Oil Shale: History, Incentives, and Policy

Oil Shale: History, Incentives, and Policy

Order Code RL33359
CRS Report for Congress
Received through the CRS Web
Oil Shale: History, Incentives, and Policy
April 13, 2006
Anthony Andrews
Specialist, Industrial Engineering and Infrastructure Policy
Resources, Science, and Industry Division
Congressional Research Service ˜ The Library of Congress

Oil Shale: History, Incentives, and Policy
Summary
Oil shale is prevalent in the western states of Colorado, Utah, and Wyoming.
The resource potential of these shales is estimated to be the equivalent of 1.8 trillion
barrels of oil in place. Retorted oil shale yields liquid hydrocarbons in the range of
middle-distillate fuels, such as jet and diesel fuel. However, because oil shales have
not proved to be economically recoverable, they are considered a contingent resource
and not true reserves. It remains to be demonstrated whether an economically
significant oil volume can be extracted under existing operating conditions. In
comparison, Saudi Arabia reportedly holds proved reserves of 267 billion barrels.
Federal interest in oil shale dates back to the early 20th Century, when the Naval
Petroleum and Oil Shale Reserves were set aside. Out of World War II concerns for
a secure oil supply, a Bureau of Mines program began research into exploiting the
resource. Commercial interest followed during the 1960s. After a second oil
embargo in the 1970s, Congress created a synthetic fuels program to stimulate large-
scale commercial development of oil shale and other unconventional resources. The
federal program proved short-lived, and commercially backed oil shale projects
ended in the early 1980s when oil prices began declining.
The current high oil prices have revived the interest in oil shale. The Energy
Policy Act of 2005 (EPACT) identified oil shale as a strategically important domestic
resource, among others, that should be developed. EPACT also directed the
Secretary of Defense to develop a separate strategy to use oil shale in meeting
Department of Defense (DOD) requirements when doing so is in the national interest.
Tapping unconventional resources, such as oil shale, has been promoted as a means
of reducing dependence on foreign oil and improving national security.
Opponents of federal subsidies for oil shale argue that the price and demand for
crude oil should act as sufficient incentives to stimulate development. Projections
of increased demand and peaking petroleum production in the coming decades tend
to support the price-and-supply incentive argument in the long term.
The failure of oil shale has been tied to the perennially lower price of crude oil,
a much less risky conventional resource. Proponents of renewing commercial oil
shale development might also weigh whether other factors detract from the resource’s
potential. Refining industry profitability is overwhelmingly driven by light passenger
vehicle demand for motor gasoline, and oil-shale distillate does not make ideal
feedstock for gasoline production. Policies that discourage the wider use of middle-
distillates as transportation fuels indirectly discourage oil shale development.
Because the largest oil shale resources reside on federal lands, the federal
government would have a direct interest and role in the development of this resource.
This report will be updated as new developments occur.

Contents
Introduction . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1
Geology and Production Technology of Oil Shale . . . . . . . . . . . . . . . . . . . . . . . . 3
Kerogen . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3
Conventional Refining . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4
Synthetic Fuel Production . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5
Oil Shale Retorting . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6
Shell In Situ Conversion Process . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 7
Oil Tech Above-Ground Retorting . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8
History of Oil Shale Development . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8
Early Synthetic Liquid Fuels Efforts . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8
Defense Department Programs . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 9
Department of Energy Synthetic Fuels Program . . . . . . . . . . . . . . . . . . . . . 10
U.S. Synthetic Fuels Corporation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10
Renewed Interest in Oil Shale . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 12
Incentives and Disincentives to Development . . . . . . . . . . . . . . . . . . . . . . . . . . . 13
The Cost of Constructing an Oil Shale Facility . . . . . . . . . . . . . . . . . . . . . . 15
The Ideal Size for an Oil Shale Facility . . . . . . . . . . . . . . . . . . . . . . . . . . . . 16
Competing with Imported Distillates . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 18
Regulatory Disincentives . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 20
Diesel Vehicle Demand . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 20
CO, NOx, and PM Emissions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 21
Ultra-Low Sulfur Diesel . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 22
Fuel Tax . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 23
Policy Perspective and Consideration . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 25
Appendix: Legislative History . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 27
List of Figures
Figure 1. Distribution of Oil Shale in the Green River Formation of Colorado,
Utah, and Wyoming . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2
Figure 2. Refiner Acquisition Cost of Imported Crude Oil . . . . . . . . . . . . . . . . 14
Figure 3. Refinery Capacity Distribution Above and Below Median 80,000
BPD Size . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 17
Figure 4. Imported Crude Oil and Refined Products . . . . . . . . . . . . . . . . . . . . . 19
Figure 5. Net Deliveries vs. Refinery Output of Gas/Diesel Oil for
OECD Europe . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 21
Figure 6. Diesel vs Gasoline Fuel Tax . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 24
List of Tables
Table 1. Properties of Oil-Shale Distillates Compared with Benchmark
Crude Oils . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 7

Oil Shale: History, Incentives, and Policy
Introduction
Projections that peak petroleum production may occur in the coming decades,
along with increasing global demand, underscore the United States’ dependence on
imported petroleum. After Hurricanes Katrina and Rita, the spike in crude oil price
and the temporary shutdown of some Gulf Coast refineries exacerbated that
dependency. With imports making up 65% of the United States’ crude oil supply
and the expectation that the percentage will rise, proponents of greater energy
independence see the nations’s huge but undeveloped oil shale resources as a
promising alternative.1
Oil shales are prevalent throughout the United States. Their kerogen content
is the geologic precursor to petroleum. The most promising oil shale resources occur
in the Green River formation that underlies 16,000 square miles of northwestern
Colorado, northeastern Utah, and southwestern Wyoming (Figure 1). Approximately
72% of the land overlying the Green River Formation is federally held.2 The
formation is estimated to contain more than 8 trillion barrels of shale oil in place;
however, much of the formation has been considered too thin, too deep, or too low
in yield to economically develop using older technology. The former Office of
Technology Assessment (OTA) estimated in 1980 that 1.8 trillion barrels appeared
marginally attractive to production, based on deposits that would yield 15 gallons per
ton and were at least 15 feet thick.3 In a more recent analysis, the portion of the
formation yielding greater than 10 gallons per ton was estimated to contain 1.5
trillion barrels.4 Because oil shales have not been proven economically recoverable,
they are considered contingent resources and not true reserves.5 By comparison, the
1 U.S. DOE Energy Information Administration (EIA), Monthly Energy Review January
2006, Table 1.7, Overview of U.S. Petroleum Trade, at [http://www.eia.doe.gov/
emeu/mer/pdf/pages/sec1_15.pdf], visited Feb. 17, 2006.
2 Thomas Lonnie, Bureau of Land Management, Testimony before the Senate Energy and
Natural Resources Committee, Oversight Hearing on Oil Shale Development Effort, Apr.
12, 2005.
3 Office of Technology Assessment, An Assessment of Oil Shale Technologies, 1980, pp. 89-
91, NTIS order #PB80-210115.
4 James W. Bunger and Peter M. Crawford, “Is oil shale America’s answer to peak-oil
challenge?” Oil & Gas Journal, Aug. 9, 2004.
5 The Society of Petroleum Engineers defines true reserves as “those quantities of petroleum
which are anticipated to be commercially recoverable from known accumulations from a
given date forward.” See [http://www.spe.org/spe/jsp/basic/0,,1104_1575_1040460,
00.html] (viewed Feb. 17, 2006).

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conventional proved oil reserves of the United States are less than 22 billion barrels,
and Saudi Arabia’s are reportedly 267 billion barrels.6
Figure 1. Distribution of Oil Shale in the Green River Formation of
Colorado, Utah, and Wyoming
Source: U.S. Geologic Survey, Circular 523 (1965), as reproduced by the U.S. Department of Energy
in Strategic Significance of America’s Oil Shale Resources, Mar. 14, 2005.
Note: The Green River formation may contain more than 8 trillion barrels of shale oil in place, with
an estimated 1.8 trillion barrels marginally attractive to production. The United States holds proved
reserves of less than 22 billion barrels of conventional crude oil, compared with Saudi Arabia’s
reported 267 billion barrels.
In the early 20th century, three oil shale reserves were set aside on federal lands
out of concern for the Navy’s petroleum supply. Naval Oil Shale Reserves (NOSRs)
Nos. 1 (36,406 acres) and 3 (20,171 acres) are located 8 miles west of Rifle,
Colorado, in Garfield County. Reserve No. 2 (88,890 acres) in Carbon and Uintah
Counties, Utah, has been transferred to the Ute Indian Tribe. NOSR No.1 has been
estimated to contain more than 18 billion barrels of shale oil in place.7 As much as
6 U.S. DOE EIA, International Petroleum (Oil) Reserves and Resources, at
[http://www.eia.doe.gov/emeu/international/oilreserves.html], visited Feb. 17, 2006.
7 U.S. DOE, Naval Petroleum & Oil Shale Reserves, Annual Report of Operations Fiscal
Year 1995 (DOE/FE-0342).

