Well Stimulation Proposed Rule: 

Economic Analysis and Initial Regulatory 

Flexibility Analysis

U.S. Bureau of Land Management
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Table of Contents

1. Executive Summary........................................................................................................................................................ 1

1.1 Introduction.............................................................................................................................................................. 1

1.2 Results....................................................................................................................................................................... 2

1.3 Organization of this Report................................................................................................................................. 6

2. Background........................................................................................................................................................................ 7

2.1 Requirements for Economic Analysis............................................................................................................. 7

2.2 Need for Policy Action......................................................................................................................................... 8

2.3 Proposed Regulations.........................................................................................................................................10

2.3a Definition Additions and Changes.............................................................................................................11

2.3b Section-By-Section Discussion of Proposed Changes........................................................................12

2.3c Alternative Approaches.................................................................................................................................22

2.4 Federal and Indian Oil and Gas Leasing Activity......................................................................................25

2.5 Industry Classifications......................................................................................................................................26

2.6 Unconventional Development..........................................................................................................................26

2.7 Well Stimulation Process...................................................................................................................................28

2.8 Industry Guidelines on Well Construction and Integrity.........................................................................29

3. Estimating Benefits and Costs...................................................................................................................................32

3.1 Theoretical Framework ......................................................................................................................................32

3.2 Methodology..........................................................................................................................................................35

3.2a Data......................................................................................................................................................................35

3.2b Discounted Present Value.............................................................................................................................38

3.2c Uncertainty........................................................................................................................................................38

4. Results...............................................................................................................................................................................40

4.2 Proposed Regulations (Preferred Option) ....................................................................................................41

4.3 Alternative 1: No Requirement for Lined Pits............................................................................................47

5. Economic Impact Analysis and Distributional Assessments...........................................................................50

5.1 Energy System Impact Analysis......................................................................................................................50

5.2 Employment Impact Analysis..........................................................................................................................51

5.3 Small Business Impacts Analysis...................................................................................................................52

6. Statutory and Executive Order Reviews.................................................................................................................55
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6.1 Executive Order 12866 Regulatory Planning..............................................................................................55

6.2 Executive Order 13132 Federalism................................................................................................................55

6.3 Executive Order 13175 Consultation and Coordination with Indian Tribal Governments..........55

6.4 Executive Order 13211 Actions Concerning Regulations that Significantly Affect Energy 

Supply, Distribution, or Use............................................................................................................................................56

6.5 Regulatory Flexibility Act and Small Business Regulatory Enforcement Fairness Act of 1996 (5 

U.S.C. 601-612)..................................................................................................................................................................57

6.6 Unfunded Mandates Reform Act of 1995 (P.L. 104-4)...........................................................................58

7. Conclusion ..................................................................................................................................................................59

8. References........................................................................................................................................................................60

9. Appendix ..........................................................................................................................................................................62
1

1. Executive Summary

1.1 Introduction

The Bureau of Land Management (BLM) estimates that roughly 90 percent of wells 

currently drilled on Federal and Indian lands are stimulated using hydraulic fracturing 

techniques. Hydraulic fracturing facilitates the production of oil and gas where there is no flow 

or the resource is trapped within reservoir rock. However, the technique is not without 

controversy. The public and other groups have expressed concerns that hydraulic fracturing and 

the expansion of oil and gas drilling into new parts of the country pose adverse impacts to water 

quality and safety. 

The BLM hosted public forums in 2011 where panelists and the audience expressed 

support for improved surface operations and the disclosure of fracturing fluid components. The 

Secretary of Energy's Advisory Board Subcommittee on Natural Gas has also recommended 

public disclosure of the chemicals used in fracturing fluids, broader use of water quality 

sampling before drilling new wells, and progressive standards for wellbore construction. A

number of states have passed legislation requiring the disclosure of fracturing fluids.1

 

The BLM has regulatory authority for hydraulic fracturing, found in 43 CFR 3162.3-2; 

however, the current regulation is inadequate in several respects. Current regulation separates 

fracture operations into “routine” and “non-routine” operations, but it does not define the 

difference, thus creating confusion among operators, stakeholders, and others. As a result, the 

BLM receives a small number of Notice of Intent Sundry proposals for hydraulic fracturing 

operations on BLM-managed lands even though these operations are common. Also, the 

regulation is 30 years old and does not reflect the many changes to technology and industry best 

practices that have occurred since that time. As such, it does not present standards for wellbore 

integrity even though such standards exist. Lastly, current regulations do not require the 

disclosure of the chemicals used in fracturing fluids and other information necessary for the 

BLM to effectively manage the nation’s resources on Federal and Indian Lands. 

As part of the regulatory process, the BLM conducted this economic analysis to estimate 

the benefits and costs of the proposed regulatory changes. The results indicate that the proposed 

rule is not economically significant according to the criteria in Executive Order 12866. 

 1 “Natural Gas: More States Require Disclosure of Fracking Chemicals” (January, 23, 2012). Greenwire.
2

However, in accordance with Executive Order 12866, the Office of Management and 

Budget (OMB) has determined that the rule is significant, since it would require operators to 

provide information to the BLM regarding well stimulation activities that they are currently not 

required to submit. As such, it might raise novel policy issues.

1.2 Results 

The analysis estimates the effects of the proposed regulations over a baseline scenario, 

where no action is taken. It also examines an alternative to the proposed regulations. It 

considers the removal of the requirement for operators to line pits when using pits to store 

fracturing fluids. 

The analysis considers impacts occurring over a ten-year period. The benefits, costs, and 

net benefits presented in this section are discounted at 7% and 3%. Results are presented as 

annualized values.

Proposed Regulations (Preferred Approach)

Benefits

Under the proposed regulations, it is assumed that the regulations would remove much of 

the risk associated with potential wellbore integrity issues and unlined pits. The change in social 

benefits from the baseline scenario is positive. Because monetization of the reduction of risk 

associated with potential wellbore integrity is a difficult issue, this analysis is using avoided cost 

of remediation as a proxy value. If you assume that there is low environmental risk posed by 

wellbore integrity issues and storage of hydraulic fracturing fluids in unlined pits and the costs of 

surface and subsurface remediation is low (on the range assumed), then the change in social 

benefit as a result of the proposed regulation is positive and ranges between $11.70MM and 

$13.79MM per year using a discount rate of 7% and between $11.74MM and $13.85MM per 

year using a discount rate of 3%. If you assume that environmental risk are high and remediation 

costs are high (on the range assumed), then the social benefits of the proposed regulation is 

positive and ranges between $42.67MM and $50.27MM per year using a discount rate of 7% and 

between $42.79MM and $50.49MM per year using a discount rate of 3%. 

Costs

The change in costs over the baseline ranges between $37.34MM and $43.99MM per 

year using a discount rate of 7% and between $37.44MM and $44.18MM per year using a 
3

discount rate of 3%, assuming either low remediation costs and low environmental risks or high 

remediation costs and low environmental risks. 

Net Benefits

The change in net benefits for the proposed regulations varies depending on the amount 

of environmental risk associated with wellbore integrity issues and unlined pits and the level of 

remediation costs associated with contamination events. Assuming low remediation costs and 

low environmental risks, the change in net benefits from the baseline is negative and ranges from 

between -$25.63MM and -$30.20MM per year using a discount rate of 7% and between 

-$25.70MM and -$30.33MM per year using a discount rate of 3%. Assuming high remediation 

costs and high environmental risks, the change in net benefits is positive and ranges from 

between $5.33MM and $6.28MM per year using a discount rate of 7% and between $5.35MM 

and $6.31MM per year using a discount rate of 3%. 

Given the assumptions made about the costs of remediating contamination and the fact 

that certain benefits were not quantified, the range of estimated outcomes could underestimate 

the actual net benefits. The analysis makes several assumptions about the occurrence or 

contamination and the costs of remediating a contamination event. It assumes low and high costs 

of $42,500 and $1,000,000, respectively, for remediation of a subsurface contamination, and 

$25,000 and $75,000 for remediation of a surface contamination. Given the uncertainty in 

estimating these costs, the assumptions used err on the side of understating net benefits. Where 

net benefits are estimated to be negative, the net benefits could be greater (meaning the net 

benefits could be less negative or positive). 

This analysis also does not capture the potential benefits associated with the disclosure of 

fracturing fluids. Disclosure might encourage operators to use fewer or safer chemicals in the 

hydraulic fracturing fluid. Operators disclosing the MIT and wellbore integrity might add more 

awareness and attention for due diligence to prudent operations. The public would benefit from 

increased knowledge about the fluids used. This transparency is also likely to benefit scientists, 

state and Federal agencies, and other organizations that study the potential impacts of well 

stimulation operations. The BLM would be able to make more informed resource decisions and 

respond effectively to events where environmental resources have been compromised.

It should be noted that the low cost and risk scenario results in negative net benefits while 

the high cost and risk scenario results in positive net benefits. This primary difference is not a 
4

result of the administrative or operational costs changing between the scenarios. Instead, the 

difference is due to the valuation of social benefits. If you assume the risk of contamination is 

greater and the costs of remediation are higher, then the change in benefits of the proposed rule 

would be greater and offset the change in compliance costs. 

Alternative 1: Removal of Requirement to Line Pits when Operators Use Pits to Store 

Fracturing Fluids

Benefits

The change in social benefits from the baseline scenario is positive. Assuming low 

remediation costs and low environmental risks, then the change in social benefit under this 

alternative is positive and ranges between $0.01MM and $0.02MM per year using a discount rate 

of 7%. Assuming high remediation costs and high environmental risks, the change in social 

benefits over the baseline ranges between $7.60MM and $8.95MM per year using a discount rate 

of 7%.

Costs

The change in costs over the baseline ranges between $34.68MM and $40.86MM per 

year using a discount rate of 7% and between $34.77MM and $41.04MM per year using a 

discount rate of 3%, regardless of the remediation costs and environmental risks assumptions.

Net Benefits

The change in net benefits is negative for this alternative. Assuming low remediation 

costs and low environmental risks, the change in net benefits range from between -$34.67MM 

and -$40.84MM per year using a discount rate of 7% and between -$34.76MM and -$41.02MM 

per year using a discount rate of 3%. Assuming high remediation costs and high environmental 

risks, the change in net benefits ranges between -$27.08MM and -$31.90MM per year using a 

discount rate of 7% and between -$27.15MM and -$32.04MM per year using a discount rate of 

3%. 
5

Energy System Impacts

The proposed regulations are unlikely to affect the investment decisions of firms, or to 

have any effect on the supply, distribution, or use of energy. The analysis estimates the cost 

burden per well stimulation and presents it as a portion of the drilling costs per well.

Small Entity Analysis

Small entities represent the overwhelming majority of entities operating in the crude oil 

and natural gas extraction industry. As such, the proposed rule is likely to affect a significant 

number of small entities. However, after considering the economic impact of the proposed rule 

on these small entities, the screening analysis indicates that this proposed rule will not have a 

significant economic impact on a substantial number of small entities. The analysis presents the 

burden per small entity as a share of a sample of small entity net incomes in 2010.

Employment Impacts Analysis

This analysis seeks to inform the discussion of labor demand and job impacts by 

providing an estimate of the employment impacts of the proposed regulations using labor 

requirements for the additional administration and operational needs.

This proposed rule would require operators, who have not already done so, to conduct 

one-time tests on a well or make a one-time installation of a mitigation control feature. In 

addition, operators would be required to perform administrative tasks related to a one-time event. 

Compliance with the operational requirements is expected to shift resources within the industry 

from the operators to firms providing the services or supplies.

Since we anticipate that the number of well stimulations will increase over time, the labor 

requirements are expected to increase over the outlook period. Depending on the scenario, the 

annual labor requirements range from about 15 to 18 additional full-time employees (FTE) in 

2013. Operators are not expected to reduce investment or employment as a result of increased 

burden. Note that these impacts are only for the regulated sector. The BLM cannot predict the 

net national employment impact, i.e., whether the increased employment in the regulated sector 

comes from previously unemployed workers or is displaces workers actively employed in other 

sectors.
6

1.3 Organization of this Report

The remainder of this report details the methodology and the results of the analysis. 

Section 2 presents additional background material. Section 3 describes the framework and 

methodology for estimating benefits and costs. Section 4 presents the estimated benefits and 

costs. Section 5 presents the energy system impact, employment impact, and small business 

impact analyses. Section 6 presents determinations regarding statutory and executive order 

requirements. Section 7 offers a conclusion. Sections 8 and 9 provide a list of the references and 

appendix materials, respectively.
7

2. Background

2.1 Requirements for Economic Analysis

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.

When an agency publishes a general notice of proposed rulemaking, 5 U.S.C. 603 

requires the agency to perform an initial regulatory flexibility analysis and make it available for 

public comment.2

 The analysis must describe the impact of the proposed rule on small entities 

and contain the following information:

• Description of the reasons why action by the agency is being considered;

• Succinct statement of the objectives of, and legal basis for, the proposed rule;

• Description of and, where feasible, an estimate of the number of small entities to which 

the proposed rule will apply;

 2 An agency must conduct a final regulatory flexibility analysis when it promulgates a final rule, per 5 U.S.C. 604.
8

• Description of the projected reporting, recordkeeping and other compliance 

requirements of the proposed rule, including an estimate of the classes of small entities 

which will be subject to the requirement and the type of professional skills necessary 

for preparation of the report or record; and 

• Identification, to the extent practicable, of all relevant Federal rules which may 

duplicate, overlap or conflict with the proposed rule.

The initial regulatory flexibility analysis should also contain a description of any 

significant alternatives to the proposed rule which would accomplish the stated objectives but 

which would minimize any significant economic impact of the proposed rule on small entities. 

2.2 Need for Policy Action

The BLM estimates that roughly 90 percent of wells currently drilled on BLM-managed 

lands are stimulated using hydraulic fracturing techniques. Hydraulic fracturing is a technique 

used to increase the amount of crude oil or natural gas produced from a reservoir. During a 

hydraulic fracturing event, an operator will pump a specially blended liquid containing water, 

chemicals, and other materials into a formation with sufficient pressure to cause the formation to 

crack, allowing the resource to flow to the wellbore. The fracturing fluid is designed to serve 

several functions, such as lubricating the fractures and leaving channels open for the

hydrocarbon resource to flow to the well. 

