The U.S. Oil Refining Industry: Background
in Changing Markets and Fuel Policies
Anthony Andrews
Specialist in Energy and Defense Policy
Robert Pirog
Specialist in Energy Economics
Molly F. Sherlock
Analyst in Economics
November 22, 2010
Congressional Research Service
7-5700
www.crs.gov
R41478
CRS Report for Congress
P
repared 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, 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, 124 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. This is the result of legislative and regulatory efforts that
were originally intended, in part, to accommodate the growing demand for petroleum products,
but which 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.
Since the Clean Air Act Amendments, 15 distinctly formulated boutique fuels are required in
portions of 12 states. H.R. 392, the Boutique Fuel Reduction Act of 2009, would further amend`
the Clean Air Act to add temporary waivers for boutique fuels due to unexpected problems with
distribution and give EPA authority to reduce the number of boutique fuels. The 2005 Energy
Policy Act created the Renewable Fuel Program to substitute increasing volumes of renewable
fuel for gasoline. The 2007 Energy Independence and Security Act 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. The 2008 Food, Conservation and
Energy Act of 2008 reduced some of the federal subsidies and tax breaks favoring ethanol
production. A 2007U.S. Supreme Court ruling found that EPA has the authority under the Clean
Air Act to regulate carbon dioxide (CO2) emissions from automobiles. Though the ruling applied
to automobiles, it had wider implications. In response to the FY2008 Consolidated
Appropriations Act (H.R. 2764; P.L. 110-161), EPA issued the Mandatory Reporting of
Greenhouse Gases Rule that requires suppliers of fossil fuels or industrial greenhouse gases
(GHG), manufacturers of vehicles and engines, and facilities that emit 25,000 metric tons or more
per year of GHG emissions to submit annual reports to EPA. H.R. 2454, The American Clean
Energy and Security Act of 2009 (passed in the House June 26, 2009) would amend the Clean Air
Act by establishing a “cap-and-trade” system designed to reduce greenhouse gas emissions
(GHG) and would cap emissions from refineries and allow trading of emissions permits
(“allowances”). As proposed, H.R. 2454 would require U.S. refiners to purchase emission credits
for both their stationary emissions and the subsequent combustion of their fuels (predominantly
consumed in the transportation sector). S. 3663, introduced in August 2010, would establish a
Natural Gas Vehicle and Infrastructure Development Program to promote natural gas as an
alternative transportation fuel in order to reduce domestic oil use.
The prospect of declining motor-fuel demand may persuade operators to idle, consolidate, or
permanently close refineries.
Congressional Research Service
The U.S. Oil Refining Industry: Background in Changing Markets and Fuel Policies
Contents
Introduction ................................................................................................................................ 1
Background─Refineries and Capacity ......................................................................................... 2
Petroleum Administration for Defense Districts..................................................................... 2
Refinery Closures ................................................................................................................. 3
Operable Refineries .............................................................................................................. 4
Refinery Capacity Distribution............................................................................................ 11
Changes in Crude Oil Supply and Demand................................................................................ 12
Crude Oil Prices.................................................................................................................. 14
Demand Conditions ............................................................................................................ 16
Profitability......................................................................................................................... 17
Capital Investment .............................................................................................................. 19
Refinery Investment and Petroleum Product Imports ........................................................... 20
Tax Considerations.................................................................................................................... 21
Policy Considerations ............................................................................................................... 22
Reformulated Gasoline........................................................................................................ 22
Renewable Fuel Program /Alternative Fuels ........................................................................ 24
Subsidies and/or Tax Breaks for Renewable Fuel................................................................. 26
Carbon Emissions/Greenhouse Gas Rules ........................................................................... 26
The American Clean Energy and Security Act of 2009 ........................................................ 27
Clean Energy and Oil Accountability Act of 2010................................................................ 27
Vehicle Efficiency/Mileage Rules........................................................................................ 28
Conclusion................................................................................................................................ 29
Figures
Figure 1. Fuel Refining Capacity by Petroleum Administration for Defense Districts................... 3
Figure 2. Operable Refineries in PADD 1 .................................................................................... 5
Figure 3. Operable Refineries in PADD 2 .................................................................................... 6
Figure 4. Operable Refineries in PADD 3 .................................................................................... 7
Figure 5. Operable Refineries in PADD 4 .................................................................................... 9
Figure 6. Operable Refineries in PADD 5 .................................................................................. 10
Figure 7. Distribution of U.S. Refinery Capacity ....................................................................... 12
Figure 8. U.S. Crude Oil Supply................................................................................................ 13
Figure 9. Major Refiners by Capacity........................................................................................ 18
Figure 10. Map of Reformulated Gasoline Areas ....................................................................... 23
Figure A-1. 35° API Crude Oil Composition.............................................................................. 31
Figure A-2. Distillation Column ................................................................................................ 33
Figure A-3. Gulf Coast Refinery Yields ..................................................................................... 35
Congressional Research Service
The U.S. Oil Refining Industry: Background in Changing Markets and Fuel Policies
Tables
Table 1. Refinery Crude Oil Input ............................................................................................. 13
Table 2. ºAPI Gravity and Sulfur Content of Representative Crude Oils..................................... 14
Table 3. Light/Heavy Crude Oil Price Spread ............................................................................ 16
Table 4. United States Gasoline Consumption 2006-2009 .......................................................... 17
Table 5. Refiners’ Net Income, 2006-2009................................................................................. 18
Table 6. U.S. Refining Industry Capital Budget Expenditures, 2008-2010.................................. 19
Table 7. Gasoline Imports Vs. Total Gasoline Supplied.............................................................. 20
Table 8. Tax Expenditures for Provisions Allowing Partial Expensing of Refinery
Investments............................................................................................................................ 22
Table 9. EISA Renewable Fuel Volume Requirement................................................................. 24
Table A-1. Crude Oil Fractions and Boiling Ranges................................................................... 31
Table A-2. Refinery Types and Process...................................................................................... 34
Appendixes
Appendix A. Petroleum and Refining Fundamentals.................................................................. 31
Appendix B. Important Fuel Properties ..................................................................................... 36
Appendix C. Glossary ............................................................................................................... 38
Contacts
Author Contact Information ...................................................................................................... 39
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 price-
spreads 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.
U.S. gasoline consumption began declining in 2008, by almost 99 million barrels from the
previous year, and another 10 million barrels in 2009.1 Paradoxically, the United States began
importing more gasoline─81 million barrels in 2009.2 U.S. renewable fuel production (in the
form of ethanol) exceeded 256 million barrels, and ethanol imports added nearly 4.6 million
barrels.3
The concern has now shifted to fears that refining overcapacity may exist in the United States, as
the state of, and the outlook for, the petroleum refining industry have changed significantly.
Current market conditions have resulted in lower capacity utilization rates and refinery closures.
These most recent changes in the conditions facing the industry are consistent with a past
performance that has been cyclic. However, mandates for a renewable fuel standard (RFS) and
increased corporate average fuel economy (CAFE) could influence permanently reduced refining
capacity in coming years.
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 at least offsetting an increasing demand for transportation fuel. Now, though, the
prospect of declining motor-fuel demand may mean that the use of more renewable fuels may
influence operators to idle, consolidate, or permanently close refineries.
This report begins by looking at the current production capacity of the refineries operating in the
United States, and the sources and changes in crude oil supply. It then examines the changing
characteristics of petroleum and petroleum product markets and identifies the effects of these
changes on the refining industry, including tax considerations. The report 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.
1 Gasoline consumption, as reported by the U.S. Energy Information Administration, includes blended ethanol.
2 Reported as 80,882 thousand barrels by EIA.
3 Reported as 256,149 thousand barrels of fuel ethanol produced and 4,614 thousand barrels imported by Energy
Information Administration, Petroleum Supply Monthly, February 2010, Table 2 p. 11, http://www.eia.doe.gov/oil_gas/
petroleum/data_publications/petroleum_supply_monthly/psm.html.
