficiency metric 

of 98%. This means that every one million BTU (mmBTU) of crude oil produced 

requires 1,020,408 BTU of energy input. One mmBTU of that input is crude oil 

feedstock (from the ground) that ends up in the final product and therefore only 20,408 

BTU of additional process energy is required. Table 2 shows the breakout of the energy 

sources used to provide the additional process energy. 

Table 2. Conventional Crude Oil Production 

Process Fuel

Share of Input Energy

(%) 

Energy use 

(BTU/mmBTU of fuel throughput)

Crude oil 1.0% 204 

Residual oil 1.0% 204 

Diesel fuel 15.0% 3,057 

Gasoline 2.0% 408 

Natural gas 61.9% 12,635 

Electricity 19.0% 3,872 

Feed loss 0.1% 28 

Total: 100% 20,408 

 The emissions from conventional crude oil extraction are calculated by 

multiplying the BTUs of the different types of energy inputs by emission factors for 

combustion of those fuel sources. The emission factors for the different fuel types are 

from GREET based primarily on assumed carbon contents of the different process fuels. 

The emissions from producing electricity are also taken from GREET and represent 

average U.S. grid electricity production emissions. In addition to process energy 

emissions, GREET also assumes there are emissions from associated flaring of natural 

gas at the oil well, assuming 16,800 BTU of natural gas is flared per mmBTU of crude oil 

produced. The emissions from flared natural gas are again based on emission factors for 

natural gas combustion. GREET also accounts for fugitive methane emissions from 

crude oil extraction and processing, assuming that 13.15 grams of fugitive methane are 

released per mmBTU of crude oil produced. 

Similar to the assumptions for conventional crude oil extraction, GREET has 

assumptions about oil sands crude oil extraction. Oil sands can be either mined or 

recovered in situ -- meaning in place; GREET has assumptions for both processes. The 

oil sands recovery processes include both extraction (surface or in situ) and separation 

systems to remove bitumen from sand and water. 
4

Surface mining of oil sands involves open-pit mining techniques. About two 

metric tons of oil sands must be dug up, moved and processed to produce one barrel of 

oil. In situ recovery is used for bitumen deposits buried too deeply for mining to be 

practical. Cyclic steam stimulation (CSS) and steam-assisted gravity drainage (SAGD) 

are in situ recovery methods, which include thermal injection through vertical or 

horizontal wells. Table 3 and Table 4 show the energy efficiency metric and assumed 

energy sources used in oil sands extraction. Emissions from the oil sands extraction 

process are based on applying emission factors to the different energy inputs. 

Table 3. Oil Sands Recovery: Bitumen Extraction – Surface Mining 

Energy Efficiency 94.8%

Process Fuel

Share of Input Energy

(%) 

Energy use 

(BTU/mmBTU of fuel throughput)

Diesel fuel 0.6% 329 

Natural gas 82.3% 45,132 

Electricity 17.1% 9,377 

Feed loss 0.03% 14 

Total: 100% 54,852 

Table 4. Oil Sands Recovery: Bitumen Extraction – In Situ Production 

Energy Efficiency 84.3% 

Process Fuel

Share of Input Energy

(%) 

Energy use 

(BTU/mmBTU of fuel throughput)

Natural gas 97.2% 181,011 

Electricity 2.8% 5,214 

Feed loss 0.01% 14 

Total: 100% 186,239 

Once oil sands are extracted through either the surface mining or in situ process 

they are further processed for transportation. The energy efficiency metric and assumed 

energy input sources for the bitumen upgrading are shown in Table 5. 
5

Table 5. Oil Sands Recovery: Bitumen Upgrading 

Energy Efficiency 98.6% 

Process Fuel 

Share of Input Energy 

(%) 

Energy use 

(BTU/mmBTU of fuel 

throughput) 

Natural gas 97.1% 13,787 

Electricity 2.8% 397 

Feed loss 0.1% 14 

Total: 100% 14,198 

In addition to the emissions from the process energy used in the upgrading 

process, GREET also assumes hydrogen is needed as an input to the upgrading process. 

Emissions from hydrogen production, based on GREET defaults, are included in the 

emissions of bitumen upgrading. GREET assumes 84,187 BTU of hydrogen is used per 

mmBTU of oil sand crude produced through surface mining, and 32,364 BTU of 

hydrogen is used per mmBTU of oil sand crude produced through the in situ process. 

Emission factors from GREET were used for bitumen extracted in situ, bitumen 

extracted by surface mining, and light crude oil extraction. Emission factors from 

McCann (1999) were used to calculate emissions from heavy oil and Venezuela extra 

heavy oil by considering the incremental extraction and processing emissions relative to 

the average of the light crudes analyzed by McCann.3

 Instead of using McCann values 

directly we used these results to determine a scaling factor for the heavy crudes compared 

to the conventional crude types. We then applied this scaling factor to the GREET 

conventional crude emissions to represent emissions from heavy crude production. The 

results of the crude oil production differentiation are shown below in Table 6. 

