Economic Analysis for

Hydraulic Fracturing Rule

U.S. Bureau of Land Management
i

Table of Contents

1. Introduction...........................................................................................................................................1

2. Background...........................................................................................................................................3

2.1 Requirements for Economic Analysis..............................................................................................3

2.2 Need for Policy Action ....................................................................................................................5

2.3 Summary of the Rule .......................................................................................................................8

2.4 Consideration of Alternative Approaches........................................................................................9

2.5 Alternatives to Direct Regulation ..................................................................................................11

2.6 Federal and Indian Oil and Gas Leasing Activity..........................................................................12

2.7 Industry Classifications..................................................................................................................15

2.8 Industry Standards for Well Construction and Integrity for Hydraulic Fracturing Operations .....17

2.9 Industry Standards for Water Management Associated with Hydraulic Fracturing ......................20

2.10 Existing Regulations Related to the Rule’s Provisions .............................................................21

2.10.1 Existing BLM Regulations on Cementing Requirements.................................................21

2.10.2 Existing BLM Regulations on Pressure Testing Requirements........................................22

2.10.3 Summary of Existing State Regulations...........................................................................22

3. Estimating Benefits and Costs ............................................................................................................27

3.1 Theoretical Framework..................................................................................................................27

3.1.1 Measuring the Incremental Change.......................................................................................27

3.1.2 Costs Framework ..................................................................................................................28

3.1.3 Benefits Framework ..............................................................................................................33

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

3.3 Discounted Present Value ..............................................................................................................47

3.4 Uncertainty.....................................................................................................................................48

3.5 Changes in the Economic Analysis from the Initial Proposed Rule ..............................................49

4. Results.................................................................................................................................................50

4.1 Costs of the Revised Proposed Rule and Alternatives...................................................................53

4.2 Average Compliance Costs for Operators .....................................................................................62

4.3 BLM Administrative Burden .........................................................................................................63

4.4 Benefits of the Revised Proposed Rule and Alternatives...............................................................64

5. Economic Impact Analysis and Distributional Assessments..............................................................66
ii

5.1 Energy System Impact Analysis....................................................................................................66

5.2 Employment Impact Analysis........................................................................................................68

5.3 Small Business Impact Analysis....................................................................................................68

6. Statutory and Executive Order Reviews.............................................................................................70

6.1 Executive Order 12866 Regulatory Planning and Review ............................................................70

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

U.S.C. 601-612)......................................................................................................................................70

6.3 Unfunded Mandates Reform Act of 1995 (P.L. 104-4).................................................................71

6.4 Executive Order 13211 Actions Concerning Regulations that Significantly Affect Energy Supply, 

Distribution, or Use.................................................................................................................................71

7. Conclusion ..........................................................................................................................................73

8. References...........................................................................................................................................76

9. Appendix.............................................................................................................................................78
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 operations. 

Hydraulic fracturing is a well completion technique that involves sequentially pumping a fluid 

mixture down the well and into the target formation at high enough pressures to cause the rock 

within the target formation to fracture. 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, enhancing the ability of these fluids to be brought to the surface. The process is 

designed to increase the flow of hydrocarbons from the rock formation to the wellbore by 

modifying the permeability of reservoir rock. 

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. The exact formulation of the fluid varies depending on the service provider, rock 

formations, the well, and the requirements of the operator.

The increased use of hydraulic fracturing over the last decade has generated concerns from the 

public about surface and subsurface water quality and resources, including heightened calls for 

improved environmental safeguards for surface operations and the disclosure of chemicals and 

materials used in fracturing fluid. 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 or have updated standards for well construction. 

With this rule, the BLM would update its existing regulations on hydraulic fracturing. The rule 

would require operators to submit a Notice of Intent (NOI) Sundry prior to hydraulic fracturing 

operations. It would require operators to conduct cement evaluation logs (hereafter referred to as 

a CEL or CELs) on casing strings that protect usable water and perform mechanical integrity 

tests (or pressure tests) prior to hydraulic fracturing operations. It allows operators proposing 

hydraulic fracturing on a group of wells in the same geologic area to submit one NOI Sundry and 

cement evaluation logs for a type well. The rule would require operators to monitor pressures 

during hydraulic fracturing operations and to use storage tanks or lined pits to manage flowback

fluid. Finally, it would require operators to submit a Subsequent Report (SR) Sundry after each

hydraulic fracturing operation. The SR Sundry would include information about the operation,

certification that wellbore integrity was maintained, and disclosure of the chemical content of the 

hydraulic fracturing fluid used. The rule allows for chemical disclosure to the BLM through

FracFocus.

Many of the requirements above are currently conducted by operators as a matter of standard 

industry practice or in compliance with existing state regulations and/or other BLM regulations 
2

and requirements. As such, for many of the requirements, the rule does not pose an additional 

burden to operators. However, there are some requirements that do pose an additional burden. 

This analysis estimates that additional burden and the potential costs and benefits of the rule.

As part of the regulatory process, the BLM published proposed regulations in May 2012. As a 

result of the comments it received from the public, the BLM made changes to the proposed 

regulations, and likewise, to the accompanying economic analysis. 

This document details the estimated economic impacts of the revised regulations appearing in the 

revised proposed rule. The rule will not have an estimated annual impact of over $100 million. 
3

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 

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.

The economic analysis is to provide information allowing decision makers to determine that:

There is adequate information indicating the need for and consequences of the 

proposed action;

The potential benefits to society justify the potential costs, recognizing that not all 

benefits and costs can be described in monetary or even in quantitative terms, unless a 

statute requires another regulatory approach;

The proposed action will maximize net benefits to society (including potential 

economic, environmental, public health and safety, and other advantages; 

distributional impacts; and equity), unless a statute requires another regulatory 

approach;

Where a statute requires a specific regulatory approach, the proposed action will be 

the most cost-effective, including reliance on performance objectives to the extent 

feasible; and

Agency decisions are based on the best reasonably obtainable scientific, technical, 

economic, and other information.

To provide this information, the economic analyses of economically significant rules will contain 

three elements1:

A statement of the need for the proposed action;

An examination of alternative approaches; and

An analysis of benefits and costs.

 

1 OMB Circular A-4.
4

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. The analysis must describe the impact of the 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;

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 rule which would accomplish the stated objectives but which would minimize 

any significant economic impact of the rule on small entities. 
5

2.2 Need for Policy Action

Subject Reports and Recommendations

For a more detailed discussion of the environmental impacts associated with hydraulic fracturing 

and on the effects of this rule on the environment, please refer to the Environmental Assessment.

Part of that document appears below. 

Much of the debate about hydraulic fracturing has centered on fluid or gas migration; that is, the 

likelihood that hydraulic fracturing fluids pumped into deep geologic formations migrate into 

shallower freshwater formations. Thus far, there have been no conclusive determinations made 

regarding claims that hydraulic fracturing fluids are the primary source of contamination to 

shallower freshwater formations. Most reports involve instances of abnormally high 

concentrations of methane in water wells or monitoring wells in or near areas with active oil and 

gas drilling.

For example, the National Academy of Sciences issued reports in 20112and in 20123finding that 

there are at least three possible mechanisms for fluid migration into shallow drinking-water 

aquifers that could help explain the increased methane concentrations observed in water wells 

that existed around shale gas wells in Pennsylvania:

1. The movement of gas-rich solutions within the shale formations up into shallow 

drinking-water aquifers, 

2. The movement of gas through inadequately constructed, or leaky gas-well casings, 

and

3. The creation of new or enlarging of existing fractures above the shale formation as a 

result of hydraulic fracturing, which increases the connectivity of the entire fracture 

system, thus allowing the gas to absolve out of solution and migrate through the 

fracture systems and into shallow aquifers.

These reports have indicated that the movement of gas-rich solutions within the shale formations 

up into shallow drinking-water aquifers is the most unlikely possibility. This is due primarily to 

the extensive distance between the shale formations and the shallow aquifers as well as high 

underground pressures exerted against the deep shale formations. The most likely possibility for 

gas contamination would be from leaky gas-well casings. These leaks could occur at hundreds 

of feet underground, with methane passing laterally through the well casing and vertically 

through fracture systems. There is also a possibility for gases to migrate through fractures above 

the shale formation that is created or enlarged as a result of hydraulic fracturing and thus 

expanding the overall underground fracture system. These new fractures could potentially 

relieve the pressures exerted against these gas-rich solutions, which would allow the gas to come 

out of solution and migrate through the fracture system and potentially into shallow aquifers or 

improperly plugged wells. However, these researchers have indicated that this possibility is 

unknown.

 

2 Osborn et al (2011). 

3 Warner et al (2012). 
6

The focus on fluid or gas migration is only one aspect of potential damage. According to the 

U.S. Environmental Protection Agency (EPA), there are other potential impacts, including 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.4

At the President’s direction, the Secretary of Energy’s Advisory Board convened a Natural Gas 

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 final report, issued on November 18, 2011, recommended, among other things, that 

operators and regulating agencies “adopt best practices in well development and construction, 

especially casing, cementing, and pressure management. Pressure testing of cemented casing 

and state-of-the-art cement bond logs should be used to confirm formation isolation. Regulations 

and inspections are needed to confirm that operators have taken prompt action to repair defective 

cementing jobs. The regulation of shale gas development should include inspections at safetycritical stages of well construction and hydraulic fracturing.”5

 

Public Concern

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.

 

4 EPA 2012. “Natural Gas Extraction – Hydraulic Fracturing.”

5

SEAB 2011, pp. 16-17. Available at http://www.shalegas.energy.gov.
7

Improving Governmental Processes

The BLM has existing regulations for hydraulic fracturing, found in 43 CFR 3162.3-2. Under 

that regulatory provision, an operator must seek approval from the BLM before performing 

“non-routine” fracturing operations. Conversely, an operator performing “routine” fracturing 

operations does not need the BLM’s approval. The regulations make a distinction between 

“routine” and “non-routine” fracturing operations, but it does not clearly define them. This 

omission makes the distinction functionally difficult to apply and confusing for both the agency 

and the regulated public. 

Also, hydraulic fracturing operations conducted now are vastly different than the operations 

conducted decades ago. Due to advances in horizontal drilling, hydraulic fracturing operations 

are conducted on wells with longer lateral legs and require larger volumes of water. The 

chemical content of the hydraulic fracturing fluids is also a growing concern to the public, such 

that many state regulatory authorities now require the chemical disclosure of fracturing fluids. 

The information that the BLM currently requires before and after fracturing operations is 

inadequate and does not reflect the complex nature of the operations. 

As the resource manager, the lack of information restricts the BLM’s ability to make informed 

resource decisions about proposed hydraulic fracturing operations. It also restricts the BLM’s 

ability to respond effectively to events where environmental resources have been compromised. 

Knowing the hydraulic fracturing plans and designs and the ingredients of fracturing fluids used 

will help the BLM better manage and protect the public’s resources. From a resource 

management perspective, the current regulation results in incomplete information being provided 

to the BLM. 

Externalities 

Generally, there is greater potential for undesirable events or incidents to occur when operations 

are conducted in wells that are inadequately constructed, where the plans are inadequate, and 

when the fluids are not properly managed. This potential extends to hydraulic fracturing 

operations, where greater pressures are placed on the well, drilling may extend laterally and for 

longer distances, and larger volumes of fluids are used and received as flowback. If and when 

these events occur, there is the potential that they may pose a negative externality to society, 

considering limitations in understanding the extent of damage or determining a causal 

relationship between the hydraulic fracturing operation and the damage.

Relative to wells constructed with sufficient and demonstrated integrity, wells that are 

inadequately constructed may not sufficiently isolate well fluids from the subsurface water 

resources or may be more likely to fail during fracturing operations. Although wellbore integrity 

provisions exist in current BLM regulations, this rule would enhance those provisions to account 

for advances in technology and hydraulic fracturing operations. In addition, the chemical 

composition of hydraulic fracturing fluid may pose additional risk to the subsurface and surface 

environments if not managed and disposed of properly. 
8

2.3 Summary of the Rule

The rule would require operators to do the following with regards to hydraulic fracturing 

operations:

Submit a Notice of Intent (NOI) Sundry for approval prior to the commencement of 

hydraulic fracturing operations. The NOI Sundry will include information relevant to the 

hydraulic fracturing plans. If an operator plans to conduct hydraulic fracturing operations 

on multiple wells in a geographic area with the same geologic characteristics, it may 

submit one NOI Sundry for a group of wells based on plans for a type well.

Conduct a cement evaluation log (CEL) or logs on the casing strings that protect usable 

water. If an operator plans to conduct hydraulic fracturing operations on multiple wells 

in a geographic area with the same geologic characteristics, it must conduct a cement 

evaluation log on the casing strings protecting usable water on the type well to

demonstrate that the cementing operations of the type well resulted in proper cement 

bonding. The operator may then use those results to indicate proper cementing of the 

subsequent wells, as long as the cement operations monitoring data from the subsequent 

wells do not indicate any problems.

When an operator encounters a problem during the cementing process that indicates that 

a proper cement bond may not have been achieved, it must notify the BLM, perform 

remediation activities, run a cement evaluation log, and certify that it corrected all issues 

before conducting the hydraulic fracturing operation.

Conduct mechanical integrity tests prior to hydraulic fracturing.

Use storage tanks or lined pits when managing flowback.

Monitor the hydraulic fracturing operations.

Submit a Subsequent Report (SR) Sundry for each hydraulic fracturing operation after it 

occurs (even if the operator submitted one NOI Sundry for hydraulic fracturing on a 

group of wells). The SR Sundry will include information about the completed hydraulic 

fracturing operation. The operator will disclose to the BLM the chemical components of 

the hydraulic fracturing fluids used, but the operator may do so indirectly through

FracFocus. The operator will also certify that wellbore integrity was maintained prior to 

and during the hydraulic fracturing operation, that the chemicals used complied with all 

applicable laws, and that the operator managed all of the flowback in storage tanks or 

lined pits. The operator will submit documentation that supports the certification on 

wellbore integrity.
9

2.4 Consideration of Alternative Approaches

In developing the rule, the BLM considered several alternatives. The alternatives primarily 

focused on two topic areas: verification of proper cementing behind casing strings through CELs 

and the management of flowback fluids from operations. 

As a matter of standard industry practice, operators conduct a CEL (which may include a cement 

bond log or CBL) on the production casing and, in some cases, on the intermediate casing when

interested in formations above the target zone. State regulations or conditions of approval

(COA) for permits may also require operators to run logs on the intermediate or production 

casings. Also, operators may run a CEL or a temperature log on the surface casing when the 

cement fails to return to the surface or there is some other indication of a problem with the 

cementing.

We examined requirements for operators to conduct cement evaluation logs on: 

Casing strings protecting usable water zones (including surface and intermediate casings) 

for all wells; and

Casing strings protecting usable water zones, but allowing operators to use results from a 

type well to demonstrate proper cementing for subsequent wells in an area with the same 

geologic characteristics.

Each of these scenarios would require the operator to conduct the CEL during the drilling of the 

well and, thus, prior to the hydraulic fracturing operation. However, both scenarios would 

require the operator to submit the results of the CEL with the Subsequent Reports Sundry after 

the hydraulic fracturing operation (unless the CEL is run to demonstrate successful corrective 

action). The BLM had considered requiring the submission of the CEL results prior to the 

hydraulic fracturing operation for BLM’s approval. However, the BLM ultimately determined 

that such a requirement might create permitting delays and unintended costs to operators.

We also considered various approaches for the management of flowback from operations. 

Currently, state regulations serve as the standard in each particular state, but the BLM may 

address requirements in individual permits as long as the state standard is met or exceeded.6 

California requires the use of storage tanks while most other states have various requirements for 

lined pits. New Mexico enacted regulations requiring closed-loop systems in 2008, but proposed 

a rule in 2012 that would allow for the use of lined pits. With this in mind, we examined the 

following requirements for operators to manage the flowback from operations:

Use of storage tanks or lined pits; 

Use of storage tanks; and

Not establish requirements and thereby defer to state regulations.

Alternative 1: Requires CELs on casing strings protecting usable water for all wells; requires 

the use of storage tanks to manage flowback.

 

6 The BLM has regulations for the disposal of produced water (different from flowback from hydraulic fracturing 

operations) in Onshore Oil and Gas Order No. 7. It specifies design requirements for lined pits and procedures for 

requesting approval to use unlined pits. 
10

Alternative 2: Requires CELs on casing strings protecting usable water for all wells; does not 

establish requirements for storage tanks or lined pits. 

The potential costs and benefits of each alternative are presented in Section 4 of this document. 

The costs and benefits, where appropriate, are broken out by activity or requirement, such that 

costs and benefits of further alternatives may be inferred, beyond those packaged as Alternative 

1 or Alternative 2.
11

2.5 Alternatives to Direct Regulation

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 as when 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

in the subject rule. 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 rule promotes performance standards rather than design standards. It does not prescribe a 

single cement evaluation tool or process, but allows for the operator to determine the appropriate 

log based upon factors which may include the geology, downhole conditions, drilling plans, 

operator or service company experience, and advances in technology.

The rule also includes a provision that allows an operator to request a variance if it can attain the 

same standards established by the regulation but in a different manner. The BLM would 

consider alternatives if an operator could show that the objectives of the rule would be met using 

an alternate approach. The variance request 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.

The rule requires disclosure of hydraulic fracturing fluids, a requirement that is informational in 

nature, rather than direct regulation on the part of the BLM. OMB Circular A-4 states that “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.” While consumers of resources produced by hydraulic fracturing cannot 

differentiate products downstream based upon the upstream conditions, the availability of 

otherwise concealed characteristics of hydraulic fracturing fluids might help those nearby to 

make informed decisions in other respects.
12

2.6 Federal and Indian Oil and Gas Leasing Activity

The BLM Oil and Gas Management program is one of the largest mineral leasing programs in 

the Federal Government. There were 48,699 Federal oil and gas leases covering 37,792,212

acres at the end of fiscal year (FY) 2012. For FY 2012, there were 92,583 producible and 

service drill holes and 99,015 producible and service completions on Federal leases.7 Table 1 

shows the number of inspection cases managed by the BLM. Most of these cases involve more 

than one well.

Table 1: Federal and Indian Oil and Gas Cases8

Producing Non-Producing

FY 2010

Federal Cases 19,995 3,523

Indian Cases 2,576 392

Total Cases 22,571 3,915

FY 2011

Federal Cases 21,278 5,417

Indian Cases 2,879 493

Total Cases 24,157 5,910

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

FY-2011 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. 

Table 2 shows the sales volume, sales value, and royalty generated from Federal and Indian oil 

and gas production in 2012. For FY 2012, onshore Federal oil and gas leases produced about 

118 million barrels (Bbl) of oil, 2.81 billion Mcf (thousand cubic feet) of natural gas, and 2.84

billion gallons (Gal) of natural gas liquids, with a production value of almost $23 billion and 

generating royalties of almost $2.6 billion. Oil and gas production from Indian leases was 

almost 29 million barrels of oil, 256 million Mcf of natural gas, and 155 million gallons of 

natural gas liquids, with a production value of $3.4 billion and generating royalties of $561

million for the Indian mineral owners.

Figure 1 illustrates the oil and gas activity on federally-administered lands in the Western U.S. 

 

7

Preliminary data (as of December 21, 2012) for the BLM’s Oil and Gas Statistics. 