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The U.S. Oil Refining Industry: Background in Changing Markets and Fuel Policies
Background─Refineries and 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.
A decade ago, 158 refineries operated in the United States and its territories. By the
Congressional Research Service’s count, the number has declined to 124 refineries that process
crude oil into fuels, and in addition, 13 refineries that produce lubricating oils and asphalt.4 These
numbers include three refinery complexes, each made up of two formerly independent refineries
joined by pipeline.
Although the number of refineries has decreased, operable refining capacity has increased over
the past decade from 16.5 million barrels/day to over 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 example, reformulating gasoline from winter to summer
blends). In addition, some refinery operators have indefinitely idled their refineries to wait for
improving demand.5
Petroleum Administration for Defense Districts
During World War II, the War Department (now the Department of Defense) delineated
“Petroleum Administration for Defense Districts” (PADD) to facilitate oil allocation. At one time,
refineries in each PADD processed crude oil and distributed petroleum products for use in the
district. The high rate of merchant-marine tankers lost to Nazi submarines operating along the
Eastern seaboard prompted construction of the Virginia and Colonial product pipelines to link the
Gulf Coast with the Northeast United States. A network of crude oil and petroleum product
pipelines now interlinks the PADDs, making them interdependent.
Crude oil sourcing for U.S. refineries varies over time, but in general, the PADD 1 (East Coast)
refineries process crude oil shipped from all over the world. 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. Permitting issues currently stall a pipeline that
would deliver Canadian syncrude (from oil sands) to Gulf Coast Refineries. PADD 5 (West
Coast) obtains crude oil primarily from Alaska (by tanker) and California, and through imports.
No crude oil pipelines link PADD 1 or PADD 5 with the rest of the country.
4 To arrive at this number, CRS used U.S. Energy Information Administration and the 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.
5 The Energy Information Administration defines idle capacity as a component of operable capacity that is not in
operation and not under active repair, but capable of being placed in operation within 30 days; and capacity not in
operation but under active repair that can be completed within 90 days.
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The U.S. Oil Refining Industry: Background in Changing Markets and Fuel Policies
Most of the country’s gasoline is refined in the Gulf Coast (PADD 3), which makes up nearly
45% of the U.S. refining capacity with 45 refineries processing more than 8 million barrels per
day (bbl/d). It is followed by the Midwest (PADD 2) and the West Coast (PADD 5) in refining
capacity.6 The East Coast (PADD 1) has been losing capacity, with gasoline imports meeting a
growing portion of demand. Figure 1 below breaks-out refining capacity by PADD.
A 95,000-mile network of petroleum product pipelines serves most of the United States. This
network, separate from the network of crude oil pipelines, distributes refined products to balance
the demand and supply conditions in each region. Regional differences in mandated fuel gasoline
specifications, however, limit the flexibility of distribution by pipeline. Additionally, PADD 5 is
largely isolated from the rest of the United States, especially from the large refineries in PADD 3,
resulting in a market that has exhibited higher prices and reduced availability under some market
conditions.
Figure 1. Fuel Refining Capacity by Petroleum Administration for Defense Districts
Barrels/day
PADD Fuel
Refineries Bbl/Day
1 12
2,083,000
2
25
3,579,000
3 44
8,802,100
4 15 614,750
5 27 3,251,200
Total 123 18,330,050
Source: CRS.
Note: During World War II, the then-War Department delineated PADDs to
facilitate oil allocation.
Refinery Closures
After crude oil prices peaked in the summer of 2008, the U.S. demand for refined petroleum
products began to decline. In response, U.S. refiners began cutting back capacity and in some
cases temporarily idled or permanently closed refineries.
6 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
Valero closed its Delaware City (DE) refinery in late 2009 and furloughed 550 workers.7 In April
2010, Valero sold the refinery to Connecticut-based PBF Energy Partners LLC (Petroplus) for
$220 million. Valero will reportedly write off more than $1.7 billion of assets.8 PBF plans to
invest another $125 million to $150 million in refurbishing the refinery with plans to reopen it in
the spring of 2011.9 Sunoco permanently closed its Eagle Point (NJ) refinery in early 2010 and
furloughed 400 workers. 10 Sunoco had purchased Eagle Point in 2004 for about $250 million. In
2010, Western Refining idled its 16,800 bbl/day refinery in New Mexico and its 70,000 bbl/day
Yorktown (VA) refinery.
Operable Refineries
Figure 2 through Table 5, below, identify operable fuel refineries by PADD.
7 Jeff Montgomery, “Valero refinery in Delaware City to close permanently,” The News Journal, November 20, 2009.
8 Jeff Montgomery, “Valero announces sale of Delaware City Refinery,” The News Journal, April 8, 2010.
9 Steve Goldstein, “Petroplus rallies on deal to buy Delaware refinery,” Wall Street Journal, April 9, 2010, Market
Watch.
10 “Sunoco idles Eagle Point refinery, furloughs 400 workers, cuts dividend,” The Associated Press, October 6, 2009.
Congressional Research Service
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The U.S. Oil Refining Industry: Background in Changing Markets and Fuel Policies
Figure 2. Operable Refineries in PADD 1
PADD #
Facility
City
State
Zip
Bbl/day
1-01
Hovic Refinery
Kingshill, St Croix
VI
00851
500,000
1-02
Sunoco Philadelphia Refinery
Philadelphia
PA
19145
340,000
1-03
ConocoPhillips Bayway Refinery
Linden
NJ
07036
238,000
1-04
Petroplus Delaware City Refinery*
Delaware City
DE
19270
210,000
1-05 Valero
Paulsboro
Refinery
Paulsboro
NJ
08066
185,000
1-06
ConocoPhillips Trainer Refinery
Trainer
PA
19061
185,000
1-07
Sunoco Marcus Hook Refinery
Marcus Hook
PA
19601
175,000
1-08
Chevron Perth Amboy Refinery/Terminal
Perth Amboy
NJ
08861
80,000
1-09
Amerada Hess Port Reading Refinery
Port Reading
NJ
07064
70,000
1-10
United Refinery
Warren
PA
16365
70,000
1-11
Western Yorktown Refinery*
Yorktown
VA
23692
70,000
1-12
Ergon Newel Refinery
Newel
WV
26050
20,000
1-13 Bradford
Refinery
Bradford
PA
16701 10,000
Total
2,153,000
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The U.S. Oil Refining Industry: Background in Changing Markets and Fuel Policies
Source: Refiner publications.
Notes: The Eagle Point Refinery, which closed in 2010, is not included on this map.
* Petroplus plans to reopen the idled Delaware City refinery in 2011. Western announced August 5, 2010,
that it would idle its Yorktown refinery but continue to operate it as a terminal.
Figure 3. Operable Refineries in PADD 2
PADD #
Facility
City
State
Zip
Bbl/day
2-01
BP Whiting Refinery
Whiting
IN
46394
405,000
2-02
Flint Hills Pine Bend Refinery
Rosemont
MN
55068
320,000
2-03
ConocoPhillips Wood River Refinery
Roxana
IL
60284
306,000
2-04
ExxonMobil Joliet Refinery
Drummond
IL
60410
238,000
2-05
Marathon Catlettsburg Refinery
Catlettsburg
KY
41129
212,000
2-06
Marathon Robinson Refinery
Robinson
IL
62454
206,000
2-07
Valero Memphis Refinery
Memphis
TN
38109
195,000
2-08
ConocoPhillips Ponca City Refinery
Ponca City
OK
74601
187,000
2-09
Sunoco Toledo Refinery
Toledo
OH
43607
170,000
2-10
Citgo Lemont Refinery
Lemont (Chicago)
IL
60439
167,000
2-11 BP-Husky
Refinery
Oregon/Toledo OH
43616
160,000
2-12
Frontier El Dorado Refinery
El Dorado
KS
67042
135,000
2-13
Coffeyville Resources Refining & Mkg Refinery
Coffeyville
KS
67337
115,000
2-14
Marathon Detroit Refinery
Detroit
MI
48217
106,000
2-15
Valero Ardmore Refinery
Ardmore
OK
73401
90,000
2-16
CHS NCRA Refinery
McPherson
KS
67460
85,000
2-17
Hol y Tulsa Refinery Complex (West Plant)
Tulsa
OK
74107
85,000
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The U.S. Oil Refining Industry: Background in Changing Markets and Fuel Policies
2-18
Marathon Canton Refinery
Canton
OH
44706
78,000
2-19
Hol y Tulsa Refinery Complex (East Plant)
Tulsa
OK
74107
75,000
2-20
Marathon St. Paul Park Refinery
Saint Paul Park
MN
55071
74,000
2-21
Tesoro Mandan Refinery
Mandan
ND
58544
58,000
2-22
Gary-Wil iams Wynnewood Refinery
Wynnewood
OK
73098
45,000
2-23
Murphy Oil Superior Refinery
Superior
WI
54880
35,000
2-24
CountryMark Refinery
Mount Vernon
IN
47620
26,500
2-25
Somerset Refinery
Somerset
KY
42501
5,500
Total
3,579,000
Source: Refiner publications.
