Regulatory Flexibility Act

Threshold Analysis

for

The Proposed Commercial Oil Shale Management Regulations

Introduction

The Regulatory Flexibility Act (RFA) requires agencies to analyze the economic impact 

of proposed and final regulations to determine the extent to which there is a significant 

economic impact on a substantial number of small entities. The RFA establishes an 

analytical process for determining how public policy goals can best be achieved without 

erecting barriers to competition, stifling innovation, or imposing undue burdens on small 

entities. Executive Order 13272 reinforces executive intent that agencies give serious 

attention to impacts on small entities and develop regulatory alternatives to reduce the 

regulatory burden on small entities. When the proposed regulation will impose a 

significant economic impact on a substantial number of small entities, the agency must 

evaluate alternatives that would accomplish the objectives of the rule without unduly

burdening small entities. Inherent in the RFA is a desire to remove barriers to 

competition and encourage agencies to consider ways of tailoring regulations to the size 

of the regulated entities.

In order to certify a rule under the RFA, an agency must provide a description of the 

affected entities and the impacts that clearly justifies and forms a factual basis for the “no 

impact” certification. The agency’s reasoning and assumptions underlying its 

certification should be explicit in order to obtain public comment and thus receive 

information that could be used to re-evaluate the certification.1

Proposed Rule

This new rulemaking provides the BLM an opportunity to consider the 2008 regulations 

in light of the still nascent character of the technology necessary to economically develop 

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.

 

1 U.S. Small Business Administration, Office of Advocacy, A Guide for Government Agencies: How to 

Comply with the Regulatory Flexibility Act, May 2003, (http://www.sba.gov/advo/laws/rfaguide.pdf ).
2

Royalty Rates

The Energy Policy Act of 2005 directs the Secretary of the Interior (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.”

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, the bonus bid 

must be held constant.
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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 costs, and as with all acquisitions, 

development and production costs must be considered when determining the bonus bid 

and royalty 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.

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, the 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 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 publication of the 2008 rule 

about the costs and revenues of commercial oil shale operations, or about royalties 

actually paid to non-Federal mineral owners in the United States that would support 

establishing royalty rates at this time.
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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 

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 BLM 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 
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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.

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 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 
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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 uncertainty for 

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 an operator 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 or the vast majority of 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 
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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 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 has 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.

Other alternatives that the BLM considered included not proposing an environmental 

standard, but employing for oil shale the practice of the BLM in numerous types of 

decisions regarding other resources of using its best professional judgment instead of a 

regulatory standard of environmental acceptability, and in light of the mandate in 

FLPMA, to prevent UUD of the public lands. The BLM expects 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 
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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 UER or the UEC standard would probably

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

understanding 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 is anticipated to be the same.

Number of Potentially Affected Entities

Entities that would be directly affected by this rule would include most, if not all, firms 

involved in the exploration and development of oil shale resources on Federal lands. 

Such firms are a subset of entities involved in the domestic oil shale industry.

The U.S. Census Bureau does not identify oil shale extraction and refining as a discrete 

industrial classification. Instead, firms involved in exploration and development of oil 

shale resources are included within the Crude Petroleum and Natural Gas Extraction2and 

Support Activities for Mining categories. Refining of oil from shale is grouped with the 

general category of Petroleum Refineries. Therefore, there is no practical way to use the 

U.S. Census Data to calculate the number of entities involved in the domestic oil shale

industry.

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 attempts ceased 

operations in 1991. Currently, there are no domestic commercial operations producing 

oil shale. In addition, there are currently no active commercial oil shale operations on 

Federal lands. However, there are six firms that hold eight R, D and D leases.

With technological advances and favorable market conditions that would support oil 

shale development, we anticipate an increase in the number of firms involved in oil shale 

development. However, the number of firms involved in oil shale development on 

Federal lands will likely remain quite limited. Estimates for the size of the industry in the 

next 30 years range from 3 to 17 operations involved in the extracting and retorting of 

shale oil. To put these numbers in perspective, in 2009 there were approximately 6,500

establishments directly involved in the extraction of crude oil and natural gas in the 

United States. 3 This count does not include establishments primarily engaged in 

performing drilling and other support activities for oil and gas operations, which would 

add about another 10,000 establishments.

