Developments in Oil Shale
Developments in Oil Shale
November 17, 2008
Specialist, Energy and Energy Infrastructure Policy
Resources, Science, and Industry Division
Developments in Oil Shale
The Green River oil shale formation in Colorado, Utah, and Wyoming is
estimated to hold the equivalent of 1.38 trillion barrels of oil equivalent in place. The
shale is generally acknowledged as a rich potential resource; however, it has not
generally proved to be economically recoverable. Thus, it is considered to be a
contingent resource and not a true reserve. Also, the finished products that can be
produced from oil shale are limited in range to primarily diesel and jet fuel. Earlier
attempts to develop oil shale under the 1970s era Department of Energy (DOE)
Synthetic Fuels program and the later Synthetic Fuels Corporation loan guarantees
ended after the rapid decline of oil prices and development of new oil fields outside
the Middle East. Improvements taking place at the time in conventional refining
enabled increased production of transportation fuels over heavy heating oils (which
were being phased out in favor of natural gas).
Rising oil prices and concerns over declining petroleum production worldwide
revived United States interest in oil shale after a two-decade hiatus. In addition to
technological challenges left unsolved from previous development efforts,
environmental issues remained and new issues have emerged. Estimates of the
ultimately recoverable resource also vary. Challenges to development also include
competition with conventional petroleum production in the mid-continent region, and
increasing petroleum imports from Canada. The region’s isolation from major
refining centers in the Gulf Coast may leave production stranded if pipeline capacity
is not increased.
The Energy Policy Act of 2005 (EPAct) identified oil shale as a strategically
important domestic resource, among others, and directed the Department of the
Interior to promote commercial development. Since then, the Bureau of Land
Management (BLM) has awarded six test leases for oil research, development, and
demonstration (RD&D). The ongoing program will confirm whether an economically
significant shale oil volume can be extracted under current operating conditions. If
so, early commercial development may directly proceed. BLM has published a final
Programmatic Environmental Impact Statement (PEIS) in which approximately two
million acres of oil shale lands, out of approximately 3.54 million acres total, are
identified as potentially available for commercial leasing. Draft rules for commercial
leases have also been issued, and final rule making is proceeding. The lease and
royalties rates proposed in the draft rules appear to compare with rates charged for
similar resources, but provide no unique incentive for producing oil shale.
In a previous report, CRS framed oil shale in the perspective of national energy
security and reviewed the circumstances under which policies first promoted and then
ended support for earlier oil shale development. This second report takes up the
progress toward commercializing oil shale development under the EPAct 2005
mandates, and offers a policy perspective that takes account of current turmoil in the
Oil Shale Resource Potential.........................................2
Challenges to Development..........................................5
Competition With Regional Resources.............................6
Supply and Disposition.........................................7
Restrictions to Leasing.........................................15
Commercial Leasing Program.......................................18
Programmatic Environmental Impact Statement.....................21
Mineral Leasing Act Amendments...............................23
Commercial Lease Sale and Royalty Rates .........................23
Proposed Leasing Rules....................................23
Standard Federal Lease and Royalty Terms.....................25
Private Lease Terms.......................................27
Conclusion and Policy Perspective...................................29
List of Figures
Figure 1. Most Geologically Prospective Oil Shale Resources within the Green
River Formation of Colorado, Utah, and Wyoming...................3
Figure 2. Oil Shale Acreage..........................................4
Figure 3. Shale Oil Volume..........................................4
Figure 4. Petroleum Administration for Defense Districts..................6
Figure 5. United States and Canada Crude Oil Pipelines...................7
Figure 6. Federal Land Access for the Most Geologically Prospective Oil
Figure 7. Locations of the Six RD&D Tracts and Associated Preference Right
Table 1. Crude Oil and Petroleum Products by PADD (2007-2008)...........8
Table 2. Refinery Yield by PADD.....................................9
Table 3. Atmospheric Crude Oil Distillation Capacity of Operable
Petroleum Refineries in PADD 4.................................10
Table 4. RD&D Leases............................................19
Table 5. Proposed Options for Oil Shale Royalty Rates...................25
Table 6. Federal Standard Lease and Royalty...........................26
Table 7. Shale Gas Bonus Bids, Rents, and Royalty Rates on Selected State
Table 8. Shale Gas Bonus Bids, Rents, and Royalty Rates on Private
Land in Selected States........................................29
Developments in Oil Shale
Declining domestic production, increasing demand, and rising prices for
petroleum have underscored the United States’ dependence on imported oil. In
response, proponents of greater energy independence have argued that the huge
undeveloped oil shale resource in the Rocky Mountain region should be opened for
commercial development.1 Those concerned over repeating past mistakes and
compromising the environment, however, have urged caution and deliberation in
Earlier attempts to develop oil shale had received direct funding support under
the 1970s era Department of Energy (DOE) Synthetic Fuels (SynFuels) program and
the later Synthetic Fuels Corporation loan guarantee program. Private sector interest
in oil shale all but ended after the rapid decline of oil prices and the development of
new oil fields outside the Middle East in the early 1980s. Federal support ended by
the mid-1980s with the commissioning of the Strategic Petroleum Reserve. Also at
the time, improved refining processes enabled conversion of petroleum residuum into
high-value transportation fuel. The residuum (figuratively, the bottom of the
petroleum barrel) had been processed into low-value heavy heating oil, which was
being replaced by cleaner burning and increasingly available natural gas. Then, as
now, oil shale was considered a strategic resource. However, its strategic value more
recently had been tied to producing defense-related jet fuel, which now appears to be
an uncertain prospect. Oil shale shows better potential as a resource for commercial
transportation fuels — jet and diesel. However, it faces regional competition from
conventional petroleum resources and their wider distribution, and thus use may be
constrained by infrastructure limitations. For information on the history of oil shale
under the Synthetic Fuels Program refer to CRS Report RL33359, Oil Shale: History,
Incentives, and Policy.
In 2005, Congress conducted hearings on oil shale to discuss opportunities for
advancing technology that would facilitate “environmentally friendly” development2
of oil shale and oil sand resources. 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.3 The subsequent Energy Policy Act of 2005 (EPAct —
1 U.S DOE/EIA. Monthly Energy Review January 2006, Table 1.7, Overview of U.S.
Petroleum Trade, [http://www.eia.doe.gov/emeu/mer/pdf/pages/sec1_15.pdf].
2 Oil sands yield a bitumen substantially heavier most crude oils and shale oil.
3 Oversight Hearing on Oil Shale Development Effort, Senate Energy and Natural Resources
P.L.109-58) included provisions under Title III Oil and Gas that promoted the
development of oil shale, tar sands, and other strategic unconventional fuels.4
Section 369 of EPAct directed the Department of the Interior (DOI) to offer test
leases for research, development and demonstration (RD&D); prepare a
programmatic environmental impact statement (PEIS); issue final rules for
commercial oil shale leasing; and commence commercial leasing. EPAct also
directed the Department of Defense (DOD) to develop a strategy for using fuel
derived from oil shale (among other unconventional resources).
Oil Shale Resource Potential
Oil shales exist in several states in the United States. Their kerogen content is
the geologic precursor to petroleum. The term shale oil is used in this report to refer
to the liquid hydrocarbon products that can be extracted from the shale. The most
promising oil shales occur in the Green River formation that underlies 16,000 square
miles (10.24 million acres) of northwestern Colorado, northeastern Utah, and
southwestern Wyoming (Figure 1). The most geologically prospective oil shale
areas make up ~3.5 million acres. The Bureau of Land Management (BLM)
administers approximately 2.1 million acres. Another 159,000 acres is made of BLM
administered split estate lands. These are areas where the surface estate is owned by
Tribes, states, or private parties, but the subsurface mineral rights are federally-
Estimates of oil shale’s resource potential vary. The DOE Office of Naval
Petroleum and Oil Shale Reserves estimates that ~1.38 trillion barrels of shale oil are
potentially recoverable from the roughly 7.8 million acres of federal oil shales
(Figures 2 and 3).5 The Rand Corporation conservatively estimates that only 8006
billion barrels may be recoverable. Though Utah represents the greatest areal extent
of federally managed oil shale land, Colorado’s shale may offer a greater potential
for recovery because of the resource richness.