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2.5 billion barrels of oil may be recoverable from shale yielding 30 gallons of oil or
more per ton. NOSR No. 3 is not considered to have commercial value.
Oil shale production has faced unique technological and environmental
challenges. The hydrocarbon resource is bound up in the shale and is not free to flow
like petroleum. In previous attempts at production, conventional subsurface and strip
mining methods were combined with high-temperature processing (retorting) to
extract petroleum-like distillates. Not only was a plentiful water supply required, but
certain processing methods had associated groundwater contamination issues. Unlike
conventional petroleum production, wherein crude oil is shipped or piped to an
established refining and distribution center, oil shale production would have required
the vertical integration of resource extraction, processing, and upgrading to a finished
product ready for blending and distribution. Recent interests in oil shale look to
overcoming the past technical challenges associated with mining by adapting oil field
production methods. Unlike conventional crude oil, oil-shale distillates make poor
feedstock for gasoline production and thus may be better suited to making distillate-
based fuels such as diesel and jet fuel. The cost of producing oil shale remains
uncertain, especially when compared with the economic fundamentals of extracting
conventional petroleum reserves.
Geology and Production Technology of Oil Shale
Kerogen
The first phase in organic matter’s geologic transformation to petroleum is
intermediate conversion to kerogen. During this low-temperature transformation —
referred to as diagenesis — organically bound oxygen, nitrogen, and sulfur are
released.8 Complete transformation to petroleum occurs during catagenesis — the
prolonged exposure to temperatures in the range of 122° to 392°F, generally
occurring at depths of 4,000 to 9,800 feet. The catalytic properties of the shale
binding the kerogen contribute to the transformation. The threshold for intense oil
generation begins at 149°F, equivalent to depths of 4,500 feet or more. Temperatures
above 392°F mark the metamorphic end-state of transformation — ultimate
conversion to methane gas and graphite (pure carbon).
Oil shales have not thermally matured beyond the diagenesis stage due to their
relatively shallow depth of burial. Some degree of maturation has taken place, but
not enough to fully convert the kerogen to petroleum hydrocarbons. The Green River
oil shale of Colorado has matured to the stage that heterocyclic (ring-like)
hydrocarbons have formed and predominate, with up to 10% normal- and iso-
paraffins (the range of hydrocarbons that includes natural gasoline).9 In comparison,
conventional crude oil may contain as much as 40% natural gasoline. The kerogen’s
rich hydrogen/carbon ratio (1.6) is a significant factor in terms of yielding high-
8 John M. Hunt, Petroleum Geochemistry and Geology, W.H. Freeman and Co., 1979.
9 C is shorthand notation for the number of carbon atoms. John M. Hunt, Petroleum
n
Geochemistry and Geology, W.H. Freeman and Co., 1979

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quality fuels. Its 1%-3% nitrogen content, however, may be problematic in terms of
producing stable fuels (petroleum typically contains less than 0.5% nitrogen), as well
as producing environmentally detrimental nitrogen oxides during combustion.10 To
assess kerogen’s potential for yielding hydrocarbon-like fuels, the processes of
conventional petroleum refining, synthetic fuel production, and oil shale retorting are
compared below.
Conventional Refining
A conventional refinery distills crude oil into various fractions, according to
boiling point range, before further processing.11 In order of their increasing boiling
range and density, the distilled fractions are fuel gases, light and heavy straight-run
naphtha (90°-380°F), kerosene (380°-520°F), gas-oil (520°-1,050°F), and residuum
(1,050°F +). Gasoline’s molecular range is C -C ; middle-distillate fuels (kerosene,
5
10
jet, and diesel) range C -C . Crude oil may contain 10%-40% gasoline, and early
11
18
refineries directly distilled a straight-run gasoline (light naphtha) of low-octane
rating.12 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.13
Just as natural clay catalysts help transform kerogen to petroleum through
catagenesis, metallic catalysts help transform complex hydrocarbons to lighter
molecular chains in modern refining processes. The catalytic-cracking process
developed during the World War II era enabled refineries to produce high-octane
gasolines needed for the war effort. Hydrocracking, which entered commercial
operation in 1958, improved on catalytic-cracking by adding hydrogen to convert
residuum into high-quality motor gasoline and naphtha-based jet fuel. U.S. refineries
rely heavily on hydroprocessing to convert low-value gas oils residuum to high-value
transportation fuel demanded by the market. Middle-distillate range fuels (diesel and
jet) can be blended from a variety of refinery processing streams.14 To blend jet fuel,
refineries use desulfurized straight-run kerosene, kerosene boiling range
hydrocarbons from a hydrocracking unit, and light coker gas-oil (cracked residuum).
Diesel fuel can be blended from naphtha, kerosene, and light cracked-oils from coker
10 Exxon Research and Engineering Co., Fundamental Synthetic Fuel Stability Study, First
Annual Report for May 1, 1979 to April 30, 1981.
11 James H. Gary and Glenn E. Handwerk, Petroleum Refining, Technology and Economics
4th ed., 2001. (Hereafter cited as Gary and Handwerk, Petroleum Refining: Technology and
Economics.)
12 Octane number refers to the gasoline property that reduces detrimental knocking in a
spark-ignition engine. In early research, iso-octane (C -length branched hydrocarbon
8
molecules ) caused the least knock and was rated 100. Cetane number refers to a similar
property for diesel fuel, for which normal hexadecane (C H ) is the standard molecule.
16
34
13 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.
14 Gary and Handwerk, Petroleum Refining: Technology and Economics.

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and fluid catalytic cracking units. From the standard 42-gallon barrel of crude oil,
U.S. refineries may actually produce more than 44 gallons of refined products
through the catalytic reaction with hydrogen.15
From a simple crude distillation unit, a typical U.S. refinery has grown to a
complex of 10 to 15 types of processes.16 The Nelson Complexity Index, a measure
of a refinery’s complexity, assigns factors to the capacities of various processing
units and compares them to the refinery’s crude distillation unit capacity. U.S.
refineries rank highest in complexity index, averaging 9.5 compared with Europe’s
at 6.5. The difference in complexity index reflects the 2-times greater catalytic
cracking and 1½-times greater reformation capacities of U.S. refineries.17 Although
U.S. refineries have optimized to produce reformulated gasoline, European refineries
yield more middle-distillate diesel fuel to meet the greater European demand for that
fuel.
Synthetic Fuel Production
Synthetic fuel technology was developed in prewar Germany to address its
scarce petroleum resources. An early process developed by Friedrich Bergius used
a catalyst to promote the reaction of hydrogen with coal liquids to produce low-
quality gasoline. During the 1960s, the Department of the Interior’s Office of Coal
Research sponsored research to directly liquefy Eastern coal into substitutes for
natural gas and oil (synthetic liquid fuels).18
In a competing process developed by German scientists Fischer and Tropsch,
low-temperature catalysts were used to promote hydrogen’s reaction with coal gas
and produce gasoline. The South African oil company Sasol later developed this
technology further. Modern “gas-to-liquids” (GTL) technology based on the
Fischer-Tropsch process converts natural gas to liquid fuels.
Essentially, both the Bergius and Fisher-Tropsch synthetic fuel processes build
up longer chain hydrocarbons from smaller molecules. This is the opposite of
hydrocracking, the refining process that breaks heavier-weight molecular chains and
rings into lighter-weight molecules using hydrogen and catalysts.
15 Hydroprocessing describes all the processes that react hydrocarbons with hydrogen to
synthesize high-value fuels. Hydrocracking reduces denser molecular weight hydrocarbons
to lower boiling range products (predominantly gasoline). Impurities such as sulfur are
removed by hydrotreating. Refineries produce the hydrogen needed for hydrotreating either
by steam reformation of methane (liberated during the atmospheric distillation) or from a
vendor who similarly converts natural gas (methane) to hydrogen. Alan G. Bridge
“Hydrogen Processing,” Chapter 14.1, in Handbook of Petroleum Refining Processes, 2nd
ed., McGraw-Hill, 1996.
16 Robert E. Maples, Petroleum Refinery Process Economics, 2nd ed., Penwell Corp., 2000.
17 Ibid., Table 4-1.
18 Cohen, Linda R. and Roger G. Noll, “The Technology Pork Barrel,” Chapter 10, in
Synthetics from Coal, Washington, DC: The Brookings Institution, 1991.

