Economic Analysis

for

The Proposed Commercial Oil Shale Management Regulations

Introduction

By statute and executive order, an agency proposing a significant regulatory action is 

required to provide a qualitative and quantitative assessment of the anticipated costs and 

benefits of that action. Executive Order 12866 requires agencies to assess the benefits 

and costs of regulatory actions, and for significant regulatory actions, submit a detailed 

report of their assessment to the Office of Management and Budget (OMB) for review. A 

rule may be significant under Executive Order 12866 if it meets any of four criteria. A 

significant regulatory action is any rule that may:

 Have an annual effect on the economy of $100 million or more or adversely affect 

in a material way the economy, a sector of the economy, productivity, 

competition, jobs, the environment, public health or safety, or state, local, or tribal 

governments or communities;

 Create a serious inconsistency or otherwise interfere with an action taken or 

planned by another agency;

 Materially alter the budgetary impact of entitlements, grants, user fees, or loan 

programs or the rights and obligations of recipients thereof; or

 Raise novel legal or policy issues arising out of legal mandates, the President’s 

priorities, or the principles set forth in the Executive Order.

For a major rule, as defined by the Small Business Regulatory Enforcement Fairness Act 

(SBREFA), the agency must prepare an initial regulatory flexibility analysis. For 

SBREFA, a rule may be major if it meets any of three criteria:

 Have an annual effect on the economy of $100 million or more;

 Create a major increase in costs or prices for consumers, individual industries, 

Federal, State, or local government agencies, or geographic regions; or

 Have significant adverse effects on competition, employment, investment, 

productivity, innovation, or on the ability of United States-based enterprises to 

compete with foreign-based enterprises in domestic and export markets.
2

If determined to be a major rule SBREFA requires an agency to prepare an analysis when 

issuing a proposed rule that will have a significant impact on a substantial number of 

small entities.

Statement of Need

The Energy Policy Act of 2005 (42 U.S.C. 15927) requires the Department of the Interior

(DOI) to publish oil shale commercial leasing program regulations. In 2008, regulations 

were promulgated addressing the leasing and management of oil shale development on 

Federal lands. In 2009, these regulations were challenged in court. As a result of this 

suit, DOI entered into an agreement that included proposing specific changes to the 

existing regulations.

Proposed Rule

This new rule provides the BLM an opportunity to consider the 2008 regulations in light 

of the still nascent character of the technology necessary to economically develop the oil 

shale resources. In addition, after publication of the final rule in 2008, the regulations 

were challenged in Federal Court. As part of the settlement agreement, the BLM agreed 

to propose revisions to the 2008 regulations by addressing the royalty rate and certain 

environmental protection requirements applicable to commercial oil shale leasing.

This proposed rule would revise the regulations at 43 CFR Parts 3900, 3920, and 3930. 

This proposed rule considers whether the royalty rate for commercial oil shale production 

should not be set until more is known about the emerging oil shale technologies, whether 

future applications to lease should include specified resource protection plans (watershed 

and groundwater protection plan, an airshed review, an integrated waste management 

plan, and an environmental protection plan), and activity would not be approved unless 

operations could proceed without unacceptable environmental risk.

Alternative Approaches

Pursuant to the settlement agreement, the Secretary of the Interior (Secretary) must 

propose revisions to the existing oil shale leasing and management regulations. Three 

main areas under consideration are the royalty rate, specific resource protection plans,

and specific environmental standards.

Royalty Rates

The Energy Policy Act of 2005 directs the Secretary to “establish royalties, fees, rentals, 

bonus, or other payments for leases under this section that shall:

Encourage development of the oil shale and tar sands resource; and

Ensure a fair return to the United States.”
3

Encourage Development - For economically developable resources, the various payments 

required to obtain, hold, and produce on a Federal oil shale lease will affect the lease’s 

development potential. The lower those payments, the less likely those costs will 

adversely impact that potential. However, a reduction in those payments will not make 

an uneconomic operation financially viable.

Fair Return - In the context of this regulatory initiative, fair return is considered the 

functional equivalent to fair market value (FMV). Fair market value is a well-established 

concept in law, case law, regulation, and practice for a number of BLM mineral and nonmineral management programs. The Federal Land Policy and Management Act 

(FLPMA) declares a policy that “the United States receive fair market value for the use 

of the public lands and their resources unless otherwise provided for by statute.”

A property’s FMV is based on the appraisal concept of the price a property would sell for 

given a knowledgeable and willing, but not obligated, buyer and seller. It is intended to 

be an estimate of what would occur in a market situation.