8 An AFMSS case can be a lease, unit participating area, communitized agreement, or other agreement. Data for 

2012 is still under review. 
13

Table 2: Federal and Indian Oil and Gas Production and Royalties, Fiscal Year 2012

Sales Volume Sales Value 

($ million)

Royalty 

($ million)

Federal Leases

 Oil (Bbl) 118,142,826 $10,442 $1,275

 Gas (Mcf) 2,806,572,692 $9,258 $976

 NGL (Gal) 2,839,924,280 $2,947 $298

Subtotal $22,648 $2,550

Indian Leases

 Oil (Bbl) 28,989,309 $2,441 $424

 Gas (Mcf) 256,176,345 $762 $116

 NGL (Gal) 155,313,421 $183 $21

Subtotal $3,386 $561

Source: ONRR, Federal Onshore Reported Royalty Revenue, Fiscal Year 2012 and American Indian 

Reported Royalty Revenue, Fiscal Year 2012
14

Figure 1:
15

2.7 Industry Classifications

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

Classification System (NAICS) 211. This 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.

The Small Business Administration (SBA) size standard for small businesses in the directly 

affected industries is 500 employees. Meaning, businesses operating in those industries are 

considered small businesses as long as they employ fewer than 500 people. 

Using data reported by the U.S. Census Bureau in the 2007 Economic Census, the BLM 

concludes that about 99 percent of the entities operating in the relevant sectors are small 

businesses. Also, within these relevant sectors, small firms account for 74 percent of the total 

value of shipments and receipts for services, 86 percent of the total cost of supplies, 78 percent

of the total capital expenditures (excluding land and mineral rights), and 67 percent of the paid 

employees (see Tables 3 through 7).
16

Note: Where range provided, employee data were estimated to be in middle of range

Table 3: 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 4: 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 5: 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 6: 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 7: 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%
17

2.8 Industry Standards for Well Construction and Integrity for Hydraulic 

Fracturing Operations

The American Petroleum Institute (API) published guidance on well construction and integrity 

for hydraulic fracturing operations in October 2009 (API Guidance Document HF1).

9

 Topics 

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

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

The guidance states that “although there is some variability in the details of well construction 

because of varying geologic, environmental, and operational settings, the basic practices in 

constructing a reliable well are similar. These practices are the result of operators gaining 

knowledge based on years of experience and technology development and improvement. These 

experiences and practices are communicated and shared via academic training, professional and 

trade associations, extensive literature and documents and, very importantly, industry standards 

and recommended practices.”10

Well Integrity and Protecting Groundwater and the Environment

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 

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

a production conduit within the well.”11

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.”12

Well Construction, Cementing Guidance, Pressure Testing, and Logging

Well design and construction generally have four components: conductor, surface, intermediate 

and production casing strings. The following discussion provides a general description of the 

drilling process as it relates to drilling, setting casing, cementing casing, pressure testing, and 

well logging. 

 

9 API Guidance Document HF1 “Hydraulic Fracturing Operations – Well Construction and Integrity Guidelines.”

10 Ibid, p. 1.

11 Ibid, p. 1.

12 Ibid, p. 2.
18

After the conductor pipe is installed and cemented, operators drill the surface hole to a 

predetermined length “based on consideration of the deepest groundwater resources.”

13 Some 

state regulations dictate the minimum setting depth of surface casing, but the minimum 

recommended API standard is at least 100 feet below the deepest underground sources of 

drinking water (USDW) encountered. The operator will run the surface casing into the hole and 

cement the casing in place. The API recommends that operators cement the surface casing “from 

bottom to the top, completely isolating groundwater aquifers.”14 

After waiting for the cement to reach “appropriate compressive strength,”

15 the operator should 

pressure test (commonly known as a casing pressure test) the surface casing. 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. The BLM and many states have regulations that dictate 

requirements for pressure tests.16

After a successful pressure test, the operator will drill out of the surface casing and for a short 

interval into a new formation below the surface casing shoe. The operator should then perform a 

formation pressure integrity test (also known as a ‘shoe test’ or ‘leak-off test’). “If the test 

results of the formation pressure integrity test are inadequate, remedial measures should be 

undertaken as appropriate.”17

The operator will then drill an intermediate hole, run casing, and cement the casing as 

appropriate. The goal is to “isolate subsurface formations that may cause borehole instability 

and to provide protection from abnormally pressured subsurface formations.”18 According to the 

guidance, intermediate casing may not be required in some cases, and that operators may not 

need to cement the intermediate casing back to the surface in many cases. It states that “if the 

intermediate casing is not cemented to the surface, at a minimum, the cement should extend 

above any exposed USDW or any hydrocarbon bearing zone.” Operators may run a CEL and/or 

other diagnostic tools to determine the adequacy of the cement integrity and that the cement 

reached the desired height. After the cement has achieved the appropriate compressive strength, 

operators will also pressure test the intermediate casing, drill out for a short interval, and perform 

a formation integrity test. If the test results of the formation pressure integrity test are inadequate 

or indicate a failure, remedial measures should be undertaken as appropriate.

Operators will then drill the production hole, log the hole, run production casing to the total 

depth, and cement the production casing into place. “The purpose of the production casing is to 

provide the zonal isolation between the producing zone and all other subsurface formations, for 

pumping the hydraulic fracturing fluids and other stimulation techniques from the surface into 

the producing formation without affecting any other geologic horizon in the well.”19 Cementing 

of the production casing must occur, but it may take different forms. The API guidance states 

 

13 Ibid, p. 11.

14 Ibid, p. 11.

15 Ibid, p. 11.

16 Onshore Order 2, section III(B)(1)(h)

17 API Guidance Document HF1, p. 11.

18 Ibid, p. 12.

19 Ibid, p. 12.
19

that the production string cement does not need to be run to the surface in most cases; however, 

in wells where there is no intermediate casing, cementing to the surface should be considered. It 

describes the minimum standard as running the cement to at least 500 feet above the highest 

formation where the operator will conduct hydraulic fracturing. Operators should pressure test 

the production casing and run a CBL and/or other diagnostic tools to determine the adequacy of 

the cement integrity and that the design and construction objectives were met. 

In horizontal wells, operators may choose an “open-hole” completion as an alternative to setting 

the casing through the producing formation to the total depth of the well. In this case, the bottom 

of the production casing is installed at the top of the productive formation or open-hole section of 

the well. The producing portion of the well is the horizontal portion of the hole and it is entirely 

in the producing formation. Sometimes an operator will install a short section of casing that runs 

up the production casing, but not back to surface nor to the bottom of the open hole section. An 

operator may also choose to use a production liner which is not cemented into place. A 

production liner is a slotted or perforated steel casing installed in the production hole. With an 

open-hole completion, the operator should extend the tail cement above the top of the confining 

formation.

20

 Figure 4 shows how surface casing and cement layers protect the aquifer. 

Figure 4: Diagram of a Horizontal and Vertical Well with Hydraulic Fracture Completion

Source: API Guidance Document HF1, 2009

 

20 Ibid, p. 13.
20

Well Logging

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.”21

A cement bond log “measures the presence of cement and the quality of the cement bond or seal 

between the casing and the formation.”22 Logs are important in “determining that the well 

drilling construction is adequate and achieves the desired design objectives.”23 As described 

above, it is industry practice to run logs on the production casing of wells and sometimes on the 

intermediate casing of wells. State requirements of conditions of the drilling permit may also 

necessitate the running of logs on the intermediate casing.

2.9 Industry Standards for Water Management Associated with Hydraulic 

Fracturing

The API published guidance on water management associated with hydraulic fracturing in June 

2010 (API Guidance Document HF2).24 Topics covered in the guidelines include, but are not 

limited to, water use and management, obtaining water supply, and water management and 

disposal. 

Overall, this guidance document is less prescriptive than the one on well construction and 

integrity; however, it describes the considerations and best practices for managing water 

associated with hydraulic fracturing. 

Operators generally store fluids onsite in tanks or in lined surface impoundments (or pits), prior 

to the hydraulic fracturing operation. Flowback, or the returned fluids from the operation, may 

also be directed to tanks or lined pits. Any tanks or impoundments used should comply with the 

state and Federal regulations. “If lined impoundments or pits are used for storage of fracture 

fluids or flowback water, the pits must comply with applicable rules, regulations, good industry 

practice, and liner specifications. However, it is important to recognize that storage 

impoundments containing fluids associated with fracturing operations will likely contain 

significantly larger volumes of fluids than from conventional operations.”

25

 

21 Ibid, p. 8.

22 Ibid, p. 9.

23 Ibid, p. 10.

24 API Guidance Document HF2 “Water Management Associated with Hydraulic Fracturing.”

25 Ibid, p. 18.
21

2.10 Existing Regulations Related to the Rule’s Provisions

The development and production of oil and gas, including hydraulic fracturing operations, are 

regulated under a complex set of Federal, state, and local laws. Several Federal agencies 

implement Federal laws and requirements while each state in which oil and gas is produced has 

one or more regulatory agencies that administer state laws and requirements. 

State and local laws apply on Federal lands except to the extent that they are preempted by 

Federal law. Federal preemption is rare, and is not at issue in the revised proposed proposed 

rule. Accordingly, the drilling and completion of oil and gas wells, including hydraulic 

fracturing operations, are subject both to Federal and to state and local regulation on Federal 

lands. If the requirements of a state regulation are more stringent than those of a Federal 

regulation, for example, the operator will comply with both the State and the Federal regulation 

by meeting the more stringent state requirement. 

Tribal and Federal laws apply to oil and gas drilling and completion operations, including 

hydraulic fracturing operations on tribal lands. Operators on tribal lands will comply with both 

tribal and Federal regulations governing drilling and completion requirements by assuring that 

they are in compliance with the stricter of those rules.

Regardless of any difference in operational regulations, operators on Federal lands must comply 

with all Federal, state, and local permitting and reporting requirements. On Indian lands, they 

must comply with all Federal and tribal permitting and reporting requirements. 

2.10.1 Existing BLM Regulations on Cementing Requirements

The BLM has existing casing and cementing requirements to protect usable water zones in 

Onshore Oil and Gas Order No. 2 – Drilling Operations on Federal and Indian Oil and Gas 

Leases.26 The provisions in Onshore Order No. 2 are consistent with this rule, such that 

operators drilling in compliance with Onshore Order No. 2 would be in compliance with this 

rule. An excerpt from Onshore Order No. 2 reads as follows, with emphasis added:

The proposed casing and cementing programs shall be conducted as 

approved to protect and/or isolate all usable water zones, lost 

circulation zones, abnormally pressured zones, and any prospectively 

valuable deposits of minerals. Any isolating medium other than cement 

shall receive approval prior to use. The casing setting depth shall be 

calculated to position the casing seat opposite a competent formation 

which will contain the maximum pressure to which it will be exposed 

during normal drilling operations. Determination of casing setting 

depth shall be based on all relevant factors, including:

presence/absence of hydrocarbons; fracture gradients; usable water 

zones; formation pressures; lost circulation zones; other minerals; or 

 

26 43 CFR 3160 III(B), found at 

http://www.blm.gov/wy/st/en/programs/energy/Oil_and_Gas/docs/onshore_order_2.html. 
22

other unusual characteristics. All indications of usable water shall be 

reported.

2.10.2 Existing BLM Regulations on Pressure Testing Requirements

The BLM has existing pressure testing requirements in Onshore Order No. 2 that require 

operators to pressure test all casing strings below the conductor casing (Onshore Order 2, section 

III(B)(1)(h)). Operators must also wait until cement achieves a minimum of 500 psi compressive 

strength at the casing shoe prior to drilling out (Onshore Order 2, section III(B)). It also has 

pressure testing requirements for liner seals (Onshore Order 2, section III(B)(1)(b)). 

2.10.3 Summary of Existing State Regulations

The BLM reviewed existing state regulations for consistency with the BLM rule. We examined 

existing state regulations in California, Colorado, Montana, New Mexico, North Dakota, Texas, 

Utah, and Wyoming. In 2011, the number of wellbores started (or spudded) on Federal lands in 

those states accounted for 99.4 percent of the total number of wellbores started on Federal lands 

nationwide. Table 8 shows a summary of the findings.

California

We reviewed the California Code of Regulations to the extent possible.27 California also lists 

“Field Rules” on its website that identify well construction information and requirements on an 

individual field basis. According to the Code, a division district deputy may require a cement 

bond log, temperature survey, or other survey to determine cement fill behind casing (Section 

1722.4). Pressure tests on the production casing are allowed when conducted under an 

established field rule (Section 1722.3(d)). The State has complex rules regarding the 

management of drilling waste. Generally, it allows operators to store drilling waste in pits (or 

sumps) (Section 20090(g)). Further, the state does not require an operator to obtain a pit permit 

as long as the sump is “for short-term use (less than one year) or if significant quantities of 

hazardous or toxic materials are not present in the mud, fluids and cuttings from drilling and 

associated operations” (Section 21565(b)(2)). The state has nine Regional Water Quality 

Control Boards that may also establish operating procedures. The Central Valley Regional Water 

Quality Control Board writes that “Produced water may be subject to Title 27 requirements 

where the concentration of waste constituents threatens to impact the beneficial uses of good 

quality underlying groundwater. To comply with Title 27 regulations, the oil field sumps could 

be lined. However, the industry generally chooses to drill Class II injection wells and close the 

sumps.”28 Flowback from hydraulic fracturing operations is likely to be treated like produced 

 

27 California Code of Regulation was accessed on December 9, 2012: 

ftp://ftp.consrv.ca.gov/pub/oil/publications/PRC04_January_11.pdf.

28 Groundwater Quality Protection Strategy - A “Roadmap” for the Central Valley Region at p. 43, August 2010. 

Accessed on March 29, 2013: 

http://www.waterboards.ca.gov/centralvalley/water_issues/groundwater_quality/final_draft_gwq_strategy_strike.pdf
23

water and manage in lined sumps, if it is not re-injected. California has chemical disclosure 

provisions related to its Spill Contingency Plan Requirements (Section 1722.9) in the context of 

operators maintaining a plan, but the provisions are not for public disclosure.

Colorado

We reviewed the Colorado Oil and Gas Commission (COGCC) rules, particularly the “200 

Series General Rules” and “300 Series Drilling, Development, Production and Abandonment.”

29

 

The COGCC does not require cement evaluation logs on the surface casing. It requires operators 

to run a cement bond log on all production casing or on the intermediate casing, if a production 

liner is used (Rule 317(O)). It requires pressure testing of the production casing prior to 

operations (Rule 317(J)). The rules also specify that the cement behind the surface and 

intermediate casing should be allowed to set for a minimum of 8 hours or until it achieves 300 

psi of compressive strength (Rule 317(H)). Pits must be lined to various specifications (Rule 

904). The State has proposed a rule that would require management of flowback in storage tanks 

(CO House Bill 12-1173) unless the COGCC permits a lined pit.30 Operators must disclose 

chemicals used after the hydraulic fracturing operation (Rule 205A).

Montana

We reviewed Montana’s rules governing oil and gas conservation.31 We found no sections in the 

regulation that require operators to conduct cement evaluation logs on any of the casing strings. 

The regulation prohibits operators from conducting any tests until the cement (for each casing 

string) has set for at least 8 hours (36.22.1001(2)). Production strings must be cemented and 

pressure tested (36.22.1001(1)). The regulation requires operators to use lined pits or tanks. 

Specifically, it states, “Waste oil, oil sludge, tank bottoms, merchantable oil, petroleum products, 

hazardous wastes, or hazardous or deleterious substances must not be stored, disposed of, or 

retained in earthen storage pits or in open vessels” (36.22.1207). It also requires the chemical 

disclosure of well stimulation fluids (Section 36.22.1015).

New Mexico

We reviewed the New Mexico Oil Conservation Commission (NMOCC) regulations, namely 

“Chapter 15 Oil and Gas.”32 We found no sections in the regulation that require operators to 

conduct cement evaluation logs on any of the casing strings. However, after cementing casing 

strings and before conducting any tests, the regulations require operators to let the cement stand 

for a minimum of 18 hours, except in some counties where 8 hours is allowed (19.15.16.10(G)). 

Operators must pressure test the casing strings (19.15.16.10(I)). 

 

29 COGCC rules were accessed on December 9, 2012: http://cogcc.state.co.us/RR_Docs_new/Rules_new2.html.

30 The introduced Colorado House Bill was accessed on March 16, 2013: 

http://www.leg.state.co.us/clics/clics2012a/csl.nsf/fsbillcont3/2E1C7B05EB7436E787257981007F436A?open&file

=1173_01.pdf.

31 Montana rules were accessed on December 9, 2012: 

http://www.mtrules.org/gateway/ChapterHome.asp?Chapter=36.22.

32 NMOCC rules were accessed on December 9, 2012: 

http://www.emnrd.state.nm.us/OCD/documents/SearchablePDFofOCDTitle19Chapter15created3-2-2012.pdf.
24

New Mexico has comparatively stricter requirements on pits. Operators may apply for a permit 

to use a lined pit or a “below-grade” tank; however, absent an approved permit, operators must 

use a closed-loop system or other approved method (19.15.17.8). The regulations also have 

disclosure provisions after the well completion (19.15.16.19(B)).

North Dakota

We reviewed the North Dakota Rules and Regulations, particularly Section II General Rules.33 

All strings of surface casing must set for at least 12 hours before drilling the plug or initiating 

tests (43-02-03-21). Each casing string must be pressure tested (43-02-03-21). If any well 

appears to have defective casing or cementing, the operator must report the defect to the director 

and must receive approval from the director before attempting remedial work (43-02-03-22). 

The director is authorized to require a pressure test to verify the casing integrity. The regulations 

require operators to run cement evaluation logs on the intermediate and production casings (43-

02-03-31).

The regulations have a specific section for hydraulic fracturing operations at 43-02-03-27.1. For 

hydraulic fracturing performed through an intermediate casing, an operator must use a cement 

evaluation log to verify adequate cementing of the intermediate casing (43-02-03-27.1(2)(c)). 

The intermediate casing and the wellhead must be pressure tested (43-02-03-27.1(2)(d) and (e)). 

The rules allow operators to use “lined earthen pits” to temporarily retain oil, water, cement,

solids, or fluids generated in well completion, servicing, or plugging operations (43-02-03-19.3). 

The rules also have a provision for public disclosure to FracFocus ((43-02-03-27.1(1)(g)). 

Texas

The Texas Railroad Commission (TRC) is the state regulatory authority.34 The TRC does not 

appear to have logging requirements on casing strings under normal circumstances. If cement 

does not circulate to surface behind the surface casing, then the operator must receive approval 

from the district director for procedures to be used to perform additional cementing operations 

(§3.13(b)(2)(B)). The TRC requires operators to conduct a temperature survey log or cement 

bond log on the surface casing for alternate casing programs where the cement is not circulated 

to the ground surface (§3.13(b)(2)(G)(iii)). 

The TRC requires operators to pressure test all strings of casing before drilling the cement plug 

(§3.13(b)(1)(D)). The TRC prohibits the use of pits for the storage of “oil and gas wastes” and 

“oil field fluids” (§3.8(d)(2)); however, an operator may request a permit to use a pit, lined or 

unlined. The TRC requires operators to disclose the chemical content of hydraulic fracturing 

fluids following the operation (§3.29).