 

2 U.S. Department of Commerce, Economics and Statistics Administration, U.S. Census Bureau, North 

American Industry Classification System (NAICS) Definitions, 

(http://www.census.gov/epcd/www/naics.html).

3 U.S. Department of Commerce, Economics and Statistics Administration, U.S. Census Bureau, Number 

of Firms, Number of Establishments, Employment, and Annual Payroll by Employment Size of the 

Enterprise for the United States, All Industries 2009 (http://www.census.gov/csd/susb/susb09.htm).
9

Although this rule would only affect entities that choose to explore and develop oil shale

resources from land administered by the BLM, there is no way to determine which firms 

would hold exploration licenses or leases, or operate on Federal lands in the future. The 

extent to which the rule would have an actual impact on any firm would depend on 

whether it holds leases or operates on Federal lands.

Impacted Small Entities

The Small Business Administration (SBA) has developed size standards to carry out the 

purposes of the Small Business Act; those size standards can be found in 13 CFR 

121.201.4 The SBA defines small entities involved in the oil and gas industry, which 

includes oil shale, as individuals, limited partnerships, or small companies considered at 

“arm’s length” from the control of any parent companies, with fewer than 500 

employees. For firms involved in oil and gas field exploration services and other field 

services SBA defines a small entity as having annual receipts of less than $5 million.

As noted above, U.S. Census data on firms involved in oil shale research, exploration,

and development by number of employees is not available; or at least not available in a 

form that allows us to separate those firms from the much larger oil and gas industry. 

Information on firms involved in the oil shale industry is included in the broader 

categories of Crude Petroleum and Natural Gas Extraction, Support Activities for Oil and 

Gas Operations and Petroleum Refineries. Within the Crude Petroleum and Natural Gas 

Extraction category, over 98 percent of the firms have fewer than 500 employees;

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and 74

percent of all firms in the Petroleum Refineries category had fewer than 500 employees. 

Ninety two percent of the firms involved in providing oil and gas field service support 

had an average annual receipt of less than $5 million.6 This data would indicate that the 

preponderance of firms in the domestic oil and gas industry are small entities as defined 

by SBA.

Currently, active oil shale research and development on Federal lands is limited to a few 

firms operating on R, D and D leases. Of the six companies holding the eight R, D and D

leases, three are subsidiaries of major oil companies, one venture is 50 percent owned by

a major oil company, and the other two firms are subsidiaries of foreign companies. 

From the available information, it is not clear the size of these foreign companies. In 

addition to the current make up of those firms operating on Federal lands, past efforts 

primarily involved the Federal Government or large corporations. This is not to say

smaller firms were not involved, but rather their involvement would have been primarily 

to support these larger organizations.

 

4 13 CFR 121.201 (http://www.sba.gov/regulations/121/).

5 U.S. Department of Commerce, Economics and Statistics Administration, U.S. Census Bureau, Number 

of Firms, Number of Establishments, Employment, and Annual Payroll by Employment Size of the 

Enterprise for the United States, All Industries 2009 (http://www.census.gov/csd/susb/susb09.htm)

6 U.S. Department of Commerce, Economics and Statistics Administration, U.S. Census Bureau, Support 

Activities for Oil and Gas Operations: 2002, Table 4

(http://www.census.gov/prod/ec02/oc0221i213112.pdf).
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Under the right conditions, we anticipate the number of firms involved in the 

development of oil shale resources on Federal lands to increase. The BLM expects

potential future oil shale development will involve both large and small firms. If past 

development efforts are an indicator of how future development might occur, most 

leasing and development will be lead by a large, well capitalized organization, supported 

by smaller entities. Given the likely size of the industry that may eventually be involved 

in the leasing and development of Federal oil shale resources, it is our conclusion that this 

rule would not impact a “substantial number of small entities.”