Table 6. Scaling factors Used to Calculate Heavy Crude Extraction GHG Emissions 

Crude Production Emissions (gCO2-eq. / mmBTU of fuel produced) 

Canadian 

Light 

Brent 

North 

Sea 

Saudi 

Light 

Average 

"conventional"

Heavy 

Oil 

Venezuela 

Extra 

Heavy Oil 

Production 

Emissions 6,617 5,081 7,746 6,482 6,962 15,524 

Scaling Factor 0.07 2.40 
6

The importation of heavy crude oil and extra heavy crude oil in the U.S. 

comprises a relatively small but growing fraction of current total crude oil imports. 

Heavy crude oils are generally of higher density and higher viscosities compared to 

lighter crude oils and similarly, are not as readily extracted from reserves. The American 

Petroleum Institute’s “API Gravity” is commonly used to delineate light, medium, heavy 

and extra heavy crude oils. Although definitions can vary slightly, the U.S. Geological 

Survey (USGS) categorizes light crude oil as having an API gravity of at least 22° and 

viscosity less than 100 centipoise (cP).4 Heavy oil, by contrast, is defined as an 

“asphaltic, dense, and viscous oil” with an upper API limit of 22° and viscosity between 

100 – 10,000 cP. Heavy oil with an API less than 10° is defined as extra-heavy oil. 

Natural bitumen –also referred to in the literature as oil sand, tar sand, oil-impregnated 

sand, asphaltic sand, rock asphalt, bituminous rock, and bitumen-bearing rock– have a 

similar API range as extra-heavy oils but have viscosities greater than 10,000 cP.5 

EPA analyzed the types of crude oils used in the U.S. by examining crude oil 

import data from the Energy Information Administration for 2005, which is based on 

reporting by refineries.6

 The amount of crude imports reported by refineries with API 

less than or equal to 22° – heavy oil – was approximately 2.9 million barrels per day 

(mmbd) in 2005 out of the 15.2 mmbd refinery net input in the U.S. estimated by EIA. 

Figure 1 below displays the break-down of U.S. heavy crude imports by country. 

Figure 1. U.S. Imports of Heavy Crude Oil in 2005 (API of 22° or less) 

2005 Heavy Oil Imports (<=22.0)

Source: EIA Form 814 Data

-

200,000

400,000

600,000

800,000

1,000,000

1,200,000

Mexico

Venezuela

Canada

Ecuador

Brazil

Chad

Norway

Russia

United Kingdom

Kuwait

Angola

Saudi Arabia

Indonesia

Guatamala

China

Peru

Columbia

Nigeria

Malaysia

Oman

Argentina

Bolivia

bbl/day

Barrels per Day

Note that this is an underestimate of the actual heavy crude oil, extra heavy crude 

oil, or bitumen used by U.S. refineries since a fraction of these crudes are upgraded at the 

country of origin and/or diluted with diluents (gas condensate, natural gas liquids or light 

crude) and transported to the U.S. These upgraded crude oils would then appear as 
7

imports with an API greater than 22° (i.e. light or medium crude oil). EPA has identified 

that crude oil from Venezuela and Canada would likely have the most upgrading of extra 

heavy crude oil or bitumen to synthetic crude, or syncrude, due to the nature of the 

reserves and current information regarding the crude oil types extracted. The 

International Energy Agency estimates that in 2005, Venezuela produced approximately 

565,000 bpd of syncrude from its extra heavy oil reserves in the Orinoco oil belt.7 An 

analysis of the production output from the four members of the Orinoco Belt Strategic 

Association shows that roughly three-fourths of the upgraded syncrude has an API 

greater than 22°.8 Thus, out of the 3 mmbd of crude oil produced in Venezuela, 

approximately 19% was syncrude (i.e. 14% with API greater than 22° and 5% with API 

less than 22%). Applying these splits to the U.S. import data would result in roughly 

145,000 bpd of syncrude from extra heavy oil, 715,000 heavy oil, and 684,000 light (or 

conventional) crude oils. This split would still likely underestimate the extra heavy 

oil/syncrude used by the U.S. since Venezuela tends to ship a greater fraction of its 

heavier crude oils to U.S. refineries that are specifically configured to handle heavier 

crude oils. 

Estimates on the types of crude oil imported from Canada were also adjusted 

based on available information. Canadian production information for 2005 was obtained 

from statistical information from the Canadian Association of Petroleum Producers.9

 

Production of crude oil in Canada totaled 2.35 mmbd in 2005, with 35% of the volume 

comprised of light crude oil, 22% heavy crude oil, 23% from bitumen or synthetic crude 

obtained via surface mining, and 19% from bitumen produced from in situ methods. 