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Oil Shale Retorting
Oil derived from shale has been referred to as a synthetic crude oil and thus
closely associated with synthetic fuel production. However, the process of retorting
shale oil bears more similarities to conventional refining than to synthetic fuel
processes. For the purpose of this report, the term oil-shale distillate is used to refer
to middle-distillate range hydrocarbons produced by retorting oil shale. Two basic
retorting processes were developed early on — aboveground retorting and
underground, or in situ, retorting. The retort is typically a large cylindrical vessel, and
early retorts were based on rotary kiln ovens used in cement manufacturing. In situ
technology involves mining an underground chamber that functions as a retort. A
number of design concepts were tested from the 1960s through the 1980s.
Retorting essentially involves destructive distillation (pyrolysis) of oil shale in
the absence of oxygen. Pyrolysis (temperatures above 900°F) thermally breaks
down (cracks) the kerogen to release the hydrocarbons and then cracks the
hydrocarbons into lower-weight hydrocarbon molecules. Conventional refining uses
a similar thermal cracking process, termed coking, to break down high-molecular
weight residuum.
OTA compiled properties of oil-shale distillates produced by various retorting
processes (Table 1). In general, oil-shale distillates have a much higher
concentration of high boiling-point compounds that would favor production of
middle-distillates (such as diesel and jet fuels) rather than naphtha.19 Oil-shale
distillates also had a higher content of olefins, oxygen, and nitrogen than crude oil,
as well as higher pour points and viscosities. Above-ground retorting processes
tended to yield a lower API gravity oil than the in situ processes (a 25° API gravity
was the highest produced).20 Additional processing equivalent to hydrocracking
would be required to convert oil-shale distillates to a lighter range hydrocarbon
(gasoline). Removal of sulfur and nitrogen would, however, require hydrotreating.
By comparison, a typical 35° API-gravity crude oil may be composed of up to
50% of gasoline and middle-distillate range hydrocarbons. West Texas Intermediate
crude (a benchmark crude for trade in the commodity futures market) has a 0.3%
sulfur content, and Alaska North Slope crude has a 1.1% sulfur content.21 The New
York Mercantile Exchange (NYMEX) specifications for light “sweet” crude limits
sulfur content to 0.42% or less (A.S.T.M. Standard D-4294) and an API gravity
between 37 and 42 degrees (A.S.T.M. Standard D-287).22
19 OTA, Ch. 5 — Technology, p. 157.
20 API gravity refers to the American Petroleum Institute measure of crude oil density — the
higher the API gravity, the lighter the crude oil’s density. Light crudes exceed 38° API,
intermediate crudes range 22° to 38° API, and heavy crudes fall below 22° API.
21 Platt’s Oil Guide to Specifications, 1999 [http://www.emis.platts.com/thezone/guides/
platts/oil/crudeoilspecs.html], viewed Apr. 5, 2006.
22 New York Mercantile Exchange, Exchange Rulebook, Light “Sweet” Crude Oil Futures
Contract, at [http://www.nymex.com/rule_main.aspx], visited Aug. 25, 2005.

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Oil-shale distillate has been considered a synthetic substitute for crude oil;
however, its fungibility may be limited in modern refining operations. Because the
kerogen contained by the shale is only a petroleum precursor, it lacks the full range
of hydrocarbons used by refineries in maximizing gasoline production. Also,
because of technology limitations, only hydrocarbons in the range of middle-
distillates (kerosene, jet fuel, diesel fuel) appear extractable.
Table 1. Properties of Oil-Shale Distillates Compared with
Benchmark Crude Oils
° API
% Sulfur
OTA Reported Oil-Shale Distillates Propertiesa
19.4-28.4
0.59-0.92
Shell ICP Oil-Shale Distillateb
34
0.8
Oil Tech Oil-Shale Distillatec
30
no report
West Texas Intermediate Crude Oild 40
0.30
NYMEX Deliverable Grade Sweet Crude Oil
Specificatione
37-42
<0.42
Alaska North Slope Crude Oild
29-29.5
1.10
a. OTA, An Assessment of Oil Shale Technologies, Table 19, 1980.
b. Energy Washington Week, “Shell Successfully Tests Pilot of New In Situ Oil Shale Technology,”
Oct. 12, 2005.
c. Jack Savage, Testimony Before the Subcommittee on Energy and Mineral Resources, June 23,
2005.
d. Platt’s Oil Guide to Specifications, 1999.
e. NYMEX, Exchange Rulebook, Light “Sweet” Crude Oil Futures Contract.
Both in situ and above-ground retorting processes have been plagued with
technical and environmental problems. Apart from the problem of sustaining
controlled combustion underground, in situ retorting suffered from the environmental
drawback of causing groundwater contamination. Above-ground retorting required
underground or open-pit mining to excavate the shale first. While either mining
method is well-practiced, the expended shale that remained after retorting presented
a disposal problem, not to mention the overburden rock that had to be removed in the
case of open-pit mining. Above-ground retorts also faced frequent problems from
caked-up shale, which led them to shut down. Some recent approaches have aimed
to avoid these drawbacks altogether.
Shell In Situ Conversion Process. For the past five years, the Shell
Exploration and Production Company has been conducting research into directly
extracting oil-shale distillates on its 20,000-acre Cathedral Bluffs property near
Parachute (Rio Blanco County), Colorado.23 Unlike previously attempted in situ
23 Testimony of Stephen Mut, Shell Unconventional Resources Energy Oil, Shale and Oil
Sands Resources Hearing, Senate Energy and Natural Resources Committee, Tuesday, Apr.
(continued...)

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retorting, Shell’s in situ conversion process (ICP) involves drilling holes up to 2,000
feet deep, inserting electrical resistance heaters, and heating the shale to 650-700°F
over a period of months. The ICP converts the kerogen to gas and petroleum-like
liquids. The process not only consumes high amounts of energy to operate the
heaters, it also requires freezing the perimeter of the production zone to restrict
groundwater flow. Shell Oil Company reports extracting a 34°API product
consisting of a gas (propane and butane) and b liquids split 30% naphtha, 30% jet
fuel, 30% diesel, and 10% slightly heavier oil. Sulfur content was 0.8% by weight.
Oil Tech Above-Ground Retorting. Oil Tech, Inc., has been developing
a new above-ground retort, which it reports as having the capacity of extracting one
barrel of shale-oil per ton of shale per hour.24 The company has reported producing
a low-sulfur 30° API-gravity oil consisting of 10% naphtha, 40% kerosene, 40%
diesel, and 10% heavy residual oil. Starting off where past retorting attempts ended,
Oil Tech intends to use previously mined oil shale that had been stockpiled.
History of Oil Shale Development
Oil shale was originally considered as a reserve supply of crude oil to fuel U.S.
naval vessels in times of short supply or emergencies. Because the largest oil shale
resources reside on federal lands, the federal government historically has had a direct
interest and role in encouraging the development of this resource. Potential
oil-bearing lands in California and Wyoming were first set aside for withdrawal as
sources of fuel for the Navy under the Pickett Act of 1910. Later, presidential
executive orders created NOSR Nos. 1 and 3 in Colorado and NOSR No. 2 in Utah.
Early Synthetic Liquid Fuels Efforts
During World War II, Congress’s concern for conserving and increasing the
nation’s oil resources prompted passage of the Synthetic Liquid Fuels Act of 1944
(30 U.S.C. Secs. 321 to 325), which authorized funds for the Interior Department’s
Bureau of Mines to construct and operate demonstration plants to produce synthetic
liquid fuel from oil shales, among other substances.
Congress passed the Defense Production Act of 1950 (Ch. 932, 64 Stat. 798)
during the Korean War to develop and maintain whatever military and economic
strength was necessary to support collective action through the United Nations. The
Title III program authorized governmental requisition of property for national defense
and expansion of productive capacity, among other authorities. Between 1949 and
1955, the U.S. Bureau of Mines received $18 million to operate three above-ground
gas combustion retorts at Anvil Points, Colorado, the site of NOSR No. 1.
23 (...continued)
12, 2005.
24 Jack S. Savage, Oil Tech, Inc., Testimony before the Hearing on The Vast North
American Resource Potential of Oil Shale, Oil Sands, and Heavy Oils — Part 1, House
Subcommittee on Energy and Mineral Resources, June 23, 2005.

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Long before the United States’ increasing dependence on imported crude oil
become apparent, oil shale began attracting the interest of some major petroleum
companies: Exxon, Occidental Petroleum, and Union Oil, among others. In 1961,
the Union Oil Company began testing its “Union A” retort at Parachute Creek,
Colorado. Though producing 800 barrels per day (bpd), Union shut the retort down
after 18 months due to cost. In 1964, The Oil Shale Company (Tosco), Standard Oil
of Ohio (Sohio), and Cleveland Cliffs Mining formed a consortium to operate the
Colony Oil Shale mine. Despite producing 270,000 barrels, Tosco shut down
production in 1972. Occidental Petroleum also began oil shale retorting experiments
in 1972 near Rifle, Colorado, and ultimately evaluated six retorts.
Defense Department Programs
The Defense Department had become interested in oil shale as an alternative
resource for producing quality jet fuel as early as 1951.25 The U.S. Navy and the
Naval Petroleum and Oil Shale Reserves Office (NPSRO) started large-scale
evaluations of oil shale’s suitability for military fuels in the early 1970s. Tosco was
contracted to produce and process 10,000 barrels of oil-shale distillates.
Development Engineering, Inc., leased the federal Anvil Points site (Naval Oil Shale
Reserve 3) in 1972 and formed the Paraho Development Corporation in 1973 (a
consortium of 17 energy companies). Paraho’s plans included a five-year program
to develop two pilot scale retorts and produce oil-shale distillates for the Navy fuel
testing. Paraho initially produced 10,000 barrels of oil-shale distillates that Sohio
processed into gasoline, JP-4 and JP-5 jet fuel, diesel fuel marine (DFM), and a
heavy fuel oil at the Gary Western Refinery in Fruita, Colorado. Though the fuels
produced were off-specification, analysis indicated that the refining process could
be optimized to produce specification fuels. Paraho was awarded a follow-on
contract to produce 100,000 barrels of oil-shale distillates for processing
specification fuels in Sohio’s Toledo Refinery. The Navy conducted extensive tests
with the fuels in military and commercial equipment.
In the late 1970s, the Air Force became interested in evaluating oil shale’s
suitability for producing JP-4 jet fuel. Under Project Rivet Shale, in 1979, the Air
Force awarded contracts to Ashland Research and Development, Suntech, Inc., and
UOP, Inc., to develop technology to produce oil shale-derived JP-4 jet fuel. In 1982,
over 10,000 gallons of JP-4 were processed at the Caribou Four Corners Refinery in
Woods Cross, Utah, from crude oil-shale distillates produced by Geokinetics. JP-4
specification fuel was produced from other oil shale retorting techniques pioneered
by Occidental, Paraho, and Union Oil. Unocal (formerly Union Oil Company)
operated the Parachute Creek oil shale plant and reportedly produced 4.6 million
barrels of oil-shale distillates from 1985 to 1990 for Air Force evaluation under
Project Rivet Shale.26 The Air Force generally phased out JP-4 in the early 1990s in
favor of kerosene-based JP-8.
25 Personal communication with William E. Harrison III, Office of Deputy Under Secretary
of Defense for Advanced Systems and Concepts, Oct. 25, 2005.
26 The Center for Land Use Integration, Unocal Oil Shale Plant, at [http://ludb.clui.org/
ex/i/CO3191/], visited Mar. 28, 2006.