Two commonly accepted procedures for value estimation are the comparable sales 

approach and the income approach. The comparable sales approach is an appraisal 

procedure in which the prices paid in prior transactions of similar properties are used to 

value the property to be disposed of through leasing, exchange, or other means. This 

procedure generally is preferred to other appraisal procedures since it is thought that 

prices paid in prior market transactions of similar properties provide the best indication of 

value. The income approach involves the estimation of annual costs and revenues 

associated with the development of the property under realistic conditions. Annual cost 

and revenue streams are reduced to a single number in which future costs and revenues 

are discounted to the present. The property's net income potential, discounted to the 

present, provides an estimate of current sale value. Under either approach, ascertaining a 

value figure must consider all factors that might affect the property’s market value. 

When estimating a property’s FMV, the agency is generally focusing on the bonus bid, 

assuming all other factors, including the royalty rate, to be held constant. Conversely, in 

making a determination about what royalty rate would ensure a fair return requires the 

bonus bid to be held constant.

Whether estimating the bonus bid or the royalty rate, to make a meaningful estimate, the 

oil shale lease must have the potential to be economically developed. In the absence of 

an economic property, the bonus bid and/or royalty rate would be a negative figure.

For economically developable resources, these payments will affect the lease’s 

development potential. These payments are cost, and as with all acquisition, 

development and production costs, must be considered when determining the royalty rate 

and bonus bid level that will allow the proposed operation to go forward. Under no 

scenario can the fair return for these payments be so onerous that the proposed 

development becomes uneconomic.
4

The ability to set a royalty rate that meets both these requirements is dependent on a 

demonstrated technology to economically develop the resource. At this point in time, 

such technology has not been demonstrated.

In 2009, environmental groups sued the Secretary, arguing in part that the royalty rates 

established in the 2008 oil shale regulations were insufficiently supported and did not 

assure a fair return to the United States. In developing this rule, approaches the BLM 

considered in addressing the royalty rate to apply to oil shale leases included:

Retaining the current royalty scheme;

Proposing a new rate or system of rates; or

Establishing the rate prior to a lease sale or lease conversion.

During negotiations to settle that litigation, the BLM considered again the analysis of the 

royalty rate alternatives that was considered prior to the promulgation of the 2008 oil 

shale regulations to determine whether to propose any amendment to those rates. The 

BLM determined that the 2008 analysis was the best possible given the information 

available at that time, but there could be doubt as to whether that information would 

accurately predict the relevant financial conditions of a commercial oil shale industry in 

the United States.

Therefore, the BLM has decided to propose that royalty rates should be established on a 

lease-by-lease basis, with the benefit of information from Research, Development, and 

Demonstration (R, D and D) leases or other oil shale operations on non-Federal lands; 

information that is not available at this time. The BLM expects that the comments on the 

proposed regulations will include detailed discussions of how best to establish royalty 

rates for an industry that has not yet become commercially viable.

The BLM also considered whether to propose establishing a new royalty rate or rates.

The BLM decided that there is no new information since the 2008 rule about the costs 

and revenues of commercial oil shale operations or about royalties actually paid to nonFederal mineral owners in the United States that would support establishing royalty rates 

at this time.

In addition to the proposal, the BLM is also requesting comments from the public on 

various options for establishing an applicable royalty scheme. These options are 

discussed below.

Option 1 - Invite Comment on Proposed Lease Terms in a Proposed Notice of Lease Sale 

Under this option, the BLM would first publish a proposed notice of sale or conversion to 

a commercial lease for a period of not less than 30 days. That proposed notice would 

include all proposed lease terms and stipulations, including proposed royalty and rental 

rates. It also would include an explanation of how the BLM determined the proposed 
5

royalty rate. This would give interested parties and the public an opportunity to comment 

on all the proposed terms, including the proposed royalty rate. Under this option, and so 

as to allow adequate time for both comment and consideration of the comments, the BLM 

would amend section 3924.5 to require at least 60 days between publication of the 

proposed notice of sale and the notice of sale. 

Option 2 - Invite Public Comment Using Coal Lease Sale Process

As an alternative to publishing a proposed notice of sale, the rule specifically seeks 

comments on a possible alternative procedure that would be modeled after a provision in 

the Federal coal leasing regulations at 43 CFR 3422.1. Instead of publishing a proposed 

notice of sale, the BLM would, at least 30 days before the notice of sale, solicit public 

comment on the fair market value of, and expected economic recovery from, the oil shale 

lands proposed to be offered for lease and on what royalty rate and other lease terms or 

stipulations commenters believe should be required. The authorized officer would 

prepare a report evaluating the comments and containing his or her recommendations for 

the minimum bid and for the royalty rate and other lease terms to be included in the 

leases offered.

