The U.S. Oil Refining Industry: Background in Changing Markets and Fuel Policies
Congressional research reportDec 27, 2012
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The U.S. Oil Refining Industry: Background
in Changing Markets and Fuel Policies
(name redacted)
Specialist in Energy and Defense Policy
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Specialist in Energy Economics
(name redacted)
Specialist in Public Finance
(name redacted)
Section Research Manager
December 27, 2012
Congressional Research Service
7-....
www.crs.gov
R41478
CRS Report for Congress
Prepared for Members and Committees of Congress
The U.S. Oil Refining Industry: Background in Changing Markets and Fuel Policies
Summary
A decade ago, 158 refineries operated in the United States and its territories and sporadic refinery
outages led many policy makers to advocate new refinery construction. Fears that crude oil
production was in decline also led to policies promoting alternative fuels and increased vehicle
fuel efficiency. Since the summer 2008 peak in crude oil prices, however, the U.S. demand for
refined petroleum products has declined, largely due to the economic recession, and the outlook
for the petroleum refining industry in the United States has changed.
In response to weak demand for gasoline and other refined products, refinery operators have
begun cutting back capacity, idling, and, in a few cases, permanently closing their refineries. By
current count, 115 refineries now produce fuel in addition to 13 refineries that produce lubricating
oils and asphalt. Even as the number of refineries has decreased, operable refining capacity has
actually increased over the past decade, from 16.5 million barrels/day to over 18 million
barrels/day. Cyclical economic factors aside, U.S. refiners now face the potential of long-term
decreased demand for their products. Legislative and regulatory efforts that originally intended to
address the growing demand for petroleum products may now displace some of that demand.
These efforts include such policies as increasing the volume of ethanol in the gasoline supply,
improving vehicle fuel efficiency, and encouraging the purchase of vehicles powered by natural
gas or electricity.
The United States met roughly 39% of its crude oil demand in 2011 through domestic
production, exclusive of the natural gas needed in various refining processes. Canada has become
the United States’ leading supplier of crude oil through its increasing production from oil sands
providing roughly 15% of U.S. demand. In total, the United States meets 62% of its demand from
crude oil produced in North America. Over the last few decades, imported crude oils have
become heavier and higher in average sulfur content. Until quite recently, the diminishing supply
of light sweet crude oil led U.S. refineries to make multi-million dollar investments in processingupgrades to convert lower-priced heavier sour crude oils to high-value products such as gasoline,
diesel, and jet fuel.
Some key environmental and energy policies enacted over the past few decades directly or
indirectly affect the operations of U.S. refineries and the market for petroleum products. These
include requirements for the use of reformulated gasoline (RFG) in many areas of the country,
mandates under the federal Renewable Fuel Standard (RFS), increasingly stringent vehicle
efficiency standards, and greenhouse gas limits under the Clean Air Act and state laws.
Declining motor-fuel demand spurred by both market and regulatory forces has influenced some
refinery operators to idle, consolidate, or permanently close refineries. However, newly available
light sweet crudes from North Dakota, Texas, and Ohio are changing refining economics in some
regions of the United States.
Congressional Research Service
The U.S. Oil Refining Industry: Background in Changing Markets and Fuel Policies
Contents
Introduction...................................................................................................................................... 1
Background: The Basics of Refining Crude Oil .............................................................................. 2
Refining Capacity ............................................................................................................................ 4
Refinery Closures and Expansions .......................................................................................... 10
Refinery Capacity Distribution................................................................................................ 10
Coking Capacity ...................................................................................................................... 11
Major Refiners ......................................................................................................................... 12
Crude Oil Supply ........................................................................................................................... 13
Changing Crude Oil Grades ........................................................................................................... 16
Crude Oil Prices ...................................................................................................................... 17
Gasoline Demand .................................................................................................................... 19
Refining Profitability ..................................................................................................................... 20
Refining Capital Investment .................................................................................................... 21
Refinery Investment and Petroleum Product Imports ............................................................. 22
Refinery Tax Considerations.......................................................................................................... 23
Energy and Environmental Policy Considerations ........................................................................ 24
Reformulated Gasoline (RFG) and State “Boutique Fuels” .................................................... 24
Renewable Fuel Standard /Alternative Fuels .......................................................................... 26
Carbon Emissions/Greenhouse Gas Rules .............................................................................. 28
Vehicle Fuel Economy/Greenhouse Gas Rules ....................................................................... 29
Conclusion ..................................................................................................................................... 30
Figures
Figure 1. Suite of Crudes ................................................................................................................. 2
Figure 2. Generic Distillation Column ............................................................................................ 3
Figure 3. Refining Capacity Vs. Product Supplied (2011) .............................................................. 6
Figure 4. U.S. Refineries by PADD ................................................................................................. 7
Figure 5. U.S. Refining Capacity Distribution .............................................................................. 11
Figure 6. Refineries with Coking Capacity ................................................................................... 12
Figure 7. Top Ten U.S. Refiners (2012) ......................................................................................... 13
Figure 8. U.S. Crude Oil Supply.................................................................................................... 14
Figure 9. Crude Oil Supply Volume .............................................................................................. 16
Figure 10. Crude Oil Supply Trend ............................................................................................... 16
Figure 11. Map of Reformulated Gasoline Areas .......................................................................... 25
Figure B-1. Gulf Coast Refinery Yields......................................................................................... 37
Figure C-1. Operable Refineries in PADD 1 ................................................................................. 38
Figure C-2. Operable Refineries in PADD 2 ................................................................................. 39
Figure C-3. Operable Refineries in PADD 3 ................................................................................. 40
Figure C-4. Operable Refineries in PADD 4 ................................................................................. 42
Figure C-5. Operable Refineries in PADD 5 ................................................................................. 43
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The U.S. Oil Refining Industry: Background in Changing Markets and Fuel Policies
Tables
Table 1. U.S. Refineries by PADD and Advertised Capacity .......................................................... 8
Table 2. Gross Input to Refineries ................................................................................................. 15
Table 3. Light/Heavy Crude Oil Price Spread ............................................................................... 19
Table 4. United States Gasoline Consumption 2006-2009 ............................................................ 20
Table 5. Refiners’ Net Income, 2006-2011 .................................................................................... 21
Table 6. U.S. Refining Industry Capital Budget Expenditures, 2008-2010 ................................... 21
Table 7. Gasoline Imports Vs. Total Gasoline Supplied ................................................................ 23
Table 8. Tax Expenditures for Provisions Allowing Partial Expensing of Refinery
Investments ................................................................................................................................. 24
Table 9. EISA Renewable Fuel Volume Requirement ................................................................... 27
Table A-1. API Gravity and Sulfur Content of Select Crude Oils ................................................. 32
Table B-1. Crude Oil Fractions and Boiling Ranges ..................................................................... 35
Table B-2. Refinery Types and Process ......................................................................................... 36
Appendixes
Appendix A. Crude Oil Properties ................................................................................................. 32
Appendix B. Refining Processes ................................................................................................... 35
Appendix C. Operable Refineries by PADD ................................................................................. 38
Appendix D. Important Fuel Properties ......................................................................................... 45
Appendix E. Glossary .................................................................................................................... 47
Contacts
Author Contact Information........................................................................................................... 48
Acknowledgments ......................................................................................................................... 48
Congressional Research Service
The U.S. Oil Refining Industry: Background in Changing Markets and Fuel Policies
Introduction
The U.S. petroleum refining industry experienced what some have called a “golden age” during
the years 2004-2007. During this period, the demand for petroleum products, especially gasoline,
increased rapidly both in the United States and world markets. Refiners found favorable pricespreads between heavy and light crude oils as well as between crude oil and refined products. The
industry operated plants at nearly maximum capacity and posted record profit levels. Unexpected
events such as hurricanes that shut down Gulf Coast refineries, concerns over “peak oil”
production, and crude oil price speculation likely contributed to spikes in gasoline prices. During
the period, many policy makers expressed the concern that U.S. refining capacity was not
increasing rapidly enough to keep up with the expected growth in demand for petroleum
products. The concern now may be that excess refining capacity has affected bottom-line refining
profitability and the ability to meet consumer demand.
Current economic conditions have led to lower refinery utilization rates and recent closure of a
few refineries. In a continuing trend, some vertically integrated oil companies (those engaged in
all phases of production, refining and marketing) either have divested their refineries or spun
them off as separate business units. The concentration of refining capacity in the U.S. Gulf Coast,
an outcome of the region’s significant petroleum resources and their history of development,
influenced the current network of crude oil and product distribution pipelines. New sources of
heavy crude oils from Canada and light crude oils from the mid-continent and mid-West are
altering the logistics in supplying established refining centers. In the absence of pipeline capacity,
existing rail lines are proving a viable alternative. Rail appears to offer an immediate solution to
both crude supply and product delivery bottlenecks, as rail-delivered ethanol appears to
demonstrate. No matter what the investment, refineries must adapt to changing crude streams to
ensure lowest cost of operation, and the largest product/crude price spread. The greatest cost in
refining is not capital investment, but crude costs. But, the growing availability of new
unconventional oil resources in the mid-continent resources is changing refining economics and
profitability on both the East and West Coasts, and perhaps challenging the Gulf Coast’s refining
center status.
The U.S. refining industry faces a number of new policies that could force downward pressure on
refinery numbers, capacity, or utilization:
•
•
•
•
Tighter Corporate Average Fuel Economy (CAFE) and vehicle greenhouse gas
standards;
the federal Renewable Fuel Standard (RFS);
natural gas as a transportation fuel; and
EPA Mandatory Greenhouse Gas Reporting.
Further, the potential binding greenhouse gas limits in the future, either through a federal capand-trade or carbon tax program, or through regulation under the Environmental Protection
Agency’s “tailoring rule,” could provide further downward pressure on petroleum demand.
This report reviews the current production capacity of the refineries operating in the United
States, and the sources and changes in their crude oil supply. It also examines the changing
characteristics of petroleum and petroleum product markets and identifies the effects of these
changes on the refining industry, including tax considerations. It concludes with discussion of the
policy and regulatory factors that are likely to affect the structure and performance of the industry
during the next decade.
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The U.S. Oil Refining Industry: Background in Changing Markets and Fuel Policies
Background: The Basics of Refining Crude Oil
Crude oil is a complex mix of hydrocarbon compounds, ranging from simple compounds with
small molecules and low densities to very dense compounds with extremely large molecules. An
average crude oil contains about 84% carbon, 14% hydrogen, 1% to 3% sulfur, and less than 1%
each nitrogen, oxygen, metals, and salts. The American Petroleum Institute (API) compares the
“lightness” or “heaviness” of crude oils on an inverted scale in terms of degrees (º) API gravity.1
Figure 1 illustrates a range of crude oil gravities. Any crude above 10 °API will float on water.
Light crude’s API gravity is higher than 31.1 ºAPI, medium crude between 22.3 °API and 31.1
°API, and heavy crude below 22.3 °API. The benchmark for comparing crudes has been West
Texas Intermediate (WTI), or Texas light sweet. Light crude has a low wax-content, and sweet
crude has less than 0.5% sulfur. (Refer to Appendix A for further information on crude oil
properties.)
Figure 1. Suite of Crudes
Source: Canadian Crude Quick Reference Guide Version 0.54, Crude Oil Quality Association, 2009,
http://www.coqa- inc.org/102209CanadianCrudeReferenceGuide.pdf; http://www.genesisny.net/Commodity/Oil/
OSpecs.html#Top; BP http://www.bp.com/productfamily.do?categoryId=16002776&contentId=7020157;
McQuilling Services, LLC, “Carriage of Heavy Grade Oil,” Garden City, NY, 2011, http://www.meglobaloil.com/
MARPOL.pdf; Hydrocarbon Publishing Co., Opportunity Crudes Report II, Southeastern, PA, 2011, p. 5,
http://www.hydrocarbonpublishing.com/ReportP/Prospectus- Opportunity%20Crudes%20II_2011.pdf.
Notes: Light crude > 31.1 ºAPI, medium crude 22.3 - 31.1 °API, and heavy < 22.3 °API.
A hypothetical refinery distills crude oil into various products, according to their boiling point
range. The most common products—gasoline, diesel, and jet fuels—are complex mixtures of
hydrocarbons that include paraffins, naphthenes, and aromatics (which give fuel its unique odor).2
1
API gravity scale: light—greater than 30º; medium—22º to 30º; heavy—less than 22º; and extra heavy—below 10º.
Formula: (141.5 ÷ relative density of the crude [at 15.5°C or 60°F]) - 131.5.
2
James H. Gary and Glenn E. Handwerk, Refining Petroleum—Technology and Economics, 4th Ed., Marcel Dekker,
Inc., 2001.
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The U.S. Oil Refining Industry: Background in Changing Markets and Fuel Policies
Refineries vary in complexity, but have
several basic processing steps in common:
Basic Refining
distillation, cracking, treating and reforming.
Refineries have several basic processing steps in
Distillation involves heating crude oil in a
common: distillation, cracking, treating and reforming.
Topping plants, the simplest refineries, separate crude oil
furnace then condensing it in an atmospheric
into constituent petroleum products by atmospheric
distillation tower (or Crude unit)—the tall,
distillation; they produce asphalt and naphtha, but no
narrow columns that give a refinery its
gasoline. Hydroskimming plants use atmospheric
distinctive skyline. The Crude unit separates
distillation, naphtha reforming and desulfurization
process to run light sweet crude to produce gasoline.
light hydrocarbon molecules from heavy
Cracking plants add vacuum distillation and catalytic
hydrocarbons based on their boiling
cracking process to run light sour crude to produce light
temperatures. The lightest materials, like
and middle distillates. The most complex refineries add
propane and butane, vaporize and rise to the
coking/resid destruction (delayed coking process) to run
top of the atmospheric column. Medium
medium/sour crude oil.
weight materials, including gasoline, jet and
diesel fuels, condense in the middle. Heavy materials, called gas oils, condense in the lower
portion of the atmospheric column. Residuum (a heavy tar-like material) referred to as the
“bottom of the barrel,” has a high boiling temperature that keeps it in the lower portion of the
column.
Figure 2. Generic Distillation Column
Source: CRS.
Note: For illustrative purposes only.
In some cases, distillation columns operate at less than atmospheric pressure (vacuum) to lower
the temperature at which a hydrocarbon mixture boils. Vacuum distillation reduces the chance of
thermal decomposition (cracking) due to overheating. As the heavier oils move through the
refinery, heat and catalysts “crack” them into lighter products through fluid-catalytic-cracking
(FCC), hydrocracking, or thermal-cracking (coking). Fluid catalytic cracking uses high
temperature and catalysts to convert heavy gas oil mostly into gasoline. Hydrocracking uses
catalysts to react gas oil and hydrogen under high pressure and high temperature to make both jet
fuel and gasoline. Coking converts low-value residuum (using thermal-cracking) to high-value
light products, producing petroleum coke as a by-product.