Committee, April 12, 2005.
4 EPAct Section 369 Oil Shale, Tar Sands, and Other Strategic Unconventional Fuels; also
cited as the Oil Shale, Tar Sands, and Other Strategic Unconventional Fuels Act of 2005.
5 U.S. DOE, Office of Petroleum and Oil Shale Reserves, National Strategic Unconventional
Resource Model, April 2006.
6 J. T. Bartis, T. LaTourrette, L. Dixon, D.J. Peterson, and G. Cecchine, Oil Shale
Development in the United States Prospects and Policy Issues (MG-414-NETL), RAND
Figure 1. Most Geologically Prospective Oil Shale
Resources within the Green River Formation of
Colorado, Utah, and Wyoming
+Geologically Prospective Areas,
Tota l BLM Split
GeologicBasin AreaAdministered Estate
St Basin Size SizeLands Lands
CO Piceance 1,185,700 503,342 319,710 41,940
UT Uinta 2 ,977,900 840,213 560,972 77,220
WYGreen River & Washakie4,506,2002,194,4831,257,68039,406
Key: NPS: National Park Service; USFS: U.S. Forest Service
Source: Bureau of Land Management, Draft Oil Shale and Tar Sands Resource Management Plan
Amendments to Address Land Use Allocations in Colorado, Utah, and Wyoming and ProgrammaticEnvironmental Impact Statement, December 2007.
Figure 2. Oil Shale AcreageFigure 3. Shale Oil Volume
Source: DOE Office of Petroleum and Oil Shale Reserves, National Strategic Unconventional
Resource Model, April 2006.
The amount of shale oil recoverable depends on extraction technology and
resource “richness.” The richest oil shales occur in the Mahogany zone of the Green
River formation and could be expected to produce more than 25 gallons/ton (~b7
barrel). At that richness, one acre-foot would hold 1,600 to 1,900 barrels of shale oil.
The Mahogany zone can reach 200 feet in thickness in the Uinta Basin of Utah, and
thus could represent a technical potential of producing from 320,000 to 380,000
barrels of shale oil per acre if that volume of shale were fully exploited. The ultimate
yield would depend on extraction technologies being evaluated under the RD&D
program and the land area made available by the preferred leasing alternative selected
in the final PEI (discussed below). The potential yield would rival the ~1,400
barrels/acre-foot yields of Canada’s oil sand.8 It could well exceed the 50 to 1,0009
barrels/acre-foot yields of North America’s now-depleted giant oil fields.
As oil shales have not yet “proved” economically recoverable, they may be
considered contingent resources and not true reserves. The United States’
conventional proved oil reserves amount to less than 22 billion barrels with the
Arctic National Wildlife Refuge Coastal Plain potentially adding up to 17 billion
barrels of oil, as estimated by the U.S. Geological Survey. In comparison, Saudi
Arabia’s reserves are reportedly 262 billion barrels according to the Energy
7 CRS assumes an oil shale density of 125 to 150 lbs/ft3. 1 acre-foot = 43,560 ft3.
8 Reported as ½ barrel per ton. See Oil Sand Facts, Government of Alberta.
[http://www.energy.gov.ab.ca/OilSands/ 790.asp]. CRS assumes an oil density of 131 lbs/ft3.
9 Conventional petroleum reservoirs may only yield 35% of the oil in place, while enhanced
oil recovery may increase the total yield up to 50%. See: Geology of Giant Petroleum
Fields, American Association of Petroleum Geologists, 1970.
Challenges to Development
Oil shale has long been proposed as a source of synthetic or substitute crude oil.
However, the organic content (kerogen) of oil shale is only a petroleum precursor.
The extracted oil lacks the lower boiling-range hydrocarbons that make up natural
gasoline, and the heavier hydrocarbons that refineries crack to make gasoline. It does
yield hydrocarbons in the middle-distillate fuels boiling range — naphtha, kerosene,
jet fuel, and diesel fuel. Thus, it may face challenges as a substitute for conventional
crude oil. It may also face competition from conventional petroleum resources under
development in the Rocky Mountain region and Canadian exports to the region.
Oil shale production continues to face unique technological challenges. The
kerogen occurs in the shale as a solid and is not free to flow like crude petroleum.
The shale must be heated or “retorted”to extract petroleum-like distillates. Retorting
oil shale involves destructive distillation (pyrolysis) in the absence of oxygen.
Pyrolysis at temperatures above 900° F is needed to thermally break down the
kerogen to release the hydrocarbons. Two basic retorting processes have been used
— above-ground retorting and in situ (underground) retorting. The above-ground
retort is typically a large cylindrical vessel based on rotary kiln ovens used in cement10
manufacturing and now used by Canada’s oil sands industry. The in situ process
involves mining an underground chamber that functions as a retort. Both concepts
were evaluated under the former DOE Synfuels program.
Both in situ and above-ground retorting processes have been plagued with
technical and environmental problems. A plentiful water supply is considered
necessary for above-ground retorting. Above-ground retorting also depends on
underground or open-pit mining to excavate the shale. While either mining method
is well-practiced, the expended shale that remains after retorting would present a
disposal problem. In the case of open-pit mining, overburden rock had to be
removed and set aside to expose the shale. Above-ground retorts also faced frequent
problems from caked-up shale, which led them to shut down frequently. Apart from
the problem of sustaining controlled combustion underground, in situ retorting also
caused groundwater contamination.11
New approaches aim to avoid the past drawbacks associated with in situ
extraction methods by adapting enhanced oil recovery methods such as horizontal
drilling, long term heating, and freezewall technology (a geotechnical engineering
method for stabilizing saturated ground). The proposed technologies are discussed
in further detail below (see RD&D Program).
10 For further information see CRS Report RL34258, North American Oil Sands: History
of Development, Prospects for the Future.
11 For further information see CRS Report RL33359, Oil Shale: History, Incentives, and
Competition With Regional Resources
The Green River oil shales are located in the Rocky Mountain Petroleum
Administration for Defense District (PADD 4 — Figure 4). PADDs were delineated
during World War II to facilitate petroleum allocation. In the past, petroleum
pipeline infrastructure left PADD 4 isolated from the other districts, a situation that
may slowly improve with the emphasis on new production in the region.
With recent record-high crude oil price, crude production has increased in
PADD 4, as has local refining of this production. PADD 4 produced roughly 577
thousand barrels/day over 2007-2008 (Table 1). An estimated 588 million barrels of
undiscovered technically recoverable conventional oil and natural gas liquids are
estimated to underlie the Uinta-Piceance Basin of Utah-Colorado and an additional12
2.9 billion barrels are estimated to underlie southwestern Wyoming. Conventional
undiscovered technically recoverable resources are those hydrocarbon resources that,
on the basis of geologic information and theory, are estimated to exist outside of
known producing fields. They are resources that are considered producible using
current technology without regard to economic profitability. Natural gas, in
particular, has also been undergoing extensive development in Rifle, Colorado (the
focal point for the 1980s oil shale boom and bust).
Figure 4. Petroleum Administration for Defense Districts
The Bakken Formation, part of the larger Williston basin, is estimated to hold
from 3 to 4.3 billion barrels of oil, according to a recent delineation of the U.S.13
Geological Survey (USGS). The formation covers 529 square miles split between
12 U.S. DOI, Inventory of Onshore Federal Oil and Natural Gas Resource and Restrictions
to Their Development, Phase III Inventory — Onshore United States, 2008, See Tables 3-8
& 3-15. [http://www.blm.gov/wo/st/en/prog/energy/oil_and_gas/EPCA_III.html]
13 U.S.G.S, National Assessment of Oil and Gas Fact Sheet: Assessment of Undiscovered Oil
Resources in the Devonian-Mississippian Bakken Formation, Williston Basin Province,
Montana (PADD 4) and North Dakota (PADD 2). The USGS estimate places the
Bakken ahead of all other lower 48 states oil assessments, making it the largest
“continuous” oil accumulation ever assessed by the USGS. A “continuous” oil
accumulation means that the oil resource is dispersed throughout a geologic
formation rather than existing as discrete, localized occurrences. Bakken production
is increasing and is likely to add to PADD 4 production.