Option 3 - Sliding Scale Royalty Based on the Market Prices of Oil and Gas

In the 2008 proposed oil shale rule, the BLM considered and sought comment on a 

sliding scale royalty. That approach was not adopted in the final 2008 rule, but in light of 

the need to reconsider the existing royalty rates under the terms of the settlement

agreement, this rule seeks public comment on the best approach to implementing a 

sliding scale royalty structure.

Although the BLM has expressed concerns in the past about the complexity of 

administering certain proposed sliding scale royalty proposals, we recognize that there is 

merit to the sliding scale concept, and in a simpler form, a sliding scale royalty could 

prove extremely useful in meeting the dual goals of encouraging production and ensuring 

a fair return to taxpayers from future oil shale development.

One of the concerns that has been expressed regarding oil shale development is that 

potential oil shale developers may be reluctant to make the large up-front investments 

required for commercial operations if they believe there is a chance that crude oil prices 

might drop in the future below the point at which oil shale production would be profitable 

(i.e., competitive with conventional oil production). A sliding scale royalty system could 

allow the government to at least partially mitigate this development risk by providing for 

a lower royalty rate if crude oil prices fall below a certain price threshold. The basic 

concept is that in return for the Federal Government accepting a greater share of the price 

risk that an operator faces when prices are low (in the form of a lower royalty), the 

Government would receive a greater share of the rewards (through a higher royalty) when 

prices are high.
6

The BLM has not decided on the specific parameters of a sliding scale royalty system, 

but is considering a simplified two- or three-tiered system based on the current royalty

rates already in effect for conventional fuel minerals. The applicable royalty rate would 

be determined based on market prices of competing products (e.g., crude oil and natural 

gas) over a certain time period. In a two-tiered system, if prices remain below a certain 

point during the applicable period, the royalty rate on oil shale products would be the 

lower of two options. If prices are above that range for the period, the higher royalty 

would be charged. In a three-tiered system, a third royalty rate would apply if prices rise 

above a second price threshold during the applicable period.

Option 4 - Establish a Minimum Royalty of 12.5% in Regulation, with Secretarial 

Flexibility to Establish a Higher Rate Later

Under this option, a minimum royalty of 12.5% would be established to address concerns 

about the existing rate and implement the terms of the settlement agreement. The 

minimum royalty rate of 12.5%, the same rate as currently applied in the BLM's oil and 

gas program, is being considered as it is contemplated that the primary products produced 

from oil shale will compete directly with those from onshore oil and gas production. 

However, the Secretary would have the authority to establish a higher rate, if determined 

to be appropriate, without completing a new rulemaking. This option would provide 

flexibility for the the Secretary to adapt and respond accordingly to new information, 

such as emerging oil shale technologies, future oil shale production cost information, and 

changes to the price of this commodity, in order to help assure a fair return to the United 

States. Establishing a minimum royalty would be consistent with how other conventional 

fuels (e.g., oil, gas, and coal) are treated under existing statutes and regulations.

In order to promote transparency in connection with the proposed change to allow a 

higher royalty rate to be established at a later time, the BLM would add a requirement to 

first publish a proposed notice of sale. That proposed notice would include all proposed 

lease terms and stipulations, including proposed royalty and rental rates. It also would 

include an explanation of how the BLM determined the proposed royalty rate.

The notice would invite comment on the proposed lease terms for a period of not less 

than 30 days. This would give interested parties and the public an opportunity to 

comment on all the proposed terms, including the proposed royalty rate. So as to allow 

adequate time for both comment and consideration of the comments, the BLM would 

require at least 60 days between publication of the proposed notice of sale and the notice 

of sale.

The rule also invites comments on any other royalty system or rates that would meet the 

dual two requirements of the Energy Policy Act of 2005 to encourage production and 

ensure a fair return to the public. 

The cost of implementing these alternative royalty schemes would not vary significantly 

for either the industry or the BLM. The proposed scheme, where the royalty rate will be 

established on a lease-by-lease basis, will, however, add a level of uncertainly for 
7

prospective lessees. The uncertainty in royalty rates might discourage commercial oil 

shale development by requiring entities to make business decisions with less information. 

Although this is a concern in theory, the proposed approach mirrors the approach used by 

the BLM for non-energy solid mineral leases.

Resource Protection Plans

Under the settlement agreement the BLM is required to propose expanding the 

information required from operators as part of its plan of development (POD). The BLM 

considered several alternatives, including:

Relying on the requirement in the 2008 regulations to provide any additional 

information necessary for the BLM’s review of a proposed POD; or

Proposing various specific resource protection plan, information, and review

requirements.