Figure 4. Operable Refineries in PADD 3
PADD #
Facility
City
State
Zip
Bbl/day
3-01
ExxonMobil Baytown Refinery
Baytown
TX
77520
576,000
3-02
ExxonMobil Baton Rouge Refinery
Baton Rouge
LA
70805
504,000
3-03
BP Texas City Refinery
Texas City
TX
77590
475,000
3-04
Citgo Lake Charles Refinery
Lake Charles
LA
70601
440,000
3-05
Marathon Garyville Refinery
Garyville
LA
70051
436,000
3-06
ExxonMobil Beaumont Refinery
Beaumont
TX
77703
345,000
3-07
Shel Deer Park Refinery
Deer Park
TX
77636
340,000
3-08
Chevron Pascagoula Refinery
Pascagoula
MS
39581
330,000
3-09
Valero Corpus Christi E. & W. Refinery Complex
Corpus Christi
TX
78407
315,000
3-10
Valero Port Arthur Refinery
Port Arthur
TX
77640
310,000
3-11
Motiva Port Arthur Refinery
Port Arthur
TX
77641
285,000
3-12
Lyondell Houston Refinery
Houston
TX
77017
268,000
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The U.S. Oil Refining Industry: Background in Changing Markets and Fuel Policies
PADD #
Facility
City
State
Zip
Bbl/day
3-13
Valero St. Charles Refinery
Norco
LA
70079
250,000
3-14
ConocoPhillips Al iance Refinery
Bel e Chasse
LA
70037
247,000
3-15
ConocoPhillips Sweeny Refinery Complex
Sweeny
TX
77463
247,000
3-16
Valero Texas City Refinery
Texas City
TX
77590
245,000
3-17
ConocoPhillips Lake Charles Refinery
Westlake
LA
70669
239,000
3-18
Motiva Convent Refinery
Convent
LA
70723
235,000
3-19
Total Port Arthur Refinery
Port Arthur
TX
77642
232,000
3-20
Motiva Norco Refinery
St. Charles Parrish
LA
70079
220,000
3-21 ExxonMobil/PDVSA
Chalmette
Refinery
Chalmette
LA
70043
192,500
3-22
Valero McKee Refinery
Sunray
TX
79086
170,000
3-23
Citgo Corpus Christi Refinery
Corpus Christi
TX
78047
163,000
3-24A
Flint Hills Corpus Christi Refining Complex E.
3-24B
Flint Hills Corpus Christi Refining Complex W.
Corpus Christi
TX
78408
150,000
3-26
ConocoPhillips Borger Refinery
Borger
TX
79007
146,000
3-27
Valero Houston Refinery
Houston
TX
77012
145,000
3-28
Murphy Oil Meraux Refinery
Meraux
LA
70075
125,000
3-29
Western El Paso Refinery
El Paso
TX
79905
125,000
3-30
Petrobras Pasadena Refining System Inc
Pasadena
TX
77506
100,000
3-31
Valero Three Rivers Refinery
Three Rivers
TX
78701
100,000
3-32
Hol y Navajo Refinery
Artesia
NM
88210
100,000
3-33
Alon Krotz Springs Refinery
Krotz Springs
LA
70750
83,100
3-34
Shel Mobile Refinery
Saraland
AL
36571
80,000
3-35
Placid Port Al en Refinery
Port Allen
LA
70767
80,000
3-36
Marathon Texas City Refinery
Texas City
TX
77590
76,000
3-37
Lion El Dorado Refinery
El Dorado
AR
71730
75,000
3-38
Alon Big Spring Refinery
Big Spring
TX
79720
70,000
3-39
Calumet Shreveport Refinery
Shreveport
LA
71109
60,000
3-40 Tyler
Refinery
Tyler
TX
75702 60,000
3-41
Hunt Tuscaloosa Refinery
Tuscaloosa
AL
35401
52,000
3-42
Western Four Corners Refinery
Gallup/Jamestown
NM
87347
40,000
3-43
Calcasieu Refinery
Lake Charles
LA
70605
32,000
3-44
Ergon Vicksburg Refinery
Vicksburg
MS
39183
25,000
3-45
AGE Refinery
San Antonio
TX
78205
13,500
Total
8,802,100
Source: Refiner publications.
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The U.S. Oil Refining Industry: Background in Changing Markets and Fuel Policies
Figure 5. Operable Refineries in PADD 4
PADD
# Facility
City
State Zip Bbl/day
4-01
Suncor Commerce City Refinery Complex
Commerce City
CO
80022
93,000
4-02
Sinclair Refinery
Sinclair
WY
82334
66,000
4-03 ExxonMobil
Billings Refinery
Billings
MT
59101
60,000
4-04
ConocoPhillips Billings Refinery
Billings
MT
59101
58,000
4-05
Tesoro Salt Lake City Refinery
Salt Lake City
UT
84103
58,000
4-06
CHS Laurel Refinery
Laurel
MT
59404
55,000
4-07
Frontier Cheyenne Refinery
Cheyenne
WY
82007
52,000
4-08
Chevron Salt Lake City Refinery
Salt Lake City
UT
84116
45,000
4-09
North Salt Lake Refinery
North Salt Lake
UT
84054
35,000
4-10
Hol y Woods Cross Refinery
Woods Cross
UT
84087
31,000
4-11
Sinclair Little America Refinery
Casper/Evansville
WY
82609
24,500
4-12 Wyoming
Refinery
Newcastle
WY
82701
14,000
4-13
Silver Eagle Woods Cross Refinery
Woods Cross
UT
84087
10,250
4-14
Montana Refining Company
Great Fal s
MT
59404
10,000
4-15
Silver Eagle Evanston Refinery
Evanston
WY
82930
3,000
Total
614,750
Source: Refiner publications.