PADD 4 has also been a destination for oil exported from western Canada,
derived from both oil sands and conventional petroleum reservoirs (Figure 5).
Canada ranks as the largest crude oil supplier to the United States, exporting 1.6
million barrels per day. Subsequently, refiners in PADD 4 are taking less western
Canadian crude supplies in order to run the readily available and heavily discounted
Wyoming sweet and sour crude oils. The large discount is in reaction to aggressive
Canadian crude pricing, a shortage of refinery capacity, and the lack of pipeline
capacity to move the crude oil to other markets.
Figure 5. United States and Canada Crude Oil Pipelines
Supply and Disposition
Supply and disposition, as tracked by the Energy Information Administration
(EIA), is an indication of petroleum production, consumption and movements
between districts. Over 2007-2008, PADD 4 consumed an average 682,000
barrels/day of supplied products. Refiners and blenders in the district could only
Montana and North Dakota, 2008.
produce roughly 593,000 barrels/day (Table 1). Its roughly 174,000 barrels/day in
distillate production placed PADD 4 behind the other districts.14 This also left it15
short of meeting the regional distillate demand of 195,000 barrels/day.
Table 1. Crude Oil and Petroleum Products by PADD
Supply Dispo sit io n
(thousand barrels/day)(thousand barrels/day)
Field NetNet Adjust-Stock BlenderProducts
ProductionProductionImportsReceipts ments Change Net InputsExports Supplied
U.S. 6,847 17,994 13,468 n.a. 653 -148 16,999 1,433 20,680
Source: EIA Petroleum Supply Annual, Volume 1, July 28, 2008
Field Production represents crude oil production on leases, natural gas liquids production at natural gas processing plants, new
supply of other hydrocarbons/oxygenates and motor gasoline blending components, and fuel ethanol blended into finished motor
ga so line.
Refinery Production represents petroleum products produced at a refinery or blending plant. Published production of these
products equals refinery production minus refinery input. Negative production will occur when the amount of a product produced
during the month is less than the amount of that same product that is reprocessed (input) or reclassified to become another product
during the same month. Refinery production of unfinished oils, and motor and aviation gasoline blending components appear on
a net basis under refinery input.
Imports represents receipts of crude oil and petroleum products into the 50 States and the District of Columbia from foreign
countries, Puerto Rico, the Virgin Islands, and other U.S. possessions and territories.
Net Receipts represents the difference between total movements into and total movements out of each PAD District by pipeline,
tanker, and barge.
Stock Change represents the difference between stocks at the beginning of the month and stocks at the end of the month. A
negative number indicates a decrease in stocks and a positive number indicates an increase in stocks.
Exports represents shipments of crude oil and petroleum products from the 50 States and the District of Columbia to foreign
countries, Puerto Rico, the Virgin Islands, and other U.S. possessions and territories.
Product Supplied approximately represents consumption of petroleum products because it measures the disappearance of these
products from primary sources, i.e., refineries, natural gas processing plants, blending plants, pipelines, and bulk terminals. In
general, product supplied of each product in any given period is computed as follows: field production, plus refinery production,
plus imports, plus unaccounted for crude oil, (plus net receipts when calculated on a PAD District basis), minus stock change,
minus crude oil losses, minus refinery inputs, minus exports.
14 U.S. DOE/EIA, This Week in Petroleum. Four-Week Average for 08/22/08 through
15 Reported as 8,190.8 thousand gal/day. See U.S. DOE EIA, Prime Supplier Sale Volumes.
[http://tonto.eia.doe.gov/dnav/ pet/pet_c ons_prim_a_EPDED_K _P00_Mga lpd_a.htm] .
With the increasing competition from other petroleum resources produced and
refined in PADD 4, shale oil appears to faces stiff competition. However, the roughly
Distillate production (kero-jet fuel, kerosine, distillate fuel oil, and residual fuel oil)
makes up 38% of PADD 4 refining output, compared to 42% for the United States
on average (Table 2). For every barrel of distillate produced, almost three barrels of
crude oil must be refined. Increasing distillate production by 4% in the Rocky
Mountain region could make up the distillate deficit (at the expense of cutting back
on gasoline production).
Table 2. Refinery Yield by PADD
P ADD1 P ADD2 P ADD3 P ADD4 P ADD5 U.S.
Liquefied Refinery Gases3.23.95.01.52.84.1
Kerosene-Type Jet Fuel5.06.19.45.415.69.1
K e rosene 0.5 0.1 0.3 0.3 0.0 0.2
Distillate Fuel Oil29.428.226.029.820.826.1
Residual Fuel Oil22.214.171.124.66.34.2
Naphtha Petro Feed126.96.36.199.00.01.3
Lubricants 1.0 0.4 1.7 0.0 0.6 1.1
Waxes 0.0 0.1 0.1 0.0 0.0 0.1
Asphalt and Road Oil5.05.31.38.91.82.9
Processing Gain(-) or Loss(+)-5.1-5.8-6.9-3.0-6.4-6.3
Middle Distillate Average188.8.131.528.243.042.5
Source: Table 21. EIA Petroleum Supply Annual 2007, Volume 1.
For now, the most likely option for upgrading shale oil into finished products
is by conventional refining. However, shale oil does not fully substitute for
conventional crude oil. A typical refinery separates middle distillates during
atmospheric distillation — the first pass in the refining process — and then removes
sulfur and nitrogen by hydrotreating. The remaining heavier fraction (residuum) is
“cracked” then into gasoline through advanced refining processes. Shale oil consists
of middle distillate boiling-range products, and a typical refinery would not be
configured to crack the middle distillates into gasoline. In fact, some refineries find
it more profitable to increase middle distillate production (diesel and jet fuel) at the
expense of gasoline. There may be no economic rationale to crack shale oil into
Given the operating refineries in the PADD 4 (Table 3), any one refinery might
be hard pressed to expand capacity or shift production to make up the regional deficit
in distillate supply. The economics of constructing and operating a shale oil plant
may be uncertain but may also be outweighed by the cost of expanding operating
refinery capacity. As a reference case, the CountryMark refinery in Mount Vernon,
Indiana, is spending $20 million to add 3,000 barrels/day in diesel fuel capacity. The
expansion will increase throughput from 23,000 barrel/day to 26,000 barrels/day.16
CountryMark is a specialty refinery that makes diesel fuel for agriculture use.
Table 3. Atmospheric Crude Oil Distillation Capacity of Operable
Petroleum Refineries in PADD 4
Colorado Refining CoCommerce CityCO27,000
Suncor Energy (USA) Inc Commerce CityCO60,000
Cenex Harvest States Coop LaurelMT55,000
ExxonMobil Refining & Supply Co BillingsMT60,000
Montana Refining Co Great FallsMT8,200
Big West Oil Co North Salt LakeUT29,400
Chevron USA Inc Salt Lake CityUT45,000
Holly Corp Refining & Marketing Woods CrossUT24,700
Silver Eagle Refining Woods Cross UT10,250
Tesoro West Coast Salt Lake City UT58,000
Frontier Refining Inc CheyenneWY46,000
Little America Refining Co Evansville (Casper) WY24,500
Silver Eagle Refining Evanston WY3,000
Sinclair Oil Corp Sinclair WY66,000
Wyoming Refining Co NewcastleWY12,500
Source: EIA, As of January, 2005.
16 CountryMark, CountryMark Refinery Expansion to Increase Diesel Fuel Supply, April 3,
The economic prospects of building a shale oil upgrading plant are uncertain.