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The U.S. Oil Refining Industry: Background in Changing Markets and Fuel Policies
While the cracking breaks most of the gas oil
into gasoline and jet fuel, it also breaks off
some smaller hydrocarbons that are lighter
than gasoline. These lighter hydrocarbons
recombine in alkylation units, in the presence
of sulfuric acid catalyst, to reform into highoctane gasoline. The products from the crude
unit and the feeds to other units contain some
natural impurities, such as sulfur and
nitrogen that contribute to air pollution when
fuels combust. Hydrotreating (a milder
version of hydrocracking) removes these
impurities by converting the sulfur to
hydrogen sulfide and then to elemental
sulfur; and converting nitrogen into ammonia
and then removing it by water-washing for
recovery as ammonia for fertilizer.
When refined, a generic 35 °API Crude Oil might yield as
much as 27% gasoline and 25% middle distillate fuels
Source: Petroleum Geochemistry and Geology,
The gasoline stream that comes out of the
1979.
crude unit or cracking unit has a relatively
low octane rating (a key measure of how gasoline performs in an automobile engine). To upgrade
gasoline octane-rating, a reforming unit uses precious-metal catalysts (platinum and rhenium) to
“reform” hydrocarbon molecules into high-octane gasoline components. The reforming process
removes hydrogen from low-octane gasoline, which refinery reuses in various cracking
(hydrocracking) and treating (hydrotreating) units.
When refined, a 35 °API crude might yield a product slate range of 27% gasoline and 25%
middle distillate fuels in the range diesel and jet fuel. For further information on refining
processes refer to Appendix A.
Refining Capacity
After a volatile decade marked by record
crude oil prices and profit margins, U.S.
refiners now face the prospect of possibly
long-term decreased demand for their
products. Refiners are responding by cutting
costs, reducing capacity utilization, and
closing facilities.
U.S. Refining Capacity by PADD (2012)
115 refineries, including several refining complexes
represent 18 million barrels per day in refining capacity.
PADD
1
2
3
4
5
Total
Refineries
7
25
43
15
25
115
Bbl/day
1,273,000
3,764,3001 complex*
9,256,3002 complexes*
632,250
3,241,8001 complex*
18,167,650
A decade ago, 158 refineries operated in the
United States and its territories. By the
Congressional Research Service’s (CRS) most
* A complex may include two or more refineries
that previously operated independently of each
recent count, 115 refineries primarily process
other.
crude oil into fuels (of which four refineries
are complexes made up of two or three
formerly independent refineries joined by pipeline). Despite permanent closures, operable
refining capacity has increased over the past decade from 16.5 million barrels/day to
approximately 18 million barrels/day. By the Energy Information Administration’s (EIA)
definition, “operable capacity” includes both operating refineries and idle refineries which shut
down temporarily for repair or “turn around” for seasonal adjustment in the product slate (for
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The U.S. Oil Refining Industry: Background in Changing Markets and Fuel Policies
example, reformulating gasoline from winter to summer blends). EIA includes refineries that also
produce lubricating oils, asphalts, and other products For this report, CRS reviewed petroleum
refiners that primarily produce fuel and used the capacity that these refiners advertise on their
corporate web pages to estimate an overall refinery capacity in excess of 18 million barrels/day.
EIA had reported a U.S. operable crude oil distillation capacity of 17.73 million barrels/day and a
gross crude oil input of 15.29 million barrels/day in 2011 yielding a refinery utilization capacity
at slightly over 86%. As a refinery’s year-to-year performance changes (for the reasons noted
above) a better measure of capacity may be “barrels/stream day”—the barrels of crude oil input a
refinery reports over the number of days it annually operates also termed “utilization.” EIA also
reported prime suppliers of refined products sold approximately 14.53 million barrels/day.3 A
prime supplier produces, imports, or transports selected petroleum products (motor gasoline,
aviation gasoline, kerosene-jet fuel, propane, total distillate and kerosene, and distillate fuel oil)
across state boundaries and local marketing areas, and sells the product to local distributors, local
retailers, or end users.
A 95,000-mile network of petroleum product pipelines serves most of the United States, making
them interdependent. The West Coast (PADD 5) remains largely isolated from the rest of the
United States, especially from the large refineries in PADD 3, as well as crude oil imports to the
Gulf Coast. The Virginia and Colonial product pipelines, built during World War II, link up
PADD 3 Gulf Coast refineries with PADD 1 northeast states. Regional differences in EPA
mandated fuel gasoline specifications, however, limit the flexibility of distribution by pipeline.
The isolation has resulted in a gasoline market that has exhibited higher prices and reduced
availability under some market conditions. No crude oil pipelines link PADD 1 or PADD 5 with
the rest of the country, but rail shipment offers a near-term alternative. Canada supplies PADD 2
refineries through the Alberta Clipper crude oil pipeline. Permitting issues currently stall the
Keystone-XL pipeline that would deliver Canadian syncrude (a diluted bitumen from oil sands) to
PADD 3 Gulf Coast refineries. Figure 3 compares each PADD’s refining capacity to supplied
petroleum products.
Figure 4 provides a general map of refinery locations by “Petroleum Administration for Defense
District” (PADD).4 At one time, refineries in each PADD processed crude oil and distributed
petroleum products for use in the district. Maps that are more detailed are available in Appendix
C. Table 1 provides refineries by PADD, city, and capacity. CRS count does not include refineries
that primarily produce lubricating oils, or asphalt.5
3
EIA, Prime Supplier Sales Volumes for 2011: http://www.eia.gov/dnav/pet/ pet_cons_prim_dcu_nus_m.htm.
During World War II, the War Department (now the Department of Defense) delineated PADDs to facilitate oil
allocation.
5
To arrive at this number, CRS used U.S. Energy Information Administration and Environmental Protection Agency
sources, and then cross-correlated information that refinery operators published on their corporate web pages and in
financial statements. CRS also geo-located the refinery sites by using online imagery and mapping tools.
4
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The U.S. Oil Refining Industry: Background in Changing Markets and Fuel Policies
Figure 3. Refining Capacity Vs. Product Supplied (2011)
(Thousand Barrels/day [Bbl/Day])
Source: Refining capacity based on CRS analysis of capacity data advertised on owner/operator websites.
Demand based on EIA Prime Supplier Sales Volumes for 2011: http://www.eia.gov/dnav/pet/
pet_cons_prim_dcu_nus_m.htm.
Notes: A prime supplier produces, imports, or transports selected petroleum products across state boundaries
and local marketing areas, and sells the product to local distributors, local retailers, or end users. Products
include motor gasoline, aviation gasoline, kerosene-jet fuel, propane, total distillate and kerosene, and distillate
fuel oil.
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The U.S. Oil Refining Industry: Background in Changing Markets and Fuel Policies
Figure 4. U.S. Refineries by PADD
Source: Prepared for CRS by the Library of Congress Geography and Map Division.
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The U.S. Oil Refining Industry: Background in Changing Markets and Fuel Policies
Table 1. U.S. Refineries by PADD and Advertised Capacity
PADD
ST
1
1
1
1
1
1
1
2
2
2
DE
NJ
NJ
NJ
PA
PA
PA
IL
IL
IL
2
IL
Citgo/ Lemont Refinery
167,000
3
TX
2
2
2
2
2
2
2
2
2
2
2
2
2
2
2
2
IN
IN
KS
KS
KS
KY
KY
MI
MN
MN
ND
OH
OH
OH
OH
OK
413,000
26,500
135,000
115,000
85,000
233,000
5,500
106,000
320,000
74,000
58,000
170,000
160,000
155,000
78,000
187,000
2
OK
2
2
2
2
3
3
3
3
3
3
OK
OK
TN
WI
AL
AL
AR
LA
LA
LA
BP/ Whiting Refinery
CountryMark/ Mount Vernon Refinery
Holly-Frontier/ El Dorado Refinery
CVR Coffeyville Refinery
Cenex-NCRA/ McPherson Refinery
Marathon/ Catlettsburg Refinery
Continental/ Somerset Refinery
Marathon/ Detroit Refinery
Flint Hills/ Pine Bend Refinery
Northern Tier/ St. Paul Park Refinery
Tesoro/ Mandan Refinery
PBF/ Toledo Refinery
BP-Husky/ Toledo Refinery
Husky/ Lima Refinery
Marathon/ Canton Refinery
Phillips 66/ Ponca City Refinery
Holly-Frontier/ Tulsa Refining Complex East
Holly-Frontier/ Tulsa Refining Complex West
Valero/ Ardmore Refinery
CVR/ Wynnewood Refinery
Valero/ Memphis Refinery
Calumet/ Superior Refinery
Shell/ Mobile Refinery
Hunt/ Tuscaloosa Refinery
Delek-Lion/ El Dorado Refinery
ExxonMobil/ Baton Rouge Refinery
Marathon/ Garyville Refinery
Citgo/ Lake Charles Refinery
3
3
3
3
3
3
3
3
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
5
5
5
5
5
TX
TX
TX
TX
TX
TX
TX
TX
CO
MT
MT
MT
MT
UT
UT
UT
UT
UT
WY
WY
WY
WY
WY
AK
AK
AK
AK
CA
CRS-8
Refinery Facility
Advertised
Capacity
(Bbl/Day)
PBF/ Delaware City Refinery
Phillips 66/ Bayway Refinery
PBF/ Paulsboro Refinery
Amerada Hess/ Port Reading Refinery
Carlyle-Sunoco/ Philadelphia Refinery
Delta/Trainer Refinery
United/ Warren Refinery
Phillips 66/ Wood River Refinery
ExxonMobil/ Joilet Refinery
Marathon/ Robinson Refinery
190,000
238,000
180,000
70,000
340,000
185,000
70,000
306,000
250,000
206,000
125,000
90,000
70,000
195,000
34,300
80,000
72,000
80,000
503,500
490,000
425,000
PADD
ST
Refinery Facility
3
3
3
3
3
3
TX
TX
TX
TX
TX
TX
3
TX
3
3
TX
TX
Valero/ Port Arthur Refinery
Lyondell/ Houston Refinery
Phillips 66/ Sweeny Refinery Complex
Valero/ Texas City Refinery
Total/ Port Arthur Refinery
Valero/ McKee Refinery
Citgo/ Corpus Christi Refinery East Plant
Citgo/ Corpus Christi Refinery West Plant
Valero/ Houston Refinery
Flint Hills/ Corpus Christi Refining Complex East
Flint Hills/ Corpus Christi Refining Complex
West
Phillips 66/ Borger Refinery
Western/ El Paso Refinery
Petrobras/ Pasadena Refinery
Valero/ Three Rivers Refinery
Marathon/ Texas City Refinery
Alon/ Big Spring Refinery
Delek/ Tyler Refinery
NuStar/ San Antonio Refinery
Suncor Commerce City Refinery complex
ExxonMobil/ Billings Refinery
Phillips 66/ Billings Refinery
Cenex/ Laurel Refinery
MRC/ Great Falls Refinery
Tesoro/ Salt Lake City Refinery
Chevron/ Salt Lake City Refinery
Big West/ North Salt Lake Refinery
Holly-Frontier/ Woods Cross Refinery
Silver Eagle/ Woods Cross Refinery
Sinclair/ Sinclair Refinery
Holley-Frontier/ Cheyenne Refinery
Sinclair/ Little America Refinery
Black Elk/ Wyoming Refinery
Silver Eagle/ Evanston Refinery
Flint Hills/ North Pole Refinery
Tesoro/ Kenai Refinery
Petro Star/ Valdez Refinery
Petro Star/ North Pole Refinery
Chevron/ El Segundo Refinery
Advertised
Capacity
(Bbl/Day)
310,000
268,000
247,000
245,000
174,000
170,000
165,000
160,000
150,000
150,000
146,000
128,000
100,000
100,000
80,000
70,000
60,000
13,500
98,000
60,000
58,000
55,000
10,000
58,000
45,000
35,000
31,000
10,250
80,000
52,000
24,500
12,500
3,000
220,000
72,000
60,000
22,000
290,000
The U.S. Oil Refining Industry: Background in Changing Markets and Fuel Policies
PADD
ST
Refinery Facility
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
LA
LA
LA
LA
LA
LA
LA
LA
LA
LA
MS
NM
NM
TX
TX
TX
TX
TX
3
TX
Valero/ St. Charles Refinery
Phillips 66/ Alliance Refinery
Phillips 66/ Lake Charles Refinery
Motiva/ Convent Refinery
Motiva/ Norco Refinery
ExxonMobil/ Chalmette Refinery
Valero/ Meraux Refinery
Alon/ Krotz Springs Refinery
Placid/ Port Allen Refinery
Calcasieu/ Lake Charles Refinery
Chevron/ Pascagoula Refinery
Holly-Frontier/ Navajo Refinery
Western/ Four Corners Refinery
Motiva/ Port Arthur Refinery
ExxonMobil/ Baytown Refinery
Marathon/ Texas City Refinery
ExxonMobil/ Beaumont Refinery
Shell/ Deer Park Refinery
Valero/ Bill Greehy Refinery Complex East
Valero/ Bill Greehy Refinery Complex West
Advertised
Capacity
(Bbl/Day)
270,000
247,000
239,000
235,000
234,700
192,500
125,000
83,100
80,000
32,000
330,000
100,000
23,000
600,000
573,000
475,000
365,000
340,000
325,000
Source: CRS analysis of capacity data advertised on owner/operator websites.
CRS-9
PADD
ST
5
5
5
5
5
5
5
5
5
5
CA
CA
CA
CA
CA
CA
CA
CA
CA
CA
5
CA
5
5
5
5
5
5
5
5
5
CA
CA
HI
HI
WA
WA
WA
WA
WA
Refinery Facility
Tesoro/ Carson Refinery
Chevron/ Richmond Refinery
Valero/ Benicia Refinery
Tesoro/ Golden Eagle Refinery
Shell/ Martinez Refinery
ExxonMobil/ Torrance Refinery
Phillips 66/ Los Angeles Refinery
Valero/ Wilmington Refinery
Phillips 66/ San Francisco Refinery/Rodeo
Tesoro Los/ Angeles Refinery
Alon/ California Refineries Paramount
Alon/ California Refineries Longbeach
Alon/ California Refineries Bakersfield
Kern Oil/ Bakersfield Refinery
San Joaquin Refinery
Tesoro Hawaii Refinery
Chevron/ Kapolei Refinery
BP/ Cherry Point Refinery
Shell/ Puget Sound Refinery
Tesoro/ Anacortes Refinery
Phillips 66/ Ferndale Refinery
US Oil Refinery
Advertised
Capacity
(Bbl/Day)
266,000
243,000
170,000
166,000
165,000
150,000
139,000
135,000
120,000
97,000
94,000
26,000
24,300
94,500
54,000
230,000
145,000
120,000
100,000
39,000
The U.S. Oil Refining Industry: Background in Changing Markets and Fuel Policies
Rail freight and the Class I Railroad System of North America are offering an alternative
transport mode that both East Coast and West Coast refiners are turning to for shipping crude
from new resources like North Dakota’s Bakken Formation. While new pipeline projects can face
increasing permitting hurdles and environmental opposition, rail sidings can be quickly
constructed and put into service loading rail tank cars. The advantage that freight rail offers in
flexibility of delivery, however, may be outweighed by the volumetric advantage that pipelines
offer. Although in defense of rail, it has proved viable in shipping ethanol (which now makes up
10% or more of the volumetric consumption of gasoline).6
Refinery Closures and Expansions
U.S. refining has experienced some significant capacity losses and additions in the last two years
(since CRS first published this report). The Hovic 500,000 barrel/day refinery in St. Croix, Virgin
Islands, permanently closed, as did Sunoco’s 175,000 barrel/day Marcus Hook Refinery in
Philadelphia. The previous owners of the Philadelphia Refinery (340,000 barrel/day) and the
Trainer Refinery (185,000 barrel/day) had “idled” their operations, but after a change in
ownership are scheduled to reopen. Motiva (Royal Dutch Shell PLC/Saudi Arabia Refining Co.)
has doubled the size of its Port Arthur, TX, refinery to 600,000 barrels/day, making it the largest
refinery in the United States and one of the largest in the world.7 Phillips 66 has expanded its
Wood River Refinery in Illinois to increase the volume of Canadian heavy crude it can handle.