The BLM considered whether such new requirements were necessary in view of the 

provision in the regulations allowing the BLM to require operators to provide any 

additional information necessary for the BLM’s review of a proposed POD. The BLM 

agreed to propose regulations requiring operators to submit a watershed and groundwater 

protection plan, an airshed review, an integrated waste management plan, and an 

environmental protection plan as part of each proposed POD because such information 

would likely be necessary in all cases to conduct a complete analysis under the National 

Environmental Policy Act of 1969 (NEPA), and to assure that resources on the public 

lands are managed in the best interests of the United States. Thus, not including those 

plans and reviews would result in the BLM requiring that additional information from 

operators on an ad hoc basis even though it would not have been specified in the 

regulations. The proposed requirements would more completely inform the industry and 

the public of the minimum requirements for a complete POD.

The proposed specific resource protection plan requirements might appear to be a 

significant additional cost to the applicant to prepare and for the BLM to review. This 

proposal, however, simply codifies in regulation what would likely be required for 

compliance with the requirements of NEPA prior to approval of a POD. The cost of 

implementing the various resource protection plans and review requirements should not 

vary significantly between the alternatives for either the industry or the BLM.

Environmental Standard

Under the settlement agreement the BLM is required to propose an environmental 

performance standard for approval of oil shale leases and operations. The BLM 

considered several alternatives including:

Continuing to make decisions based upon the BLM’s judgment subject to the mandate of 

the Federal Lands and Policy Management Act of 1976 (FLPMA) to prohibit unnecessary 
8

and undue degradation (UUD) of the public lands, except that the existing R, D and D

leases include an additional standard for conversions to commercial leases that operations 

would not cause unacceptable environmental consequences (UEC); applying the UEC 

standard for all decisions; or applying the unacceptable environmental risk (UER) 

standard to all decisions.

The BLM had included in the eight outstanding R, D and D leases a standard for deciding 

whether to approve conversion to commercial leases – UEC. The BLM took that 

standard from a decision by the United States Court of Appeals for the District of 

Columbia Circuit in a case concerning compliance with NEPA. Although UEC is not 

defined, the intent was that it would be an appropriate qualitative standard for oil shale 

operations. In the course of its consideration of proposing regulations, however, the 

Department of the Interior (DOI) decided to propose as the standard UER. The DOI

reasoned that the BLM should not be placed in the unintended position of having to issue 

leases or to approve plans of development unless it could prove that “consequences” 

would result, rather, it should be the proponent’s burden to establish that the risk of 

unacceptable environmental outcomes was acceptable. The notice of proposed 

rulemaking expressly requests public comments on both UEC and UER.

The BLM also considered proposing no environmental standard, but instead employing 

for oil shale the practice of the BLM of using its best professional judgment instead of a 

regulatory standard of environmental acceptability in light of the mandate in FLPMA to 

prevent UUD of the public lands. This approach is used by the BLM in managing other 

resource uses. The BLM would benefit from thoughtful comments on whether an 

environmental standard is necessary and, if so, what it should be.

Assessing the cost differences between these alternative is problematic. The BLM has 

extensive experience in evaluating environmental consequences, specifically tied to 

carrying out its FLPMA, UUD, and NEPA analysis and disclosure responsibilities. The 

agency has limited experience in evaluating and measuring environmental risk, and that 

standard generally applies to laws that govern hazardous materials. The BLM does not 

anticipate that a quantitative risk assessment would be possible for its decisions regarding 

oil shale leasing and development. The application of this standard qualitatively may

increase the economic burden for the agency and the proponent, potentially including the 

costs of non-approval. However, there is no practical way of quantifying the potential 

costs of this regulatory alternative.

As a practical matter, applying either the UUD or the UEC standard would probably

result in the same level of protection. Both standards are based on the BLM’s 

understanding of the environmental impacts of a proposed action. Application of either 

standard would involve the BLM’s professional judgment. As such, the cost of 

implementing these different standards are anticipated to be the same.
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Background

Oil Shale - Oil shale is organic-rich marlstone that yields significant quantities of oil 

when processed by conventional destructive distillation methods. The organic-rich shale 

is composed of fine-textured sedimentary rock containing a high percentage of 

combustible organic matter.

The world’s largest known oil shale deposits are located on Federal lands in the Western 

United States. Domestic commercial-quality oil shale resources, including undiscovered 

resources, exceed 2 trillion barrels, including about 1.5 trillion barrels of oil equivalent in 

high quality shales concentrated in the Green River Formation in Colorado, Utah, and 

Wyoming.

1

 Recent estimates for domestic oil shale resources range from 2.1 to 26 

trillion barrels (see Table 1). For geographic reference, Figure 1 shows the location of 

the Green River Formation.