The public and other groups have expressed strong concerns about the prevalence of 

hydraulic fracturing and the chemical content of the fluids used in the process. As a follow-up to 

the Department of the Interior (DOI) forum on hydraulic fracturing on November 30, 2010, the 

BLM hosted public forums in Bismarck, North Dakota on April 20, 2011; Little Rock, Arkansas

on April 22, 2011; and Golden, Colorado on April 25, 2011, to collect broad input on the issues 

surrounding hydraulic fracturing. Over 600 members of the public attended the forums. Some 

of the comments frequently heard during these forums included concerns about water quality, 

water consumption, and a desire for improved environmental safeguards for surface operations. 

Commenters also strongly encouraged the agency to require public disclosure of the chemicals 

used in hydraulic fracturing operations on Federal and tribal lands.
9

Around the time of the BLM’s forums, at the President’s direction, the Secretary of 

Energy’s Advisory Board convened a Natural Gas Subcommittee (Subcommittee) to evaluate 

hydraulic fracturing issues. The Subcommittee met with industry, service providers, state and 

Federal regulators, academics, environmental groups, and many others stakeholders. Initial 

recommendations were issued by the Subcommittee on August 18, 2011. Among other things, 

the report recommended that more information be provided to the public, including disclosure of 

the chemicals used in fracturing fluids. The Subcommittee also recommended the adoption of 

progressive standards for wellbore construction and testing. The initial report was followed by a 

final report that was issued on November 18, 2011. The final report recommended, among other 

things, that operators engaging in hydraulic fracturing prepare cement bond logs and undertake 

pressure testing to ensure the integrity of all casings. These reports are available to the public 

from the Department of Energy’s web site at http://www.shalegas.energy.gov.

The U.S. Environmental Protection Agency (EPA) lists the following as potential impacts 

of hydraulic fracturing3

:

• Stress on surface water and ground water supplies from the withdrawal of large 

volumes of water used in drilling and hydraulic fracturing; 

• Contamination of underground sources of drinking water and surface waters 

resulting from spills, faulty well construction, or by other means; and

• Adverse impacts from discharges into surface waters or from disposal into 

underground injection wells.

The BLM regulatory authority for hydraulic fracturing is found in 43 CFR 3162.3-2. 

Under that regulatory provision, “Subsequent Well Operations,” if a “routine” hydraulic 

fracturing operation is performed on an existing well, the operator must provide a sundry report 

of the operation to the BLM within the 30 days following its performance. For “non-routine” 

fracturing operations, the operator must seek approval from the BLM authorizing officer before 

operations begin in addition to the subsequent report required for the “routine” operation. The 

regulations do not offer a definition regarding the terms “routine” or “non-routine.” The current 

regulations make a distinction between routine fracture jobs and nonroutine fracture jobs. The 

terms “routine” and “nonroutine” are not defined in 43 CFR 3162.3-2 or anywhere else in BLM 

regulations, making this distinction functionally difficult to apply and confusing for both the 

 3 EPA (2012). “Natural Gas Extraction – Hydraulic Fracturing.”
10

agency and those attempting to comply with the regulations. These regulations were established 

in 1982.

Since the current regulations do not require operators to demonstrate wellbore integrity 

and disclose the plans for and results of the well stimulation operations, there is greater potential 

for negative externalities to occur. Wellbores that are constructed inadequately may not 

sufficiently isolate the wellbore and well fluids from the subsurface water resources or may be 

more likely to fail during fracturing operations, than wellbores constructed with sufficient and 

demonstrated integrity. Although the current liability regime allows for remediation of 

environmental damages associated with hydraulic fracturing, potential difficulties in tracing 

contamination of underground sources of water to the particular wells that may have contributed 

to the damage may exist. This potential externality provides conceptual basis for this federal 

regulatory effort.

Also, the current regulation results in incomplete information being provided to the BLM 

and the public. As the resource manager, the lack of information restricts the BLM’s ability to 

make informed resource decisions or respond effectively to events where environmental 

resources have been compromised.

The BLM proposes to revise 43 CFR 3162.3-2 for several reasons. First, the increased 

use of well stimulation operations over the last decade has generated concerns among the public. 

Knowing the ingredients of fracturing fluids will help the government better manage and protect 

valuable resources. Next, 43 CFR 3162.3-2 distinguishes between non-routine fracture jobs and 

routine fracture jobs but never defines them. Subsequently, operators, stakeholders and others, 

are confused about which fracturing operations need the BLM’s approval. Finally, the regulation 

is now 30 years old, and many changes to technology and industry standards have occurred since 

that time and these changes have not yet been addressed in BLM regulations. 

2.3 Proposed Regulations

As an administrative matter, the proposed rule would amend the authorities section for 

the BLM’s oil and gas operations management regulations at 43 CFR 3160.0-3 to include 

FLPMA. Section 310 of FLPMA authorizes the Secretary of the Interior to promulgate 

regulations to carry out the purposes of FLPMA and other laws applicable to the public lands. 

See 43 U.S.C. 1740. This amendment would not be a major change and would have no effect on 

lessees, operators, or the public.
11

The proposed rule would remove the terms “nonroutine fracturing jobs,” “routine 

fracturing jobs,” and “acidizing jobs” from 43 CFR 3162.3-2(a) and 43 CFR 3162.3-2(b). It 

would add a new section, 43 CFR 3162.3-3, for well stimulation activities. In the proposed rule, 

there would be no distinction drawn between what was previously considered nonroutine or 

routine well stimulations. Prior approval would be required for well stimulation activities, 

generally in connection with the prior approval process that already is in place for general well 

drilling activities through the Application for Permit to Drill (APD) process. Operators also will 

be required to submit cement bond logs before fracturing operations begin. The running of 

cement bond logs on surface casing, which is currently an optional practice, would now be 

required for new wells. Existing wells would require mechanical integrity testing prior to 

hydraulic fracturing.

2.3a Definition Additions and Changes

The proposed rule would include six new definitions for technical terms used in the 

proposed rule. These definitions will improve readability and clarity of the regulations. 

The proposed rule intends to add the following definitions:

• Annulus means the space around a pipe in a wellbore, the outer wall of which may be the 

wall of either the borehole or the casing; sometimes also called the annular space.

• Bradenhead means a heavy, flanged steel fitting connected to the first string of casing

that allows suspension of intermediate and production strings of casing, and supplies the 

means for the annulus to be sealed off.

• Proppant means a granular substance (most commonly sand, sintered bauxite, or ceramic) 

that is carried in suspension by the fracturing fluid and that serves to keep the cracks open 

when fracturing fluid is withdrawn after a hydraulic fracture treatment.

• Stimulation fluid means the liquid or gas, and any accompanying solids, used during a 

treatment of oil and gas wells, such as the water, chemicals, and proppants used in 

hydraulic fracturing.

• Usable water means water containing up to 10,000 ppm of total dissolved solids. 

• Well stimulation means those activities conducted in an individual well bore designed to 

increase the flow of hydrocarbons from the rock formation to the well bore by modifying 
12

the permeability of the reservoir rock. Examples of well stimulation operations are 

acidizing and hydraulic fracturing. 

The proposed rule would delete the definition of “fresh water.” The BLM has maintained 

a definition of fresh water in its oil and gas operating regulations since 1988. However, in its 

onshore orders, the BLM has sought to protect all usable waters during drilling operations, not 

just fresh water. This distinction has led to confusion in the regulations. Usable water includes 

fresh water and water that is of lower quality than fresh water. The BLM intends to be more 

protective when it seeks to protect all usable water during drilling operations, not just fresh 

water. Therefore, the BLM proposes to delete the definition of fresh water. 

2.3b Section-By-Section Discussion of Proposed Changes

Revised section 3162.3-2(a) would remove the phrase “perform nonroutine fracturing 

jobs” from the current 43 CFR 3162.3-2(a). The phrase “routine fracturing jobs or acidizing 

jobs, or” would also be removed from existing section 3162.3-2(b). Well stimulation activities 

would be addressed under the new proposed 43 CFR 3162.3-3.

Proposed section 3162.3-3(a) would make it clear that this section applies only to well 

stimulation activities and that all other injection activities must comply with section 3162.3-2. 

This language is necessary to make the distinction between well stimulation activities and other 

well injection activities, such as secondary and tertiary recovery operations. 

Proposed section 3162.3-3(b) would require the BLM’s approval of all well stimulation 

activity. For new wells, the operator has the option of applying for the BLM’s approval in its 

application for permit to drill (APD). For wells permitted prior to the effective date of this 

section or for wells permitted after the effective date of this section, the operator would submit a 

Sundry Notice and Report on Wells (Form 3160-5) for the well stimulation proposal for the 

BLM’s approval before the operator begins the stimulation activity. This section would 

supersede and replace existing section 3162.3-2(b) that states that no prior approval is required 

for routine fracturing. This reference in the existing section would be deleted. Also, an operator 

must submit a Sundry Notice prior to well stimulation activity if the BLM’s previous approval 

for well stimulation is more than five years old, or if the operator becomes aware of significant 

new information about the relevant geology, the stimulation operation or technology, or the 

anticipated impacts to any resource. The five-year period is consistent with common state 
13

practices, including those of Montana, Wyoming, and Colorado, which require that operators 

reconfirm well integrity for fracturing operations through a pressure test every five years. 

The BLM understands the time sensitive nature of oil and gas drilling and well completion 

activities and does not anticipate that the submittal of additional well stimulation-related 

information with APD applications will impact the timing of the approval of drilling permits. 

The BLM believes that the additional incremental information that would be required by this rule 

would be reviewed in conjunction with the APD and within the normal APD processing time 

frame. Also, the BLM anticipates that requests to conduct well stimulation activities on existing 

wells that have been in service more than five years will be reviewed promptly. The BLM 

understands that delays in approvals of operations can be costly to operators and the BLM 

intends to avoid delays whenever possible. However, as with any operational activity, there may 

be unforeseen circumstances that may on rare occasions delay approval of APDs. Please 

specifically comment on the nature and severity of impacts that delays in approvals of hydraulic 

fracturing operations could cause.

Proposed section 3162.3-3(c)(1) would require a report that includes the geological 

names, a geological description, and the depth of the top and the bottom of the formation into 

which well stimulation fluids would be injected. The report is needed so that the BLM may 

determine the properties of the rock layers and the thickness of the producing formation and 

identify the confining rocks above and below the zone that would be stimulated.

Proposed section 3162.3-3(c)(2) would require the operator to submit information in the 

form of a cement bond log, which will help the BLM in its efforts to make sure that water 

resources are protected. A cement bond log is a tool used to gauge the extent to which water 

bearing formations are isolated from the casing string. The log is a document that reports the 

data from a probe of the wellbore that uses sonic technology to detect gaps or voids in the 

cement and the casing. This log would be used to verify that the operator has taken the 

necessary precautions to prevent migration of fluids in the annulus from the fracture zone to the 

usable water horizons. The proposed regulation allows for the use of other evaluation tools 

acceptable to the BLM in order to allow the substitution of equally effective tools or procedures. 

For example, an operator could request a variance from the requirements of proposed section 

3162.3-3(c)(2) that it submit cement bond logs to prove that the occurrences of usable water have 

been isolated to protect them from contamination. The BLM could grant a variance to allow for 
14

the use of logs other than cement bond logs (e.g., slim array sonic tool, ultrasonic imager tool) if 

it was satisfied that the alternative logs would meet or exceed the objectives of section (c)(2). 

The BLM recognizes that the cement bond log would not be available prior to drilling a well. 

Therefore, when the operator takes advantage of the option to submit its well stimulation 

information as part of its APD, the cement bond log would be required after approval of the 

permit to drill and prior to commencing well stimulation activities. Many operators routinely 

perform cement bond logs for the zones of interest, so the BLM does not expect this step to be a 

burden for operators. The best available means for the BLM to help ensure that well stimulation 

activities do not contaminate aquifers is to require cement bond logs for the cement behind the 

pipe along all areas intersecting useable water, including running cement bond logs on the 

surface casing.

Proposed section 3162.3-3(c)(3) would require reporting of the measured depth to the 

perforations in the casing and uncased hole intervals (open hole). This proposed section would 

also require the operator to disclose specific information about the water source to be used in the 

fracturing operation, including the location of the water that would be used as the base fluid. 

The BLM needs this information to determine the impacts associated with operations and the 

need for any mitigation applicable to Federal and Indian lands. This section would also require 

the operator to disclose the type of materials (proppants) that would be injected into the fractures 

to keep them open and the anticipated pressures to be used in the well stimulation operation.

Proposed section 3162.3-3(c)(4), consistent with protecting public health and safety and 

preventing unnecessary or undue degradation to the public lands, would require operators to 

certify in writing that they have complied with all applicable Federal, tribal, state, and local laws, 

rules, and regulations pertaining to proposed stimulation fluids. The BLM will use this 

information to make an informed decision on the proposed action. This section also would 

require the operator to certify that it has complied with all necessary permit and notice 

requirements. The BLM acknowledges that other Federal, state, tribal, and local agencies may 

have regulatory requirements that would apply to chemical handling, injecting fluids into the 

subsurface, and the protection of groundwater. It remains the responsibility of the operator to be 

aware of and comply with these regulatory requirements. The BLM will rely on the operator’s 

certification that it has complied with all of the laws and regulations that apply to its operation.
15

Proposed section 3162.3-3(c)(5) would require the operator to submit a detailed 

description of the well stimulation engineering design to the BLM for approval. This 

information is needed in order for the BLM to be able to verify that the proposed engineering 

design is adequate for safely conducting the proposed well stimulation. 

Proposed section 3162.3-3(c)(5)(i) would require the operator to submit to the BLM an 

estimate of the total volume of fluid to be used in the stimulation. 

Proposed section 3162.3-3(c)(5)(ii) would require the operator to submit to the BLM a 

description of the range of the surface treating pressures anticipated for the stimulation. This 

information is needed by the BLM to verify that the maximum wellbore design burst pressure 

will not be exceeded at any stage of the well stimulation operation. 

Proposed section 3162.3-3(c)(5)(iii) would require the operator to submit to the BLM the 

proposed maximum anticipated injection pressure for the stimulation. This information is 

needed by the BLM to verify that the maximum allowable injection pressure will not be 

exceeded at any stage of the well stimulation operation.

Proposed section 3162.3-3(c)(5)(iv) would require the operator to submit to the BLM the 

estimated or calculated fracture length and height anticipated as a result of the stimulation, so 

that the BLM can verify that the intended effects of the well stimulation operation will remain 

confined to the petroleum-bearing rock layers and will not have unintended consequences on 

other rock layers, such as aquifers. 