Crude oil sourcing for U.S. refineries varies over time, but some fundamental changes in supply
have recently occurred. PADD 1 (East Coast) refineries that heavily relied on imported crude oil
are now looking to unconventional crude from North Dakota and Ohio. PADD 2 (Midwest) and
PADD 4 (Rocky Mountains) increasingly depend on crude oil produced and moved by pipeline
from Canada and PADD 3 (Gulf Coast) as well as production from the Rocky Mountain states.
PADD 3, the largest refining region, obtains crude oil from the Gulf Coast outer continental shelf,
Mexico, Venezuela, and the rest of the world. PADD 5 (West Coast) obtains crude oil primarily
from Alaska (by tanker) and California, and through imports.
Most of the country’s gasoline refining occurs in the Gulf Coast (PADD 3), which makes up
nearly 45% of the U.S. refining capacity with 42 refineries processing more than 18 million
barrels per day (bbl/d).8 The Midwest (PADD 2) and the West Coast (PADD 5) follow in capacity.
The East Coast (PADD 1) has been losing capacity, giving way to cheaper gasoline imports.
Refinery Capacity Distribution
A different picture of the refining industry base emerges when examining the distribution of
refinery capacity. As Figure 5 shows, a quarter of U.S. refining capacity is concentrated in 11
refineries with capacities exceeding 300,000 barrels/day. These refineries, the largest and most
complex in the United States (if not the world) reflect the increased profitability through reduced
refining costs that economies of scale bring. All but one refinery have added coking capacity to
convert lower value residuum (formerly used as heavy heating oil) to high-value gasoline.
European refineries, by comparison, are less complex than U.S. refineries in part because of less
6
Although in the case of ethanol, there may be few options other than rail tanker transport because of potential
incompatibility of ethanol with existing pipelines.
7
Texas Gulf Coast Online, Shell Plans Major Expansion of Texas Gulf Coast Refinery,
http://www.texasgulfcoastonline.com/News/tabid/86/ctl/ArticleView/mid/466/articleId/72/Default.aspx.
8
Texas, 4,747,179 bbl/day and Louisiana, 2,992,123 bbl/day.
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The U.S. Oil Refining Industry: Background in Changing Markets and Fuel Policies
coking capacity. The second quartile consists of 16 refineries with capacities between 235,000
and 325,000 barrel/day. (For a further discussion of refinery complexity and processes, refer to
Appendix B.)
Figure 5. U.S. Refining Capacity Distribution
(Quartile Distribution of Refineries by Capacity)
600,000
Barrels/Day
500,000
11 Refineries
400,000
16 Refineries
300,000
25 Refineries
200,000
63 Refineries
100,000
0
Source: CRS analysis of capacity data advertised on owner/operator websites.
Notes: Each quartile represents roughly 4.5 million barrels per day in refining capacity. Each bar represents a
refinery.
Coking Capacity
After many electric power plants and
industrial plants that had burned heavy,
Coking
residual fuel oil switched to cleaner burning
Coking is a severe thermal cracking process that drives
fuels, refiners were left the residuum or the
off lighter volatile fractions of petroleum that are
diverted to a refinery’s gasoline processing stream. The
figurative “bottom of the barrel” to dispose of.
carbon end product—“petcoke”—has economic value as
A combination of factors including gasoline
a substitute for coal-derived coke used in steel-making.
shortages (the effect of 1970s Arab OPEC oil
Variations of the coking process include fluid or flexiembargoes), oil price spikes, increased
coking, delayed coking, and visbreaking.
demand for transportation fuels, and the
declining availability of light sweet crude oils
led refiners to develop “coking” processes to convert high-boiling range residuum to lighter
hydrocarbons for making gasoline. Coking has become an increasingly important capability for
U.S. refining industry because it has enabled refineries to upgrade a wide range of heavy crude
oils to high value fuels. Making better use of the available supply also helped the industry reduce
demand for imports and reduce waste stream generation (an environmental benefit); all gains that
otherwise would qualify as energy-efficiency improvements.
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A coker in various configurations cracks large residuum molecules into smaller molecules by
holding the residuum in a coke drum at a high temperature. The solid carbon that remains
(petcoke) must be drilled out from the coke drum. Pet-coke increasingly substitutes for coke
made from coal for steel-making.
Some 54 refineries have some form of coking capacity, with Gulf Coast refineries (PADD 3)
having nearly half—26 (see Figure 6). The prevalence of coking capacity in PADD 3 reflects the
dependence on imports of heavier crude from the Middle East, Africa, South America, Mexico,
and the Gulf of Mexico.
Figure 6. Refineries with Coking Capacity
(2012)
Source: CRS analysis of capacity data advertised on owner/operator websites.
Notes: Number of refineries by PADD with number of refineries having coking capacity.
Major Refiners
Forty-five firms refine petroleum in the United States. The top 10 refiners—Valero, ExxonMobil,
Phillips 66 (formerly ConocoPhillips), Marathon, BP, Motiva (a Shell Saudi Arabia Refineries
Co. joint venture), Chevron, Tesoro, Citgo, and Shell—account for nearly 75% of total U.S. fuel
refining capacity (Figure 7). These top ten firms operate more than half of the U.S. fuel refining
fleet, a combined 62 out of 115 refineries.
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The U.S. Oil Refining Industry: Background in Changing Markets and Fuel Policies
Figure 7.Top Ten U.S. Refiners (2012)
(Advertised Capacity in Barrels per Day)
Source: CRS analysis of capacity data advertised on owner/operator websites.
Notes: Figures in parenthesis indicate number of refineries owned. The top 10 refiners represent roughly 75%
of the total fuel refining capacity, some 13.2 million barrels per year. Motiva is a joint venture between Royal
Dutch Shell and the Saudi Arabian Refining Co. The Venezuelan oil company Petrovesa owns Citgo.
ExxonMobil, Chevron, Citgo, Shell, and BP engage in all phases of the oil business from
producing and refining their own oil to transporting it and marketing at retail. Valero, the largest
independent refiner and marketer, does not own petroleum reserves. ConocoPhillips, which had
been a fully integrated firm, split its business into upstream (Conoco) and downstream (Phillips
66) business units. Marathon Oil Corporation (an independent upstream company) operates
separately from Marathon Petroleum Corporation (a refiner and marketer). The fully integrated
firms plus the top two independent refiners and marketers Valero and Tesoro also control the
largest refineries.9
Crude Oil Supply
In 2011, the United States consumed 5,327 million barrels of crude oil, importing 3,261 million
barrels and producing 2,065 million barrels. The United States met roughly 39% of its crude oil
demand in 2011 through domestic production (Figure 8). This does not include natural gas
needed in various refining processes, nor natural gas and petroleum condensates that are sold
directly to retail markets (for example, propane and butane). Canada provided roughly 15% of
U.S. demand, followed by Saudi Arabia at 9% (which has directly invested in U.S. refineries to
directly refine its exports), and Mexico at 8%. In total, the United States meets 62% of its demand
from crude oil produced in North America. Canada has become the United States’ leading
imported crude oil supplier through its increasing production from oil sands.10
9
Downstream operations include refining and marketing. Not all petroleum products are marketed by the large oil
companies. Some retail outlets are company owned, some privately owned.
10
CRS Report RL34258, North American Oil Sands: History of Development, Prospects for the Future, by (name
redacted).
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The U.S. Oil Refining Industry: Background in Changing Markets and Fuel Policies
Figure 8. U.S. Crude Oil Supply
(Million Barrels By Source of Supply for 2011)
Source: EIA U.S. Crude Oil Imports, August 30, 2012, http://www.eia.gov/dnav/pet/
pet_move_impcus_a2_nus_epc0_im0_mbbl_a.htm; and U.S. Crude Oil Production, August 30, 2012,
http://www.eia.gov/dnav/pet/pet_crd_crpdn_adc_mbbl_a.htm
Notes: In 2011, the United States consumed 5,327 million barrels of crude oil, importing 3,261 million barrels
and producing 2,065 million barrels.
While crude oil input to U.S. refineries has decreased somewhat compared to a decade ago, input
appears to be on the rise from a low point in 2009 (Table 2). In 2011, refineries consumed an
average 15.3 million barrels per day of crude oil, an increase of 630 thousand barrels/day over
2009. The increase does not necessarily reflect a rise in U.S. demand, as product exports have
been steadily increasing, partly due to ethanol blending into the fuel supply (see “Renewable Fuel
Standard /Alternative Fuels.”)
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The U.S. Oil Refining Industry: Background in Changing Markets and Fuel Policies
Table 2. Gross Input to Refineries
(Thousand Barrels/Day)
Year
Average Daily Inputa
Daily Input
Change
Daily
Product
Exportsb
2001
15,352
951
2002
15,180
-172
975
2003
15,508
+328
1,014
2004
15,783
+275
1,021
2005
15,578
-205
1,133
2006
15,602
+24
1,292
2007
15,450
-152
1,405
2008
15,027
-423
1,773
2009
14,659
-368
1,980
2010
15,177
+518
2,311
2011
15,289
+112
2,939
Sources:
a. EIA Petroleum Navigator, Petroleum Supply Annual; Refinery Utilization and Capacity, http://www.eia.gov/
dnav/pet/pet_pnp_unc_dcu_nus_a.htm.
b. EIA Petroleum Navigator, U.S. Exports by Destination, http://www.eia.gov/dnav/pet/
pet_move_expc_a_EPP0_EEX_mbblpd_a.htm.
Crude oil imports by the United States have declined since the middle of the last decade, while
U.S. crude oil production has been increasing. Volumetrically, U.S. crude oil production in 2011
essentially matched the 2003 level of approximately 2.06 billion barrels per day (Figure 9).
However, the production reflected the new unconventional resources (such as the North Dakota
Bakken and Texas Woodford shales) coming online to make up for a decline in production from
the Outer Continental Shelf/Gulf of Mexico. While net imports have been declining, Canadian
imports have been on a steady rise. The improved trend in U.S. crude production compared to
imports in the last several years is more apparent in Figure 10. In 2011, imports had declined to
roughly 60% of demand.
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Changing Crude Oil
Grades
Bitumen-derived crudes11 from the
Athabasca oil sands of Alberta, Canada,
represent an increasingly important
feedstock for U.S. refineries. The
Enbridge North Dakota pipeline system
already pumps Canadian crude oil to
PADD 2 refineries, and the proposed
Keystone XL pipeline will transport
“diluted bitumen (Dilbit)” to PADD 3
(U.S. Production vs. Imports)
6,000
5,000
Million Barrels
Each refinery depends upon a certain
grade or blend of crude oils to operate
efficiently, depending upon its customdesigned processing equipment. A light
crude oil might not be interchanged for
heavy crude oil, and without coking
capacity a refinery designed to process
light sweet crude could not refined
heavy sour crude. Some refineries—for
example the Citgo refinery (a
subsidiary of the Venezuelan National
Oil Company)—rely on a very heavy
range of crude oil produced in
Venezuela, whereas Motiva refineries
rely on Saudi Arabian crude oils. Over
the last 25 years, the ºAPI gravity of
imported crude oils has been
decreasing while average sulfur content
has been increasing. Until quite
recently, the diminishing supply of light
sweet crude oil led U.S. refineries to
make multi-million dollar investments
in processing-upgrades to convert
lower-priced heavier sour crude oils to
high-value products such as gasoline,
diesel, and jet fuel. Newly available
light sweet crudes from the North
Dakota’s Bakken formation are
changing refining dynamics in some
regions of the United States.
Figure 9. Crude Oil Supply Volume
U.S. Crude Oil
Production
4,000
3,000
2,000
U.S.Crude Oil
Imports
1,000
0
Source: EIA, Crude Oil Production, http://www.eia.gov/
dnav/ pet/pet_crd_crpdn_adc_mbbl_a.htm; and U.S. Crude
Oil Imports: http://www.eia.gov/dnav/pet/
pet_move_impcus_ a2_nus_epc0_im0_mbbl_a.htm.
Notes: Excludes natural gas liquids.
Figure 10. Crude Oil Supply Trend
(U.S. Production vs. Imports)
100%
80%
U.S. Crude Oil
Production
60%
40%
U.S.Crude Oil
Imports
20%
0%
Source: EIA, Crude Oil Production: http://www.eia.gov/
dnav/ pet/pet_crd_crpdn_adc_mbbl_a.htm, and U.S. Crude
Oil Imports: http://www.eia.gov/dnav/pet/
pet_move_impcus_ a2_nus_epc0_im0_mbbl_a.htm.
Notes: Excludes natural gas liquids.
11
Gary R. Brierley, Visnja A. Gembicki and Tim M. Cowan, Changing Refinery Configuration for Heavy and
Synthetic Crude Processing, UOP LLC Des Plaines, Illinois, USA, 2006.
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The U.S. Oil Refining Industry: Background in Changing Markets and Fuel Policies
refineries.12 Pumping bitumen-derived crudes by pipeline requires dilution with conventional
crude oil and gas condensate (a by-product of natural gas production).13 Dilbit is comparable to
other types of heavy crude oils produced in northern California, Nigeria, Russia, Mexico, and
Venezuela and currently transported and refined in the United States. If the Keystone-XL Gulf
Coast Expansion project is complete, in addition to Canadian crude oil, Keystone will also be
able to transport crude oil from U.S. producers in Texas, Oklahoma, Montana, and North Dakota.