In a report, Oil Shale Development in the United States – Prospects and Policy Issues,

prepared for the U.S. Department of Energy, National Energy Technology Laboratory in 

2005, the RAND Corporation cites in-place resource estimates of 1.5 to 1.8 trillion 

barrels for the Green River Formation.

2

 RAND’s recoverable resource estimates for the 

Green River Formation ranged from 500 billion to 1.1 trillion barrels of oil. The 

Strategic Unconventional Fuels Task Force3estimated that “as much as 800 billion 

barrels of oil equivalent could be recoverable from oil shale resources yielding >25 

gallons per ton.”

4

 To put these estimates in perspective, domestic oil consumption in

2010 was about 19.2 million barrels per day.

5

 

 

1 America’s Strategic Unconventional Fuels Resources, Volume I - Preparation Strategy Plan, and 

Recommendations, Task Force on Strategic Unconventional Fuels, September 2007, page I-17 

(http://www.unconventionalfuels.org).

2 Oil Shale Development in the United States – Prospects and Policy Issues, RAND Corporation, 2005, 

page 6 (www.rand.org).

3 The Task Force on Strategic Unconventional Fuels was established in 2005 as required by the Energy 

Policy Act to promote the development of the nation’s unconventional fuel resources.

4 America’s Strategic Unconventional Fuels Resources, Volume I - Preparation Strategy Plan, and 

Recommendations, Task Force on Strategic Unconventional Fuels, September 2007, page I-17 

(http://www.unconventionalfuels.org).

5 U.S. Energy Information Administration (http://www.eia.gov/energyexplained/index.cfm?page=oil_use). 

More recent information is available for some of these figures-for instance, the EIA AEO of 2012 includes 

updated estimates for oil prices. However, as discussed below, the BLM has used figures throughout 

consistent with those relied on in the task force report and the RAND report. Updating any figure would 

not be particularly meaningful absent an update of those two reports. 
10

Figure 1

Green River Formation

Table 1

U.S. Oil Shale Resource Estimates

Source of Estimate Oil Shale

(billion barrels)

U.S. Geological Survey62,100

American Petroleum Institute75,600

Office of Technology Assessment826,000

 

6 Dyni, J.R., Geology and Resources of Some World Oil-Shale Deposits, U.S. Geological Survey, 

Investigations Report 2005–5294, June 2006 (http://pubs.usgs.gov).

7

Porter, E.D., American Petroleum Institute, Policy Analysis and Strategic Planning Department, Are we 

running out of oil?, Discussion Paper #081, December 1995 (http://new.api.org).

8 Congress of the United States, Office of Technology Assessment, An Assessment of Oil Shale 

Technologies, June 1980, OTA Report # OTA-M-118 (http://govinfo.library.unt.edu/ota/).
11

Quality and Grade - Oil shale resources of the United States have been extensively

characterized. Yields greater than 25 gallons per ton are generally viewed as the most 

economically attractive, and hence, the most favorable for initial development.

The most economically attractive deposits, containing in excess of 1.2 trillion barrels, are 

found in the Green River Formation of Colorado (Piceance Creek Basin), Utah (Uinta 

Basin), and Wyoming (Green River and Washakie Basins). More than a quarter million 

assays have been conducted on the Green River oil shale. In the richest zone, known as 

the Mahogany Zone, oil yields vary from 10 to 50 gallons per ton and, for a few feet in 

the Mahogany zone, up to about 65 gallons per ton.

9

 An estimated 418 billion barrels of 

these resources are in deposits that will yield at least 30 gallons per ton in zones at least 

100 feet thick. Additional resource estimates are for 750 billion at 25 gallons per ton in 

zones at least 10 feet thick.

The mineral deposits (conventional crude oil versus oil shale –kerogen) are distinctly

different. Uncertainty relating to the quantity of recoverable oil is a function of 

technological efficiency. All oil shale technologies and projects are purely experimental 

and technological efficiency would not be known until a technology has been perfected.

Technological Advances - While there has been a great deal of interest recently in the 

potential of oil shale resources, utilization of this material is still, for the most part, in the 

research and development mode. Currently, there is no commercial production of oil 

from shale in the United States. Recent technological developments have proven to be of 

great interest, and those developments, along with technologies that were developed 

during the last wave of interest in oil shale, are now being considered for application in 

tapping this potential resource.

Existing technologies for producing domestic oil shale have not yet been tested beyond 

the pilot scale. Major investments by industry and government have resulted in an indepth understanding of oil shale resources and the development and testing of a broad 

spectrum of surface retorting and in-situ technologies for converting oil shale to liquid 

fuels. The lessons learned and the technologies developed from these past efforts remain 

available and provide the technical basis needed to advance oil shale commercialization 

efforts. 