CRS-10
Department of Energy Synthetic Fuels Program
The Department of Energy (DOE) encouraged interest in large-scale oil shale
development through its Synthetic Fuels Program. DOE initially promoted two
prototype lease tracts in the Piceance Basin of Rio Blanco County, Colorado (NOSR
tracts C-a and C-b).27 Amoco later produced 1,900 barrels using in situ retorting in
tract C-a, and Occidental Petroleum planned a similar effort for tract C-b.
The Interior Department Appropriations Act (P.L. 96-126) and the Supplemental
Appropriations Act of 1980 (P.L. 96-304) appropriated $17.522 billion to the Energy
Security Reserve fund in the Treasury Department. Of that amount, $2.616 billion
was committed by the Department of Energy to three synthetic fuels projects. Two
of the projects were approved under the Defense Production Act: Union Oil
Company’s Parachute Creek project in Garfield County, Colorado, and Exxon-
Tosco’s Colony oil shale project, also in Garfield County. Union Oil Company
received a $0.4 billion price guarantee for the Parachute Creek Shale Oil Project, and
the Exxon-Tosco Colony Oil Shale Project received a loan guarantee of $1.15 billion
(applied to the 40% owned by Tosco).28 Union Oil was expected to produce 10,400
bpd at $42.50/bbl, which, adjusted for inflation, equaled $51.20/bbl by March 1,
1985.
As an additional stimulus to producing alternative fuels — for which oil shale,
among others, qualified — Congress provided a $3.00 /bbl production tax credit
provision in the Crude Oil Windfall Profit Tax Act of 1980 (P.L. 96-223). The credit
would take full effect when crude oil prices fell below $23.50 /bbl (in 1979 dollars)
and would gradually phase out as prices rose above to $29.50/bbl.
Tosco’s interest in the Colony project was sold in 1979, and again in 1980, to
Exxon Company for the Colony II development. Exxon planned to invest up to $5
billion in a planned 47,000 bpd plant using a Tosco retort design. After spending
more than $1 billion, Exxon announced on May 2, 1982, that it was closing the
project and laying off 2,200 workers.
U.S. Synthetic Fuels Corporation
The Energy Security Act of 1980 (P.L. 96-294, Title I, Part B) established the
United States Synthetic Fuels Corporation (SFC) with the authority to provide
financial assistance to qualified projects that produced synthetic fuel from coal, oil
shale, tar sands, and heavy oils. The SFC’s loan commitments would be paid from
the Energy Security Reserve fund. Executive Order 12346 (Synthetic Fuels) later
provided for an orderly transition of DOE’s earlier synthetic fuel program to the SFC.
27 Garfield County, Colorado, Garfield County Comprehensive Plan Revision, Study Area
Five, adopted version, Apr. 24, 2002, at [http://garfield-county.com/home/index.asp?page
=664], visited Mar. 28, 2006.
28 H.Rept. 99-196, Part 1, July 11, 1985.

CRS-11
Between 1981 and 1984, the SFC received 34 proposals for oil shale projects
in three rounds of solicitations. Only three letters of intent were ever issued. Union
Oil’s Parachute Creek Phase II 80,000 bpd plant was to receive a $2.7 billion funding
commitment and a guarantee of $60/bbl, escalated up to $67 /bbl; another $0.5
billion in price and loan guarantees was added in October 1985 to Union’s Parachute
Creek Phase I. Cathedral Bluffs, a 14,300 bpd plant based on a Union Oil design,
was to receive a $2.19 billion loan guarantee and a $60/bbl price guarantee. Seep
Ridge Oil Shale’s 1,000 bpd plant was to receive $45 million in price and loan
guarantees. None of the oil shale projects that received SFC loan guarantees ever
received actual funding, as Congress rescinded $2 billion originally appropriated for
the Energy Security Reserve fund in the Deficit Reduction Act of 1984 (P.L. 98-369)
and later abolished the SFC.
In 1984, Congress asked the General Accounting Office (GAO) to report on the
progress of synthetic fuels development and to specifically respond to the question
“Why have project sponsors dropped synthetic fuels projects?” GAO answered that
oil had become plentiful, with about 8 to 10 million barrels per day in excess
worldwide capacity, and the trend in rising oil prices had reversed after early 1981.
President Reagan’s Executive Order 12287 had removed price and allocation
controls on crude oil and refined petroleum products in 1981. For the first time since
the early 1970s, market forces replaced regulatory programs and domestic crude oil
prices were allowed to rise to a market-clearing level. Decontrol also set the stage
for the relaxation of export restrictions on refined petroleum products. Oil demand
had also declined, due in part to energy conservation measures and a worldwide
economic recession. A more fundamental change had taken place in the way that oil
commodities were traded. Prior to 1980, the price of crude oil was determined by
long-term contracts, with 10% or so of internationally traded oil exchanged on the
spot market.29 By the end of 1982, more than half of the internationally traded oil
was exchanged on the spot market or tied to the spot market price. The most
significant change occurred in 1983, with the introduction of crude oil futures by the
New York Mercantile Exchange (NYMEX). All served to undermine price setting
by the Organization of Petroleum Exporting Countries (OPEC).
Tax incentives for oil shale projects had also been reduced. Some of the
generous oil depreciation allowances under the 1981 Economic Recovery Tax Act
(P.L. 97-48) were rescinded in 1982 by the Tax Equity and Fiscal Responsibility Act
(P.L. 97-248), reducing potential project sponsors’ after-tax rates of return.
The House began considering a bill to abolish the SFC in 1985, and Congress
terminated the Corporation the following year under the Consolidated Omnibus
Budget Reconciliation Act of 1985 (P.L. 99-272). The Appendix to this report
provides a more complete legislative history of the Synthetic Fuels program.
29 Daniel Yergin, The Prize, Touchstone, 1991, pp. 722-725.

CRS-12
Renewed Interest in Oil Shale
In 2005, Congress conducted hearings on oil shale to discuss opportunities for
advancing technology that would facilitate “environmentally friendly” development
of oil shale and oil sands resources.30 The hearings also addressed legislative and
administrative actions necessary to provide incentives for industry investment, as
well as exploring concerns and experiences of other governments and organizations
and the interests of industry. The Energy Policy Act of 2005 included provisions
under Section 369 (Oil Shale, Tar Sands, and Other Strategic Unconventional
Fuels31) that direct the Secretary of the Interior to begin leasing oil shale tracts on
public lands and to cooperate with the Secretary of Defense in developing a program
to commercially develop oil shale, among other strategic unconventional fuels.
The Bureau of Land Management (BLM) established the Oil Shale Task Force
in 2005 to address oil shale access on public lands and impediments to oil shale
development on public lands. Title 30, Section 241(a) of the Mineral Lands Leasing
Act formerly restricted leases to 5,120 acres. Advocates of oil shale development
claimed that restrictions on lease size hindered economic development. The Energy
Policy Act amended Section 241(a) by raising the lease size to 5,760 acres and
restricting total lease holdings to no more than 50,000 acres in any one state.32
On September 20, 2005, the Bureau of Land Management announced it had
received 19 nominations for 160-acre parcels of public land to be leased in Colorado,
Utah, and Wyoming for oil shale research, development, and demonstration
(RD&D). On January 17, 2006, BLM announced that it accepted eight proposals
from six companies to develop oil shale technologies; the companies selected were
Chevron Shale Oil Co., EGL Resources Inc., ExxonMobil Corp., Oil-Tech
Exploration LLC, and Shell Frontier Oil & Gas.33 Six of the proposals will look at
in situ extraction to minimize surface disturbance. Each proposal will be evaluated
under the National Environmental Policy Act (NEPA). In addition to the 160 acres
allowed in the call for RD&D proposals, a contiguous area of 4,960 acres is reserved
for the preferential right for each project sponsor to convert to a future commercial
lease after additional BLM reviews.
The Energy Policy Act also identified oil shale as a strategically important
domestic resource and directed DOE to coordinate and accelerate its commercial
development. Section 369(q) (Procurement of Unconventional Fuels by the
30 The Senate Energy and Natural Resources Committee, Oversight Hearing on Oil Shale
Development Effort, Apr. 12, 2005.
31 Also cited as the Oil Shale, Tar Sands, and Other Strategic Unconventional Fuels Act of
2005.
32 30 USC 241 (4) “For the privilege of mining, extracting, and disposing of oil or other
minerals covered by a lease under this section ... no one person, association, or corporation
shall acquire or hold more than 50,000 acres of oil shale leases in any one State.”
33 Bureau of Land Management, BLM Announces Results of Review of Oil Shale Research
Nominations, Jan. 17, 2006, at [http://www.blm.gov/nhp/news/releases/pages/2006/
pr060117_oilshale.htm], visited Mar. 29, 2006.