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The U.S. Oil Refining Industry: Background in Changing Markets and Fuel Policies
Figure 6. Operable Refineries in PADD 5
PADD #
Facility
City
State
Zip
Bbl/day
5-01
Chevron El Segundo Refinery
El Segundo
CA
90245
269,000
5-02
BP Carson Refinery
Los Angeles
CA
90745
265,000
5-03
Chevron Richmond Refinery
Richmond
CA
94802
243,000
5-04
BP Cherry Point Refinery
Blaine
WA
98230
234,000
5-05
Flint Hills North Pole Refinery
North Pole
AK
99705
220,000
5-06
Valero Benicia Refinery
Benicia
CA
94510
170,000
5-07
Tesoro Golden Eagle Refinery
Martinez
CA
94553
166,000
5-08
Shel Martinez Refinery
Martinez
CA
94553
165,000
5-09
ExxonMobil Torrance Refinery
Torrance
CA
90509
150,000
5-10
Shel Puget Sound Refinery
Anacortes
WA
98221
145,000
5-11A
ConocoPhillips Los Angeles Refinery Complex/ Wilmington
Wilmington
CA
90744
139,000
5-11B
ConocoPhillips Los Angeles Refinery Complex/ Carson
Carson
CA
90745
5-12
Valero Wilmington Refinery
Wilmington
CA
90744
135,000
5-13A
ConocoPhillips San Francisco Refinery/Rodeo Facility
Rodeo
CA
94572
120,000
5-13B
ConocoPhillips San Francisco Refinery/Santa Maria Facility
Arroyo Grande
CA
93420
5-14
Tesoro Anacortes Refinery
Anacortes
WA
98221
120,000
5-15
ConocoPhillips Ferndale Refinery
Ferndale
WA
98248
100,000
5-16
Tesoro Los Angeles Refinery
Wilmington
CA
90744
97,000
5-17
Tesoro Hawai Refinery
Kapolei
HI
96707
93,500
5-18
Tesoro Kenai Refinery
Kenai
AK
99611
72,000
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The U.S. Oil Refining Industry: Background in Changing Markets and Fuel Policies
PADD #
Facility
City
State
Zip
Bbl/day
5-19
Alon Bakersfield Refinery
Bakersfield
CA
93308
70,000
5-20
Alon Paramount Refinery
Paramount
CA
90723
54,000
5-21
Chevron Kapolei Refinery
Kapolei
HI
96707
54,000
5-22
Petro Star Valdez Refinery
Valdez
AK
99686
50,000
5-23
US Oil Refinery
Tacoma
WA
98421
39,000
5-24
Kern Oil Bakersfield Refinery
Bakersfield
CA
93307
25,000
5-25
San Joaquin Refinery
Bakersfield
CA
93308
24,300
5-26
Petro Star North Pole Refinery
North Pole
AK
99705
17,000
5-27
ConocoPhillips Kuparuk Refinery
Kuparuk
AK
99734
14,400
Total 3,251,200
Source: Refiner publications.
Notes: The ConocoPhillips 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 ConocoPhillips Los Angeles Refinery Complex is composed of two facilities linked by a 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.
Refinery Capacity Distribution
A different picture of the refining industry base emerges when examining the distribution of
capacity. As Figure 7 shows, a quarter of U.S. refining capacity is concentrated in a few, larger
refineries, reflecting economies of scale that yield decreasing per barrel costs. For example, Royal
Dutch Shell PLC plans to double the size of the oil refinery it operates with a Saudi partner in
Port Arthur, Texas. This would make it the largest refinery in the United States and one of the
largest in the world.11 ConocoPhillips has plans to expand its Wood River Refinery in Illinois to
increase the volume of Canadian heavy crude it can handle, but has run into regulatory hurdles
over the use of best available technology under the Clean Air Act. Eleven of the 124 refineries
provide one quarter of total U.S. refining capacity. ExxonMobil operates the top two refineries
(with a combined capacity exceeding 1 million bbl/day), followed by BP, Petrovesa (PDV),
Sunoco, Chevron, Deer Park, and WRB.
11 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.
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Figure 7. Distribution of U.S. Refinery Capacity
Barrels per Calendar Day
600,000
500,000
400,000
300,000
1
200,000
9 17 25
100,000
33 41 49
0
57 65
7
2
1
1
1
5 r
7
1
re
re
re
e
f
f
f
f
i
i
i
i
n
n
n
n
e
e
e
e
r
r
r
r
ie
ie
ie
ie
s
s
s
s
Source: EIA Table 5. Refiners’ Total Operable Atmospheric Crude Oil Distillation Capacity as of January 1,
2009, as adjusted by CRS.
Notes: Each quartile represents roughly 4.7 million barrels per calendar day of total refining capacity.
These eleven refineries are among the largest and most complex in the United States, if not the
world, as their owners have added new processes to convert lower value residuum (formerly used
as heavy heating oil) to high-value gasoline. Typically, this involves adding fluid or delayed
cokers. European refineries, by comparison, employ less complex processes than U.S. refineries
on average, as they produce more diesel fuel. (For a further discussion of refinery complexity and
processes, refer to Appendix A.)
Changes in Crude Oil Supply and Demand
The crude oil input to U.S. refineries has decreased almost 8% compared to five years ago,
reflecting reduced demand for petroleum products. In 2009, refineries consumed an average 14.3
million barrels per day of crude oil. (Refer to Table 1.) Roughly one-third of this input was U.S.-
produced in 2009. The balance came from imports supplied by Canada, Saudi Arabia, Mexico,
Nigeria, Iraq, and other smaller producers (See Figure 8). Canada has become the United States’
leading crude oil supplier through its increasing production from oil sands.12
12 CRS Report RL34258, North American Oil Sands: History of Development, Prospects for the Future, by Marc
Humphries.
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Table 1. Refinery Crude Oil Input
(million barrels)
Annual
Input
Year Daily Annual Change
2004 15.5 5,663.9
2005 15.2 5,555.3
-108.6
2006 15.2 5,563.4
+8.1
2007 15.1 5,532.1
-32.3
2008 14.7 5,361.3
-170.8
2009 14.3 5,224.3
-137.0
Source: EIA Petroleum Navigator, Petroleum Supply Annual; Refinery and Blender Net Inputs of Crude Oil;
http://www.eia.doe.gov/oil_gas/petroleum/data_publications/petroleum_supply_annual/psa_volume1/
psa_volume1_historical.html.
Figure 8. U.S. Crude Oil Supply
2008
All Other
Suppliers
24%
U.S.
35%
Iraq
4%
Nigeria
6%
Canada
Mexico
Saudi
13%
8%
Arabia
10%
Source: Based on EIA U.S. Crude Oil Imports, June 29, 2009. http://tonto.eia.doe.gov/dnav/pet/
pet_move_impcus_a2_nus_epc0_im0_mbbl_a.htm
Over the last 25 years, the ºAPI gravity of imported crude oils has been decreasing while average
sulfur content has been increasing. ºAPI gravity, a measure developed by the American Petroleum
Institute, expresses the “lightness” or “heaviness” of crude oils on an inverted scale.13 With a
diminishing supply of light sweet (low sulfur) crude oil, U.S. refineries have had to invest in
multi-million dollar processing-upgrades to convert lower-priced heavier sour crude oils to high-
value products such as gasoline, diesel, and jet fuel. Refer to Table 2 for a comparison of various
crude oil ºAPI gravities and sulfur contents.
13 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.
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Table 2. ºAPI Gravity and Sulfur Content of Representative Crude Oils
Crude Oil
°API Gravity
%Sulfur
West Texas Intermediate
40
0.30
Alaska North Slope
29.5 – 29
1.10
Strategic Petroleum Reserve sweet/sour
40 – 30
0.5 – 2.0
NYMEX Deliverable Grade Sweet Crude Oil 42 – 37
<0.42
Canadian Sweet/Sour
37.7 – 37.5
0.42 – 0.56
Canadian Alberta Syncrude
38.7
0.19
Saudi Arabia Arab Extra Light / Heavy
37.2 – 27.4
1.15 – 2.8
Mexico Maya/Olmeca
39.8 – 22.2
0.80 – 3.30
Nigeria Bonny Light
33.8
0.30
Iraq Basra Light
34 –35
1.5
Venezuela Tia Juana Light/Heavy
31.8 – 18.2
1.16 – 2.24
North Sea Brent Blend
38 – 39
0.37
Source: NYMEX.
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.
Crude Oil Prices
The longstanding benchmark for pricing crude oil futures contracts traded on the New York
Mercantile Exchange (NYMEX) has been 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 Brent is typically refined in Northwest Europe, and also is exported to the U.S. Gulf and
East Coasts.
WTI on average is priced 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 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.16 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.17 According to OPEC, the basket crude has a 32.7º API gravity, making it heavier than
14Commodity Online, http://www.commodityonline.com/commodities/energy/brentcrudeoil.php.
15 On a daily basis the pricing relationships between these can vary greatly.
16 PetroStrategies, http://www.petrostrategies.org/Graphs/OPEC_Basket_Crude_Oil_Prices.htm.
17 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).