Proposed section 3162.3-3(c)(6) would require the operator to provide information 

pertaining to the handling of recovered fluids that will be used for the stimulation activities for 

approval. This information is being requested so that the BLM has all necessary information 

regarding chemicals being used in the event that the information is needed to help protect health 

and safety or to prevent unnecessary or undue degradation of the public lands.

Proposed section 3162.3-3(c)(6)(i) would require the operator to submit to the BLM an 

estimate of the volume of fluid to be recovered during flow back, swabbing, and recovery from 

production facility vessels. This information is required to ensure that the facilities needed to 

process or contain the estimated volume of fluid will be available on location. 

Proposed section 3162.3-3(c)(6)(ii) would require the operator to submit to the BLM the 

proposed methods of managing the recovered fluids. This information is needed to ensure that 

the handling methods will adequately protect of public health and safety.
16

Proposed section 3162.3-3(c)(6)(iii) would require the operator to submit to the BLM a 

description of the proposed disposal method of the recovered fluids. This is currently required 

by existing BLM regulations (i.e., Onshore Order Number 7, Disposal of Produced Water, (58 

FR 47354). This information is requested so that the BLM has all necessary information 

regarding disposal of chemicals used in the event it is needed to protect the environment and 

human health and safety and to prevent unnecessary or undue degradation of the public lands. 

The BLM specifically requests comments on whether the operator should be required to submit 

as part of the Sundry Notice application additional information about how it will dispose of 

waste streams not specifically addressed in this proposal.

Proposed section 3162.3-3(c)(7) would require the operator to provide, at the request of 

the BLM, additional information pertaining to any facet of the well stimulation proposal. For 

example, the BLM may require new or different tests or logs in cases where the original 

information submitted was inadequate, out of date, or incomplete. Any new information that the 

BLM may request will be limited to information necessary for the BLM to ensure that operations 

are consistent with applicable laws and regulation. Such information may include, but is not 

limited to, tabular or graphical results of a mechanical integrity test, the results of logs run, the 

results of tests showing the total dissolved solids in water proposed to be used as the base fluid, 

and the name of the contractor performing the stimulation. This provision would allow the BLM 

to obtain additional information about the proposed well stimulation activities. For example, 

after initial cementing activities, an operator may be asked to perforate the well casing and 

squeeze cement into the areas with inadequate cement bonding. In this case, the BLM may ask 

for additional information to show that the corrective action was successful and to ensure that the 

corrective work addressed any cement bonding deficiencies. The BLM wants to ensure that any 

additional information requested under this provision is the least burdensome to operators as 

possible while still accomplishing the goal of protecting the public lands and resources; 

therefore, the BLM is specifically requesting public comment on how this may be best achieved. 

Proposed section 3162.3-3(d) would require the operator to perform a successful 

mechanical integrity test before beginning well stimulation operations. This requirement is 

necessary to help ensure the integrity of the wellbore under anticipated maximum pressures 

during well stimulation operations. 
17

Proposed section 3162.3-3(d)(1) would require the mechanical integrity test to emulate 

the pressure conditions that would be seen in the proposed stimulation process. This test would 

show that the casing is strong enough to protect water and other subsurface resources during well 

stimulation activities.

The proposed section 3162.3-3(d)(2) would establish the engineering criteria for using a 

fracturing string as a technique during well stimulation. The requirement to be 100 feet below 

the cement top would be imposed to ensure that the production or intermediate casing is 

surrounded by a competent cement sheath as required by Onshore Order Number 2. The 100 

foot requirement is required by some state statutes (e.g., Montana Board of Oil and Gas 

Conservation, section 36.22.1106, Hydraulic Fracturing) and is a generally accepted standard in 

the industry. Testing would emulate the pressure conditions that would be seen in the proposed 

stimulation process in order to ensure that the casing used in the well would be robust enough to 

handle the pressures. 

Proposed section 3162.3-3(d)(3) would require the use of the pressure test time 

requirement of holding pressure for 30 minutes with no more than 10 percent pressure loss. This 

requirement is the same standard applied in Onshore Order Number 2, Drilling, (53 FR 46790) 

Section III.B.h., to confirm the mechanical integrity of the casing. This language does not set a 

new standard in the BLM’s regulations. This test, together with the other proposed 

requirements, would demonstrate if the casing is strong enough to protect water and other 

subsurface resources during well stimulation activities. The BLM believes that all of these tests 

are important to show that reasonable precautions have been taken to ensure the protection of 

other resources during well stimulation activities. 

Proposed section 3162.3-3(e)(1) would require the operator to continuously monitor and 

record the pressure(s) during the well stimulation operation. The pressure during the stimulation 

should be contained in the string through which the stimulation is being pumped. Unexpected 

changes in the monitored and recorded pressure(s) would provide an early indication of the 

possibility that well integrity has been compromised. This information is needed by the BLM to 

ensure that well stimulation activities are conducted as designed. This information would also 

show that stimulation fluids are going to the formation for which they were intended.

Proposed section 3162.3-3(e)(2) would require the operator to orally notify the BLM as 

soon as possible, but no later than 24 hours following the incident, if during the stimulation 
18

operation the annulus pressure increases by more than 500 pounds per square inch over the 

annulus pressure immediately preceding the stimulation. Within 15 days after the occurrence, 

the operator must submit a Subsequent Report Sundry Notice (Form 3160-5, Sundry Notices and 

Report on Wells) to the BLM containing all details pertaining to the incident, including 

corrective actions taken. This information is needed by the BLM to ensure that stimulation 

fluids are going into the formation for which they were designed. The BLM also needs to obtain 

reasonable assurance that other resources are adequately protected. An increase of pressure in 

the annulus of this amount could indicate that the casing had been breached during well 

stimulation. Consistent with the BLM’s Onshore Order Number 2, Drilling Operations, the 

operator must repair the casing should a breach occur. 

Proposed section 3162.3-3(f) would require the operator to store recovered fluids in tanks 

or lined pits. This provision grants flexibility for the operator to choose using either a lined pit 

or a storage tank, whichever the operator determines is the least burdensome or costly option for 

the storage of flowback fluid. The BLM is proposing this requirement because flowback fluids 

could contain hydrocarbons from the formation and could also contain additives and other 

components that might degrade surface and ground water if they were to be released without 

treatment. This provision is consistent with existing industry practice and American Petroleum 

Institute (API) recommendations for handling completion fluids (including hydraulic fracturing 

fluids) (see Section 6.1.6 of API Recommended Practice 51R, Environmental Protection for 

Onshore Oil and Gas Production Operations and Leases, First Edition, July 2009). Section 

302(b) of the Federal Land Policy and Management Act (43 U.S.C. 1732(b)) states that “In 

managing the public lands, the Secretary shall, by regulation or otherwise, take any action 

necessary to prevent unnecessary or undue degradation of the public lands.” In addition, existing 

BLM regulations at 43 CFR 3161.2 requires that “all operations be conducted in a manner which 

protects other natural resources and the environmental quality.” Because the use of lined pits or 

tanks for the storage of recovered fluids are methods that best and reasonably protect the public 

lands from spills or leaks of recovered fluids, the BLM believes that this provision is in keeping 

with FLPMA’s mandate to prevent unnecessary or undue degradation of the public lands and the 

BLM regulation’s requirement to protect environmental quality. 

Additional conditions of approval for the handling of flowback water may be placed on 

the project by the BLM if needed to ensure protection of the environment and other resources. 
19

The BLM specifically requests comments on whether this rule should impose additional 

requirements that would require tanks or lined pits for drilling fluids and any other fluids 

associated with well stimulation operations. The BLM recognizes the ongoing efforts of states to 

regulate hydraulic fracturing operations. In implementing this rule, the BLM intends to avoid 

duplication of existing state requirements and will continue to engage states in cooperative 

efforts to avoid duplication. Please comment on whether this proposed provision would be 

duplicative of provisions of state rules and whether it is unnecessarily burdensome. 

Proposed section 3162.3-3(g) would require the operator to submit to the BLM the postoperation data on a Subsequent Report Sundry Notice (Form 3160-5, Sundry Notices and Report 

on Wells) following the completion of the stimulation activities. The BLM would determine if

the well stimulation operation was conducted as approved. This information would be retained 

by the BLM as part of the individual well record and would be available for use when the well 

has been depleted and the plugging of the well is being designed.

Proposed section 3162.3-3(g)(1) would require reporting of the actual measured depth to 

the perforations and open hole interval. This information identifies the producing interval of the 

well and will be available for use when the well has been depleted and plugging of the well is 

being designed. Specific information as to the actual source of water, including location of the 

water being used as the base fluid, is required because the BLM needs the information to 

determine the impacts associated with operations and the need for any mitigation applicable to 

Federal and Indian lands.

Proposed section 3162.3-3(g)(2) would require the operator to submit to the BLM the 

actual total volume of fluid used, including water, proppants, chemicals, and any other fluid used 

in the stimulation(s) in order for the BLM to maintain a record of the stimulation operation as 

actually performed. 

Proposed section 3162.3-3(g)(3) would require the operator to submit to the BLM a 

report of the surface pressure at the end of each stage pumped and the rate at which the fluid was 

pumped at the completion of each stage (i.e., just prior to shutting down the pumps). In addition 

to the information provided for the individual stages, the pressure values for each flush stage 

must also be included. This information is needed by the BLM for it to ensure that the maximum 

allowable pressure was not exceeded at any stage of the well stimulation operation.
20

Proposed sections 3162.3-3(g)(4) and (5) would require the operator to identify to the 

BLM the stimulation fluid by additive trade name and additive purpose, the Chemical Abstracts 

Service Registry Number, and the percent mass of each ingredient used in the stimulation 

operation. This information is needed in order for the BLM to maintain a record of the 

stimulation operation as performed. The information is being required in a format that does not 

link additives (required by 3162.3-3(g)(4)) to chemical composition of the materials (required by 

3162.3-3(g)(5)) to minimize the risk of disclosure of any formulas of additives. This approach is 

similar to the one the State of Colorado adopted in 2011 (Colorado Oil and Gas Conservation 

Commission Rule 205A.b2.ix – xii). The BLM intends to place this information on a public web 

site and is working with the Ground Water Protection Council in an effort to integrate this 

information into the existing website known as FracFocus.org. The disclosure of the fluids used 

in hydraulic fracturing would only be required after the fracturing operation has taken place.

Proposed section 3162.3-3(g)(6) would require the actual, estimated, or calculated 

fracture length and height of the stimulation(s) to be reported to the BLM so that it can verify 

that the intended effects of the well stimulation operation remain confined to the petroleumbearing rock layers and will not have unintended consequences on other rock layers or aquifers. 

This section would require the operator to show that the well stimulation activity was 

successfully implemented as designed and that the integrity of the well was maintained during 

stimulation. 

Proposed section 3162.3-3(g)(7) would allow the operator flexibility to report online the 

information listed in proposed sections 3162.3-3(g)(1) through 3162.3-3(g)(6) by attaching a 

copy of the service company contractor’s job log or report, provided the information required is 

adequately addressed. The operator is responsible for ensuring the accuracy of any information 

provided to the BLM, even if originally drafted by a third party.

Proposed section 3162.3-3(g)(8), would require operators to certify they have complied 

with all applicable Federal, state, tribal, and local laws, rules, and regulations pertaining to the 

stimulation fluids that were actually used during well stimulation operations. The proposed 

section would also require that the operator certify that it has complied with all necessary permit 

and notice requirements. This information would be retained by the BLM as part of the well 

record and be available for use when the well has been depleted and closure of the well is being 
21

designed. The information is also needed for the BLM to fulfill its obligation to prevent 

unnecessary or undue degradation of the public land.

Proposed section 3162.3-3(g)(9) would require operators to certify that wellbore integrity 

was maintained throughout the operation. This information is needed because the BLM has a 

mandate to protect human health and safety and prevent contamination of the environment.

Proposed section 3162.3-3(g)(10) would require the operator to provide information 

describing the handling of the fluids used for the stimulation activities, flow-back fluids, and 

produced water. The operator must also report how it handled those fluids after operations were 

completed. 

Proposed section 3162.3-3(g)(10)(i) would require the operator to report the volume of 

fluid recovered during flow back, swabbing, or recovery from production facility vessels. 

Proposed section 3162.3-3(g)(10)(ii) would require the operator to report the methods of 

managing the recovered fluids. 

Proposed section 3162.3-3(g)(10)(iii) would require the operator to report the disposal 

method of the recovered fluids. This section also makes it clear that the fluid disposal methods 

must be consistent with Onshore Order Number 7, Disposal of Produced Water (58 FR 47353). 

This information is needed so that the BLM can help protect human health and safety and 

prevent the contamination of the environment. The BLM also needs to confirm that the disposal 

methods used are those that were approved and conform to the regulations.

Proposed section 3162.3-3(g)(11) would require the operator to submit documentation 

and an explanation if the actual operations deviated from the approved plan. Understanding the 

complexities of well stimulation, the BLM expects there to be slight differences between the 

proposed plan and the actual operation.

Proposed sections 3162.3-3(h) and (i) would notify the operator of procedures it needs to 

follow to identify information required to be submitted under this section that the operator 

believes to be exempt, by law, from public disclosure. If the operator fails to specifically 

identify information as exempt from disclosure by Federal law, the BLM will release that 

information. The BLM may also release information which the operator has marked as exempt if 

the BLM determines that public release is not prohibited by Federal law after providing the 

operator with no fewer than 10 business days’ notice of the determination. All other information 

submitted by the operator will become a matter of public record. 
22

Proposed section 3162.3-3(j) would provide the operator with a process for requesting a 

variance from the minimum standards of this regulation. Variances apply only to operational 

activities and do not apply to the actual approval process. The proposed regulation would make 

clear that the BLM has the right to rescind a variance or modify any condition of approval due to 

changes in Federal law, technology, regulation, field operations, noncompliance, or other 

reasons. The BLM must make a determination that the variance request meets or exceeds the 

objectives of the regulation. For example, an operator could request a variance from the 

requirements of proposed section 3162.3-3(c)(2) that it submit cement bond logs to prove that 

the occurrences of usable water have been isolated to protect them from contamination. The 

BLM could grant a variance to allow for the use of logs other than cement bond logs if it was 

satisfied that the alternative logs would meet or exceed the objectives of section (c)(2). This 

variance provision is consistent with existing BLM regulation such as Onshore Order Number 1 

(see section X. of Onshore Oil and Gas Operations; Federal and Indian Oil and Gas Leases; 

Onshore Oil and Gas Order Number 1, Approval of Operations (72 FR 10308, 10337).

