Regulatory Impact Analysis for

Hydraulic Fracturing Rule

U.S. Bureau of Land Management
i

Table of Contents

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

2. Background...........................................................................................................................................4

2.1 Requirements for Economic Analysis..............................................................................................4

2.2 Need for Policy Action ....................................................................................................................6

2.3 Final Rule Requirements and Discussion ......................................................................................10

2.4 Consideration of Alternative Approaches......................................................................................26

2.5 Alternatives to Direct Regulation ..................................................................................................28

2.6 Federal and Indian Oil and Gas Leasing Activity..........................................................................29

2.7 Hydraulic Fracturing on Federal and Indian Lands.......................................................................31

2.8 Industry Classifications..................................................................................................................34

2.9 Industry Standards for Well Construction and Integrity for Hydraulic Fracturing Operations .....36

2.10 Industry Standards for Water Management Associated with Hydraulic Fracturing..................40

2.11 Existing Regulations Related to the Rule’s Provisions .............................................................41

2.11.1 Existing BLM Regulations and Requirements..................................................................41

2.11.2 Summary of Existing State Regulations...........................................................................51

3. Estimating Benefits and Costs............................................................................................................57

3.1 Theoretical Framework..................................................................................................................57

3.2 Measuring the Incremental Costs...................................................................................................58

3.3 Benefits Framework.......................................................................................................................77

3.4 Discounted Present Value ..............................................................................................................80

3.5 Uncertainty.....................................................................................................................................80

4. Results.................................................................................................................................................82

4.1 Costs of the Rule............................................................................................................................82

4.2 Cost Breakout According to Federal and Tribal Lands .................................................................83

4.3 Cost Breakout by Activity .............................................................................................................88

4.4 Compliance Costs Per-Operation...................................................................................................88

Table 11C: Workload Required for BLM to Review Information Associated with the Rule................91

4.5 Examination of Alternative Approaches........................................................................................92

5. Economic Impact Analysis and Distributional Assessments..............................................................95

5.1 Energy System Impact Analysis....................................................................................................95
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5.2 Employment Impact Analysis........................................................................................................95

5.3 Small Business Impact Analysis....................................................................................................96

6. Statutory and Executive Order Reviews.............................................................................................98

6.1 Executive Order 12866 Regulatory Planning and Review ............................................................98

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

U.S.C. 601-612)......................................................................................................................................98

6.3 Unfunded Mandates Reform Act of 1995 (P.L. 104-4).................................................................99

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

Distribution, or Use.................................................................................................................................99

7. Conclusion ........................................................................................................................................101

8. References.........................................................................................................................................103

9. Appendix...........................................................................................................................................105
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1. Introduction

The Bureau of Land Management (BLM) estimates that operators conduct hydraulic fracturing 

on roughly 90 percent of the wells on Federal and Indian lands. 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. 

During the 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 potential impacts to 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 carries forward requirements in existing BLM regulations and 

establishes new requirements that are generally consistent with existing industry guidance on

hydraulic fracturing. The rule would primarily require an operator planning to conduct hydraulic 

fracturing to do the following:

 Submit information about the proposed hydraulic fracturing operation to the BLM with 

the Application for Permit to Drill (APD) or a Notice of Intent (NOI) Sundry (with a few 

exceptions, detailed below, for certain recently drilled wells that are fracked within 90 

days of the effective date of the rule);

 Design and implement a casing and cementing program that protects and/or isolates

usable water, defined generally as those waters less than 10,000 parts per million (ppm) 

of total dissolved solids (TDS);

 Monitor cementing operations during well construction and provide reports to the BLM 

prior to the hydraulic fracturing operation;
2

 Take remedial action if there are indications of inadequate cementing and demonstrate 

that the remedial action was successful prior to the hydraulic fracturing operation;

 Demonstrate that there is at least 200 feet of adequately-bonded cement between the zone 

to be hydraulically fractured and the deepest usable water zone with a cement evaluation 

log (CEL), unless the operator returns the cement behind the casing to surface;

 Perform a successful mechanical integrity test (defined as a pressure test on the string 

through which the fracturing will occur) prior to the hydraulic fracturing operation;

 Monitor annulus pressures during the hydraulic fracturing operation;

 Manage recovered fluids in rigid enclosed, covered, or netted and screened above-ground 

tanks (with tank capacity limited to 500 barrels or bbl) – operators may seek approval to 

use a lined pit with a leak detection system under certain circumstances specified in the 

rule;

 Submit information to the BLM after the hydraulic fracturing operation in a Subsequent 

Report (SR) Sundry; and

 Disclose the chemicals used to the BLM through FracFocus – operators may withhold

formulations that are trade secrets.

This regulatory impact analysis examines the potential costs and benefits of these requirements. 

Various statutes and executive orders require Federal agencies to examine such impacts when 

proposing a regulatory action. This analysis examines the requirements of the final rule and the 

alternatives to those requirements. Similar analyses were prepared for the proposed rule and the 

supplement to the proposed rule.

After reviewing the requirements of the final rule, we have determined that it 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. Additionally, we have 

determined that it would not have a significant economic impact on a substantial number of 

small entities. 

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

practice or in compliance with existing state regulations or other BLM regulations (including 

Onshore Oil and Gas Orders No. 1 and No. 2).

1

 We measure the incremental burden to operators 

against that baseline. While some requirements do not pose an additional burden, other 

requirements will pose an additional burden. 

We estimate that the rule will impact about 2,800 hydraulic fracturing operations per year, but 

that it could impact up to 3,800 operations per year based on previous levels of activity on 

Federal lands and growing activity on Indian lands. We estimate that the compliance cost could 

reach about $11,400 per operation or $32 million per year. The estimated per-operation 

 

1 Onshore Order 1 is available on the web at 

http://www.blm.gov/style/medialib/blm/wo/MINERALS__REALTY__AND_RESOURCE_PROTECTION_/energ

y/onshore_order_videos.Par.62610.File.dat/Onshore_Order_No_1_The_Order.pdf and Onshore Order 2 is available 

at http://www.blm.gov/wy/st/en/programs/energy/Oil_and_Gas/docs/onshore_order_2.html.
3

compliance costs represent about 0.13 to 0.21 percent of the cost of drilling a well. Given the 

potential to impact 3,800 operations per year, the compliance costs might reach $45 million per 

year. 

There are reasons why we believe these cost estimates may be overstated and that the true costs 

of the rule will be less. We attribute most of the costs to two requirements: (1) Demonstrating 

with a CEL that there is 200 feet of adequately-bonded cement between the zone to be 

hydraulically fractured and the deepest usable water zone when the operator chooses not to have 

the intermediate or production casing cemented to surface, and (2) Use of rigid above-ground 

storage tanks to manage recovered fluids. For both of these requirements, we would expect a 

large degree of voluntary compliance regardless of the rule. This expectation is validated by our 

observations of field operations where operators generally: (1) Use a CEL to verify the cement 

behind the intermediate casing string (to demonstrate that it cemented the well according to the 

design and/or when conducting hydraulic fracturing through a production liner) or the production 

casing (to demonstrate that it cemented the well according to the design and/or when conducting 

hydraulic fracturing through the production string); and (2) Use rigid steel above-ground tanks to 

manage and transport recovered fluids from hydraulic fracturing operations. This analysis 

estimates the voluntary use of rigid above-ground storage tanks to manage recovered fluids for 

operations in states that do not have requirements mandating their use; however the analysis may 

still overstate the compliance costs to the industry due to uncertainty about requirements in some 

areas. 

The rule will reduce the risks associated with hydraulic fracturing operations on Federal and 

Indian lands. The rule includes operational requirements regarding casing and cementing 

programs, pressure testing prior to completion operations, and monitoring annulus pressures 

during completion operations. The majority of these requirements are consistent with industry 

guidance or voluntary practice, and some are required by state regulations, which are highly 

variable from state to state. However, this rule will make these best practices mandatory on all 

Federal and Indian lands and increase the assurance that operators conduct hydraulic fracturing 

in an environmentally sound and safe manner. 

The rule also includes fluid management requirements mandating the use of rigid above-ground 

storage tanks to manage recovered fluids that exceed industry guidance (although reflect the 

voluntary practices of some operators) and are consistent with regulations in Texas and New 

Mexico, but exceed those of other states. Thus, the rule will provide additional benefits by 

reducing the potential risks to surface and groundwater resources.

In addition, the rule will provide for increased public access to detailed information about the 

hydraulic fracturing operations taking place, including the chemicals used during the operations

and the location and nature of the operation. These disclosures will increase public awareness 

and understanding of these operations. 
4

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 elements2:

 A statement of the need for the proposed action;

 An examination of alternative approaches; and

 An analysis of benefits and costs.

 

2 OMB Circular A-4.
5

The Regulatory Flexibility Act (RFA) and the Small Business Regulatory Enforcement Fairness 

Act (SBREFA) require agencies to analyze the economic impact of regulations to determine 

whether there would be a significant economic impact on a substantial number of small entities. 

If a rule will have a significant economic impact on a substantial number of small entities when 

it is promulgated, then agencies must conduct an initial regulatory flexibility analysis with the 

proposed rule and a final regulatory flexibility analysis with the final rule.3 If the rule will not 

have a significant economic impact on a substantial number of small entities when it is 

promulgated, then agencies do not have to conduct the initial or final regulatory flexibility 

analyses.4

The United States Code also requires special considerations if the Office of Information and 

Regulatory Affairs (OIRA) of the Office of Management and Budget (OMB) determines that the 

rule is “major.”5 A rule is major if it has resulted in or is likely to result in:

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

 A major increase in costs or prices for consumers, individual industries, Federal, State, or 

local government agencies, or geographic regions; or 

 Significant adverse effects on competition, employment, investment, productivity, 

innovation, or on the ability of United States-based enterprises to compete with foreignbased enterprises in domestic and export markets. 

If OIRA determines that a rule is major, then the rule may become effective 60 days after the 

agency promulgates it and submits it to Congress. A major rule is subject to congressional 

review during this time and other procedural requirements.

6

 If OIRA determines that the rule is 

not major, then it becomes effective when the agency submits it to Congress.

Executive Order 13272 reinforces executive intent that agencies give serious attention to impacts 

on small entities and develop regulatory alternatives to reduce the regulatory burden on small 

entities. When the proposed regulation will impose a significant economic impact on a 

substantial number of small entities, the agency must evaluate alternatives that would accomplish 

the objectives of the rule without unduly burdening small entities. 

 

3 Under 5 U.S.C. 603 and 5 U.S.C. 604, respectively.

4 Under 5 U.S.C. 605.

5 Under 5 U.S.C. 804.

6 Described in 5 U.S.C. 801.
6

2.2 Need for Policy Action

The rule is designed to reduce the environmental and safety risks posed by hydraulic fracturing 

operations, particularly in its treatment of hydraulic fracture design, well construction, and

management of recovered fluids. The 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 will help the BLM better manage and protect the public’s resources, and to carry 

out the Secretary’s responsibilities on Indian lands. 

Subject Reports and Recommendations

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, or oil or gas 

liberated by hydraulic fracturing, will migrate into shallower drinking water sources with 

potential contamination made more likely if the wellbore integrity is compromised. Most reports 

suggesting that hydraulic fracturing operations contributed to contamination of water supplies 

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 20117and in 20128finding 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 drinkingwater 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 least likely 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 

 

7 Osborn et al. (2011). 

8 Warner et al. (2012). 
7

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 the extent to which this possibility has occurred 

is unknown.

The BLM is aware that a small number of hydraulic fracturing operations on Federal lands have 

communicated with other wells in their vicinity. These hydraulic fracturing operations created 

fractures that connected with existing fissures or fractures in the shale, allowing pressurized fluid 

to flow into wellbores. During these instances of downhole inter-well communication, known as 

“frack hits,” the pumped-in hydraulic fracturing fluid may flow into and up through the nearby 

well causing a blowout and spill.

We provide a sample of some of the incidents with a description below:

1. New Mexico, Feb 10, 2012 - A horizontal well being fractured communicated downhole 

with an older producing well, leading to a spill of 9,000 gallons of oil. The wells were 

separated by 600 feet. About 4300 gallons of oil spill was recovered and the site was 

later cleaned up. 

2. New Mexico, Nov 20, 2012 - The Tiger 11 Federal #1H (horizontal well located 30’ FNL 

& 990’ FWL, sec. 11, T20S-R34E) was being fractured. The fracture path intercepted the 

Federal #3 (vertical well). The fluids entered a second facility (Federal #1, located 1980’ 

FNL & 2130’ FWL) via flow lines and over-topped an open top fiberglass tank to 

overflow 1220 bbls of fluids into an unlined firewall. The majority of the overflow were

fracturing fluids. This interception occurred during Stage 9, after the first two stages 

(beginning from the toe of the horizontal section) were completed without any problem. 

3. Colorado, Jan 14, 2013 - MARALEX Well No. USA JC 1-20 (vertical, Shut In well) was 

impacted by a Mancos Horizontal hydraulic fracturing well within 300 feet of this well 

resulting in 200 bbls of produced water spill. 

4. New Mexico, Sept. 29, 2013 - The Parko Oil’s wellhead had ruptured and was spewing 

oil, nitrogen gas and wastewater. On that day, a hydraulic fracturing job by Encana Oil 

& Gas (USA) Inc. at a nearby well pad affected a Parko Oil well, causing a spill of 200 

barrels of oil and fracturing fluid. Of the contaminants, 75 barrels were recovered.

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.9

 

9 EPA 2014. “Natural Gas Extraction – Hydraulic Fracturing.”
8

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.”10

 

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. 