Economic Viability - The last concerted effort to bring domestic shale oil into production 

was in the 1970s and 1980s. There was significant interest in developing the vast oil 

shale resources on Federal lands, specifically in Colorado and Utah. The last of these 

operations ceased in 1991. Numerous times throughout history, there have been attempts 

to produce oil from shale with limited reported success. The availability of relatively 

inexpensive alternative sources of oil has generally made shale oil production 

uneconomic.

 

9 America’s Strategic Unconventional Fuels Resources, Volume III Resource and Technology Profiles, 

Task Force on Strategic Unconventional Fuels, September 2007, page III-2 

(http://www.unconventionalfuels.org).
12

At present, oil shale production is characterized by high initial capital investments, high 

operating costs, and long periods of time between expenditure of capital and the 

realization of production revenues and return on investment. For first-generation 

facilities, there is substantial uncertainty about the magnitude of capital and operating 

costs because technologies are not yet proven on a commercial scale. Table 2 - Estimated 

Costs and Minimum Economic Prices for Oil Shale Processes presents recent cost and 

minimum price estimates associated with oil shale development. However, 

demonstration of first-generation technologies will be required at a commercially 

representative scale before definitive capital and operating costs of oil shale projects will 

be known.

Table 2

Estimated Costs and Minimum Economic Prices for Oil Shale Processes10

Technology Average Minimum

Economic Price

(Dollars per Barrel)

Capital Cost

($1000 per SDB11)

Operating Costs

(Dollars per Barrel)

Surface Mining $44.24 $40 - $41 $12 - $13

Underground Mining $54.00 $41 - $42 $16 - $17

Modified In-Situ12 (MIS) $65.21 $27 - $40 $18 - $26

True In-Situ13 $37.7514 $36 - $56 $19 - $20

Source: America’s Strategic Unconventional Fuels Resources, Volume III Resource and Technology 

Profiles, Task Force on Strategic Unconventional Fuels, February 2007, page III-14, Table III-3. Estimated 

Costs and Minimum Economic Prices for Oil Shale Processes, (http://www.unconventionalfuels.org).

Revenues are uncertain because world crude oil prices are volatile and future market 

prices for shale oil and byproducts are unknown. These and other uncertainties pose 

investment risks that make oil shale investment less attractive than other potential uses of 

capital.

Oil shale technologies must be demonstrated at commercial scale before definitive capital 

and operating costs of oil shale projects will be known. Cost estimates will vary

according to the oil shale resource and the extraction process selected.

 

10 Capital and operating costs are reported in constant 2005 dollars.

11 Streaming daily barrels (SDB) is a measure of an operations productive or installed capacity. Capital 

costs are the sum of investments needed per barrel of installed capacity. These costs include investments in 

mining, retorting, solid waste disposal, refining and upgrading, plant utilities, and other facilities.

12 MIS involves mining below the target shale before heating. Once the shale is mined, the virgin shale is 

rubblized by explosions to create a void space of 20 to 25 percent. Combustion is started on the top of the 

rubblized shale and moves down the column. In advance of the combustion front, oil shale is raised to 

retorting temperature that converts the kerogen to shale oil and to gases. Both products are captured and 

returned to the surface.

13 A true in-situ process involves no mining. The shale is fractured, air is injected, the shale is ignited to 

heat the formation, and shale oil moves through fractures to production wells.

14 Shell Oil Company had estimated the average minimum economic per barrel price for a true in situ 

operation to between $35 and $40 per barrel.
13

Economic and Distributional Effects

The proposed regulation changes would modify the commercial oil shale leasing and 

management regulations that were promulgated in 2008. The main proposed revisions to 

the existing regulations include changes in the royalty applied to production, changes in 

the information required prior to authorization, and changes in the standards applied to an 

authorization. The primary proposed provision with the potential to significantly alter the 

future distributional effects15 is the royalty provision.

Royalty Rate - Without a demonstrated technology, costs and production scenarios are 

speculative, at best. Instead of generating our own hypothetical costs and production 

scenarios, for the 2008 rulemaking we adopted the cost and production scenarios 

prepared by the Task Force on Strategic Unconventional Fuels.

16

 In preparing the 

original analysis, we also relied on the Department of Energy, Energy Information 

Administration’s (EIA) Annual Energy Outlook (AEO) crude oil price projections.17 

Using these 2006 oil price assumptions meshed with the Task Force’s 2006 cost 

assumptions in presenting the simulation based analysis of the possible relationships 

underlying potential royalties under various scenarios.

Since the Task Force completed their work in 2007, there has been no comparable effort 

to analyze and report on oil shale development potential, including production cost 

projections or production scenarios. EIA continues to publish their crude oil price 

projections. However, using these newer price projections creates a disconnect, i.e. using 

financial inputs for two different time periods, with the older cost assumptions. 