A new refinery has not been built in the United States since the late 1970s, as
operators have found it more efficient to expand the capacity of existing refineries
to yield more gasoline. Refineries increase gasoline yield by processes downstream
from atmospheric distillation that crack residuum with heat, pressure, catalysts, and
hydrogen. Overall refinery throughput though is limited by the atmospheric
distillation capacity. A shale oil plant would process a narrower boiling range of
hydrocarbons than a conventional refinery, and thus would not require the suite of
complex processes. Shale oil’s high nitrogen and sulfur content was considered
problematic, but the hydrotreating processes now used by refineries to produce ultra-
low sulfur diesel fuel can overcome that drawback. The hydrogen required for
hydrotreating may be made up in part from shale oil’s high hydrogen content and the
lighter volatile gases devolved during processing. A less-complex facility making
a limited slate of products compared to conventional refinery may prove less
burdensome to permit. The approval process for new refinery construction has been
estimated to require up to 800 different permits, notwithstanding anticipated
legislation mandating carbon capture and sequestration.17
Congress has recognized that increasing petroleum refining capacity serves the
national interest and included provisions under Title III of EPAct (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
EPAct Title XVII (Incentives for Innovative Technologies) guarantee loans for
refineries that avoid, reduce, or sequester air pollutants and greenhouse gases if they
employ new or significantly improved technology. It should be noted that permitting
would be a secondary consideration for new construction, if refining was an
Short of building new pipelines, expanding pipeline capacity to export either
crude or refined products from the Rocky Mountain regions appears to be an apparent
alternative. As shown in Figure 5, PADD 4 is relatively isolated from refining centers
in the Gulf Coast and does not serve the western states. To accommodate increased
crude oil imports from Canada, the Mobile Pipe Line Company reversed its 858 mile
crude oil pipeline that historically ran from Nederland, Texas, to Patoka, Illinois. The
pipeline now takes Canadian crude oil delivered to the Chicago region to Gulf Coast
Congress is considering various bills aimed at reducing and stabilizing
greenhouse gas emission. The Energy Independence and Security Act of 2007 (EISA
— P.L. 110-140) amends the Energy Policy Act of 2005 with research and
development programs to demonstrate carbon capture and sequestration, and restricts
17 Investor’s Business Daily, “Crude Awakening,” March 28, 2005.
the federal government’s procurement of alternative fuels that exceed the lifecycle
greenhouse gas emissions associated with conventional petroleum based fuels. Title
II of EISA directs the EPA to establish “baseline life cycle greenhouse gas
emissions” for gasoline or diesel transportation fuel replaced by a renewable fuel.18
The Lieberman-Warner Climate Security Act (S. 3036) would have established a
program to decrease emissions.
Until ongoing oil shale research development and demonstration projects are
completed (discussed below), and environmental impact statements are prepared for
permitting commercial development, adequate data to assess baseline emissions is
not available. Greenhouse gas emissions, primarily carbon dioxide (CO2), associated
with oil shale production can originate from fossil fuel consumption, and carbonate
A 1980 analysis concluded that retorting Green River oil shales and burning the
product could release from 0.18 tons to 0.42 tons CO2/barrel of oil equivalent,
depending on retorting temperatures.19 A large portion of the CO2 released would be
due to decomposition of carbonate minerals in the shale. The analysis concluded that
equivalent of 1½ to 5 times more CO2 could be emitted by producing fuels by
retorting and burning shale oil than burning conventional oil to obtain the same
amount of usable energy.
An “In Situ Conversion Process” being tested by the Shell Oil Company
(discussed below) is projected to emit from 0.67 to 0.81 tons CO2/barrel of refined
fuel delivered.20 The analysis concluded that the in situ retorting process could
produce 21% to 47% greater greenhouse gases than conventionally produced
Petroleum refining alone, accounts for approximately 0.05 tons CO2/barrel
refined of oil. In 2005, U.S. refineries emitted 306.11 million tons of CO2 to produce
5,686 million barrels of petroleum products.21 However, from a life-cycle
perspective, these emissions do not account for the CO2 emitted by expending fossil
energy for drilling, lifting (production), and transporting crude oil by tanker ship and
18 EISA Title II — Energy Security Through Increased Production of Biofuels. Section 201.
19 Originally reported as 30 kg carbon as CO2 per MBTtu for low-temperature retorting and
70kgC/MBtu for higher temperature retorting. CRS assumes a product equivalent of to No.2
diesel w/net heating value = 5.43 MBtu/barrel. See Eric T. Sundquist and G. A Miller
(U.S.G.S,), Oil Shales and Carbon Dioxide, Science, Vol 208. No. 4445, pp740-741, May
20 Originally reported as 30.6 and 37.1 gCequiv /MJ refined fuel delivered. (1 metric ton carbon
equivalent = 3.67 metric tons carbon dioxide, and assumes refined fuel equivalent to No. 2
diesel in heating value.) See Adam R. Brandt, Converting Oil Shale to Liquid Fuels: Energy
Inputs and Greenhouse Gas Emissions of the Shell in Situ Conversion Process, American
Chemical Society, August 2008.
21 Mark Schipper, Energy-Related Carbon Dioxide Emissions in U.S. Manufacturing
pipeline. The practice in some parts of the world of flaring (burning) “associated
natural gas” that can’t be delivered to market also contributes to emissions.
As a benchmark, CO2 emissions associated with Canadian oil sand production
reportedly range from 0.08 tons CO2/barrel for in situ production to 0.13 tons
CO2/barrel for mining/extraction/upgrading.22 Starting at 0.15 tons CO2/barrel in
1990 the oil sand industry expects to nearly halve its average CO2 emissions by 2010
to ~0.08 tons/barrel for all processes.
Depending on the depth of the oil shale and the extraction methods used,
demands on water resources may vary considerably. Utah’s shallower oil shale may
be more suited to conventional open-pit or underground mining, and processing by
retorting. Colorado’s deeper shale may require in situ extraction. The DOE Office
or Petroleum Reserves expects that oil shale development will require extensive
quantities of water for mine and plant operations, reclamation, supporting
infrastructure, and associated economic growth.23 Water could be drawn from the
Colorado River Basin or purchased from existing reservoirs. Oil shale has a high
water content, typically 2 to 5 gallons/ton, but as high as 30 to 40 gallons/ton. In situ
methods may produce “associated water,” that is, water naturally present in the shale.
EPAct 2005 Section 369 (r) is clear on not preempting or affecting state water
law or interstate water compacts when it comes to allocating water. Water rights
would not be conveyed with federal oil shale leases. The law of water rights is
traditionally an area regulated by the states, rather than the federal government.
Depending on the individual state’s resources, it may use one of three doctrines of
water rights: riparian, prior appropriation, or a hybrid of the two. Under the riparian
doctrine, which is favored in eastern states, a person who owns land that borders a
watercourse has the right to make reasonable use of the water on that land.24
Traditionally, users in the riparian systems are limited only by the requirement of
reasonableness in comparison to other users. Under the prior appropriation doctrine,
which is favored in western states, a person who diverts water from a watercourse
(regardless of his location relative thereto) and makes reasonable and beneficial use
of the water acquires a right to that use of the water.25 Typically, under a prior
appropriation system of water rights, users apply for a permit from a state
administrative agency which limits users to the quantified amount of water the user
22 Reported as 439.2 kg/m3 and 741.2 kg CO2/m3 respectively. Appendix Six, Canada’s Oil
Sands: Opportunities and Challenges to 2015, National Energy Board of Canada, May
23 U.S. DOE/Office of Petroleum Reserves, Fact Sheet: Oil Shale Water Resources.
[ ht t p: / / www.f e .doe.gov/ pr ogr ams/ r e ser ves/ npr / Oi l _Shal e_Wat er _Requi r e me nt s.pdf ]
24 See generally A. Dan Tarlock, Law of Water Rights and Resources, ch. 3 “Common Law
of Riparian Rights.”
25 See generally ibid. at ch. 5, “Prior Appropriation Doctrine.”
secured under the permit process. Some states have implemented a dual system of
water rights, assigning rights under both doctrines.26
One of the most controversial areas of oil and gas production operations today
is the handling, treatment, and disposal of produced water.27 Water produced in
association with mineral extraction (including oil and gas) typically contains high
levels of contaminants, and it usually must be treated before it can be safely used or
discharged. As clean water is a scarce resource, treating produced water may have
significant economic use, such as irrigation, washing, or even drinking. A recently
completed plant in the Power River basin in Wyoming treats 30,000 barrel/day water
produced from coal-bed methane (CBM) wells, and is expected to discharge 120,000
barrels/day to the basin within the next year without affecting water quality.28
The Produced Water Utilization Act of 2008 (H.R. 2339) would encourage
research, development, and demonstration of technologies to utilize water produced
in connection with the development of domestic energy resources.