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.

Improving Governmental Processes

The BLM has an existing regulation for hydraulic fracturing, found at 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 regulation makes a distinction between 

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

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

regulated public. 

 

10 SEAB 2011, pp. 16-17. Available at http://www.shalegas.energy.gov.
9

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

conducted decades ago. For decades, hydraulic fracturing was a completion or re-completion 

technology that used relatively small quantities of fluid to improve the flow of hydrocarbons 

around the bottom of conventional wells. Due to advances in horizontal drilling, hydraulic 

fracturing operations are now conducted on wells with longer lateral legs (often one to two 

miles) 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 disclosure of the chemicals in fracturing fluids. 

From a resource management perspective, the current regulation results in incomplete 

information being provided to the BLM. As the resource manager or trustee, the lack of 

information restricts the BLM’s ability to make informed resource decisions about proposed 

hydraulic fracturing operations or to respond effectively to incidents that may occur. Knowledge 

of the hydraulic fracturing operations will help the BLM better manage and protect the public’s

resources and the resources of tribes and individual Indians.

Potential for Externalities 

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

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

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

where the well may extend laterally and for longer distances, greater pressures are placed on the 

well, and larger volumes of fluids are used and recovered. As with all drilling and production 

activities, there is a potential that they may pose a negative externality11 to society, considering 

limitations in understanding the extent of potential damage or determining a causal relationship 

between the operation and the damage.

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

inadequately constructed may not sufficiently isolate formation gas or fluids from 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 through 

verification to account for advances in technology and hydraulic fracturing operations. In 

addition, the recovered fluid from hydraulic fracturing operations may pose additional risk to the 

surface and subsurface environments if not managed and disposed of properly. The final rule has 

new requirements to reduce this risk. 

 

11 A negative externality is an economic activity that imposes a negative effect on an unrelated third party.
10

2.3 Final Rule Requirements and Discussion

This section describes the final requirements and the significance of the requirements. In parts, we reference industry guidance on 

hydraulic fracturing, namely two American Petroleum Institute (API) documents: API Guidance Document HF1 “Hydraulic 

Fracturing Operations – Well Construction and Integrity Guidelines” and API Guidance Document HF2 “Water Management 

Associated with Hydraulic Fracturing.” We discuss the guidance in further details in sections 2.9 and 2.10 of this report. We also 

refer to BLM regulations and some state regulations, but we discuss them in further detail in section 2.11 of this report.

Provision Significance

Sec. 3160.0-5 Definitions.

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

may be the wall of either the borehole or casing; sometimes also called 

annular space.

* * * * *

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

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

casing and supplies the means for the annulus to be sealed.

* * * * *

Cement Evaluation Log (CEL) means any one of a class of tools that verify 

the integrity of annular cement bonding, such as, but not limited to, a cement 

bond log (CBL), ultrasonic imaging log, variable density logs, CBLs with 

directional receiver array, ultrasonic pulse echo log, or isolation scanner.

* * * * *

Confining zone means a geological formation, group of formations, or part of 

a formation that is capable of preventing fluid movement from any formation 

that will be hydraulically fractured into a usable water zone.

*****

Hydraulic fracturing means those operations conducted in an individual 

wellbore designed to increase the flow of hydrocarbons from the rock 

formation to the wellbore through modifying the permeability of reservoir 

rock by applying fluids under pressure to fracture it. Hydraulic fracturing 

does not include enhanced secondary recovery such as water flooding, tertiary 

recovery, recovery through steam injection, or other types of well stimulation 

operations such as acidizing.

This section defines terms related to the regulation and the hydraulic 

fracturing process. The terms annulus, bradenhead, confining zone, 

hydraulic fracturing, hydraulic fracturing fluid, and proppant are 

defined as commonly used in the industry. 

The term cement evaluation log is defined to include cement bond 

logs and other tools that can verify the integrity of the cementing 

behind a wellbore casing. 

The term master hydraulic fracturing plan would allow operators to 

gain certain efficiencies in submitting information to the BLM. The 

actual process is explained in sections 3162.3-3(c) and (d).

The term usable water is defined in a manner consistent with existing 

BLM requirements in Onshore Oil and Gas Order No. 2, Drilling 

Operations on Federal and Indian Oil and gas leases (53 FR 46798) 

(Onshore Order 2). Onshore Order 2 defines usable water as 

“generally those waters containing up to 10,000 ppm of total 

dissolved solids” (section II.Y.). Onshore Order 2 has been in effect 

since 1988; therefore, the requirement to protect and/or isolate usable 

water generally containing up to 10,000 ppm of TDS has been in 

effect since that time. The rule corrects the inconsistency between 

the definition in Onshore Order 2 (the definition in effect) and the 

definition in the existing CFR 3162.5-2(d). The definition in the 

CFR, of a 5,000 ppm standard, was superseded by the Onshore Order 
11

Provision Significance

* * * * *

Hydraulic fracturing fluid means the liquid or gas, and any associated solids 

used in hydraulic fracturing, including constituents such as water, chemicals, 

and proppants.

* * * * *

Isolating or to isolate means using cement to protect, separate, or segregate 

usable water and mineral resources.

* * * * *

Master hydraulic fracturing plan means a plan containing the information 

required in section 3162.3-3(d) of this part for a group of wells where the 

geologic characteristics for each well are substantially similar.

* * * * * 

Proppant means a granular substance (most commonly sand, sintered bauxite, 

or ceramic) that is carried in suspension by the fracturing fluid that serves to 

keep the cracks in the geologic formation open when fracturing fluid is 

withdrawn after a hydraulic fracture operation.

* * * * *

Usable water means generally those waters containing up to 10,000 parts per 

million (ppm) of total dissolved solids. Usable water includes, but is not 

limited to: (1) Underground water that meets the definition of “underground 

source of drinking water” as defined at 40 CFR 144.3; (2) Underground 

sources of drinking water under the law of the State (for Federal lands) or 

tribe (for Indian lands); and (3) Water in zones designated by the State (for 

Federal lands) or tribe (for Indian lands) as requiring isolation or protection 

from hydraulic fracturing operations. The following geologic zones are 

deemed not to contain usable water:

(A) Zones from which the BLM has authorized an operator to produce oil 

and gas, provided that the operator has obtained all other authorizations 

required by the Environmental Protection Agency, the State (for Federal 

lands), or the tribe (for Indian lands) to conduct hydraulic fracturing 

operations in the specific zone;

(B) Zones designated as exempted aquifers pursuant to 40 CFR 144.7; and 

(C) Zones that do not meet the definition of underground source of drinking 

water at 40 CFR 144.3 which the State (for Federal lands) or the tribe (for 

Indian lands) has designated as exempt from any requirement to be isolated or 

2 definition in 1998. As defined, the term usable water includes 

water designated as an “underground source of drinking water” in 

EPA’s regulations or under the law of the State or tribe, and water in 

zones that the State or tribe requires to be isolated or protected from 

hydraulic fracturing operations. The term usable water excludes the 

zone to be fractured if the operator has all necessary authorizations, 

zones designated as “exempted aquifers” under EPA’s regulations, 

and zones that both do not meet the definition of “underground 

source of drinking water” in EPA’s regulations and which the State or 

tribe has exempted from isolation or protection from hydraulic 

fracturing operations.

The terms “isolating or to isolate” are defined consistent with 

exisiting Onshore Order 2. Onshore Order 2 section III. B. requires 

casing and cement to “protect and/or isolate all usable water zones.” 

Onshore Order 2 defines isolating as “using cement to protect, 

separate, or segregate usable water and mineral resources” (section 

II.I.).
12

Provision Significance

protected from hydraulic fracturing operations.

* * * * *

Subpart 3162--Requirements for Operating Rights Owners and Operators

Sec. 3162.3-2 Subsequent well operations.

(a) A proposal for further well operations must be submitted by the operator 

on a Sundry Notice and Report on Wells (Form 3160-5) as a Notice of Intent

for approval by the authorized officer prior to commencing operations to 

redrill, deepen, perform casing repairs, plug-back, alter casing, recomplete in 

a different interval, perform water shut off, combine production between 

zones, and/or convert to injection. 

* * *

(b) Unless additional surface disturbance is involved and if the operations 

conform to the standard of prudent operating practice, prior approval is not 

required for acidizing jobs or recompletion in the same interval; however, a 

subsequent report on these operations must be filed on a Sundry Notice and 

Report on Wells (Form 3160-5).

* * * * *

Revised sections 3162.3-2(a) and (b) no longer refer to nonroutine or 

routine fracturing jobs. All other injection activities must still 

comply with section 3162.3-2, while hydraulic fracturing operations 

must comply with the requirements under revised section 3162.3-3.

Sec. 3162.3-3 Subsequent well operations; Hydraulic fracturing.

(a) Activities To Which This Section Applies. This section, or portions of 

this section, apply to hydraulic fracturing as shown in the following table:

If... Then

(1) No APD was submitted as of the 

[insert effective date of this rule].

The operator must comply 

with all paragraphs of this 

(2) An APD was submitted but not section.

approved as of [insert effective date 

of this rule].

(3) An APD or APD extension was 

approved before [insert effective date 

of this rule], but the authorized drilling 

operations did not begin until after 

[insert effective date of this rule].

To conduct hydraulic 

fracturing within 90 days after 

the effective date of this rule, 

the operator must comply with 

all paragraphs of this section, 

(4) Authorized drilling operations except (c) and (d).

began, but were not completed before 

[ insert effective date of this rule].

Section 3162.3 lists the requirements concerning all hydraulic 

fracturing operations. BLM is informed that contracts with hydraulic 

fracturing service contractors are typically made six months prior to 

the planned start of hydraulic fracturing operations. Thus the final 

rule requires the maximum compliance with the new requirements 

with a minimum of disruption of existing contracts.

Section 3162.3(a) establishes the conditions under which certain 

wells may be exempted from certain requirements. Note that the 

effective date of the rule will be at least 90 days after it is published 

as final, and so 90 days after the effective date would be at least 180 

days after it is published as final.

Planned wells for which the operator does not have an approved APD 

by the effective date (at least 3 months after publication) of the rule 

would be subject to all of the requirements including the request for 

hydraulic fracturing.
13

Provision Significance

(5) Authorized drilling operations 

were completed after [insert date 180 

days before the effective date of this 

rule].

(6) Authorized drilling activities were 

completed before [insert date 180 days 

before the effective date of this rule].

The operator must comply 

with all paragraphs of this 

section.

Planned wells for which the operator has an approved APD on the 

effective date (at least 3 months after publication), wells where 

drilling was underway on the effective date (at least 3 months after 

publication), and wells that were drilled between 180 days prior to the 

effective date (or 3 months prior to publication) and the effective date 

(at least 3 months after publication) but were not hydraulically 

fractured, would be subject to all of the requirements except the 

operator would not need to request approval to conduct hydraulic 

fracturing operations if those operations occur within 90 days after 

the effective date (at least 6 months after publication). The operator 

would have to request for hydraulic fracturing if the planned 

operations occur beyond 90 days after the effective date (at least 6 

months after publication). 

Wells that were drilled 180 days or more prior to the effective date 

(or 3 months or more prior to publication) and not hydraulically 

fractured, would be subject to all of the requirements. All older 

existing wells will fall under this category.

Note also that the regulatory language in section (e)(1)(ii) allows the 

operator of a well drilled prior to the rule’s publication to comply 

with the operational requirements of the rule by demonstrating that 

adequate cementing was achieved using other documentation and not 

specifically those reports prescribed in (e) (1)(i). 

(b) Isolation of Usable Water to Prevent Contamination. All hydraulic 

fracturing operations must meet the performance standard in section 3162.5-

2(d) of this title.

Section 3162.3-3(b) presents no substantive change. As discussed 

above, the definition of usable water in section 3160.5 is carried 

forward from current requirements in Onshore Order 2. The 

definition is slightly modified from Onshore Order 2 to provide 

greater clarity and appropriate deference to determinations of the 

EPA, or state or tribal groundwater agencies.

(c) How an Operator Must Submit a Request for Approval of Hydraulic 

Fracturing. A request for approval of hydraulic fracturing must be submitted 

by the operator and approved by the authorized officer before commencement 

of operations. The operator may submit the request in one of the following 

ways:

Section 3162.3-3(c) requires an operator to submit a notification of 

hydraulic fracturing to the BLM for approval. The operator may 

submit an application for a single well or for a group of wells under a 

master hydraulic fracturing plan. This requirement for an approval 

for all operations or for a master plan is different from the 
14

Provision Significance

(1) With an application for permit to drill; or 

(2) With a Sundry Notice and Report on Wells (Form 3160-5) as a notice of 

intent (NOI). 

(3) For approval of a group of wells submitted under either paragraph (c)(1) 

or (c)(2) of this section, the operator may submit a master hydraulic fracturing 

plan. Submission of a master hydraulic fracturing plan does not obviate the 

need to obtain an approved APD from the BLM for each individual well.

(4) If an operator has received approval from the authorized officer for 

hydraulic fracturing operations, and the operator has significant new 

information about the geology of the area, the stimulation operation or 

technology to be used, or the anticipated impacts of the hydraulic fracturing 

operation to any resource, then the operator must submit a new NOI (Form 

3160-5). Significant new information includes, but is not limited to, 

information that changes the proposed drilling or completion of the well, the 

hydraulic fracturing operation, or indicates increased risk of contamination of 

zones containing usable water or other minerals.

requirement prior to this rule, which only required a NOI Sundry for 

non-routine hydraulic fracturing operations. This application is new 

process and places an incremental burden on operators to complete 

the application, and will require BLM’s time and resources to review 

the information under section 3162.3-3(d).