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The U.S. Oil Refining Industry: Background in Changing Markets and Fuel Policies
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 heavier, sourer 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 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 2008.18 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
and into 2010.
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.19
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.20
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.21 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. 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.
The multiplicity of oil prices, which reflect the quality of various crude oils, further complicates
the linkage between oil prices and the 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.
18 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.
19 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).
20 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.
21 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
Table 3. Light/Heavy Crude Oil Price Spread
$ per barrel
Year Spread
2006 15.51
2007 12.88
2008 14.85
2009 5.60
Source: Energy Information Administration.
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. In February of 2009, the price-spread declined to a low of $1.93 per barrel, and stayed
below $9 per barrel every month in 2009. By September of 2010 the price-spread was $7.95 per
barrel.
Demand Conditions
The demand for crude oil is derived from the demand for petroleum products. For example, if
consumers demand more gasoline, refiners may 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. (Refer to Appendix A for a discussion of refining fundamentals.)
The demand for gasoline itself may depend 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 for gasoline are in the range of -0.25
or less.22 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 make 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 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
22 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
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, an 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% the following
year, as Table 4 shows.
Table 4. United States Gasoline Consumption 2006-2009
(million barrels per year)
Change
Change
Year Consumption volume
percent
2006 3,377.2
2007 3,389.3
12.1 0.35%
2008 3,290.1
-99.0 -2.90%
2009 3,280.0
-10.1 -0.30%
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 3% reduction in gasoline demand, as experienced during the 2007-2008 recession
years, may seem minor compared to 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 faces today.
In the longer term, even when income growth returns, 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.
Profitability
There are 45 firms refining petroleum in the United States. The top 10 refiners—Valero, Conoco
Phillips, ExxonMobil, BP, Shell, Marathon, Chevron, Flint Hills, Citgo, and Sunoco—account for
more than 75% of total U.S. refining capacity, as shown in Figure 9. The top ten firms operate
half of the U.S. fuel refineries, a combined 68 out of 124 refineries (including currently idled
refineries).
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Figure 9. Major Refiners by Capacity
Barrels per Calendar Day
0
500,000
1,000,000
1,500,000
2,000,000
2,500,000
Valero (12)
2,310,000
ConocoPhillips (13)
2,226,400
Exxon/Mobil (7)
2,065,500
BP (5)
1,539,000
Shell (7)
1,470,000
Marathon (7)
1,188,000
Chevron (6)
1,021,000
Flint Hills (4)
840,000
Citgo (3)
770,000
Sunoco (3)
685,000
Source: CRS compiled from refiner published information, August 2010.
Notes: Figures in parenthesis indicate number of refineries owned. The top ten refiners represent roughly 75%
of the total fuel refining capacity, some 18.5 million barrels per calendar day. This excludes topping and
lubricating oils. The privately held Koch Industries owns Flint Hills Resources. The Venezuelan oil company
Petrovesa owns Citgo.
The top six integrated oil companies—ConocoPhillips, ExxonMobil, BP, Shell, Marathon, and
Chevron—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. The top six integrated firms plus the top two independent refiners
and marketers also make up over 50% of U.S. refining capacity, and control the largest
refineries.23
Their overall financial performance offers a measure of the profitability in refining and marketing
in general. The comparative financial performance for the period 2006 through 2009 is presented
in Table 5. The decline in net income over the period is attributable to several factors, including
the combination of high crude oil prices and weak demand. The high inventories of gasoline and
diesel fuel depressed product prices relative to the cost of crude oil, which further reduced
refining profit margins.24 In addition, the narrowing price spread between light and heavy crude
reduced the refining margin and contributed to earlier capital investments failing to generate
expected returns.
Table 5. Refiners’ Net Income, 2006-2009
(million dollars)
Company
2006 2007 2008 2009
ExxonMobil
8,454 9,573 8,151 1,781
23 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.
24 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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Company
2006 2007 2008 2009
BP
5,667 3,569 4,176 4,517
Shel
6,989 6,624 446 3,054
ConocoPhillips 4,481 5,923 2,322
37
Chevron
3,973 3,502 3,429 565
Marathon
2,795 2,077 1,179 464
Valero
5,461 5,234 -1,131 -1,982
Sunoco
979 891 776 -329
Source: Oil Daily, Profit Profile Supplements, various issues, 2007-2010.
Notes: Data in the table is downstream net income, which includes income derived from refining and marketing.
Privately owned Flint Hills and Venezuelan owned Citgo do not publish financial reports.
All six of the major integrated oil companies have experienced mixed returns, but in all cases,
their net incomes in 2009 were lower than in 2006. Valero and Sunoco, independent refiners and
marketers, experienced losses.
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, or regulatory
compliance. Facility expansion and new technology implementation are indicators that the
industry expects increasing demand and economic growth.
Capital improvement and expansion require that an initial outlay of funds in the current time-
period be offset by earnings that might accrue far into the future. If this stream of appropriately
discounted future earning is greater than the initial outlay, then a capital investment project
qualifies for inclusion in the capital budget.25 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.
Capital spending in the U.S. refining sector has been declining, as Table 6 shows. A 22% decline
from 2008 through 2009 is expected to be followed by an almost 50% decline from 2009-2010.
Combined with refinery closures discussed in this report, this data suggests that the industry does
not see a need to expand, or even maintain, production capacity in the United States.
Table 6. U.S. Refining Industry Capital Budget Expenditures, 2008-2010
(billions of dollars)
Year
2005 2006 2007 2008 2009 2010
Expenditure 7.2 9.0 8.3 13.0 10.1 5.3
Source: Oil and Gas Journal, Week of March 1, 2010, p. 26.
25 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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The U.S. Oil Refining Industry: Background in Changing Markets and Fuel Policies
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 has also been rising. Oil companies can
meet the demand for petroleum products, such as gasoline, in three basic ways. They can build
new 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.
Alternatively, an oil company can expand the capacity 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 can
usually be brought on line faster than new refineries due to simplified permitting requirements,
but have the disadvantage of augmenting capacity in smaller steps.
Instead of investing in new refineries or expanding existing ones, an oil company might choose to
meet petroleum product demand by importing finished, or partially finished, products from other
areas of the world. The advantage of this approach is twofold. The imported products can be
introduced, relatively quickly, into the domestic market with no requirement for additional capital
spending. The imports can be easily expanded, or contracted, should the need arise. Reliance on
foreign sources for petroleum products as well as crude oil adds an additional dimension to
concerns of energy dependence, even though prices of these products may 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 2004-2009 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 and
2009. Adjustments in imports to reflect reduced demand are likely to be accomplished with fewer
losses in domestic employment and economic dislocations than refinery closures.
Table 7. Gasoline Imports Vs. Total Gasoline Supplied
(Thousand Bbl/Day)
Product
2004 2005 2006 2007 2008 2009
Finished Motor Gasoline Imports
496
603 475
413
302
223
Motor Gasoline Blending Component Imports
451 510 669 753 789 719
Total Gasoline Imports Subtotal
947 1,113
1,126 1,166 1,091
942
Total Finished Motor Gasoline Supplied
9,105 9,159
9,253 9,286 8,989 8,997
Total
Petroleum
Product
Imports
3,057 3,588 3,589 3,437 3,132 2,678
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/
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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.
Tax Considerations26
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.27 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.28 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, 2008.29 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
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.30 Since the provision is
temporary, there is an incentive to speed up the investment in refinery capacity so as to qualify for
the tax incentive. Nevertheless, the incentive to speed up investment is limited, because the
effective price discount is small. Investing in excess capacity that would not otherwise be
desirable would either leave the plant idle or provide too much output and lower prices and
profits for a period of time. The latter cost should be at least as big as the cost of remaining idle.
26 Molly Sherlock, Analyst in Economics, contributed to this section of the report.
27 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.