Revised section 3162.5-2(d) would remove the references to fresh water and remove the 

phrase “containing 5,000 ppm or less of dissolved solids.” This revision would require the 

operator to isolate all usable water. This language does not set a new standard in the BLM’s 

regulations. Since 1988, Onshore Order Number 2, Drilling Operations, (53 FR 46790) Section 

II.Y. has defined usable water and Onshore Order Number 2, Drilling Operations, Section III.B.

has required the operator to “protect and/or isolate all usable water zones.” Section 3162.5(d) 

was not revised when Onshore Order Number 2, Drilling Operations, was promulgated, which 

has led to some confusion in implementing and interpreting the regulations.

2.3c Alternative Approaches

Alternative 1: Removal of Requirement to Line Pits when Operators Use Pits to Store Fracturing 

Fluids

In addition to the preferred approach, the BLM also considered an alternative to the 

proposed regulation which would remove the requirement for operators to use lined pits if they 

choose to use pits to store hydraulic fracturing fluids. This alternative was considered since the 

percentage of operators who use pits is expected to be lower, relative to the number of operators 

using storage tanks. Results of this alternative are presented in Table 4 and Table 5.
23

Other Alternative Approaches Considered

The BLM considered alternatives to direct regulation. Executive Order 13563 reaffirms 

the principles of Executive Order 12866 and requires that agencies, among other things, “identify 

and assess available alternatives to direct regulation, including providing economic incentives to 

encourage the desired behavior, such as user fees or marketable permits, or providing 

information upon which choices can be made by the public.” 

The use of economic incentives, such as user fees or marketable permits, is not a good 

option for this particular subject area. User fees are monies paid to the government to recover 

the costs of providing the regulatory good or service or for access to the resource. Marketable 

permits provide efficiencies when the compliance costs vary by producers, such that there are 

efficiency gains in having certain producers attain more of the emissions reductions, but be 

compensated otherwise, through the sale of pollution allowances to other producers where 

reductions are more costly than the price of a permit. This is not the case with the requirements 

considered in the proposed action and alternatives. The unit costs of the requirements do not 

vary significantly across wells or producers. Also, a unit of potential environmental degradation 

and remediation costs are not uniform across wells, events, and geographic areas (unlike, for 

example, a ton of CO2 which disperses in the atmosphere).

The preferred approach promotes performance standards rather than design standards in 

its variance language. The BLM chose to include a provision that allows an operator to request a 

variance if it can attain the same standards established by the proposed regulation but in a 

different manner. The BLM would consider alternatives if an operator could show that intent

and requirements of the proposed rule would be met using an alternate approach. The variance 

request, like the sundry forms, would be subject to BLM approval. From an efficiency 

standpoint, variances are important because they allow operators to use technology or other 

improvements to meet requirements in a more efficient or cost effective manner. This analysis 

does not quantify the benefits or costs of this provision; however, the provision would likely 

increase the net benefits of the proposal by reducing the costs.

In the proposed approach, the BLM has provisions for disclosure of hydraulic fracturing 

fluids. This requirement is informational in nature, rather than direct regulation on the part of the 

BLM. OMB Circular A-4 describes informational measures as follows:
24

If intervention is contemplated to address a market failure that 

arises from inadequate or asymmetric information, informational 

remedies will often be preferred. Measures to improve the 

availability of information include government establishment of a 

standardized testing and rating system (the use of which could be 

mandatory or voluntary), mandatory disclosure requirements (e.g., 

by advertising, labeling, or enclosures), and government provision 

of information (e.g., by government publications, telephone 

hotlines, or public interest broadcast announcements). A regulatory 

measure to improve the availability of information, particularly 

about the concealed characteristics of products, provides 

consumers a greater choice than a mandatory product standard or 

ban.

Specific informational measures should be evaluated in terms 

of their benefits and costs. Some effects of informational measures 

are easily overlooked. The costs of a mandatory disclosure 

requirement for a consumer product will include not only the cost 

of gathering and communicating the required information, but also 

the loss of net benefits of any information displaced by the 

mandated information. The other costs also may include the effect 

of providing information that is ignored or misinterpreted, and 

inefficiencies arising from the incentive that mandatory disclosure 

may give to overinvest in a particular characteristic of a product or 

service.

Where information on the benefits and costs of alternative 

informational measures is insufficient to provide a clear choice 

between them, you should consider the least intrusive 

informational alternative sufficient to accomplish the regulatory 

objective. To correct an informational market failure it may be 

sufficient for government to establish a standardized testing and 

rating system without mandating its use, because competing firms 

that score well according to the system should thereby have an 

incentive to publicize the fact.

 
25

2.4 Federal and Indian Oil and Gas Leasing Activity

The BLM Oil and Gas Management program is one of the most important mineral leasing 

programs in the Federal government. There were 49,173 Federal oil and gas leases covering 

38,463,410 acres at the end of fiscal year (FY) 2011. For FY 2011, there were 90,452 producible 

and service drill holes and 96,606 producible and service completions on Federal leases.4

Table 1: Federal and Indian Oil and Gas Cases5

Producing Non-Producing

FY 2008

Federal Cases 19,215 5,200

Indian Cases 2,614 125

Total Cases 21,829 5,325

FY 2009

Federal Cases 19,409 4,081

Indian Cases 2,693 254

Total Cases 22,102 4,335

FY 2010

Federal Cases 19,995 3,523

Indian Cases 2,576 392

Total Cases 22,571 3,915

Source: BLM, Automated Fluid Mineral Support System (AFMSS), 

FY-2010 Inspection and Enforcement Strategy

Production accountability and revenue collection are now the responsibility of the DOI 

Office of Natural Resources Revenue (ONRR) though the figures cited below were originally 

reported by the Minerals Management Service or the Bureau of Ocean Energy Management, 

Regulation and Enforcement. For FY 2011, onshore Federal oil and gas leases produced about 

98 million barrels of oil, 2.97 billion Mcf of natural gas, 2.55 billion gallons of natural gas 

liquids, and approximately $2.7 billion in royalties. The production value of the oil and gas 

produced from public lands exceeded $23 billion. Oil and gas production from Indian leases was 

almost 20 million barrels of oil, 255 million Mcf of natural gas, and 143 million gallons of 

natural gas liquids, with a production value of $2.7 billion and generating royalties of $433

million.

 4 U.S. Department of the Interior, Bureau of Land Management, www.blm.gov, Oil and Gas Statistics. 5 An AFMSS case can be a lease, unit participating area, communitized agreement, or other agreement.
26

Table 2: Federal and Indian Oil and Gas Production and Royalties, Fiscal Year 2011

Sales Volume Sales Value

($MM)

Royalty

($MM)

Federal Leases

 Oil (bbl) 97,721,813 $8,374 $1,111

 Gas (Mcf) 2,974,916,041 $12,556 $1,360 

 NGL (Gal) 2,551,994,725 $2,474 $254

Subtotal $23,404 $2,725

Indian Leases

 Oil (bbl) 19,550,536 $1,571 $271

 Gas (Mcf) 255,401,453 $950 $145

 NGL (Gal) 143,404,729 $167 $18

Subtotal $2,687 $433

Source: ONRR, Federal Onshore Reported Royalty Revenue, Fiscal Year 2011 and American Indian 

Reported Royalty Revenue, Fiscal Year 2011

2.5 Industry Classifications

Most crude oil and natural gas entities are classified under North American Industry 

Classification System (NAICS) 211. This proposed rule directly affects entities classified within 

the Crude Petroleum and Natural Gas Extraction (211111), Natural Gas Liquid Extraction 

(211112), and the Drilling of Oil and Natural Gas Wells (213112) industries. Other industries 

include various distribution or transportation, storage, or support activities for oil and gas 

operations industries.

2.6 Unconventional Development

The proposed rule affects crude oil and natural gas producers conducting well stimulation 

operations. Well stimulations and hydraulic fracturing have grown increasing common in the 

United States over the past decade with the development of advanced drilling techniques, 

including horizontal drilling and sidetrack drilling. Horizontal drilling allows the production 

operation to reach a larger portion of the pay zone and ultimately recover more of the resource. 

For sidetrack drilling, operators drill horizontally off to the side of a plugged or abandoned 

vertical well. 

Figure 1 displays the North American shale plays, while Figure 2 shows the increasing 

share of consumption needs that shale gas is expected to meet in the future. 
27

Figure 1: North American Shale Plays, EIA

Figure 2: Expected Growth of Shale Gas

Source: Richard Newell, EIA. June 21, 2011. “Shale Gas and the Outlook for U.S. Natural Gas 

Markets and Global Gas Resources. Paris.
28

2.7 Well Stimulation Process

Well stimulation techniques, including hydraulic fracturing of oil and gas wells, are used 

by oil and gas producers to increase oil and natural gas volumes available to the Nation. After 

drilling into hydrocarbon bearing rocks, producers use hydraulic fracturing to increase the 

effective permeability of the oil and gas bearing strata and increase oil and gas production from 

the well. Hydraulic fracturing involves the injection of fluid under high pressure to create or 

enlarge fractures in the reservoir rocks. In the fracturing process, a “proppant” such as sand is

deposited in the fractures to keep the fractures from closing after the fracturing pressure is 

released. The proppant-filled fractures become conduits for fluid migration from the reservoir to 

the wellbore and are subsequently brought to the surface. Hydraulic fracturing allows 

hydrocarbons to move more freely into the well bore so that they can be brought to the surface 

for consumption. 

Water and sand often make up 98 to 99 percent of the fluid used in hydraulic fracturing. 

In addition, chemical additives are generally used. Chemicals serve many functions in hydraulic 

fracturing. Some chemicals may limit the growth of bacteria and others prevent corrosion of the 

well casing. Chemicals are used to ensure that the work is effective and efficient. The exact 

formulation of the fluid varies depending on the rock formations, the well, and the requirements 

of the operator.

The number of stimulated wells has steadily increased over the years as technology has 

improved. These improvements allow geologic formations that were once thought to be 

incapable of production to produce in commercial quantities.

An important component to the production of the resource and to environmental safety is 

the casing that encases the well bore. “Casing prevents contamination of groundwater from oil 

production, prevents water encroachment into the well, and also enhances the structural integrity 

of the hole, preventing collapse as it passes through weak rock or rock containing fluids.”6 

Figure 3 shows how surface casing and cement layers protect the aquifer.

 6 Downey, 107. Casing is important for oil and gas wells.
29

Figure 3: Horizontal Hydraulic Fracturing Operation

Source: API (2010). “Freeing Up Energy.”

2.8 Industry Guidelines on Well Construction and Integrity

The American Petroleum Institute (API) provides guidelines for well construction and 

integrity for hydraulic fracturing operations in the API Guidance Document HF1 (2009). Topics 

covered in the guidelines include but are not limited to general principles, protecting 

groundwater and the environment, casing guidance, and well logging and other testing. 

Well integrity is critical to protecting the environment and facilitating recovery of the 

resource. The guidance states, “Maintaining well integrity is a key design principle and design 

feature of all oil and gas production wells. Maintaining well integrity is essential for the two 

following reasons: 1) To isolate the internal conduit of the well from the surface and subsurface 

environment. This is critical in protecting the environment, including the groundwater, and in 
30

enabling well drilling and production; and 2) To isolate and contain the well’s produced fluid to 

a production conduit within the well.”7

Protecting Groundwater and the Environment

The combination of steel casing and cement sheaths protect groundwater by isolating the 

contents within the well from the groundwater aquifers. “The primary method used for 

protecting groundwater during drilling operations consists of drilling the wellbore through the 

groundwater aquifers, immediately installing a steel pipe (called casing), and cementing this steel 

pipe into place.... The steel casing protects the zones from material inside the wellbore during 

subsequent drilling operations and, in combination with other steel casing and cement sheaths 

that are subsequently installed, protects the groundwater with multiple layers of protection for 

the life of the well.”8

Casing Guidance and Well Logging

The surface casing protects the groundwater aquifers by isolating well fluids within the 

well. “The surface hole is typically drilled to a predetermined depth based on consideration of 

the deepest groundwater resources and pressure control requirements of subsequent drilling. The 

surface hole should be drilled using air, freshwater, or freshwater-based drilling fluid. The 

setting depth can be from a few hundred feet up to 2000 ft deep or more. The surface casing is 

usually set at a depth sufficient to ensure groundwater protection. State regulations dictate the 

minimal setting depth of surface casing, and the vast majority of states require the casing to be 

set below the deepest groundwater aquifer. At a minimum, it is recommended that surface 

casing be set at least 100 ft below the deepest USDW encountered while drilling the well. It is 

recommended that the surface casing be cemented from the bottom to the top, completely 

isolating groundwater aquifers.”9

Well logging is a common practice of operators and may be conducted multiple times 

while drilling a well. “Well logs are critical data gathering tools used in formation evaluation, 

well design, and construction. Also, various types of mechanical integrity and hydraulic pressure 

tests can be used to assess well integrity during the construction of the well.”10

 7 API (2009), pg. 1.

8 Ibid, pg. 2.

9 Ibid, pg. 11.

10 Ibid, pg. 8.
31

After cementing the casing, logs may be run within the well. A cement bond log “measures the 

presence of cement and the quality of the cement bond or seal between the casing and the 

formation.”11 Logs are important in “determining that the well drilling construction is adequate 

and achieves the desired design objectives.”12

Pressure Testing

The API recommends pressure testing on the surface casing. The proposed rule 

establishes that Mechanical Integrity Tests must be performed at specified pressures. This is 

consistent with API guidelines, which state, “After the surface casing cement has achieved the 

appropriate compressive strength and prior to drilling out, the surface casing should be pressure 

tested (commonly known as a casing pressure test). This test should be conducted at a pressure 

that will determine if the casing integrity is adequate to meet the well design and construction 

objectives.”13

 11 Ibid, pg. 9. 12 Ibid, pg. 10. 13 Ibid, pg. 11.
32

3. Estimating Benefits and Costs

3.1 Theoretical Framework

This analysis attempts to capture the potential benefits and costs that would result if the 

BLM implemented the proposed rule. As such, the current operating environment is the 

reference point from which the change is measured. Potential costs and benefits rely on the 

number of well stimulation events estimated to occur in the future on BLM-managed lands. 