(d) What a Request for Approval of Hydraulic Fracturing Must Include. The 

request for approval of hydraulic fracturing must include the information in 

this paragraph. If the information required by this paragraph has been 

assembled to comply with State law (on Federal lands) or tribal law (on 

Indian lands), such information may be submitted to the BLM authorized 

officer as provided to the State or tribal officials as part of the APD or NOI

(Form 3160-5).

(1) The following information regarding wellbore geology: 

(i) The geologic names, a geologic description, and the estimated depths 

(measured and true vertical) to the top and bottom of the formation into which 

hydraulic fracturing fluids are to be injected; 

(ii) The estimated depths (measured and true vertical) to the top and bottom 

of the confining zone(s); and

(iii) The estimated depths (measured and true vertical) to the top and bottom 

of all occurrences of usable water based on the best available information.

(2) A map showing the location, orientation, and extent of any known or 

suspected faults or fractures within one-half mile (horizontal distance) of the 

wellbore trajectory that may transect the confining zone(s). The map must be 

of a scale no smaller than 1:24,000.

Section 3162.3-3(d) specifies that the application must include:

 Information about the geology and the formation, confining zones, 

usable water (depths estimated), faults and fractures, location of 

water supply, and transportation method – This information is 

generally consistent the requirements in Onshore Order 1;

 Information about the proposed hydraulic fracturing operation, the 

volume of fluid to be used, the maximum anticipated surface 

pressure, wellbore trajectory, the estimated direction, length, and 

height of fractures, and the locations and depths of existing 

wellbores within a half mile of the wellbore.

 Information about how the operator will handle recovered fluids, 

the estimated volume of fluids to be recovered, the proposed 

disposal method.

Operators planning to conduct hydraulic fracturing should already 

possess this information to comply with Onshore Order 1 and to plan 

their operations. The process of providing it to the BLM will pose 

some additional administrative burden to operators and necessitate 

BLM review.
15

Provision Significance

(3) Information concerning the source and location of water supply, such as 

reused or recycled water, rivers, creeks, springs, lakes, ponds, and water 

supply wells, which may be shown by quarter-quarter section on a map or 

plat, or which may be described in writing. It must also identify the 

anticipated access route and transportation method for all water planned for 

use in hydraulically fracturing the well;

(4) A plan for the proposed hydraulic fracturing design that includes, but is 

not limited to, the following:

(i) The estimated total volume of fluid to be used;

(ii) The maximum anticipated surface pressure that will be applied during the 

hydraulic fracturing process;

(iii) A map at a scale no smaller than 1:24,000 showing:

(A) The trajectory of the wellbore into which hydraulic fracturing fluids are to 

be injected;

(B) The estimated direction and length of the fractures that will be propagated 

and a notation indicating the true vertical depth of the top and bottom of the 

fractures; and

(C) All existing wellbore trajectories, regardless of type, within one-half mile 

(horizontal distance) of any portion of the wellbore into which hydraulic 

fracturing fluids are to be injected. The true vertical depth of each wellbore 

identified on the map must be indicated. 

(iv) The estimated minimum vertical distance between the top of the fracture 

zone and the nearest usable water zone; and 

(v) The measured depth of the proposed perforated or open-hole interval. 

(5) The following information concerning the handling of fluids recovered 

between the commencement of hydraulic fracturing operations and the 

approval of a plan for the disposal of produced fluid under BLM 

requirements:

(i) The estimated volume of fluid to be recovered;

(ii) The proposed methods of handling the recovered fluids as required under 

paragraph (h) of this section; and

(iii) The proposed disposal method of the recovered fluids, including, but not 

limited to, injection, storage, and recycling.

(6) If the operator submits a request for approval of hydraulic fracturing with 

an NOI (Form 3160-5), the following information must also be submitted:
16

Provision Significance

(i) A surface use plan of operations, if the hydraulic fracturing operation 

would cause additional surface disturbance; and

(ii) Documentation required in paragraph (e). 

(7) The authorized officer may request additional information prior to the 

approval of the NOI (Form 3160-5) or APD.

(e) Monitoring and Verification of Cementing Operations Prior to Hydraulic 

Fracturing.

(1)(i) During cementing operations on any casing used to isolate and protect 

usable water zones, the operator must monitor and record the flow rate, 

density, and pump pressure, and submit a cement operation monitoring report 

for each casing string used to isolate and protect usable water to the 

authorized officer prior to commencing hydraulic fracturing operations. The 

cement operation monitoring report must be provided at least 48 hours prior 

to commencing hydraulic fracturing operations unless the authorized officer 

approves a shorter time. 

(ii) For any well completed pursuant to an APD that did not authorize 

hydraulic fracturing operations, the operator must submit documentation to 

demonstrate that adequate cementing was achieved for all casing strings 

designed to isolate and protect usable water. The operator must submit the 

documentation with its request for approval of hydraulic fracturing 

operations, or no less than 48 hours prior to conducting hydraulic fracturing 

operations if no prior approval is required, pursuant to paragraph (a) of this 

section. The authorized officer may approve the hydraulic fracturing of the 

well only if the documentation provides assurance that the cementing was 

sufficient to isolate and to protect usable water, and may require such 

additional tests, verifications, cementing or other protection or isolation 

operations, as the authorized officer deems necessary.

(2) Prior to starting hydraulic fracturing operations, the operator must 

determine and document that there is adequate cement for all casing strings 

used to isolate and protect usable water zones as follows:

(i) Surface casing. The operator must observe cement returns to surface and 

document any indications of inadequate cement (such as, but not limited to, 

Section 3162.3-3(e) requires operators to:

 Monitor and record their cementing operations – This is consistent 

with industry guidance stressing the importance of using data from 

reports, logs, and tests to evaluate the quality of a cement job, 

including drilling reports, drilling fluid reports, cement design and 

related laboratory reports, open-hole log information including 

caliper logs, cement placement information including centralizer 

program, placement simulations and job logs, etc.12 The rule 

requires that the operator submit the report to the BLM at least 48 

hours prior to the completion operation. The process of providing 

it to the BLM will pose some additional administrative burden to 

operators and necessitate BLM review. The BLM may allow 

submission of a cement monitoring report in a shorter time prior to 

a hydraulic fracturing operation.

 For existing wells, provide the information required in 3162.3-

3(e)(1)(i) (described in the previous bullet item) to the extent it is 

available, and provide any other information or perform any other 

measures deemed necessary by the authorized officer to assure that 

the cementing will isolate and protect usable water zones.

 Cement the surface casing to the surface – This is already required 

by Onshore Order 2 and most state regulations, and is consistent 

with industry practice, and therefore does not pose an additional 

burden to operators;

 The operator must demonstrate that there is at least 200 feet of 

adequately bonded cement between the deepest usable water zone 

and the formation to be fractured, if the cement is not circulated to 

the surface. This is generally consistent with industry guidance and 

 

12 API Guidance Document HF1 “Hydraulic Fracturing Operations – Well Construction and Integrity Guidelines” at p. 10.
17

Provision Significance

lost returns, cement channeling, gas cut mud, failure of equipment, or fallback 

from the surface exceeding 10 percent of surface casing setting depth or 200 

feet, whichever is less). If there are indications of inadequate cement, then 

the operator must determine the top of cement with a CEL, temperature log, 

or other method or device approved in advance by the authorized officer. 

(ii) Intermediate and production casing.

(A) If the casing is not cemented to surface, then the operator must run a CEL 

to demonstrate that there is at least 200 feet of adequately-bonded cement 

between the zone to be hydraulically fractured and the deepest usable water 

zone.

(B) If the casing is cemented to surface, then the operator must follow the 

requirements of paragraph (e)(2)(i) of this section. 

(3) For any well, if there is an indication of inadequate cement on any casing 

used to isolate usable water, then the operator must:

(i) Notify the authorized officer within 24 hours of discovering the inadequate 

cement; 

(ii) Submit a NOI (Form 3160-5) to the authorized officer requesting approval 

of a plan to perform remedial action to achieve adequate cement. The plan 

must include the supporting documentation and logs required under paragraph 

(e)(2) of this section. In emergency situations, an operator may request oral 

approval from the authorized officer for actions to be undertaken to remediate 

the cement. However, such requests must be followed by a written notice 

filed not later than the fifth business day following oral approval; 

(iii) Verify that the remedial action was successful with a CEL or other 

method approved in advance by the authorized officer; 

(iv) Submit a Sundry Notice and Report on Wells (Form 3160-5) as a 

subsequent report for the remedial action including:

(A) A signed certification that the operator corrected the inadequate cement 

job in accordance with the approved plan; and

(B) The results from the CEL or other method approved by the authorized 

officer showing that there is adequate cement. 

(v) The operator must submit the results from the CEL or other method 

specified in some state regulations, but is new in the BLM’s 

regulations. API HF1 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” and 

that operators may run a CEL or other diagnostic tools to 

determine the adequacy of the cement integrity and that the cement 

reached the desired height. In our review of state regulations 

regarding intermediate casing, Colorado requires a CBL if using a 

production liner, North Dakota requires a CBL, Texas requires a 

CBL or temperature log if cement is not circulated to the surface, 

and Wyoming and California may require CELs. Additionally, the 

BLM and states may require operators to log the intermediate 

casing as a condition of approval. Circumstances that may warrant 

logging of the intermediate casing include: If the operator plans to 

hang a production liner off of the intermediate casing, if the 

proposed fracturing is through the intermediate casing, or if there 

are salt zones that need to be isolated. Industry guidance also 

specifies that operators should run a cement bond log on the 

production casing to determine the adequacy of cement integrity 

and that the cement should be brought at least 500 feet above the 

highest formation where the operator will conduct hydraulic 

fracturing.13 Considering the design standards recommended in 

the industry guidance, we believe that the rule’s requirements may 

pose an additional burden to operators regarding CELs on the 

intermediate casing, but not for CELs on the production casing.

 Notify the BLM within 24 hours if there is an indication of 

inadequate cement, submit a plan to perform remedial action, 

verify that the remedial action was successful with a CEL or other 

approved method, and submit a SR Sundry including a signed 

certification and results of the corrective action. Onshore Order 2 

section B.1 specifies minimum standards and enforcement 

provisions for casing and cementing. It specifies corrective action 

 

13 API HF1 at p. 12.
18

Provision Significance

approved by the authorized officer (see paragraph (e)(3)(iv)(B) of this 

section) at least 72 hours before starting hydraulic fracturing operations.

for provisions, which are sometimes specified by the AO. Under 

this rule, the AO does not specify the corrective action, but instead 

approves it, allowing operators greater flexibility in taking 

corrective action.

(f) Mechanical Integrity Testing Prior to Hydraulic Fracturing. Prior to 

hydraulic fracturing, the operator must perform a successful mechanical 

integrity test, as follows:

(1) If hydraulic fracturing through the casing is proposed, the casing must be 

tested to not less than the maximum anticipated surface pressure that will be 

applied during the hydraulic fracturing process.

(2) If hydraulic fracturing through a fracturing string is proposed, the 

fracturing string must be inserted into a liner or run on a packer-set not less 

than 100 feet below the cement top of the production or intermediate casing. 

The fracturing string must be tested to not less than the maximum anticipated 

surface pressure minus the annulus pressure applied between the fracturing 

string and the production or intermediate casing.

(3) The mechanical integrity test will be considered successful if the pressure 

applied holds for 30 minutes with no more than a 10 percent pressure loss.

Section 3162.3-3(f) requires the operator to conduct a MIT. The MIT 

required by this rule is a pressure test of the casing through which the 

hydraulic fracturing will occur or through the fracturing string (if 

used). Industry guidance and state regulations are consistent with this 

requirement. As such, the requirement does not pose an additional 

burden to the operator.

Industry guidance on hydraulic fracturing states that the operator 

should pressure test the production casing to determine if the casing 

integrity is adequate to meet the well design and construction 

objectives.14 The MIT required by the rule is consistent with the 

industry guidance.

Further, the guidance discusses the use of fracturing strings. “In 

some cases, the production casing will never be exposed to high 

pressure except during hydraulic fracturing. In these cases, a highpressure ‘frac string’ may be used to pump the fluids into the well to 

isolate the production casing from the high treatment pressure. Once 

the hydraulic fracturing operations are complete, the frac string is 

removed...The well operator or the operator’s designated 

representative should be on site throughout the hydraulic fracturing 

process. Prior to beginning the hydraulic fracture treatment, all 

equipment should be tested to make sure it is in good operating 

condition. All high-pressure lines leading from the pump trucks to the 

wellhead should be pressure tested to the maximum treating pressure. 

Any leaks must be eliminated prior to initiation of the hydraulic 

 

14 API HF1 at p. 12.
19

Provision Significance

fracture treatment. After this, the final safety and operational 

meetings should be conducted.”15

In our review of state regulations, all of the states except California 

require the operator to pressure test the production casing. The 

California Code allows operators to pressure test the production 

casing, but defers to the field rules. We were unable to track down all 

of the California field rules to determine the extent to which it is a 

requirement. But the MIT requirement will not be a new burden on 

operators who are complying with State laws and industry guidance.

(g) Monitoring and Recording During Hydraulic Fracturing.

(1) During any hydraulic fracturing operation, the operator must continuously 

monitor and record the annulus pressure at the bradenhead. The pressure in 

the annulus between any intermediate casings and the production casing must

also be continuously monitored and recorded. A continuous record of all 

annuli pressure during the fracturing operation must be submitted with the 

required Subsequent Report Sundry Notice (Form 3160-5) identified in 

paragraph (i) of this section.