CRS-13
Department of Defense) of the act directs the Secretaries of Defense and Energy to
develop a strategy to use fuel produced from oil shale to help meet the fuel
requirements of the Defense Department when the Defense Secretary determines that
doing so is in the national interest. The Defense Department had worked jointly with
Energy on a Clean Fuels Initiative to develop, test, certify, and use zero-sulfur jet
fuels from alternative resources (oil shale, among others). By eliminating sulfur, the
fuels would be suitable for use in fuel cells to generate electricity and in turbine
engines used in aircraft and ground vehicles. A synthetic fuel process based on
Fischer-Tropsch had been considered. At the time of the President’s FY2007 budget
request, DOE proposed terminating oil technology research, and the Defense
Department left Clean Fuels unfunded.34
Since 1910, several legislation-based initiatives have attempted to promote oil
shale development. (Legislation establishing the oil shale reserves and related federal
programs is summarized in the Appendix of this report.) However, more recent
regulatory policies (see below) appear adverse to oil shale development, at least to
the wider use of middle-distillate fuels producible from oil shale.
Incentives and Disincentives to Development
The economic incentive for producing oil shale has long been tied to the price
of crude oil. The highest price that crude oil ever reached — $87/bbl (2005 dollars)
— occurred in January 1981 (Figure 2).35 Exxon’s decision to cancel its Colony oil
shale project came a year and half later, after prices began to decline and newly
discovered, less-costly-to-produce reserves came online. The price of crude oil
spiked to nearly $70/bbl after Hurricanes Katrina and Rita, and the recent climb to
above $67 /bbl has led to some speculation that prices may remain high indefinitely.
In the Energy Information Administration’s (EIA’s) reference case projection,
though, “the average world crude oil price continues to rise through 2006 and then
declines to $46.90/bbl in 2014 (2004 dollars) as new supplies enter the market. It
then rises slowly to $54.08/bbl in 2025.”36 Near-record gasoline prices have led to
similar speculation, as the average price of gasoline has stayed consistently above $2
per gallon since May of 2005, and the on-highway diesel price has stayed even
higher.37 However, oil company investment decisions may be more conservatively
based on making profits at the $20-$30/barrel range of just a few years ago than on
projected prices. That is, high prices may not be enough of an incentive for risky
developments in conventional oil, let alone oil shale.
34 Personal communication with Dr. Theodore K. Barna, Feb. 8, 2006.
35 U.S. DOE EIA, Imported Crude Oil Prices: Nominal and Real, at
[http://www.eia.doe.gov/emeu/steo/pub/fsheets/petroleumprices.xls], visited Apr. 5, 2006.
36 U.S. DOE EIA, Annual Energy Outlook 2006 with Projections to 2030 (Early Release)
— Overview, December 2005, at[http://www.eia.doe.gov/oiaf/aeo/key.html], visited Apr.
5, 2006.
37 U.S. DOE EIA, Gasoline and Diesel Fuel Update, at [http://tonto.eia.doe.gov/oog/
info/gdu/gasdiesel.asp], visited Apr. 5, 2006.

CRS-14
Figure 2. Refiner Acquisition Cost of Imported
Crude Oil
Source: U.S. DOE EIA, World Oil Market and Oil Price Chronologies 1970-2004, Mar. 2005, at
[http://www.eia.doe.gov/cabs/chron.html]; EIA Refiner Acquisition Cost of Crude Oil (for July 2005
to Jan. 2006), at [http://tonto.eia.doe.gov/dnav/pet/pet_pri_rac2_dcu_nus_m.htm].
Crude oil production costs vary widely by geography and reservoir conditions,
and they may be more important factors now than 25 years ago as aging reservoirs
decline in production. Production involves lifting the oil to the surface and the
gathering, treating, and field processing and storage of the oil. The cost of
production, sometimes referred to as lifting cost, includes labor to operate the wells
and related equipment; repair and maintenance of the wells and equipment; and
materials, supplies, and energy required to operate the wells and related equipment.
In the Persian Gulf region, where a single well may produce thousands of barrels per
day, production costs may be as little as a few dollars per barrel. Production costs
in the United States had approached $15/bbl by 2004.38 ExxonMobile reported
production costs increases from $4½ to $5½ /bbl for its U.S. operations over the past
several years.39 In older, far less productive wells in the United States, production
costs may reach more than $25/bbl.40
In 1998, a supply glut forced the price of crude oil down to almost $10/barrel
and gasoline sold for less than $0.80/gallon in some markets. Some domestic
producers charged, in a U.S. Court of International Trade suit, that oil imports had
38 U.S. DOE EIA, Performance Profiles of Major Energy Producers 2004,Table 11, Income
Components and Financial Ratios in Oil and Natural Gas Production for FRS Companies,
2003 and 2004, at [http://www.eia.doe.gov/emeu/perfpro/], visited Apr. 12, 2006.
39 Exxon Mobile Corp, Form 10-K, Average sales prices and production costs per unit of
production — consolidated subsidiaries Feb. 28, 2006.
40 Thomas R. Stauffer, “Trends In Oil Production Costs In The Middle East, Elsewhere,”
Oil & Gas Journal, Mar. 21, 1994.

CRS-15
been dumped on the American market.41 Though unsuccessful, the suit does say
something further about bottom-line production costs (the crude oil price equivalent
that producers could not compete below) and the production costs that oil shale may
need to compete against. For several years preceding the price drop, crude oil ranged
from $20 to $30/bbl.
The perception that oil shale serves as a crude oil substitute overlooks the
limited fungibility of the middle distillates that are extractable — they make poor
feedstock for gasoline production. That does not necessarily prevent oil-shale
distillates from being used as gasoline feedstock, but additional energy and hydrogen
are needed to crack them. The loss may be even greater considering the lower fuel
efficiency of spark-ignition engines that use gasoline, compared with compression
ignition engines that use diesel distillate fuels.
Other incentives or disincentives may include the cost and size of an oil shale
processing facility, conventional refining profitability, and the cost and availability
of refined commodities. Certain environmental and tax regulations that act as
incentives to using gasoline in light-duty vehicles discourage middle-distillate diesel
fuel use, and thus oil-shale distillates as substitute motor fuels.
The Cost of Constructing an Oil Shale Facility
A reliable cost estimate for producing oil shale has proved challenging, if not
controversial. The cost of resources extraction had depended on whether
conventional underground or strip-mining methods were employed. Because there
was a considerable experience in mining, reliable cost estimates could be developed.
A second variable — the cost of constructing and operating an oil shale facility —
had to be accounted for separately. The former OTA estimated in 1979 that a 50,000
bpd oil shale facility (based on above-ground retorting technology) would have
required an investment of $1.5 billion and operating costs of $8 to $13/bbl. Using
the Nelson-Farrar Cost Indexes to adjust refinery construction and operation costs to
2004 dollars, the investment would be equivalent to $3.5 billion, with operating costs
of $13 to $21/bbl.42 This excludes the cost of shale extraction.
In comparison, the cost of building a new conventional refinery has been
estimated to range between $2 and $4 billion as recently as 2001.43 The cost of
operating a refinery (marketing, energy, and other costs) averaged nearly $6/bbl
during 2003-2004, as reflected in the difference between gross and net margins
(where the gross margin reflects the refiner’s revenue minus the cost of crude oil).44
41 “U.S. Oil Dumping Case Wins Investigation By Commerce,” Oil & Gas Journal, Oct. 2,
2000.
42 1980 vs. 2004 Refinery Inflation Index and 1980 vs. 2004 Refinery Operating Index from
the Nelson-Farrar Cost Indexes, Oil & Gas Journal (published first issue each month).
43 “U.S. appears to have built last refinery,” Alexander’s Gas & Oil Connections, vol. 6,
issue 13, Jul. 17, 2001.
44 U.S. DOE EIA, Performance Profiles of Major Energy Producers 2004, Table 15, U.S.
(continued...)