Surface mining comprised over half of the Canadian bitumen extraction, but use of in situ

techniques is now growing at a faster rate due to the lower availability of surface bitumen 

and improvements in in situ techniques. 

Domestic production of heavy oil was not included in the EIA import data 

analyzed by the EPA.10 To account for this, various estimates were used from different 

sources. In 2005, we estimate that roughly 475,000 bpd of heavy oil was produced in the 

U.S. with the vast majority produced in California.11

 

A fraction weighted estimate of the crude oil types used in the U.S., calculated 

based on the data sources and calculations described above, was used in our estimation of 

the 2005 gasoline and diesel baseline. Note that this does not include crude-type 

breakdowns for finished products imported into the U.S. from overseas (e.g. Europe) or 

exported and consumed overseas, which may change the fractions slightly. Out of the 

15.3 mmbd of crude oil reported to be used in the U.S. in 200512, approximately 5% was 

composed of bitumen-based syncrude (mainly from Canada), 1% was extra heavy crude 

oil based syncrude (mainly from Venezuela), and 23% was heavy crude oil, as shown in 

Figure 2 
8

Figure 2. Percent of U.S. Crude Oil by Source 

U.S. Crude Oil Consumption

5% 1%

23%

72%

-

2.00

4.00

6.00

8.00

10.00

12.00

Bitumen-based

syncrude

Extra heavy oil-based

syncrude

Heavy crude oil Light or medium crude

oil 

million barrels per day . .

The emission factors for the 2005 baseline were adjusted based on the above weighting 

for the different types of crude oil. 

2.2 Crude Transport 

Transport of crude oil to the U.S. was based on GREET defaults, which are 

shown in Figure 3. The figure indicates the percent of the different types of crude oil 

used (Canada and Mexico are assumed to include the Canadian oil sands imports) and 

associated modes of transportation and miles traveled for each mode. The emissions are 

based on emission factors for each type of vehicle including capacity, fuel economy, and 

type of fuel used. 
9

Figure 3. Crude Oil Transportation Assumptions 

7.0% 7.0%

2,100

35.0%

1.0%

500

50.0% 50.0%

5,500 92.0%

750

8.0%

750 0.0%

8.0% 800

0.0%

800

US Terminal

Petroleum 

Refinery

Domestic: 

Alaska

Domestic: 

US 48 States

Imported: 

Canada and 

Mexico

Imported: 

Offshore 

Countries

Ocean Tanker

Pipeline

Rail

Ocean Tanker

Pipeline

Barge

Rail

2.3 Refining 

The emissions associated with petroleum refining can also be calculated based on 

the energy efficiency of the refinery and the type of process energy fuel sources used. 

However, the refinery is producing a number of different petroleum-based products 

including different transportation fuels. Therefore, the total energy use and emissions 

from the refinery needs to be allocated to the different products. 

The basis for the overall refinery energy efficiency in GREET is a set of linear 

programming model runs representing energy use in a typical refinery. Different refinery 

configurations with different slates of products produced will have different energy 

efficiencies. For calculating baseline emissions associated with gasoline and diesel fuel 

we are assuming an average U.S. refinery, so defaults in GREET are reasonable for our 

analysis. 

Allocation of the total refinery energy use and emissions to the different products 

can be done in a number of ways. Total energy use and emissions can be allocated based 

on the energy, mass, or economic value of the different output products. Alternately, 

energy use and emissions can be based on first breaking out total refinery energy use to 

the different refinery sub-processes (e.g., distillation, cracking, alkylation, isomeration, 

desulfurization), and then allocating energy from each sub process to the different 

products, for example 100% of alkylation used for gasoline. This type of subprocess 

allocation would require a level of detail that was beyond the scope of this analysis. 

Therefore, we used the GREET default allocation which in general allocated 60–65% of 

total refining process fuel use to gasoline production, 18–22% to diesel production, and 

the remaining 13–22% to other petroleum products. 

The refinery modeling runs and the allocation to different products results in the 
10

energy efficiency values for different types of gasoline and diesel fuel shown in Table 7. 

Table 7. Refinery Energy Efficiency 

Transportation Fuel Type Energy Efficiency

Conventional Gasoline 87.7%

Reformulated Gasoline Feedstock 87.2% 

Low Sulfur Diesel Fuel 87% 

The following table shows the process fuel breakout and BTUs of process fuel used per 

million BTU of finished transportation fuel produced. 