Crude Oil Prices
The longstanding benchmark for pricing crude oil futures contracts traded on the New York
Mercantile Exchange (NYMEX) is West Texas Intermediate (WTI) crude oil; a high-quality crude
oil with a 39.6° API gravity (making it a “light” crude oil) and a 0.24% sulfur content (making it
a “sweet” crude oil). North Sea Brent crude oil, a 38°-39° API gravity light sweet crude oil but
with higher sulfur content than WTI, is a global benchmark for other crude oil grades and is
widely used to determine crude oil prices in Europe and in other parts of the world.14 Although
Brent is typically refined in Northwest Europe, it is also exported to the U.S. Gulf and East
Coasts.
Historically, the price of WTI has been about $1-$2 per barrel above North Sea Brent crude, and
$2-$4 per barrel above the Organization of the Petroleum Exporting Countries (OPEC) “basket”
of crude prices.15 Recently, however, Brent crude has brought a premium of over $10 per barrel
against WTI.16
OPEC collects price data on a basket of crude oils it produces, and uses the average prices for
these oil streams to develop an OPEC reference price for monitoring world oil markets.17 OPEC’s
reference basket consists of eleven crude streams representing the main export crudes of all its
member countries, weighted according to production and exports to the main markets.18
According to OPEC, the basket crude has a 32.7 ºAPI gravity, making it heavier than WTI or
Brent, and a 1.77% sulfur content, making it sourer. Both of these characteristics tend to make it
less valuable than WTI or Brent crude. With the diminishing availability of sweet crudes
worldwide, U.S. refiners have increasingly turned to heavier sour crudes, and many refineries
have upgraded to refine these crudes.
At the beginning of the U.S. invasion of Iraq in March 2003, the spot price for a barrel of WTI
crude oil was $28.11, and prices generally rose during the course of the Iraq War. On a monthly
basis, the spot market price of WTI peaked at $133.88 per barrel in June 2008.19 By February
2009, the price had declined to $39.09 per barrel, only to rise to around $75 per barrel by the end
of 2009. In 2012, the average spot price of WTI has been over $96 per barrel.
12
See CRS Report R41668, Keystone XL Pipeline Project: Key Issues, by (name redacted) et al.
TransCanada, http://www.transcanada.com/5747.html.
14
Commodity Online, http://www.commodityonline.com/commodities/energy/brentcrudeoil.php.
15
On a daily basis the pricing relationships between these can vary greatly.
16
For a detailed discussion of oil markets, see CRS Report R42024, Oil Price Fluctuations, by (name redacted) and
(name redacted).
17
PetroStrategies, http://www.petrostrategies.org/Graphs/OPEC_Basket_Crude_Oil_Prices.htm.
18
The OPEC basket crude oil streams in the basket are: Saharan Blend (Algeria), Minas (Indonesia), Iran Heavy
(Islamic Republic of Iran), Basra Light (Iraq), Kuwait Export (Kuwait), Es Sider (Libya), Bonny Light (Nigeria), Qatar
Marine (Qatar), Arab Light (Saudi Arabia), Murban (UAE) and BCF 17 (Venezuela).
19
On a yearly basis, the average price per barrel of WTI rose every year from 2003 through 2008. The daily peak was
attained in July 2008, at over $145 per barrel. See WTI Spot Price data at http://www.eia.gov.
13
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The U.S. Oil Refining Industry: Background in Changing Markets and Fuel Policies
Recently, crude produced from North Dakota’s Bakken Formation (a light sweet crude
comparable to WTI) has sold in the Midwest at large discounts because of limited pipeline
takeaway capacity. Thus, producers have begun shipping Bakken crude to both East and West
Coast refineries by rail car. A few PADD 1 refineries that had been idled are able to restart given
the newly available lower-cost Bakken.
Beside the political uncertainty introduced by the Iraq War, economists have suggested other
reasons for the observed price volatility in crude oil markets, including political tensions in Africa
and other regions, financial speculation, currency hedging, inflation hedging, excess demand,
supply tightness, and a host of other factors. Widely publicized and debated concerns regarding
global “peak oil” production may have contributed to speculation in the oil futures market.20
Because the U.S. dollar serves as the reference price currency for oil in the world market, some
oil analysts link the peak in oil prices in mid-2008 to the dollar’s weakness at the time. As a
result, the oil price rise was much less pronounced when measured in other major currencies.21
Although crude oil represents the primary input and cost factor in refinery operations, the
relationship between the price of crude oil and the profit margin in refining is neither simple nor
direct.22 Rising crude oil prices increase primary refining costs and can tighten refining profit
margins. However, if product prices rise proportionally to crude oil prices, as they did in 2008,
refiners effectively pass cost increases on to consumers. Because of the short-term price
insensitivity of demand when gasoline prices rise, the revenue derived from the sale of gasoline
and other petroleum products is likely to increase in these market conditions, even as total costs
are likely to decrease because the volume of oil passing through the refinery declines somewhat.
These factors can permit refiners to maintain or even increase profits during periods of high crude
oil prices. The situation differs if less oil is passing through the refinery due to weak product
demand. In that event, product prices and profits may fall in tandem as capacity utilization
declines.
20
For background on the subject of peak oil see Kenneth S. Deffeyes, Beyond Oil: The View from Hubbert’s Peak
(Farrar, Straus and Giroux, 2005).
21
Steve Hawkes, “Oil nears $100 mark as crude reaches yet another record,” Times Online, October 30, 2007,
http://business.timesonline.co.uk/tol/business/industry_sectors/natural_resources/article2767141.ece.
22
Crude oil generally represents over 50% of the cost of gasoline, the most important refinery product in the United
States.
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The U.S. Oil Refining Industry: Background in Changing Markets and Fuel Policies
The multiplicity of oil prices, which reflect the
quality of various crude oils, further
complicates the linkage between oil prices and
refining profitability. Generally, lighter crude
oils command a price premium over heavier
oils, as discussed earlier in this report. The
size of the price premium tends to vary as
relative supply availability changes and as
refiners adapt refineries to use lower cost
crude oil stocks. The price spread between
light and heavy crude oils, shown in Table 3,
shrank by almost $10 per barrel between 2006
and 2009. After some recovery in 2010, the
price premium became negative in May 2011
with Mexican Maya (a heavy crude)
commanding a higher price than WTI. During
the first eight months of 2012, the price spread
remained inverted with Maya priced over
$5.71 higher, on average, than WTI.
Table 3. Light/Heavy Crude Oil
Price Spread
($/Bbl)
Year
Spread
2006
2007
2008
2009
2010
2011
$15.51
$12.88
$14.85
$5.60
$9.12
-$3.64
Source: EIA.
Notes: CRS based calculations on North American
crude oils, West Texas Intermediate, and Mexican
Maya crude.
During the period of high oil prices from 2004 through 2008, heavy crude oils sold at a large
discount relative to light crude. The relative tightness in the light crude market, coupled with the
price discounts for heavy crude, induced refiners to invest in facilities and processes that would
make refineries more able to process heavy crude oils and take advantage of these favorable price
spreads. These investments declined in profitability after oil prices fell and the price premium
narrowed and inverted in 2011.
Gasoline Demand
The demand for crude oil is derived from the demand for petroleum products. For example, if
consumers demand more gasoline, refiners generally purchase and process more crude oil.
Afterwards, refiners might adjust their product slate, within technological limits, to yield more
gasoline from each barrel of crude oil.
The demand for gasoline depends upon the price of gasoline and the income level of consumers.
However, in the short run, the responsiveness of gasoline demand to variations in price is quite
low. Estimates of the short-run price elasticity of gasoline are in the range of -0.25 or less.23 This
value implies that if the price of gasoline rises by 1.0% the result is likely to be only a ¼ %
decline in the quantity of gasoline demanded. Consumers may have difficulty reducing their
demand for gasoline in the short-run, as commuting distance, automobile fuel-efficiency, and
other commitments are fixed in the near term, making it hard to lower consumption quickly. They
may respond to higher gasoline prices by reducing expenditures on other goods or increasing
household debt levels. The demand for gasoline also depends on consumer’s income growth, and
perhaps, as well, on the fraction of consumer’s disposable income accounted for by gasoline
purchases. The average estimate of income elasticity for gasoline demand in the United States is
23
Price elasticity of demand is calculated as the percent change in quantity demanded divided by a specified percentage
change in price. The result is a pure number (not measured in any units) that expresses the responsiveness of quantity
demanded to changes in the price of the product. A formula to determine price elasticity is e= (percentage change in
quantity) / (percentage change in price).
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The U.S. Oil Refining Industry: Background in Changing Markets and Fuel Policies
about 1.0, meaning that a 1% increase in income is associated with a 1% increase in spending on
gasoline. Taken together, these elasticity values imply that gasoline demand may increase, even in
an environment of high or rising prices, as long as the effect of higher incomes outweighs the
effect of higher prices.
This condition appears to have been in place in the United States, and much of the world, during
the first half of 2008, as well as much of the 2003-2008 period in general. However, after the
third quarter of 2008 when U.S. gasoline prices had peaked at over $4.00 per gallon, the
economic recession, coupled with expectations of reduced income growth, began moderating the
demand for gasoline. After a 0.35% growth in gasoline demand in 2007, demand declined 2.9%
in 2008 and continued to fall through 2011, as Table 4 shows.
Table 4. United States Gasoline Consumption 2006-2009
(Million Barrels/Year)
Year
Consumption
Volume
Change
%
Change
2006
2007
2008
2009
2010
2011
3,377.2
3,389.3
3,290.1
3,280.0
3,283.2
3,194.7
12.1
-99.0
-10.1
-0.5
-88.5
0.35
-2.90
-0.30
-0.01
-2.60
Source: Energy Information Administration.
Notes: Gasoline consumption is a measure of product supplied as finished motor gasoline. It includes refinery
and blender net production, and imports.
The nearly 6% reduction in gasoline demand, as experienced as the result of the 2007-2008
recession and high prices, may seem minor compared to recessionary demand reductions in other
industries. Nonetheless, it was sufficient to create the current weak market conditions
(characterized by reduced capacity utilization rates, refinery closures, and weak profitability) that
the refining industry has faced over the past two years.
In the longer term, even with more rapid growth in income, the outlook for the gasoline demand
in the United States will be constrained by changing attitudes toward petroleum usage,
regulations to increase automobile fuel efficiency standards, and regulations mandating the
expanded use of alternative fuels in motor transportation.
Refining Profitability24
Over the period of 2006 through 2001, leading refiners’ net income (profit) generally declined.
This may be attributable to several factors including the combination of high crude oil prices and
weak demand. The comparative financial performance of the leading firms’ downstream business
for the 2006 through 2011 period is presented in Table 5. High inventories of gasoline and diesel
fuel depressed product prices relative to the cost of crude oil, which further reduced refining
profit margins.25 In addition, the narrowing price spread between light and heavy crude reduced
24
For a more detailed discussion of oil company profits, see CRS Report R42364, Financial Performance of the Major
Oil Companies, 2007-2011, by (name redacted).
25
Refining margins are the difference between the value of refined products derived from a barrel of crude oil and the
cost of refining that barrel. The gross margin subtracts only the cost of crude oil, while the net margin includes all other
operational costs as well as crude oil.
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the refining margin and contributed to earlier capital investments failing to generate expected
returns.
Table 5. Refiners’ Net Income, 2006-2011
($ Million)
Company
Valero
ExxonMobil
ConocoPhillips
Marathon
BP
Shell
Chevron
Tesoro
2006
5,461
8,454
4,481
2,795
5,667
6,989
3,973
801
2007
5,234
9,573
5,923
2,077
3,569
6,624
3,502
566
2008
-1,131
8,151
2,322
1,179
4,176
446
3,429
278
2009
-1,982
1,781
37
464
4,517
3,054
565
-140
2010
324
3,567
192
682
7,239
3,873
2,478
-29
2011
2,090
4,459
3,751
549
5,474
4,274
3,591
546
Source: Oil Daily, Profit Profile Supplements, various issues, 2007-2011.
Notes: Data in the table are downstream net income, which include income derived from refining and
marketing. Venezuelan owned Citgo does not publish financial reports. ConocoPhillips split into Conoco and
Phillips 66 after 2011. Shell and the Saudi Arabian Refineries Co, are in the Motiva joint venture.
All the major integrated oil companies have experienced mixed returns in the last few years.
Valero, an independent refiner and marketer and owner of the most U.S. refineries, experienced a
substantial gain in 2011.
Refining Capital Investment
Refiners undertake capital investment for a
variety of reasons, for example, expanding
existing or creating new production
facilities, implementing new or enhanced
technology, regulatory compliance, and
adapting refineries to available crude oil
streams. Facility expansion and new
technology implementation are indicators
that the industry expects increasing demand
and economic growth.
Table 6. U.S. Refining Industry Capital
Budget Expenditures, 2008-2010
Year
$ Billion
2005
7.2
2006
9.0
2007
8.3
2008
13.0
2009
10.1
Capital improvement and expansion require
2010
5.3
that an initial outlay of funds in the current
2011
9.2
time-period be offset by earnings that might
accrue far into the future. If this stream of
Source: Oil and Gas Journal, March 7, 2011, p. 26.
appropriately discounted future earning is
greater than the initial outlay, then a capital
investment project qualifies for inclusion in the capital budget.26 Because the estimated earnings
stream embodies management’s forecast of the industry’s future economic potential, increasing
capital budgets imply expectations of healthy profitability, while declining budgets imply a weak
profit outlook.
26
This method, which is widely employed by economists and financial analysts, is referred to as Net Present Value. An
alternative measure is calculation of the internal rate of return to a hurdle rate, usually the company cost of capital.
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Capital spending in the U.S. refining sector has been mixed, as Table 7 shows. A 22% decline
from 2008 through 2009 was followed by an almost 50% decline from 2009-2010. This trend,
coupled with recent refinery closures, suggests that the industry does not see a need to expand,
though several refineries have increased capacity in the United States.
Refinery Investment and Petroleum Product Imports
While imports of crude oil have been an important part of the U.S. energy supply picture for
decades, the importance of petroleum product imports also rose before the recession and
expansion of U.S. crude oil production. Oil companies can meet increasing/decreasing demand
for petroleum products, such as gasoline, in three basic ways. They can build or close refineries,
using either domestic or imported crude oil. This strategy puts refinery investment in competition
with the companies’ other capital projects, but offers the possibility of relatively large increases in
supply.
Second, an oil company can expand or reduce the capacity or capacity utilization-rate of existing
refineries. Investment in expanded capacity can run parallel to investments made to keep existing
refinery assets in compliance with environmental and other regulations affecting the industry.
Expansions or contractions in capacity utilization can usually be brought on line faster than new
refineries due to simplified permitting requirements, but have the disadvantage of augmenting or
reducing capacity in smaller steps.