Those estimates depend on a number of factors likely including, but not limited to, future oil and 

gas prices, the number of applications to drill, the number of wells completed, and the portion of 

wells that are stimulated.

The potential benefits of the proposed regulations include reduced surface and subsurface 

contamination. For the base case, where no action is taken, it is assumed that a certain number 

of well stimulation events may result in contamination and thus pose a cost to society. The 

proposed rule is designed to identify potential issues concerning wellbore integrity and other 

deficiencies in the design of well stimulation operations, thereby reducing the likelihood of 

contamination events. Because monetization of the reduction of risk associated with potential 

wellbore integrity is a difficult issue, this analysis is using avoided cost of remediation as a proxy 

value. An operator should identify potential issues with the wellbore once it runs and analyzes 

the results of the tests. If potential issues exist, the operator is likely to address the problem 

before submitting the NOI Sundry, rather than have its NOI Sundry disapproved. Requirements 

to address these issues are covered under BLM’s Onshore Order Number 1.

Estimating the benefits is uncertain and subject to assumptions about the number of 

deficiencies, likelihood of contamination if a deficiency was present, and extent of damage. One 

way to measure the benefits is by estimating the cost to internalize the contamination, which may 

include the restoring a source of drinking water or remediation of an aquifer. 

Under the proposed regulations, it is assumed that the contamination events assumed to 

occur in the base case would be avoided, and thus the remediation costs that would likewise be 

avoided. As such, the social benefit would be zero, but the change in social benefits from the 

base case to the proposed regulation scenario would be positive. The difference in costs and 

benefits from the base case to the proposed case represents the net benefits of the proposed rule.

The current regulations make a distinction between routine fracture jobs and nonroutine 

fracture jobs. However, the terms “routine” and “nonroutine” are not defined in 43 CFR 3162.3-
33

2 or anywhere else in BLM regulations, making this distinction functionally difficult to apply 

and confusing for both the agency and those attempting to comply with the regulations. The 

BLM estimates that about 20 percent of current well stimulations are considered “non-routine” 

for which the BLM receives a Notice of Intent Sundry prior to the stimulation operation. The 

proposed rule would require BLM approval for all well stimulation events. For each event, 

operators would obtain the BLM’s approval prior to the event and submit a Subsequent Report 

Sundry within 30 days of the event. In most cases, the operator may seek approval for the 

stimulation operation at the same time that it submits the APD. Other information would be 

required if an incident occurs during a fracturing operation or if the BLM determines that there is 

a need for additional information. 

Administrative costs include only the additional burden posed by the requirements. For 

operators, this burden includes the submission of forms and supporting documentation that are 

not currently required. The reporting requirements would also pose an additional burden on the 

BLM, since it would review an additional number of sundry forms and additional information 

per form. The efficiency of processing applications relies on operators submitting complete and 

adequate information. The BLM understands the time sensitive nature of oil and gas drilling and 

well completion activities and does not anticipate that the submittal of additional well 

stimulation-related information with APD applications will impact the timing of the approval of 

drilling permits. The BLM believes that the additional incremental information that would be 

required by this rule would be reviewed in conjunction with the APD and within the normal APD 

processing time frame. Also, the BLM anticipates that requests to conduct well stimulation 

activities on existing wells that have been in service more than five years will be reviewed 

promptly. The BLM understands that delays in approvals of operations can be costly to 

operators and the BLM intends to avoid delays whenever possible. However, as with any 

operational activity, there may be unforeseen circumstances that may on rare occasions delay 

approval of APDs. 

Particularly relevant to the disclosure requirement in the Subsequent Report Sundry, the 

BLM would not disclose any information that is propriety under Federal law. The protection of 

proprietary information is important so that a company’s trade secrets are not revealed to its 

competitors. Any information that is not proprietary is available for public disclosure. 

The proposed rule seeks to achieve benefits by making more information available to the 

public about the chemicals injected in well stimulation fluids, while protecting trade secrets. The 
34

information that would be submitted to the BLM under this section would generally be made 

available to the public. The proposed rule, however, would allow an operator to identify specific 

information that it believes is protected from disclosure by Federal law, and to substantiate those 

claims of exemption. Under existing law, the BLM may nonetheless make that information 

available to the public, but only if it determines that the information is not protected by Federal 

law, and provides not less than ten business days notice to the operator prior to releasing the 

information. 

Furthermore, the disclosure mechanism in the proposed rule would require a table of the 

additives by trade name and the purpose for which they are included in the well stimulation fluid. 

It would also require a separate table listing all the chemicals used by the Chemical Abstracts 

Service Registry Number. This design will inhibit reverse-engineering of specific additives. 

Operational costs include any additional logs, tests, or other procedures needed to submit 

all documents required as additional information that are not currently required. Depending on 

the well and the operator, these tests or other requirements may be currently conducted or 

practiced pursuant to other permits, general well testing, etc. For example, operators planning to 

conduct well stimulations on new wells are almost certainly expected to run MITs at the higher 

pressures specified in the proposed rule rather than the lower pressures specified in existing 

regulations. Thus, the requirements of the rule with regards to MITs on new wells should not 

pose any cost burden to operators.

There are other benefits that are difficult to quantify in monetary terms though they 

certainly exist. The disclosure requirement might encourage operators to use fewer chemicals in

the hydraulic fracturing fluid. The public would benefit from increased knowledge about the 

fluids used. Increased transparency is also likely to benefit scientists, state and Federal agencies, 

and other organizations that study the potential impacts of hydraulic fracturing operations. The 

BLM would have more information with which to make resource management decisions or 

respond to incidents. Furthermore, the numerical comparison of costs and benefits does not 

include the benefits to water users from avoiding harms that could not be compensated by 

alternate water supplies.

The analysis further explores an alternative which would not require operators to line pits 

when they are used to store fracturing fluid. Operators do not typically use pits to store hydraulic 

fracturing fluids either prior to or after a well stimulation event. Rather, operators typically store 

the fluids in storage tanks, especially with deeper wells that require more water for the fracturing 
35

process. Examination of this alternative assumes that the removal of these requirements would 

result in potential contamination and pose a social cost. 

3.2 Methodology

This analysis presents costs and benefits expected to occur over the next 10 years, from 

2013 to 2022. This period of analysis was chosen because 10 years is the length of the primary 

lease term on BLM-managed lands. Net benefits are discounted using 7 and 3 percent discount 

rates. The analysis presents a range of expected outcomes since the number of well stimulation 

events occurring in the future is highly variable and subject to future conditions. 

The proposed regulation is designed to reduce the risk that well stimulation events may 

pose to the environment. Any contamination event that occurs is expected to require 

remediation. Since the remediation costs are uncertain, the analysis makes assumptions about 

remediation costs which may underestimate the true costs of remediation. The analysis assumes 

two scenarios: a low remediation cost – low environmental risk scenario and a high remediation 

cost – high environmental risk scenario. The benefits, while representing the value of risk 

reduction, will underestimate or overestimate the true benefits if the true risk of well stimulation 

operations varies from the assumptions. 

3.2a Data

The number of well stimulations expected to occur on BLM-managed lands is estimated 

as a percent of new well completions, which in turn is estimated using the historical relationship 

between well completions and approved APDs. The number of approved APDs is estimated 

using EIA commodity price projections in the Annual Energy Outlook (AEO) 2012 Early 

Release Overview. 

Private wages are based on Bureau of Labor Statistics (BLS) data. The base private wage 

is calculated using the average 2010 hourly wage of first-line supervisors/managers of 

construction trades and extraction workers14 at 80% and the average hourly wage of executive 

secretaries and administrative assistants15 at 20%. BLM wages are based on Office of Personnel 

Management (OPM) data for a GS grade 12, step 1 with no locality adjustment.

Costs for the MITs are estimated for older wells that would require MITs. New wells

should already have MITs performed under existing regulations. Although this proposed rule 

 14 Mining, Quarrying, and Oil and Gas Extraction (NAICS code 21). 15 Administrative and Support Services (NAICS 561).
36

requires testing at higher pressure, this poses no additional cost burden to operators. Service 

costs for MITs were quoted from industry sources. 

Costs for running CBLs on surface casings are estimated for wells that are assumed to 

require them. Currently, operators do not typically run CBLs on surface casings. The costs of 

running a CBL vary widely depending on the distance that the service firm must travel to the 

well site. Service costs were quoted from industry sources.

16 

The proposed rule requires operators to use storage tanks or lined pits to hold the 

flowback of fracturing fluids during the fracturing operation. The majority of producers, 

especially those on deeper wells where larger volumes of water are needed, currently use storage 

tanks to hold fracturing fluids before and after the fracturing process. The proposed rule would 

not pose a burden to those producers. Some producers on smaller fracturing jobs may use a 

reserve pit, typically used to hold drilling mud during drilling operations, to hold fracturing fluid 

as well, but in general these pits are too small to hold the volume of fluid used for fracturing. 

The requirements of the proposed rule would require these operators to use a lined pit or a 

storage tank. Service costs were quoted from industry sources.

17

Remediation actions may vary widely depending on the contamination event. For the 

low remediation cost – low risk scenario, the analysis uses the cost of drilling a new water well 

as a proxy for the cost of remediating a subsurface contamination.18 For the high remediation 

cost – high risk scenario, the analysis uses an assumed cost that would proxy for the remediation 

of the contaminated aquifer. The Federal Remediation Technologies Roundtable makes a 

number of case studies available on its website.19 It provides a description of the contamination 

event and source, and remediation efforts and costs. This analysis assumes a cost of $1M to 

remediate contamination to an aquifer. Estimates of total remediation costs also vary depending 

on the number of contamination events, which rely on assumptions made about the likelihood of 

contamination occurring on the number of wells where the requirements or tests are not 

conducted. 

Table 3 lists the assumptions used in the analysis. 

 16 The average cost of an MIT and CBL is estimated to be $10,000 and $9,000, respectively, although the ranges of 

prices that BLM was quoted varied.

17 Estimated at $0.24 per square foot of lining. The amount of lining required varies by well and the cost of lining 

depends on the thickness and other properties that vary by the use of the pit.

18 The BLM received estimates ranging from $35,000 to $50,000, depending on the depth.

19 http://www.frtr.gov/
37

Table 3: List of Base Year Assumptions

Input

Low Remediation 

Costs – Low 

Environmental 

Risk

High Remediation 

Costs – High 

Environmental 

Risk

Proportion of wells that are stimulated 0.900 0.900

Proportion of wells needing MIT 0.200 0.200

Proportion of wells needing CBL on the surface casing 0.975 0.975

Proportion of wells where tests would reveal subsurface risk 0.010 0.050

Likelihood of subsurface contamination if subsurface risk 0.010 0.050

Avg remediation of subsurface contamination 42,500 1,000,000

Proportion of wells needing storage tank or lined pit 0.150 0.150

Proportion of wells where tanks or lining would remove surface risk 1.000 1.000

Likelihood of surface contamination if surface risk 1.000 1.000

Avg remediation of surface contamination 25,000 75,000

Avg incremental cost per MIT 0.000 0.000

Avg cost per MIT 10,000 10,000

Avg cost per CBL 9,000 9,000

Avg cost of lining pit 6,000 6,000

Priv - Percent of current HF operations that are "non-routine" 0.200 0.200

Priv - Percent of current HF operations that provide SR Sundry 1.000 1.000

Priv - Hours to prepare per NOI Sundry 8.000 8.000

Priv - Current hours to prepare NOI Sundry 8.000 8.000

Priv - Hours to prepare per SR Sundry 8.000 8.000

Priv - Current hours to prepare SR Sundry 8.000 8.000

Priv - Hourly wage 30.950 30.950

BLM - Hours to review per NOI Sundry 5.000 5.000

BLM - current hrs to review NOI 2.000 2.000

BLM - Hours to review per SR Sundry 3.000 3.000

BLM - current hrs to review SR 1.000 1.000

BLM – Hours to webpost per disclosure 1.000 1.000

BLM - Hourly wage 28.450 28.450
38

3.2b Discounted Present Value

There is a time dimension to estimates of potential benefits and costs. The potential 

events described, if they occur at all, may be in the distant future. The further in the future the 

benefits and costs are expected to occur, the smaller the present value associated with the stream 

of costs and benefits. As such, future costs and benefits must be discounted.20 The discount 

factor is then used to convert the stream of costs and benefits into “present discounted values.” 

When the estimated benefits and costs have been discounted, they can be added to determine the 

overall value of net benefits.

The OMB’s basic guidance on the appropriate discount rate to use is provided in OMB 

Circular A-94. The OMB’s Circular A-94 states that a real discount rate of 7 percent should be 

used as a base-case for regulatory analysis. The OMB considers the 7 percent rate as an estimate 

of the average before-tax rate of return to private capital in the U.S. economy. It is a broad 

measure that reflects the returns to real estate and small business capital as well as corporate 

capital. It approximates the opportunity cost of capital, and it is the appropriate discount rate 

whenever the main effect of a regulation is to displace or alter the use of capital in the private 

sector. 

OMB Circular A-4 also states that a 3 percent discount rate should be used for regulatory 

analyses and provides an explanation of the use of the discount rate as follows: “The effects of 

regulation do not always fall exclusively or primarily on the allocation of capital. When 

regulation primarily and directly affects private consumption (e.g., through higher consumer 

prices for goods and services), a lower discount rate is appropriate. The alternative most often 

used is sometimes called the ‘social rate of time preference.’ This simply means the rate at which 

"society" discounts future consumption flows to their present value.”

3.2c Uncertainty

The benefits and costs provided in this analysis are indeed estimates and come with 

uncertainty. Estimated costs and benefits rely on the number of well stimulation events 

occurring in future years and those estimates are uncertain. This analysis estimates the number 

of future well stimulation events using regression models and future projections of commodity 

prices. 

 20 Discount factor = 1/(1+ r)

t where r is the discount rate and t is time measured in years during which benefits and

costs are expected to occur. 
39

Assuming the number of well stimulation events is known, though administrative costs 

are more easily estimated, the operational costs required by producers to comply with the 

regulations are subject to assumptions about the number of wells that would require such 

expenditures.

Further uncertainty lies in the estimation of remediation costs. For the purposes of this 

analysis, a range of assumed average costs of remediating both subsurface and surface 

contaminations are used. This assumption may be too low or too high in the real world, 

depending on the location, severity, consequences, duration of the contamination, and if a causal 

link between the source and contamination can be made. 