Table 8. Refinery Energy Use 

Energy use (BTU/mmBTU of fuel throughput) 

Process Fuel 

Share of 

Input 

Energy 

Conventional 

Gasoline RFG Feedstock Low Sulfur Diesel Fuel 

Residual oil 3.0% 4,208 4,404 3,595 

Natural gas 30.0% 42,075 44,037 35,946 

Coal 13.0% 18,233 19,083 15,577 

Electricity 4.0% 5,610 5,872 4,793 

Refinery still gas 50.0% 70,125 73,395 59,910 

Total: 100% 140,251 146,789 119,821 

The emissions from refining are calculated by multiplying the BTUs of the 

different types of energy inputs by emissions factors for combustion of those fuel 

sources. The emission factors for the different fuel types are from GREET based 

primarily on assumed carbon contents of the different process fuels. The emissions from 

producing electricity are also taken from GREET and represent average U.S. grid 

electricity production emissions. In addition to process energy emissions, GREET also 

assumes there are non-combustion GHG emissions associated with petroleum refining. 

These emissions are also allocated to the different fuels based on the same energy 

efficiency ratios used to allocate energy use. The non-combustion CO2 emissions 

amount to 1,172 g CO2 per mmBTU of conventional gasoline, 1,214 g CO2 per mmBTU 

of reformulated gasoline (RFG) blendstock, and 1,088 g CO2 per mmBTU of low sulfur 
11

diesel fuel. 

To represent baseline gasoline we considered the types of gasoline used in 2005. 

Based on EIA data on sales of gasoline to end users in 2005, 57.4% was conventional 

gasoline, 28.4% was reformulated gasoline and 14.2% was California reformulated 

gasoline. The California reformulated gasoline is represented in GREET as reformulated 

with slightly different assumptions about crude transport distances. We also considered 

imported finished product vs. domestically produced gasoline. According to EIA data, in 

2005 6.0% of conventional gasoline used was imported and 7.7% of reformulated 

gasoline was imported. Imported gasoline was modeled the same as domestic for 

refinery emissions for GHGs, except conventional crude was used to represent crude oil 

production impacts, instead of a domestic mix. To represent baseline diesel fuel use we 

used a similar analysis and assumed 100% low-sulfur diesel fuel and 8.0% imported 

finished product. 

2.4 Fuel Transport 

Transport of the finished petroleum product was also included in the baseline 

values for gasoline and diesel fuel. Transport included carriage from refinery to bulk 

terminal and from bulk terminal to retail location. Transport of imported finished product 

was also included and was assumed to be transported by ocean tanker 2,600 miles to the 

U.S. Once in the U.S. both domestic and imports were assumed to be transported by the 

modes and distances shown in Table 9 and Table 10. 

Table 9. Gasoline Transport Assumptions 

Refinery to Bulk 

Terminal 

Bulk Terminal to 

Mode Refueling Station 

Percent Distance Percent Distance 

Ocean Tanker 17 1,500 0 N/A 

Barge 4 520 0 N/A 

Pipeline 72 400 0 N/A 

Rail 7 800 0 N/A 

Truck 0 N/A 100 30 
12

Table 10. Diesel Fuel Transport Assumptions 

Refinery to Bulk 

Terminal 

Bulk Terminal to 

Mode Refueling Station 

Percent Distance Percent Distance 

Ocean Tanker 12 1,500 0 N/A 

Barge 6 520 0 N/A 

Pipeline 72 400 0 N/A 

Rail 7 800 0 N/A 

Truck 0 N/A 100 30 

The GHG emissions from transport of gasoline and diesel fuel were based on 

GREET default emission factors for each type of vehicle including capacity, fuel 

economy, and type of fuel used. 

2.5 Modifications of 2005 Analysis for Future Years

For the impacts analysis of the proposed light duty vehicle GHG rule we modified 

the petroleum baseline fuel assumptions described above to account for expected shifts in 

petroleum production and fuel imports. For this analysis we considered the mix of crude 

oils and finished gasoline in 2022, since portions of the analysis were already available 

for that year in the Draft Regulatory Impact Analysis (DRIA) for the RFS2 proposed rule. 

For this analysis we consider that 50% of the reduction in gasoline consumption 

will come from imported gasoline, and 90% of the reduction in domestically refined 

crude will come from imported crude. 

We assume 65% of the reduction in gasoline consumption will be conventional 

gasoline and 35% will be RFG blendstock gasoline, and all of the RFG reduction will 

come from domestic production. 

In order to come up with emissions for average crude oil used in producing the 

marginal gasoline that would be reduced by this proposed rule we assumed for imported 

gasoline that 7.6% would be from tar sands and 3.8% would be from Venezuelan extra 

heavy crude, with the remainder from international light and heavy crude. For 

domestically refined gasoline, our assumption that only 10% of the crude oil reduction 

would be domestic crude shifted the allocation to 10.2% from tar sands and 5.1% from 

Venezuelan extra heavy crude, with the remaining 75% from international light and 

heavy crude. The basis for this was EIA projections for 2022. EIA projects that roughly 

64% of total Canadian crude oil production will be oil sand production in 2022, and that 

roughly 40% of total Venezuelan crude oil production will be heavy crude production in 

2022. EIA also has assumptions on how much crude oil will be imported into the U.S. 
13

from Canada and Venezuela in 2022. We assumed the percentage of this imported 

Canadian and Venezuelan crude oil that would be oil sands and heavy oil was the same 

percentage of total production that is unconventional crude in those countries (~64% for 

Canada and ~41% for Venezuela). Based on the percent of Canadian and Venezuelan 

imports to total crude oil projected in 2022, oil sands represented 7.6% and heavy oil 

represented 3.8% of total crude oil use. 