Royalty payments are recurring income to the Federal Government and costs to the 

operator/lessee. As such, they are transfer payments that do not affect total resources 

available to society. Changes in the royalty rate have the potential to significantly alter 

the future distributional effects; however, the revenues that they generate would not 

represent a net cost or benefit to the economy. The OMB defines “transfer payment” to 

include payments to the government in addition to the unearned payments from the 

government (Economic Analysis of Federal Regulations Under Executive Order 12866, 

January 11, 1996, http://www.whitehouse.gov/omb/inforeg_riaguide). In addition, the 

definition OMB uses encompasses the revenue collected through a fee, surcharge, or tax 

 

15 Note, an important, but sometimes difficult, problem in cost estimation is to distinguish between real 

costs and transfer payments. Transfer payments are not social costs, but rather are payments that reflect a 

redistribution of wealth. While transfers should not be included in the economic analysis estimates of the 

benefits and costs of a regulation, they may be important for describing the distributional effects of a 

regulation. Scarcity rents and monopoly profits, insurance payments, government subsidies and taxes, and 

distribution expenses are four potential problem areas that may affect both social benefits and costs as well 

as involve significant transfer payments. (See Economic Analysis of Federal Regulations Under Executive 

Order 12866, January 11, 1996, http://www.whitehouse.gov/omb/inforeg_riaguide)

16 America’s Strategic Unconventional Fuels Resources, Volume III Resource and Technology Profiles, 

Task Force on Strategic Unconventional Fuels, September 2007 (http://www.unconventionalfuels.org).

17 Department of Energy, Energy Information Administration, Annual Energy Outlook 2007, Report #: 

DOE/EIA-0383(2007), February 2007.
14

(in excess of the cost of any service provided) as a transfer payment. Since a royalty is 

not a payment for service, this OMB transfer payment definition holds that a royalty is a 

transfer payment and is not to be included in the annual effect to the economy

calculation. Thus, even if oil shale royalties were to increase annual government 

revenue, such revenue would be excluded from the annual effect to the economy

calculation because royalties are transfer payments for purposes of this analysis and as 

defined in OMB guidance.

Other potential Federal revenues associated with an oil shale leasing program would 

include rents and bonus bids. Rental rates are set by 43 CFR 3903.40 and would not be 

affected by this proposed rulemaking. Although the leasing process, including bonus 

bidding (see 43 CFR 3924.10), is not being modified by the proposed changes in this 

rulemaking, a change in the royalty rate will likely affect a lease’s fair market value.

Lessees pay bonuses, rentals, and royalties reflecting the fair market value of the rights to 

explore and potentially develop and produce oil shale resources.

An increase in the royalty rate, for example, will likely lower the amount producers are 

willing to pay for bonus bids, and thereby generate less net revenue for the Federal 

Government (and have a lower impact on producer profit) than would be anticipated by

analyzing royalty rates alone. These are factors the Secretary will need to consider in 

establishing the royalty rate for a lease, but cannot be quantified at this point in time since 

under this proposal the royalty rate will be set on a case-by-case basis in the notice of 

lease sale.

In addition to potentially affecting a lessee’s interest in acquiring a lease, or at a 

minimum, the amount they are willing to bid, the timing of payments and the financial 

risks are also shifted. Because a bonus bid is an up-front cost to the lessee, regardless of 

the economic success of the operation, the lessee/operator takes on all the financial risk. 

A royalty on the other hand is only payable when there is actual production. However, 

with a gross royalty, the economic burden still rests with the operator as the royalty 

payment is based on the value of the output regardless of the operation’s profitability. An 

alternative to a gross royalty would be a net royalty that allows for the accounting of 

certain production costs in determining the royalty base. Establishing an appropriate 

royalty rate requires an understanding of the dynamics between the royalty base and the 

royalty rate.

Any analysis of government revenues, including royalty revenues, of what constitutes a 

fair return and what royalty rate encourages development of the resource must consider a 

number of factors including the government’s take and the operator’s return on 

investment. What revenue scheme ensures a fair return to the government and also 

encourages development is much more complicated than simply picking a royalty rate.

If changing the royalty rate were not to impact oil shale production, then this rule would 

have no net national costs or benefits. The only potential impact would be on 

government revenues and producer profits, but as discussed above, the magnitude of this 

distributional impact would also be uncertain due to the expected interaction between 
15

royalty rates and bonus bids. If, however, changing the royalty rate were to affect 

production, then there would be benefits and costs. Lowering the royalty rate, for 

example, would be expected to increase the value of shale oil produced by diverting 

scarce resources (capital, skilled labor, etc.) from other economic activity. The cost to 

society would be the value of the output foregone by the diversion of these productive 

resources. In theory, the net national impact could be either positive or negative. 