(2) If during any hydraulic fracturing operation any annulus pressure 

increases by more than 500 pounds per square inch as compared to the 

pressure immediately preceding the stimulation, the operator must stop the 

hydraulic fracturing operation, take immediate corrective action to control the 

situation, orally notify the authorized officer as soon as practicable, but no 

later than 24 hours following the incident, and determine the reasons for the 

pressure increase. Prior to recommencing hydraulic fracturing operations, the 

operator must perform any remedial action required by the authorized officer, 

and successfully perform a mechanical integrity test under paragraph (f) of 

this section. Within 30 days after the hydraulic fracturing operations are 

completed, the operator must submit a report containing all details pertaining 

to the incident, including corrective actions taken, as part of a Subsequent 

Report Sundry Notice (Form 3160-5).

Section 3162.3.3(g) requires the operator to continuously monitor and 

record the annulus pressure at the bradenhead during the hydraulic 

fracturing operation. This requirement does not pose an additional 

burden to operators, who currently monitor annulus pressures during 

operations as a matter of industry practice. HF1 states that “if the 

annulus between the production casing and the intermediate casing 

has not been cemented to the surface, the pressure in the annular 

space should be monitored and controlled. Pressure behavior 

throughout the hydraulic fracture treatment should be monitored so 

that any unexplained deviation from the pretreatment design can be 

immediately detected and analyzed before operations continue.”16 

 

15 API HF1 at p. 16.

16 API HF1 at p. 21.
20

Provision Significance

(h) Management of Recovered Fluids. Except as provided in paragraphs 

(h)(1) and (h)(2), all fluids recovered between the commencement of 

hydraulic fracturing operations and the authorized officer’s approval of a 

produced water disposal plan under BLM requirements must be stored in 

rigid enclosed, covered, or netted and screened above-ground tanks. The 

tanks may be vented, unless Federal law, or State regulations (on Federal 

lands) or tribal regulations (on Indian lands) require vapor recovery or closedloop systems. The tanks must not exceed a 500 barrel (bbl) capacity unless 

approved in advance by the authorized officer.

(1) The authorized officer may approve an application to use lined pits only if

the applicant demonstrates that use of a tank as described in paragraph (h) is

infeasible for environmental, public health or safety reasons and only if, at a 

minimum, all of the following conditions apply:

(i) The distance from the pit to intermittent or ephemeral streams or water 

sources would be at least 300 feet;

(ii) The distance from the pit to perennial streams, springs, fresh water 

sources, or wetlands would be at least 500 feet;

(iii) There is no usable groundwater within 50 feet of the surface in the area 

where the pit would be located;

(iv) The distance from the pit to any occupied residence, school, park, school 

bus stop, place of business, or other areas where the public could reasonably 

be expected to frequent would be greater than 300 feet;

(v) The pit would not be constructed in fill or unstable areas; 

(vi) The construction of the pit would not adversely impact the hydrologic 

functions of a 100-year floodplain; and

(vii) Pit use and location complies with applicable local, State (on Federal 

lands), tribal (on Indian lands), and other Federal statutes and regulations

including those that are more stringent than these regulations. 

(2) Pits approved by the authorized officer must be:

(i) Lined with a durable, leak-proof synthetic material and equipped with a 

leak detection system; and

(ii) Routinely inspected and maintained, as required by the authorized officer, 

to ensure that there is no fluid leakage into the environment. The operator

must document all inspections.

Section 3162.3-3(h) requires operators to manage recovered fluids in 

“rigid enclosed, covered, or netted and screened above-ground 

tanks.” The tanks may be vented, unless Federal law, state 

regulations, or tribal regulations require vapor recovery or closedloop systems. The regulation limits the tank capacity to 500 bbl or 

less unless larger tanks are approved by the AO. 

The type of tanks that the rule requires, rigid and not to exceed 500 

bbl capacity, are commonly used in hydraulic fracturing operations to 

receive recovered fluids. These tanks are commonly referred to as 

“frac tanks” and have a holding capacity of up to 21,000 gallons, or 

500 bbl, of fluid. The tanks are generally limited to that capacity or 

size by the need to transport them on surface roads to and from a well 

site. 

The rule does not require a closed-loop system, unless the operations 

are in areas where other laws or regulations require a closed-loop 

system. The rule allows for some flexibility regarding the size 

standards, with advanced approval by the AO, to allow for potential 

improvements in technology, e.g., if industry developed rigid tanks 

that exceed 500 bbl of capacity. 

In certain circumstances, the AO may approve the use of a pit that is 

both lined and equipped with a leak detection system. 

This section may pose an initial upfront burden to the operator 

depending on its current practice. Industry guidance (API HF2) does 

not specify one method over another. New Mexico and Texas have 

regulations that require tanks, but also allow the supervisor to 

approve permits for pits. Other states that we examined place no 

such requirement in regulations, but may have standard conditions of 

approval that require tanks. The BLM has also observed that 

operators are generally using steel rigid tanks as a matter of practice, 

and we also estimate that the amount of recovered fluids that come 

from operations on Federal and Indian lands generally makes storage 
21

Provision Significance

tanks less costly than pits. When the state regulations allow pits, 

almost all require the pits to be lined but not necessarily equipped 

with a leak detection system (which could also be required as a 

condition of approval). 

(i) Information that Must be Provided to the Authorized Officer After 

Hydraulic Fracturing is Completed. The information required in paragraphs 

(i)(1) through (i)(10) of this section must be submitted to the authorized 

officer within 30 days after the completion of the last stage of hydraulic 

fracturing operations for each well. The information is required for each well, 

even if the authorized officer approved fracturing of a group of wells (see 

section 3162.3-3(c)). The information required in paragraph (i)(1) of this 

section must be submitted to the authorized officer through FracFocus or 

another BLM-designated database, or in a Subsequent Report Sundry Notice 

(Form 3160-5). If information is submitted through FracFocus or another 

BLM-designated database, the operator must specify that the information is 

for a Federal or an Indian well, certify that the information is both timely filed 

and correct, and certify compliance with applicable law as required by 

paragraph (i)(8)(ii) or (i)(8)(iii) of this section using FracFocus or another 

BLM-designated database. The information required in paragraphs (i)(2) 

though (i)(10) of this section must be submitted to the authorized officer in a 

Subsequent Report Sundry Notice (Form 3160-5). The operator is 

responsible for the information submitted by a contractor or agent, and the 

information will be considered to have been submitted directly from the 

operator to the BLM. The operator must submit the following information:

(1) The true vertical depth of the well, total water volume used, and a 

description of the base fluid and each additive in the hydraulic fracturing 

fluid, including the trade name, supplier, purpose, ingredients, Chemical 

Abstract Service Number (CAS), maximum ingredient concentration in 

additive (% by mass), and maximum ingredient concentration in hydraulic 

fracturing fluid (% by mass) . 

(2) The actual source(s) and location(s) of the water used in the hydraulic 

fracturing fluid;

(3) The maximum surface pressure and rate at the end of each stage of the 

hydraulic fracturing operation and the actual flush volume.

(4) The actual, estimated, or calculated fracture length, height and direction.

Section 3162.3-3(i) lists information that the operator must submit to 

the BLM after the completion of a hydraulic fracturing operation. 

Gathering the information should not pose a burden to the operator, 

but the process of providing it to the BLM will pose some additional 

administrative burden to operators. 

This section requires a disclosure of the chemicals used in during the 

operation to FracFocus, the BLM, or another database that the BLM 

specifies. For wells in states that already require disclosure to 

FracFocus, the requirements in this rule do not pose any additional 

burden; meaning, the operator would provide that disclosure 

regardless of whether this rule required it. The primary Western 

states with such agreements or requirements include Colorado, 

Montana, North Dakota, Oklahoma, Texas, and Utah.
22

Provision Significance

(5) The actual measured depth of perforations or the open-hole interval.

(6) The total volume of fluid recovered between the completion of the last 

stage of hydraulic fracturing operations and when the operator starts to report 

water produced from the well to the Office of Natural Resources Revenue. If 

the operator has not begun to report produced water to the Office of Natural 

Resources Revenue when the Subsequent Report Sundry Notice is submitted, 

the operator must submit a supplemental Subsequent Report Sundry Notice 

(Form 3160-5) to the authorized officer documenting the total volume of 

recovered fluid. 

(7) The following information concerning the handling of fluids recovered, 

covering the period between the commencement of hydraulic fracturing and 

the implementation of the approved plan for the disposal of produced water 

under BLM requirements:

(i) The methods of handling the recovered fluids, including, but not limited 

to, transfer pipes and tankers, holding pond use, re-use for other stimulation 

activities, or injection; and

(ii) The disposal method of the recovered fluids, including, but not limited to, 

the percent injected, the percent stored at an off-lease disposal facility, and 

the percent recycled. 

(8) A certification signed by the operator that:

The operator complied with the requirements in paragraphs (b), (e), (f), (g), 

and (h) of this section;

(ii) For Federal lands, the hydraulic fracturing fluid constituents, once they 

arrived on the lease, complied with all applicable permitting and notice 

requirements as well as all applicable Federal, State, and local laws, rules, and 

regulations; and

(iii) For Indian lands, the hydraulic fracturing fluid constituents, once they 

arrived on the lease, complied with all applicable permitting and notice 

requirements as well as all applicable Federal and tribal laws, rules, and 

regulations.

(9) The operator must submit the result of the mechanical integrity test as 

required by paragraph (f) of this section.

(10) The authorized officer may require the operator to provide 

documentation substantiating any information submitted under paragraph (i) 

of this section.
23

Provision Significance

(j) Identifying Information Claimed to be Exempt from Public Disclosure.

(1) For the information required in paragraph (i) of this section, the operator 

and the owner of the information will be deemed to have waived any right to 

protect from public disclosure information submitted with a Subsequent 

Report Sundry Notice (Form 3160-5) or through FracFocus or another BLMdesignated database. For information required in paragraph (i) of this section 

that the owner of the information claims to be exempt from public disclosure 

and is withheld from the BLM, a corporate officer, managing partner, or sole 

proprietor of the operator must sign and the operator must submit to the 

authorized officer with the Subsequent Report Sundry Notice (Form 3160-5) 

required in paragraph (i) of this section an affidavit that:

(i) Identifies the owner of the withheld information and provides the name, 

address and contact information for a corporate officer, managing partner, or 

sole proprietor of the owner of the information;

(ii) Identifies the Federal statute or regulation that would prohibit the BLM 

from publicly disclosing the information if it were in the BLM's possession;

(iii) Affirms that the operator has been provided the withheld information 

from the owner of the information and is maintaining records of the withheld 

information, or that the operator has access and will maintain access to the 

withheld information held by the owner of the information;

(iv) Affirms that the information is not publicly available;

(v) Affirms that the information is not required to be publicly disclosed under 

any applicable local, State or Federal law (on Federal lands), or tribal or 

Federal law (on Indian lands);

(vi) Affirms that the owner of the information is in actual competition and 

identifies competitors or others that could use the withheld information to 

cause the owner of the information substantial competitive harm;

(vii) Affirms that the release of the information would likely cause substantial 

competitive harm to the owner of the information and provides the factual 

basis for that affirmation; and 

(viii) Affirms that the information is not readily apparent through reverse 

engineering with publicly available information.

(2) If the operator relies upon information from third parties, such as the 

owner of the withheld information, to make the affirmations in paragraphs 

(j)(1)(vi) through (j)(1)(viii) of this section, the operator must provide a 

Section 3162.3-3(j) allows operators to withhold information from 

their chemical disclosure that would compromise their trade secrets. 

When claiming a trade secret, the operator must provide an affidavit 

verifying that claim. The process of providing it to the BLM will 

pose some additional administrative burden to operators and the 

owners of the information (if different from the operator).

The operator must maintain the withheld information for the longer of 

the life of the well, or for Federal leases seven years, or for Indian 

lands six years. The Federal Oil and Gas Royalty Management Act, 

as amended, specifies minimum information retention periods of 

seven and six years. The lease forms require retention of documents 

for the life of the well. If the operator is not the owner of the 

information, the operator may comply by maintaining access to the 

information.
24

Provision Significance

written affidavit from the third party that sets forth the relied upon 

information. 

(3) The BLM may require any operator to submit to the BLM any withheld 

information, and any information relevant to a claim that withheld 

information is exempt from public disclosure. 

(4) If the BLM determines that the information submitted under paragraph 

(j)(3) of this section is not exempt from disclosure, the BLM will make the 

information available to the public after providing the operator and owner of 

the information with no fewer than 10 business days’ notice of the BLM’s 

determination.

(5) The operator must maintain records of the withheld information until the 

later of the BLM’s approval of a final abandonment notice, or 6 years after 

completion of hydraulic fracturing operations on Indian lands, or7 years after 

completion of hydraulic fracturing operations on Federal lands. Any 

subsequent operator will be responsible for maintaining access to records 

required by this paragraph during its operation of the well. The operator will 

be deemed to be maintaining the records if it can promptly provide the 

complete and accurate information to BLM, even if the information is in the 

custody of its owner.

(6) If any of the chemical identity information required in paragraph (i)(1) of 

this section is withheld, the operator must provide the generic chemical name 

in the submission required by paragraph (i)(1) of this section. The generic 

chemical name must be only as generic as is necessary to protect the 

confidential chemical identity, and should be the same as or no less 

descriptive than the generic chemical name provided to the Environmental 

Protection Agency.

(k) Requesting a Variance from the Requirements of this Section.