Third, instead of investing in new refineries or expanding existing ones, an oil company might
choose to meet changes in petroleum product demand by varying net imports of finished, or
partially finished, products from other areas of the world. The advantage of this approach is
twofold. The net imports can be introduced or reduced, relatively quickly, into the domestic
market with no requirement for additional capital spending on refining capacity.27 The imports
can be easily expanded, or contracted, should the need arise. Reliance on foreign sources for
petroleum products as well as crude oil may add an additional dimension to concerns of energy
dependence, even though prices of these products may tend to be the same in domestic and
foreign markets.
Cost is likely to determine an oil company’s decision on which alternative to use to meet demand
variations. If products available on the world market can meet mandated domestic specifications
and are available at competitive prices, importing them gives an oil company flexibility while
avoiding the long-term commitment of expanding existing, or constructing new capacity.
A look at U.S. total motor gasoline imports over the 2004-2011 period shows that they averaged
about 11% of the roughly 9 million barrels per day finished motor gasoline products supplied to
U.S. consumers (see Table 7). Total petroleum products imports made up about 17% of domestic
consumption. The effects of the recession can be seen in the reduced level of imports in 2008
through 2011. Adjustments in imports to reflect reduced demand are likely to be accomplished
with fewer losses in domestic employment and economic dislocations than refinery closures. The
recent trend in net imports reflects the export of petroleum products by U.S. refineries. Exports
have helped maintain capacity utilization rates and have allowed for efficient use of rising U.S.
crude oil production.
27
Other investments (e.g., in import facilities or pipeline capacity) may be necessary.
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Table 7. Gasoline Imports Vs. Total Gasoline Supplied
(Thousand Barrels per Day)
Product
2004
2005
2006
2007
2008
2009
2010
2011
496
603
475
413
302
223
134
105
Finished Motor Gasoline Imports
Motor Gasoline Blending Component
Imports
Total Gasoline Imports Subtotal
451
510
669
753
789
719
741
718
947
1,113
1,126
1,166
1,091
942
875
823
Total Finished Motor Gasoline Supplied
Total Petroleum Product Imports
9,105
3,057
9,159
3,588
9,253
3,589
9,286
3,437
8,989
3,132
8,997
2,678
8,993
2,580
8,753
2,568
Total Petroleum Product Exports (-)
Net Imports
913
2,144
1,101
2,578
1,144
2,445
1,247
2,190
1,608
1,524
1,777
901
2,025
555
2,503
65
Source: U.S. Energy Information Administration, U.S. Imports by Country of Origin, http://www.eia.gov/dnav/
pet/pet_move_impcus_d_nus_Z00_mbbl_a.htm; and Refiner Motor Gasoline Sales Volumes http://www.eia.gov/
dnav/pet/pet_cons_refmg_d_nus_VTR_mgalpd_a.htm, Product Supplied http://www.eia.gov/dnav/pet/
pet_cons_psup_dc_nus_mbblpd_a.htm.
Notes: Other products include fuel oils, pentanes, LPG, unfinished oils, oxygenates, fuel ethanol, kerosene,
naphtha, waxes, and lubricants.
Refinery Tax Considerations
Provisions adopted in the Energy Policy Act of 2005 (EPAct05; P.L. 109-58) allowed taxpayers to
expense 50% of qualified investments in refinery assets.28 Congress adopted this provision to
address concerns that domestic refineries would not have the capacity to meet anticipated growth
in domestic fuel demand; a condition that has since reversed. The potential for fuel price spikes
also rises when domestic refineries operate at near capacity, as there may be insufficient spare
capacity to make up for a refinery outage.
The provisions allowing taxpayers to partially expense investments in refinery assets was initially
enacted on a temporary basis.29 Specifically, taxpayers making qualified investments in domestic
refinery property used to refine liquid fuel from crude oil (or other qualified fuels) were eligible
for the tax deduction if a binding contract for construction of the qualified property had been
entered into by January 1, 2008.30 Further, under EPAct05, it was required that qualifying
property be placed in service prior to January 1, 2012. The Emergency Economic Stabilization
Act of 2008 (EESA; P.L. 110-343) extended the under-contract and placed-in-service deadlines,
such that the incentive is now available for refineries that entered into a binding construction
contract before January 1, 2010, and will be placed in service by January 1, 2014.
Allowing taxpayers to expense part of their investment in refinery property reduces the cost of
construction, encouraging additional refinery investment. Allowing 50% of refinery investments
28
Internal Revenue Code (IRC) §179C. Under the Modified Accelerated Cost Recovery System (MACRS), petroleum
refining assets are depreciated over a 10-year period using a double declining balance method.
29
For additional background information on energy tax issues, see CRS Report R40999, Energy Tax Policy: Issues in
the 111th Congress, by (name redacted) and (name redacted) and CRS Report R41227,
Energy Tax Policy:
Historical Perspectives on and Current Status of Energy Tax Expenditures, by (name redacted).
30
Existing refineries may qualify if the installation of new property increases the refinery’s capacity by at least 5% or
increases the percentage of total throughput attributable to qualified fuels such that it equals or exceeds 25%. All
qualifying property must be in compliance with applicable environmental laws on the placed-in-service date.
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to be expensed, rather than depreciated over
the normal 10-year life, reduces the cost of
construction by approximately 5% for
taxpayers in the 35% tax bracket.31 Since the
provision is
Table 8. Tax Expenditures for Provisions
Allowing Partial Expensing of Refinery
Investments
($ Billion)
temporary, there is an incentive to speed up
Year Revenue Loss
the investment in refinery capacity so as to
qualify for the tax incentive. Nevertheless, the
2008
0.4
2009
0.5
incentive to speed up investment is limited,
2010
0.7
because the effective price discount is small.
2011
0.8
Investing in excess capacity that would not
2012
0.7
otherwise be desirable would either leave the
2013
0.6
plant idle or provide too much output and
Source: Joint Committee on Taxation.
lower prices and profits for a period of time.
Notes: Tax expenditures are estimate federal
The latter cost should be at least as big as the
revenue losses associated with special tax
cost of remaining idle. With a 5% price
provisions.
discount, the interest cost of carrying excess
capacity or losing profits could offset the tax
credit’s value. The estimated reduction in federal receipts associated with provisions allowing
taxpayers to expense 50% of qualified investments in refinery assets is presented in Table 8. Over
the five-year 2009 through 2013 budget window, estimates suggest this provision will cost $3.4
billion.32
Energy and Environmental Policy Considerations
The conventional gasoline refined today has changed considerably since the Clean Air Act
Amendments of 1990 prohibited lead additives and established requirements for oxygenated
gasoline and reformulated gasoline (RFG). Each of the three formulations of gasoline
(conventional, oxygenated and reformulated) is available in at least three grades (87, 89-mid
grade, and 91+ super) and the volatility is adjusted for winter/summer and northern/southern
driving conditions. (For information on other properties such as Reid Vapor Pressure, octane, and
cetane refer to Appendix D.)
Reformulated Gasoline (RFG) and State “Boutique Fuels”
The Clean Air Act, as amended in 1990, directed the Environmental Protection Agency (EPA) to
designate areas not complying with national ambient air quality standards (NAAQS) as ozone
“nonattainment areas.”33 Cities with the worst smog pollution are required to reduce harmful
31
The present value of a 10-year, double declining balance depreciation per dollar of investment is $0.74 with an 8%
nominal discount rate. For every dollar expensed, the benefit of expensing is to increase the present value of deductions
by $0.26, and since half of the investment is expensed, the value is $0.13. Multiplying this value by 35% leads to a
4.6% benefit as a share of investment. The value would be larger with a higher discount rate. For example, at a 10%
discount rate, the benefit would be 5.4%. The benefit is smaller for firms facing lower tax rates or those with limited
tax liability.
32
U.S. Congress, Joint Committee on Taxation, Estimates of Federal Tax Expenditures for Fiscal Years 2009-2013,
committee print, 111th Cong., 2nd sess., January 11, 2010, JCS-1-10.
33
Section 181 of the act required EPA to classify each area as a marginal, moderate, serious, severe or extreme ozone
nonattainment area. EPA classified all areas that were designated as in nonattainment for ozone at the time of the
(continued...)
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emissions that cause ground-level ozone by using reformulated gasoline (known as RFG), which
is blended to burn cleaner by reducing smog-forming and toxic pollutants during the summer
ozone season. Reformulated gasoline undergoes additional processing to remove volatile
components that contribute most to air pollution, and to make it less prone to evaporation.34 (See
Figure 11.) In addition to RFG, states with less severe ozone problems may opt into the RFG
program or may establish their own fuel standards to address emissions in those areas. These state
fuels—often referred to as “boutique fuels”—generally have tighter summer volatility standards
than conventional gasoline but not as stringent as federal RFG. Further, the state of California
requires its own blend of gasoline across the state.35 In addition to federal and California RFG,
five distinctly formulated summer blends are required in portions of 12 states.36
In analyzing the proliferation of gasoline types, EIA concluded in 2002 that: “... the general
impact of an increasing number of distinct gasoline fuels with smaller demands and, in some
cases, served by fewer suppliers has been to reduce the flexibility of the supply and distribution
system to respond to unexpected supply/demand shifts.”37 The prospect that more refineries may
sit idle or permanently close due to decreased demand could further reduce that flexibility.
Figure 11. Map of Reformulated Gasoline Areas
Source: EPA.
(...continued)
enactment of the 1990 Amendments, except for certain “nonclassifiable” areas (56 FR 56694,(1) November 6, 1991).
34
Reid Vapor Pressure (RVP) is a measure of a fuel’s propensity to evaporate. Fuels with higher RVP emit more
volatile compounds into the atmosphere, contributing to greater smog formation. See Appendix D for a discussion of
RVP and other fuel properties.
35
In the Los Angeles area, the federal and California standards overlap.
36
Other state standards (which may or may not be related to emissions controls) also overlap with the RFG and
boutique fuels standards in some areas. Depending on how these areas are counted, some in the industry argue that
there are 15 distinct blends of gasoline including federal conventional and RFG fuels and various state fuels, although
in many cases the fuels produced for these areas are identical.
37
Energy Information Administration, Analysis of Selected Transportation Fuel Issues Associated with Proposed
Energy Legislation - Summary, September 2002, http://www.eia.doe.gov/oiaf/servicerpt/fuel/gasoline.html.
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To reduce the proliferation of boutique fuels, the 2005 Energy Policy Act38 amended the Clean
Air Act (in 42 U.S.C. 7545) by limiting them to the number existing as of September 1, 2004.39
Between 1992 and 2005, the Clean Air Act RFG standards included a requirement that the fuel
contain oxygen as part of an overall strategy to reduce ground-level ozone and smog. Much of the
gasoline sold in the United States during that period was blended with up to 10% methyl tertiarybutyl ether (MTBE) as the oxygenate in almost all RFG outside of the Midwest, while ethanol
was used in the Midwest. Both MTBE and ethanol served several functions: as an oxygenate in
RFG, as an octane booster, and as a volume extender in conventional gasoline.40 Groundwater
contamination concerns and the State of California’s ban on MTBE as a gasoline additive left
ethanol as the most popular fuel oxygenate. MTBE was produced and added at the refinery.
However, ethanol’s corrosive nature makes long-distance shipment of ethanol mixed into gasoline
impractical. In consequence, ethanol (produced mostly from corn fermentation in the United
States) is blended with gasoline at the storage terminal where the fuel is dispensed to the fuel tank
truck. The shift from MTBE to ethanol thus contributed to a reduction in refinery production.
Renewable Fuel Standard /Alternative Fuels
During an era of increasing crude oil prices and concerns for declining domestic crude oil
production, many policy makers advocated energy self-sufficiency. Renewable fuels offered the
promise of reducing—or at least offsetting an increase in—demand for transportation fuel.
Recently motor-fuel demand has declined due both to economic factors and increased use of
ethanol and other biofuels. These factors combined may influence operators to idle, consolidate,
or permanently close refineries.
Congress created the Renewable Fuel Standard (RFS under Title XV of the Energy Policy Act of
2005 (EPAct; P.L. 109-58) to substitute increasing volumes of renewable fuel for gasoline.41 EPA
has the statutory authority to administer the RFS. The act set a target consumption volume of 7.5
billion gallons of renewable fuels for calendar year 2012. The 2007 Energy Independence and
Security Act (EISA; P.L. 110-140) expanded the program to cover transportation fuels in general,
extended the program to calendar year 2022, and increased the target volume to 36 billion gallons
renewable fuel annually (857 million barrels annually or 2.3 Million bbl/d) (see Table 9 below).
38
Subtitle C—Boutique Fuels Sec. 1541. Reducing the Proliferation of Boutique Fuels.
EPA maintains that list at http://www.epa.gov/oms/fuels/boutiquefuels/boutiquelist.htm.
40
Environmental Protection Agency, Status and Impact of State MTBE Bans, http://www.eia.doe.gov/oiaf/servicerpt/
mtbeban/pdf/mtbe.pdf.
41
For more information on the Renewable Fuel Standard, see CRS Report R40155, Renewable Fuel Standard (RFS):
Overview and Issues, by (name redacted) and (name redacted).
39
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Table 9. EISA Renewable Fuel Volume Requirement
(Billion Gallons)
Year
Cellulosic
Biofuel
Requirement
Biomassbased Diesel
Requirement
Advanced
Biofuel
Requirement
2008
n/a
n/a
n/a
2009
n/a
Total
Renewable
Fuel
Requirement
Total
Renewable
Fuel
Requirement
9.00
214
0.50
0.60
11.10
264
2010
0.0065a
0.65
0.95
12.95
308
2011
0.0066
0.80
1.35
13.95
332
2012
0.00865
1.00
2.00
15.20
362
2013
1.00
b
2.75
16.55
394
2014
1.75
b
3.75
18.15
432
2015
3.00
b
5.50
20.50
488
2016
4.25
b
7.25
22.25
530
2017
5.50
b
9.00
24.00
571
2018
7.00
b
11.00
26.00
619
2019
8.50
b
13.00
28.00
667
2020
10.50
b
15.00
30.00
714
2021
13.50
b
18.00
33.00
786
2022
16.00
b
21.00
36.00
857
2023+
c
c
c
c
Source: EPA Renewable Fuel Standard http://www.epa.gov/otaq/fuels/renewablefuels/.
Notes: 1 barrel = 42 gallons.
a. The initial EISA cellulosic biofuels mandate for 2010 was 100 million gallons. EPA revised this mandate
downward to 6.5 million ethanol-equivalent gallons. For 2011 and 2012, the mandates were scheduled at
250 million and 500 million gallons, respectively, but were revised down to 6.6 million and 8.65 million
gallons, respectively.
b. To be determined by EPA through a future rulemaking, but not less than 1.0 billion gallons.
c. To be determined by EPA through a future rulemaking.
The 2012 requirement of 15.2 billion gallons of renewable fuels represents roughly 10% of 2012
gasoline and diesel fuel consumption by volume.