EPAct Section 369 (q) directed the Department of Defense (DOD) and DOE
with developing a strategy for using fuel produced from oil shale (among other
unconventional resources) to help meet DOD’s requirements when it would be in the
national interest. EPAct Section 369 (g) also charged a joint Interior/Defense/Energy
task force with coordinating and developing the commercial development of strategic
unconventional fuels (including oil shale and tar sands). DOD’s earlier “Assured
Fuels Initiative” and later “Clean Fuels Initiative” considered oil shale, but shifted
emphasis to jet fuels produced by Fisher-Tropsch synthesis from coal and gas.
Under the provisions of EPAct Section 369 (h), the BLM established the Oil
Shale Task Force in 2005, which in turn published the report “Development of
America’s Strategic Unconventional Fuel Resources” (September 2006). The Task
Force concluded that oil shale, tar sands, heavy oil, coal, and oil resources could
supply all of the DOD’s domestic fuel demand by 2016, and supply upwards of seven
million barrels of domestically produced liquid fuels to domestic markets by 2035.
Under Section 526 of EISA 2007, DOD is restricted in buying a fuel derived
from oil shale or any other unconventional fuel unless the procurement contract
specifies that the lifecycle greenhouse gas emission associated with the fuel’s
production is less than conventional petroleum derived fuel. Section 334 of the
National Defense Authorization Act for FY2009 (S. 3001), however, directs DOD
26 For further information, see CRS Report RS22986, Water Rights Related to Oil Shale
Development in the Upper Colorado River Basin, by Cynthia Brougher.
27 Oil & Gas Journal, “Produced water management: controversy vs. opportunity,” May 12,
28 Oil & Gas Journal, “Custom-designed process treats CBM produced water,” July 14,
to study alternative fuels in order to reduce lifecycle emissions with the goal of
certifying their use in military vehicles and aircraft.
Restrictions to Leasing
EPAct Section 364 amended the Energy Policy and Conservation Act of 2000
(EPCA — 42 U.S.C. 6217) by requiring an inventory of all oil and gas resources
underlying onshore federal lands, and an identification of the extent and nature of any
restrictions or impediments to their development. The study areas were delineated
by aggregating oil and/or natural gas resource plays within the provinces as defined
by the U.S. Geological Survey (USGS) National Assessment of Oil and Gas
Certain lands within the oil shale resource areas are excluded from commercial
leasing on the basis of existing laws and regulations, Executive Orders,
administrative land use plan designations as noted below, or withdrawals. As a
result, commercial leasing is excluded from all designated Wilderness Areas,
Wilderness Study Areas (WSAs), other areas that are part of the National Landscape
Conservation System (NLCS) administered by the BLM (e.g., National Monuments,
National Conservation Areas (NCAs), Wild and Scenic Rivers (WSRs), and National
Historic and Scenic Trails), and existing Areas of Critical Environmental Concern
(ACECs) that are currently closed to mineral development. Within the oil shale
areas, 261,441 acres are designated as Areas of Critical Concern (ACEC), and thus
closed to developments (Colorado - 10,790; Utah - 199,521; Wyoming - 51,130).
A significant portion of public land within the most geologically prospective oil
shale area is already undergoing development of oil, gas and mineral resources. BLM
has identified the most geologically prospective areas for oil shale development on
the basis of the grade and thickness of the deposits: in Colorado and Utah, deposits
that yield 25 gallons of shale oil per ton of rock or more and are 25 feet thick or
greater; in Wyoming, 15 gallons/ton or more, and 15 feet thick or greater.
CRS has overlain a profile of the most geologically prospective oil shale
resources of the Green River formation over maps of access categories prepared for
the EPCA inventory (Figure 6). The Uinta basin in Utah is shown as being subject
to standard lease terms. The Piceance basin in Colorado is more subject to short term
lease of less than three months with controlled surface use. Approximately 5.3
million acres (40%) of the federal land in the Uinta-Piceance study area is not
accessible. Currently a total of ~5.2 million federal acres are under oil and gas lease
in Colorado, ~4.7 million acres in Utah, and ~12.6 million acres in Wyoming.
In Colorado, BLM administers approximately 359,798 federal acres of the most
geologically prospective oil shale deposits, of which 338,123 acres (94% margin of29
error is +/-2%) are already under lease for oil and gas development.
29 Personal communication with Jim Sample, U.S. BLM Colorado State Office, September
In Utah, BLM administers approximately 638,192 federal acres of the most
geologically prospective oil shale deposits, of which approximately 529,435 acres
(83%) are currently leased for oil and gas development.30
In Wyoming, BLM administers approximately 1,297,086 acres of the most
geologically prospective oil shale deposits, of which approximately 917,789 acres
(71%) are currently leased for oil and gas development.
BLM’s policy is to resolve conflicts among competing resources when
processing potential leasing action. However, BLM considers the commercial oil
shale development technologies currently being evaluated (see discussion below) as
largely incompatible with other mineral development activities and would likely
preclude those activities while oil shale development and production are ongoing.
EPAct Sec. 369 (n) authorizes the Interior Secretary to consider land exchanges to
consolidate land ownership and mineral rights into manageable areas.
30 Personal communication with Barry Rose, U.S. BLM, October 7, 2008.
Figure 6. Federal Land Access for the Most
Geologically Prospective Oil Shale
Land Leased for
BLM Administered Oil and Gas
Oil Shale Lands Development
St a t e acres acres
Utah 638,192 529,435
Wyoming 1 ,297,086 917,789
Commercial Leasing Program
EPAct Sec 369 (c) directed the Secretary of Interior to make land available
within each of the States of Colorado, Utah, and Wyoming for leasing to conduct
research, development, and demonstration (RD&D) of technologies to recover liquid
fuels from oil shale. In a November 2004 Federal Register notice (prior to EPAct’s
enactment in August 2005), the BLM sought public input on the terms to be included
in leases of small tracts for oil shale research and development within the Piceance
Creek Basin in northwestern Colorado, the Uinta Basin in southeastern Utah, and the
Green River and Washakie Basins in western Wyoming.31 BLM followed in June
development, and demonstration of oil shale recovery technologies in Colorado,
Utah, and Wyoming.32 BLM received 20 nominations for parcels in response to its
Federal Register announcement, and rejected 14 nominations. On September 20,
2005, the BLM announced it had received 19 nominations for 160-acre parcels of
public land to be leased in Colorado, Utah, and Wyoming for oil shale 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 Five of the proposals will evaluate in situ extraction
to minimize surface disturbance. The sixth proposal will employ mining and
retorting. Environmental Assessments (EA) prepared for each proposal prepared
under the National Environmental Policy Act (NEPA) resulted in a Finding of No
Significant Impact. 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
To date, BLM has issued six RD&D leases granting rights to develop oil shale
resources on 160-acre tracts of public land (see Table 4). The leases grant an initial
term of 10 years and the possibility of up to a 5-year extension upon proof of diligent
progress toward commercial production. RD&D lessees may also apply to convert
the leases plus 4,960 adjacent acres to a 20-year commercial lease once commercial
production levels have been achieved and additional requirements are met. The
RD&D projects are summarized below, and locations shown in Figure 7.
31 Federal Register, Potential for Oil Shale Development; Vol. 69, No. 224 / Monday,
November 22, 2004 / Notices 67935.
32 Federal Register, Potential for Oil Shale Development; Call for Nominations — Oil Shale
Research, Development and Demonstration (R, D & D) Program; Vol. 70, No. 110 /
Thursday, June 9, 2005 / Notices 33753.
33 U.S. DOI/BLM, BLM Announces Results of Review of Oil Shale Research Nominations,
January 17, 2006. [http://www.blm.gov/nhp/news/releases/pages/2006/pr060117_
Table 4. RD&D Leases
OSECUTVernalUnderground mining and surface
ChevronCOPiceance Basin, Rio Blanco In situ/ heated gas injection
EGLCOPiceance Basin, Rio Blanco In situ/ steam injection
ShellCOOil Shale Test Site (1);In situ Conversion Process (ICP)
Piceance Basin, Rio Blancousing self-contained heaters.