CRS-16
An oil shale facility may not be directly comparable to a refinery in terms of
construction costs, though some processes, such as hydrotreating, may be common
to both. If oil field-based technologies such as Shell’s proposed ICP are successfully
adapted to resource extraction, facility costs could be reduced, but operating costs
could increase given the energy-intensive aspect of the technology.
Under the U.S. Air Force Project Rivet Shale, Union Oil’s Parachute Creek
Phase I project produced 4.6 million barrels of oil-shale distillates from 1985 to 1990
at a cost of $650 million; roughly the equivalent of $141/bbl, or $3.52/gal.
(wholesale). Since Rivet Shale produced a jet fuel equivalent, a comparison might
be made with the price of jet fuel at the time. In comparison, a refiner’s crude oil
acquisition costs ranged from a less $15/bbl to $27/bbl in nominal dollars over that
same time period.45 The spot market price for kerosene-based jet fuel rose from less
than $0.40/gal in 1985 to more than $1.10/gal by 1990.
The Rand Corporation recently estimated that a “first-of-kind” surface retort
facility might cost $5-$7 billion, with operating costs of $17 to $23/bbl in 2005
dollars. Rand projects that a crude oil equivalent of West Texas Intermediate would
need to be at least $70 to $95/bbl for such an operation to be profitable.46 Shell Oil
believes that in situ conversion can be profitable, producing oil-shale distillates at
$25/bbl once steady-state production is reached.47 The disparity in estimates
demonstrates the controversy over the issue. It should be noted that Rand refers to
the older retorting technology that relied on mining methods for resource extraction,
whereas Shell’s estimate is based on oil field-based technology for resource
extraction.
The Ideal Size for an Oil Shale Facility
As domestic crude oil production declined through the 1970s, many marginally
profitable and often smaller refineries were closed or idled.48 Of the 324 refineries
operating 1981, 142 refineries currently remain operating. However, they represent
a crude distillation capacity of approximately 17.5 million bpd, compared with 14.5
million bpd in the mid 1980s, and range in size from 557,000 bpd (ExxonMobile’s
Baytown, Texas refinery) to 1,707 bpd (Foreland Refining Corp’s refinery in Eagle
44 (...continued)
Refined Product Margins and Costs per Barrel Sold and Product Sales Volume for FRS
Companies, 2003-2004, at [http://www.eia.doe.gov/emeu/perfpro/], visited Apr. 12, 2006.
45 U.S. DOE EIA, Crude Oil Refiner Acquisitions Costs, Table 5.21, 1968-2004, at
[http://www.eia.doe.gov/emeu/aer/txt/ptb0521.html], visited Feb. 21, 2006.
46 Bartis, James, T., et al., Oil Shale Development in the United States, The Rand
Corporation, 2005.
47 “Is Oil Shale America’s Answer to Peak-Oil Challenge?” Oil & Gas Journal, Aug. 9,
2004.
48 The last new U.S. refinery was built in 1976 by Marathon Ashland in Garyville,
Louisiana. U.S. DOE EIA, Country Analysis Briefs — United States of America January,
2005, at [http://www.eia.doe.gov/emeu/cabs/usa.html], visited Apr. 5, 2006.

CRS-17
Springs, Nevada).49 The median capacity (half above and half below) of all operating
refineries is approximately 80,000 bpd (Figure 3). The 71 refineries above the
median capacity are responsible for 85% of the current overall U.S. production (14.8
million bpd). The trend toward larger refineries reflects the economic efficiency
gained by increased scale. (For further information on refining, refer to CRS Report
RL32248, Petroleum Refining: Economic Performance and Challenges for the
Future, by Robert L. Pirog.)
Figure 3. Refinery Capacity Distribution Above and
Below Median 80,000 BPD Size
Source: EIA Annual Energy Outlook, Table 38, Capacity of Operable Petroleum Refineries by State,
2005.
OTA’s reference case 50,000 bpd oil shale facility would have been typical for
refinery capacities in the late 1970s, but compared with current capacities, it might
appear undersized. However, in terms of matching middle-distillate output, an oil
shale facility requires a the capacity of a conventional refinery. Since U.S. refineries
yield at most 47% motor gasoline vs. 33% middle-distillates, a 50,000 bpd oil shale
facility today (producing middle distillates exclusively) would match the distillate
output of a 150,000 bpd conventional refinery.50 This suggests that relatively smaller
oil shale production facilities could be as effective as a larger conventional refinery
when it comes to producing middle distillates.
The complicated permitting process has been an argument against building a
new refinery and for expanding an existing refinery’s capacity instead. The approval
49 U.S. DOE EIA, Refinery Utilization and Capacity, at [http://tonto.eia.doe.gov/
dnav/pet/pet_pnp_top.asp.], visited Feb. 22, 2006.
50 U.S. DOE EIA, Petroleum Supply Annual 2004, vol. 1, Table 19, Percent Refinery Yield
of Petroleum Products by PAD and Refining Districts, 2004, at [http://www.eia.doe.gov/
oil_gas/petroleum/data_publications/petroleum_supply_annual/psa_volume1/psa_volum
e1.html], visited Apr. 5, 2006.

CRS-18
process for new refinery construction has been estimated to require up to 800
different permits.51 An oil shale facility’s considerably less complexity would appear
to have an inherent advantage over a conventional refinery when it comes to
permitting. Congress recognized that increasing petroleum refining capacity serves
the national interest and included provisions in the Energy Policy Act of 2005 (Title
III, Subtitle H — Refinery Revitalization) to streamline the environmental permitting
process. A refiner can now submit a consolidated application for all permits required
by the Environmental Protection Agency (EPA). To further speed the permit’s
review, the EPA is authorized to coordinate with other federal agencies, enter into
agreements with states on the conditions of the review process, and provide states
with financial aid to hire expert assistance in reviewing the permits. Additional
provisions under Title XVII (Incentives for Innovative Technologies) of the act
guarantee loans for refineries that avoid, reduce, or sequester air pollutants and
greenhouse gases if they employ new or significantly improved technology.
Permitting would be a secondary consideration for new construction, if refining was
an unfavorable investment.
Competing with Imported Distillates
Between 1993 and 2005, low-sulfur middle distillate production in the United
States tripled from 328 million barrels to 1,058 million barrels, but some imports
were still needed to satisfy demand (Figure 4). The current 55 million barrels per
year of imports is the equivalent of 150,000 bpd in production, or three oil shale
plants on the scale of OTA’s reference case 50,000 bpd facility.
51 “Crude Awakening,” Investor’s Business Daily, Mar. 28, 2005.

CRS-19
Figure 4. Imported Crude Oil and Refined Products
Source: EIA Petroleum Navigator, U.S. Refinery Production of Distillates 15-500 ppm Sulfur, and
U.S. Distillates 15-500 ppm Sulfur Imports, at [http://tonto.eia.doe.gov/dnav/pet/hist].
Like U.S. refineries, European refineries also began to optimize for gasoline
production in the early 1990s, only to see the European demand shift toward middle-
distillate diesel fuel due largely to European tax incentives (discussed below) that
favor diesel fuel use. Excess gasoline now produced by these refineries is exported
to the U.S. market. Diesel fuel is forecast to make up 68% percent of European
consumption by 2010.52 How European refineries respond to an increased diesel fuel
demand will likely affect gasoline exports to the United States, particularly if the
refineries shift their optimization more toward diesel than investing capital in
additional diesel capacity. Both diesel and gasoline exports to the U.S. market could
be reduced. U.S. refineries appear to have little excess capacity to make up both the
gasoline and diesel loss, leaving some opportunity for oil shale to make up the
distillate loss.
Assuming that U.S. refineries yield a middle-distillates, actual refining capacity
on the order of 1 million bpd would have been required. In terms of oil shale
production, three 50,000-bpd plants processing 1,867 million tons of oil shale
(yielding 15 to 30 gallons per ton) could be required to fill the possible gap in
domestic supply.
52 Energy Intelligence Group, “European Refiners Need to Bite Bullet of Downstream
Investment,” Mar. 14, 2005, at [http://www.energyintel.com/].

CRS-20
Regulatory Disincentives
Apart from economic reasons, some regulatory policies may discourage the
production and use of oil-shale distillate fuels. Both gasoline and diesel fuel are
subject to Clean Air Act regulations and federal motor fuel taxes. Both regulations
and taxes are more lenient towards gasoline use. In comparison, European Union
(EU) environmental standards and tax regulations are more lenient towards diesel
fuel and consequently have stimulated its broader consumption. Since oil-shale
distillates could substitute for diesel fuel, any regulatory bias toward gasoline could
act as a disincentive to oil shale production.
Diesel Vehicle Demand. Passenger vehicles and light-duty trucks (under
8,500 lbs. gross vehicle weight) create the primary demand for transportation fuel in
the United States. However, nearly 22% of the transportation fuel demand is for
diesel, primarily in heavy-duty on- and off-road vehicles (semi-tractor trucks,
earthmoving equipment, and railroad locomotives). Light-duty diesel trucks and
passenger vehicles make up a smaller (but uncertain) percentage of the diesel
demand, based on the lower number of miles private vehicles drive annually
compared with commercial vehicles. Light-duty vehicles do, however, make up
slightly more than half of the on-road diesel vehicles sold. Though overall, light-duty
diesel vehicles have made up only 5% of the total light-duty vehicles sold recently
(~349,000 light-duty diesel trucks and ~30,000 diesel passenger vehicles versus 16.9
million total light-duty vehicles sold in 2004).53 The EIA sees a slower growth of
light-duty diesel vehicles in the United States than in Europe.54 In contrast to U.S.
sales of light-duty diesel vehicles, new diesel passenger vehicle registration in Europe
rose from 22.3% in 1998 to 48.25% in 2004.55 The effect of increased diesel
registration can be seen in the increased refinery output and net deliveries of diesel
reported for European members of the Organization of Economic Co-operation and
Development (OECD) by the International Energy Agency (IEA).56 (See Figure 5.)
Assuming that a separate diesel fuel for light-duty diesel vehicles will not be
created, the EIA projects that U.S. refiners are unlikely to see the impact of a
developing light-duty diesel vehicle market in the next decade. Given EIA’s
projection, the opportunity for oil-shale distillates as diesel substitutes would appear
similarly limited in the United States.
53 Ward’s Automotive Yearbook 2005, U.S. Diesel Car Market Share, p. 36.
54 U.S. DOE EIA, Can U.S. Supply Accommodate Shifts to Diesel-Fueled Light-Duty
Vehicles?, Oct. 7, 2005.
55 “The Changing Face of Europe’s Car Industry,”The Economist Newspaper Ltd, Mar. 24,
2005.
56 International Energy Agency, IEA Energy Statistics, Monthly Oil Survey, at
[http://www.iea.org/Textbase/stats/oilresult.asp], visited Apr. 12, 2006.