For this analysis we did not assume any efficiency improvements at the petroleum 

refining portion of the gasoline and diesel fuel lifecycle. Therefore the same refining 

energy use and emissions was assumed that was used to represent the 2005 petroleum 

fuel baseline. On the one hand this may be overestimating energy use and emissions 

from petroleum refining, however, this also does not factor in recent regulations that 

might increase energy use and emissions, such as increased desulfurization of both 

gasoline and diesel fuel. 

3.0 Modifications and Additions to GREET Analysis 

 For this analysis certain updates and enhancements were made to GREET13 and 

incorporated into an EPA spreadsheet model.14 This section describes (1) the methods 

used to estimate evaporative emission impacts during gasoline distribution, (2) updates to 

the transport vehicle/equipment emission factors to account for applicable EPA emission 

standards, and (3) addition of air toxic emission estimates. This analysis is adapted from 

the analysis done for the RFS2 proposed rule for year 2022, but for this GHG proposed 

rule there are no expected impacts related to biofuels such as ethanol, as those volumes 

are assumed constant. The year 2022 is considered to represent a reasonable estimate of 

the emission factors (not total emissions) for the future years analyzed in this proposed 

rule. 

3.1 Finished Fuel Transport and Distribution 

VOC emissions are produced by transfer and storage activities associated with 

distribution of gasoline, gasoline/ethanol blends, and ethanol. These are referred to as 

Stage I emissions.15 Stage I distribution begins at the point the fuel leaves the production 

facility and ends when it is loaded into the storage tanks at dispensing facilities. 

There are five types of facilities that make up this distribution chain for gasoline. 

Bulk gasoline terminals are large storage facilities that receive gasoline directly from the 

refineries via pipelines, barges, or tankers (or are collocated at refineries). Gasoline from 

the bulk terminal storage tanks is loaded into cargo tanks (tank trucks or railcars) for 

distribution to smaller intermediate storage facilities (bulk plants), or directly to gasoline 

dispensing facilities (retail public service stations and private service stations). When 

ethanol is blended into gasoline it usually occurs in the pipes which supply the tank 

trucks. 

There are two types of pipeline facilities found at various intervals along gasoline 

distribution pipelines: pipeline breakout stations and pipeline pumping stations. Pipeline 
14

breakout stations receive gasoline via pipelines, store it in storage tanks, and re-inject it 

into pipelines as needed to meet the demand from downstream facilities. Pipeline 

pumping stations are located along the entire length of a pipeline at about 40 mile 

intervals. Their purpose is to provide the extra ‘‘push’’ needed to move the product 

through the pipeline. They do not normally have gasoline storage capability. 

Bulk plants are intermediate storage and distribution facilities that normally 

receive gasoline or gasoline/ethanol blends from bulk terminals via tank trucks or 

railcars. Gasoline and gasoline/ethanol blends from bulk plants are subsequently loaded 

into tank trucks for transport to local dispensing facilities. 

Gasoline dispensing facilities include both retail public outlets and private 

dispensing operations such as rental car agencies, fleet vehicle refueling centers, and 

various government motor pool facilities. Dispensing facilities receive gasoline and 

gasoline/ethanol blends via tank trucks from bulk terminals or bulk plants. Inventory 

estimates for this source category only include the delivery of gasoline at dispensing 

facilities and does not include the vehicle or equipment refueling activities. 

Emission factors (EFs) for gasoline were based on inventory estimates from the 

2002 NEI.16 We used these data to develop E0 gasoline emission factors even though the 

2002 emissions included the E10 that was in the fuel pool at that time. In 2002 this was 

still a relatively small proportion of gasoline consumption, so it should not substantially 

affect the national E0 estimates. Since ethanol is blended with gasoline at bulk terminals 

to produce E10 and E85 at the point fuel is loaded into tank trucks, we assumed bulk 

terminal emissions were associated with unblended gasoline. We then divided emissions 

into a refinery to bulk terminal component and a bulk terminal to dispensing facility 

component. Total nationwide emissions for these two components were divided by the 

energy content of the total volume of gasoline distributed in 1999, to obtain the emission 

factor in g/mmBTU. Total volume of gasoline was based on gasoline sales as reported by 

the Energy Information Administration.17 These emission factors are provided in 

Table 11. 