Similarly, the net impact of government revenues is also ambiguous since reduced 

royalty revenues from foregone production elsewhere would have to be netted from 

increased gross government revenues from oil shale production. In light of the fact that 

currently there is no domestic oil shale industry or even a definitive commercial 

technology for extracting oil from the shale, the BLM does not believe it has sufficient 

information to quantify the costs, benefits, or net government revenues arising from any

given royalty rate. The rule seeks public comment regarding quantitative analysis on the 

potential supply implications of alternative royalty rates.

The interested reader may consult the analysis of revenue, profit, and royalty implications 

under various production scenarios that was prepared for the 2008 rulemaking. This 

analysis may help frame the potential implications of the proposed royalty provision. 

However, the reader should keep in mind that since that analysis assumed that royalty 

rates would not affect production, it necessarily implied that the rule would have no net 

national benefit, the only impact would be on government revenues and producer profits.

Moreover, the projections of these transfer payments in the 2008 analysis are gross 

royalty payments only since they do not include potential countervailing effects of 

changes in bonus bids in response to changes in royalty rates.

Other Proposed Revisions - In addition to the proposed changes to the existing royalty 

provisions, there are a number of provisions related to the information requirements and 

performance standards associated with lease issuance and operational approval.

The proposal is to amend 43 CFR 3926.10 by specifying that the BLM may deny an 

application to convert an R, D, and D lease to a commercial lease based on 

“environmental or other natural resource considerations.” In addition, 43 CFR 3931.10 

would be amended by adding that the BLM may deny or require a modification of the 

proposed plan of development based on “environmental or other resource 

considerations.” At 43 CFR 3931.11, the plan of development content provisions would 

be amended by identifying specific required content, including a “watershed and 

groundwater protection plan,” an “airshed review,” a “integrated waste management 

plan,” and an environmental protection plan.” As these proposed additions for the most 

part codify into regulations what the agency currently requires by policy and procedure, 

and these proposed provisions are not expected to significantly increase the costs to the 

agency, lessees, or operators. Qualitative benefits include clarity in expectations for 

applicants regarding information requirements as well as for the BLM’s consideration of 

environmental issues.

Under the proposed language at 43 CFR 3925.10, 3926.10, and 3931.10, the BLM would

not issue a lease or approve an operation unless it determined that the operations can 
16

occur without unacceptable environmental risk. The agency has extensive experience in 

evaluating environmental consequences, specifically tied to its Federal Lands and Policy

Management Act of 1976 responsibilities. This process is intended to help the agency

make decisions that are based on understanding the environmental consequences of a 

proposed action. The agency has limited experience in evaluating and measuring 

environmental risk and that standard generally applies to laws that govern hazardous 

materials and public health risks. The application of this standard may increase the 

economic burden for the agency and the proponent, potentially including the costs of 

non-approval. The BLM does not have sufficient information to quantify the potential 

costs or benefits of this proposed regulatory provision. 

Short of a lease or plan of development being denied, the requirement is primarily on the 

BLM to make the determination of whether a lease or operations pose an unacceptable 

environmental risk. To the extent there is an increase in compliance costs, the agency

would bear most additional cost associated with making such a determination under the 

proposed standard.

Conclusion

Executive Order 12866 and SBREFA require agencies to assess, where practical, the 

anticipated costs and benefits of a proposed regulatory action to determine if it is a 

significant regulatory action. For the 2008 rulemaking, the BLM projected distributional 

implications of various royalty rates under the assumption that royalty rates affect neither 

output nor bonus bids. As has been noted, there is no domestic oil shale industry to help 

substantiate or form the basis for the projections, and the BLM does not have new 

information with which to update that analysis.

As proposed, the oil shale applicant would not have a basis for a royalty rate until the 

time of a notice of sale or at the time of conversion of an R, D, and D lease. The effect of 

this change would be to permit royalty rates to be established on the basis of 

contemporaneous market conditions; however, it would also introduce uncertainty. The 

intent of the proposed removal of the royalty rates from the regulations is to allow rates to 

be set in the future when more information may be known about the costs and revenues 

of oil shale operations. Uncertainty in royalty rates, however, might discourage 

commercial oil shale development by requiring entities to make business decisions with 

less information.

There are other proposed provisions that may change the information requirements and 

performance standards associated with lease issuance and operational approval. Short of 

a lease or plan of development being rejected due to the proposed performance standard, 

potential increases to the processing cost, if they occur, would primarily be associated 

with analysis by the agency.
17

References

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