As the mandated level of biofuels under the RFS increases, fuel suppliers are rapidly facing a
“blend wall” limiting the amount of ethanol they can use in gasoline.42 Under earlier EPA rules,
the maximum ethanol content in gasoline was 10% by volume (E10) for use in conventional
vehicles. For flexible fuel vehicles (FFVs), ethanol concentration is capped at 85%. In response to
a waiver petition by Growth Energy, EPA granted a partial waiver from the 10% limit, allowing
the use of 15% ethanol (E15) in some vehicles. The partial waiver allows the sale of E15 for use
in 2001 and newer model year passenger cars and light trucks. EPA denied the waiver to use E15
in vehicles older than model year 2000, and in all heavy-duty, motorcycle, and non-road engines.
However, EPA’s approval of the use of E15 only addresses one facet of the blend wall issue.
Retail pumps, storage tanks, and other infrastructure may not be compatible with ethanol blends
42
For a more detailed discussion of these issues, see CRS Report R40445, Intermediate-Level Blends of Ethanol in
Gasoline, and the Ethanol “Blend Wall”, by (name redacted).
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above E15. Further, while EPA allows the use of E15 in newer model year vehicles, no automaker
has yet updated their warranties to allow the use of E15. Further, state and local codes and
standards may prohibit the storage, use and/or sale of blends above 10%. If fuel suppliers are
unable or unwilling to sell E15, they will need to find some other way to address the blend wall.43
EPA is finalizing RFS regulations for 2011 with specific annual volumes for cellulosic biofuel,
biomass-based diesel, advanced biofuel, and total renewable fuel requirements. Although current
ethanol production capacity is more than adequate to meet current blending goals, increased
biofuel production faces a number of economic, land use, and policy barriers. The feasibility of
expanding current ethanol production by another 1 million bbl/d is linked to the ethanol industry’s
ability to expand under escalating feedstock prices and economic conditions that discourage
capital investment. Congress is also looking toward cellulosic ethanol to meet much of the RFS
requirements. However, cellulosic ethanol production has technological barriers to overcome
before commercial-scale plants can begin operating.
Carbon Emissions/Greenhouse Gas Rules
Emissions standards for carbon dioxide and other greenhouse gases could dramatically affect the
refining industry. Although it is unclear when, or if, federal regulations will affect petroleum
refiners, programs in states—especially California—could have a dramatic effect on refining in
the future. Similarly, if a federal carbon tax were enacted it would directly affect the price of
gasoline and other petroleum products.
On December 15, 2009, EPA finalized rules finding that greenhouse gases endanger public health
and welfare, and that emissions from automobiles cause or contribute to that endangerment.44 The
rules follow from a 2007 Supreme Court decision in Massachusetts v. EPA that EPA must make a
determination under the Clean Air Act one way or the other on the question of greenhouse gas
emissions and their effects. The most direct result of that decision was subsequent emissions
standards for cars and trucks (see below). However, that determination led to a cascade of other
effects, including greenhouse gas emissions controls and permitting requirements on new
stationary sources.
However, the automatic thresholds in the Clean Air Act would have caused a massive number of
previously unregulated sources to fall under the permitting requirements and would have created
an overwhelming burden on federal and state permitting authorities. Thus, in June 2010, EPA
finalized the “tailoring rule” limiting at least through 2016 any requirements to only the largest
emitters and then generally only if a new project or facility expansion leads to increases of nongreenhouse pollutants as well.
In December 2010 EPA settled a lawsuit petitioning the EPA to set New Source Performance
Standards (NSPS) for greenhouse gas emissions from refineries. In the settlement, EPA agreed to
promulgate by November 10, 2012, NSPS for greenhouse gas emissions from new and modified
refineries, as well as guidelines for existing petroleum refineries. However, this deadline has
since passed and it is unclear when EPA will issue a proposal or a final rule.
Future federal regulations, if applied to petroleum refineries, could affect their operations.
However, any effects would necessarily come in the future as these regulations do not yet apply
43
Other ways to address the blend wall include increased use of non-ethanol fuels such as biodiesel, and the increased
sale of E85 for use in FFVs.
44
For more information, see CRS Report R41103, Federal Agency Actions Following the Supreme Court’s Climate
Change Decision in Massachusetts v. EPA: A Chronology, by (name redacted).
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to refiners. State regulations, however, could dramatically affect refinery operations, especially
rules in the state of California.
In 2007 the California legislature passed, and then-Governor Schwarzenegger signed, a law
requiring statewide reductions in greenhouse gas emissions by 2020. Among other regulations to
implement the law, the California Air Resources Board established a Low-Carbon Fuel Standard
(LCFS) requiring refiners to reduce the carbon intensity45 of the fuels they provide to the
California market. By 2020, the regulations require a roughly 10% reduction from 2010 levels. In
general, it is expected that most of the requirement will be met using various lower-carbon
biofuels, although California’s standards for lifecycle emissions are stringent, and some biofuels
actually have higher emissions than gasoline or diesel fuel under the rule.46 The interactions
between the California program and the federal RFS could be complex, and it is unclear how
much the LCFS will raise refiners’ costs as early reviews of the program have shown little effect
on the market and compliance credits are currently trading at low levels. However, as the program
becomes more stringent, the compliance costs are likely to increase.
Vehicle Fuel Economy/Greenhouse Gas Rules
The most recent federal legislation on fuel efficiency was the Energy Independence and Security
Act of 2007 (EISA),47 which requires the National Highway Traffic Safety Administration
(NHTSA) to increase combined passenger car and light truck fuel economy standards to at least
35 miles per gallon (mpg) by 2020,48 up from roughly 26.6 mpg in 2007.49 Along with requiring
higher passenger vehicle standards, EISA dramatically changed the structure of the passenger
vehicle fuel economy program. It also directed DOT to study improvements in heavy-duty
vehicles and, if feasible, issue standards for those vehicles as well.50 In the same year, the
Supreme Court found that the Environmental Protection Agency (EPA) has the authority to
regulate vehicle greenhouse gas (GHG) emissions under the Clean Air Act.51 These two actions
have significantly changed how motor vehicles are regulated at the federal level.
Fuel consumption and GHG emissions from motor vehicles are closely linked. The vast majority
of vehicle GHG emissions result from the burning of petroleum products, so reducing vehicle fuel
consumption is the most direct means of reducing emissions. For these reasons, the Obama
Administration has issued joint rules on vehicle fuel economy and GHG emissions for model year
45
Lifecycle greenhouse gas emissions per unit of energy delivered. Measured in grams of carbon dioxide equivalent of
emissions per MegaJoule of energy delivered (gCO2E/MJ).
46
See CRS Report R40078, A Low Carbon Fuel Standard: State and Federal Legislation and Regulations, by (name red
acted).
47
P.L. 110-140
48
Thirty-five miles per gallon is a lower bound: the Administration is required to set standards at the “maximum
feasible” fuel economy level for any model year.
49
Previously, passenger car Corporate Average Fuel Economy (CAFE) standards had been established in 1975 by the
Energy Policy and Conservation Act (EPCA, P.L. 94-163), and had not increased beyond that level after 1985. Before
the enactment of EISA, DOT had very little authority to modify the passenger car standards. Light truck standards had
been flat at 20.7 mpg through the mid-2000s until the Bush Administration used broader authority within EPCA to
raise the light trucks standards.
50
For more analysis, see CRS Report RL34294, Energy Independence and Security Act of 2007: A Summary of Major
Provisions, by (name redacted).
51
For more analysis, see CRS Report RS22665, The Supreme Court’s Climate Change Decision: Massachusetts v.
EPA, by (name redacted).
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(MY) 2012-2016 passenger cars and light trucks,52 MY2014-MY2018 medium- and heavy-duty
trucks,53 and MY2017-MY2025 passenger cars and light trucks.54 The Administration intends the
passenger vehicle standards to be harmonized with standards issued by the state of California
under the Clean Air Act.
By 2020, the new passenger vehicle standards will require a combined car/truck fuel economy of
an estimated 49.7 mpg, significantly beyond what was required under EISA. Combined, these
standards could reduce gasoline consumption by roughly 5 million barrels per day compared to
business-as-usual projections, and by roughly 2 million-3 million barrels per day from 2010
levels.55 Similarly, EPA estimates that the heavy-duty vehicle and engine standards will save 530
million barrels of oil (mostly diesel fuel) over the life of the MY2014-2018 vehicles covered by
the rule.56 Such a dramatic reduction in demand for gasoline will almost certainly affect the
overall levels of refined products as well as the mix of products produced from U.S. refineries.
Conclusion
The petroleum refining industry has a long history of cyclical performance. The most recent
downturn closely followed a period many identified as the “golden age” of refining. Cycles in the
industry have been historically related to movements in the price of oil, which is the primary cost
element in refinery operations, and this will likely remain true in the future.
The composition and properties of crude oil inputs to U.S. refineries has shifted over time,
requiring investments in new equipment to refine heavier, more sour crudes. As international
supply continues to shift toward heavier crudes, investments in these capabilities may increase.
The refining industry also faces structural challenges from recent government policies that aim at
directly reducing the demand for the industry’s output. Higher fuel mileage standards for
automobiles, increased blending of renewable fuels in gasoline and diesel fuel, and the expansion
in the use of pure biofuels suggest that even if economic conditions encourage a period of
increasing demand for transportation fuels, the need for refined petroleum products will not
necessarily increase proportionately. Electric vehicles, if adopted on a large-scale basis, could
reduce the demand for liquid transportation fuels of all types, although a large-scale shift in this
direction seems unlikely any time soon.
These policies were intended, in part, to address the growing demand for refined petroleum
products. Now, though, combined with the prospect of declining motor fuel demand overall, the
52
Environmental Protection Agency (EPA) and National Highway Traffic Safety Administration (NHTSA), “LightDuty Vehicle Greenhouse Gas Emission Standards and Corporate Average Fuel Economy Standards; Final Rule,” 75
Federal Register 25324-25728, May 7, 2010.
53
EPA and NHTSA, “Greenhouse Gas Emissions Standards and Fuel Efficiency Standards for Medium- and HeavyDuty Engines and Vehicles; Final Rule,” 76 Federal Register 57106-57513, September 15, 2011.
54
The CAFE standards only apply through MY2021 because of stipulations in the fuel economy law. NHTSA will
need to issue additional regulations for MY2022 onward, while EPA has the authority to set GHG standards for
MY2025 and beyond. EPA and NHTSA, 2017 and Later Model Year Light-Duty Vehicle Greenhouse Gas Emissions
and Corporate Average Fuel Economy Standards, Prepublication Version, August 28, 2012, http://www.epa.gov/oms/
climate/documents/2017-2025-ghg-cafe-standards-frm.pdf.
55
CRS analysis of projections from EIA, Annual Energy Outlook Table Browser, Washington, DC, Accessed
September 21, 2012, http://www.eia.gov/oiaf/aeo/tablebrowser/.
56
EPA, EPA and NHTSA Adopt First-Ever Program to Reduce Greenhouse Gas Emissions and Improve Fuel
Efficiency of Medium- and Heavy-Duty Vehicles, EPA-420-F-11-031, Washington, DC, August 2011,
http://www.epa.gov/oms/climate/documents/420f11031.pdf.
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The U.S. Oil Refining Industry: Background in Changing Markets and Fuel Policies
use of more renewable fuels could influence operators to idle, consolidate, or permanently close
refineries. This possibility may help explain why some refiners do not see a need to expand, or
even maintain, production capacity in the United States.
Because of market forces, technological changes, and regulatory pressures on the refining
industry, additional refineries are likely to close even as some of the more technologically
complex and efficient refineries are likely to expand. If a trend toward even larger refineries
emerges, this could lead to concentration in the industry at least on the national level. In the event
such adjustments occur, Congress may wish to monitor competitive conditions in oil refining, and
in particular the impact of consolidation on consumer prices and consumer choice.
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The U.S. Oil Refining Industry: Background in Changing Markets and Fuel Policies
Appendix A. Crude Oil Properties
Table A-1. API Gravity and Sulfur Content of Select Crude Oils
Source
United States
Gulf of Mexico
California
North Dakota
Canada
Saudi Arabia
Mexico
Venezuela
Nigeria
Iraq
Dubai
United Kingdom
Crude Type
West Texas Intermediate
Alaska North Slope
Alaska North Slope
Strategic Petroleum Reserve sweet/sour
NYMEX Deliverable Grade Sweet Crude Oil
Hoops Blend
Poseidon Heavy-sour
Mars Heavy-sour
Thunder Horse ACM Light-Sour
Southern Green Canyon Heavy-sour
Hondo Monterey
Kern River
Bakken Sweet/Light
Access Western Blend
Cold Lake
Black Rock Seal Heavy
Western Canadian Blend
Western Canadian Select
Wabasca Heavy
Smiley Coleville Heavy
Albian Heavy DilSynBit
Canadian Sweet/Sour
Canadian Alberta Syncrude
Arabian Heavy
Saudi Arabia Arab Extra Light / Heavy
Maya
Mexico Maya/Olmeca
Pilon
Bachaquero
Tia Juana Heavy
Laguna
Boscan
Mesa 30
Mesa 28
Tia Juana Light
BCF-24
BCF-17
Nigeria Bonny Light
Iraq Basra Light
Dubai Fateh Heavy
Captain
North Sea Brent Blend
ºAPI Gravity
40
29.5 – 29
31.9
40 – 30
42 – 37
31.6
29.7
28.9
34.50
28.40
19.4
13.4
39.7
22.3
20.8
20.7
20.7
20.6
20.4
20.0
19.5
37.7 – 37.5
38.7
27.5
37.2 – 27.4
21.5
39.8 – 22.2
16.2
13.5
12.3
10.9
10.1
30.5
28.0
31.9
23.7
13.5
33.8
34 –35
30.8
19.2
38 – 39
Sulfur %
0.30
1.10
0.93
0.5 – 2.0
<0.42
1.16
1.65
2.05
0.61
2.48
4.70
1.10
0.25
3.93
3.71
4.59
3.09
3.37
4.05
2.97
2.53
0.42 – 0.56
0.19
2.95
1.15 – 2.8
3.31
0.80 – 3.30
2.47
2.30
2.82
2.66
5.40
0.85
1.18
1.18
1.88
2.30
0.30
1.5
2.07
0.70
0.37
Source: Canadian Crude Quick Reference Guide Version 0.54, Crude Oil Quality Association, 2009,
http://www.coqa- inc.org/102209CanadianCrudeReferenceGuide.pdf; http://www.genesisny.net/Commodity/Oil/
OSpecs.html#Top; BP, http://www.bp.com/productfamily.do?categoryId=16002776&contentId=7020157;
McQuilling Services, LLC, “Carriage of Heavy Grade Oil,” Garden City, NY, 2011, http://www.meglobaloil.com/
MARPOL.pdf; Hydrocarbon Publishing Co., Opportunity Crudes Report II, Southeastern, PA, 2011, p. 5,
http://www.hydrocarbonpublishing.com/ReportP/Prospectus-Opportunity%20Crudes%20II_2011.pdf.