Table 11. VOC Emission Factors for Gasoline Storage and Transfer 

Emissions (Stage 1) 

Process EF 

(g/mmBTU) 

Refinery to Bulk Terminal 14.94 

Bulk Terminal to Pump 27.79 

3.2 Combustion Emissions from Transport and Distribution of Fuel and Feedstock 

 Emissions are produced by the vehicles and equipment used to transport 
15

feedstocks such as crude oil to refineries, as well as the equipment and vehicles that 

distribute finished gasoline from refineries to distribution terminals and retail outlets. 

For example, foreign crude oil is transported to domestic refineries by ocean tankers, and 

finished gasoline is then moved by pipeline to distribution terminals and from there by 

tank truck to retail outlets.. The emission factors for the year 2022 in Table 12 take into 

account the mix of newer better controlled engines (including trucks meeting the 

standards for 2008 and later engines18 and engines meeting the 2008 locomotive/marine 

diesel engine rule19), as well as any remaining older engines subject to less stringent 

standards. The truck EFs are given in terms of grams per vehicle mile traveled, while the 

other EFs are in grams per million BTU of fuel burned by the engine. Emission factors 

for these engines are taken from the respective rulemaking analyses. 

 To estimate the net emission rates for the assumed mix of transport modes for 

each fuel type, these emission factors were incorporated into a modified version of 

GREET20, since GREET 1.7 and 1.8 retained emission factors based only on earlier 

regulations. Thus, the miles traveled and quantities of fuel burned are those used by 

GREET for each transport mode and fuel being transported. 
16

Table 12. Criteria Emission Factors for Fuel and Feedstock Transport/Distribution 

Transport Mode Year VOC CO NOx PM10 PM2.5 

Class 2B HD Diesel Trucks 

(g/mile) 2005 0.282 1.303 3.594 0.163 0.139 

2022 

(2020) 0.137 0.205 0.483 0.033 0.019 

Medium HD Diesel Trucks 

(g/mile) 2005 0.653 2.482 8.297 0.309 0.271 

2022 

(2020) 0.289 0.417 1.243 0.053 0.035 

Locomotive (g/mmBTU of fuel 

burned) 2005 84.733 212.861 1620.376 51.575 50.028 

2022 

(2020) 34.070 203.984 815.271 19.015 18.445 

Barge (avg of C1 & C2 vessels)21 2005 26.761 237.513 1276.901 47.923 46.485 

 (g/mmBTU of fuel burned) 

2022 

(2020) 15.527 188.994 676.097 22.017 21.356 

Ocean Tanker (C3 vessels) 2005 79.943 181.746 2177.881 181.410 166.930 

 (g/mmBTU of fuel burned) 

2022 

(2020) 79.891 181.526 2054.819 181.118 166.666 

3.3 Upstream Air Toxics 

3.3.1 Upstream Air Toxics Reference Case 

Air toxic emissions are associated with a variety of upstream processes. These 

processes include operation of petroleum refineries, operation of electrical production 

facilities which supply power to these facilities, and transport of feedstocks and 

distribution of finished gasoline. 

Although a large number of compounds which are considered air toxics could be 

impacted by this rule, we focused on those which were identified as national and 

regional-scale cancer and noncancer risk drivers in the 1999 NATA22 and were also 

likely to be significantly impacted by this rule. These compounds include benzene, 1,3-

butadiene, formaldehyde, acetaldehyde, and acrolein. Naphthalene was not included in 

this analysis since the impacts of the proposed program on it would be minor relative to 

the other air toxics. 
17

Air toxic emissions for year 2002 for stationary sources refineries, other than for fires, 

were obtained from the 2002 National Emissions Inventory (NEI), version 3. Future year 

emissions of benzene, 1,3-butadiene, formaldehyde, acetaldehyde, and acrolein were 

estimated for sectors only, rather than individual sources. These sectors included nonEGU (electric generating unit) point sources, EGU point sources, the nonpoint storage 

and transfer subsector, and other nonpoint sources. Emissions were estimated by 

applying future year to 2002 VOC ratios to 2002 air toxic estimates. More details on the 

methods and data used to develop these inventories are found in a memo included in the 

docket for the RFS2 proposed rule.23

3.3.2 Upstream Air Toxics Control Case 

 

As described below, we developed emission factors for several air toxics using 

the most recent available data. These emission factors were used with estimates of 

changes in fuel volumes and associated energy outputs to estimate inventory changes 

associated with the proposed program. In general, emission factors are expressed as 

grams per million BTU (g/mmBTU) of energy produced or distributed as part of the 

process. Underlying data are available in the docket for the rule. 

Petroleum Refineries – Total nationwide emissions of air toxics for 153 U. S. petroleum 

refineries in 2002 were obtained from data collected as part of a risk and technology 

review (RTR) for EPA’s proposed rule, “National Emission Standards for Hazardous Air 

Pollutants From Petroleum Refineries.”24 These emissions were divided by BTUs of 

energy produced by those refineries in 2002 to obtain emission factors in g/mmBTU. 