(1) Individual Variance. The operator may make a written request to the 

authorized officer for a variance from the requirements under this section. A 

request for an individual variance must specifically identify the regulatory 

provision of this section for which the variance is being requested, explain the 

reason the variance is needed, and demonstrate how the operator will satisfy 

the objectives of the regulation for which the variance is being requested. 

(2) State or Tribal Variance. In cooperation with a State (for Federal lands) 

or a tribe (for Indian lands), the appropriate BLM State Director may issue a 

Section 3162.3-3(k)(1) allows operators to request a variance from 

the requirements. Variance language is common among BLM 

regulations. The BLM will consider alternatives if an operator can 

demonstrate that the objectives of the rule would be met using an 

alternate approach. 

The section 3162.3-3(k)(2) allows states or tribes to work with BLM 

to agree on variances from specific regulatory provisions of the final 

rule that could apply state- or tribe-wide, or within certain designated 
25

Provision Significance

variance that would apply to all wells within a State or within Indian lands, or 

to specific fields or basins within the State or the Indian lands, if the BLM 

finds that the variance meets the criteria in paragraph (k)(3) of this section. A 

State or tribal variance request or decision must specifically identify the 

regulatory provision(s) of this section for which the variance is being 

requested, explain the reason the variance is needed, and demonstrate how the 

operator will satisfy the objectives of the regulation for which the variance is 

being requested. A State or tribal variance may be initiated by the State, tribe, 

or the BLM. (3) The authorized officer (for an individual variance), or the 

State Director (for a State or tribal variance), after considering all relevant 

factors, may approve the variance, or approve it with one or more conditions 

of approval, only if the BLM determines that the proposed alternative meets 

or exceeds the objectives of the regulation for which the variance is being 

requested. The decision whether to grant or deny the variance request must 

be in writing and is entirely within the BLM’s discretion. The decision on a 

variance request is not subject to administrative appeals either to the State 

Director (for an individual variance) or under 43 CFR part 4.

(4) A variance under this section does not constitute a variance to provisions 

of other regulations, laws, or orders.

(5) Due to changes in Federal law, technology, regulation, BLM policy, field 

operations, noncompliance, or other reasons, the BLM reserves the right to 

rescind a variance or modify any conditions of approval. The authorized 

officer must provide a written justification before a variance is rescinded or a 

condition of approval is modified.

areas. BLM could approve a state or tribal variance if it would meet 

or exceed the requirements of the specific provision of the rule.

The variances should result in some reduction in the costs of 

compliance with some requirements for specific operations, or for all 

operators within an area subject to a State-wide or tribe-wide 

variance, without compromising the protections of the final rule for 

usable water. Approval of a variance, however, is not a delegation of 

regulatory primacy to a State or a tribe.

Sec. 3162.5-2 Control of wells.

* * * * *

(d) Protection of usable water and other minerals. The operator must isolate 

all usable water and other mineral-bearing formations and protect them from 

contamination.

* * * * *

Revised section 3162.5-2(d) conforms the out-of-date CFR language 

with the Onshore Order 2 requirements. Onshore Order 2 superseded 

the existing CFR in 1988. Since the final rule is consistent with 

Onshore Order 2, it does not represent a change in policy and does 

not pose an additional burden to operators.
26

2.4 Consideration of Alternative Approaches

In developing the final rule and during the rulemaking process, the BLM considered several 

alternative regulatory approaches. The alternatives primarily focused on several topic areas: 

1) What are the best and most appropriate ways to verify wellbore integrity, including the 

operator’s casing and cementing program, tests conducted prior to hydraulic fracturing 

operations, and pressure monitoring?

2) What are the best and most appropriate ways for recovered fluids to be managed? 

3) What is the best method for receiving chemical disclosure information? What time is 

most appropriate to receive this information, i.e. before and/or after the hydraulic 

fracturing operation occurs? How should we treat trade secrets?

With regard to well construction requirements, the requirements put forth in the final rule are 

somewhat different than those in the initial proposed rule or the supplemental proposed rule. 

In the initial proposal, the BLM proposed that operators must run a cement bond log (CBL) on 

the cement behind each casing string protecting usable water. While CBLs (or other logs that 

evaluate the quality of the cement behind a casing string) are common on the intermediate and 

production casings, they are relatively uncommon on the surface casing, where operators 

generally witness cement returns to surface (without cement loss) as evidence of adequate 

cementing.

In response to the initial proposal, we received many comments that the CBL requirement would 

disrupt drilling operations, requiring operators to maintain idle drilling rigs onsite for up to 72 

hours while the surface casing cement hardened sufficiently for a CBL to return results. The 

comments identified an unintended consequence of the initial proposal that we had not 

anticipated. Further, the requirement for a CBL on the surface casing is not standard industry 

practice, since operators typically circulate cement to the surface and monitor cementing 

operations to ensure adequate cementing.

In the supplemental proposal, the BLM proposed that operators must run a CEL on the cement 

behind each casing string protecting usable water. However, an operator demonstrating that the 

casing and cementing program was successful by running successful logs on a “type well” could 

forego running logs on subsequent wells in the same geologic area.

Again, we received many comments about this proposal – about the effectiveness of the type 

well approach and the usefulness of a CEL on the surface casing. Comments on the economic 

analysis suggested that the application of the type well concept would be highly variable 

depending on the field, indicating that operators may not be able to avoid cost burdens.

For the final rule, the BLM requires that operators run a CEL to verify the cement behind each 

casing string that protects usable water, unless the operator returns the cement to the surface. 

This approach is consistent with industry practices and limits the burden on operators. A CEL is 

required when the operator does not return the cement to surface in order to locate the top of the 

cement – to demonstrate that the casing and cementing program meets the original design 

standards. If an operator witnesses inadequate cementing, then the BLM requires the operator to 
27

take remedial action and to demonstrate that the remedial action was successful. It may do so 

with a CEL or other test, where approved. This is consistent with Onshore Order 2. 

The next area where we considered alternatives was with the management of flowback fluids. In 

the initial proposal, the BLM required operators to manage flowback in lined pits or tanks. We 

believed that those requirements were generally being met by operators in the field, since many 

states have minimum requirements for pits to be lined or for flowback to be contained in storage 

tanks. We maintained that proposal in the supplemental proposal, but asked for comment on the 

costs and benefits of requiring flowback to be managed in storage tanks only. We received 

comments about that request (detailed in the preamble to the final rule) and about the potential 

cost burdens (discussed later in this report). 

For the final rule, the BLM requires operators to manage recovered fluids in rigid enclosed, 

covered, or netted and screened above-ground tanks (each tank not exceeding 500 bbl of 

capacity), unless the Authorized Officer approves the use a lined pit equipped with a leak 

detection system. The rule lays out the conditions under which an operator may receive such an 

approval. The rule’s requirements apply until the operator begins implementing a plan for the 

disposal of produced water approved by the BLM pursuant to Onshore Order No. 7.

Finally, the BLM gave consideration to several policy options for requiring the disclosure of 

chemicals used in the hydraulic fracturing operations. The initial, supplemental, and final rules

all would require the disclosure of chemicals after the hydraulic fracturing operations are 

complete. Although it was never proposed, the BLM also considered requiring chemical 

disclosure (chemical name and not the volume or percent) prior to the operations. Ultimately, 

the BLM did not carry that policy option forward for the reasons detailed in the final rule’s 

preamble discussion. 

This report discusses the potential impacts of these alternatives in subsequent sections.
28

2.5 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 BLM considered alternatives to direct regulation and determined that some alternatives are 

appropriate while others are not. 

User fees and marketable permits are not appropriate 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. Similar to a user fee but different in concept, an “impact 

fee” is a fee imposed by a government for a given project with the receipts designated to address

the impacts of the project or to compensate the impacted parties. The difficulty in applying this 

approach in this context lies in determining an appropriate impact fee at a national level for local 

projects, understanding that impacts are likely to vary by location, project, operator, or other 

circumstance. 

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 damage is not uniform or 

predictable across wells, events, and geographic areas (unlike, for example, a ton of carbon 

dioxide which disperses in the atmosphere). 

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 the 

operations to make informed decisions in other respects.

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. Variance language is 

common among the BLM’s regulations. The BLM would consider alternatives if an operator 

could demonstrate that the objectives of the rule would be met using an alternate approach. 

From an efficiency standpoint, variances are important because they allow operators to use 

technology, innovations, or other improvements to meet requirements in a more efficient or cost 

effective manner. This analysis does not quantify the benefits or costs of allowing for variances; 

however, the provision would likely reduce compliance costs. Similarly, the provision for state 

or tribal variances would likely reduce some compliance costs.
29

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. At the end of fiscal year (FY) 2013, there were 47,427 Federal oil and 

gas leases covering 36,092,482 acres, 93,598 producible and service drill holes, and 99,975

producible and service completions on Federal leases. 

Table 1 shows the sales volume, sales value, and royalty generated from Federal and Indian oil 

and gas production in 2013. For FY 2013, onshore Federal oil and gas leases produced about 

133 million barrels (bbl) of oil, 2.67 trillion cubic feet of natural gas, and 2.5 billion gallons (gal) 

of natural gas liquids, with a sales value of almost $24 billion and generating royalties of almost

$2.7 billion. Oil and gas production from Indian leases was almost 46 million bbl of oil, 238 

billion cubic feet (Bcf) of natural gas, and 155 million gallons of natural gas liquids, with a sales 

value of over $5 billion and generating royalties of $860 million for the Indian mineral owners.

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

Table 1: Federal and Indian Oil and Gas Production and Royalties, Fiscal Year 2013

Jurisdiction Commodity Sales Volume Sales Value Revenue

Federal Leases

Oil (bbl) 133,364,128 $11,927,069,991 $1,444,886,822

Gas (Mcf) 2,662,577,254 $9,905,897,816 $1,051,198,875

NGL (gal) 2,477,721,602 $2,076,639,138 $195,789,932

Subtotal $23,909,606,945 $2,691,875,629

Indian Leases

Oil (bbl) 45,966,597 $4,137,453,205 $721,089,106

Gas (Mcf) 238,717,918 $813,440,706 $124,217,560

NGL (gal) 155,399,916 $135,369,266 $15,192,781

Subtotal $5,086,263,176 $860,499,447

Source: Office of Natural Resources Revenue (ONRR), Federal Onshore Reported Royalty Revenue, 

FY 2013 and American Indian Reported Royalty Revenue, FY 2013. 
30

Figure 1:
31

2.7 Hydraulic Fracturing on Federal and Indian Lands

Since under current regulations, operators only seek BLM approval before performing “nonroutine” fracturing operations, it is difficult to know the exact number of hydraulic fracturing 

operations occurring on Federal or Indian lands. Generally, we believe that roughly 90 percent 

of wells are completed using hydraulic fracturing and that 3 percent of those wells may be refractured within the same zone.17

 By applying that assumed prevalence to the number of well 

completions on Federal and Indian lands reported in Automated Fluid Minerals Support System

(AFMSS), we have estimated the number of hydraulic fracturing operations on Federal lands by 

state and operations on Indian lands by reservation, for FY 2010 to FY 2013, shown in Tables 

2A and 2B.

On Federal lands, the estimated number of well completions using hydraulic fracturing was 

generally about 3,100 per year for FY 2010, FY 2011, and FY 2012. However, the estimated 

hydraulic fracturing operations dropped to about 2,320 in FY 2013. The 4-year average of the 

estimates is about 2,925 hydraulic fracturing well completions per year on Federal lands. 

On Indian lands, the estimated number of well completions using hydraulic fracturing increases 

from about 340 in FY 2010 to 520 in FY 2013. The 4-year average of the estimates is about 425

hydraulic fracturing well completions per year on Indian lands. The data reveal differing trends 

for hydraulic fracturing on Federal and Indian lands. While hydraulic fracturing peaked on 

Federal lands in fiscal year FY 2011 and declined sharply in FY 2013, it has increased rather 

steadily on Indian lands over that period. 

We estimate activity in the near-term based on the activity from FY 2010 to FY 2013. We 

believe that the rule would impact about 2,350, 2,135, and 1,950 hydraulic fracturing operations 

on Federal lands and about 600, 670, and 750 operations on Indian lands in the first three years 

of implementation. Combined, that equates to 2,815 operations per year on Federal and Indian 

lands.

The data show a recent downward trend in the activity on Federal land and the upward trend on 

Indian land. However, it is possible that the decrease in completions on Federal lands in FY 

2013 was an aberration and that previous year totals might provide a better predictor of future 

activity. Estimated completions on Federal and Indian lands combined were about 3,550 and 

2,840 in FY 2012 and FY 2013, respectively. Estimated hydraulic fracturing operations on 

Federal and Indian lands were about 3,350 per year for the four-year period from FY 2010 to FY 

2013.