This analysis does not quantify other benefits that are undoubtedly relevant, such as the 

benefit that disclosing the components of fracturing fluids will have on the public health 

research. It is also uncertain what additional benefits, if any, would result from the disclosure 

requirements, for instance, if companies find substitutes for the chemicals in the fracturing fluids.
40

4. Results

This section presents the results of the analysis. Table 4 and Table 5 show a summary of 

the changes in benefits, costs, and net benefits, expected to occur as a result of the proposed 

regulations or the alternatives examined over the baseline scenario. To annualize the change in 

benefits, costs, and net benefits of the proposal and alternatives, the analysis calculates the 

annualized value (AV) as AV = [PDV * r]/[1 - (1+r)

-10], where PDV is the present discounted 

value of the benefits, costs, or net benefits over 10 years and “r” is the discount rate. All results 

are presented in 2012 dollars.

Table 4: Annualized Value of Net Benefits of the Proposed Regulations and Alternatives

(7% Discount Rate; $MM)

Low Remediation Cost/ 

Low Environmental Risk

High Remediation Cost/ 

High Environmental Risk

Proposed Regulations

Social Benefits 11.70 13.79 42.67 50.27

Costs 37.34 43.99 37.34 43.99

Net Benefits -25.63 -30.20 5.33 6.28

Alternative 1: No Requirement for Lined Pits

Social Benefits 0.01 0.02 7.60 8.95

Costs 34.68 40.86 34.68 40.86

Net Benefits -34.67 -40.84 -27.08 -31.90

Estimated Number of Well 

Stimulations Low High Low High

 Total 31,328 37,015 31,328 37,015

 Annual Average 3,133 3,701 3,133 3,701
41

Table 5: Annualized Value of Net Benefits of the Proposed Regulations and Alternatives

(3% Discount Rate; $MM)

Low Remediation Cost/ 

Low Environmental Risk

High Remediation Cost/ 

High Environmental Risk

Proposed Regulations

Social Benefits 11.74 13.85 42.79 50.27

Costs 37.44 44.18 37.44 44.18

Net Benefits -25.70 -30.33 5.35 6.31

Alternative 1: No Requirement for Lined Pits

Social Benefits 0.01 0.02 7.62 8.99

Costs 34.77 41.04 34.77 41.04

Net Benefits -34.76 -41.02 -27.15 -32.04

Estimated Number of Well 

Stimulations Low High Low High

 Total 31,328 37,015 31,328 37,015

 Annual Average 3,133 3,701 3,133 3,701

4.2 Proposed Regulations (Preferred Option)

Results contained in this section represent the estimates for the preferred regulatory 

action described in this report in Section 2.3.

Benefits

Under the proposed regulations, it is assumed that the regulations would remove much of 

the risk associated with potential wellbore integrity issues and unlined pits. The change in social 

benefits from the baseline scenario is positive. If you assume that there is low environmental 

risk posed by wellbore integrity issues and storage of hydraulic fracturing fluids in unlined pits 

and the costs of surface and subsurface remediation is low (on the range assumed), then the 

change in social benefit as a result of the proposed regulation is positive and ranges between 

$11.70MM and $13.79MM per year using a discount rate of 7% and between $11.74MM and 

$13.85MM per year using a discount rate of 3%. If you assume that environmental risks are high 

and remediation costs are high (on the range assumed), then the social benefits of the proposed 

regulation is positive and ranges between $42.67MM and $50.27MM per year using a discount 

rate of 7% and between $42.79MM and $50.49MM per year using a discount rate of 3%. Tables 

7 and 8 (below) show the annual change in benefits over the baseline.
42

Note that the figures for the estimated benefits of the proposed rule do not include such 

benefits as avoiding harm to water users that cannot be compensated by later providing 

alternative water sources. The increase in information about additives could aid water users 

when they consider the potential effects of well stimulation operations and constituent chemicals.

Costs

The costs include both costs to the industry and the BLM under this alternative. Costs 

include operational tests that demonstrate wellbore integrity and those associated with lining 

open pits in the instances where operators use pits instead of storage tanks. 

The change in costs over the baseline ranges between $37.34MM and $43.99MM per 

year using a discount rate of 7% and between $37.44MM and $44.18MM per year using a 

discount rate of 3%, assuming low remediation costs and low environmental risks. The change 

in costs ranges between $37.34MM and $43.99MM per year using a discount rate of 7% and 

between $37.44MM and $44.18MM per year using a discount rate of 3%, assuming high 

remediation costs and high environmental risks. Tables 7 and 8 (below) show the annual change 

in costs over the baseline. Table 9 shows the annual administrative costs associated with the 

proposed regulation.

Net Benefits

The change in net benefits for the proposed regulations varies depending on the amount 

of environmental risk associated with wellbore integrity issues and unlined pits and the level of 

remediation costs associated with contamination events. Assuming low remediation costs and 

low environmental risks, the change in net benefits from the baseline is negative and ranges from 

-$25.63MM and -$30.20MM per year using a discount rate of 7% and between -$25.70MM and

-$30.33MM per year using a discount rate of 3%. Assuming high remediation costs and high 

environmental risks, the change in net benefits is positive and ranges between $5.33MM and 

$6.28MM per year using a discount rate of 7% and between $5.35MM and $6.31MM per year 

using a discount rate of 3%. Tables 7 and 8 (below) show the annual change in net benefits over 

the baseline scenario.

Given the assumptions made and the fact that certain benefits were not quantified, the 

range of estimated outcomes could underestimate the actual net benefits, meaning, where net 

benefits are estimated to be negative, the net benefits would be greater (or less negative). 

This analysis also does not capture the potential benefits associated with the disclosure of 

fracturing fluids. For example, disclosure might encourage operators to use fewer or safer 
43

chemicals in the hydraulic fracturing fluid. The public would benefit from increased knowledge 

about the fluids used. This transparency is also likely to benefit scientists, state and Federal 

agencies, and other organizations that study the potential impacts of well stimulation operations. 

The BLM would be able to make more informed resource decisions and respond effectively to 

events where environmental resources have been compromised.

Also, the variance language might also enable operators to reduce costs, in which case, 

these estimates may overestimate the actual costs and underestimate the change in net benefits. 

It should be noted that the low cost and risk scenario results in negative net benefits while 

the high cost and risk scenario results in positive net benefits. The primary difference is not a 

result of the administrative or operational costs changing between the scenarios. Instead, the 

difference is due to the valuation of social benefits. If you assume the risk of contamination is 

greater and the costs of remediation are higher, then the change in benefits of the proposed rule 

would be greater and offset the change in compliance costs. 

Table 6 illustrates how the annual costs per well stimulation do not vary greatly between 

the cost and risk scenarios and how the benefits do. The average annual cost per well (including 

administrative and operational costs) is estimated to be about $11,833. However, the average 

annual benefit ranges more widely, between $3,754 and $13,688. The uncertainty about risk and 

damages causes this variability. The net benefit ranges from -$8,079 to $1,855 on a per well 

stimulation basis.

Table 6: Annual Average Change in Benefits, Costs, and Net Benefits Per Well Stimulation

Low Remediation Cost - Low Environmental Risk

(Assumed Subsurface Remediation Action is Drilling a 

New Water Well)

Benefits 3,754

Costs 11,833

Net Benefits -8,079

High Remediation Cost - High Environmental Risk

(Assumed Subsurface Remediation Action is to 

Remediate the Aquifer)

Benefits 13,688

Costs 11,833

Net Benefits 1,855
44

Table 7: Change in Benefits, Costs, and Net Benefits of the Proposed Regulations from the Baseline Scenario ($MM)

High Remediation Cost - High Environmental Risk

Low EIA Price Scenario 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 Total AV

Benefits - Undiscounted 41.60 41.61 41.92 41.98 42.37 42.91 43.36 43.59 44.25 45.20

Benefits - 7% Discount 38.88 36.34 34.22 32.03 30.21 28.60 27.00 25.37 24.07 22.98 299.70 42.67

Benefits - 3% Discount 40.39 39.22 38.36 37.30 36.55 35.94 35.25 34.41 33.92 33.63 364.98 42.79

Costs - Undiscounted 36.40 36.41 36.68 36.73 37.07 37.55 37.94 38.14 38.72 39.55

Costs - 7% Discount 34.02 31.80 29.94 28.02 26.43 25.02 23.63 22.20 21.06 20.11 262.23 37.34

Costs - 3% Discount 35.34 34.32 33.57 32.64 31.98 31.45 30.85 30.11 29.68 29.43 319.36 37.44

Net Benefits - Undiscounted 5.20 5.20 5.24 5.25 5.30 5.36 5.42 5.45 5.53 5.65

Net Benefits - 7% Discount 4.86 4.54 4.28 4.00 3.78 3.57 3.37 3.17 3.01 2.87 37.46 5.33

Net Benefits - 3% Discount 5.05 4.90 4.80 4.66 4.57 4.49 4.41 4.30 4.24 4.20 45.62 5.35

Reference EIA Price Scenario 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 Total AV

Benefits - Undiscounted 47.12 48.14 49.25 49.70 50.48 51.17 51.75 52.12 52.91 53.99

Benefits - 7% Discount 44.04 42.05 40.20 37.92 35.99 34.10 32.23 30.33 28.78 27.44 353.09 50.27

Benefits - 3% Discount 45.75 45.38 45.07 44.16 43.55 42.85 42.08 41.14 40.55 40.17 430.71 50.49

Costs - Undiscounted 41.23 42.13 43.10 43.49 44.17 44.77 45.28 45.60 46.30 47.24

Costs - 7% Discount 38.53 36.79 35.18 33.18 31.49 29.83 28.20 26.54 25.18 24.01 308.95 43.99

Costs - 3% Discount 40.03 39.71 39.44 38.64 38.10 37.50 36.82 36.00 35.48 35.15 376.87 44.18

Net Benefits - Undiscounted 5.89 6.02 6.16 6.21 6.31 6.40 6.47 6.51 6.61 6.75

Net Benefits - 7% Discount 5.50 5.26 5.03 4.74 4.50 4.26 4.03 3.79 3.60 3.43 44.13 6.28

Net Benefits - 3% Discount 5.72 5.67 5.63 5.52 5.44 5.36 5.26 5.14 5.07 5.02 53.84 6.31

Note: AV means Annualized Value
45

Table 8: Change in Benefits, Costs, and Net Benefits of the Proposed Regulations from the Baseline Scenario ($MM)

Low Remediation Cost - Low Environmental Risk

Low EIA Price Scenario 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 Total AV

Benefits - Undiscounted 11.41 11.41 11.50 11.51 11.62 11.77 11.89 11.96 12.14 12.40

Benefits - 7% Discount 10.66 9.97 9.39 8.78 8.29 7.84 7.41 6.96 6.60 6.30 82.20 11.70

Benefits - 3% Discount 11.08 10.76 10.52 10.23 10.02 9.86 9.67 9.44 9.30 9.23 100.10 11.74

Costs - Undiscounted 36.40 36.41 36.68 36.73 37.07 37.55 37.94 38.14 38.72 39.55

Costs - 7% Discount 34.02 31.80 29.94 28.02 26.43 25.02 23.63 22.20 21.06 20.11 262.23 37.34

Costs - 3% Discount 35.34 34.32 33.57 32.64 31.98 31.45 30.85 30.11 29.68 29.43 319.36 37.44

Net Benefits - Undiscounted -24.99 -25.00 -25.18 -25.22 -25.45 -25.78 -26.05 -26.19 -26.58 -27.15

Net Benefits - 7% Discount -23.36 -21.83 -20.56 -19.24 -18.15 -17.18 -16.22 -15.24 -14.46 -13.80 -180.04 -25.63

Net Benefits - 3% Discount -24.26 -23.56 -23.05 -22.41 -21.96 -21.59 -21.18 -20.67 -20.37 -20.21 -219.25 -25.70

Reference EIA Price Scenario 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 Total AV

Benefits - Undiscounted 12.92 13.20 13.51 13.63 13.85 14.03 14.19 14.29 14.51 14.81

Benefits - 7% Discount 12.08 11.53 11.03 10.40 9.87 9.35 8.84 8.32 7.89 7.53 96.84 13.79

Benefits - 3% Discount 12.55 12.45 12.36 12.11 11.94 11.75 11.54 11.28 11.12 11.02 118.13 13.85

Costs - Undiscounted 41.23 42.13 43.10 43.49 44.17 44.77 45.28 45.60 46.30 47.24

Costs - 7% Discount 38.53 36.79 35.18 33.18 31.49 29.83 28.20 26.54 25.18 24.01 308.95 43.99

Costs - 3% Discount 40.03 39.71 39.44 38.64 38.10 37.50 36.82 36.00 35.48 35.15 376.87 44.18

Net Benefits - Undiscounted -28.31 -28.92 -29.59 -29.86 -30.33 -30.74 -31.09 -31.31 -31.79 -32.43

Net Benefits - 7% Discount -26.46 -25.26 -24.15 -22.78 -21.62 -20.48 -19.36 -18.22 -17.29 -16.49 -212.11 -30.20

Net Benefits - 3% Discount -27.48 -27.26 -27.08 -26.53 -26.16 -25.74 -25.28 -24.72 -24.36 -24.13 -258.74 -30.33

Note: AV means Annualized Value
46

Table 9: Administrative Costs of the Proposed Regulations (in Dollars, Undiscounted)

Low EIA Price Scenario 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022

Operator Compliance

Notices of Intent (Sundry) 481,655 481,725 485,334 485,995 490,538 496,825 501,953 504,663 512,341 523,316

Total Private Administrative Cost 481,655 481,725 485,334 485,995 490,538 496,825 501,953 504,663 512,341 523,316

BLM Review

Notices of Intent (Sundry) 318,226 318,272 320,657 321,093 324,095 328,249 331,637 333,427 338,500 345,751

Subsequent Reports (Sundry) 30,395 30,400 30,627 30,669 30,956 31,353 31,676 31,847 32,332 33,024

Webposting 86,474 86,487 87,135 87,254 88,069 89,198 90,119 90,605 91,984 93,954

Total BLM Administrative Cost 435,096 435,159 438,419 439,016 443,120 448,799 453,432 455,879 462,815 472,730

Ref EIA Price Scenario 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022

Operator Compliance

Notices of Intent (Sundry) 545,550 557,377 570,212 575,398 584,460 592,410 599,128 603,385 612,565 625,029

Total Private Administrative Cost 545,550 557,377 570,212 575,398 584,460 592,410 599,128 603,385 612,565 625,029

BLM Review

Notices of Intent (Sundry) 360,441 368,255 376,735 380,161 386,149 391,401 395,840 398,652 404,717 412,952

Subsequent Reports (Sundry) 34,427 35,174 35,984 36,311 36,883 37,385 37,808 38,077 38,656 39,443

Webposting 97,946 100,069 102,374 103,305 104,932 106,359 107,565 108,329 109,978 112,215

Total BLM Administrative Cost 492,814 503,498 515,092 519,777 527,963 535,144 541,213 545,058 553,352 564,611
47

4.3 Alternative 1: No Requirement for Lined Pits

Benefits

Under this alternative, it is assumed that the regulations would remove much of the risk 

associated with potential wellbore integrity issues. The change in social benefits from the 

baseline scenario is positive. Assuming low remediation costs and low environmental risks, then 

the change in social benefit under this alternative is positive and ranges between $0.01MM and 

$0.02MM per year using discount rates of 7% and 3%. Assuming high remediation costs and 

high environmental risks, the change in social benefits over the baseline ranges between 

$7.60MM and $8.95MM per year using a discount rate of 7% and from $7.62MM and $8.99MM 

per year using a discount rate of 3%. Since there is no requirement to use lined pits, the benefits 

in this alternative come from well integrity.