Thus the resultant emission factors represent 2002 technology and emission standards. 

Energy output estimates included all refinery products, such as conventional and 

reformulated gasoline, aviation gasoline, jet fuel, kerosene, distillate fuel oil, residual fuel 

oil, petrochemical feedstocks, naphthas, lubricants, and other miscellaneous products. 

Energy output was estimated by multiplying volume of each product supplied17 by its 

heating value in BTUs per gallon. 

Resultant emission factors are provided below in Table 13, along with those for 

electricity production. 
18

Table 13. Air Toxic Emission Factors for Petroleum Refineries and Electricity 

Production (g/mmBTU of fuel or electricity produced) 

Pollutant Petroleum 

Refinery 

Electricity 

Production 

1,3-butadiene 0.0014 0.0001 

Acetaldehyde 0.0002 0.0297 

Acrolein 0.0001 0.0115 

Benzene 0.0264 0.0443 

Formaldehyde 0.0042 0.0629 

Table 14. Benzene Evaporative Emission Factors for Gasoline Transport and 

Distribution (g/mmBTU of fuel transported) 

Process Year Benzene EF 

(g/mmBTU) 

Refinery to 

Bulk Terminal 2002 0.0488 

Refinery to 

Bulk Terminal 2022 0.0270 

Bulk Terminal 

to Pump 2002 0.0908 

Bulk Terminal 

to Pump 2022 0.0502 

There are also toxic emissions associated with combustion of fuels used in 

transport and distribution of feedstocks and fuels. The emission factors for these are 

shown in Table 15 as fractions of exhaust VOC. The VOC emission factors that these 

fractions are applied to are presented above in Table 12. The locomotive, marine 

distillate, and residual boiler estimates come from a 2005 EPA report.25 The heavy-duty 

diesel truck emission fractions come from a 2002 report documenting the toxics module 

of EPA's MOBILE6.2 model,26 and the pipeline values come from the EPA AP-42 

document.27 
19

Table 15. Toxic Fractions of Exhaust VOC 

(grams toxics per gram of VOC) 

Mode Source 1,3-

Butadiene Acetaldehyde Acrolein Benzene Formaldehyde

Rail Diesel 

Locomotive 0.003246519 0.018786 0.0031238 0.002587511 0.04328653 

Barge 

Marine 

Diesel -- 

Distillate 

0.00061 0.074298 0.0035 0.020344 0.1496 

Ocean 

Tanker 

Residual 

Boiler 0 0.003858 0 0.000165354 0.02645669 

Truck HD Diesel 

Trucks 0.00061 0.0288 0.0035 0.0105 0.0782 

Pipeline Natural Gas 

Turbines 0 0.019048 0.0030476 0.005714286 0.33809524 
20

 

1

 Argonne National Laboratories, The Greenhouse Gas and Regulated Emissions from 

Transportation (GREET) Model, Version 1.8, June 2007, available at 

http://www.transportation.anl.gov/software/GREET/index.html (accessed April 20, 

2008). 

2

 U.S. EPA, Draft Regulatory Impact Analysis: Changes to Renewable Fuel Standard 

Program, EPA-420-D-09-001, May 2009. Docket EPA-HQ-OAR-2005-0161. 

http://www.epa.gov/otaq/renewablefuels/420d09001.pdf 

3

 McCann, T., and Magee, P., Crude Oil Greenhouse Gas Life Cycle Analysis Helps 

Assign Values For CO2 Emissions Trading . Oil and Gas Journal. Vol. 97, no. 8, pp. 38-

44. Feb 1999. 

4

 USGS (November 2006), “Natural Assessment of Oil and Gas Fact Sheet: Natural 

Bitumen Resources of the United States,” Fact Sheet 2006-3133. 

5

 USGS (August 2003), “Heavy Oil and Natural Bitumen – Strategic Petroleum 

Resources,” Fact Sheet 70-03. 

6

 Energy Information Administration, EIA Survey Form 814, "Monthly Imports Report," 

http://www.eia.doe.gov/oss/forms.html#eia-814. 

7 International Energy Agency (March 14, 2006), Oil Market Report: A Monthly Oil 

Market and Stocks Assessment, www.oilmarketreport.org. pp. 18. 

8

 Energy Information Administration, “Country Analysis Briefs,” Venezuela Oil. 

http://www.eia.doe.gov/emeu/cabs/Venezuela/Oil.html (last viewed 6/18/2008). 

9

 Canadian Association of Petroleum Producers (May 2008), Statistical Handbook for 

Canada’s Upstream Petroleum Industry. 

10 National Petroleum Council (2007), "Working Document of the NPC Global Oil & 

Gas Study" July 18, 2007, Topic Paper #22 Heavy Oil. 