Utah 

 

33 North Dakota rules were accessed on December 9, 2012: https://www.dmr.nd.gov/oilgas/rules/rulebook.pdf.

34 The Texas Administrative Code for the TRC was accessed on December 9, 2012: 

http://info.sos.state.tx.us/pls/pub/readtac$ext.ViewTAC?tac_view=4&ti=16&pt=1&ch=3&rl=Y.
25

We reviewed Utah Oil and Gas Conservation rules, particularly rule R649-3, Drilling and 

Operating Practices.35 We found no evidence of requirements for operators to run logs to 

evaluate the cement behind casing strings. The regulations require operators to perform a 

pressure test on casing before drilling out of any casing string, suspending drilling operations or 

completing the well (R649-3-13 Casing Tests).

Utah has specific regulations regarding hydraulic fracturing at R649-3-39. The section reiterates 

provisions described previously. Operators must conduct pressure tests on the well’s casing 

string set (per R649-3-13). Utah requires lined pits or storage tanks (R649-3-16). Operators 

must disclose the chemicals used to FracFocus after the completion (R649-3-39(1)). 

Wyoming

We reviewed the Wyoming Oil and Gas Conservation Commission (WOGCC) rules, particularly 

Chapter 3 of the code, titled “Operational Rules, Drilling Rules.”36 The regulations do not 

require operators to conduct cement evaluation logs under normal circumstances. However, the 

Supervisor may require operators run “cased hole bond logs” for casing strings to demonstrate 

cementing across and above the productive intervals or above the last casing shoe in the well, “if 

there is a demonstrated reason to believe an inadequate cement job was performed” (at Ch. 3 

Section 22(a)(i)). Operators are required to pressure test the production string (at Ch. 3 Section

22(a)(v)). The Supervisor also has broad authority to require operators to conduct tests or 

surveys, including on the formation, casing, tubing, or other pressures (at Ch. 2 Section 6(a)). 

Section 45 of the chapter lists the requirements for well stimulation activities. Operators must 

submit a Sundry Notice to the WOGCC prior to any well stimulation activity. Prior to the well 

stimulation, the Supervisor also may require the operator to “perform a suitable mechanical 

integrity test of the casing or of the casing-tubing annulus or other mechanical integrity test 

methods” (Section 45(a)). The section requires operators to use storage tanks or lined pits to 

manage flowback (at Section 45(j)) and it requires operators to disclose the contents of hydraulic 

fracturing fluids proposed for the operation (Section 45(d)) and, after the operation, the contents 

of the fluids actually used (at Section 45(h)).

 

35 Utah rules were accessed on December 9, 2012: http://oilgas.ogm.utah.gov/Rules/Rules.htm.

36 WOGCC rules were accessed on December 9, 2012: http://soswy.state.wy.us/Rules/default.aspx.
26

Table 8: State Regulations Covering Requirements in the Revised Proposed Rule

State

Percent of 

wellbores 

started on 

Federal lands 

in 2011

CEL on 

Surface 

Casing

CEL on 

Intermediate 

Casing

CEL if 

Inadequate 

Cement 

Job

Mechanical 

Integrity 

Test or 

Pressure 

Tests

Minimum 

Requirement 

for Storage 

Tanks

Minimum 

Requirement 

for Lined 

Pits

Chemical 

Disclosure

California 13% Authority 

to request

Authority to 

request

No, but 

authority to 

request

Depends on 

the field 

rule

No Generally No

Colorado 14% No No, unless 

using a 

production 

liner

No Yes No Yes Yes

Montana 1% No No No Yes No Yes Yes

New 

Mexico

22% No No No Yes Yes, unless 

approved to 

use lined pits

N/A unless 

approved

Yes

North 

Dakota

4% No Yes No, but 

authority to 

request 

pressure 

test

Yes No Yes Yes

Texas 1% No No No Yes Yes, unless 

approved to 

use pits

N/A Yes

Utah 13% No No No Yes No Yes Yes

Wyoming 32% Authority 

to request

Authority to 

request

No, but 

authority to 

request

Yes No Yes Yes
27

3. Estimating Benefits and Costs

3.1 Theoretical Framework

This analysis estimates the potential costs and benefits that would occur as a result of the rule. 

As such, it estimates the impacts in relation to the current operating environment (or the 

baseline). 

In analyzing costs and benefits of the rule, it is important to differentiate between the activities 

that operators currently conduct and those additional activities that the rule would compel. This 

change in behavior is the basis of the cost and benefit estimates.

OMB Circular A-4 recognizes that not all benefits and costs can be described in monetary or 

even in quantitative terms. In those cases, it directs agencies to present any relevant quantitative 

information along with a description of the unquantified effects.

3.1.1 Measuring the Incremental Change

Many of the provisions in the rule are conducted voluntarily by operators as a matter of company

practice or standard industry practice. Operators have a vested interest in ensuring that wells are 

constructed properly to avoid problems that might jeopardize their investment. As a matter of 

industry practice, operators typically do the following:

Develop a plan for the hydraulic fracturing operation;

Monitor the cementing processes;

Cement casing protecting water zones;

Conduct pressure tests on casing strings during the drilling process or before 

hydraulic fracturing operations;

Maintain drill logs identifying usable water zones;

Run CBLs and/or other evaluation logs on the production casing and sometimes on 

the intermediate casing, if there are formations of interest higher than the producing 

zone or to maintain compliance with state regulations, state permit requirements, or 

Federal permit requirements;

Monitor annulus pressures during the hydraulic fracturing operation; and 

Manage the flowback of fluids.

Some practices required in the rule are already conducted by operators in order to comply with 

existing applicable state regulations or requirements. Such state regulations often dictate how an 

operator cements a well, what tests or logs it conducts, how it handles flowback, or whether it

must disclose the chemical contents of the hydraulic fracturing fluid. In addition to regulations, 

states may place requirements in the drilling permits as conditions of approval. For example, as 

a condition of approval for a particular permit, a state may require an operator to use tanks to 

store flowback even if the state has regulations allowing the use of lined pits.
28

Some of the provisions in the rule are also consistent with existing Federal requirements. As 

such, operators on Federal and Indian lands are already in compliance with those provisions, and 

therefore the rule does not pose an additional burden. For example, the BLM has casing and 

cementing requirements to protect and/or isolate usable water zones, found in Onshore Order No. 

2, that are consistent with the final rule. Operators on Federal and Indian leases that are drilling 

in compliance with Onshore Order No. 2 would also be in compliance with this rule, and so 

accordingly, the rule poses no additional burden for casing and cementing operations, but it does 

require testing and reporting to evaluate the protection/isolation of those zones. Like state

regulatory authorities, the BLM or a tribe may also place requirements on operators as a

condition of approval for the drilling permit. 

Where appropriate and possible, the analysis does not consider impacts in areas where operators 

already adhere to the rule’s provisions as a matter of voluntary practice or regulatory compliance 

with existing Federal, tribal, or state regulations or requirements in conditions of approval.

3.1.2 Costs Framework

To examine the costs of the rule, the analysis considers the number of hydraulic fracturing 

operations that would be subject to the various requirements (referred to as “subject activity”) 

and the costs of the various requirements. While the rule would apply to all hydraulic fracturing 

operations on Federal and Indian lands, specific provisions in the rule may only apply to a subset 

of those operations. For example, the rule requires SR Sundry submissions for all hydraulic 

fracturing operations, but the number of required NOI Sundry requests and the CELs conducted 

would be fewer. 

The three key components to the cost formulation are the estimated number of hydraulic 

fracturing operations, the applicability of provisions to those operations, and the compliance 

costs to satisfy the provisions. Lower estimates in either of these areas would lead to lower

estimates of the total costs of the rule. Likewise, higher estimates would lead to higher estimated 

total costs.

Protecting usable water: The BLM has existing casing and cementing requirements to protect

and/or isolate usable water zones, found in Onshore Order No. 2. As such, the rule does not pose 

an additional burden to operators.

Pressure Testing Requirement: The pressure testing requirement is consistent with standard 

industry practice, state regulations, and BLM regulation Onshore Order No. 2. As such, the 

requirement does not pose an additional burden to operators.

Pit liner or storage tank requirement: The requirement to manage flowback in lined pits or 

storage tanks is consistent with almost all existing state regulations in states where new oil and 

gas activity is occurring on BLM-managed lands. As such, the requirement would only pose an 

additional burden to operators on Federal and Indian leaseholds in states or on Indian lands

without existing requirements and who are not voluntarily in compliance.
29

Storage tank requirement: We examine an alternative that would require operators to manage 

flowback in storage tanks (or often referred to as “closed-loop” systems). Closed-loop systems 

in which fluids are never exposed to the elements have been acknowledged as an 

environmentally-sound method of waste storage.37 A report from members of the US House 

Committee on Natural Resources expressed support for prohibiting the use of open pits in favor 

of closed-loop systems, writing, “the use of pits to capture or dispose of flowback water can 

result in greater surface disturbance and a higher risk of leaks and spills, which threatens soils, 

groundwater, surface water and wildlife. Pits can also be a significant source of hazardous and 

toxic air pollution.”38

Closed-tank storage is regarded as a best management practice by many oil and gas companies39

(as well as by many states) and minimizes the potential for spill.40 The practice is particularly 

prevalent in the Eastern U.S. and is being incorporated into standards for model shale 

development.41 Colorado has proposed legislation to mandate closed-loop systems unless the 

COGCC grants a permit for a lined pit. Several other states, including New Mexico and Texas 

generally require closed-loop systems but allow operators to apply for permits to use pits. 

The prevalence of closed-loop systems is uncertain, and the BLM requests comment and 

information in the preamble of the proposed rule about the use of closed-loop systems or storage 

tanks. We are particularly interested in the prevalence of closed-loop systems in western states 

without such requirements but where they are voluntarily used as best practice. 

The use of storage tanks to manage flowback also tends to vary by operators and the regions in 

which they operate. It has been documented that about 60 to 70 percent of flowback is recycled 

in Marcellus Shale wells,42 but it is unclear the extent to which that recycling is done with 

closed-loops systems or open pits, or if there is other flowback not recycled that is being 

managed with closed-loops systems. For example, EOG Resources manages all flowback in 

lined storage tanks for wells in the Marcellus Shale, but injects it into permitted disposal wells in 

 

37 NRDC writes, “Flowback and produced water should be collected at the well and either recycled or directly 

routed to disposal. In the event that storage of wastewater is necessary, it should be done in closed tanks.” Hammer, 

R. and VanBriesen, J., “In Fracking’s Wake: New Rules are Needed to Protect Our Health and Environment from 

Contaminated Wastewater”, NRDC, May 2012.

38 Letter from Reps. Markey, Holt, Sablan, Napolitano, Tonko, Grijalva to Sec. Salazar, U.S. House of 

Representatives Committee on Natural Resources, September 10, 2012. 

39 For example, Chief Oil and Gas eliminated the storage of recovered fluids in open reserve pits and moved all 

operations to a closed-loop drilling process in 2010. http://www.chiefog.com/newsletters/1110/index_111610.html

40 Presentation “Shale Gas Flowback Water Treatment, Reuse, and Disposal” by Dave Yoxtheimer, P.G. Accessed 

March 16, 2013, 

http://www.acus.org/files/EnergyEnvironment/BrusselsWorkshop/Yoxtheimer_Produced%20and%20Flowback%20

Water.pdf

41 Center for Sustainable Shale Development website. Accessed March 29, 2013, 

http://037186e.netsolhost.com/site/performance-standards/

42 Data from two sources: 1) Marcellus Shale Coalition. Accessed March 16, 2013, 

http://www.prnewswire.com/news-releases/marcellus-shale-coalition-releases-the-facts-on-flowback-watertreatment-83561557.html. 2) Presentation “Shale Gas Flowback Water Treatment, Reuse, and Disposal” by Dave 

Yoxtheimer, P.G. 
30

Texas Barnet Shale.43 WPX Energy recycles 100 percent of its flowback and produced water in 

the Piceance Basin but it uses centralized open pits.44

Though tanks are reported to be more expensive than open pits upfront, companies and states 

make an economic argument for favoring closed-loop systems over open pits. The New York 

Department of Environmental Conservation, for example, writes, “Tanks, while initially more 

expensive, experience fewer operational issues associated with liner system leakage. In addition, 

tanks can be easily covered to control odors and air emissions from the liquids being stored. 

Precipitation loading in a surface impoundment with a large surface area can, over time, increase 

the volumes of liquid needing treatment. Lastly, above ground tanks also can be dismantled and 

reused.”45

It also found that closed-loop tank system can offer the following advantages, depending on the 

design:

46

Eliminates the time and expense associated with reserve pit construction and reclamation;

Reduces the surface disturbance associated with the well pad;

Reduces the amount of water and mud additives required as a result of re-circulation of 

drilling mud;

Lowers mud replacement costs by capturing and re-circulating drilling mud;

Reduces the wastes associated with drilling by separating additional drilling mud from 

the cuttings; and

Reduces expenses and truck traffic associated with transporting drilling waste due to the 

reduced volume of the waste.

Other groups have argued that closed-loop system requirements are expensive to build and 

obtain. For example, the Independent Petroleum Association of New Mexico (IPANM) argued 

that the New Mexico rules restricting pits increased industry drilling costs by more than 

$200,000 per well.47 

The BLM believes that the additional upfront cost of using a closed-loop system (instead of an 

open pit) will vary depending on the design or setup. Different operations are likely to have 

differing capacity requirements due to the volume of fluid using in the operation, the expected 

volume of flowback, and the purpose of the storage tank (e.g. whether it just captures the 

flowback or is used to as part of a water management system for the site to recycle flowback for 

use in operations on subsequent wells).

 

43 EOG Resources website. Accessed March 16, 2013, 

http://www.eogresources.com/responsibility/water_management.html

44 WPX Energy website. Image depicts a water management system with an open pit. Accessed March 16, 2013, 

http://www.wpxenergy.com/environment/water.aspx 

45 Revised Draft SGEIS on the Oil, Gas and Solution Mining Regulator Program, New York Department of 

Environmental Conservation at p. 7-61, September 2011. http://www.dec.ny.gov/energy/75370.html

46 Ibid at 5-39.

47 IPANM brief on New Mexico’s Pit Rule. Accessed March 16, 2013, 

http://www.ipanm.org/images/library/File/Pit-Rule.pdf
31

The BLM contacted two companies that rent large volume storage tanks used for hydraulic 

fracturing. The length of the rental would vary depending on the design.48 One company 

serving eastern operations quoted a price of $220 per 300 bbl tank for a 10-day rental. A second 

company serving operations in Colorado quoted a price of $50 per 500 bbl tank per day. We 

also contacted a company that sells storage tanks for use in multiple fracturing operations. The 

company manufactures tanks with capacities ranging from 5,000 to 500,000 gallons. A single 

50,000 gallon tank would cost about $25,000 or a single 210,000 gallon tank would cost about 

$105,000. According to the company, the tanks could be reused for 5 to 7 years.

If pits are designed to hold only flowback from an operation before being trucked off-site, then 

the replacement tanks required would need to be of a capacity to hold only that flowback, or 

about 15 to 40 percent of the volume of fluid injected.49 Assuming a 1.2 million gallon 

fracturing job and different amounts of flowback,

50 renting storage tanks to handle the flowback 

only would cost between about $6,000 to $17,000 per operation.

51 Or consequently, though it 

makes less sense logistically, a company might purchase storage tanks for $100,000 to $250,000, 

depending on the flowback expected, and reuse the tanks for multiple hydraulic fracturing 

operations. 

For companies that use a centralized pit and recycle the flowback (and produced water) for use in 

operations on multiple wells, we would expect them to require tanks with sufficient total 

capacity to handle all of the fluid used in the operations. Assuming a 1.2 million gallon 

fracturing job, we estimate that the rental of storage tanks could cost about $42,000 per well.

Purchasing storage tanks to meet that capacity could cost about $600,000, but the operator could 

use those storage tanks for multiple hydraulic fracturing operations.

The use of storage tanks instead of pits does not necessarily mean that the operator would avoid 

costs associated with digging pits. Often, operators will construct berms and other barriers as 

secondary containment for storage tanks. Operators are expected, however, to experience longer 

term cost savings from avoided remediation of spill events, though such cost savings is difficult 

to quantify for the average operation.

The BLM requests comment and information in the preamble to the proposed rule about the 

costs of using closed-loop systems or storage tanks instead of open pits.

Cement evaluation logs on casing strings that protect usable water: The rule has a provision to 

conduct CELs on the casing strings that protect usable water. The applicable casing strings 

include the surface casing and sometimes the intermediate casing. Operators do not typically run 

CELs to evaluate the cement behind the surface casing, so the rule would require an additional 

step in the drilling process. Not all wells require intermediate casing, and wells that require 

 

48 Most of the flowback comes within 7 to 10 days, with the total volume occurring over 3 to 4 weeks. 

49 WikiMarcellus. Accessed March 16, 2013, http://waytogoto.com/wiki/index.php/Flowback_water

50 Encana reports that fracturing in the DJ Basin, Colorado requires approximately 1.2 million gallons of water per 

well. Encana. April, 2011. “Well Completion & Hydraulic Fracturing.” 

51 For company 1, costs calculated assuming two rental periods required. For company 2, costs calculated assuming 

a rental period of 14 days.
32

intermediate casing may do so for reasons other than to protect usable water.52 The rule would 

only compel CELs on intermediate casing that protects usable water, and further, on those 

intermediate casings where the operator would not otherwise conduct a CEL in compliance with 

state regulations or conditions of approval or do so voluntarily.

53

 

Subsequent wells under a type well approval: Under the rule, the number of wells requiring NOI 

Sundry submissions and subject to the CEL requirements should reflect that number of CELs on 

single wells and on type wells, but not subsequently drilled wells under a type well approval. 

Requiring a CEL when there is an indication of inadequate cementing: Under the rule, 

operators on all wells (single wells, type wells, and subsequent wells to a type well) are required 

to run a CEL when there is an indication of inadequate cementing of a casing string that protects 

usable water. The BLM and many state regulations and requirements have established protocol 

for remedial actions in the event of inadequate cementing, which require operators to remediate 

and/or take action as directed by the regulatory authority. For example, Onshore Order 2 

requires that operators perform remedial cementing if cement is not circulated back to the surface 

for the surface casing (section III.B.1.c). Onshore Order 2 also requires an additional pressure 

test and/or remedial action as specified by the authorized officer if a pressure test indicates that 

casing strings do not meet minimum standards (section III.B.1.h). Onshore Order 2 lists other 

minimum standards and corrective actions, including some that require logging or testing,

remedial cementing, and actions specified by the authorized officer. Subject activity for the

requirement to conduct a CEL under the revised proposed rule should reflect the prevalence of 

inadequate cement jobs. 

Measuring the costs of a CEL: The rule introduces a new step (or steps) to the drilling process, 

depending on the well. This new step potentially poses an additional cost burden to operators for 

the costs of the CEL and the costs to maintain idle drilling equipment if the drilling process is 

delayed.

After cementing casing, operators must wait for a period of time for the cement to harden before 

conducting any well tests and drilling the plug. The BLM requires operators to wait until the 

cement at the casing shoe reaches a compressive strength of 500 psi. States generally have 

compressive strength standards similar to the BLM. For example, the state of Montana requires 

operators to wait 8 hours and New Mexico requires operators to wait anywhere from 8 to 18 

hours. 