ShellCONahcolite Test Site (2);Two-Step ICP using hot water injection
Piceance Basin, Rio Blanco
ShellCOAdvanced Heater Test SiteElectric-ICP using bare wire heaters
(3); Picenace Basin, Rio
Source: Final Environmental Assessment [http://www.blm.gov/co/st/en/fo/wrfo/oil_shale_wrfo.html],
[ ftp ://ftp .b lm.go v/b lminco ming/UT /VN/] .
Notes: OSEC — Oil Shale Exploration Co., LLC; EGL — EGL Resources, Inc.; Shell — Shell
Frontier Oil and Gas Inc.
OSEC. The Oil Shale Exploration Co., LLC (OSEC) RD&D project will
evaluate developing oil shale by underground mining and surface retorting using the
Alberta-Taciuk (ATP) Process — a horizontal rotary kiln retort. The first phase
would consist mainly of hauling stockpiles of oil shale to a retorting demonstration
plant in Canada. The second phase would consist of moving a demonstration retort
processing plant to the former White River Mine area, processing stockpiles of oil
shale that are on the surface, and eventually reopening the White River Mine, and the
commencement of mining of oil shale. The third phase would involve an upscaling
of the retort demonstration plant, continuation of mining, and the construction of
various supporting facilities and utility corridors.
OSEC currently intends to use the Petrosix process (a patented retort process)
as the technology to process the mined oil shale into shale oil at the White River
Mine. The Petrosix process has been under development since the 1950s and is one
of the few retorting processes in the world that can show significant oil production
while remaining in continuous operation. This retort technology is owned by
Petrobras and has been operational in Brazil since 1992. Petrosix is an externally
generated hot gas technology. Externally generated hot gas technologies use heat,
transferred by gases which are heated outside the retort vessel. As with most internal
combustion retort technologies, the Petrosix retort processes oil shale in a vertical
shaft kiln where the vapors within the retort are not diluted with combustion exhaust.
The world’s largest operational surface oil shale pyrolysis reactor is the Petrosix
thirty-six foot diameter vertical shaft kiln which is located in São Mateus do Sul,
Paraná, Brazil. This retort processes 260 tons of oil shale per hour.34
Chevron. Chevron’s research focuses on oil shale recovery using conventional
drilling methods and controlled horizontal fracturing technologies to isolate the target
interval, and to prepare the production zone for the application of heat to convert the35
kerogen to oil and gas. The intent of the Chevron proposal is to prove an in-situ
development and production method that would apply modified fracturing
technologies as a means to control and contain the production process within the
target interval. The use of conventional drilling methods is aimed at reducing the
environmental footprint and water and power requirements compared to past shale
oil extraction technologies. The project will evaluate shale oil within the oil-rich
Mahogany zone, an oil shale deposit that is approximately 200 feet thick. It will be
conducted in a series of seven distinct phases that would entail drilling wells into the
oil shale formation and applying a series of controlled horizontal fractures within the
target interval to prepare the production zone for heating and in-situ combustion.
EGL. EGL’s research will gather data on oil shale recovery using gentle,
uniform heating of the shale to the desired temperature to convert kerogen to oil and
gas.36 The intent of the EGL proposal is to prove an in-situ development and
production method using drilling and fracturing technology to install conduit pipes
into and beneath the target zone. A closed circulation system would circulate
pressurized heating fluid. The methodology requires circulating various heating fluids
through the system. EGL plans to test the sequential use of different heating fluids
during different phases of the project. Field tests will involve introducing heat near
the bottom of the oil shale zones to be retorted. This would result in a gradual,
relatively uniform, gentle heating of the shale to 650-750 ºF to convert kerogen to oil
and gas. Once sufficient oil has been released to surround the heating elements, EGL
anticipates that a broad horizontal layer of boiling oil would continuously convect hot
hydrocarbon vapors upward and transfer heat to oil shale above the heating elements.
The oil shale that would be tested by EGL at the nominated 160-acre tract is a
300-foot-thick section comprising the Mahogany zone (R-7) and the R-6 zone of the
Green River formation, the top of which is at a depth of approximately 1,000-feet.
The affected geologic unit would be approximately 1,000 feet long and 100 feet
Shell. Shell Frontier Oil and Gas, Inc. (Shell) intends to develop three pilot
projects to gather operating data for three variations to in-situ hydrocarbon recovery
from oil shale.37 At the Shell Oil Shale Test (OST) site (Site 1), testing of in-situ
34 OSEC. [http://www.oilshaleexplorationcompany.com/tech.asp]
35 U.S. DOI/BLM, Environmental Assessment — Chevron Oil Shale Research, Development
& Demonstration CO-110-2006=120-EA, November 2006.
36 U.S. DOI/BLM, Environmental Assessment — EGL Resources, Inc., Oil Shale Research,
Development and Demonstration Tract CO-110-2006-118-EA, November 2006.
37 U.S. DOI/BLM, Environmental Assessment — Shell Frontier Oil and gas Inc., Oil Shale
Research, Development and Demonstration Pilot Project CO-110-2006-117-EA, November
extraction process components and systems will demonstrate the commercial
feasibility of extracting hydrocarbons from oil shale. The Second Generation In-situ
Conversion Process (ICP) test at Site 2 will determine the practicability of combining
already developed nahcolite extraction methods with in-situ hydrocarbon extraction
technology.38 The electric-ICP (E-ICP) or advanced heater technology test at Site 3
will assess an innovative concept for in-situ heating. The sites identified by Shell
overlie high grade oil shale yielding more than 25 gallons/ton of shale and a valuable
Figure 7. Locations of the Six RD&D Tracts and Associated
Preference Right Lease Areas
Source: Draft OSTS PEIS. December 2007
Programmatic Environmental Impact Statement
EPAct Sec. 369 (d)(1) directed the Interior Secretary to complete a
programmatic environmental impact statement (PEIS) for an oil shale and tar sands
commercial leasing program on the most geologically prospective lands within each
38 Nahcolite is a carbonate mineral currently mined for its economic value.
of the States of Colorado, Utah, and Wyoming.39 The Notice of Availability of
Proposed Oil Shale and Tar Sands Resource Management Plan Amendments To
Address Land Use Allocations in Colorado, Utah, and Wyoming and Final
Programmatic Environmental Impact Statement was published September 5, 2008.40
In the final PEIS, the BLM proposes to amend 12 land use plans in Colorado,
Utah, and Wyoming to provide the opportunity for commercial oil shale leasing. The
existing resource management plans within the PEIS study area are:
!Glenwood Springs RMP (BLM 1988b, as amended by the 2006
Roan Plateau Plan Amendment [BLM 2006a, 2007])
!Grand Junction RMP (BLM 1987)
!White River RMP (BLM 1997a, as amended by the 2006 Roan
Plateau Plan Amendment [BLM 2006a, 2007])
Uta h . 42
!Book Cliffs RMP (BLM 1985)
!Diamond Mountain RMP (BLM 1994)
!Grand Staircase!Escalante National Monument RMP (BLM1999)
!Henry Mountain MFP (1982)
!Price River Resource Area MFP, as amended (BLM 1989)
!San Rafael Resource Area RMP (BLM 1991a)
!San Juan Resource Area RMP (BLM 1991b)
W yoming. 43
!Great Divide RMP (BLM 1990)
!Green River RMP (BLM 1997b, as amended by the Jack Morrow
Hills Coordinated Activity Plan [BLM 2006b])
!Kemmerer RMP (BLM 1986)
Three alternatives to commercial leasing were presented in the draft PEIS, and
in the Final PEIS, BLM selected Alternative B as the proposed plan amendment. The
!Alternative A — No Action Alternative. Under this alternative,
approximately 294,680 acres in Colorado (White River) and 58,100
acres in Utah (Book Cliffs) are currently classified as available for
leasing under existing land use plan. No amendments would be
made to the plans to identify additional lands for commercial oil
39 In accordance with section 102(2)(C) of the National Environmental Policy Act of 1969
(42 U.S.C. 4332(2)(C)).
