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 largescale 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 middledistillates 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. 8991, 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 distillatebased 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 isoparaffins (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

9

John M. Hunt, Petroleum Geochemistry and Geology, W.H. Freeman and Co., 1979.

Cn is shorthand notation for the number of carbon atoms. John M. Hunt, Petroleum

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 C5-C10; middle-distillate fuels (kerosene,

jet, and diesel) range C11-C18. Crude oil may contain 10%-40% gasoline, and early

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 (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.

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 lowquality 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 middledistillates (kerosene, jet fuel, diesel fuel) appear extractable.

Table 1. Properties of Oil-Shale Distillates Compared with

Benchmark Crude Oils

° API

OTA Reported Oil-Shale Distillates Propertiesa

% Sulfur

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

37-42

<0.42

29-29.5

1.10

NYMEX Deliverable Grade Sweet Crude Oil

Specificatione

Alaska North Slope Crude Oild

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 ExxonTosco’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 middledistillate 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.

CRS-21

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 (CO2), 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) 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 CO2 emissions (which

favors diesel).57 This move is in response to the Kyoto Protocol on climate change,

which seeks to limit CO2 emissions, a treaty that the United States signed but did not

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.

CRS-23

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

Cents per Gallon

Figure 6. Diesel vs Gasoline Fuel Tax

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-intime 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.

CRS-27

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.

CRS-29

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.