28 For additional background information on energy tax issues, see CRS Report R40999, Energy Tax Policy: Issues in
the 111th Congress, by Molly F. Sherlock and Donald J. Marples and CRS Report R41227, Energy Tax Policy:
Historical Perspectives on and Current Status of Energy Tax Expenditures, by Molly F. Sherlock.
29 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.
30 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.
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With a 5% price 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.31
Table 8. Tax Expenditures for Provisions Allowing Partial Expensing of Refinery
Investments
billions of dollars
2008 2009 2010 2011 2012 2013
Revenue
Loss 0.4 0.5 0.7 0.8 0.7 0.6
Source: Joint Committee on Taxation
Notes: Tax expenditures are estimate federal revenue losses associated with special tax provisions.
Policy Considerations
The conventional gasoline refined today has changed considerably since the Clean Air Act of
1970 prohibited lead additives, and later amendments created demand 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.
(Other properties such as Reid Vapor Pressure, octane, and cetane are discussed in Appendix A.)
Reformulated Gasoline
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.”32 Cities with the worst smog pollution are required to reduce harmful
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. It also
contains chemical oxygen, known as oxygenate, to improve combustion.
Since the Clean Air Act Amendments, a growing number of distinct types of gasoline (“boutique
fuels”) have entered the supply chain. Currently, 15 distinctly formulated boutique fuels are
required in portions of 12 states (see Figure 10). In addition to the federal RFG standards, State
Implementation Plans to improve air quality require low-Reid Vapor Pressure conventional
31 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.
32 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
enactment of the 1990 Amendments, except for certain “nonclassifiable” areas (56 FR 56694,(1) November 6, 1991).
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gasoline (referred to as “low-RVP”). (Refer to Appendix B for a discussion of RVP and other fuel
properties.) California mandates a cleaner fuel than federal RFG (referred to as California RFG,
or CaRFG), and the Midwestern states require a unique ethanol-blended RFG.
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.”33 The prospect that more refineries may
sit idle or permanently close due to decreased demand could further reduce that flexibility.
Figure 10. Map of Reformulated Gasoline Areas
Source: EPA.
Notes: Currently, 12 states have 15 boutique fuels. Alaska and Hawai do not have RFG areas.
To reduce the proliferation of boutique fuels, the 2005 Energy Policy Act34 amended the Clean
Air Act (in 42 U.S.C. 7545) by limiting them to the number existing as of September 1, 2004.
H.R. 392, the Boutique Fuel Reduction Act of 2009, would further amend the Clean Air Act
Section 211(c)(4)(C)(ii)II) to add temporary waivers for unexpected problems with distribution or
delivery equipment necessary for transporting fuel or fuel additives. Amendments to Section
211(c)(4)(C) would give the EPA Administrator authority to reduce the number of boutique fuels
after determining that a particular fuel is no longer included in a state implementation plan or is
identical to a federally approved fuel.
Between 1992 and 2005, EPA also mandated oxygenated fuel blends 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 tertiary-butyl ether (MTBE) as the oxygenate in almost all RFG outside of
33 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.
34 Subtitle C—Boutique Fuels Sec. 1541. Reducing the Proliferation of Boutique Fuels.
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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.35 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) 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 Program /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, at least, offsetting an increasing demand for transportation fuel. Now, though, the
prospect of declining motor-fuel demand may mean that the use of more renewable fuels may
influence operators to idle, consolidate, or permanently close refineries.
Congress created the Renewable Fuel Program under Title XV of the Energy Policy Act of 2005
(EPAct─P.L. 109-58) to substitute increasing volumes of renewable fuel for gasoline. The U.S.
Environmental Protection Agency (EPA) has the statutory authority for administering the
National Renewable Fuel Standard (RFS) program. The act set a target production volume of 7.5
billion gallons of renewable fuels for calendar year 2012. The 2007 Energy Independence and
Security Act (EISA) 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).
Table 9. EISA Renewable Fuel Volume Requirement
Total
Total
Cellulosic
Biomass-
Advanced
Renewable
Renewable
Biofuel
based Diesel
Biofuel
Fuel
Fuel
Requirement Requirement Requirement Requirement Requirement
Billion
Billion
Billion
Billion
Million
Year
Gallons
Gallons
Gallons
Gallons
Barrels
2008 n/a
n/a
n/a
9.00 214
2009 n/a
0.50 0.60 11.10 264
2010 0.10 0.65 0.95 12.95
308
2011 0.25 0.80 1.35 13.95
332
2012 0.50 1.00 2.00 15.20
362
2013 1.00 a 2.75
16.55
394
2014 1.75 a 3.75
18.15
432
2015 3.00 a 5.50
20.50
488
2016 4.25 a 7.25
22.25
530
2017 5.50 a 9.00
24.00
571
35 Environmental Protection Agency, Status and Impact of State MTBE Bans, http://www.eia.doe.gov/oiaf/servicerpt/
mtbeban/pdf/mtbe.pdf.
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Total
Total
Cellulosic
Biomass-
Advanced
Renewable
Renewable
Biofuel
based Diesel
Biofuel
Fuel
Fuel
Requirement Requirement Requirement Requirement Requirement
Billion
Billion
Billion
Billion
Million
Year
Gallons
Gallons
Gallons
Gallons
Barrels
2018 7.00 a 11.00
26.00
619
2019 8.50 a 13.00
28.00
667
2020 10.50 a 15.00
30.00
714
2021 13.50 a 18.00
33.00
786
2022 16.00 a 21.00
36.00
857
2023+
b
b
b
b
Source: EPA Renewable Fuel Standard http://www.epa.gov/otaq/fuels/renewablefuels/
Notes: 1 barrel = 42 gallons.
a. To be determined by EPA through a future rulemaking, but not less than 1.0 billion gallons.
b. To be determined by EPA through a future rulemaking.
The 2010 requirement of nearly 13 billion gallons of renewable fuels represents more than 9% of
2009 gasoline consumption.
Under current EPA rules, ethanol is blended up to 10% by volume in retail gasoline (E10) and
85% in E85 fuel for use in flex-fuel vehicles (FFV). On October 13, 2010, the EPA partially
granted Growth Energy’s waiver request application submitted under section 211(f)(4) of the
Clean Air Act.36 The partial waiver allows the sale of gasoline that contains ethanol up to 15% by
volume (E15) for use in 2007 and newer model year vehicles. EPA denied the waiver to use E15
in vehicles older than model year 2000, and is deferring a decision on using E15 in model years
2001 through 2006. The E15 fuel must be sold from a separate pump, as is E85. The new ruling
would appear to be at odds with the EPAct 2005 provision that limits the proliferation of boutique
fuels.
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.
36 EPA, Partial Grant and Partial Denial of Clean Air Act Waiver Application Submitted by Growth Energy to
Increase the Allowable Ethanol Content of Gasoline to 15 Percent; Decision of the Administrator, October 13, 2010,
http://www.epa.gov/otaq/regs/fuels/additive/e15/e15-waiver-decision.pdf.
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Subsidies and/or Tax Breaks for Renewable Fuel
Some of the federal subsidies and tax breaks favoring ethanol production were reduced by Title
XV of the Food, Conservation and Energy Act of 2008 (P.L. 110-246). The ethanol blender tax
credit of $0.51 per gallon (which applies to all ethanol blends, including imports) was reduced to
$0.45 per gallon in January 2009 under Section 15331 of the act. The $0.54 per gallon import
tariff on ethanol, which effectively offsets the blender tax credit when imported ethanol is
blended into gasoline in the United States, is set to expire at the end of 2010 under Section 15333
of the act.
Under the strong motor fuel demand conditions that existed when the Food, Conservation, and
Energy Act was passed, ethanol was considered to be a means of extending the volume of refined
transportation fuels, particularly after the elimination of MTBE. Since then, ethanol has begun to
displace refined fuel, albeit under subsidy. If the renewable fuel volume mandate is met by 2022,
and the $0.45 per gallon subsidy were to remain in place, the RFS goal of 857 million barrels
could represent a $16.2 billion annual subsidy to displace 564 million barrels of refined gasoline
(on an energy equivalent basis).37
Carbon Emissions/Greenhouse Gas Rules
In 2007, the United States Supreme Court ruled that EPA has the authority under the Clean Air
Act to regulate carbon dioxide (CO2) emissions from automobiles, and directed EPA to conduct a
thorough scientific review.38 After the ordered review, EPA issued a proposed finding, in April
2009, that greenhouse gases contribute to air pollution that may endanger public health or
welfare.39 Though the finding pertained to automobile emissions, it has wide ranging
implications.