Direct Economic Impacts

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

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

the existing regulations would 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 discussed impacts are associated with this proposed rule, 

not the anticipated impacts of the existing regulations.

The primary proposed provision with the potential to significantly alter the future effects 

on lessees and operators is the proposal to replace the existing royalty provision with a 

provision that the Secretary would establish a lease royalty rate prior to lease issuance in 

the notice of lease sale.

As with the original analysis prepared for the final oil shale rule in 2008 (73 FR 69414, 

November 18, 2008), any assessment of future effects must recognize significant 

uncertainties and unknowns. Currently, there is no domestic oil shale industry or even a 

definitive commercial technology for extracting oil from the shale.

As proposed, the cost associated with royalty payments could be higher or lower than that

required by the current royalty provisions. As the Secretary would establish the rate prior 

to lease issuance in the notice of lease sale, we have no way of accurately projecting what 

the royalty rate(s) might actually be in the future under the proposed rule.

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,” an “integrated waste management 
11

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, 

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

occur without unacceptable environmental risk. 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.

Impact Significance

Oil shale development is characterized by high capital investment and long periods of 

time between expenditure of capital and the realization of production revenues and return 

on investment. Revenues are uncertain because future market prices for shale oil and 

byproducts are unknown. Therefore, a key economic barrier to private development is 

the inability to predict when profitable operations would begin. The economic risk 

associated with this uncertain outcome is magnified by the unusually large capital 

exposure, measured in billions of dollars per project, required for development. Given 

the myriad of technological and economic unknowns, in addition to not knowing what the 

royalty rate might be until lease issuance, it is not possible to quantify the potential 

impacts of the proposed changes. There are significant barriers to oil shale development, 

including technological unknowns and potentially significant environmental impacts. 

But the proposed regulatory changes, including proposed changes to production royalties, 

are not likely to impede development or have a significant economic impact on lessees or 

operators, regardless of the firm’s size.

Conclusion

Potential oil shale development, if it occurs, will most likely involve a few very large 

well capitalized firms, supported by a few smaller firms. We make this assumption 

because:

 Most development scenarios suggest relatively few operations;

 Most engineering cost models and past development efforts suggest significant 

capital investments; and
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 Past development efforts involved a few large well capitalized companies 

supported by a few smaller research and development firms and support firms.

As such, we do not anticipate the proposed revisions to the existing regulations to impact 

a significant number of small entities.

In addition to not impacting a significant number of small entities, we also do not 

anticipate the impact of this final rule to have a significant economic impact. The 

proposed provision that has the potential to significantly alter the future costs is the 

royalty provision. However, as the proposed royalty provision is for the Secretary to 

establish the royalty rate prior to lease issuance, the BLM cannot estimate the impact of 

the potential rate change. The other proposed changes are not anticipated to be 

economically significant and/or are unknown.
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Certification

In conformance with section 605(b) of the Regulatory Flexibility Act, I certify that this

rule will not have a significant economic impact on a substantial number of small entities.

______________________________________________________________________

Director, Bureau of Land Management Date
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References

U.S. Small Business Administration, Office of Advocacy, A Guide for Government 

Agencies: How to Comply with the Regulatory Flexibility Act, May 2003,

(http://www.sba.gov/advo/laws/rfaguide.pdf).

U.S. Department of Commerce, Economics and Statistics Administration, U.S. Census 

Bureau, North American Industry Classification System (NAICS) Definitions, 

(http://www.census.gov/epcd/www/naics.html).

Small Business Size Regulations, 13 CFR 121.201 

(http://www.sba.gov/regulations/121/).

U.S. Department of Commerce, Economics and Statistics Administration, U.S. Census 

Bureau, Number of Firms, Number of Establishments, Employment, and Annual Payroll 

by Employment Size of the Enterprise for the United States, All Industries 2009

(http://www.census.gov/csd/susb/susb04.htm).

U.S. Department of Commerce, Economics and Statistics Administration, U.S. Census 

Bureau, Support Activities for Oil and Gas Operations: 2002, Table 4

(http://www.census.gov/prod/ec02/oc0221i213112.pdf).