Notes: ºAPI gravity is the American Petroleum Institute’s measure of specific gravity of crude oil or condensate
in degrees. The measuring scale is calculated as Degrees API = (141.5 / sp.gr.60 deg.F/60 deg. F) - 131.5. Higher
API degree indicates lighter, and generally higher priced, crude oils.
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The U.S. Oil Refining Industry: Background in Changing Markets and Fuel Policies
Light oil, also called conventional oil, has an API gravity of at least 22° and a viscosity less than
100 centipoise (cP).57 Viscosity is a measure of the fluid’s resistance to flow. It varies greatly with
temperature. Viscosity matters to producers because the oil’s viscosity at reservoir temperature
determines how easily oil flows to the well for extraction.
Heavy oil is an asphaltic, dense (low API gravity), and viscous oil that is chemically
characterized by its content of asphaltenes (very large molecules incorporating most of the sulfur
and perhaps 90% of the metals in the oil). Although variously defined, the upper limit for heavy
oil has been set at 22 °API gravity and a viscosity of 100 cP.
Extra-heavy oil is that portion of heavy oil having an API gravity of less than 10°.
Natural bitumen, also called tar sands or oil sands, shares the attributes of heavy oil but is yet
more dense and viscous. Natural bitumen is oil having a viscosity greater than 10,000 cP.
Sour crude contains sulfur present as hydrogen sulfide (H2S), which is generated at temperatures
greater than 392°F (200°C) by thermolysis of carbon-sulfur bonds in sulfur-containing
compounds in the crude. Part of crude oil refining involves removing sulfur by converting it to
hydrogen sulfide (H2S). Until the 1970s, refineries burned H2S as a fuel and along with the other
gaseous hydrocarbons released during refining. In response to the Clean Air Act, refineries had to
add processes that converted the H2S to elemental sulfur.
Natural bitumen is a very viscous crude oil that may be up to 50% by weight of asphaltenes—a
general class of aromatic-type hydrocarbons that are very high in molecular weight, highly
viscous, and lack a specific melting point. Asphaltenes have a pronounced tendency to “selfaggregate” (self-join), and thus cause problems in crude oil processing and refining. The same
property lends itself well to making asphalt (a mixture of asphaltenes and petrolenes) useful for
road paving.
SynCrude has no formal definition but typically represents a blend of naphtha, distillate, and gas
oil range materials, containing no resid, with a boiling range of 1050°F+ (565°C). Canada began
producing oil-sand bitumen in the 1960s by partially refining the bitumen into “synthetic crude”
(or “syncrude”). In 1967, Suncor (then Great Canadian Oil Sands) started producing a light sweet
syncrude by hydrotreating the naphtha, distillate, and gas oil generated in a refinery delayed
coking unit; marketed today as Suncor Oil Sands Blend A (OSA). Syncrude Canada Ltd. started
producing a fully hydrotreated syncrude blend in 1978, using fluidized-bed coking technology as
the primary upgrading step, marketed today as Syncrude Sweet Blend (SSB). Husky Oil started
upgrading a heavy, conventional crude in 1990 using a combination of ebullated-bed
hydroprocessing and delayed coking technologies to produce a sweet synthetic crude marketed as
Husky Sweet Blend (HSB). Most recently, the Athabasca Oils Sands Project (AOSP) started
producing a sweet, synthetic crude in 2003 called Premium Albian Synthetic (PAS) using
ebullated-bed hydroprocessing technology.
DilBit, or diluted bitumen, is produced without refinery upgrading, by blending the bitumen with
natural gas condensates to meet the specifications required for pipeline shipping. Condensates
form when the heavier fractions of natural gas—propane, butane, pentane—turn to liquid in
surface processing facilities. Dilbit may be blended with 25%-30% condensate and 70%-75%
bitumen. The most common Dilbit streams are Cold Lake Blend (CLB), Bow River (BRH), and
various Lloyd blends (LLB, LLK, WCB). Since the majority of condensate is in the C5 to C12
length hydrocarbons (5 to 12 carbon atoms) range, and the majority of bitumen is C30+ boiling
57
USGS, Heavy Oil and Natural Bitumen—Strategic Petroleum Resources, Fact Sheet 70-03, August 2003,
http://pubs.usgs.gov/fs/fs070-03/fs070-03.html
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The U.S. Oil Refining Industry: Background in Changing Markets and Fuel Policies
range material, these blends are referred to as “dumbbell crudes,” reflecting the absence of
intermediate range hydrocarbons.
SynBit is a blend of sweet synthetic crude (typically OSA) and bitumen, typically 50% synthetic
crude and 50% bitumen. As natural gas condensate is in short supply in Northern Alberta and
sells at a significant premium to light sweet crudes, some producers have started marketing
“SynBit.” The most common SynBits on the market today are Christina Lake Blend (CSB) and
MacKay Heavy (MKH), both of which are blends of bitumen produced by Steam Assisted
Gravity Drainage (SAGD) and OSA crudes. As a result of the condensate shortage, some
condensate is separated from the SyBits after delivery to the United States, and is being shipped
back to Alberta by rail car.
SynDilBits are actually blends of condensate, hydrotreated synthetic crude, and bitumen. They
typically contain about 65% bitumen, with the remaining volume split between the two dilutent
streams. The most common of these streams are Wabasca Heavy (WH) and Western Canadian
Select (WCS).
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The U.S. Oil Refining Industry: Background in Changing Markets and Fuel Policies
Appendix B. Refining Processes
Crude oil contains natural components in the boiling range of gasoline, kerosene/jet fuel and
diesel fuel. (Table B-1.) Light crude oils tend to have more paraffin in the range of gasoline, as
much as 10%-40%. When light crude oils were more abundant in the United States, early
refineries directly distilled a straight-run gasoline (light naphtha) of low-octane rating.
Table B-1. Crude Oil Fractions and Boiling Ranges
Fraction
Boiling Range °F
Residuum
1,050° +
Gas-oil
520° – 1,050°
Kerosene/Jet/ Diesel
380° – 520°
Gasoline /Naphtha
90° – 380°
Fuel Gases
Below 90°
Source: CRS.
Notes: Gasoline’s molecular weight is based on the number of carbon atoms, in the range of C5 to C10;
middle-distillate fuels like kerosene, jet, and diesel range from C11 to C18.
Crude oil processing begins in a refinery’s atmospheric distillation unit. The refinery’s “name
plate capacity,” usually expressed as barrels per calendar day or barrels per stream day describes
the volume of crude oil that flows through a refinery’s atmospheric distillation unit. This is the
initial refining stage that separates crude oil into gasoline, kerosene, diesel fuel and heavier
petroleum components on the basis of their boiling range. There, the “straight-run” petroleum
fractions in the boiling ranges of gasoline, naphtha, kerosene, diesel, and jet fuel condense and
separate. Heavier fractions are cracked with catalysts and hydrogen to produce more gasoline
range (C5+) blending stock, and low-octane paraffins are converted into high-octane aromatics
(octane is discussed below). Other processes such as alkylation produce branched chain
hydrocarbons in the gasoline range.
Generally, refineries are set up to run specific grades of crude oil, for example light sweet or
heavy sour. Light sweet crude is particularly desirable as a feedstock for gasoline refining
because its lighter-weight hydrocarbons make it easier to refine. Heavier crude oils require more
complex processing than light crudes, and sour crudes require desulfurization. Refineries
upgraded to process heavier crudes cannot readily switch back to lighter oils and run at normal
capacity.
Catalytic cracking, coking, and other conversion units, referred to as secondary processing units,
have enabled refineries to produce more high-value products, such as gasoline, from a barrel of
crude oil and process heavier crude oils. These processing units add to a refinery’s complexity
and can actually increase the volume of its output. These processes also require a supply of
hydrogen, typically derived from natural gas.
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Table B-2. Refinery Types and Process
Refinery Type
Processes
Complexity
Coking
Add coking/resid destruction (delayed coking process)
to run medium/sour crude oil.
9
Cracking
Add vacuum distillation and catalytic cracking process
to run light sour crude to produce light and middle
distillates.
5
Hydroskimming
Atmospheric distillation, naphtha reforming and
desulfurization process to run light sweet crude and
produce gasoline.
2
Topping
Separate crude oil into constituent petroleum products
by atmospheric distillation; produce naphtha but no
gasoline.
1
Source: Reliance Industries, Ltd., “Types of Refinery & Nelson’s Complexity.”
Notes: Complexity, as denoted above, is based on the Nelson Complexity Index, which rates the proportion of
secondary processes to primary distillation (topping) capacity. Nelson’s index varies from about 2 for
hydroskimming refineries to about 5 for cracking refineries, and over 9 for coking refineries. While the average
index for U.S. refineries is 10, only 52 have coking capacity (accounting for the Delaware City refinery closure,
this represent 3.485 million barrels per day capacity).58 By and large, U.S. refineries have become the most
complex in the world in order to convert low-value residuum, formerly used as heavy heating oil, to high-value
gasoline. European refineries, in comparison, are less complex than U.S. refineries on average, being geared
toward producing more diesel fuel.
Distillation Unit: Heats crude oil until it boils and vaporizes. Each hydrocarbon rises
to a tray at a temperature just below its own boiling point. There, it cools and turns
back to a liquid. The lightest fractions are liquefied petroleum gases (propane and
butane) and the petrochemicals used to make plastics and other products. Next come
gasoline, kerosene, and diesel fuel. Heavier fractions are used as home heating oil
and as fuel in ships and factories. Still heavier fractions are made into lubricants and
waxes. The remains, which include asphalt, are known as “residuals.”
Fluid Catalytic Cracker: “Cat cracking” is a refining process used to manufacture
gasoline. The process uses intense heat, low pressure, and powdered catalyst to
accelerate the chemical reaction of the heavy fractions into smaller gasoline
molecules.
Selective Hydrocracker: Partially converts diesel-range material into gasoline,
propane and butane via a chemical reaction that uses high temperatures and pressures
in a catalyst-containing reactor.
Alkylation Plant: Converts light hydrocarbons to heavier hydrocarbons more
compatible as gasoline components for high-octane gasoline.
Catalytic Reforming: A process for upgrading low octane naphtha to a high octane
gasoline blending component, reformate. Important by-products of this process
include hydrogen, benzene, toluene, and xylenes.
Delayed Coker: Converts petroleum pitch into petroleum coke and gas oils for
processing in other units to higher quality, higher value diesel fuel and gasoline.
58
Oil & Gas Journal, 2006 U.S. Refining Survey, December 19, 2005.
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The U.S. Oil Refining Industry: Background in Changing Markets and Fuel Policies
Gas Oil Hydrotreater: Provides for removal of sulfur and nitrogen from various
products, making them more suitable for conversion feed to other process units.
Gas Plants: Collect gases from processing units (hydrocracker, hydrotreater,
reformer, coker, cat cracker) and separate volatiles into appropriate product streams.
Sulfur Recovery Unit: Recovers sulfur from refinery streams as elemental sulfur for
A typical refinery yields a limited supply of jet and diesel fuel depending on the type of crude oil
processed. Gulf Coast (Texas and Louisiana) may yield up to 8% jet fuel, and over 30% diesel.
(See Figure B-1.) These refineries have an average complexity of 12 to 13, which is above the
national average of 9.5.
Figure B-1. Gulf Coast Refinery Yields
(Percent [%])
100
90
80
Percent
70
48.1
39.9
36.8
8.2
6.7
9.7
Gasoline
60
50
40
30
20
10
0
44.9
8.1
7.8
24.7
30.9
Kerosene/Jet
Diesel
Fuel Oil
41.6
39.6
23.7
9.8
West Texas
Intermediate
4.5
Arab Light
Arab Heavy
Nigerian Bonny
Light
Source: Data used from Energy Intelligence, The International Crude Oil Refining Handbook, 2007,
http://www.energyintel.com.
Note: Winter yields shown.
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The U.S. Oil Refining Industry: Background in Changing Markets and Fuel Policies
Appendix C. Operable Refineries by PADD
Figure C-1. Operable Refineries in PADD 1
Source: CRS analysis of capacity data advertised on owner/operator websites.
Facility
PBF Delaware City Refinery
Phillips 66 Bayway Refinery
PBF Paulsboro Refinery
Amerada Hess Port Reading Refinery
Carlyle -Sunoco Philadelphia Refinery
Delta Trainer Refinery
United Warren Refinery
Congressional Research Service
City
Delaware City
Linden
Paulsboro
Port Reading
Philadelphia
Trainer
Warren
State
DE
NJ
NJ
NJ
PA
PA
PA
Bbl/day
190,000
238,000
180,000
70,000
340,000
185,000
70,000
1,273,000
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The U.S. Oil Refining Industry: Background in Changing Markets and Fuel Policies
Figure C-2. Operable Refineries in PADD 2
Source: CRS analysis of capacity data advertised on owner/operator websites.
Facility
City
Phillips 66 Wood River Refinery
Roxana
ExxonMobil Joliet Refinery
Drummond
Robinson
Marathon Robinson Refinery
Lemont (Chicago)
Citgo Lemont Refinery
Whiting
BP Whiting Refinery
Mount Vernon
CountryMark Refinery
El Dorado
Holley Frontier El Dorado Refinery
CVR Coffeyville Refinery
Coffeyville
McPherson
Cenex-NCRA McPherson Refinery
Catlettsburg
Marathon Catlettsburg Refinery
Somerset
Continental Somerset Refinery
Detroit
Marathon Detroit Refinery
Rosemont
Flint Hills Pine Bend Refinery
Saint Paul Park
Northern Tier St. Paul Park Refinery
Mandan
Tesoro Mandan Refinery
Toledo
PBF Toledo Refinery
Oregon/Toledo
BP-Husky Refinery
Lima
Husky Lima Refinery
Canton
Marathon Canton Refinery
Ponca City
Phillips 66 Ponca City Refinery
Holly –Frontier Tulsa Refinery Complex (East Plant) Tulsa
Holly –Frontier Tulsa Refinery Complex (West
Tulsa
Plant)
Ardmore
Valero Ardmore Refinery
Wynnewood
CVR Wynnewood Refinery
Memphis
Valero Memphis Refinery
Superior
Calumet Superior Refinery
Congressional Research Service
State
IL
IL
IL
IL
IN
IN
KS
KS
KS
KY
KY
MI
MN
MN
ND
OH
OH
OH
OH
OK
Bbl/day
306,000
250,000
206,000
167,000
413,000
26,500
135,000
115,000
85,000
233,000
5,500
106,000
320,000
74,000
58,000
170,000
160,000
155,000
78,000
187,000
OK
125,000
OK
OK
TN
WI
90,000
70,000
195,000
34,300
3,764,300
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The U.S. Oil Refining Industry: Background in Changing Markets and Fuel Policies
Figure C-3. Operable Refineries in PADD 3
Source: CRS analysis of capacity data advertised on owner/operator websites.