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Figure 5. Net Deliveries vs. Refinery Output of
Gas/Diesel Oil for OECD Europe
Source: International Energy Agency, Monthly Oil Survey, 2000 through 2005.
CO, NOx, and PM Emissions. Compared with spark-ignition (gasoline)
engines, compression-ignition (diesel) engines characteristically emit lower amounts
of carbon monoxide (CO) and carbon dioxide (CO ), but they emit higher amounts
2
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) Tier 1 and 2
Emission Standards. Under Tier 1, the NOx standard had been 1.0 gram/mile for
diesel passenger and light-duty trucks, versus 0.4 grams/mile for gasoline vehicles.
The Tier 2 standards that started taking effect in 2004 are fuel-neutral. Regardless
of the fuel, a fleet of vehicle models manufactured in a given year must average 0.07
grams/mile for NOx emissions. A particular vehicle model may qualify in a unique
emission “bin” (the maximum allowable is 0.2 grams/mile), as long as the fleet of
models meets the average NOx emission standard. Other pollutants are similarly
regulated.
Since diesel engines inherently produce more NOx and PM than gasoline
engines, producing more diesel vehicles raises the fleet emission average and thus
limits the total number of vehicles a manufacturer can sell in the United States. This
in turn limits the demand for diesel vehicles, which thus limits the opportunity for
oil-shale distillates. The U.S. Tier 2 NOx emissions standards are more stringent

CRS-22
than the EU’s current Euro 4 standards of 0.4 grams/mile for diesel cars and 0.6
grams/mile for light-duty diesel trucks. Tier 2 PM-emission standards of 0.01 to 0.02
grams/mile are also more stringent than Euro 4 PM-emissions of 0.04 grams/mile.
The Tier 2 CO-standard of 4.2 grams/mile is significantly less stringent than the
Euro 4 standard of 0.8 grams/mile for diesel passenger cars and 1.2 grams/mile for
light-duty diesel trucks. Tier 2 favors gasoline over diesel in this case.
The EU is moving toward taxing cars on the basis of CO emissions (which
2
favors diesel).57 This move is in response to the Kyoto Protocol on climate change,
which seeks to limit CO emissions, a treaty that the United States signed but did not
2
ratify.
Should oil-shale distillates substitute for diesel, Tier 2 limits on CO, NOx, and
PM emissions would continue to apply, as the standard is fuel-neutral. However, the
emission characteristics of oil-shale distillates (similar to diesel) have not been the
subject of documented research.
Ultra-Low Sulfur Diesel. By mid-2006, new U.S. standards for ultra-low
sulfur diesel (ULSD) take effect under a 2001 rule issued by the EPA.58 Diesel fuel
sulfur content must be reduced to no more than 15 parts-per-million (ppm) from the
current 500 ppm (established by a 1993 rule that reduced the level from 5,000 ppm).
However, to account for pipeline contamination, refiners may have to produce diesel
fuel with a sulfur content as low as 7 ppm; a four-year phase-in period allows for
20% of the highway diesel produced to meet the current limit.
The EIA estimates the marginal cost of producing ultra-low sulfur diesel to
range from 2.5¢ to 6.8¢ per gallon, depending on whether supply falls short of
demand or consumers bid up the price.59 EIA projects the ULSD rule to require total
refinery investments ranging from $6.3 to $9.3 billion. As the energy content of
ULSD is somewhat less than 500 ppm diesel, fuel efficiency may be affected
(increasing fuel consumption and therefore demand).
The sulfur content of oil-shale distillates is comparable in weight percentage to
crude oil (Table 1). U.S. refiners were able to meet the current 500 ppm requirement
by increasing the existing capacity of their hydrotreatment units and adding new
units. However, refineries may face difficulty in treating diesel to below 500 ppm.
The remaining sulfur is bound in non-hydrocarbon, multi-ring thiophene-type
compounds that prove difficult to hydrotreat because the molecular ring structure
attaches the sulfur on two sides. Although these compounds occur throughout the
range of petroleum distillates, they are more concentrated toward the residuum end.
57 “Emission Taxes Could Displace Registration Taxes,” The Economist Newspaper Ltd.,
Mar. 24, 2005.
58 U.S. EPA, “Control of Air Pollution from Motor Vehicles: Heavy-Duty Engine and
Vehicle Standards and Highway Diesel Fuel Sulfur Control Requirements: Final Rule,”
Federal Register, 40 CFR, Parts 69, 80, and 86.
59 U.S. DOE EIA, The Transition to Ultra-Low-Sulfur Diesel Fuel: Effects on Prices and
Supply, May 2001.

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So, the problem is compounded when residuum is cracked to increase gasoline
production. Improved hydrotreatment technology since the 1980s has increased
sulfur removal and provided a means to removing oil-shale distillate’s excessive
nitrogen content (desirable in terms of producing stable fuels with low NOx
emissions).
Whereas conventional refineries may be able to further upgrade hydrotreatment
capacity by retrofitting, an oil shale processing plant would be designed and built
from the ground up with necessary capacity. However, many refineries either
produce the hydrogen needed for hydrotreating or purchase it from vendors that
operate near established refining centers. An oil shale facility may require the
addition of a steam reforming process to convert natural gas to the hydrogen needed.
Refiners’ response to the ULSD rule ultimately affects diesel supply and thus
price. As increased diesel fuel prices are likely to erode the lower operating-cost
advantage of diesel engines over gasoline, the incentive for purchasing light-duty
diesel vehicles would be less, in keeping with EIA’s projection of a slow growth in
light-duty diesel vehicles over the next decade. On the other hand, a decline in diesel
demand would offer even less incentive to produce oil-shale distillates for light-duty
vehicles.
Fuel Tax. The U.S. federal tax rate on motor fuel currently favors gasoline
over diesel fuel by 6¢ per gallon (18.4¢ and 24.4¢, respectively).60 Both gasoline and
diesel tax rates began increasing after the mid-1980s, but diesel increased at a faster
rate (Figure 5). The higher diesel fuel tax is essentially a user fee paid by heavy-duty
trucks to offset the higher road damage they cause than lighter duty vehicles. Where
motor fuel taxes are applied to transportation infrastructure improvements in the
United States, they are a source of general revenue for the 15 EU member states.
60 U.S. DOT, “Federal Tax Rates on Motor Fuels and Lubricating Oil,” Table Fe-101a., at
[http://www.fhwa.dot.gov/policy/ohim/hs03/htm/fe101a.htm]. The effective tax rate on
gasoline and diesel terminated Oct.1, 2005; new rates have not yet been published.

CRS-24
Figure 6. Diesel vs Gasoline Fuel Tax
llon
a
G
per
ents
C
Source: U.S. DOT, “Federal Tax Rates on Motor Fuels and Lubricating Oil,” Table Fe-101a.
Note: The U.S. federal tax rate on motor fuel currently favors gasoline over diesel fuel by 6¢ per
gallon. European Union states (except UK) tax diesel fuel on average (62¢/gallon less than gasoline).
Overall, motor fuel taxes are significantly higher in the EU, ranging from the
equivalent of $3.28/gallon ( 742/1,000 liters at an exchange rate of $1.17: 1) for
diesel and gas in the United Kingdom, to as low as 253/1,000 liters) ($1.12/gallon)
for diesel in Luxemburg. Except for the United Kingdom, diesel fuel is taxed on
average 62¢/gallon( 140/1,000 liters) less than gasoline.61 In December 2005, the
average end-use prices of gasoline in France and Germany were $5.26/gallon and
$6.08/gallon, respectively ( 1.170/liter and 1.226/liter), compared with $2.17/gallon
in the United States — with automotive diesel averaging $3.89/gallon and
$4.23/gallon in France and Germany, respectively ( 0.865/liter and 0.941/liter),
compared with $2.45/gallon in the United States.62 The end-use price difference in
the two fuels appears to correlate with the increasing registration of diesel cars in the
EU. With higher crude oil prices, the fuel savings advantage of diesel cars should
become even more compelling.
Diesel fuel demand is “regulatory driven” to an extent. Motor fuel taxes that
favor diesel over gasoline offer one means of redirecting demand, but the tax
differential may need to be significantly higher than the current 6¢ per gallon
differential favoring gasoline. Raising motor fuel taxes above the current federal
level runs counter to current policy. In the aftermath of Hurricane Katrina, when
gasoline prices surged above $3 per gallon, some states suspended or considered
suspending taxes on gasoline. However, advocates of energy conservation argued
61 EurActive, Fuel Taxation, Nov. 25, 2003, at [http://www.euractiv.com/Article?
tcmuri=tcm:29-117495-16&type=LinksDossier], visited Apr. 5, 2006.
62 International Energy Agency, End-user Petroleum Product Prices and Average Crude Oil
Import Costs, December 2005, Jan. 6, 2006.