While waiting for the cement behind the surface casing to set, operators will install other 

required equipment on the well, including blowout preventers. After the cement has hardened 

sufficiently and the operator has satisfied Federal or state requirements, operators would 

normally conduct a pressure test on the surface casing, drill through the plug, drill for an 

additional interval into the formation, and then test the shoe. After a successful shoe test, 

 

52 Other reasons may include to control pressure during lost circulation zones, for hole stability (e.g., against clay 

swelling), for isolation through salt zones, or for isolation through disposal zones.

53 North Dakota requires cement bond logs to be run on this string, while Colorado requires it in some cases. In 

addition, some states and the BLM may place requirements to conduct logs on the intermediate casing as conditions 

of approval in the individual drilling permits.
33

operators then drill the intermediate hole. The process is generally the same for the intermediate 

casing; however, operators may also run a log on the intermediate casing depending on the 

circumstances described before.

We received many comments on the initial proposed rule suggesting that, by requiring CBLs, the 

rule would force all operators to maintain idle drilling equipment while the cement reached 

additional compressive strength sufficient for a CBL to show meaningful results. At issue is the 

idea that an operator would need to wait an additional amount of time before pressure testing the 

casing or drilling through the plug. 

An operator does not necessarily have to stand idle at this point in time. For example, an 

operator may pressure test the surface casing, drill out the plug, test the shoe, and then drill the 

intermediate hole. They may then run a CEL at any point in time before they set the 

intermediate casing, for example, while replacing a drill bit. In any of these scenarios, there 

could still be ancillary delays associated with the availability of the logging company and the 

time required to run the log.

Operators drilling multiple wells on a pad should also be able to run a CEL and avoid potential 

drilling delays. When drilling multiple wells on a pad, an operator may use a smaller drilling rig

(sometimes called a “double” rig) to sequentially drill a casing hole, set casing, and cement 

casing of each well, one by one.

54

 After the surface holes have all been sequentially drilled, 

cased, and cemented, the operator will remove the small drilling rig from the pad, and bring in a 

large drilling rig to drill the subsequent sections of each well. If an operator is drilling multiple 

wells in this fashion, then it may continue the drilling process while the cement sets on the first 

well, and log that well at the operator’s convenience. Thus, in those situations, the operator 

would incur no additional costs associated with maintaining idle drilling equipment.

3.1.3 Benefits Framework

The potential benefits of the rule are more challenging to monetize than the costs, but that does 

not mean that rule is without benefits. The rule is designed to reduce the environmental and 

health risk posed by hydraulic fracturing operations, particularly in its treatment of flowback

fluids, well construction, and hydraulic fracture design. 

The primary challenge in monetizing benefits lies in the quantification of a risk that is largely 

unknown. Risk is the product of the likelihood of an incident occurring and the impact that will 

be incurred. Or in this context, risk is the probability of an incident occurring from hydraulic 

fracturing times the cost of the damage. 

Thus, the potential and monetized benefit would be the reduction in risk attributed to the rule, 

which also represents the avoided costs of remediating damage. Because monetization of the 

risk reduction associated with potential wellbore integrity and other facets of hydraulic fracturing 

 

54 A double rig may also drill the intermediate hole depending on the depth, but for the purpose of this illustration 

we describe it as drilling the surface hole. 
34

is a difficult issue, this analysis discusses the avoided cost of remediation as a proxy for social 

benefits. 

Though operators are required to remediate damage when it occurs, there may be uncertainty 

about the true value or extent of the damage or limitations in connecting an incident with an 

operation. Even if the damage is internalized, and as long as the compliance costs are less than 

the damage costs, the overall benefit to society would be less than if the incident was avoided, 

since resources would have been unnecessarily dedicated to the remediation.

Operators are required to notify the BLM when undesirable events occur. Undesirable events 

may include accidents, or accidental spills or releases of hydrocarbon fluids, produced water, 

hydraulic fracturing flowback fluids, or other substances. These events have the potential to 

adversely affect public lands and other important resources. 

There are limitations in using the BLM data on undesirable events for this analysis. First, the 

data do not specify whether the undesirable events occur as a result of hydraulic fracturing 

operations. In addition, the available data cannot be readily matched with particular provisions 

in the rule. The data provide figures for the incidence of spills, accidents, injuries, and other 

impacts on a well, but the pit liner information is generally not specified in the incident reports 

for spills or leaks. As such, there is difficulty in quantifying the level of risk reduction that 

would be attributed to the regulations, even though the regulations would most certainly reduce 

risk.

Damage, in general, is unknown, particularly when attempting to generalize damage costs which 

may vary by expected magnitude and reversibility of effects. Also, the valuation of the damage

may also take many and highly variable forms. For example, an undesirable incident occurring 

during hydraulic fracturing might require the remediation of surface or subsurface areas. The 

incident might also require that the operator shut-in temporarily or plug the well before it may 

produce all of the mineral resources. In this case, the operator would lose revenue and society 

would not benefit from the produced resources. Such would be the same for spills.

Measuring various implications of incidents: The following is an example of an event that 

occurred in 2012 when a hydraulic fracturing operation on one Federal well affected another 

Federal well. The incident occurred on November 20, 2012, in Lea County, New Mexico.55 The 

fracture path of the first well intercepted the fracture path of the second well, pushing produced 

fluids through the second well and its associated equipment such as the separator and an open top 

fiberglass tank. The open top fiberglass tank overflowed into an unlined firewall. The firewall 

was over-topped and fluids ran into a pasture. The fluids also entered a second facility via flow 

lines and over-topped an open fiberglass tank to overflow into an unlined containment berm. 

The majority of fluids, 1,220 barrels consisting primarily of fracturing fluids, were contained 

within unlined firewalls and inside two 210 barrel open top fiberglass tanks. About 60 barrels of 

oil ran into a pasture on the well location of the second well. 

 

55 The Carlsbad Field Office submitted an Initial Report for the major undesirable event, occurring on lease 

NMNM0631.
35

In order to control the event, the fracturing job had to be shut in. The active wells in the area 

were also shut in. The surface damage included less than 0.1 acre of pasture land, and the 

removal and disposal of the material inside the two firewalls. Vacuum trucks picked up all of the 

standing fluids. The impacted surface material was removed for sampling, site delineation, and 

remediation. The fracturing operation was in the 9th stage of an 11-stage job. 

This incident illustrates the difficulty in estimating benefits. The environmental damage 

included potential surface contamination and subsequent remediation efforts, and most of the 

environmental damage appears to have been remediated by the operator.

Aside from the environmental damage, there were several economic impacts. The well 

conducting the hydraulic fracturing operation was shut-in. The incident affected other wells 

which were also shut in. It is unclear what damage was done to the wellbore of the second well 

or how long it would be shut-in until it could produce again. The well causing the incident was 

in the 9th stage of an 11-stage fracturing job. This means the operator had completed two stages 

and was on the third, leaving 8 stages remaining to be fractured.

56

 It is uncertain at this time if 

the operator would have to forego stages of the operation, and if so, what the volume of the 

unrecoverable resources from those foregone stages would be. The unrecovered resources 

reduce social benefit.

The incident also illustrates the difficulty in attributing an exact level of risk reduction to the 

rule. This incident may or may not have been avoided had the rule been in place, as the rule 

would require operators to provide information about the proposed lengths, heights, and 

directions of fractures. Ideally, these and other information would have indicated that the 

fracture plan was inadequate. 

3.2 Data

Number of Hydraulic Fracturing Operations: This analysis divides the number of hydraulic 

fracturing operations into three categories, since provisions of the rule may apply differentially. 

Estimates are provided in Table 9.

Hydraulic fracturing operations on newly drilled wells: The BLM estimates that 90

percent of newly drilled wells will be completed using hydraulic fracture.57 We first 

estimated future applications for permit to drill (APD) approvals using Energy 

Information Administration (EIA) commodity price projections in the Annual Energy 

Outlook (AEO) 2012. We then estimated the number of well completions by examining 

the relationship between the number of approved APDs and number of well completions. 

The well completion data came from the BLM’s Automated Fluid Minerals Support 

System (AFMSS). APD data came from BLM oil and gas statistics. We estimate the 

 

56 The stages of fracturing operations are numbered such that stage 1 is actually the last to be fractured. 

57 According to a survey by the API and ANGA, 94% of gas well completions in 2010 and the first half of 2011 

were with hydraulic fracturing (Shires and Lev-On 2012, p. 8). This figure may not represent the oil and gas well 

completions on Federal and Indian lands since activity on non-federal and non-Indian lands may be driving that 

figure. 
36

number of hydraulic fracturing operations on newly drilled wells on Federal and Indian 

lands to range between about 3,400 and 3,900 per year over the next 10 years. 

Hydraulic fracturing operations on existing wells: Operators may conduct hydraulic 

fracturing operations on previously producing wells. Often, the operator will drill deeper 

and/or laterally to reach other pay zones. AFMSS data show that, between 2003 and 

2011, on Federal and Indian lands the average number of well completions on deepened 

wells was 28 per year. The range was 18 to 54 completions.

Refracturing operations: Operators may also conduct refracturing operations which are 

designed to identify and recomplete underperforming wells. The American Petroleum 

Institute (API) and the American Natural Gas Alliance (ANGA) conducted a nationwide 

survey and estimates that the refracture rate ranges from 1.6 percent to 2.3 percent for 

unconventional wells.58 Of the wells in regions where most of activity on BLM-managed 

lands occurs, the refracture rate is slightly higher at 3.0 percent.

59

 We applied the 3.0

percent refracture rate to the annual totals for the operations on newly drilled wells and 

operations on existing wells to estimate the number of refracturing operations. As such, 

we estimate annual the number of refracturing operations on Federal and Indian lands to 

range between about 100 and 120 over the next 10 years. 

Subject Activity for Specific Requirements in the Revised Proposed Rule: Many of the 

requirements of this rule are currently conducted by operators as a matter of general practice, 

standard industry practice, or in compliance with existing state or Federal regulations, 

requirements, or conditions of approval for specific drilling permits. Estimates are provided in 

Table 10.

Protection of usable water: The BLM’s existing regulation, Onshore Order No. 2, has 

provisions for the protection of usable water that are consistent with the provisions in this 

rule.60 As such, there should be no additional subject activity related to compliance with 

this provision of rule.

Mechanical integrity tests (or pressure tests): As described previously, operators 

conduct pressure tests on casing strings when drilling wells as a matter of standard 

practice. The BLM has pressure testing requirements in Onshore Order No. 2 and other 

requirements for operators to “demonstrate the mechanical integrity of the downhole 

equipment” in 43 CFR 3162.4-2(b). In addition, we examined the regulations in 8 states 

where new drilling activity is most prevalent on Federal lands and found that those states 

have existing requirements for operators to conduct pressure tests when drilling wells. 

As such, there should be no additional subject activity related to compliance with this 

provision of the rule.

 

58 Shires and Lev-On 2012, p. 23.

59 Calculated from the survey information for the Mid-Continent, Southwest, and Rocky Mountain regions. The 

survey data is listed in Table 9 on p. 20.

60 After proposing the rule in May 2012, we received public comments suggesting that the rule’s provisions would 

require operators to conduct additional cementing. A response to those comments are in the preamble.
37

Cement evaluation logs on casing strings that protect usable water: The rule would 

require operators to run cement evaluation logs on the casing strings that protect usable 

water. Practically, this provision applies to new wells and not wells approved as a group 

conforming to a successful type well, existing wells, or wells being refractured.

61

 

o CELs on the surface casing: To estimate the number of logs that the rule would 

compel, we examined the extent to which subsequent wells would likely fall 

under type well approval. Using AFMSS well completion data from the past 5 

years,62 we looked at 3 different potential groupings of wells within geologic and 

geographic areas: by case, by field, and by township. We found that operators 

completed an average of 5.067 wells in a case, 12.572 wells in a field (or pool), 

and 13.289 wells in a township. The distribution of wells in each category is 

positively skewed, meaning the average is greater than the median (of midpoint 

value of the data) or that some of the observations have a large number of wells 

and those observations are pushing the average higher. For the purpose of 

analyzing the application of the type well rule provision, we believe that the field 

grouping is most appropriate, because it is based on geologic characteristics. 

o CELs on intermediate casing: Not all wells require intermediate casing and 

wells that require intermediate casing may do so for reasons other than to protect

usable water.63 The rule would only compel cement evaluation logs on 

intermediate casing protecting usable water. Based on field experience, we 

anticipate that only about 5 percent of wells have intermediate casing to protect 

usable water. Further, the rule would only compel CELs on these wells where the 

operators do not otherwise conduct these logs. As detailed earlier, state 

regulations in North Dakota require logs on the intermediate casing.

64

 

Accordingly, we further reduce the expected number of CELs compelled by 4

percent.

65

o CELs where there is an indication of inadequate cementing: The number of

wells where there is an indication that the initial cement jobs require repairs is 

generally believed to be between 1 and 5 percent.66 We use the midpoint of the 

 

61 Operators proposing to hydraulically fracture an existing well (one drilled prior to the effective date of the rule) 

cannot practically comply with the cement evaluation log requirement of the rule, as it pertains to logging the 

surface casing and possibly the intermediate casing. Operators proposing to refracture a well also cannot practically 

comply with the cement evaluation log requirement of the rule, as it pertains to logging the surface casing and 

possibly deeper casing strings.

62 The dataset included 17,475 Federal in Indian wells that were completed between January 2008 and December 

2012.

63 Other reasons may include to control pressure during lost circulation zones, for hole stability (e.g., against clay 

swelling), for isolation through salt zones, or for isolation through disposal zones.

64 Colorado requires them when operators use a production liner.

65 In 2011, the number of wellbores started on Federal lands in North Dakota represented about 4% of the wellbores 

started on Federal lands nationwide.

66 Percent range cited by George King, a petroleum engineer for Apache Corporation (Behr 2012). That range is 

consistent with a survey of enforcement actions conducted by the Energy Institute (Groat & Grimshaw , Ch. 6, 

section 3, p. 16).
38

range, or 3 percent, and apply it to the number of newly drilled wells for the 

activity data.

Lining Pits: The rule would require operators to use a lined pit or a storage tank to 

manage flowback from hydraulic fracturing operations. As described in Section 2, this 

requirement is consistent with industry practice. We also examined regulations in 8 

states where new drilling activity is most prevalent on Federal lands and found that those 

states either have existing minimum requirements for lined pits or storage tanks or that 

operators do so to be consistent with the protection of groundwater. According to 

Resources for the Future (RFF), Arkansas, Kansas, Louisiana, Mississippi, Nevada, and 

Oklahoma also have existing pit liner requirements.67 Considering the low level of oil 

and gas development on Federal lands in the remaining states, the impact of this 

provision is likely to be very small. For example, in 2011, only 5 wellbores were 

spudded on Federal lands in states without current pit liner requirements.68 This 

represents about 0.15% of the wellbores spudded on Federal lands. We apply that 

percentage to the number of hydraulic fracturing operations on new and existing wells to 

get the activity data. However, even that number is potentially exaggerated, since 

multiple wells on a lease may use the same reserve pit and/or the BLM or the state might 

require the pits to be lined as a condition of approval. Also, those operators are likely to 

voluntarily use storage tanks or lined pits (which is standard industry practice).

NOI Sundries: The revised proposed rule would require NOI Sundry submissions for 

hydraulic fracturing operations on type wells, existing wells and refractured wells. 

Although the BLM currently receives NOI Sundries for “non-routine” hydraulic 

fracturing operations, for this analysis, we consider the NOI Sundry burden as a new 

burden, since the submission of NOI Sundries currently is inconsistent.

SR Sundries: The revised proposed rule would require SR Sundry submissions for 

hydraulic fracturing operations on all wells. Although the BLM currently receives SR 

Sundries for all hydraulic fracturing operations, for this analysis, we consider the SR 

Sundry burden as a new burden, since the information required by the rule is substantially 

different. 

Variance Requests: The revised proposed rule allows operators to request for variances. 

The BLM has no basis with which to estimate the number of variances that it would 

receive. For the purpose of this analysis, we assume that operators could potentially 

request variances on 10 percent of the NOI Sundries.

Subject Activity for Specific Requirements in the Alternatives: We adjusted the subject 

activity data for the alternatives. 

 

67 The RFF findings cited are available on its website under flowback/wastewater storage and disposal, accessed 

here on December 9, 2012: http://www.rff.org/centers/energy_economics_and_policy/Pages/Shale_Maps.aspx

68 Represents wellbores in Nevada and Ohio which were either not in the RFF study or that the RFF found no 

evidence of regulations. In 2010, only 4 wellbores were spudded on Federal lands in states (again Nevada and Ohio) 

without current pit liner requirements.
39

Alternative 1 does not have the type well provisions; therefore, operators would be required to 

submit NOI Sundries for all operations and conduct CELs on all wells with casing strings 

protecting usable water. The prevalence and cost of tank usage is a source of uncertainty and we 

have requested comments and information regarding storage tanks in the preamble of the 

proposed rule. We were not able to find data on the prevalence of voluntary storage tank usage 

in States without mandatory requirements. Thus, the number of operations where this alternative 

approach would compel the use of storage tanks is unknown at this time. 

Alternative 2 would not require lined pits. Estimates are provided in Table 11 and Table 12. 