11 California 2007 Annual Report of the State Oil & Gas Supervisor, 

http://www.conservation.ca.gov/dog/pubs_stats/annual_reports/Pages/annual_reports.asp

x (last viewed 6/18/2008). 

12 Energy Information Administration, U.S. Imports by Country of Origin, 2005 data. 

http://tonto.eia.doe.gov/dnav/pet/pet_move_impcus_a2_nus_epc0_im0_mbbl_a.htm (last 

viewed 6/18/2008) 

13 EPA Modified version of GREET 1.7 Argonne National Lab model for RFS2 NPRM 

Emission Factors, October 31, 2008, Docket ID: EPA-HQ-OAR-2005-0161-0428. 
21

 

14 U.S. EPA, GHG Vehicle NPRM Upstream (Production/Distribution) Emission 

Impacts Calculation Spreadsheet, September 9, 2009. 

15 40 CFR Part 63 National Emission Standards for Hazardous Air Pollutants for Source 

Categories: Gasoline Distribution Bulk Terminals, Bulk Plants, Pipeline Facilities, and 

Gasoline Dispensing Facilities; Proposed Rule, Thursday, November 9, 2006, 66064-

66092. 

16 E. H. Pechan. Documentation For The Final 2002 Nonpoint Sector (Feb 06 Version) 

National Emission Inventory For Criteria And Hazardous Air Pollutants, Appendix A, pp. 

A-89 to A-105. Prepared for Emissions Inventory and Analysis Group (C339-02) Air 

Quality Assessment Division Office of Air Quality Planning and Standards U.S. 

Environmental Protection Agency Research Triangle Park, NC 27711, Report No. 

05.10.001/9014.401 Jul-06. Available at 

ftp://ftp.epa.gov/EmisInventory/2002finalnei/documentation/nonpoint/2002nei_final_non

point_documentation0206version.pdf. 

17 Energy Information Administration. 2007. Product Supplied, Petroleum Supply 

Reporting System. http://tonto.eia.doe.gov/dnav/pet/pet_cons_psup_dc_nus_mbbl_a.htm 

18 U. S. EPA. 2001. Final Rule: Control of Air Pollution From New Motor Vehicles: 

Heavy-Duty Engine and Vehicle Standards and Highway Diesel Fuel Sulfur Control 

Requirements, January 18, 2001. 

19 U. S. EPA. 2008. Final Rule: Control of Emissions of Air Pollution from 

Locomotives and Marine Compression-Ignition Engines Less than 30 Liters per Cylinder, 

Regulatory Impact Analysis, June 30, 2008. http://www.epa.gov/otaq/locomotives.htm 

20 U.S. EPA. 2009. Modified version of GREET1.7/1.8 upstream emissions spreadsheet 

model, September, 2009. 

21 Emission Inventories for Ocean-Going Vessels Using Category 3 Propulsion Engines 

In or Near the United States, Draft Technical Support Document, EPA420-D-07-007, 

December 2007. This is available in Docket OAR-2007-0121 at 

http://www.regulations.gov/ . 

22 U. S. EPA. 2006. National-Scale Air Toxics Assessment for 1999: Estimated 

Emissions, Concentrations And Risk, Technical Fact Sheet. 

http://www.epa.gov/ttn/atw/nata1999. 

23 U. S. EPA. 2008. Technical Support Document: Preparation of Emissions Inventories 

For the 2002-based Platform, Version 3, Criteria Air Pollutants, January 2008, Docket ID 

EPA-HQ-OAR-2004-0008-0857. 
22

 

24 Federal Register. 2007. National Emission Standards for Hazardous Air Pollutants 

From Petroleum Refineries. 72(170): 50715-50742. http://www.epa.gov/EPAAIR/2007/September/Day-04/a17009.htm. 

25 Diesel Locomotives, Marine Distillate, Residual Boiler -- E. H. Pechan. 2005. 

Documentation For Aircraft, Commercial Marine Vessel, Locomotive, And Other 

Nonroad Components Of The National Emissions Inventory, Volume I - Methodology. 

Prepared for U. S. Environmental Protection Agency, Office of Air Quality Planning and 

Standards, Research Triangle Park, NC. 

http://www.epa.gov/ttn/chief/net/2002inventory.html

26 HDD Trucks -- R. Cook, E. Glover. 2002. Technical Description of the Toxics 

Module for MOBILE6.2 and Guidance on Its Use for Emission Inventory Preparation. U. 

S. Environmental Protection Agency, Office of Transportation and Air Quality. Report 

No. EPA420-R-02-011. http://www.epa.gov/otaq/m6.htm 

27 Natural Gas Turbines -- U. S. EPA. 2000. AP-42, 5th Edition, Volume 1. Chapter 3: 

Stationary Internal Combustion Sources. 

http://www.epa.gov/ttn/chief/ap42/ch03/index.html