 

17 Re-completions are separate events from initial well completions. However, they appear as separate entries in 

AFMSS only if the re-completion occurs in a different zone. The API and the American Natural Gas Alliance 

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

unconventional wells. Of the wells in regions where most of activity on BLM-managed lands occurs, the refracture 

rate is slightly higher at 3.0 percent (Shires and Lev-On 2012, p. 23).
32

Table 2A: Estimated Hydraulic Fracturing Well Completions on Federal Lands

State

Fiscal Year 4-Year Implementation Year

2010 2011 2012 2013 Average 1 2 3

ALASKA 1 0 1 7 2 7 9 11

ALABAMA 0 0 1 0 0 0 1 1

ARKANSAS 8 9 7 5 7 4 3 2

CALIFORNIA 77 108 222 98 126 171 188 206

COLORADO 369 420 365 129 321 127 50 0

KANSAS 1 5 1 0 2 0 0 0

LOUISIANA 0 3 4 0 2 2 2 2

MISSISSIPPI 0 1 0 5 1 5 6 7

MONTANA 56 22 15 22 29 2 0 0

NORTH DAKOTA 78 124 127 132 115 156 173 189

NEW MEXICO 910 951 956 756 893 778 732 686

NEVADA 4 1 0 2 2 0 0 0

OHIO 1 0 3 1 1 2 2 2

OKLAHOMA 6 8 15 9 10 13 15 16

PENNSYLVANIA 2 0 0 10 3 9 12 14

SOUTH DAKOTA 1 1 5 2 2 4 4 5

TEXAS 17 46 39 14 29 25 23 22

UTAH 347 335 517 446 411 531 579 627

WYOMING 1,159 1,206 827 682 968 516 335 155

TOTAL 3,036 3,241 3,104 2,319 2,925 2,353 2,135 1,946

PERCENT CHANGE --- 7% -4% -25% --- 1.5% -9.3% -8.8%

Notes: For FY 2010- FY 2013, the estimates reflect the number of well completions on Federal lands (AFMSS data as of April 15, 2014), 

assuming that 90% of wells were hydraulically fractured and that 3% percent of those wells were re-fractured. For Implementation years 1, 2, 

and 3, the estimates reflect a linear extension of the activity from FY 2010 to FY 2013 (where the forecast returned a negative value, we imputed 

a zero value).
33

Table 2B: Estimated Hydraulic Fracturing Well Completions on Indian Lands

Reservation

Geographic 

Location 

(State of Political 

Boundary)

Fiscal Year 4-Year Implementation Year

2010 2011 2012 2013 Average 1 2 3

ANADARKO OK 5 4 6 5 5 6 6 6

ARDMORE OK 1 3 1 0 1 0 0 0

BLACKFEET MT 3 8 6 3 5 5 4 4

CHEYENNE & ARAPAHO OK 0 0 2 0 0 1 1 1

CONCHO OK 11 19 13 13 14 14 14 14

CROW MT 6 0 0 1 2 0 0 0

EASTERN NAVAJO NM 10 12 25 10 14 18 19 20

FIVE CIVILIZED TRIBES OK 1 0 1 0 0 0 0 0

FORT BELKNAP MT 1 2 0 0 1 0 0 0

FORT BERTHOLD ND 53 84 185 210 133 277 334 391

FORT PECK MT 1 0 2 0 1 0 0 0

JICARILLA APACHE NM 24 44 44 70 45 80 93 107

MUSKUGEE OK 1 0 0 0 0 0 0 0

OKMULGEE OK 1 6 1 2 3 2 2 1

PAWNEE OK 0 3 0 7 3 7 9 11

SHAWNEE OK 1 2 0 0 1 0 0 0

SHIPROCK NM/UT* 1 3 4 2 2 3 4 4

SOUTHERN UTE, BIA CO 48 17 18 1 21 0 0 0

TAHLAQUAH OK 0 0 1 0 0 0 1 1

TALIHINA OK 0 3 0 1 1 1 1 1

TURTLE MOUNTAIN ND 2 3 2 2 2 2 2 2

UINTAH AND OURAY UT 160 168 132 186 162 172 176 180

UTE MOUNTAIN UTE CO/NM* 9 6 2 5 5 1 0 0

WIND RIVER WY 3 4 6 3 4 4 4 5

TOTAL 342 389 451 520 425 592 670 749

PERCENT CHANGE --- 14% 16% 15% --- 13.9% 13.2% 11.8%

Notes: For FY 2010- FY 2013, estimates reflect the number of well completions on Indian lands (AFMSS data as of April 15, 2014), assuming that 90% of 

wells were hydraulically fractured and that 1% percent of those wells were re-fractured. Estimates for Implementation years 1, 2, and 3 were derived using the 

"forecast" function in excel (where the forecast returned a negative value, we imputed a zero value). The geographic location identifies the state(s) within 

which wells for the reservations were drilled between FY2012-FY2013. The asterisk identifies the state within which the majority of wells were completed for 

that reservation. For example, the majority of wells on the Ute Mountain Ute reservation were completed within the political boundary of New Mexico.
34

2.8 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 latest year 

available), 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 3A through 3E).
35

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

Table 3A: 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 3B: 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 3C: 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 3D: 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 3E: 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%
36

2.9 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).

18

 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.”19

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.”20

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.”21

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 

 

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

19 Ibid, p. 1.

20 Ibid, p. 1.

21 Ibid, p. 2.
37

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

well logging. 

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.”

22 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.”23 

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

24 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.25

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.”26

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.”27 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 

 

22 Ibid, p. 11.

23 Ibid, p. 11.

24 Ibid, p. 11.

25 Onshore Order 2, section III.B.1.h.

26 API Guidance Document HF1, p. 11.

27 Ibid, p. 12.
38

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.”28 Cementing 

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

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.

29

 Figure 2 shows a general schematic of a horizontal and vertical well with a 

hydraulic fracture completion. 

Figure 2: Diagram of a Horizontal and Vertical Well with Hydraulic Fracture Completion

 Source: API Guidance Document HF1, 2009

 

28 Ibid, p. 12.

29 Ibid, p. 13.
39

Cement Evaluation, Well Logging, Mechanical Integrity Tests, and Other Tests

API Guidance Document HF1 stresses the importance of using data from reports, logs, and tests 

to evaluate the quality of a cement job. “It is important to remember that the quality of a cement 

job cannot be fully evaluated without other supporting data. All of the available well information 

is reviewed thoroughly when assessing the integrity of a well’s cement job. Such information 

includes drilling reports, drilling fluid reports, cement design and related laboratory reports, 

open-hole log information including caliper logs, cement placement information including 

centralizer program, placement simulations and job logs, results of mechanical integrity tests 

performed on the well, and other information. The effectiveness of a cement seal should also be 

tested with various hydraulic pressure tests to ensure well integrity.”

30

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.”31 

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

between the casing and the formation.”32 Logs are important in “determining that the well 

drilling construction is adequate and achieves the desired design objectives.”33 As described 

above, it is industry practice to run logs on the production casing of wells. For the intermediate 

casing, if cement is not circulated to the surface, 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 (above any exposed USDW or any hydrocarbon bearing zone). State 

requirements or conditions of the drilling permit may also necessitate the running of logs on the 

intermediate casing.

The guidance clearly states that the operator should pressure test the production casing. “Prior to 

perforating and hydraulic fracturing operations, the production casing should be pressure tested 

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

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

objectives.”34 

Further, the guidance discusses the use of fracturing strings. “In some cases, the production 

casing will never be exposed to high pressure except during hydraulic fracturing. In these cases, 

a high-pressure ‘frac string’ may be used to pump the fluids into the well to isolate the 

production casing from the high treatment pressure. Once the hydraulic fracturing operations are 

complete, the frac string is removed...The well operator or the operator’s designated 

representative should be on site throughout the hydraulic fracturing process. Prior to beginning 

the hydraulic fracture treatment, all equipment should be tested to make sure it is in good 

 

30 Ibid, p. 10.

31 Ibid, p. 8.

32 Ibid, p. 9.

33 Ibid, p. 10.

34 Ibid, p. 12.
40

operating condition. All high-pressure lines leading from the pump trucks to the wellhead should 

be pressure tested to the maximum treating pressure. Any leaks must be eliminated prior to 

initiation of the hydraulic fracture treatment. After this, the final safety and operational meetings 

should be conducted.”35 The casing pressure test on the production casing and the tests on the 

fracturing string describe the intent of the MIT required by the rule.

Pressure Monitoring 

API Guidance Document HF1 says that if the annular space is not cemented to the surface, then 

operators should monitor pressures in the annulus between the production casing and the 

intermediate casing. Language from the guidance is below.

“Pressure is normally measured at the pump and in the pipe that connects the pump to the 

wellhead. If the annulus between the production casing and the intermediate casing has not been 

cemented to the surface, the pressure in the annular space should be monitored and controlled. 

Pressure behavior throughout the hydraulic fracture treatment should be monitored so that any 

unexplained deviation from the pretreatment design can be immediately detected and analyzed 

before operations continue. Typically, variations are within normal ranges, and slight 

adjustments to the original design may be made as operations proceed, based on real-time data 

obtained from the process monitoring. Pressure exerted on equipment should not exceed the 

working pressure rating of the weakest component.

Unexpected or unusual pressure behavior during the hydraulic fracturing process could indicate 

some type of problem. Some problems such as a leak in the casing string are immediately 

apparent, and if this is the case, it is possible to shut down the treatment as soon as this occurs. 

The intermediate casing annulus should be equipped with an appropriately sized and tested relief 

valve. The relief valve should be set so that the pressure exerted on the casing does not exceed 

the working pressure rating of the casing. The flow line from the relief valve should be secured 

and diverted to a lined pit or tank.”

36

2.10 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).37 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. 

 

35 Ibid, p. 16.

36 Ibid, p. 21.

37 API Guidance Document HF2 “Water Management Associated with Hydraulic Fracturing.”
41

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 

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.”

38

2.11 Existing Regulations Related to the Rule’s Provisions

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

regulated under a framework 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 final 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. 

2.11.1 Existing BLM Regulations and Requirements

The BLM has an extensive process in place to ensure that operators conduct oil and gas 

operations in an environmentally sound manner that protects resources. This rule adds specific 

requirements for hydraulic fracturing operations, which supplement the existing requirements. 

Following is a description of these existing processes and requirements, and how they fit in with 

this rule.

 

38 Ibid, p. 18.
42

Section 202 of the Federal Land Policy and Management Act of 1976 (FLPMA) requires the 

BLM to develop and maintain land use plans (the BLM refers to these plans as Resource 

Management Plans, or RMPs). The RMP serves as the basis for all land use decisions made by 

the BLM, including decisions to allow oil and gas leasing, allow oil and gas leasing under certain 

conditions, or prohibit oil and gas leasing altogether. The RMP applies to public lands and 

public mineral estate; however, it does not apply to Indian land or to land managed by other 

Federal agencies such as the United States Forest Service. Those other agencies rely on their 

own planning guidance when determining if their lands are suitable for oil and gas development. 

FLPMA also requires that the public be given ample opportunity to participate in the 

development, maintenance, and revision of land use plans. Regulations implementing FLPMA 

(43 CFR 1610.2) require the BLM field office to publish notices to prepare, amend, or revise 

RMPs in the Federal Register and local newspapers. In addition, the BLM must send notices to 

interest groups and individuals who have expressed an interest to be involved in BLM activities 

or have participated in the past. 

Typically, the first step in the development or revision of an RMP is for the BLM to hold public 

scoping meetings to identify the primary issues that the BLM will need to consider and address 

in the RMP. If, for example, the public identifies tracts of land that are heavily used for 

recreational activities or that hold special environmental significance, the BLM may consider 

closing these tracts to oil and gas leasing or placing restrictions on development. Restrictions 

can include limiting the timing of oil and gas activities to avoid certain impacts, setbacks from 

sensitive resources, establishing limits on surface disturbance, and prohibiting surface occupancy 

entirely. Other areas, such as wilderness areas or land within an incorporated city are closed to 

leasing by law. In addition to public scoping, the BLM coordinates with state, county, and local 

governments, Indian tribes, and other Federal agencies. 

Once various land use options have been developed, the BLM must comply with NEPA by 

analyzing the environmental impacts of the alternatives being considered in the proposed RMP. 

This is done through an Environmental Impact Statement (EIS) developed in conjunction with 

the RMP. The EIS process offers additional opportunity for public involvement. For proposed 

land use decisions, such as keeping areas open for oil and gas leasing, environmental impacts are 

assessed based on a Reasonable Foreseeable Development (RFD) Scenario. The RFD Scenario 

projects the estimated levels and types of industry activity, and the associated surface disturbance 

that might occur during the life of the RMP. Because the RMP/EIS in general covers all the 

Federal land and mineral estate in a field office, the impact analysis is typically done on a broad 

scale. Mitigation measures developed through the EIS can be implemented as leasing 

stipulations. In addition to compliance with NEPA, the BLM must comply with other 

environmental requirements including the National Historic Preservation Act and the 

Endangered Species Act. For example, under the Endangered Species Act, the BLM would

engage in a consultation process with the United States Fish and Wildlife Service or National 

Marine Fisheries Service, if threatened or endangered species or critical habitat may be affected. 

Once a draft RMP/EIS is developed, the public has an additional opportunity to review and 

comment on the analysis of impacts and proposed mitigation measures in an EIS. When all 

comments have been considered, the BLM develops a final RMP/EIS. The Record of Decision 

includes the final land use options from the alternatives considered and justifies the rationale for 
43

the decision. Once the BLM signs the final RMP/EIS, the BLM makes all land use decisions, 

including oil and gas development decisions, in accordance with the RMP. 

Prior to issuing oil and gas leases, the BLM conducts another environmental review, which may 

include, if necessary, additional analysis of the potential impacts of leasing a particular tract or 

tracts of land. Under existing regulations, the public may nominate tracts of land for leasing. In 

practice, though, it is more common for the industry to informally request parcels to be offered 

for leasing. For the BLM, the first step is to ensure that the proposed tracts are under Federal 

jurisdiction and are open to leasing in the RMP. The next step is to develop NEPA review 

documentation-- typically an Environmental Assessment (EA) --to address potential impacts that 

could be caused by oil and gas development within the nominated area. The NEPA review 

conducted at the leasing stage “tiers” from the RMP/EIS. In other words, the issues, potential 

impacts, mitigation measures, and decisions in the RMP/EIS are carried through to the NEPA 

review conducted at this stage. 