For both alternatives, there is no activity data for the requirement to conduct a CEL in the event 

of an inadequate cement job. This is not because there would be no inadequate cement jobs, but 

simply that CELs are required on all casing strings that protect usable water, and so that 

requirement category encompasses the inadequate cementing category.
40

Table 9: Estimated Number of Hydraulic Fracturing Operations by Type, Years 1 – 10 

HF Type 1 2 3 4 5 6 7 8 9 10

HF on New Wells 3,434 3,525 3,608 3,628 3,663 3,685 3,724 3,764 3,832 3,911

HF on Existing Wells 28 28 28 28 28 28 28 28 28 28

Refracturing Operations 104 107 109 110 111 111 113 114 116 118

Total 3,566 3,659 3,745 3,765 3,802 3,825 3,864 3,906 3,975 4,057

Table 10: Estimated Activity Data for Specific Requirements in the Rule, Years 1 – 10 

Requirement 1 2 3 4 5 6 7 8 9 10

Surface Casing Logs 273 280 287 289 291 293 296 299 305 311

Intermediate Casing Logs 13 13 14 14 14 14 14 14 15 15

Logs for Inadequate Cementing 103 106 108 109 110 111 112 113 115 117

Lining Pits 5 5 5 5 6 6 6 6 6 6

NOI Sundry 405 415 424 426 430 433 437 441 449 457

SR Sundry 3,566 3,659 3,745 3,765 3,802 3,825 3,864 3,906 3,975 4,057

Variance Requests 41 41 42 43 43 43 44 44 45 46
41

Table 11: Estimated Activity Data for Specific Requirements in the Alternative 1, Years 1 – 10

Requirement 1 2 3 4 5 6 7 8 9 10

Surface Casing Logs 3,434 3,525 3,608 3,628 3,663 3,685 3,724 3,764 3,832 3,911

Intermediate Casing Logs 165 169 173 174 176 177 179 181 184 188

Logs for Inadequate Cementing 0 0 0 0 0 0 0 0 0 0

Storage Tanks Unk Unk Unk Unk Unk Unk Unk Unk Unk Unk

NOI Sundry 3,566 3,659 3,745 3,765 3,802 3,825 3,864 3,906 3,975 4,057

SR Sundry 3,566 3,659 3,745 3,765 3,802 3,825 3,864 3,906 3,975 4,057

Variance Requests 357 366 374 377 380 382 386 391 398 406

Table 12: Estimated Activity Data for Specific Requirements in the Alternative 2, Years 1 – 10

Requirement 1 2 3 4 5 6 7 8 9 10

Surface Casing Logs 3,434 3,525 3,608 3,628 3,663 3,685 3,724 3,764 3,832 3,911

Intermediate Casing Logs 165 169 173 174 176 177 179 181 184 188

Logs for Inadequate Cementing 0 0 0 0 0 0 0 0 0 0

No Tanks or Pit Liner Req. 0 0 0 0 0 0 0 0 0 0

NOI Sundry 3,566 3,659 3,745 3,765 3,802 3,825 3,864 3,906 3,975 4,057

SR Sundry 3,566 3,659 3,745 3,765 3,802 3,825 3,864 3,906 3,975 4,057

Variance Requests 357 366 374 377 380 382 386 391 398 406
42

Activity Costs: Activity costs vary by the requirements, as follows:

Cement evaluation logs: The costs associated with conducting these logs include the 

cost of the log itself and cost of maintaining any idle drilling equipment on-site, where 

appropriate. 

o Log costs: The costs of running a log varies depending on the type of test and 

whether it is for the surface casing or intermediate casing. Although the rule 

allows for a suite of CELs, operators will generally choose to use a CBL to log 

casing strings protecting usable water.69 In estimating compliance costs, we 

estimate that it costs $6,000 to run a CBL on the surface casing and about $20,000 

to run a CBL on the intermediate casing.70 For a CBL required when there is an 

indication of inadequate cementing, we estimate a cost of $7,000 to run a CBL, 

since it is unknown what length of casing the CBL would apply.71

o Maintaining idle drilling equipment for CELs on the surface casing – Lower 

bound of costs: The length of additional time required to cement behind the 

surface casing to reach compressive strength is a matter of debate. There may be

no additional time required if an operator avoids having to idle the equipment or if 

additional compressive strength in the cement is not required. We received a 

number of comments suggesting that 24 hours is an appropriate amount of time 

for the surface casing cement to reach compressive strength for a CEL.72 Using 

AFMSS well completion data for the past 5 years, which includes spud dates for 

wells in leases and agreements (referred to as cases in AFMSS), we counted the 

number of wells that were spudded successively on a case within 5 days of each 

other. We believe this represents the extent to which operators use small drilling 

rigs to successively drill the surface holes for multiple wells on a pad. The data 

show that 56.47 percent of all wells completed were spudded in this manner. On 

these wells, we expect the CEL provision will not cause operators to maintain idle 

drilling equipment. For the lower bound estimate, we attribute a lower bound cost 

of $19,850 to maintaining idle drilling equipment for a CEL on the surface 

casing.

73

 

o Maintaining idle drilling equipment for CELs on the surface casing – Upper 

bound of costs: Due to the uncertainty in operators’ ability to avoid having to 

 

69 Other CELs may be more expensive and/or require more time, under present technologic and economic 

conditions.

70 Estimates were listed in the appendix to the comment from Devon.

71 Calculated as: ($6,000) x (100%) + ($20,000) x (5%). We do not consider costs to maintain idle drilling 

equipment, since operators must current remediate to satisfaction.

72 We received a comments suggesting delay times up to 72 hours; however, many comments were not specific 

about whether the cited times were specific to cement behind the surface casing or the intermediate casing, or if the 

suggested times included both. Most comments were not specific as to whether the suggest times included the initial 

amount of time required for the cement to reach compressive strength sufficient for the casing pressure test. That 

initial time should not be considered as additional burden. We still believe that there could be efficiencies made by 

operators on these wells, for example, by drilling the intermediate hole and logging the surface casing before setting 

the intermediate casing. 

73 Calculated as the product: ($1900 per hour) x (24 hours) x (1-0.5647)
43

maintain idle drilling equipment, we calculated an upper bound for the CEL 

requirement on the surface casing. We account for 24 hours of additional time for 

operators to maintain idle drilling equipment, at a cost of $1,900 per hour. 

Overall, we attribute an upper bound cost of $45,600 to maintaining idle drilling 

equipment for a CEL on the surface casing.74

o Maintaining idle drilling equipment for CELs on the intermediate casing: 

For this analysis, we account for 48 hours of additional time at a cost of $1,900 

per hour. Since operators generally use additives to speed up the hardening of 

cement behind intermediate casing, we believe that 48 hours is the upper bound of 

the potential cost. Overall, we attribute a cost of $91,200 to maintaining idle 

drilling equipment for a CEL on the intermediate casing.

75

Lining Pits: We estimated the costs to be about $6,000 per pit, using prices quoted by 

suppliers of about $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.

Storage Tanks: As described earlier, we received general price quotes from two firms 

that rent storage tanks for hydraulic fracturing operations. The per-well costs of requiring 

storage tanks is likely to vary depending on the operator’s design. If the operator uses the 

tanks for managing flowback and then trucks the flowback from the site, then the costs of 

renting storage tanks might be between $6,000 and $17,000 per well. If the operator uses 

the tanks as part of a centralized recycling system for use on multiple wells, then the 

costs of renting storage tanks might be about $42,000 per well. Instead of renting, 

operators might choose to purchase storage tanks for use on multiple sites. We quoted 

one firm that sells 50,000 gallon tanks for $25,000. A hydraulic fracturing job using 1.2 

million gallons of fluid would require 24 tanks of this size at an initial cost of $600,000. 

However, the operator might reuse these tanks for up to 5 to 7 years.

Depending on the design of the closed-loop system, operators may also benefit from 

other cost savings. For example, the closed-loop system may eliminate the time and 

expense associated with reserve pit construction and reclamation. Recycling may reduce 

the amount of water needed, expenses and truck traffic associated with transporting water 

to the site and drilling waste from the site, surface disturbance, and the volume of waste. 

Operators are expected to experience fewer operational issues associated with liner 

system leakage. Also, tanks may be dismantled and reused in future operations.

NOI Sundries, SR Sundries, and Variance Requests: The sundries and variance 

requests are all anticipated to require 8 hours to prepare at a cost of about $60 per hour. 

As such, the cost for each sundry or variance request is estimated to be about $480.

76

 

74 Calculated as the product: ($1900 per hour) x (24 hours).

75 Calculated as the product: ($1900 per hour) x (48 hours).

76 The cost formulation for administrative requirements is detailed in the supporting statement for the Paperwork 

Reduction Act in the preamble of the final rule. It calculates costs of $59.78 per hour or $478.24 per request.
44

Average Compliance Costs by Well Type or Fracturing Operation

The average compliance costs will vary by well type or hydraulic fracturing operation. The 

estimates also reflect the likelihood that the particular type of well would be subject to the 

requirements. For example, the rule would compel only some operators of a type well to conduct 

a CEL on the intermediate casing, since not all wells have intermediate casing and only a portion 

of wells with intermediate casing protect usable water.

Operators on a single well or the type well for a group of wells are expected to see compliance 

costs ranging from $32,107 to $57,858. The majority of the costs are associated with conducting 

CELs on the surface casing and/or the intermediate casing. Compliance costs for the CEL 

requirement alone range from $29,737 to $54,959. In Year 1, only 273 wells are estimated to be 

subject to the CEL requirement in the rule, but 3,434 wells would be subject under Alternatives 1 

and 2.

Average compliance costs for subsequent wells are only relevant for the rule, and not for the 

alternatives, since the alternatives do not consider the type well concept. Average compliance 

costs are expected to be $697 per subsequent well. Existing wells and refracture operations have 

average compliance costs of $1,013 and $1,004, respectively, and would apply to about 132 

wells in Year 1. Average compliance costs by well type and fracturing operation are also 

provided.

77

Table 13: Average Compliance Costs by Well Type or Fracturing Operation 

Requirement

Well Type or Fracturing Operation

Type Well or Single Well

Subsequent 

Well under 

Type Well 

Approval

Existing 

Well

ReFracture 

Low High Operation

Count of Hydraulic Fracturing 

Operations (in Year 1) 273 3,161 28 104

CEL on Surface Casing $25,850 $51,600 $0 $0 $0

CEL on Intermediate Casing $3,149 $3,149 $0 $0 $0

CEL if Inadequate Cementing $210 $210 $210 $0 $0

Lining Pits $9 $9 $9 $9 $0

NOI Sundry $38 $38 $0 $478 $478

SR Sundry $478 $478 $478 $478 $478

Variance Requests $4 $4 $0 $48 $48

Total $29,737 $55,488 $697 $1,013 $1,004

 

77 As mentioned earlier, operators proposing to hydraulically fracture an existing well (one drilled prior to the 

effective date of the rule) cannot practically comply with the cement evaluation log requirement of the rule, as it 

pertains to logging the surface casing and possibly the intermediate casing. Operators proposing to refracture a well 

also cannot practically comply with the cement evaluation log requirement of the rule, as it pertains to logging the 

surface casing and possibly deeper casing strings.
45

Costs to the BLM to Maintain Capacity: The BLM will require additional staffing in order to 

incorporate the NOI Sundry approvals into the BLM’s processing of APDs. We calculate the 

administrative burden per NOI Sundry as being 8 hours (to include possible complexity with the 

type well approval), per SR Sundry as being 4 hours, and per Variance Request as being 1 hour. 

Full time employee (FTE) requirements to maintain capacity are calculated using 2,080 hours per 

year at an hourly wage of $28.45. The BLM wages are based on Office of Personnel Management 

data for a GS grade 12, step 1, with no locality adjustment.

Benefits: We describe the process of developing a possible risk calculation. However, we

provide a qualitative discussion (rather than a quantitative analysis) of benefits in the results 

section because of uncertainty about the magnitude of damages and the amount of risk reduction 

that we can attribute to the rule’s implementation.

Likelihood of a Minor Incident associated with Hydraulic Fracturing: The BLM 

does not track undesirable events by whether they were caused by hydraulic fracturing. 

The Energy Institute conducted a survey of violations that occurred on shale wells and 

tight sands and shales in four states, including Louisiana, Michigan, New Mexico, and 

Texas. Of those states, only New Mexico listed violations (categorized as “fracturing,” 

“groundwater contamination (complaints only),” and “surface spill frac fluid”)

specifically related to hydraulic fracturing operations. Another category listed and 

related to the rule was “casing and cementing.” Violations in these categories 

represented 2.7 percent of the total violations.78 

Likelihood of a Major Incident associated with Hydraulic Fracturing: As stated 

above, the BLM does not track undesirable events by whether they were caused by 

hydraulic fracturing. That one incident described before represents 0.028 percent of the 

total hydraulic fracturing operations that we estimate will occur in Year 1.

79

 There are 

likely other incidents that occurred in 2012 that were associated with hydraulic fracturing 

operations and for which this rule would be relevant in addressing. 

Damage from a Minor Incident from Hydraulic Fracturing: We include surface 

remediation for damage from a minor incident for purposes of a qualitative discussion. 

For the incident described above, we estimated the remediation costs of the surface 

environment to be about $15,000, but we note that the affected surface area is generally 

considered to be small. Remediation efforts of larger spills are much more complicated 

and can reach the hundreds of thousands of dollars. 

Damage from a Major Incident from Hydraulic Fracturing: We include several costs

that may comprise this formulation. As with the example incident, there were surface, 

possible subsurface impacts (including impacts on the second well), and resources 

unrecovered.

 

78 Groat 2012, Ch. 6, section 3, pp. 16-17.

79 Calculated as 1 / 3566.
46

o Subsurface Remediation Damage: The Federal Remediation Technologies 

Roundtable (FRTR) makes a number of case studies available on its website.80 It 

provides a description of the contamination event and source, and remediation 

efforts and costs. This analysis assumes a cost of $1 million to remediate 

contamination to an aquifer, but we note that the FRTR does not list any case 

studies of contamination events resulting from hydraulic fracturing operations. 

o Surface Remediation Damage: We believe remediation efforts could range 

from $15,000 to hundreds of thousands of dollars for an incident that affects the 

surface environment.

o Value of Stranded (or Unrecovered) Resource: We believe that these costs 

would be variable depending on the damage and the particular well or wells. In 

the example incident, the operator could lose a number of stages, be required to 

shut in the well for a period of time, or plug the well entirely.

 

80 http://www.frtr.gov/.
47

3.3 Discounted Present Value

There is a time dimension to estimates of potential costs and benefits. 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.81 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.”

The analysis also examines potential costs and benefits using 10 and 12 percent discount rates. 

The consideration of higher discount rates are appropriate for this analysis, since the rule 

imposes costs on the oil and gas industry and the opportunity cost of not having that available 

capital is generally higher than 3 and 7 percent. The higher rates also serve as a sensitivity test.

 

81 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. 
48

3.4 Uncertainty

The costs and benefits provided in this analysis are indeed estimates and come with uncertainty. 

We describe the primary sources of uncertainty below:

Type well applicability: The estimates for the rule rely largely on the concept of the 

type well. In terms of cost calculations, the uncertainty lies in an average number of 

wells that would be covered under a type well approval. While we are confident that the 

average number of wells that an operator completes in a field is a good measure with 

which to base the estimate, the measure is positively skewed by a fewer number of firms 

with a high numbers of wells. This does not suggest a problem with the data, but rather 

that the experiences of operators will vary, and that the likely scenario is that the typical 

operator completes fewer wells than the average. In terms of benefit calculations, there is 

uncertainty about the effectiveness of the type well concept, and how reliably the CEL 

results on casing strings of a type well assure adequate cementing for subsequent wells in 

the same geologic area. 

Length of delay time to run a CEL: A large source of uncertainty is the amount of time 

that the CEL requirement might delay drilling operations. We received comments 

suggesting that the CEL would delay drilling operations for up to 72 hours. The CEL on 

the surface casing, in particular, poses a new step in the drilling process for operators. A 

large source of uncertainty is the extent to which operators would be subject to delays, 

and if so, how they will be able to incorporate this new requirement and minimize or 

eliminate potential delays through operating efficiencies. 

Percent of wells encountering problems during the cementing process: Cementing 

problems, and downhole conditions in general, are not a widely reported measure. This 

analysis uses 3 percent as the basis for calculating the potential costs and benefits. 

Benefits of specific provisions for well integrity and NOI Sundry submission: 

Further uncertainty lies in the estimation of benefits and the cumulative effect of the 

rule’s provisions on mitigating the potential risks of hydraulic fracturing operations. This 

rule has specific provisions that would help operators and the BLM better identify 

potential issues in wellbore integrity and fracturing design, before operations begin. 

However, it is difficult to attribute benefits to one single test (for instance the CEL) when 

that is only one part of the overall evaluation of wellbore integrity.

 
49

3.5 Changes in the Economic Analysis from the Initial Proposed Rule

The BLM received many comments about the economic analysis that it conducted for the initial 

proposed rule. We reviewed these comments and made changes to the economic analysis, where 

appropriate. We describe those changes in this section. 

We refined the estimation of costs and benefits in several ways. The revised analysis includes an 

examination of costs for maintaining idle drilling equipment. We also account for existing state 

regulations, understanding that operators are already in compliance with many of the rule’s 

provisions. This improvement resulted in updated estimates for the pit liner and mechanical 

integrity test requirements. In response to comments, we revised the estimated number of 

hydraulic fracturing operations to include refracture jobs. We also revised the formulation of 

administrative costs to be consistent with the Paperwork Reduction Act analysis assumptions in 

the proposed preamble. 

We provide a qualitative discussion of the benefits for the rule. Also, recognizing the limitations 

in being able to estimate all of the benefits of the rule, we present the costs and benefits 

separately rather than as net benefits.

In response to public comments, we included additional discount rates.

The small business impacts analysis was refined and expanded. The costs associated with the 

CEL provisions represent the majority of the potential costs and these provisions will affect 

operators drilling new wells. We took a closer look at the operators completing new wells on 

federal and tribal lands in the past 5 years and researched those companies filing annual reports 

with the Securities and Exchange Commission (SEC). The result is an expanded pool of 

companies and a more in depth look at the potential impacts.

In addition to changes stemming from public comments, this analysis examines the provisions 

contained in the revised proposed rule. 
50

4. Results

Where appropriate, this analysis monetizes costs and benefits expected to occur over a 10-year

period. This period of analysis was chosen because 10 years is the length of the primary lease 

term on BLM-managed lands. The analysis presents a range of expected outcomes due to 

uncertainty about the generalization of costs and benefits across all hydraulic fracturing 

operations.

Table 14 and Table 15 show a summary of incremental costs and benefits, respectively, for the 

rule and the alternatives examined. To annualize the incremental costs and benefits, the analysis 

calculates the annualized value (AV).

82

 When monetized, the results are presented in 2012 

dollars.

Table 14: Summary of Costs ($million)

Annualized Value

Revised 

Proposed Rule Alternative 1* Alternative 2

Undiscounted 12 - 20 119 - 213 119 - 213

Discounted at 3% 12 - 19 118 - 213 118 - 213

Discounted at 7% 12 - 19 118 - 212 118 - 212

Discounted at 10% 12 - 19 117 - 211 117 - 211

Discounted at 12% 12 - 19 117 - 211 117 - 211

* Does not represent total costs, because the cost of requiring storage tanks is unknown.

The annualized values of the costs do not vary significantly across different discount rates. This 

is expected for several reasons. 

When comparing annualized values across a range of possible discount rates, it is important to 

recognize three effects. First is the effect of discounting within any given year: a higher discount 

rate results in a smaller real value for a cost in that year. This is shown in Table 16 by 

comparing the undiscounted and discounted rows for any of the year columns. For example, in 

Year 1, the undiscounted cost is $11.19 million, while discounting at 3 percent reduces this to 

$10.86 million in real terms, and discounting at 12 percent reduces it to $9.99 million.

The second effect is the impact of compounded discounting: the farther in the future a cost is to 

be incurred, the smaller the real value of that cost. This is shown in Table 16 by comparing the 

effect of a given discount rate in two different years. For example, in Year 1 the effect of 

discounting at 3 percent (as discussed in the previous paragraph) is to reduce the undiscounted 

costs by $0.33 million, a change of 3 percent. In Year 2, the reduction is $0.66 million, a change 

of 6 percent, and in Year 10 the reduction is $3.26 million, a change of 26 percent.

 

82 AV = [PDV] * [ (r(1+r)^n) / ((1+r)^n – 1)], where PDV is the present discounted value of the benefits, costs, or 

net benefits over “n” years and “r” is the discount rate.
51

From these first two effects, we see that real costs are driven down by using a higher discount 

rate and by delaying costs.

The third effect is related to how the annualized value (AV) compares to the average cost over a 

stream of payments. For a given (real) lump sum, the AV is an annual nominal payment such 

that a discounted stream of these payments equals the real value of the lump sum. When the 

discount rate is zero, the AV is simply the average cost: the sum of the costs in the original 

schedule divided by the number of years in the schedule.

When the original cost schedule is front-loaded (nominal costs are higher in early years), 

discounting has less of an effect, as the time for compounding is limited. Thus, any real lump 

sum is not much less than the sum of the undiscounted costs. In a hypothetical stream of AV 

payments, payments made in later years contribute little to total real value, but the stream must 

nonetheless tally to a real-value amount relatively close to the undiscounted total. This forces 

the AV value up relative to the average cost.

When the original cost schedule is back-loaded (nominal costs are higher in later years), 

discounting has more of an effect, given the longer time for compounding. Thus, any real lump 

sum is significantly less than the sum of the undiscounted costs. This forces the AV value down 

relative to the average cost.