Costs

The costs include both costs to the industry and the BLM under this alternative. Costs 

include operational tests that demonstrate wellbore integrity, but not those costs associated with 

lining open pits in the instances where operators use pits instead of storage tanks. 

The change in costs over the baseline ranges between $34.68MM and $40.86MM per 

year using a discount rate of 7% and between $34.77MM and $41.04MM per year using a 

discount rate of 3%, assuming either low remediation costs and low environmental risks or high 

remediation costs and low environmental risks. 

Net Benefits

The change in net benefits is negative for this alternative. Assuming low remediation 

costs and low environmental risks, the change in net benefits from the baseline is negative and 

ranges from -$34.67MM and -$40.84MM per year using a discount rate of 7% and between 

-$34.76MM and -$41.02MM per year using a discount rate of 3%. Assuming high remediation 

costs and high environmental risks, ranges from -$27.08MM and -$31.90MM per year using a 

discount rate of 7% and between -$27.15MM and -$32.04MM per year using a discount rate of 

3%.
48

Table 10: Change in Benefits, Costs, and Net Benefits of Alternative 1 from the Baseline Scenario ($MM)

High Remediation Cost - High Environmental Risk

Low EIA Price Scenario 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 Total AV

Benefits - Undiscounted 7.41 7.41 7.47 7.48 7.55 7.64 7.72 7.76 7.88 8.05

Benefits - 7% Discount 6.92 6.47 6.09 5.70 5.38 5.09 4.81 4.52 4.29 4.09 53.37 7.60

Benefits - 3% Discount 7.19 6.98 6.83 6.64 6.51 6.40 6.28 6.13 6.04 5.99 65.00 7.62

Costs - Undiscounted 33.81 33.82 34.07 34.12 34.44 34.88 35.24 35.43 35.97 36.74

Costs - 7% Discount 31.60 29.54 27.81 26.03 24.55 23.24 21.94 20.62 19.56 18.68 243.57 34.68

Costs - 3% Discount 32.83 31.88 31.18 30.31 29.70 29.21 28.65 27.97 27.57 27.34 296.63 34.77

Net Benefits - Undiscounted -26.40 -26.41 -26.60 -26.64 -26.89 -27.23 -27.52 -27.66 -28.09 -28.69

Net Benefits - 7% Discount -24.68 -23.06 -21.72 -20.32 -19.17 -18.15 -17.14 -16.10 -15.28 -14.58 -190.20 -27.08

Net Benefits - 3% Discount -25.63 -24.89 -24.35 -23.67 -23.20 -22.81 -22.37 -21.84 -21.53 -21.35 -231.63 -27.15

Reference EIA Price 

Scenario 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 Total AV

Benefits - Undiscounted 8.39 8.57 8.77 8.85 8.99 9.11 9.22 9.28 9.42 9.61

Benefits - 7% Discount 7.84 7.49 7.16 6.75 6.41 6.07 5.74 5.40 5.13 4.89 62.88 8.95

Benefits - 3% Discount 8.15 8.08 8.03 7.86 7.76 7.63 7.49 7.33 7.22 7.15 76.70 8.99

Costs - Undiscounted 38.30 39.13 40.03 40.39 41.03 41.59 42.06 42.36 43.00 43.88

Costs - 7% Discount 35.79 34.18 32.68 30.82 29.25 27.71 26.19 24.65 23.39 22.30 286.96 40.86

Costs - 3% Discount 37.18 36.88 36.63 35.89 35.39 34.83 34.20 33.44 32.96 32.65 350.05 41.04

Net Benefits - Undiscounted -29.91 -30.55 -31.26 -31.54 -32.04 -32.47 -32.84 -33.08 -33.58 -34.26

Net Benefits - 7% Discount -27.95 -26.69 -25.52 -24.06 -22.84 -21.64 -20.45 -19.25 -18.26 -17.42 -224.08 -31.90

Net Benefits - 3% Discount -29.03 -28.80 -28.61 -28.02 -27.64 -27.20 -26.70 -26.11 -25.74 -25.49 -273.34 -32.04

Note: AV means Annualized Value
49

Table 11: Change in Benefits, Costs, and Net Benefits of Alternative 1 from the Baseline Scenario ($MM)

Low Remediation Cost - Low Environmental Risk

Low EIA Price Scenario 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 Total AV

Benefits - Undiscounted 0.01 0.01 0.01 0.01 0.01 0.01 0.01 0.01 0.01 0.01

Benefits - 7% Discount 0.01 0.01 0.01 0.01 0.01 0.01 0.01 0.01 0.01 0.01 0.09 0.01

Benefits - 3% Discount 0.01 0.01 0.01 0.01 0.01 0.01 0.01 0.01 0.01 0.01 0.11 0.01

Costs - Undiscounted 33.81 33.82 34.07 34.12 34.44 34.88 35.24 35.43 35.97 36.74

Costs - 7% Discount 31.60 29.54 27.81 26.03 24.55 23.24 21.94 20.62 19.56 18.68 243.57 34.68

Costs - 3% Discount 32.83 31.88 31.18 30.31 29.70 29.21 28.65 27.97 27.57 27.34 296.63 34.77

Net Benefits - Undiscounted -33.80 -33.80 -34.06 -34.10 -34.42 -34.86 -35.22 -35.41 -35.95 -36.72

Net Benefits - 7% Discount -31.59 -29.53 -27.80 -26.02 -24.54 -23.23 -21.94 -20.61 -19.56 -18.67 -243.48 -34.67

Net Benefits - 3% Discount -32.82 -31.86 -31.17 -30.30 -29.69 -29.20 -28.64 -27.96 -27.55 -27.33 -296.52 -34.76

Reference EIA Price 

Scenario 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 Total AV

Benefits - Undiscounted 0.01 0.01 0.01 0.02 0.02 0.02 0.02 0.02 0.02 0.02

Benefits - 7% Discount 0.01 0.01 0.01 0.01 0.01 0.01 0.01 0.01 0.01 0.01 0.11 0.02

Benefits - 3% Discount 0.01 0.01 0.01 0.01 0.01 0.01 0.01 0.01 0.01 0.01 0.13 0.02

Costs - Undiscounted 38.30 39.13 40.03 40.39 41.03 41.59 42.06 42.36 43.00 43.88

Costs - 7% Discount 35.79 34.18 32.68 30.82 29.25 27.71 26.19 24.65 23.39 22.30 286.96 40.86

Costs - 3% Discount 37.18 36.88 36.63 35.89 35.39 34.83 34.20 33.44 32.96 32.65 350.05 41.04

Net Benefits - Undiscounted -38.28 -39.11 -40.01 -40.38 -41.01 -41.57 -42.04 -42.34 -42.99 -43.86

Net Benefits - 7% Discount -35.78 -34.16 -32.66 -30.80 -29.24 -27.70 -26.18 -24.64 -23.38 -22.30 -286.86 -40.84

Net Benefits - 3% Discount -37.17 -36.87 -36.62 -35.88 -35.38 -34.82 -34.18 -33.42 -32.95 -32.64 -349.91 -41.02

Note: AV means Annualized Value
50

5. Economic Impact Analysis and Distributional Assessments 

5.1 Energy System Impact Analysis

Executive Order 13211 provides that agencies prepare and submit to the Administrator of 

the Office of Information and Regulatory Affairs (OIRA), OMB, a Statement of Energy Effects 

for certain actions identified as significant energy actions. Section 4(b) of Executive Order 

13211 defines a “significant energy action” as “any action by an agency (normally published in 

the Federal Register) that promulgates or is expected to lead to the promulgation of a final rule or 

regulation, including notices of inquiry, advance notices of proposed rulemaking, and notices of 

proposed rulemaking: 1)(i) that is a significant regulatory action under Executive Order 12866 or 

any successor order, and (ii) is likely to have a significant adverse effect on the supply, 

distribution, or use of energy; or 2) that is designated by the Administrator of OIRA as a 

significant energy action. 

This analysis estimates the additional cost burden per well stimulation event and finds 

that the average burden per stimulation is about $11,833 in 2013. 

The BLM believes that the additional cost per well stimulation resulting from this 

proposed rule is insignificant when compared with the drilling costs in recent years, the 

production gains from hydraulically fractured wells operations and the net incomes of entities 

within the oil and natural gas industries. 

Table 14 presents drilling costs per well for a range of wells from 1998 to 2007. The data 

clearly show that drilling costs increased during this time. Using the estimates for the average 

burden per well stimulation and the average cost of drilling wells in 2007, the annual costs of this 

proposed rule represents about 0.3% of the drilling cost of a well. 

As such, the proposed regulations are unlikely to have an effect on the investment 

decisions of firms, and the rule is unlikely to affect the supply, distribution, or use of energy. 

Alternative 1 poses slightly lower costs (about $10,958 in 2013) than the proposed 

(favored) regulations on a per well stimulation basis.
51

Table 14: Per Well Costs of Crude Oil and Natural Gas Wells Drilled

Year

Crude Oil, 

Natural Gas, and 

Dry Wells Drilled 

(Nominal $)

Crude Oil Wells 

Drilled 

(Nominal $)

Natural Gas Wells 

Drilled 

(Nominal $)

1998 769,100 566,000 815,600

1999 856,100 783,000 798,400

2000 754,600 593,400 756,900

2001 943,200 729,100 896,500

2002 1,054,200 882,800 991,900

2003 1,199,500 1,037,300 1,106,000

2004 1,673,100 1,441,800 1,716,400

2005 1,720,700 1,920,400 1,497,600

2006 2,101,700 2,238,600 1,936,200

2007 4,171,700 4,000,400 3,906,900

Source: EIA (2012), “Costs of Crude Oil and Natural Gas Wells Drilled”

5.2 Employment Impact Analysis

Executive Order 13563 reaffirms the principles established in Executive Order 12866, but 

calls for additional consideration of the regulatory impact on employment. It states, “Our 

regulatory system must protect public health, welfare, safety, and our environment while 

promoting economic growth, innovation, competitiveness, and job creation.” An analysis of 

employment impacts is a standalone analysis and the impacts should not be included in the 

estimation of benefits and costs. 

This analysis seeks to inform the discussion of labor demand and job impacts by 

providing an estimate of the employment impacts of the proposed regulations using labor 

requirements for the additional administration and operational needs.

This proposed rule would require operators, who have not already done so, to conduct 

one-time tests on a well or make a one-time installation of a mitigation control feature. In 

addition, operators would be required to perform administrative tasks related to a one-time event. 

Compliance with the operational requirements would shift resources within the industry from the 

operators to firms providing the services or supplies. For example, the requirement for a CBL on 

the surface casing represents a burden to the operator but a benefit to the company running the 

log. 

This analysis calculates the labor requirements anticipated for compliance. Since the 

BLM anticipates that the number of well stimulations will increase over time, the labor 

requirements increase over the outlook period, albeit slightly. Under both risk and cost 
52

scenarios, the labor requirements for operators to meet additional administrative and operational 

needs are estimated to be about 15 to 18 FTE in each of the next three years. The results appear

in the Appendix. Note that these impacts are only for the regulated sector. The BLM cannot 

predict the net national employment impact, i.e., whether the increased employment in the 

regulated sector comes from previously unemployed workers or is displaces workers actively 

employed in other sectors.

Another area of interest is the extent to which the financial burden is expected to change 

operators’ investment decisions. If the financial burden is not significant and all other factors are 

equal, then one would expect operators to maintain existing levels of investment and 

employment. As with the results in the Section 5.1, the BLM believes that the proposed rule 

would result in an additional cost per well stimulation that is small and will not alter the 

investment or employment decisions, of firms. Therefore, considering the labor requirements 

and that operators would not likely reduce investment, the BLM anticipates an overall net gain in 

employment.

For alternative 1, the labor requirements are about 15 to 18 FTE in each of the next three 

years.

5.3 Small Business Impacts Analysis

The Regulatory Flexibility Act as amended by the Small Business Regulatory 

Enforcement Fairness Act (SBREFA) generally requires an agency to prepare a regulatory 

flexibility analysis of any rule subject to notice and comment rulemaking requirements under the 

Administrative Procedure Act or any other statute, unless the agency certifies that the rule will 

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

include small businesses, small governmental jurisdictions, or small not-for-profit enterprises.

The BLM reviewed the Small Business Administration (SBA) size standards for small 

businesses and the number of entities fitting those size standards as reported by the U.S. Census 

Bureau in the 2007 Economic Census. Using the Economic Census data, the BLM concludes 

that about 99% of the entities operating in the relevant sectors21 are small businesses in that they 

employ fewer than 500 employees. Also, within these relevant sectors, small firms account for 

74% of the total value of shipments and receipts for services, 86% of the total cost of supplies, 

 21 NAICS codes: 211111 - Crude Petroleum and Natural Gas Extraction, 211112 - Natural Gas Liquid Extraction, 

and 213111 - Drilling Oil and Gas Wells.
53

78% of the total capital expenditures (excluding land and mineral rights), and 67% of the paid 

employees (see Tables 15 through 19). 