An interdisciplinary team consisting of resource specialists such as wildlife biologists, 

archeologists, recreation specialists, geologists, petroleum engineers, hydrologists, and soil 

scientists develops the NEPA documentation. The interdisciplinary team conducts a site visit to 

gather on-the-ground data on potential impacts and mitigation measures. After the site visit has 

been conducted, an EA is drafted, including coordination with county, state, and Federal 

agencies, and consultation with the Fish and Wildlife Service and Indian tribes, if applicable, in 

the area proposed for leasing. EAs are posted on the BLM website and are available in the 

public room(s) for public review and comment, typically for a 30-day period. After the 30-day 

period, the BLM reviews and addresses any comments and finalizes the EA. Specific mitigation 

measures are developed in the context of the NEPA review and are included in a notice to 

potential bidders of an oil and gas lease at a lease sale. Once the environmental review is 

concluded, usually with a finding that the proposed lease issuance would result in no significant 

impacts to the quality of the human environment (FONSI), the lease parcel is included in the 

next scheduled lease sale. In those cases where, based on mitigation, an EA results in a finding 

that the proposed lease issuance would result in no significant impacts to the quality of the 

human environment (FONSI), the mitigation measures relied upon in reaching the FONSI would 

be included as stipulations in potential leases. Upon issuance by the BLM, the lease allows the 

operator to conduct operations on the lease subject to the regulations and lease stipulations.

The BLM has existing regulations including Onshore Oil and Gas Orders to ensure that operators 

conduct oil and gas exploration and development in an environmentally responsible manner that 

protects other resources. Existing section 3162.3-1 and Onshore Order 1 require an operator to 

get approval from the BLM prior to drilling a well. The operator must submit an Application for 

Permit to Drill (APD) containing all of the information required by Onshore Order 1. This 

includes a completed Form 3160-3, Application for Permit to Drill or Re-Enter, a well plat, a 

drilling plan, a surface use plan, bonding information, and an operator certification.

Upon receiving a drilling proposal on Federal lands, the BLM is required by existing section 

3162.3-1(g) to post information for public inspection for at least 30 days before action to approve 

the APD. The information must include: The company/operator name; the well name/number; 

and the well location described to the nearest quarter-quarter section (40 acres), or similar land 
44

description in the case of lands described by metes and bounds, or maps showing the affected 

lands and the location of all tracts to be leased and of all leases already issued in the general area. 

Where the inclusion of maps in such posting is not practicable, the BLM provides maps of the 

affected lands available to the public for review. The BLM will also promptly provide this 

information to the appropriate office of the Federal surface management agency, for lands the 

surface of which is not under Bureau jurisdiction, requesting that agency to post the proposed 

action for public inspection for at least 30 days. The public posting is in the office of the BLM 

authorized officer and in the appropriate surface managing agency office, if other than the 

Bureau.

The public can review the posted information and provide any input they would like the BLM to 

consider during the environmental analysis the BLM prepares prior to making a decision on the 

APD. If the public has questions and concerns regarding drilling proposals, they can meet with 

BLM staff and share those concerns.

The drilling plan provided by the operator must be in sufficient detail to permit the BLM to 

complete an appraisal of the technical adequacy of, and environmental effects associated with, 

the proposed project. The operator must provide geological information, including the name and 

estimated tops of all geologic groups, formations, members, and zones. The operator must also 

provide the estimated depths and thickness of formations, members, or zones potentially 

containing usable water, oil, gas, or prospectively valuable deposits of other minerals that the 

operator expects to encounter, and their plans for protecting such resources. The BLM uses this 

information and the BLM’s geologists’ and engineers’ professional reviews to ensure that usable 

water zones are protected.

The operator must provide their minimum specifications for blowout prevention equipment that 

they will use to keep control of well pressures encountered while drilling. The BLM evaluates 

the proposed equipment to determine that it is adequate for anticipated pressures the well may 

encounter in order to prevent loss of control of the well and potential environmental issues. The 

operator must provide their proposed casing program including the size, grade, weight, and 

setting depth of each casing string. BLM engineers evaluate the proposed casing to ensure that it 

is being set at proper depths to protect other resources, including usable water. The BLM 

engineers also ensure that the casing size and strength is sufficient for the depths at which it will 

be set, and the pressures that the well will encounter.

The operator must also provide information regarding their proposed cementing program. This 

includes the amount and types of cement the operator will use for each casing string, and the 

expected top of cement for each casing string. The cement is critical for the isolation and 

protection of usable water since it is the cement that establishes a barrier outside the casing 

between any hydrocarbon bearing zones and usable water zones. The proposed cementing 

program is the first step for this protection. The BLM engineers evaluate the proposed 

cementing program to ensure that the volume and strength of the cement is adequate to achieve 

the desired protections. 

The operator must also include in the drilling plan information regarding their proposed drilling

fluid. The operator must provide the type and characteristics of the proposed circulating medium 
45

for drilling each well bore section including the quantities and types of mud the operator will 

maintain, and the monitoring equipment the operator will utilize on the circulating system. The 

BLM engineers review this information to ensure that the drilling fluid system and additives will 

be compatible and not detrimental to all usable water and prospectively valuable mineral zones 

that the well bore may encounter. The operator must also provide their proposed testing, 

logging, and coring procedures. This may include resistivity, gamma ray, spontaneous potential, 

caliper, and neutron logs as well as cement evaluation logs. The BLM reviews the proposed 

logging suite and determines if the operator will need to run any additional logs to provide 

additional downhole information. 

The operator’s drilling plan must also address the expected bottom-hole pressure and any 

anticipated abnormal pressures, temperatures, or potential hazards that the well may encounter. 

Hazards may include lost circulation zones, hydrogen sulfide zones, or faults and fractures. The 

operator must also include a plan for mitigating such hazardous. The BLM geologists review 

this information and determine if any other anticipated hazards exist. The BLM engineers 

review this information to ensure the proposed mitigation to address any anticipated hazards is 

acceptable.

The operator must also include any other information regarding their proposed operation that 

they would like the BLM to consider. This would include the directional drilling plan for 

deviated or horizontal wells, which would provide the proposed wellbore path. The BLM 

engineers review the proposed directional plan to ensure there will not be any potential issues 

with existing wells.

The operator’s APD must also include a surface use plan of operations, or the equivalent 

required by another surface management agency. The surface use plan must contain sufficient 

details of the proposed surface use to provide for safe operations, adequate protection of the 

surface resources, groundwater, and other environmental components. The operator must also 

describe any Best Management Practices (BMPs) they plan to use.39 BMPs are state-of-the-art 

mitigation measures applied to oil and natural gas drilling and production to help ensure that 

operators conduct energy development in an environmentally responsible manner. BMPs can 

protect water, wildlife, air quality, or landscapes. The BLM encourages operators to incorporate 

BMPs into their plans.

The operator’s surface use plan should incorporate the BLM’s Surface Operating Standards and 

Guidelines for Oil and Gas Exploration and Development which is commonly referred to as The 

Gold Book.40 The BLM developed The Gold Book to assist operators by providing information 

on the requirements for obtaining permit approval and conducting environmentally responsible 

oil and gas operations. 

 

39 Information concerning BMPs is available on the BLM’s website, at 

http://www.blm.gov/wo/st/en/prog/energy/oil_and_gas/best_management_practices.html

40 The Gold Book is available on the BLM’s website, at 

http://www.blm.gov/wo/st/en/prog/energy/oil_and_gas/best_management_practices/gold_book.html.
46

The operator’s surface use plan must include information regarding existing roads they plan to 

use to access the proposed well location and must explain how they will improve or maintain 

existing roads. The surface use plan must also include the operator’s plan for any new access 

roads they plan to build. The operator must design roads based upon the type of road, the safety 

requirements, traffic characteristics, environmental conditions, and the type of vehicles that will 

use the road. The proposed road description must include: Road width, maximum grade, crown 

design, turnouts, drainage and ditch design, on-site and off-site erosion control, revegetation of 

disturbed areas, location and size of culverts and/or bridges, fence cuts and/or cattleguards, major 

cuts and fills, source and storage of topsoil, and the type of surface materials that the operator 

will use.

The operator must also include a map showing all known wells, regardless of well status 

(producing, abandoned, etc.) within a one-mile radius of the proposed location. The BLM uses 

this information to ensure the proposal does not conflict with any current surface use. The BLM 

also uses this well information to identify any potential downhole conflicts or issues between the 

existing wells and the proposed well. If the BLM does identify conflicts, the BLM will require 

the operator to modify their proposal or to submit plans to mitigate the issue.

The operator must also include a map or diagram that shows the location of all production 

facilities and lines they will install if the well is successful (a producing well), as well as any 

existing facilities. This would include all buried oil, water, or gas pipelines and all overhead and 

buried power lines. The BLM reviews this information to identify any potential conflicts with 

the proposed facilities.

The operator must also include in their surface use plan information concerning the water supply, 

such as rivers, creeks, springs, lakes, ponds, and wells that the operator plans to use for drilling 

the well. This may or may not be the same source of water the operator plans to use for their 

hydraulic fracturing operations. The BLM does not regulate water usage, but the BLM does use 

the information about water supply in conducting the environmental analysis of the APD. The 

BLM also uses the information to determine if the operator must obtain any additional approvals 

such as a right-of-way across Federal lands that may be necessary for the transport of water. 

The operator must also include a written description of the methods and locations it proposes for 

safe containment and disposal of each type of waste material (e.g., cuttings, garbage, salts, 

chemicals, sewage, etc.) that results from drilling the proposed well. The narrative must include 

plans for the eventual disposal of drilling fluids and any produced oil or water recovered during 

testing operations. The operator must describe plans for the construction and lining, if necessary, 

of the reserve pit.

The surface use plan must also include the character, intended use, and source of all construction 

materials, such as sand, gravel, stone, and soil material. The operator must also identify the 

location and construction method and materials from all anticipated ancillary facilities such as 

camps, airstrips, and staging areas. This information will be used to assess the environmental 

impacts of the proposed operations.
47

The operator must also include a diagram of the proposed well site layout. The layout must 

show the location and orientation of the following: The proposed drill pad, the reserve pit/blooie 

line/flare pit location, access road entry points, and the reserve pit showing all cuts and fills, the 

drilling rig, any dikes and ditches to be constructed, and topsoil and/or spoil material stockpiles.

The operator must also submit a plan for the surface reclamation or stabilization of all disturbed 

areas. The plan must address interim (during production) post-drilling reclamation for the area 

of the well pad not needed for production, as well as final abandonment of the location. The plan 

must include, as appropriate, the following: Configuration of the reshaped topography, drainage 

systems, segregation of stockpiles, surface disturbances, backfill requirements, proposals for pit 

closures, redistribution of topsoil, soil treatments, seeding or other steps to reestablish vegetation, 

weed control, and practices necessary to reclaim all disturbed areas, including any access roads 

and pipelines.

If BLM does not manage the surface, the surface management agency must approve the surface 

use plan.

The APD must also provide proof of adequate bond coverage as required by existing 43 CFR 

3104.1 for Federal lands and by 25 CFR 211.24, 212.24, and 225.30, for Indian lands. These 

regulations require the operator or the lessee to have an adequate bond in place prior to the 

BLM’s approval of the APD. If the BLM determines that the current bond amount is not 

sufficient, the BLM can require additional bond coverage. The BLM determines the need for 

bond increases by considering the operator’s history of previous violations, the location and 

depth of wells, the total number of wells involved, the age and production capability of the field, 

and any unique environmental issues.

Upon receipt of a complete APD, the BLM will schedule an onsite inspection with the operator. 

The purpose of the onsite inspection is for the BLM and operator to further identify site-specific 

resource concerns and requirements not originally identified during the application stage. Prior 

to, or in conjunction with, the onsite inspection, the BLM or other surface management agency 

will advise the operator if any special inventories or studies are required, such as for cultural 

resources or threatened and endangered species. 

The onsite inspection team will include the BLM, a representative of any other surface 

management agency, the operator or permitting agent, and other parties associated with planning 

work on the project, such as the operator’s principal dirtwork contractor, agency resource 

specialists, surveyors, and pipeline or utility company representatives. When the onsite 

inspection is on private surface, the BLM will invite the surface owner to attend. The purpose of 

the onsite inspection is to discuss the proposal; determine the best location for the well, road, and 

facilities; identify site-specific concerns and potential environmental impacts associated with the 

proposal; and discuss the conditions of approval (COAs) or possible environmental BMPs. If the 

BLM identifies resource conflicts, the BLM has the authority to require the operator to move 

surface facilities to locations that would reduce resource impacts while still allowing 

development of the leased minerals. 
48

After the BLM has reviewed the operator’s proposed plans and conducted the onsite inspection, 

the BLM will prepare an environmental document in conformance with the requirements of 

NEPA, the regulations of the Council of Environmental Quality (CEQ), and the Department of 

the Interior’s regulations. The extent of the environmental analysis process and the time frame 

for issuance of a decision on the APD will depend upon the complexity of the proposed action 

and resulting analysis, the significance of the environmental effects disclosed, and the 

completion of appropriate consultation processes. Regardless of the complexity of the proposed 

action, the environmental analysis will always consider environmental concerns and resource 

issues in the area, including those the BLM or operator identified during the onsite inspection

such as potentially impacted cultural resources, endangered species, surface water, ground water,

and other natural resources. A group of resource specialists will conduct the analysis. The 

composition of the team will depend on the resource issues in that area and any resource issues 

that the BLM or operator identified during the onsite inspection. The resource specialists may 

include petroleum engineers, geologists, natural resources specialists, wildlife biologists, 

archeologists, hydrologists, soil scientists, botanists, recreation specialists, range management 

specialists, and realty specialists.