When the original cost schedule is relatively constant over time (neither front-loaded nor backloaded) the AV will be relatively similar to the average cost. This is expected with compliance 

costs related to this rule. The total compliance costs for the rule are expected to be relatively 

similar over future years, owing to similar activity data (i.e. the number of hydraulic fracturing 

operations) and that the compliance costs for a single operation are contained within a short 

timeframe. 
52

Table 15: Summary of Non-Monetized Benefits

Non-Monetized Benefits Rule Alternative 

1

Alternative 

2

Percent of individual hydraulic 

fracturing plans reviewed by the BLM

11% 100% 100%

Percent of hydraulic fracturing 

operations using unlined pits

0% 0% 0.15%

Percent of individual wells where 

wellbore integrity is demonstrated with 

CELs on casing strings that protect 

usable water

8% 96% 96%

Percent of wells where wellbore 

integrity is demonstrated with pressure 

tests

100% 100% 100%

Percent of hydraulic fracturing 

operations where chemical content of 

fluids are disclosed

100% 100% 100%

Non-Monetized 

Benefits

Estimated 

Baseline

Rule Alternative 

1

Alternative 

2

Likelihood of Minor 

Incident

2.70% N/A N/A N/A

Likelihood of Major 

Incident

0.03% N/A N/A N/A
53

4.1 Costs of the Revised Proposed Rule and Alternatives

Estimated Costs of Revised proposed Rule

Annualized costs to the industry are estimated to be between about $12 and $20 million when 

undiscounted and when using discount rates of 3, 7, 10, and 12 percent. 

Table 16 and Table 17 show lower and upper bound estimates, respectively. The tables provide 

a range for potential costs for each year of the 10-year period. In a given year, requirement costs 

are provided separately and also totaled at the bottom of the table. The net present values for the 

total costs are also provided, using discount rates of 3, 7, 10, and 12 percent. We also present the 

annualized value in the right column of each table for each of those discount rates. 

The net present value of total costs over the 10-year period are estimated to be between $102 to 

$166 million when discounted at 3 percent, between $84 and $136 million when discounted at 7

percent, between $73 and $119 million when discounted at 10 percent, and between $67 and 

$109 million when discounted at 12 percent. 

The largest cost burden lies with the CEL requirement, which is also the source of the greatest 

amount of uncertainty when developing estimates. Drilling methods, procedures, and 

requirements vary across operations, locations, and states, so it is challenging to place an exact 

dollar figure on the appropriate cost. 

The estimated costs for the CEL requirement are driven to a large extent by the amount of time 

operators might have to maintain idle drilling equipment on-site. The lower bound of the 

estimated CEL requirement includes the annual costs of conducting CELs on the surface casing, 

assuming that operators using a small rig to drill the surface holes of wells would likely avoid the 

costs of maintaining idle drilling equipment. The estimate possibly represents the lowest 

possible cost; however, there is a chance it could be even lower depending on the ability of the 

operators on other wells to maximize efficiencies and reduce delays. The upper bound of the 

estimated CEL requirement does not account for the potential of operators to reduce delays 

below 24 hours per CEL on the surface casing and 48 hours on the intermediate casing. While 

the estimate possibly represents the maximum total cost, it may underestimate the total costs if 

CELs result in the delays assumed.

We have assumed delay times to account for additional compressive strength requirements for 

cement bonding and ancillary delays that could occur. However, there are several ways for 

operators to reduce the amount of idle time. Table 18 shows the sensitivity of the upper bound 

total estimates to assumed idle times. If operators are able to reduce the assumed delays by 25

percent, then the upper bound costs estimates would be reduced by 19 percent. On the other 

hand, if the assumptions underestimate the delay times by 25 percent, then the upper bound 

estimate would be increased by 19 percent.

The administrative compliance costs are non-trivial and are based on a per submission cost of 

$478. It is likely that operators, over time, will be able to gain efficiencies and reduce costs 

below the estimates provided.
54

The costs provided are estimates of the direct costs and not the overall costs to society. There is 

uncertainty about the effect that the rule would have across all potential hydraulic fracturing 

operations. The rule has a provision for type well approval of the NOI Sundry and log 

requirements (unless the operator encounters problems with improper cementing) and affords 

operators drilling many wells in a geologic area greater efficiency than it does for operators 

drilling a single well or few wells. If one assumes that operators cannot derive efficiencies to 

avoid the costs of idle rig time, it could favor activity in development fields over exploratory 

areas.

There is also flexibility in how the various BLM authorized officers might treat applications for 

variances, and to what extent that will allow operators to potentially reduce costs. The revised 

proposed rule includes a provision allowing the BLM to approve a variance that would apply to 

all lands within the boundaries of a State, a tribe, or on a field, or a basin. The BLM must 

determine that the variance would meet or exceed the effectiveness of the revised proposed rule. 

State and tribes would be invited work with the BLM to craft variances that would allow 

technologies, processes or standards required or allowed by the State or tribe to be accepted as 

compliance with the rule. Such broad variances would allow the BLM and the States and tribes 

to improve efficiency and reduce costs for operators and for the agencies. There are well 

construction methods, such as the use of a “frac string,” that reduce the pressures placed on the 

intermediate casing and surface casing strings during hydraulic fracturing operations. This is one 

potential area where an operator might receive a variance. 
55

Table 16: Lower Bound of Cost Estimates for Specific Requirements in the Rule, Years 1 – 10 ($MM)

Requirement 1 2 3 4 5 6 7 8 9 10 Total AV

CEL on Surface Casing 7.06 7.25 7.42 7.46 7.53 7.58 7.66 7.74 7.88 8.04 75.61

CEL on Intermediate Casing 1.46 1.50 1.53 1.54 1.56 1.56 1.58 1.60 1.63 1.66 15.61

CEL if Inadequate Cementing 0.72 0.74 0.76 0.76 0.77 0.77 0.78 0.79 0.80 0.82 7.72

Lining Pits 0.03 0.03 0.03 0.03 0.03 0.03 0.03 0.03 0.03 0.04 0.33

NOI Sundry 0.19 0.20 0.20 0.20 0.21 0.21 0.21 0.21 0.21 0.22 2.06

SR Sundry 1.70 1.75 1.79 1.80 1.82 1.83 1.85 1.87 1.90 1.94 18.24

Variance Requests 0.02 0.02 0.02 0.02 0.02 0.02 0.02 0.02 0.02 0.02 0.21

Nominal Total (Undiscounted) 11.19 11.48 11.75 11.82 11.93 12.00 12.13 12.26 12.48 12.74 119.79 11.98

Real Total (Discounted at 3%) 10.86 10.82 10.76 10.50 10.29 10.05 9.86 9.68 9.57 9.48 101.88 11.94

Real Total (Discounted at 7%) 10.46 10.03 9.59 9.02 8.51 8.00 7.55 7.14 6.79 6.48 83.56 11.90

Real Total (Discounted at 10%) 10.17 9.49 8.83 8.07 7.41 6.78 6.22 5.72 5.29 4.91 72.90 11.86

Real Total (Discounted at 12%) 9.99 9.15 8.37 7.51 6.77 6.08 5.49 4.95 4.50 4.10 66.92 11.84

Table 17: Upper Bound of Cost Estimates for Specific Requirements in the Rule, Years 1 – 10 ($million)

Requirement 1 2 3 4 5 6 7 8 9 10 Total AV

CEL on Surface Casing 14.10 14.47 14.81 14.89 15.04 15.13 15.28 15.45 15.73 16.05 150.93

CEL on Intermediate Casing 1.46 1.50 1.53 1.54 1.56 1.56 1.58 1.60 1.63 1.66 15.61

CEL if Inadequate Cementing 0.72 0.74 0.76 0.76 0.77 0.77 0.78 0.79 0.80 0.82 7.72

Lining Pits 0.03 0.03 0.03 0.03 0.03 0.03 0.03 0.03 0.03 0.04 0.33

NOI Sundry 0.19 0.20 0.20 0.20 0.21 0.21 0.21 0.21 0.21 0.22 2.06

SR Sundry 1.70 1.75 1.79 1.80 1.82 1.83 1.85 1.87 1.90 1.94 18.24

Variance Requests 0.02 0.02 0.02 0.02 0.02 0.02 0.02 0.02 0.02 0.02 0.21

Nominal Total (Undiscounted) 18.22 18.70 19.14 19.25 19.44 19.55 19.76 19.97 20.33 20.75 195.11 19.51

Real Total (Discounted at 3%) 17.69 17.63 17.52 17.10 16.77 16.38 16.06 15.77 15.58 15.44 165.93 19.45

Real Total (Discounted at 7%) 17.03 16.34 15.63 14.68 13.86 13.03 12.30 11.62 11.06 10.55 136.10 19.38

Real Total (Discounted at 10%) 16.57 15.46 14.38 13.15 12.07 11.04 10.14 9.32 8.62 8.00 118.73 19.32

Real Total (Discounted at 12%) 16.27 14.91 13.63 12.23 11.03 9.91 8.94 8.07 7.33 6.68 108.99 19.29
56

Table 18: Sensitivity of Upper Bound Estimate to Various Idle Times

Effect on Upper Bound 

Estimate

Percent Change in Hours of Idle Time

-50% -25% 0% 25% 50%

Upper Bound Estimate ($MM) 

(Undiscounted) 12.20 15.86 19.51 23.17 26.82

Percent Change in Upper 

Bound Estimate -37% -19% --- 19% 37%
57

Estimated Costs of Alternative 1

Alternative 1 requires logs to evaluate the cement behind casing strings protecting usable water. 

It requires the use of storage tanks to manage flowback. 

We were not able to estimate the total costs of the storage tank requirement, due to the lack of 

available data on the prevalence of storage tank use. Therefore, the annualized costs of 

Alternative 1 are unknown but expected to be higher than those presented below and in Table 20 

and Table 21.

For the remaining requirements, the annualized costs to the industry are estimated to be between 

about $117 and $213 million. Table 20 and Table 21 show lower and upper bound estimates, 

respectively, for the quantifiable costs. The tables provide a range for potential costs for each 

year of the 10-year period. In a given year, requirement costs are provided separately and also 

totaled at the bottom of the table. The net present values for the total costs are also provided, 

using discount rates of 3, 7, 10, and 12 percent. We also present the annualized value in the right 

column of each table for each of those discount rates. 

The net present value of total costs over the 10-year period are estimated to be between $1.0 to 

$1.8 billion when discounted at 3 percent, between $0.8 and $1.5 billion when discounted at 7

percent, between $0.7 and $1.3 billion when discounted at 10 percent, and between $0.7 and $1.2 

billion when discounted at 12 percent. 

The annualized costs are between $118 and $213 million when undiscounted, between $118 and 

$213 million when using a 3 percent discount rate, between $118 and $212 million when using a 

7 percent discount rate, between $117 and $211 million when using a 10 percent discount rate, 

and between $117 and $211 million when using a 3 percent discount rate. 

Like the rule provisions, the largest cost burden with Alternative 1 lies with the cement 

evaluation log requirement. The cost of the CEL requirement is estimated to be between roughly 

$100 million and $200 million per year. Alternative 1 does not have provisions allowing for 

type well approval. As such, operators would be required to run CELs (or CBLs as originally 

proposed) on all casing strings in a well that protect usable water. 

Also, like the cost estimates described in the previous section, these results attempt to constrain 

the potential costs. The results are highly dependent on the potential delays associated with 

running CELs. Other compliance costs are generally the same, except for the total costs to 

submit NOI Sundry requests, since this alternative would require submissions for each proposed 

hydraulic fracture operation.

The cost of requiring storage tanks is unknown due to the lack of data about the prevalence of 

storage tank use, particularly on BLM-managed leases. As described previously, the costs of 

renting storage tanks for managing flowback may vary based on the design. The costs could be 

$6,000 and $17,000 per well for recovery of the flowback alone. Or, if the operator uses the 

storage tanks as part of a centralized recycling system for use on multiple wells, then the costs of 

renting tanks may be about $42,000 per well. Instead of renting, operators might choose to 
58

purchase storage tanks for use on multiple sites. The initial investment might be about $600,000, 

but the operator might reuse the tanks for up to 5 to 7 years.

This estimate does not account for cost savings that operators are likely to experience. Closedloop systems may eliminate the time and expense associated with reserve pit construction and 

reclamation. Operators are expected to experience fewer operational issues associated with liner 

system leakage. Also, tanks may be dismantled and reused in future operations.

Estimates for Alternative 1 describe direct costs to the industry and not costs to society. It is far 

more likely under this scenario that the industry would be adversely impacted, with harmful 

effects on employment, exploration and production activities, and production.
59

Table 20: Lower Bound of Cost Estimates for Specific Requirements in Alternative 1, Years 1 – 10 ($million)

Requirement 1 2 3 4 5 6 7 8 9 10 Total AV

CEL on Surface Casing 88.78 91.11 93.26 93.77 94.69 95.26 96.26 97.31 99.05 101.09 950.58

CEL on Intermediate Casing 18.33 18.81 19.26 19.36 19.55 19.67 19.88 20.09 20.45 20.87 196.28

CEL if Inadequate Cementing 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00

Storage Tanks Unk Unk Unk Unk Unk Unk Unk Unk Unk Unk Unk

NOI Sundry 1.70 1.75 1.79 1.80 1.82 1.83 1.85 1.87 1.90 1.94 18.24

SR Sundry 1.70 1.75 1.79 1.80 1.82 1.83 1.85 1.87 1.90 1.94 18.24

Variance Requests 0.17 0.17 0.18 0.18 0.18 0.18 0.18 0.19 0.19 0.19 1.82

Nominal Total (Undiscounted) 110.69 113.60 116.28 116.91 118.06 118.77 120.02 121.32 123.49 126.04 1,185.17 118.52

Real Total (Discounted at 3%) 107.47 107.07 106.41 103.88 101.84 99.47 97.58 95.77 94.64 93.78 1,007.92 118.16

Real Total (Discounted at 7%) 103.45 99.22 94.92 89.19 84.18 79.14 74.74 70.61 67.17 64.07 826.69 117.70

Real Total (Discounted at 10%) 100.63 93.88 87.36 79.85 73.31 67.04 61.59 56.60 52.37 48.59 721.22 117.38

Real Total (Discounted at 12%) 98.83 90.56 82.76 74.30 66.99 60.17 54.29 49.00 44.53 40.58 662.02 117.17

Table 21: Upper Bound of Cost Estimates for Specific Requirements in Alternative 1, Years 1 – 10 ($million)

Requirement 1 2 3 4 5 6 7 8 9 10 Total AV

CEL on Surface Casing 177.21 181.87 186.16 187.18 189.02 190.16 192.15 194.24 197.71 201.79 1,897.51

CEL on Intermediate Casing 18.33 18.81 19.26 19.36 19.55 19.67 19.88 20.09 20.45 20.87 196.28

CEL if Inadequate Cementing 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00

Storage Tanks Unk Unk Unk Unk Unk Unk Unk Unk Unk Unk Unk

NOI Sundry 1.70 1.75 1.79 1.80 1.82 1.83 1.85 1.87 1.90 1.94 18.24

SR Sundry 1.70 1.75 1.79 1.80 1.82 1.83 1.85 1.87 1.90 1.94 18.24

Variance Requests 0.17 0.17 0.18 0.18 0.18 0.18 0.18 0.19 0.19 0.19 1.82

Nominal Total (Undiscounted) 199.13 204.35 209.18 210.32 212.39 213.67 215.91 218.25 222.16 226.74 2,132.10 213.21

Real Total (Discounted at 3%) 193.33 192.62 191.43 186.87 183.21 178.94 175.55 172.29 170.26 168.71 1,813.23 212.57

Real Total (Discounted at 7%) 186.10 178.49 170.75 160.45 151.43 142.38 134.46 127.03 120.84 115.26 1,487.19 211.74

Real Total (Discounted at 10%) 181.02 168.89 157.16 143.65 131.88 120.61 110.80 101.82 94.22 87.42 1,297.46 211.16

Real Total (Discounted at 12%) 177.79 162.91 148.89 133.66 120.52 108.25 97.67 88.15 80.11 73.00 1,190.95 210.78
60

Estimated Costs of Alternative 2

Alternative 2 requires logs to evaluate the cement behind casing strings protecting usable water. 

It does not establish requirements for storage tanks or lined pits.

Annualized costs to the industry are estimated to be between about $117 and $213 million. The 

annualized costs vary only slightly under the various discount rates examined. We attribute the 

uniformity to the fact that the cost per operation is expected to remain relatively constant over 

time, the costs for an operation are confined within a short time period, and the number of 

hydraulic fracturing operations on Federal and Indian leases is expected to increase only slightly 

in future years, meaning the total industry costs are expected to be relatively consistent in future 

years. 

Table 22 and Table 23 show lower and upper bound estimates, respectively. The tables provide 

a range for potential costs for each year of the 10-year period. In a given year, requirement costs 

are provided separately and also totaled at the bottom of the table. The net present values for the 

total costs are also provided, using discount rates of 3, 7, 10, and 12 percent. We also present the 

annualized value in the right column of each table for each of those discount rates. 

The net present value of total costs over the 10-year period are estimated to be between $1.0 to 

$1.8 billion when discounted at 3 percent, between $0.8 and $1.5 billion when discounted at 7

percent, between $0.7 and $1.3 billion when discounted at 10 percent, and between $0.7 and $1.2 

billion when discounted at 12 percent. Again, the annualized costs are estimated to be between 

$117 and $213 million in all discount rate scenarios examined.
61

Table 22: Lower Bound of Cost Estimates for Specific Requirements in Alternative 2, Years 1 – 10 ($million)

Requirement 1 2 3 4 5 6 7 8 9 10 Total AV

CEL on Surface Casing 88.78 91.11 93.26 93.77 94.69 95.26 96.26 97.31 99.05 101.09 950.58

CEL on Intermediate Casing 18.33 18.81 19.26 19.36 19.55 19.67 19.88 20.09 20.45 20.87 196.28

CEL if Inadequate Cementing 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00

No Tanks/Pit Liner Req. 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00

NOI Sundry 1.70 1.75 1.79 1.80 1.82 1.83 1.85 1.87 1.90 1.94 18.24

SR Sundry 1.70 1.75 1.79 1.80 1.82 1.83 1.85 1.87 1.90 1.94 18.24

Variance Requests 0.17 0.17 0.18 0.18 0.18 0.18 0.18 0.19 0.19 0.19 1.82

Nominal Total (Undiscounted) 110.69 113.60 116.28 116.91 118.06 118.77 120.02 121.32 123.49 126.04 1,185.17 118.52

Real Total (Discounted at 3%) 107.47 107.07 106.41 103.88 101.84 99.47 97.58 95.77 94.64 93.78 1,007.92 118.16

Real Total (Discounted at 7%) 103.45 99.22 94.92 89.19 84.18 79.14 74.74 70.61 67.17 64.07 826.69 117.70

Real Total (Discounted at 10%) 100.63 93.88 87.36 79.85 73.31 67.04 61.59 56.60 52.37 48.59 721.22 117.38

Real Total (Discounted at 12%) 98.83 90.56 82.76 74.30 66.99 60.17 54.29 49.00 44.53 40.58 662.02 117.17

Table 23: Upper Bound of Cost Estimates for Specific Requirements in Alternative 2, Years 1 – 10 ($million)

Requirement 1 2 3 4 5 6 7 8 9 10 Total AV

CEL on Surface Casing 177.21 181.87 186.16 187.18 189.02 190.16 192.15 194.24 197.71 201.79 1,897.51

CEL on Intermediate Casing 18.33 18.81 19.26 19.36 19.55 19.67 19.88 20.09 20.45 20.87 196.28

CEL if Inadequate Cementing 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00

No Tanks/Pit Liner Req. 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00

NOI Sundry 1.70 1.75 1.79 1.80 1.82 1.83 1.85 1.87 1.90 1.94 18.24

SR Sundry 1.70 1.75 1.79 1.80 1.82 1.83 1.85 1.87 1.90 1.94 18.24

Variance Requests 0.17 0.17 0.18 0.18 0.18 0.18 0.18 0.19 0.19 0.19 1.82

Nominal Total (Undiscounted) 199.13 204.35 209.18 210.32 212.39 213.67 215.91 218.25 222.16 226.74 2,132.10 213.21

Real Total (Discounted at 3%) 193.33 192.62 191.43 186.87 183.21 178.94 175.55 172.29 170.26 168.71 1,813.23 212.57

Real Total (Discounted at 7%) 186.10 178.49 170.75 160.45 151.43 142.38 134.46 127.03 120.84 115.26 1,487.19 211.74

Real Total (Discounted at 10%) 181.02 168.89 157.16 143.65 131.88 120.61 110.80 101.82 94.22 87.42 1,297.46 211.16

Real Total (Discounted at 12%) 177.79 162.91 148.89 133.66 120.52 108.25 97.67 88.15 80.11 73.00 1,190.95 210.78
62

4.2 Average Compliance Costs for Operators 

The provisions of the rule would result in compliance costs ranging from $3,138 to $5,110 for all 

hydraulic fracturing operations expected to occur. We derive these estimates by averaging the 

total estimated costs (undiscounted) over the 10-year period by the total number of hydraulic 

fracturing operations expected to occur. The CEL requirements represent the bulk of that 

portion, $2,591 to $4,564. 