Small entities represent the overwhelming majority of entities operating in the crude oil 

and natural gas extraction industry. As such, the proposed rule is likely to affect a significant 

number of small entities. To examine the economic impact of the rule on small entities, the 

BLM performed a screening analysis for impacts on a sample of expected affected small entities 

by comparing compliance costs to entity net incomes.

Under the cost and risk scenarios, the average cost per entity in 2013 is estimated to 

represent between 0.002% and 0.22% of the 2010 net incomes of the sampled companies, 

depending on the AEO commodity price forecasts. The proportions do not change substantially 

over the outlook period. The results appear in the Appendix. 

For alternative 1, the average cost per entity in 2013 is estimated to represent between 

0.002% and 0.21% of the 2010 net incomes of the sampled companies, depending on the AEO 

commodity price forecasts.
54

Table 15: Number of Firms by Firm Size and NAICS, 2007

NAICS NAICS Description

SBA Size 

Standard All Firms

< 20 

Employees

20-99 

Employees

100-499 

Employees

> 500 

Employees

211111 Crude Petroleum and Natural Gas 

Extraction

500 5,964 4,905 820 197 42

211112 Natural Gas Liquid Extraction 500 296 171 114 11 0

213111 Drilling Oil and Gas Wells 500 2,109 1,454 439 180 36

Total firms 8,369 6,530 1,373 388 78

Percent of total 78.03% 16.41% 4.64% 0.93%

Table 16: Total Value of Shipments and Receipts for Services ($1000) by Firm Size and NAICS, 2007

NAICS NAICS Description

SBA Size 

Standard All Firms

< 20 

Employees

20-99 

Employees

100-499 

Employees

> 500 

Employees

211111 Crude Petroleum and Natural Gas 

Extraction

500 212,783,171 27,779,989 63,673,010 58,879,619 62,450,553

211112 Natural Gas Liquid Extraction 500 42,321,678 6,920,098 27,110,810 8,290,770 0

213111 Drilling Oil and Gas Wells 500 22,512,322 631,501 4,011,228 8,382,350 9,733,440

Total firms 277,617,171 35,331,588 94,795,048 75,552,739 72,183,993

Percent of total 12.73% 34.15% 27.21% 26.00%

Table 17: Total Cost of Supplies ($1000) by Firm Size and NAICS, 2007

NAICS NAICS Description

SBA Size 

Standard All Firms

< 20 

Employees

20-99 

Employees

100-499 

Employees

> 500 

Employees

211111 Crude Petroleum and Natural Gas 

Extraction

500 37,755,041 5,709,734 11,650,183 12,335,810 8,059,314

211112 Natural Gas Liquid Extraction 500 31,129,919 4,858,309 19,948,706 6,322,904 0

213111 Drilling Oil and Gas Wells 500 6,576,675 246,328 1,012,247 2,567,116 2,027,623

Total firms 75,461,635 10,814,371 32,611,136 21,225,830 10,086,937

Percent of total 14.33% 43.22% 28.13% 13.37%

Table 18: Total Capital Expenditures (except land and mineral rights) ($1000) by Firm Size and NAICS, 2007

NAICS NAICS Description

SBA Size 

Standard All Firms

< 20 

Employees

20-99 

Employees

100-499 

Employees

> 500 

Employees

211111 Crude Petroleum and Natural Gas 

Extraction

500 87,551,089 9,714,838 26,003,272 33,504,207 18,328,772

211112 Natural Gas Liquid Extraction 500 1,965,593 513,229 1,058,819 393,545 0

213111 Drilling Oil and Gas Wells 500 6,532,941 157,959 1,049,920 2,519,731 2,013,806

Total firms 96,049,623 10,386,026 28,112,011 36,417,483 20,342,578

Percent of total 10.81% 29.27% 37.92% 21.18%

Table 19: Number of Paid Employees by Firm Size and NAICS, March, 2007

NAICS NAICS Description

SBA Size 

Standard All Firms

< 20 

Employees

20-99 

Employees

100-499 

Employees

> 500 

Employees

211111 Crude Petroleum and Natural Gas 

Extraction

500 143,054 23,928 34,791 37,717 33,454

211112 Natural Gas Liquid Extraction 500 7,389 1,014 4,907 1,468 0

213111 Drilling Oil and Gas Wells 500 106,859 6,375 20,122 41,616 37,420

Total firms 257,302 31,317 59,820 80,801 70,874

Percent of total 12.17% 23.25% 31.40% 27.55%

Note: Where range provided, employee data were estimated to be in middle of range.
55

6. Statutory and Executive Order Reviews

6.1 Executive Order 12866 Regulatory Planning 

In accordance with the criteria in Executive Order 12866, the Office of Management and 

Budget has determined that this rule is a significant regulatory action.

The rule will not 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. However, the rule may raise novel policy issues because of the proposed 

requirement that operators provide to the BLM information regarding well stimulation activities 

that they are not currently providing to the BLM.

6.2 Executive Order 13132 Federalism

Under Executive Order 13132, this proposed rule would not have significant Federalism 

effects. A Federalism assessment is not required because the proposed rule would not have a 

substantial direct effect on the states, on the relationship between the national government and 

the states, or on the distribution of power and responsibilities among the various levels of 

government. The proposed rule would not have any effect on any of the items listed. The 

proposed rule would affect the relationship between operators, lessees, and the BLM, but would 

not impact states. Therefore, under Executive Order 13132, the BLM has determined that the 

proposed rule would not have sufficient Federalism implications to warrant preparation of a 

Federalism Assessment.

6.3 Executive Order 13175 Consultation and Coordination with Indian Tribal 

Governments

Subject to Executive Order 13175, the BLM may not issue a regulation that has tribal 

implications, that imposes substantial direct compliance costs, and that is not required by statute, 

unless the Federal Government provides the funds necessary to pay the direct compliance costs 

incurred by tribal governments, or the BLM consults with tribal officials early in the process of 

developing the proposed regulation and develops a tribal summary impact statement. 

Under Executive Order 13175, the President’s memorandum of April 29, 1994, 

‘‘Government-to-Government Relations with Native American Tribal Governments’’ (59 FR 
56

22951), and 512 Departmental Manual 2, the BLM evaluated possible effects of the proposed 

rule on federally recognized Indian tribes. The BLM approves proposed operations on all Indian 

onshore oil and gas leases (except those excluded by statute). Therefore, the proposed rule has 

the potential to affect Indian tribes. In conformance with the Secretary’s policy on tribal 

consultation, the Bureau of Land Management held four tribal consultation meetings to which 

over 175 tribal entities were invited. The consultations were held in:

• Tulsa, Oklahoma on January 10, 2012; 

• Billings, Montana on January 12, 2012; 

• Salt Lake City, Utah on January 17, 2012; and 

• Farmington, New Mexico on January 19, 2012. 

The purpose of these meetings was to solicit initial feedback and preliminary comments 

from the tribes. Comments from tribes will be received and consultation will continue as this 

rulemaking proceeds. To date, the tribes have expressed concerns about the BLM’s Inspection 

and Enforcement program’s ability to enforce the terms of this rule; previously plugged and 

abandoned wells being potential conduits for contamination of ground water; and the operator 

having to provide documentation that the water used for the fracturing operation was legally 

acquired. The BLM will further address these concerns during the drafting of the final rule. 

6.4 Executive Order 13211 Actions Concerning Regulations that Significantly 

Affect Energy Supply, Distribution, or Use

Executive Order 13211 provides that agencies shall prepare and submit to the 

Administrator of the Office of Information and Regulatory Affairs (OIRA), OMB, a Statement of 

Energy Effects for certain actions identified as significant energy actions. Section 4(b) of 

Executive Order 13211 defines a “significant energy action” as “any action by an agency 

(normally published in the Federal Register) that promulgates or is expected to lead to the 

promulgation of a final rule or regulation, including notices of inquiry, advance notices of 

proposed rulemaking, and notices of proposed rulemaking: 1)(i) that is a significant regulatory 

action under Executive Order 12866 or any successor order, and (ii) is likely to have a significant 

adverse effect on the supply, distribution, or use of energy; or 2) that is designated by the 

Administrator of OIRA as a significant energy action. 
57

The BLM estimated the additional cost per well stimulation resulting from this proposed 

rule and compared it with the average cost of drilling wells in 2007. The additional cost 

represents about 0.3% of the drilling cost of a well.

As such, the proposed regulations are unlikely to have an effect on the investment 

decisions of firms, and the rule is unlikely to affect the supply, distribution, or use of energy. 

The proposed rule is unlikely to have a significant adverse effect on the supply, distribution, or 

use of energy. As such, the proposed rule is not a “significant energy action” as defined in 

Executive Order 13211. 

6.5 Regulatory Flexibility Act and Small Business Regulatory Enforcement 

Fairness Act of 1996 (5 U.S.C. 601-612)

The Regulatory Flexibility Act as amended by the Small Business Regulatory 

Enforcement Fairness Act (SBREFA) generally requires an agency to prepare a regulatory 

flexibility analysis of any rule subject to notice and comment rulemaking requirements under the 

Administrative Procedure Act or any other statute, unless the agency certifies that the rule will 

not have a significant economic impact on a significant number of small entities (SISNOSE). 

Small entities include small businesses, small governmental jurisdictions, and small not-forprofit enterprises. 

The BLM reviewed the Small Business Administration (SBA) size standards for small 

businesses and the number of entities fitting those size standards as reported by the U.S. Census 

Bureau in the 2007 Economic Census. Using the Economic Census data, the BLM concludes 

that about 99% of the entities operating in the relevant sectors are small businesses in that they 

employ fewer than 500 employees. Also, small firms account for 86% of the total cost of 

supplies and 78% of the total capital expenditures (excluding land and mineral rights). 

Small entities represent the overwhelming majority of entities operating in the crude oil 

and natural gas extraction industry. As such, the proposed rule is likely to affect a significant 

number of small entities. To examine the economic impact of the rule on small entities, the 

BLM performed a screening analysis for impacts on a sample of expected affected small entities 

by comparing compliance costs to entity net incomes.

The average cost per entity in 2013 is estimated to represent between 0.002% and 0.22%

percent of the 2010 net incomes of the sampled companies, depending on the EIA Annual 
58

Energy Outlook commodity price forecasts. The proportions do not change substantially over 

the outlook period. 

Therefore, after considering the economic impact of the proposed rule on these small 

entities, the screening analysis indicates that this proposed rule will not have a significant 

economic impact on a substantial number of small entities.

6.6 Unfunded Mandates Reform Act of 1995 (P.L. 104-4)

This proposed rule does not contain a federal mandate that may result in expenditures of 

$100 million or more for state, local, and tribal governments, in the aggregate, or to the private 

sector in any one year. Thus, the proposed rule is also not subject to the requirements of sections 

202 or 205 of UMRA.

This proposed rule is also not subject to the requirements of section 203 of UMRA 

because it contains no regulatory requirements that might significantly or uniquely affect small 

governments, because it contains no requirements that apply to such governments, nor does it 

impose obligations upon them.
59

7. Conclusion

This analysis presents potential effects that would result from the proposed rule. These 

effects are measured as the change from the baseline scenario, that which would likely occur 

absent of the regulation. In addition to an examination of the favored option, the BLM presents 

as an alternatives the proposed regulations without the requirement for those operators who use 

pits to line them (alternative 1).

The preferred regulation is estimated to result in a positive change in net benefits over 

the baseline scenario when it is assumed that there is high environmental risk and high 

remediation costs associated with well stimulation operations and hydraulic fracturing. These 

additional net benefits are calculated to be between about $5.33MM to $6.28MM, annually, 

using a 7% discount rate, when assuming that the risks posed from well integrity issues are high 

and the remediation costs of contamination are high. Of course, whether those assumptions for 

risks and costs are “high” is a source of uncertainty, given the variety of potential impacts and 

range of costs. If the average cost of remediating a subsurface contamination event is greater 

than $1 million, then the net benefits calculated in this analysis are underestimated. The 

additional net benefits are negative when assuming that risks are low and the remediation 

required for a subsurface contamination would be to simply drill a new water well. In many 

cases, this assumption does not hold.

Alternative 1 does not approach the change in net benefits estimated under the other 

alternatives.

For the preferred approach, the estimated costs per well stimulation is not significant 

when compared against the costs of drilling an oil and gas well. The average cost per well 

stimulation is estimated to be about $11,833 in 2013, which represents about 0.3% of the cost 

drilling a well. 

The analysis also measures the employment impacts by estimating the labor requirements 

for the additional administration and operational needs. The labor requirements were estimated 

to be between 15 and 18 FTE over the next three years. The proposed regulations are not 

expected to alter investment decisions or reduce production.
60

8. References

American Petroleum Institute (2009). “Hydraulic Fracturing Operations – Well Construction 

and Integrity Guidelines. API Guidance Document HF1. First Edition.”

Bureau of Labor Statistics (2010). “Industries at a Glance: Mining, Quarrying, and Oil and Gas 

Extraction: NAICS 21.” January 28, 2012. Retrieved from 

http://www.bls.gov/iag/tgs/iag21.htm.

Bureau of Labor Statistics (2010). “Industries at a Glance: Administrative and Support Services: 

NAICS 561.” January 28, 2012. Retrieved from http://www.bls.gov/iag/tgs/iag561.htm.

Bureau of Labor Statistics (2012). “Economic News Release: Employment Cost Index News 

Release Text.” January 31, 2012. Retrieved from

http://www.bls.gov/news.release/eci.nr0.htm.

Downey, M. (2009). Oil 101. Wooden Table Press, LLC.

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62

9. Appendix

The appendix provides a list of tables, A-1 through A-7, for the high remediation cost –

high environmental risk and low remediation cost – low environmental risk scenarios, as follows:

High Remediation Cost – High Environmental Risk

A-1 Summary of Benefits and Costs

A-2 Administrative Costs

A-3 Operational Costs

A-4 Social Costs

A-5 Estimated Employment in Full-Time Equivalents

A-6 Estimated Benefits and Cots to Producers Per Well Stimulation

A-7 Small Business Impacts

Low Remediation Cost – Low Environmental Risk

A-1 Summary of Benefits and Costs

A-2 Administrative Costs

A-3 Operational Costs

A-4 Social Costs

A-5 Estimated Employment in Full-Time Equivalents

A-6 Estimated Benefits and Cots to Producers Per Well Stimulation

A-7 Small Business Impacts