40 Federal Register / Vol. 73, No. 173 / Friday, September 5, 2008 / Notices.
41 BLM. [/www.blm.gov/co/st/en/BLM_Programs/land_use_planning/rmp.html]
42 BLM. [http://www.blm.gov/ut/st/en.html]
43 BLM. [ http://www.blm.gov/rmp/WY/]
!Alternative B. Under this alternative, BLM is designating 1,991,222
acres available for leasing by amending nine land use plans. This
would include BLM-administered lands and split-estate land that the
federal government owns mineral rights within the most geologically
prospective oil shale areas. Land exempted by statute, regulation, or
Executive Order would be excluded.
!Alternative C. This alternative would exclude additional land from
commercial leasing under Alternative B, reducing the land available
to 830,296 acres. The additionally excluded lands require special
management or resource protection under existing land use plans.
BLM administers 2,138,361 acres of the most geologically prospective oil shale
lands (Table 1). Alternative B makes 93% available for leasing. As discussed below,
a significant portion of these lands are already under lease for oil and gas
Mineral Leasing Act Amendments
Advocates of oil shale development claimed that restrictions on lease size
hindered economic development. EPAct Section 369 (j) amended Section 241(a) of
the Mineral Leasing Act (30 U.S.C. 241(a)) by increasing the size of an individual
oil shale lease from 5,120 acres to 5,760 acres (9 square miles), but limiting the total
acreage that an individual or corporation may acquire in any one state to 50,000 acres
(78.125 square miles).44 Under the act, federal oil and gas lessees may hold to
Commercial Lease Sale and Royalty Rates
EPAct Section 369 (e) directs a lease sale of oil shale within 180 days of
publishing the final lease rules if sufficient interest exists in a state, and Section
369(o) directs BLM in establishing royalties and other payments for oil shale leases
that: “(1) Encourage development of the oil shale and tar sands resources; and (2)
Ensure a fair return to the United States.”
Proposed Leasing Rules. EPAct Section 369 (d)(2) directed the DOI to
publish a final regulation establishing a commercial lease program not later than 6
months after the completion of the PEIS. Now expired, Section 433 of the 2008
Consolidated Appropriations Act (P.L. 110-161) stipulated that “None of the funds
made available by this Act shall be used to prepare or publish final regulations
regarding a commercial leasing program for oil shale resources on public lands
pursuant to section 369(d) of the Energy Policy Act of 2005 (Public Law 109-58) or
to conduct an oil shale lease sale pursuant to subsection 369(e) of such Act.” Section
152 of the Consolidated Security, Disaster Assistance, and Continuing
Appropriations Act of 2009 (P.L. 110-329) rescinds the Section 433 spending
44 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.”
prohibition effectively through March 2009. In the mean time, BLM published
proposed regulations to establish a commercial leasing program of federally owned
oil shale on July 28, 2008.45
In an advance notice of proposed rulemaking (ANPR), the BLM requested
comments and suggestions to assist in the writing of a proposed rule to establish a
commercial leasing program for oil shale.46 Section 369(j) set the annual rental rate
for an oil shale lease at $2.00/ acre. Since the statute sets the rental rate, the BLM has
no discretion to revise it.
In response to ANPR, BLM received comments expressing various ideas
concerning minimum production amounts and requirements ranging from no
minimum production to a minimum rate of 1,000 barrels/day. BLM considers the
minimum production requirement for 1,000 barrels/day too inflexible a standard
because it does not allow for differences in shale quality and differences in extraction
technology. A minimum annual production requirement would apply to every lease,
and payments in lieu of production beginning with the 10th lease-year. The BLM
would determine the payment in lieu of annual production, but in no case would it
be less than $4.00/acre. Payments in lieu of production are not unique and are
requirements of other BLM mineral leasing regulations, as the BLM believes they
provide an incentive to maintain production. A payment in lieu of production of
$4.00/acre for the maximum lease size of 5,760 acres equals a payment of $23, 040/
Proposed Royalties. BLM would establish a royalty rate for all products
that are sold from or transported off of the lease area. BLM recognizes that
encouraging oil shale development presents some unique challenges compared to
BLM’s traditional role in managing conventional oil and gas operations. BLM has
not yet settled on a single royalty rate for this proposed rule, but instead proposes two
royalty rate alternatives in the proposed rule, and may also consider a third
alternative, a sliding scale royalty rate.
BLM assumes that the market demand for oil shale resources based on the price
of competing sources (e.g., crude oil) of similar end products is expected to provide
the primary incentive for future oil shale development. Additional encouragement for
development may be provided through the royalty terms employed for oil shale
relative to conventional oil and gas royalty terms, but BLM recognizes that such
incentives must be balanced against the objective of providing a fair return to
taxpayers for the sale of these resources. The range of royalty options BLM initially
examined through the ANPR process are summarized in Table 5.
45 Federal Register, Oil Shale Management - General, Vol. 73, No. 142 / Wednesday, July
46 Federal Register, Commercial Oil Shale Leasing Program, Vol. 71, No. 165 / Friday,
August 25, 2006 / Proposed Rules.
Table 5. Proposed Options for Oil Shale Royalty Rates
12.5%on the first marketable product
12.5%on value of the mined oil shale as proposed in 1983
1% annual increase on products sold for 10 years, similar to the rates
12.5 % maximumestablished by the State of Utah in 1980
2% initialproduction encouragement, infrastructure
0%-12.5% Sliding scaletied to time frames
0%-12.5% Sliding scaletied to production
Sliding scaletied to the of crude oil price
1% of gross profit before payout
25% of net profit after payoutbased on old Canadian oil sands model
¢ / ton proposed in the 1973 oil shale prototype program
% / Btuas compared to crude oil
For comparison, the proposed standard lease terms for for oil and gas, tar
sands, and coal are provided below.
Standard Federal Lease and Royalty Terms. Oil and gas in public
domain lands are subject to lease under the Mineral Leasing Act of 1920, as amended47
(30 U.S.C. 181 et seq.) with certain exceptions. All lands available for leasing are
offered through competitive bidding, including lands in oil and gas leases that have48
terminated, expired, been cancelled or relinquished. A lessee has the right to use
so much of the leased lands as is necessary to explore for, drill for, mine, extract,
remove, and dispose of all the leased resource in a leasehold subject to certain
stipulations.49 The maximum lease holding in any one state is limited to 246,080
acres, and no more than 200,000 acres may be held under an option. Alaska’s lease
limit is 300,000 acres in the northern leasing district and 300,000 acres in the
southern leasing district, of which no more than 200,000 acres may be held under
option in each of the two leasing districts. The annual rental for all leases issued after
December 22, 1987, is $1.50/acre or fraction thereof for the first five years of the
lease term and $2/acre or fraction for any subsequent year (Table 6). Generally, a
12½% royalty is paid in amount (royalty-in-kind) or value of the oil and gas produced
or sold on mineral interests owned by the United States.50 A 16b% royalty is paid
on noncompetitive leases. In order to encourage the greatest ultimate recovery of oil
47 43 CFR 3100 Oil and gas Leasing.
48 43 CFR 3120 Competitive Leases.
49 43CFR 3101.1-2 Surface Use Rights.
50 43 CFR 3103.3-1 Oil and Gas Leasing Royalty on Production.
or gas, the Secretary of the Interior may waive, suspend, or reduce the rental or
minimum royalty or reduce the royalty on a portion or the entire leasehold. For
heavy oil leases producing crude oil less than 20° on the American Petroleum
Institute (API) scale, the royalty may be reduced on a sliding scale from 12½% for
Table 6. Federal Standard Lease and Royalty
($/acre) Terms (percent)
Federal Oil & Gas$1.50 to $2.00Competitive12½
Federal Oil & GasNon-competitive16b
Heavy Oil12½ to ½
Tar Sands$2.00 10 years12½
Coal surface$3.00 12½
Coal underground$3.00 8
In special tar sand areas, combined hydrocarbon, oil and gas, or tar sand leases
are offered competitive bonus bidding.52 (The terms “tar sands” and “oil sands” are
sometime used interchangeably, but here tar sands refers to resources in the United
States, and oils sands to Canada.) If no qualifying bid is received during the
competitive bidding process, the area offered for a competitive lease may be leased
noncompetitively. Combined leases may be awarded, or leases may be awarded
exclusively for oil and gas or tar sand development. Combined hydrocarbon leases
or tar sand leases in Special Tar Sand Areas cannot exceed 5,760 acres. The
minimum acceptable bid is $2.00/acre. Special tar sands area leases have a primary
term of 10 years and remain in effect as long as production continues. The rental rate
for a combined hydrocarbon lease shall be $2.00/acre/year. The rental rate for a tar
sand lease is $1.50/acre for the first 5 years and $2.00/acre for each year thereafter.