The provisions in Alternative 1 would result in higher compliance costs per operation since 

CELs are required for each well. We also expect that the storage tank requirements would be 

costly; however, we were not able to calculate an average cost for this requirement. The 

estimated costs of the alternative range from $31,047 to $55,845. Compliance costs for 

Alternative 2 are roughly the same. 

Average compliance costs per operation for each of the policy options are shown below.

Table 24: Average Compliance Costs in 2013 Across All Operations 

for the Rule, Alternative 1, and Alternative 2

Requirement

Average Across All Operations

Rule Alternative 1 Alternative 2

Low High Low High Low High

Count of Hydraulic Fracturing 

Operations (in Year 1) 3,566 3,566 3,566

CEL on Surface Casing $1,980 $3,953 $24,894 $49,692 $24,894 $49,692

CEL on Intermediate Casing $409 $409 $5,140 $5,140 $5,140 $5,140

CEL if Inadequate Cementing $202 $202 $0 $0 $0 $0

Lining Pits or Tank Req. $9 $9 Unk Unk $0 $0

NOI Sundry $54 $54 $478 $478 $478 $478

SR Sundry $478 $478 $478 $478 $478 $478

Variance Requests $5 $5 $48 $48 $48 $48

Total $3,138 $5,110 $31,038 $55,836 $31,038 $55,836
63

4.3 BLM Administrative Burden 

The processing of NOI Sundry, SR Sundry, and variance requests associated with the rule would 

pose additional burden to the BLM; however, it is unclear the extent to which the BLM can meet 

the additional burden with existing capacity. 

An additional 8.44 full-time equivalent (FTE) of workload is estimated to be required to meet the 

administrative burden of the rule in Year 1. Alternatives 1 and 2 would require about 21 FTE in 

Year 1, since the NOI Sundry requests would be far greater. There are opportunities for the 

BLM to experience efficiencies in the processing of these sundry requests or in the processing of 

other permits, and those efficiencies would reduce the required capacity in future years.

Table 25: BLM Administrative Burden and FTE Requirements for Year 1

Requirement

Revised Proposed Rule Alternative 1 Alternative 2

Annual 

Burden 

Cost ($)

Equivalent 

FTE 

Required

Annual 

Burden 

Cost ($)

Equivalent 

FTE 

Required

Annual 

Burden 

Cost ($)

Equivalent 

FTE 

Required

NOI Sundry 92,189 1.56 811,682 13.72 811,682 13.72

SR Sundry 405,841 6.86 405,841 6.86 405,841 6.86

Variance Requests 1,152 0.02 10,146 0.17 10,146 0.17

Total 499,183 8.44 1,227,669 20.75 1,227,669 20.75
64

4.4 Benefits of the Revised Proposed Rule and Alternatives

Benefits of the Revised Proposed Rule

The rule provisions, as described in the revised proposed rule, would require an operator to 

conduct tests on a well before it conducts hydraulic fracturing operations on that well. It would 

compel operators to conduct an estimated 293 CELs per year on surface casings, 14 CELs per 

year on intermediate casings, and 110 CELs per year on casing strings where there is an initial 

indication of inadequate cementing. 

Relative to the alternatives, the rule would not compel as many CELs. Therefore, the rule might 

not reduce as much of the risk (of conducting hydraulic fracturing operations on wells with 

inadequate formation protection) as the alternatives would. The rule would ensure that operators 

demonstrate wellbore integrity with pressure tests on 100 percent of the wells and with CELs on 

the casing strings that protect usable water on only 8 percent of wells. The level of risk 

reduction across subsequent wells relies on the replication of adequate cementing across multiple 

wells in a geographic area with the same geologic characteristics.

The rule would compel an estimated 110 CELs to demonstrate that inadequate cementing was 

corrected by operators. As such, it requires a verification of proper remedial cementing on the 

very wells that pose greater risk.

Under the rule, operators would submit an average of 432 NOI Sundry applications per year 

covering about 3,816 hydraulic fracturing operations.83 The BLM would receive individual 

hydraulic fracturing plans for 11 percent of the proposed operations, and the remaining 89

percent of operations would be for subsequent wells to a type well. The type well provision, 

relative to the alternatives, reduces burden on the industry and the BLM. The submission of NOI 

Sundry applications would provide the BLM with the necessary information needed to make 

informed decisions about the public’s resources and thus improve the public welfare. 

The rule is estimated to compel only 6 additional lined pits per year, simply because most of the 

states where the BLM manages oil and gas resources already require lined pits. For those 6 pits, 

the requirement would immediately remove sources of harm to the environment and the public

from the saturation of the surface environment with fracturing fluids.

The rule would compel an estimated 3,816 SR Sundry reports and public disclosures of the 

chemical content of the hydraulic fracturing fluids annually. The increase in information about 

additives could aid water users when they consider the potential effects of hydraulic fracturing 

operations and constituent chemicals. 

Without implementing the rule, we estimate that the likelihood of an incident resulting from a 

hydraulic fracturing operation could be between 0.03 and 2.70 percent. The rule would 

potentially reduce the risks associated with hydraulic fracturing operations; however, it is 

uncertain by what amount. Damage from an incident that occurs could cost between $15,000 

 

83 The average is for the 10-year period, 2013-2022.
65

and $1 million for remediation plus any lost revenue from unrecoverable resources, including 

spilled or stranded resources. 

Benefits of Alternative 1

Alternative 1 would compel operators to conduct CELs on the casing strings protecting usable 

water in 96 percent of the wells proposed for hydraulic fracturing operations. The remaining 4

percent of operations are estimated to be on existing wells or refracturing jobs, where CELs are 

impractical. The rule would compel an average of 3,677 CELs per year on surface casings, 177 

CELs per year on intermediate casings, and 0 CELs per year on casing strings where there is an 

initial indication of inadequate cementing. The requirement to run a CEL when there is 

inadequate cementing would have no practical effect under Alternative 1, since operators would 

conduct those logs regardless. Compared with the rule, Alternative 1 would compel significantly 

more CELs. As such, it is likely to offer more risk reduction than the rule does. 

Under Alternative 1, operators would submit an average of 3,816 NOI Sundry applications per 

year covering all of the hydraulic fracturing operations. There is uncertainty about the added 

benefit of receiving so many NOI Sundry applications if information for a large majority of the 

hydraulic fracturing operations are relatively the same. 

It is likely that the alternative would compel operators on a substantial number of hydraulic 

fracturing operations to use storage tanks instead of pits; however, that number is not known at 

this time. This would immediately remove sources of harm to the environment and the public.

Alternative 1 would compel 3,816 SR Sundry reports and public disclosures of the chemical 

content of the hydraulic fracturing fluids. The increase in information about additives could aid 

water users when they consider the potential effects of hydraulic fracturing operations and 

constituent chemicals. 

Overall, this alternative would reduce the risks associated with hydraulic fracturing operations. 

Generally speaking, it could offer greater risk reduction than the rule, since it would require 

operators to conduct CELs on all casing strings that protect usable water. Also, the BLM would 

receive individual applications for all hydraulic fracturing operations. There could be some 

variability in the operations across hydraulic fracturing jobs on subsequent wells even if they are 

under a type well approval. The nature of hydraulic fracturing necessitates some degree of 

variability in plans, including the well depth, fluid mixture, and subsurface conditions. Since the 

BLM would receive and review each proposed operation individually, this alternative potentially 

offers greater risk reduction.

Benefits of Alternative 2

Possibly 5 or 6 hydraulic fracturing operations may use unlined pits without the regulation. 

However, even that number could overestimate the effect, since states currently without 

minimum requirements for pit liners or storage tanks are likely to adopt such regulations in the 

near future.
66

5. Economic Impact Analysis and Distributional Assessments 

5.1 Energy System Impact Analysis

Executive Order 13211 requires 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. 

The additional burden posed by this rule would vary by the type of well proposed for hydraulic 

fracture. As such, we estimate the additional cost burden under a number of well types (in Table 

13) and the average cost per hydraulic fracturing operation (in Table 24). 

A key consideration is the extent to which the costs of the requirements might impact 

investment, production, employment, and a number of other factors. That is, to what extent, if 

any, would an operator choose to invest in other areas, non-Federal and non-Indian lands, when 

faced with the cost requirements of the rule. Since the bulk of the costs would apply to hydraulic 

fracturing operations on wells that are yet to be drilled (and not on existing wells and to 

refracturing operations), operators will be able to account for any cost increases up front when 

making investment decisions. 

The BLM believes that the additional cost per hydraulic fracturing operation is insignificant 

when compared with the drilling costs in recent years, the production gains from hydraulically 

fractured well operations, and the net incomes of entities within the oil and natural gas industries. 

Table 26 shows the average compliance costs, by well type or operation, as a percent of the total 

costs of drilling a well. For a single well or a type well, the compliance costs represent about 0.4 

to 1.4 percent of the costs of drilling a well. For a subsequent well to a type well, the costs 

represent between 0.01 and 0.02 percent of the total drilling costs. For existing wells and 

refracture operations, the percentages are even lower, at about 0.01 to 0.03 percent. When 

averaging the compliance costs across all operations, the costs represent between 0.04 and 0.13 

percent of the costs of drilling a well. 

Since the estimated compliance costs are not substantial when compared with the total costs of 

drilling a well, we believe that the rule is 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. 
67

Table 26: The Average Compliance Costs of the Rule as a Percent of Total Drilling Costs

Activity

Well Type or Fracturing Operation

Average Across All 

Operations

Type Well or Single 

Well

Subsequent 

Well under 

Type Well 

Approval

Existing 

Well

ReFracture 

Low High Operation Low High

Percent of Drilling Costs 

for a Crude Oil, Natural 

Gas, and Dry Well (2007$) 

(1) 0.7128% 1.3301% 0.0167% 0.0243% 0.0241% 0.0752% 0.1225%

Percent of Drilling Costs 

for a Crude Oil Well 

(2007$) (1) 0.7434% 1.3871% 0.0174% 0.0253% 0.0251% 0.0784% 0.1277%

Percent of Drilling Costs 

for a Natural Gas Well 

(2007$) (1) 0.7611% 1.4202% 0.0178% 0.0259% 0.0257% 0.0803% 0.1308%

Percent of Drilling Costs 

for a horizontal well in the 

Bakken Three Forks 

(reported in 2010) (2) 0.5507% 1.0275% 0.0129% 0.0188% 0.0186% 0.0581% 0.0946%

Percent of Drilling Costs 

for a horizontal well in the 

Marcellus Shale (reported 

in 2011) (3) 0.3913% 0.7301% 0.0092% 0.0133% 0.0132% 0.0413% 0.0672%

Notes: 

(1) Average drilling costs in 2007 range from $3.9 million to about $4.2 million. (EIA 2012)

(2) Costs of $5.4 million cited by Investopedia from Continental Resources. (Investopedia 2010)

(3) Costs of $7.6 million cited by Marcellus Drilling News from a University of Pittsburgh Study (Marcellus 2011)
68

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 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 from firms in the 

crude oil and natural gas extraction industries (NAICS codes: : 211111 - Crude Petroleum and 

Natural Gas Extraction, 211112 - Natural Gas Liquid Extraction) to firms providing support 

services for drilling oil and gas wells (NAICS code: 213111 - Drilling Oil and Gas Wells). For 

example, the requirement for a CEL on the surface casing represents a burden to the operator but 

a benefit to the company running the log. 

Of principal 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. 

Firms in the support services for oil and gas drilling industry are likely to benefit from the rule, 

since they would likely carry out the operational requirements of the rule. Though we do not 

know the incremental revenue gains from performing these services, the operational 

requirements themselves are likely to require additional capacity. 

5.3 Small Business Impact 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, and 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 
69

that about 99 percent of the entities operating in the relevant sectors84 are small businesses in that 

they employ fewer than 500 employees. Also, within these relevant sectors, small firms account 

for 74 percent of the total value of shipments and receipts for services, 86 percent of the total 

cost of supplies, 78 percent of the total capital expenditures (excluding land and mineral rights), 

and 67 percent of the paid employees (see tables in Section 2.7). 

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

and natural gas extraction industry. As such, the 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 firms most likely to be affected by the rule are those conducting hydraulic fracturing 

activities on Federal and Indian lands. More specifically, the firms most impacted are expected 

to be those drilling new wells for hydraulic fracture completions. Using AFMSS data for well 

completions, we compiled a list of firms that completed wells within the past 5 years. We expect 

that these firms are most likely to be impacted. From that list, we researched for company 

annual report filings with the Securities and Exchange Commission (SEC) to determine annual 

company net incomes and employment figures. From the original list, we found 55 company 

filings. Of those, 33 were small businesses. 

Using the net income data for the companies that filed SEC Form 10-K, we used the estimated 

compliance costs per type of well or fracturing operation and the average costs across all 

operations to calculate the percent of compliance costs as a portion of annual company net 

incomes for 2011. We used the absolute values of the percentages in the average, so that the 

negative net incomes would not negate the positive net incomes, and vice versa. Averaging 

results for the small businesses that we examined, the average costs of the rule are expected to 

represent between 0.041 and 0.066 percent of the company net incomes. The results of those 

findings are in Table 29 and also in the Appendix.

Table 27: Compliance Costs as a Share of Company Net Income

Descriptive Statistic

Type of Well or Operation, and Average across All Operations (%)

Type well 

or single 

well (lower 

bound)

Type well 

or single 

well 

(upper 

bound)

Subsequent 

well under 

type well 

approval

Existing 

well

Refracture 

operation

Average

across all 

operations 

(lower 

bound)

Average 

across all 

operations 

(upper 

bound)

Average of absolute 

values

0.3838% 0.7161% 0.0090% 0.0131% 0.0130% 0.0405% 0.0660%

Minimum value -2.4855% -4.6377% -0.0583% -0.0847% -0.0839% -0.2622% -0.4271%

Maximum value 2.1196% 3.9549% 0.0497% 0.0722% 0.0715% 0.2236% 0.3642%

 

84 NAICS codes: 211111 - Crude Petroleum and Natural Gas Extraction, 211112 - Natural Gas Liquid Extraction, 

and 213111 - Drilling Oil and Gas Wells.
70

6. Statutory and Executive Order Reviews

6.1 Executive Order 12866 Regulatory Planning and Review

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. 

6.2 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 substantial number of small entities (SISNOSE). Small entities 

include small businesses, small governmental jurisdictions (including tribal governments), and 

small not-for-profit enterprises. 

The BLM reviewed the 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 percent of the entities 

operating in the relevant sectors are small businesses in that they employ fewer than 500 

employees. 

We also examined potential impacts on small businesses that are most likely to be impacted by 

the rule and, more specifically, the requirements that would pose a burden to operators. Using 

AFMSS data for well completions, we compiled a list of firms that completed wells within the 

past 5 years. We expect that these firms are most likely to be financially impacted by the CEL 

requirements. From that list, we researched for company annual report filings with the SEC to 

determine annual company net incomes and employment figures. From the original list, we 

found 55 company filings. Of those, 33 firms were classified as small businesses.

Using the net income data for the small businesses that filed SEC Form 10-K, we used the 

estimated compliance costs per well type or fracturing operation, and the average costs across all 

operations to calculate the percent of compliance costs as a portion of annual company net 

incomes for 2011. Averaging results for the small businesses that we examined, the average 

costs of the rule are expected to represent between 0.041 and 0.066 percent of the company net 

incomes. 
71

Therefore, after considering the economic impact of the rule on these small entities, the 

screening analysis indicates that this rule will not have a significant economic impact on a 

substantial number of small entities.

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

Under the Unfunded Mandates Act, agencies must prepare a written statement about benefits and 

costs prior to issuing a proposed or final rule that may result in aggregate expenditure by State, 

local, and tribal governments, or by the private sector, of $100 million or more in any one year.

This 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 rule is also not subject to the requirements of sections 202 or 205 of UMRA.

This 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.

6.4 Executive Order 13211 Actions Concerning Regulations that Significantly 

Affect Energy Supply, Distribution, or Use

Under Executive Order 13211, agencies are required to prepare and submit to OMB a Statement 

of Energy Effects for significant energy actions. This Statement is to include a detailed 

statement of “any adverse effects of energy supply, distribution, or use (including a shortfall in 

supply, price increases, and increase use of foreign supplies)” for the action and reasonable 

alternatives and their effects. 

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. 

The BLM believes that the additional cost per hydraulic fracturing operation is insignificant 

when compared with the drilling costs in recent years, the production gains from hydraulically 

fractured well operations, and the net incomes of entities within the oil and natural gas industries. 

For a single well or a type well, the compliance costs represent about 0.4 to 1.5 percent of the 

costs of drilling a well. For a subsequent well to a type well, the costs represent between 0.04 

and 0.08 percent of the total drilling costs. For existing wells and refracture operations, the 

percentages are even lower, at about 0.01 to 0.03 percent. When averaging the compliance costs 

across all operations, the costs represent between 0.04 and 0.13 percent of the costs of drilling a 

well. 
72

Since the estimated compliance costs are not substantial when compared with the total costs of 

drilling a well, we believe that the rule is 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. As such, the 

rule is not a “significant energy action” as defined in Executive Order 13211. 
73

7. Conclusion

Combined with horizontal drilling, hydraulic fracturing has grown in significance over the past 

decade, allowing oil and gas operators to produce from shale and tight formations that previously 

were uneconomic. The well completion technique involves injecting fluids--containing water, 

proppants, and chemicals--into the reservoir rock with sufficient pressure to fracture the rock and 

thus access the resources that were previously trapped. The technique has been under scrutiny 

because it is resource intensive and many are concerned about potential surface and subsurface 

damage to freshwater aquifers. 