In response to the FY2008 Consolidated Appropriations Act (H.R. 2764; P.L. 110-161), EPA
issued the Mandatory Reporting of Greenhouse Gases Rule.40 The rule requires suppliers of fossil
fuels or industrial greenhouse gases, manufacturers of vehicles and engines, and facilities that
emit 25,000 metric tons or more per year of GHG emissions to submit annual reports to EPA.41
The rule includes final reporting requirements for 31 of the 42 emission sources listed in the
proposal. EPA plans to finalize additional source categories listed in the proposal in 2010. The
rule establishes the basis for future legislation and regulations that could cap GHG emissions
from refineries as well as other industrial sources.
37 Assumes that one barrel of refined crude oil can yield up to 46% gasoline.
38 Massachusetts et al. v. Environmental Protection Agency, 549 U.S. 497 (Supreme Court of the United States, April
2, 2007).
39 The Proposed Endangerment and Cause or Contribute Findings for Greenhouse Gases under the Clean Air Act was
signed on April 17, 2009. On April 24, 2009, the proposed rule was published in the Federal Register
(www.regulations.gov) under Docket ID No. EPA-HQ-OAR-2009-0171.
40 The final rule was published in the Federal Register (www.regulations.gov) under Docket ID No. EPA-HQ-OAR-
2008-0508-2278. The rule became effective December 29, 2009.
41 The gases covered by the proposed rule are carbon dioxide (CO2), methane (CH4), nitrous oxide (N2O),
hydrofluorocarbons (HFC), perfluorocarbons (PFC), sulfur hexafluoride (SF6), and other fluorinated gases including
nitrogen trifluoride (NF3) and hydrofluorinated ethers (HFE).
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The American Clean Energy and Security Act of 2009
H.R. 2454─The American Clean Energy and Security Act of 2009 (passed in the House June 26,
2009) would amend the Clean Air Act by establishing a “cap-and-trade” system designed to
reduce greenhouse gas emissions (GHG) and would cap emissions from refineries and allow
trading of emissions permits (“allowances”). Over time, H.R. 2454’s provisions would reduce the
cap to 83% of current emissions, forcing industries to reduce emissions by that amount (cap) or
purchase allowances from others who would have reduced emissions more than required or
offsets from eligible entities not covered by the cap (trade). The bill would allocate the refining
industry only 2% of the total emission allowances for the entire U.S. economy.
Petroleum refineries emit approximately 205 million metric tons of CO2 annually, which
(according to the new EPA rule) represents approximately 3% of the U.S. GHG emissions. The
cost of complying with the new EPA rule could be minimal, but the cost of complying with “cap
and trade” provisions of H.R. 2454 or similar legislation could be disruptive to the refining
industry according to recent analyses by the consulting firm Wood Mackenzie and the Energy
Policy Research Foundation, Inc.42
As proposed, H.R. 2454 would require U.S. refiners to purchase emission credits for both their
stationary emissions and the subsequent combustion of their fuels (predominantly consumed in
the transportation sector). U.S. refiners could face competitive disadvantages with refined
petroleum products imported from countries where refinery greenhouse-gas emissions are treated
differently. In Wood McKenzie’s analysis, U.S. refiners would need to purchase roughly 2,000
million credits in 2015, whereas European Union refiners who export their products
(predominantly gasoline) to the United States would only need to purchase 3 million allowances.
Clean Energy and Oil Accountability Act of 2010
S. 3663, introduced in August 2010, would establish a Natural Gas Vehicle and Infrastructure
Development Program to promote natural gas as an alternative transportation fuel in order to
reduce domestic oil use (see Title XX—Natural Gas Vehicle And Infrastructure Development).
The program would also offer incentives to convert or repower conventionally fueled vehicles to
operate on compressed natural gas (CNG) or liquefied natural gas (LNG).43
Natural gas is abundant in the United States and has already been introduced as a transportation
fuel for intra-city buses, principally as means of reducing air emissions. U.S. automobile
manufactures marketed passenger vehicles modified to run on compressed natural gas in the
1990s. 44
U.S refineries currently produce 1,386.5 million barrels of diesel fuel annually. Approximately
5.3 trillion cubic feet (tcf) of natural gas would be needed to replace this fuel, as S. 3663
42 Alan Gelder, The (potentially) Disruptive Impact of Carbon on US Refiners, Wood Mackenzie, October 27, 2009,
http://www.woodmacresearch.com/cgi-bin/wmprod/portal/energy/highlightsDetail.jsp?oid=1611276.
43 The provision shares objectives similar to the Pickens Plan, which proposes to shift over-the-road trucks and
municipal buses from diesel fuel to natural gas. http://www.pickensplan.com.
44 For further information refer to CRS Report RS22971, Natural Gas Passenger Vehicles: Availability, Cost, and
Performance, by Brent D. Yacobucci.
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proposes.45 In 2008, the United States produced 20.8 tcf of natural gas. To displace its diesel fuel
with natural gas, the United States would need to increase natural gas production by more than
25%. This does not take into consideration policies aimed at replacing coal-based electricity
generation with natural gas, nor any lost efficiency in converting diesel engines to natural gas.
A refined barrel of 35º API crude can yield about five gallons of diesel fuel, or 12% of the barrel.
Displacing all diesel fuel consumption with natural gas represents about two million bbl/day in
refining capacity. Refineries cannot cut back diesel production without cutting back on
production of gasoline and other refined products. Assuming no decreased gasoline demand,
refiners would likely export the excess diesel or market it as heating oil.
Vehicle Efficiency/Mileage Rules
The 2007 Energy Independence and Security Act (EISA) amended the “corporate average fuel
efficiency” (CAFE) standards. By 2020, a manufacturer’s combined fleet of passenger and non-
passenger vehicles must achieve an average 35 mpg. The American Council on an Energy-
Efficient Economy estimates that the new standard will save 2.4 million bbl/d by 2030, the
equivalent of 13% of the current U.S. refinery output. The EPA and the National Highway
Transportation Safety Administration (NHTSA) recently published final rules to implement the
first phase of these new standards. Further, they have announced their intention to improve fuel
efficiency and reduce greenhouse gas (GHG) emissions for commercial trucks and to adopt the
second phase of GHG and fuel economy standards for light-duty vehicles.
Economists have recognized that improving energy efficiency releases an economic reaction that
partially offsets the original energy savings, a “rebound effect.”46 According to the National
Highway Traffic Safety Administration (NHTSA),
improving a vehicle’s fuel economy reduces its fuel cost per mile driven. In response to the
reduced per-mile cost of driving a more fuel-efficient vehicle, some buyers will increase the
amount of driving they do, although the precise magnitude of this response is uncertain. Thus
imposing stricter fuel economy standards can increase the annual number of miles driven .”47
Research on the magnitude of the rebound effect in light-duty vehicles dating to the early 1980s
concluded that a statistically significant rebound effect occurs when vehicle fuel efficiency
improves.48
45 The heat content of diesel fuel (139,000 Btu per gallon) refined in 2008 (1,386.5 million barrels) is roughly: (Eq. 1)
0.67 × 1,386.5 million bbls × 42 gal./ bbl × 139,000 Btu/gal × therm/100,000 Btu = 5.423 therms. The equivalent
volume of natural gas (1,028 Btu per cubic foot) needed to replace the diesel fuel is: (Eq. 2) 5,423,239 million Btu ÷
1,028 Btu/ ft3 = 5,275.5 million cubic feet.