The royalty rate on all combined hydrocarbon leases or tar sand leases is 12½% of
the value of production removed or sold from a lease.
Coal leases may be issued on all federal lands with some exceptions including
oil shale.53 Lease sales may be conducted using cash bonus — fixed royalty bidding
systems or any other bidding system adopted through rulemaking procedures. The
annual rental cannot be less than $3.00 per acre on any lease issued or readjusted.54
A coal lease requires payment of a royalty of not less than 12½% of the value of the
51 43CFR 3103.4-3 Heavy oil royalty reductions.
52 43 CFR 3140 Leasing in Special Tar Sand Areas.
53 43 CFR 3400 Coal Management: General.
54 34 CFR 3473.3-1 Coal Management Provisions and Limitations.
coal removed from a surface mine and a royalty of 8% of the value of coal removed
from an underground mine.55
Private Lease Terms. Although information on lease terms for privately
held oil shale is unavailable, comparison can be made with terms for private and
state-owned land above natural gas-producing shales; for example, the Marcellus and56
Barnett shales. Bonus payments and royalties received by state and private
landowners in West Virginia, Pennsylvania, New York, and Texas are shown in
Tables 7 and 8. Rents are not included because nearly all of the information
available reports on signing bonuses and royalties. Further, rents are often rolled into
signing bonuses, and paid upfront or paid quarterly as a “delay rental.” Rents appear
to be much less significant to small landowners who lease a few acres. On state and
private leases, as with federal leases, rents would be paid until production
commences, at which time royalties are paid on the value of production. All
Marcellus shale lessors have shown significant increases in the amounts paid as
signing bonuses and increases in royalty rates. But there are still several lease sales
as reported by the Natural Gas Leasing Tracking Service, that record signing bonuses
in the range of $100 to $200/acre because of greater uncertainty and less interest
among natural gas companies and/or the lack of information among landowners on
what the land is worth.57
55 43 CFR 3473.3-2 Royalties.
56 Prepared by Marc Humphries, Analyst in Energy Policy, Congressional Research Service.
57 Natural Gas Leasing Offer Tracking, Natural Gas Lease Forum for Landowners.
Table 7. Shale Gas Bonus Bids, Rents, and Royalty Rates on
Selected State Lands
Royal RateRange (per acre)Comments
West Virginiaa12.5%--No state shale gas leases
Pennsylvaniab12.5%12.5-16%$2,500In many cases bonus bids were
in the $25-$50 per acre range
as recent as 2002. A royalty
rate of 12.5% was most
New Yorkc12.5%15-20%about $600Bonus bids ranged from $15-
$600 per acre around 1999-
2000 and most royalty rates
were at 12.5%.
Texas12.5%25%$350-$400Bonus bids have been
(Delawarerelatively consistent in recent
Basin)times (within the past 5 years).
Royalty rates were more
$12,000common at 20%-25% about 5
(river tracts)years ago. Most state-owned
lands are not considered to be
among the best sites for shale
a. Personal communication with Joe Scarberry in the WV Department of Natural Resources, October
b. Personal communication with Ted Borawski in the PA Bureau of Forestry, who provided
information on shale gas leases on both state and private lands, October 2008.
c. Personal communication with Lindsey Wickham of the NY Farm Bureau and Bert Chetuway of
Cornell University, discussed lease sales on state and private land, October 2008.
Table 8. Shale Gas Bonus Bids, Rents, and Royalty Rates on
Private Land in Selected States
Royalty RatesBonus Bids
West Virginiaa12.5-18%$1,000-$3,000Bonus payments were in the $5
per acre range as recently as 1-
2 years ago. Royalty rates were
Pennsyl va nia 17-18% $2,000-$3,000
Texas25-28%$10,000-$20,000Bonus bids were in the $1,000
range around 2000-2001.
Royalty rates were in the 20-
a. Personal communication with David McMahon, Director of the WV Surface Owners Rights
Organization, October 2008.
Conclusion and Policy Perspective58
Shale oil is difficult and expensive to extract and has not competed well with
conventional oil supplies in the past. The major barrier has been cost, but additional
barriers are potential environmental damage during development, and the cost of
refining and transportation from the interior western United States.
The recent spike in crude oil price has once again stirred interest in oil shale.
As in the past, however, the rapid runup in prices (to a high of $145/barrel) was soon
followed by a rapid and precipitous drop in prices ($64/barrel at the time of this
writing). Although the major oil companies have reaped record profits, such price
volatility discourages investment in contingent resources such as oil shale. Oil price
volatility has produced patterns of boom and bust for oil shale, as seen in the interest
in oil shale development in the early 1980s, followed by the cancellation of Exxon’s
$5 billion Colony Oil Shale Project in 1982, and the cancellation of loan guarantees
under the Synthetic Fuels Corporation.
Volatility in the price of oil affects all contingent or marginal hydrocarbon
resources. After considerable investment in unconventional oil sand resources,
Canadian producers have announced cutbacks in capital spending and are scaling
back or cancelling plans for expansion altogether. While OPEC cuts oil output to
prop up prices, the major and super-major oil companies continue to use an oil price
of $32/barrel for their business planning. In this climate, the development of oil
shale seems difficult indeed. While oil shale development faces continuous
58 With contributions by Gene Whitney, Energy and Minerals Section Research Manger,
Congressional Research Service.
challenges, the exploration and production of conventional oil and gas grows steadily
in the region.
The regional isolation of the massive oil shale deposits of western Colorado,
eastern Utah, and southwestern Wyoming provides both opportunity and challenges
for developing shale oil there. Shale oil is best used to produce middle distillate
diesel and jet fuel, commodities in high demand in the region. Additionally, the oil
and product pipeline infrastructure into and out of the region is limited, so moving
shale oil to another region for refining is difficult, and importing refined product is
equally difficult. This isolation provides an opportunity for shale oil as long as
regional refining capacity is available.
An additional point of uncertainty is introduced by the government’s changes
in rules. A recent spending moratorium on finalization of the commercial leasing
rules had added considerable uncertainty to oil shale development. Without a final
rule, no developer could attract investors or plan for full development of the oil shale
resources. The subsequent rescission of the spending moratorium now allows final
rule making to be completed before the 111th Congress convenes. In the meantime,
much of the land surface that might be leased for oil shale development has already
been leased for conventional oil and gas development, adding further complication
to the leasing process.
The oil shale boom-bust cycles are part of the cause of, and also the result of,
an exodus of skilled labor and technical talent from the Rocky Mountain region.
Whole communities grew up around the oil shale development of the 1980s, only to
disappear again when the projects stopped. The uncertainty surrounding the viability
of oil shale development, combined with competition from the conventional oil and
gas industry and from other regions, makes it difficult to recruit and keep skilled
labor for oil shale development.
Finally, the draft leasing rules are silent on CO2 emission requirements; and yet
oil shale development may be accompanied by troublesome emission of CO2 as a
result of the retorting process. Full analysis of CO2 emissions from oil shale
development must wait until the research and development phase of shale oil
production is completed. Such an analysis would probably be part of the
environmental impact statement required for permitting commercial development.
Canada’s oil sands industry has demonstrated that emission concerns may be
addressed over time as technology develops.
Oil shale, along with other unconventional and alternative energy sources, will
continue to struggle as long as oil prices are volatile. Sustained high oil prices will
likely be required to motivate oil shale developers to make the massive investments
required for ongoing production of oil from shale. Although the quantities of
hydrocarbons held in oil shale is staggering, its development remains uncertain.