A report conducted by the Secretary of Energy’s Advisory Board Natural Gas Subcommittee

made several recommendations for operators and regulatory authorities who manage oil and gas 

development. It recommended that they adopt best practices in well development and 

construction, especially casing, cementing, and pressure management. It recommended the use 

of pressure testing, and cement bond logs to confirm formation isolation, and that regulations and 

inspection activity confirm that operators take prompt action to repair defective cementing jobs. 

The BLM has existing regulations on hydraulic fracturing that were conceived before the 

operations grew in prevalence and magnitude to where they are today. It requires NOI Sundry 

applications for “non-routine” fracturing operations, but is unclear about what that means. This 

omission makes the regulation functionally difficult to apply. Also, from a resource 

management perspective, the current regulation results in incomplete information being provided 

to the BLM. The lack of information restricts the BLM’s ability to make informed resource 

decisions about proposed hydraulic fracturing operations. It also restricts the BLM’s ability to 

respond effectively to events where environmental resources have been compromised. 

This rule seeks to improve governmental processes by requiring necessary information about 

proposed hydraulic fracturing operations and subsequent reports to confirm that the operations 

were conducted in a safe manner. Ultimately, the reporting requirements of the rule would help 

the BLM better manage and protect the public’s resources. The rule also seeks to minimize the 

risks associated with hydraulic fracturing by placing requirements to help ensure wellbore 

integrity and proper management of flowback.

This analysis attempts to measure the potential costs and benefits that would occur as a result of 

the rule. As such, it attempts to measure the impacts in relation to the current operating 

environment. An important aspect of this analysis and the rule itself is the distinction between 

the activities that operators currently conduct and those additional activities that the rule would 

compel. This change in behavior is the basis of the cost and benefit estimates. Operators 

conduct many of the activities required by the rule as a matter of standard industry practice or to 

comply with other state and Federal regulations or conditions of approvals for permits. 

Potential costs of the rule are easier to estimate because the requirements are clear. The 

challenge lies in estimating the potential unintended consequences of the rule. The rule has a 

requirement that would add an additional step to the drilling process. A large source of 

uncertainty is whether operators would be able to incorporate that step into their current process 
74

without incurring costs associated with drilling delays. The benefits are more uncertain, because 

much of the potential damage from hydraulic fracturing may occur in the subsurface 

environment, making it difficult to first identify and then to assign responsibility to an operation. 

The compliance costs of the rule are estimated to be between $12 and $20 million per year. The 

estimated costs of the alternatives are much higher, generally between $115 and $215 million per 

year. This rule would impose fewer costs than the alternatives, primarily because it would 

require fewer cement evaluation logs. The rule would require operators on a single or a type 

well to conduct cement evaluation logs on casing strings that protect usable water. Operators 

may seek and receive approval to forego the requirement on subsequent wells under a type well 

approval. The usefulness of this exemption relies on its functional application. The rule would 

also require operators to run logs on wells where there is an indication of an inadequate cement 

job. This will likely apply to between 1 and 5 percent of wells. Operators are currently required 

to take remedial action when there is inadequate cementing, so the proposed rule would require 

that the operator run a log.

Among the alternatives examined, the BLM explored the option of requiring operators to manage 

flowback in storage tanks rather than pits. We were unable to estimate total compliance costs for 

this alternative requirement, since the prevalence of voluntary storage tank use, in general, is 

unknown. We believe that managing flowback in storage tanks could cost operators between 

$6,000 and $17,000 per well if trucking the flowback off-site and $42,000 per well if recycling 

flowback to use as fluid for subsequent hydraulic fracturing operations on-site.

OMB Circular A-4 recognizes that not all benefits and costs can be described in monetary or 

even in quantitative terms. The potential benefits of the rule are more challenging to monetize 

than the costs, but that does not mean that rule is without benefits. The rule is designed to reduce 

the environmental and safety risks posed by hydraulic fracturing operations, particularly in its 

treatment of flowback fluids, well construction, and hydraulic fracture design. 

The rule requires operators to take steps to ensure that wellbore integrity is maintained prior to 

and throughout the hydraulic fracturing process. It also requires operators to provide the BLM 

with information about the fracturing plan and design. We estimate that operators would submit 

an average of 432 NOI Sundry applications per year covering about 11 percent of hydraulic 

fracturing operations. The requirement should help the BLM to make informed decisions about 

fracturing proposals and potentially avoid other surface or subsurface damage.

The rule would compel operators to demonstrate wellbore integrity by conducting pressure tests 

on 100 percent of wells and by conducting CELs on the casing strings that protect usable water 

for about 8 percent of the wells. The rule would compel 110 CELs to demonstrate that 

inadequate cementing was corrected by operators. As such, it requires a verification of proper 

remedial cementing on the very wells that pose greater risk. Relative to the alternatives, the rule 

provisions would not compel as many CELs. Therefore, there is a chance that the rule would not 

reduce as much risk as the alternatives. However, the estimated costs of the alternatives far 

exceed the estimated costs of the proposed rule.
75

The rule would compel an estimated 3,816 SR Sundry reports and public disclosures of the 

chemical content of the hydraulic fracturing fluids annually. The increase in information about 

additives could aid water users when they consider the potential effects of hydraulic fracturing 

operations and constituent chemicals. 

Overall, the rule is likely to reduce the risks associated with hydraulic fracturing operations, but 

it is unclear by how much. Without any policy intervention, we estimate the likelihood of an 

incident resulting from a hydraulic fracturing operation to be between 0.03 and 2.70 percent. 

Damage from an incident could cost between $15,000 and $1 million for remediation plus any 

lost revenue from unrecoverable resources, including spilled or stranded resources.
76

8. References

American Petroleum Institute (2009). Hydraulic Fracturing Operations – Well Construction and 

Integrity Guidelines. API Guidance Document HF1. First Edition.

American Petroleum Institute. (July 19, 2010). Freeing Up Energy. Hydraulic Fracturing: 

Unlocking America’s Natural Gas Resources.

American Petroleum Institute (2010). “Water Management Associated with Hydraulic 

Fracturing. API Guidance Document HF2. First Edition.”

Behr, P. (October 1, 2012). Safety of shale gas wells is up to the states – and the ‘cement job’. 

EnergyWire. Retrieved from 

http://www.eenews.net/energywire/2012/10/01/archive/1?terms=hydraulic+fracturing+10

%2F01%2F2012

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

Downey, M. (2009). Oil 101. Wooden Table Press, LLC.

Executive Office of the President, Office of Management and Budget, Circular A-4, September 

17, 2003.

Executive Office of the President, Office of Management and Budget, Circular A-94, October 

29, 1992.

Executive Office of the President, Office of Management and Budget, Executive Order 12866, 

January 18, 2007.

Executive Office of the President, Office of Management and Budget, Executive Order 13211, 

May 5, 2001.

Executive Office of the President, Office of Management and Budget, Executive Order 13563, 

January 18, 2011. 

Groat, C. & Grimshaw, T. (February 2012). Fact-based regulation for environmental protection 

in shale gas development. The Energy Institute.

Investopedia (March 12, 2010). Oil service costs to move higher. Retrieved from 

http://www.investopedia.com/stock-analysis/2010/mondaymarch-15-oil-service-costs-tomove-higher-clr-xco-sd-bexp0315.aspx?partner=YahooSA#axzz2EleoUQQw
77

Marcellus Drilling News (September 2011). How much does it cost to drill a single Marcellus 

well? $7.6M. Retrieved from http://marcellusdrilling.com/2011/09/how-much-does-itcost-to-drill-a-single-marcellus-well-7-6m/

National Energy Technology Laboratory (2009). Modern Shale Gas Development in the United 

States: A Primer. U.S. Department of Energy.

Osborn, S., et al (2011). Methane contamination of drinking water accompanying gas-well 

drilling and hydraulic fracturing. Proceedings of the National Academy of Sciences.

Secretary of Energy Advisory Board (2011). Shale Gas Production Subcommittee Second 

Ninety Day Report. November 18, 2011. Retrieved from 

http://www.shalegas.energy.gov/resources/111811_final_report.pdf

Shires, T. and Lev-On, M (September 21, 2012). Characterizing Pivotal Sources of Methane 

Emissions from Natural Gas Production: Summary and Analysis of API and ANGA 

Survey Responses.” 

U.S. Census Bureau (2010). "Mining: Subject Series: General Summary: Industry Statistics by 

Employment Size: 2007 Economic Census." January 28, 2012. Retrieved from 

http://factfinder2.census.gov/faces/tableservices/jsf/pages/productview.xhtml?pid=ECN_

2007_US_21SG13&prodType=table

U.S. Energy Information Administration (January 23, 2012). Annual Energy Outlook with 

Projections to 2035. 

U.S. Energy Information Administration (January 31, 2012). Costs of Crude Oil and Natural 

Gas Wells Drilled. Retrieved from 

http://www.eia.gov/dnav/ng/ng_enr_wellcost_s1_a.htm

U.S. Environmental Protection Agency (January 31, 2012). Natural Gas Extraction – Hydraulic 

Fracturing. Retrieved from http://www.epa.gov/hydraulicfracture/#providing

U.S. Small Business Administration (2010). "Table of Small Business Size Standards Matched 

to North American Industry Classification System Codes." Retrieved November 5, 2010.

U.S. Office of Personnel Management (2009). “Salaries & Wages: Salary Table 2009-GS.” 

January 31, 2012. Retrieved from http://www.opm.gov/flsa/oca/09tables/html/gs_h.asp

Warner, N., et al (2012). Geochemical evidence for possible natural migration of Marcellus 

Formation brine to shallow aquifers in Pennsylvania. Proceedings of the National 

Academy of Sciences, Vol. 109, July 24, 2012.
78

9. Appendix

A-1 Estimation of Type Well Applicability

A-2 Sample of Small Businesses
79

Appendix A-1

Estimation of Type Well Applicability

Descriptive Statistic Grouping Method

By Case By Field By Township

Total Wells 17,475 17,475 17,475

Count of Grouping Category 

(e.g. # cases)

3,449 1,390 1,315

Average 5.067 12.572 13.289

Standard Deviation 27.608 62.011 55.103

Median 1 2 2

Low 1 1 1

High 1,048 1,446 1,048
80

Appendix A-2

Sample of Small Businesses

Includes companies that completed wells with the past 5 years and filed SEC 10-K forms in 2012

Shaded companies are small businesses

Company

Number 

of 

Employees

2011 

Company 

Net Income 

($)

Comments Explaining 

Company Losses

Per Unit Compliance Costs as a Share of Company Net Income by Well Type (%)

Type well or 

single well 

(lower 

bound)

Type well or 

single well 

(upper 

bound)

Subsequent 

well under 

type well 

approval Existing well

Refracture

operation

Average 

across all 

operations 

(lower 

bound)

Average 

across all 

operations 

(upper 

bound)

1 2 2,535,599 1.2663% 2.2818% 0.1210% 0.0399% 0.0396% 0.1237% 0.2015%

2 5 -1,196,440 Paid down accounts 

payable

-2.6836% -4.8358% -0.2563% -0.0847% -0.0839% -0.2622% -0.4271%

3 6 -5,268,905 -0.6094% -1.0981% -0.0582% -0.0192% -0.0191% -0.0596% -0.0970%

4 11 -11,600,158 -0.2768% -0.4988% -0.0264% -0.0087% -0.0087% -0.0270% -0.0441%

5 19 162,388,000 0.0198% 0.0356% 0.0019% 0.0006% 0.0006% 0.0019% 0.0031%

6 20 10,384,496 0.3092% 0.5572% 0.0295% 0.0098% 0.0097% 0.0302% 0.0492%

7 23 -4,104,338 -0.7823% -1.4097% -0.0747% -0.0247% -0.0245% -0.0764% -0.1245%

8 23 11,687,000 0.2747% 0.4951% 0.0262% 0.0087% 0.0086% 0.0268% 0.0437%

9 32 -27,841,000 -0.1153% -0.2078% -0.0110% -0.0036% -0.0036% -0.0113% -0.0184%

10 42 -1,764,000 Losses the past 3 years 

due to expanding the 

company (buying 

acreage, exploratory 

drilling, drilling 

advances)

-1.8201% -3.2799% -0.1739% -0.0574% -0.0569% -0.1779% -0.2897%

11 62 1,753,000 1.8316% 3.3005% 0.1750% 0.0578% 0.0573% 0.1790% 0.2915%

12 77 392,678,000 0.0082% 0.0147% 0.0008% 0.0003% 0.0003% 0.0008% 0.0013%

13 96 12,691,000 0.2530% 0.4559% 0.0242% 0.0080% 0.0079% 0.0247% 0.0403%

14 104 13,743,000 0.2336% 0.4210% 0.0223% 0.0074% 0.0073% 0.0228% 0.0372%

15 113 -31,758,000 -0.1011% -0.1822% -0.0097% -0.0032% -0.0032% -0.0099% -0.0161%

16 145 65,179,000 0.0493% 0.0888% 0.0047% 0.0016% 0.0015% 0.0048% 0.0078%

17 146 79,390,000 0.0404% 0.0729% 0.0039% 0.0013% 0.0013% 0.0040% 0.0064%

18 153 -132,915,000 -0.0242% -0.0435% -0.0023% -0.0008% -0.0008% -0.0024% -0.0038%
81

Company

Number 

of 

Employees

2011 

Company 

Net Income 

($)

Comments Explaining 

Company Losses

Per Unit Compliance Costs as a Share of Company Net Income by Well Type (%)

Type well or 

single well 

(lower 

bound)

Type well or 

single well 

(upper 

bound)

Subsequent 

well under 

type well 

approval Existing well

Refracture

operation

Average 

across all 

operations 

(lower 

bound)

Average 

across all 

operations 

(upper 

bound)

19 163 72,061,000 0.0446% 0.0803% 0.0043% 0.0014% 0.0014% 0.0044% 0.0071%

20 169 36,629,000 0.0877% 0.1580% 0.0084% 0.0028% 0.0027% 0.0086% 0.0140%

21 170 -57,480,023 Blame losses and 

variability of net 

income on "dry hole 

costs"

-0.0559% -0.1007% -0.0053% -0.0018% -0.0017% -0.0055% -0.0089%

22 186 105,554,000 0.0304% 0.0548% 0.0029% 0.0010% 0.0010% 0.0030% 0.0048%

23 188 1,403,000 2.2885% 4.1239% 0.2186% 0.0722% 0.0715% 0.2236% 0.3642%

24 305 -76,761,000 Estimates of reserves 

decline, lowering 

market prices making 

drilling uneconomic

-0.0418% -0.0754% -0.0040% -0.0013% -0.0013% -0.0041% -0.0067%

25 305 -76,661,000 -0.0419% -0.0755% -0.0040% -0.0013% -0.0013% -0.0041% -0.0067%

26 313 30,707,000 0.1046% 0.1884% 0.0100% 0.0033% 0.0033% 0.0102% 0.0166%

27 317 -228,063,000 Company factors field 

reserves into net 

earnings calculation.

-0.0141% -0.0254% -0.0013% -0.0004% -0.0004% -0.0014% -0.0022%

28 333 35,809,000 0.0897% 0.1616% 0.0086% 0.0028% 0.0028% 0.0088% 0.0143%

29 352 194,332,000 0.0165% 0.0298% 0.0016% 0.0005% 0.0005% 0.0016% 0.0026%

30 365 62,314,000 0.0515% 0.0928% 0.0049% 0.0016% 0.0016% 0.0050% 0.0082%

31 395 110,698,000 0.0290% 0.0523% 0.0028% 0.0009% 0.0009% 0.0028% 0.0046%

32 462 73,132,000 0.0439% 0.0791% 0.0042% 0.0014% 0.0014% 0.0043% 0.0070%

33 477 90,046,000 0.0357% 0.0643% 0.0034% 0.0011% 0.0011% 0.0035% 0.0057%

34 529 122,408,000 0.0262% 0.0473% 0.0025% 0.0008% 0.0008% 0.0026% 0.0042%

35 592 548,137,000 0.0059% 0.0106% 0.0006% 0.0002% 0.0002% 0.0006% 0.0009%

36 609 429,072,000 0.0075% 0.0135% 0.0007% 0.0002% 0.0002% 0.0007% 0.0012%

37 639 215,400,000 0.0149% 0.0269% 0.0014% 0.0005% 0.0005% 0.0015% 0.0024%

38 692 491,600,000 0.0065% 0.0118% 0.0006% 0.0002% 0.0002% 0.0006% 0.0010%

39 761 42,048,000 0.0764% 0.1376% 0.0073% 0.0024% 0.0024% 0.0075% 0.0122%

40 824 529,932,000 0.0061% 0.0109% 0.0006% 0.0002% 0.0002% 0.0006% 0.0010%
82

Company

Number 

of 

Employees

2011 

Company 

Net Income 

($)

Comments Explaining 

Company Losses

Per Unit Compliance Costs as a Share of Company Net Income by Well Type (%)

Type well or 

single well 

(lower 

bound)

Type well or 

single well 

(upper 

bound)

Subsequent 

well under 

type well 

approval Existing well

Refracture

operation

Average 

across all 

operations 

(lower 

bound)

Average 

across all 

operations 

(upper 

bound)

41 876 267,200,000 0.0120% 0.0217% 0.0011% 0.0004% 0.0004% 0.0012% 0.0019%

42 880 206,679,000 0.0155% 0.0280% 0.0015% 0.0005% 0.0005% 0.0015% 0.0025%

43 1,200 292,000,000 0.0110% 0.0198% 0.0011% 0.0003% 0.0003% 0.0011% 0.0018%

44 1,643 539,000,000 0.0060% 0.0107% 0.0006% 0.0002% 0.0002% 0.0006% 0.0009%

45 1,835 479,769,000 0.0067% 0.0121% 0.0006% 0.0002% 0.0002% 0.0007% 0.0011%

46 1,876 453000000 0.0071% 0.0128% 0.0007% 0.0002% 0.0002% 0.0007% 0.0011%

47 2,550 1,091,123,000 0.0029% 0.0053% 0.0003% 0.0001% 0.0001% 0.0003% 0.0005%

48 3,304 881,914,000 0.0036% 0.0066% 0.0003% 0.0001% 0.0001% 0.0004% 0.0006%

49 3,322 2946000000 0.0011% 0.0020% 0.0001% 0.0000% 0.0000% 0.0001% 0.0002%

50 4,800 -

2,649,000,000

Company cited loss due 

to settlement 

agreement.

-0.0012% -0.0022% -0.0001% 0.0000% 0.0000% -0.0001% -0.0002%

51 5,200 4,704,000,000 0.0007% 0.0012% 0.0001% 0.0000% 0.0000% 0.0001% 0.0001%

52 5,299 11,750,000 0.2733% 0.4924% 0.0261% 0.0086% 0.0085% 0.0267% 0.0435%

53 8,120 660,000,000 0.0049% 0.0088% 0.0005% 0.0002% 0.0002% 0.0005% 0.0008%

54 8,147 434,186,000 0.0074% 0.0133% 0.0007% 0.0002% 0.0002% 0.0007% 0.0012%

55 11,300 6,771,000,000 0.0005% 0.0009% 0.0000% 0.0000% 0.0000% 0.0000% 0.0001%