Facility
Shell Mobile Refinery
Hunt Tuscaloosa Refinery
Delek-Lion El Dorado Refinery
ExxonMobil Baton Rouge Refinery
Marathon Garyville Refinery
Citgo Lake Charles Refinery
Valero St. Charles Refinery
Phillips 66 Alliance Refinery
Phillips 66 Lake Charles Refinery
Motiva Convent Refinery
Motiva Norco Refinery
ExxonMobil Chalmette Refinery
Valero Meraux Refinery
Alon Krotz Springs Refinery
Placid Port Allen Refinery
Calcasieu Lake Charles Refinery
Chevron Pascagoula Refinery
Holly-Frontier Navajo Refinery
Western Four Corners Refinery
Motiva Port Arthur Refinery
ExxonMobil Baytown Refinery
Marathon Texas City Refinery
Congressional Research Service
City
Saraland
Tuscaloosa
El Dorado
Baton Rouge
Garyville
Lake Charles
Norco
Belle Chasse
Westlake
Convent
St. Charles Parrish
Chalmette
Meraux
Krotz Springs
Port Allen
Lake Charles
Pascagoula
Artesia
Gallup/Jamestown
Port Arthur
Baytown
Texas City
State
AL
AL
AR
LA
LA
LA
LA
LA
LA
LA
LA
LA
LA
LA
LA
LA
MS
NM
NM
TX
TX
TX
Bbl/day
80,000
72,000
80,000
503,500
490,000
425,000
270,000
247,000
239,000
235,000
234,700
192,500
125,000
83,100
80,000
32,000
330,000
100,000
23,000
600,000
573,000
475,000
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The U.S. Oil Refining Industry: Background in Changing Markets and Fuel Policies
Facility
ExxonMobil Beaumont Refinery
Shell Deer Park Refinery
Valero Bill Greehy E. & W. Refinery Complex
Valero Port Arthur Refinery
Lyondell Houston Refinery
Phillips 66 Sweeny Refinery Complex
Valero Texas City Refinery
Total Port Arthur Refinery
Valero McKee Refinery
Citgo Corpus Christi Refinery East & West Plant
Valero Houston Refinery
Flint Hills Corpus Christi East Refining Complex
Flint Hills Corpus Christi West Refining Complex
Phillips 66 Borger Refinery
Western El Paso Refinery
Petrobras Pasadena Refining System Inc
Valero Three Rivers Refinery
Marathon Texas City Refinery
Alon Big Spring Refinery
Delek Tyler Refinery
NuStar San Antonio Refinery
Congressional Research Service
City
Beaumont
Deer Park
Corpus Christi
Port Arthur
Houston
Sweeny
Texas City
Port Arthur
Sunray
Corpus Christi
Houston
Corpus Christi
Corpus Christi
Borger
El Paso
Pasadena
Three Rivers
Texas City
Big Spring
Tyler
San Antonio
State
TX
TX
TX
TX
TX
TX
TX
TX
TX
TX
TX
TX
TX
TX
TX
TX
TX
TX
TX
TX
TX
Bbl/day
365,000
340,000
325,000
310,000
268,000
247,000
245,000
174,000
170,000
165,000
160,000
150,000
150,000
146,000
128,000
100,000
100,000
80,000
70,000
60,000
13,500
9,256,300
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The U.S. Oil Refining Industry: Background in Changing Markets and Fuel Policies
Figure C-4. Operable Refineries in PADD 4
Source: CRS analysis of capacity data advertised on owner/operator websites.
Facility
Suncor Commerce City Refinery Complex
ExxonMobil Billings Refinery
Phillips 66 Billings Refinery
Cenex Laurel Refinery
MRC Great Falls Refinery
Tesoro Salt Lake City Refinery
Chevron Salt Lake City Refinery
Big West North Salt Lake Refinery
Holly-Frontier Woods Cross Refinery
Silver Eagle Woods Cross Refinery
Sinclair Refinery
Holley-Frontier Cheyenne Refinery
Sinclair Little America Refinery
Black Elk Wyoming Refinery
Silver Eagle Evanston Refinery
City
Commerce City
Billings
Billings
Laurel
Great Falls
Salt Lake City
Salt Lake City
North Salt Lake
Woods Cross
Woods Cross
Sinclair
Cheyenne
Casper/Evansville
Newcastle
Evanston
State
CO
MT
MT
MT
MT
UT
UT
UT
UT
UT
WY
WY
WY
WY
WY
Bbl/day
93,000
60,000
58,000
55,000
10,000
58,000
45,000
35,000
31,000
10,250
66,000
52,000
24,500
12,500
3,000
632,250
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The U.S. Oil Refining Industry: Background in Changing Markets and Fuel Policies
Figure C-5. Operable Refineries in PADD 5
Source: CRS analysis of capacity data advertised on owner/operator websites.
Notes: The Phillips 66 San Francisco Refinery comprises two facilities inked by a 200-mile pipeline ─ the Santa
Maria facility located in Arroyo Grande, CA, and the Rodeo facility in the San Francisco Bay Area. The Santa
Maria facility upgrades heavy crude oil for final processing in the San Francisco Bay facility. The Santa Maria
facility is not on the map. The Phillips 66 Los Angeles Refinery Complex is composed of two facilities linked by a
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The U.S. Oil Refining Industry: Background in Changing Markets and Fuel Policies
five-mile pipeline. The Carson facility serves as the front end of the refinery by processing crude oil, and
Wilmington serves as the back end by upgrading the products.
City
St
Flint Hills North Pole Refinery
Petro Star Valdez Refinery
Petro Star North Pole Refinery
Tesoro Kenai Refinery
Chevron El Segundo Refinery
Tesoro Carson Refinery
Chevron Richmond Refinery
Valero Benicia Refinery
Tesoro Golden Eagle Refinery
Shell Martinez Refinery
ExxonMobil Torrance Refinery
Phillips 66 Los Angeles Refinery Complex/ Wilmington
Phillips 66 Los Angeles Refinery Complex/ Carson
Valero Wilmington Refinery
Phillips 66 San Francisco Refinery/Rodeo Facility
Phillips 66 San Francisco Refinery/Santa Maria Facility
Tesoro Los Angeles Refinery
Alon California Refineries Paramount
Facility
North Pole
Valdez
North Pole
Kenai
El Segundo
Los Angeles
Richmond
Benicia
Martinez
Martinez
Torrance
Wilmington
Carson
Wilmington
Rodeo
Arroyo Grande
Wilmington
Paramount
AK
AK
AK
AK
CA
CA
CA
CA
CA
CA
CA
CA
CA
CA
CA
CA
CA
CA
Alon California Refineries Longbeach
Longbeach
CA
Alon California Refineries Bakersfield
Kern Oil Bakersfield Refinery
San Joaquin Refinery
Tesoro Hawaii Refinery
Chevron Kapolei Refinery
BP Cherry Point Refinery
Shell Puget Sound Refinery
Tesoro Anacortes Refinery
Phillips 66 Ferndale Refinery
US Oil Refinery
Bakersfield
Bakersfield
Bakersfield
Kapolei
Kapolei
Blaine
Anacortes
Anacortes
Ferndale
Tacoma
CA
CA
CA
HI
HI
WA
WA
WA
WA
WA
Congressional Research Service
Bbls/day
220,000
60,000
22,000
72,000
290,000
266,000
243,000
170,000
166,000
165,000
150,000
139,000
135,000
120,000
97,000
94,000
26,000
24,300
94,500
54,000
230,000
145,000
120,000
100,000
39,000
3,241,800
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The U.S. Oil Refining Industry: Background in Changing Markets and Fuel Policies
Appendix D. Important Fuel Properties
Reid Vapor Pressure
Vapor pressure is an important physical property of both automotive and aviation gasoline,
affecting starting, warm-up, and tendency to vapor lock with high operating temperatures or high
altitudes. EPA regulates the vapor pressure of gasoline sold at retail stations during the summer
ozone season (June 1 to September 15) to reduce evaporative emissions from gasoline that
contribute to ground-level ozone and diminish the effects of ozone-related health problems.
Shifting to gasoline with lower Reid vapor pressure (RVP) reduces emissions. The Reid Method
refers to American Society for Testing and Materials (ASTM) standard test method D 323-08 for
measuring the vapor pressure of petroleum products. RVP of conventional gasoline varies from
8.7 in the summer to 11.5 in the winter; reformulated gasoline (RFG) and state “boutique” fuel
blends may have a summer RVP as low as 7.0.
Octane
Higher octane-number fuels better resist engine “knock”—the sound caused by fuel prematurely
igniting during compression. In early gasoline research, the least knock resulted from using isooctane, which arbitrarily received a rating of 100.59 Isooctane refers to a branched “isomer” in the
paraffin series having eight carbons (C8H18).60 The straight-chain isomer in this series, n-octane,
has a rating -19. Modern formulated gasoline ranges in octane from 87 to 93, achieved by
blending various petroleum distillates, reforming gasoline-range hydrocarbons, and adding
oxygenates such as ethanol to boost octane-number.
Cetane
The standard for rating diesel fuel’s ease of auto-ignition during engine compression is based on
“cetane”─a straight-chain hydrocarbon in the paraffin series with the common name of nhexadecane. It consists of 16 carbon atoms with three hydrogen atoms bonded to the two end
carbons and two hydrogens bonded to each of the middle carbons; written as C16H34. Pure cetane
received the number 100 for rating purposes. Diesel fuel cetane-number ranges from 40 to 45 in
the United States to as high as 55 in Europe (where high-speed diesel engines are prevalent in
light-duty passenger vehicles). Diesel fuel formulation blends straight-run cut distillates with
cracked stock (heavier fractions) to meet standardized specifications developed by the American
Society for Testing and Materials (ASTM International) and EPA.
Sulfur
As now regulated by EPA (40 C.F.R. 80.520), diesel fuel must contain less than 15 parts-permillion (ppm) sulfur—referred to as ultra-low-sulfur diesel (ULSD). Conventionally refined
aviation jet fuel may contain as high as 3,000 ppm sulfur. However, as it has been used in
blending winter diesel fuel to lower the gel point, it has had a practical limit of 500 ppm (the
previous EPA limit for diesel). It is uncertain whether EPA may promulgate future rules on jet
fuel sulfur-content, thus limiting its use in blending winter ULSD. Despite its detrimental
environmental effects, sulfur contributes to the “lubricity” of fuel. Under reduced sulfur, engines
59
60
John M. Hunt, Petroleum Geochemistry and Geology, W. H. Freeman and Co., 1979. p. 51.
Or more correctly, 2,2,4-trimethylpentane.
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The U.S. Oil Refining Industry: Background in Changing Markets and Fuel Policies
wear out sooner. Fuel can be blended with additives to make up for the loss of sulfur lubricity and
engines can be manufactured from tougher materials, as has been the case in the EPA mandated
transition from low-sulfur diesel (500 ppm) to ultra-low-sulfur diesel (15 ppm). Average annual
sulfur content in all gasoline dropped from about 300 ppm in 1997 to a maximum of 30 ppm for
most refiners in 2006.
Exhaust Emissions
Diesel engines characteristically emit lower amounts of carbon monoxide (CO) and carbon
dioxide (CO2) than gasoline engines, but they emit higher amounts of nitrogen oxides (NOx) and
particulate matter (PM). NOx is the primary cause of ground-level ozone pollution (smog) and
presents a greater problem, technically, to reduce in diesel engines than PM. The CO, NOx, and
PM emissions for gasoline and diesel engines are regulated by the 1990 Clean Air Act
amendments (42 U.S.C. 7401-7671q).
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The U.S. Oil Refining Industry: Background in Changing Markets and Fuel Policies
Appendix E. Glossary61
Motor Gasoline (Finished). 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. Motor gasoline (as defined in ASTM Specification D 4814 or Federal Specification VVG-1690C) has a boiling range of 122º to 158º F at the 10% percent recovery point, and a 365º to
374º F boiling range at the 90% recovery point. “Motor Gasoline” includes conventional gasoline,
all types of oxygenated gasoline (including gasohol), and reformulated gasoline, but excludes
aviation gasoline. Volumetric data on blending components, such as oxygenates, are not counted
in data on finished motor gasoline until the blending components are blended into the gasoline.
Note: E85 is included only in volumetric data on finished motor gasoline production and other
components of product supplied.
Conventional Gasoline. Finished motor gasoline not included in the oxygenated or reformulated
gasoline categories. Note: This category excludes reformulated gasoline blendstock for oxygenate
blending (RBOB) as well as other blendstock.
Reformulated Gasoline. Finished gasoline formulated for use in motor vehicles, the composition
and properties of which meet the requirements of the reformulated gasoline regulations
promulgated by the U.S. Environmental Protection Agency under Section 211(k) of the Clean Air
Act. It includes gasoline produced to meet or exceed emissions performance and benzene content
standards of federal-program reformulated gasoline even though the gasoline may not meet all of
the composition requirements (e.g., oxygen content) of federal-program reformulated gasoline.
Note: This category includes Oxygenated Fuels Program Reformulated Gasoline (OPRG).
Reformulated gasoline excludes Reformulated Blendstock for Oxygenate Blending (RBOB) and
Gasoline Treated as Blendstock (GTAB).
Blendstock for Oxygenate Blending (RBOB). Specially produced reformulated gasoline
blendstock intended for blending with oxygenates downstream of the refinery where it was
produced. Includes RBOB used to meet requirements of the federal reformulated gasoline
program and other blendstock intended for blending with oxygenates to produce finished gasoline
that meets or exceeds emissions performance requirements of Federal reformulated gasoline (e.g.,
California RBOB and Arizona RBOB). Excludes conventional gasoline blendstocks for
oxygenate blending(CBOB).
RBOB for Blending with Alcohol. Motor gasoline blending components intended to be blended
with an alcohol component (e.g., fuel ethanol) at a terminal or refinery to raise the oxygen
content.
Fuel Ethanol (E10). Blends of up to 10% by volume anhydrous ethanol (200 proof) (commonly
referred to as “gasohol”).
61
U.S. Energy Information Administration, Glossary, http://www.eia.gov/tools/glossary/index.cfm.
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The U.S. Oil Refining Industry: Background in Changing Markets and Fuel Policies
Author Contact Information
(name redacted)
(name redacted)
Specialist in Energy and Defense Policy
[redacted]@crs.loc.gov, 7-....
Specialist in Public Finance
[redacted]@crs.loc.gov, 7-....
(name redacted)
(name redacted)
Specialist in Energy Economics
[redacted]@crs.loc.gov, 7-....
Section Research Manager
[redacted]@crs.loc.gov, 7-....
Acknowledgments
Jacqueline V. Nolan, Cartographer, Library of Congress Geography and Maps Division
Amber H. Wilhelm, Graphics Specialist, Congressional Research Service
Congressional Research Service
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