46 Kenneth Small and Kurt Van Dender, The Effect of Improved Fuel Economy on Vehicle Miles Traveled: Estimating
the Rebound Effect Using U.S. State Data, 1966-2001, University of California Energy Institute, Policy and Economics
Series, UC Berkeley, CA, September 21, 2005, http://escholarship.org/uc/item/1h6141nj.
47 National Highway Traffic Safety Administration, Corporate Average Fuel Economy Compliance and Effects
Modeling, DOT HS 811 112, April 2009, p. 24, http://www.nhtsa.gov/DOT/NHTSA/Traffic%20Injury%20Control/
Articles/Associated%20Files/811112.pdf.
48 National Highway Traffic Safety Administration, Corporate Average Fuel Economy for MY2012-MY2016 Passenger
Cars and Light Trucks, August 2009, p. 355, http://www.nhtsa.gov/DOT/NHTSA/Rulemaking/Rules/
Associated%20Files/MY2012-2016_CAFE_PRIA.pdf.
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Mathematically, the rebound effect is equal to the elasticity of average vehicle use with respect to
fuel cost per mile driven, although the rebound effect is customarily expressed as a positive
percentage. NHTSA found that two-thirds of all rebound estimates it reviewed fell in the range of
10% to 30%.49 NHTSA also cited recent evidence “that the rebound effect has been declining
over time, and may decline even further over the immediate future if income rises faster than
gasoline prices.” In light of the various study results NHTSA reviewed, it elected to use a 10%
rebound effect in its analysis of fuel savings and other benefits from higher CAFE standards for
MY2012-MY2016 vehicles. The EPA has chosen a more conservative 5% effect.
Will rebound—that is, increased driving—stimulate additional demand for refined petroleum
products, or will renewable fuel mandates offset the demand? The legal mandate for increased
ethanol consumption further complicates the effort to improve vehicle fuel efficiency. For
example, on the basis of energy content it would take roughly 1.39 gallons of E85 to move a
vehicle the same distance as one gallon of gasoline.50
With EPA’s partial Clean Air Act waiver allowing the sale of E15, drivers may see further
decreases in vehicles’ advertised mile-per-gallon (MPG) ratings. The blend wall increase may
further challenge automobile manufacturers to meet the new CAFE standards and possibly erode
demand for refined products.
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.
More urgently, the refining industry faces structural challenges from recent government
regulations that aim at directly reducing the demand for the industry’s output. Higher gas mileage
standards for automobiles, increased ethanol content in gasoline blends, and the expansion in the
use of pure bio-fuels 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.
These policies were intended, in part, to accommodate the growing demand for refined petroleum
products. Now, though, the prospect of declining motor-fuel demand means that the 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
49 NHTSA, August 2009, p. 356
50 E85 has 81,800 BTUs/gal) compared to gasoline’s 114,100 BTUs/gal.
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such adjustments occur, Congress may wish to monitor competitive conditions in oil refining, and
in particular the impact of consolidation on the prices and less choice facing consumers.
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Appendix A. Petroleum and Refining Fundamentals
Crude oil contains natural components in the boiling range of gasoline, kerosene/jet fuel and
diesel fuel. A typical 35° API crude, oil as shown in Figure A-1, might contain 27% of the
hydrocarbons in the range of gasoline and 13% of the hydrocarbons in the range of kerosene and
jet fuel. Average crude oils tend to have more paraffin in the gasoline range and more aromatics
and asphaltic in the residuum.
Figure A-1. 35° API Crude Oil Composition
Gasoline 27%
Kero/Jet 13%
Diesel 12%
%
Gas Oil 10%
Lube Oil 20%
Residuum
18%
Source: Petroleum Geochemistry and Geology, 1979.
Notes: For illustrative purposes only. Does not represent a specific crude oil assay.
A conventional refinery distills crude oil into various fractions, according to boiling point range,
before further processing. In order of their increasing boiling range and density, the distilled
fractions are:
Table A-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 range of C5 toC10; middle-
distillate fuels like kerosene, jet, and diesel range from C11 to C18.
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Crude oil may contain 10%-40% gasoline, and early refineries directly distilled a straight-run
gasoline (light naphtha) of low-octane rating.51
A hypothetical refinery may “crack” a barrel of crude oil into two-thirds gasoline and one-third
distillate fuel (kerosene, jet, and diesel), depending on the refinery’s configuration, the slate of
crude oils refined, and the seasonal product demands of the market.52
Conventionally refined gasoline, diesel, and jet fuels are complex mixtures of hydrocarbons that
include paraffins, naphthenes, and aromatics (which give fuel its unique odor).53
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 (see
Figure A-2), 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.
51 Octane number refers to the gasoline property that reduces detrimental knocking in a spark-ignition engine. In early
research, iso-octane (C8-length branched hydrocarbon molecules) caused the least knock and was rated 100. Cetane
number refers to a similar property for diesel fuel, for which normal hexadecane (C16H34) is the standard molecule.
52 The term “crack spread” refers to the 3-2-1 ratio of crude-gasoline-distillate. The crack spread and the 3-2-1 crack is
a hypothetical calculation used by the New York Mercantile Exchange for trading purposes.
53 James H. Gary and Glenn E. Handwerk, Refining Petroleum—Technology and Economics, 4th Ed., Marcel Dekker,
Inc., 2001.
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Figure A-2. Distillation Column
Source: CRS.
Distillation Unit: Heats crude oil until it boils 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.
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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.
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 sale as end-use products.
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; see Table A-2. 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.
Table A-2. Refinery Types and Process
Refinery Type Processes
Complexity
Coking
Add coking/resid destruction (delayed coking process)
9
to run medium/sour crude oil.
Cracking
Add vacuum distillation and catalytic cracking process
5
to run light sour crude to produce light and middle
distillates.
Hydroskimming Atmospheric distillation, naphtha reforming and
2
desulfurization process to run light sweet crude and
produce gasoline.
Topping
Separate crude oil into constituent petroleum products
1
by atmospheric distillation; produce naphtha but no
gasoline.
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).54 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 more producing diesel fuel.
54 Oil & Gas Journal, 2006 U.S. Refining Survey, December 19, 2005.
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A typical refinery yields a limited supply of jet and diesel fuel depending on the type of crude oil
processed, see Figure A-3. Gulf Coast (Texas and Louisiana) may yield up to 8% jet fuel, and
over 30% diesel. These refineries have an average complexity of 12 to 13, which is above the
national average of 9.5.
Figure A-3. Gulf Coast Refinery Yields
Percent (%)
100
90
80
39.9
36.8
48.1
44.9
70
Gasoline
t
60
n
e
8.2
6.7
Kerosene/Jet
50
rc
9.7
7.8
8.1
Diesel
Pe
40
24.7
Fuel Oil
30
30.9
39.6
20
41.6
23.7
10
9.8
4.5
0
West Texas
Arab Light
Arab Heavy
Nigerian Bonny
Intermediate
Light
Source: Data used from Energy Intelligence, The International Crude Oil Refining Handbook, 2007.
http://www.energyintel.com
Notes: Winter yields shown.
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Appendix B. 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 varies from 8.7 in the summer to 11.5
in the winter.
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 iso-
octane, which arbitrarily received a rating of 100.55 Isooctane refers to a branched “isomer” in the
paraffin series having eight carbons (C8H18).56 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 n-
hexadecane. 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-per-
million (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
55 John M. Hunt, Petroleum Geochemistry and Geology, W. H. Freeman and Co., 1979. p. 51.
56 Or more correctly 2,2,4-trimethylpentane.
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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
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 about 90 ppm in 2005.
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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Appendix C. Glossary
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 VV-
G-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 the “gasohol waiver”).
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Author Contact Information
Anthony Andrews
Molly F. Sherlock
Specialist in Energy and Defense Policy
Analyst in Economics
aandrews@crs.loc.gov, 7-6843
msherlock@crs.loc.gov, 7-7797
Robert Pirog
Specialist in Energy Economics
rpirog@crs.loc.gov, 7-6847
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