CRS-25
that the higher gasoline prices conserved fuel by discouraging driving, thus the motor
fuel tax should have remained or even increased. If higher motor fuel tax stimulates
the demand for more fuel-efficient vehicles, as the European experience suggests, the
inherent fuel efficiency offered by a diesel passenger vehicle becomes more apparent,
if not desirable. This in turn could act as an additional incentive for producing diesel
or alternatives such as oil-shale distillates.
Policy Perspective and Consideration
Federally sponsored research to develop fuel substitutes from oil shale dates
back the U.S. Synthetic Liquid Fuels Act of 1944 out of World War II concerns for
oil supplies. Later, in response to the oil embargos of the 1970s, Congress created
the Synthetic Fuels Corporation. National security had been a motivating concern
(i.e., to aid the prosecution of the war and to contend with foreign actions that
interrupt energy supplies). As newly discovered, less-costly-to-produce petroleum
reserves entered production in the early 1980s, the economic and operating
conditions of oil shale production became unfavorable. As commercial interests
backed out of projects, Congress terminated synthetic fuel development. Various
commercial attempts to exploit the resource met with limited success. Technological
developments that transformed petroleum refining efficiency, and the discovery of
new petroleum reserves, shifted private sector interest away from oil shale resources.
The global demand-driven petroleum supply cycle, if true to history, is likely to
exhibit periods of surplus and shortage. Periods of surplus fit well with the just-in-
time supply model that seeks to hold down inventory costs by minimizing stocks on
hand. Proponents of the self-correcting petroleum market theory may argue that
supply interruptions are temporary and that price spikes signal customers to reduce
consumption. Opponents may argue that reduced consumption is not an option
during a national security crisis and that there ought to be a “just-in-case”
contingency in place, such as oil shale. While the threat from future OPEC-like
embargoes appears unlikely, the President’s goal “to replace more than 75 percent
of our oil imports from the Middle East by 2025" indicates continuing concern.63
Recent high crude oil prices renewed interest in oil shale, prompting Congress
to include provisions in the Energy Policy Act of 2005 promoting the lease and
development of federal oil shale holdings. The Act also identified oil shale as a
strategically important domestic resource and directed the Energy Department to
coordinate and accelerate its commercial development.
The misconception persists, however, regarding oil shale’s fungibility as a crude
oil substitute. It doesn’t effectively replace crude oil as a gasoline feedstock. Thus,
policies that attempt to foster oil shale development come into conflict with
regulatory policies that favor gasoline as transportation fuel. The best use of the
resource appears to be as feedstock for producing middle-distillate fuels. Regulatory
policies that are acting to discourage wider use of middle-distillate fuels thus may be
acting as a disincentive to oil shale production. Congress may wish to consider
63 President George W. Bush, State of the Union, Jan. 31, 2006.

CRS-26
whether a special case should be made for oil shale, and whether to exempt the
middle-distillate fuels produced from regulatory policies that restrict their wider use
as transportation fuels.
The President’s FY2007 budget request would terminate the Energy
Department’s oil technology research, and the Defense Department’s initiative to
develop clean fuels from oil shale (among other resources) appears unfunded.64
Whether oil shale can be economically produced, even given the current high
cost of conventionally recovered petroleum, remains unclear. However, without a
long-term concerted effort to produce oil shale, either through a federal- or private
sector-sponsored enterprise, the economic viability will remain questionable. The
expectation of initial high unit costs should be weighed against the offset in demand
for imported products and the effect on lowering price that competition brings.
64 Personal communication with Dr. Theodore K. Barna, Feb. 8, 2006.

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Appendix: Legislative History
The Pickett Act of 1910 initially authorized withdrawal of potential oil-bearing
lands in California and Wyoming as sources of fuel for the Navy. Executive orders
later created three Naval Petroleum and Oil Shale Reserves between 1912 and 1927
by setting aside federal lands believed to contain oil as an emergency reserve.
The U.S. Synthetic Liquid Fuels Act of 1944 (30 USC Secs. 321 to 325)
authorized $30 million over five years for “the construction and operation of
demonstration plants to produce synthetic liquid fuels from coal, oil shales,
agricultural and forestry products, and other substances, in order to aid the
prosecution of the war, to conserve and increase the oil resources of the Nation, and
for other purposes.” The act also authorized the Interior Secretary to construct,
maintain, and operate plants producing synthetic liquid fuel from coal, oil shale, and
agricultural and forestry products. The Bureau of Mines received $87.6 million for
an 11-year demonstration plant program.
The Defense Production Act of 1950 (Ch. 932, 64 Stat. 798), enacted during the
Korean War, was intended to develop and maintain whatever military and economic
strength necessary to support collective action through the United Nations. The
diversion of certain materials and facilities from civilian to military use required
expansion of production facilities beyond the levels needed to meet civilian demand.
Section 303 of Title III (Expansion of Production Capacity and Supply) authorized
the President “extraordinary” procurement power to have liquid fuels processed and
refined for government use or resale, and to make improvements to government or
privately owned facilities engaged in processing and refining liquid fuels when it
would aid the national defense. In 1980, Congress added provisions (P.L. 96-294)
that related to preparing for terminated or reduced availability of energy supplies for
national defense needs. Section 305 of the act authorized the President to purchase
synthetic fuels for the purpose of national defense. Executive Order 12242 then
directed the Secretary of Defense to determine the quantity and quality of synthetic
fuel needed to meet national defense needs for procurement.
The Naval Petroleum Reserves Production Act of 1976 (P.L. 94-258), in
reference to Naval Petroleum Reserve No. 4 in Alaska, defined petroleum to include
crude oil, gases (including natural gas), natural gasoline, and other related
hydrocarbons, oil shale, and the products of such sources.
The Department of Energy Organization Act of 1977 (P.L. 95-91) transferred
control of the Naval Petroleum and Oil Shale Reserves from the Navy to the
Department of Energy.
The United States Synthetic Fuels Corporation Act of 1980 (P.L. 96-294)65
amended the Defense Production Act by establishing the U.S. Synthetic Fuels
Corporation (SFC) “to improve the Nation’s balance of payments, reduce the threat
of economic disruption from oil supply interruptions, and increase the Nation’s
65 Title I, Part B of the Energy Security Act of 1980.

CRS-28
security by reducing its dependence on foreign oil.” The corporation was authorized
to provide financial assistance to qualified projects that produced synthetic fuel from
coal, oil shale, tar sands, and heavy oils. Financial assistance could be awarded as
loans, loan guarantees, price guarantees, purchase agreements, joint ventures, or
combinations of those types of assistance. An Energy Security Reserve fund was
also established in the U.S. Treasury and appropriated $19 billion to stimulate
alternative fuel production. Executive Order 12242 (1980) directed the Secretary of
Defense to determine the quantity and quality of synthetic fuel needed to meet
national defense needs for procurement under the Defense Production Act.
Executive Order 12346 (Synthetic Fuels) of 1982 revoked EO 12242 and provided
for an orderly transition of synthetic fuel responsibilities from the Department of
Energy to the United States Synthetic Fuels Corporation.
The Crude Oil Windfall Profit Tax Act of 1980 (P.L. 96-223) ostensibly
provided revenue to maintain the Energy Security Reserve fund. The Internal
Revenue Code was amended to impose an excise tax on windfall profits of domestic
producers of taxable crude oil. A production tax credit of $3.00 (1979 dollars) per
barrel of oil equivalent was provided to stimulate oil shale development. The House
conference report (H. Rept 96-817) projected $227.3 billion in total revenue from
the tax after 1988. In the Windfall Profit Tax Account established to hold the
revenue, 15% had been allocated for energy and transportation. In 1983, the
Congressional Budget Office estimated that the revenue would only reach 40% of the
conference report’s projection and only 20% by 1988, as the price of crude oil had
been lower than projected. Congress repealed the windfall profit tax in 1988 ( P.L.
100-418).
The House began considering a bill to abolish the SFC with the Synthetic Fuels
Fiscal Responsibility Act of 1985 (H.R. 935). The Energy and Commerce
Committee debate of the bill (Rept. 99-196) linked abolishing the Corporation to
reducing the federal deficit and viewed purchasing oil for the Strategic Petroleum
Reserve as a far more cost effective defense against another embargo by OPEC than
subsidizing synthetic fuels. The minority view noted that as late as 1983, the
Department of Defense had certified that synthetic fuel was needed to meet national
defense needs under Executive Order 12242. In September 1985, the Senate
Committee on Appropriations report (S.Rept. 99-141) recommended increasing the
Department of Energy Oil Shale Program budget and reaffirmed the goal of oil shale
reserves supplying petroleum during a national emergency. Support for the SFC
could not be sustained, and Congress terminated it under the Consolidated Omnibus
Reconciliation Act of 1985 (P.L. 99-272). Remaining obligations were transferred
to the Treasury Department, and the duties of the Chairman of the SFC Board were
transferred to the Secretary of the Treasury.
The Department of Energy Organization Act of 1977 (P.L. 95-91) transferred
Navy control of the NOSRs to the Department of Energy. The National Defense
Authorization Act of 1998 (P.L. 105-85) transferred NOSR Nos. 1 and 3, located
near Rifle, Colorado, from the Department of Energy to the Bureau of Land
Management. The National Defense Authorization Act of 2000 (P.L. 106-398)
transferred NOSR No. 2 in Utah to the Ute Indian Tribe.

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The Oil Shale, Tar Sands, and Other Strategic Unconventional Fuels Act of
200566 declares the strategic importance of domestic oil shale resources and their
development. The act directs the Secretary of the Interior to commence commercial
leasing of oil shale on public lands and to establish a task force in cooperation with
the Secretary of Defense to develop a program for commercially developing strategic
unconventional fuels, including but not limited to oil shale. Section 2398a.
(Procurement of Fuel Derived from Coal, Oil Shale, and Tar Sands) directs the
Secretary of Defense to develop a strategy to use fuel produced from oil shale to help
meet the fuel requirements of the Department of Defense when the Secretary
determines that doing so is in the national interest
66 Section 369 of the Energy Policy Act of 2005.