The environmental analysis may be conducted for a single well, a group of wells, or for an entire 

field. The public is welcome to provide input to the BLM for inclusion in the analysis. As 

discussed previously, the BLM posts notices of all Federal APDs for public inspection in the 

authorizing office. For large projects, such as field development environmental assessments or 

environmental impact statements, the BLM will go through public scoping and will issue a draft 

analysis for public comment prior to completing the final analysis and issuing a decision.

The environmental analysis will identify potential impacts from the proposed action. The BLM 

will develop any necessary conditions of approval to mitigate those potential impacts. If the 

BLM identifies unacceptable impacts, the BLM will ask the operator to modify its proposal, or 

the BLM may deny the application. The BLM will attach the conditions of approval to the 

approved APD. The operator must follow the approved plan and all conditions of approval.

Upon BLM’s approval of an APD, the operator may commence drilling of the well. In addition 

to the approved plan and the conditions of approval attached to the APD, the operator must also 

comply with the requirements of Onshore Order 2. Onshore Order 2 details the BLM's uniform 

national minimum standards of performance expected from operators when conducting drilling 

operations on Federal and Indian lands. Many of the requirements of Onshore Order 2 ensure 

the protection of usable water. Onshore Order 2 defines isolating as “using cement to protect, 

separate, or segregate usable water and mineral resources” and usable water as “generally those 

waters containing up to 10,000 ppm of total dissolved solids.” 

Onshore Order 2 requires that the operator conduct the proposed casing and cementing programs 

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

pressured zones, and any prospectively valuable deposits of minerals. It requires that the 

operator determine the casing setting depths based on all relevant factors, including: 

Presence/absence of hydrocarbons; fracture gradients; usable water zones; formation pressures; 

lost circulation zones; other minerals; or other unusual characteristics. It also requires the 

operator to report all indications of usable water.
49

Onshore Order 2 requires the operator to run centralizers on the bottom 3 joints of surface casing 

to help ensure the casing is centered in the drilled hole prior to cementing. This helps to ensure 

wellbore integrity. It also requires the operator to cement the surface casing back to the surface 

either during the primary cement job or by remedial cementing. Cementing the surface casing 

back to the surface ensures that all usable water zones behind the surface casing are isolated and 

protected. Onshore Order 2 requires the operator to wait until the cement for all casing strings 

achieves a minimum of 500 psi compressive strength at the casing shoe prior to drilling out the 

casing shoe. It also requires the operator to use top plugs during cementing operations to reduce 

contamination of the cement by displacement fluid. It requires the operator to use a bottom plug 

or other acceptable technique, such as a preflush fluid, inner string cement method, etc., to help 

isolate the cement from contamination by the mud fluid being displaced ahead of the cement 

slurry. By using proper cementing techniques such as these, the operator can complete the 

cement job as planned and thus protect usable water.

Onshore Order 2 requires the operator to pressure test the casing prior to drilling out the casing 

shoe. This test ensures the integrity of the casing. Onshore Order 2 also requires the operator to 

conduct a pressure integrity test of each casing shoe on all exploratory wells, and on that portion 

of any well approved for a 5000 psi blowout preventer. The operator must conduct this test 

before drilling 20 feet of new hole. The pressure test ensures the integrity of the cement around 

the casing shoe.

Onshore Order 2 also identifies the minimum requirements for blowout prevention equipment 

and the minimum standards for testing the equipment. Proper sizing, installation, and testing of 

the blowout prevention equipment ensures that the operator maintains control of the well during 

the drilling process, which is necessary for protection of usable water zones.

The BLM conducts inspections of drilling operations to ensure that operators comply with the 

Order 2 drilling regulations, the approved permit, and the conditions of approval. The BLM 

drilling inspections consist of two general types of inspections: Technical and environmental. 

The BLM petroleum engineering technicians conduct technical inspections of the drilling 

operations such as witnessing the running and cementing of the casing, witnessing the testing of 

the blowout prevention equipment, and detailed drilling rig inspections that include review of 

documentation such as the third party cementing job ticket which describes the cementing 

operation including the type and amount of cement used, the cement pump pressures, and the 

observation of cement returns to the surface, if applicable. Through witnessing the operation or 

the review of the documentation, the BLM inspectors verify that the drilling operations are 

conducted in accordance with the approved plan and that no wellbore issues exist. The BLM 

natural resource specialists conduct environmental inspections of drilling operations. The 

environmental inspections focus primarily on the surface use portion of the approved drilling 

permit. This includes inspection of the access road, the well pad, and any pits. While the BLM 

does not have the budget or personnel available to inspect every drilling operation on Federal 

and Indian minerals, the BLM conducts inspections in accordance with an annual strategy to 

ensure compliance with the regulations, lease stipulations, conditions of approval for the plan, 

and permits.
50

As described above, the BLM has numerous processes and requirements to ensure that operators

conduct oil and gas exploration and development in an environmentally responsible manner that 

protects other resources. This final rule complements these existing requirements by providing 

specific requirements for hydraulic fracturing operations. The final rule requires the operator to 

submit an application and receive BLM approval prior to conducing hydraulic fracturing 

operations. The application provides details of the operator’s proposed operations. The rule 

provides the operator with specific requirements, including testing and verification to ensure 

proper wellbore construction and integrity. It also sets standards for handling of the fluids the 

operator recovers from the well after hydraulic fracturing operations. Each of these items 

ensures that the operator protects Federal and Indian resources including groundwater and 

surface water. 

Within 30 days after the operator completes a well, the operator is required by existing 

regulations to submit a BLM Well Completion or Recompletion Report and Log (Form 3160-4), 

which provides drilling and completion information. This includes the actual casing setting 

depths and the amount of cement the operator used in the well along with information regarding 

the completion interval such as the top and bottom of the formation, the perforated interval, and 

the number and size of perforation holes. The operator is also required to submit copies of all 

electric and mechanical logs, including the cement evaluation log, which the operator ran on the 

well prior to conducting hydraulic fracturing operations. The BLM reviews this information to 

ensure that the operator set the casing and pumped the cement according to the approved permit.

Once a well goes into production, water is often produced with the oil and gas. The water tends 

to be of poor quality and is not generally suitable for drinking, livestock, or other uses and, 

therefore, must be disposed of properly. Onshore Oil and Gas Order 7 (Order 7) regulates the 

disposal of produced water. Under Order 7, operators must apply to the BLM for authorization 

to dispose of produced water by injecting the water into a suitable formation, by storing it in pits, 

or by other methods approved by the BLM. If the disposal is into injection wells, the operator 

must also obtain approval from the Environmental Protection Agency (EPA) under the 

Underground Injection Control (UIC) program. In many states, the EPA has delegated its UIC 

authority to the state agency responsible for oil and gas development. If the water will be stored 

in pits, the BLM requires specific design standards to ensure the water does not contaminate the 

environment or pose a threat to public health and safety.

After a well has been drilled and completed, the BLM continues to inspect the well until it has 

been plugged and abandoned and the surface has been rehabilitated. During the production 

phase of the well, the BLM inspections focus on two primary issues: production and the 

environment. The Federal Government (Federal leases) or an Indian tribe or individual Indian 

allottee (Indian leases) receive a royalty on the oil and gas removed or sold from the lease based 

on the volume, quality, and value of the oil and gas. Royalties from Federal leases are shared 

with the state as provided by statute. Production inspections are done to ensure the volume and 

quality of the oil and gas is accurately measured and properly reported. Environmental 

inspections are done to ensure that well pads and facilities are in compliance with regulations, 

Onshore Orders, and approved permits. Environmental inspections include ensuring that pits are 

properly constructed, maintained, and protected from wildlife; identifying leaking wells or 
51

pipelines; ensuring that the wellsite and facilities are properly maintained; and ensuring that 

proper erosion controls and rehabilitation measures are in place. 

When a well has reached the end of its economic life, Federal regulations require that it be 

plugged and abandoned to prevent oil and gas from leaking to the surface or contaminating water 

bearing zones or other mineral zones. Well abandonment can be requested by the operator or 

required by the BLM. In either case, the operator must submit a proposal for well plugging, 

including the length, location, type of cement, and placement method to be used for each plug. 

Onshore Order 2 contains minimum requirements for well plugging. The operator must also 

submit a plan to rehabilitate the surface once the well has been plugged. The goal of surface 

rehabilitation is to remove obvious visual evidence of the pad and to promote the long-term 

stability of the site and vegetation. 

The BLM inspects both well plugging and surface restoration. Well plugging inspections are 

done to ensure the plugs are set into the wellbore as approved by the BLM. The inspector will 

witness the depth and volume of cement used in each plug as well as the physical verification of 

the top of each plug. When an operator has complete surface restoration, it will notify the BLM. 

The BLM will send surface protection specialists to ensure the restoration is adequate. Once the 

BLM is satisfied with the restoration efforts, the BLM will approve the operator’s Final 

Abandonment Notice.

2.11.2 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, 

Oklahoma, Texas, Utah, and Wyoming. From FY 2010 to FY 2013, the number of well 

completions on Federal and Indian lands in those states accounted for 99.3 percent of the total 

well completions on Federal and Indian lands nationwide. Table 4 shows a summary of the 

findings.

California

We reviewed the California Code of Regulations to the extent possible.41 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 

 

41 California Code of Regulation was accessed on May 27, 2014: 

ftp://ftp.consrv.ca.gov/pub/oil/publications/PRC04_January_11.pdf.
52

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.”42 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.”

43

 

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 317O). It requires pressure testing of the production casing prior to 

operations (Rule 317J). 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 317H). Pits must be lined to various specifications (Rule 904). 

Operators in Surface Water Supply Areas must contain flowback and stimulation fluids within 

tanks that are placed on a well pad or in an area with downgradient perimeter berming (Rule 

317B.d(2)). Operators must disclose chemicals used after the hydraulic fracturing operation 

(Rule 205A).

Montana

We reviewed Montana’s rules governing oil and gas conservation.44 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 (Rule 36.22.1001(2)). Production strings must be cemented 

and pressure tested (Rule 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” (Rule 36.22.1207). It also requires the 

chemical disclosure of well stimulation fluids (Section 36.22.1015).

 

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

Accessed on May 27, 2014: 

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

43 COGCC rules were accessed on May 27, 2014: http://cogcc.state.co.us/RR_Docs_new/Rules_new2.html.

44 Montana rules were accessed on May 27, 2014: 

http://www.mtrules.org/gateway/ChapterHome.asp?Chapter=36.22.
53

New Mexico

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

“Chapter 15 Oil and Gas.”45 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 (Section 

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

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 (Section 19.15.17.8). The regulations also 

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

North Dakota

We reviewed the North Dakota Rules and Regulations, particularly Section II General Rules.46 

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

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

(Section 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 (Section 43-02-03-31).

The regulations have a specific section for hydraulic fracturing operations at Section 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 (Section 43-02-

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

03-19.3). The rules also have a provision for public disclosure to FracFocus (Section 43-02-03-

27.1(1)(g)). 

Oklahoma

The Oklahoma Corporation Commission Oil and Gas Division (OCC) is the state regulatory 

authority, with oil and gas regulations in Title 165, Chapter 10 of the Oklahoma Register.47 We 

 

45 NMOCC rules were accessed on May 27, 2014: 

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

46 North Dakota rules were accessed on May 27, 2014: https://www.dmr.nd.gov/oilgas/rules/rulebook.pdf.

47 Oklahoma rules were accessed on May 27, 2014: 

http://www.occeweb.com/rules/Web%20Ready%20Ch10%20FY14%2007-01-13%20searchable.pdf.
54

found no sections in the regulation that require operators to conduct cement evaluations on any 

of the casing strings under normal circumstances. If the cement fails to circulate to the surface 

while cementing the surface casing, then the operator will determine the top of the cement using 

a method approved by the District Manager (Section 165:10-3-4(d)(4)(E)). It then specifies 

remedial actions that the operator must take if that occurs. The operator must submit cementing 

reports for the surface, intermediate, and production casing strings (OAC 165:10-3-4(j)(1)). The 

operator must pressure test all casing strings (OAC 165:10-3-4(h)(1)). From our review, we 

believe it allows lined pits for recovered fluids (OAC 165:10-7-16(b)(1)). It requires chemical 

disclosure to FracFocus (OAC 165:10-3-10(b)).

Texas

The Texas Railroad Commission (TRC) is the state regulatory authority and, on January 1, 2014, 

updated its regulations covering casing, cementing, drilling, well control, and completion 

requirements.

48

 The TRC does not appear to have logging requirements on casing strings under 

normal circumstances, however operators may use logs or other tools to show that the cementing 

operations reached the specified depths above productive zones, potential flow zones, and/or 

zones with corrosive formations (Section 3.13(a)(4)(D)). Operators must receive approval from 

the TRC for alternate surface casing programs and must conduct a temperature survey log or 

cement bond log when the cement is not circulated to the surface (Section 3.13(b)(2)(H)). The 

TRC requires operators to pressure test the surface in intermediate strings of casing before 

drilling the cement plug (Section 3.13(a)(5)). 

The Texas Administrative Code places specific requirements on hydraulic fracturing operations. 

All casing strings or fracture tubing installed in a well that will be subjected to hydraulic 

fracturing treatments shall have a minimum internal yield pressure rating of at least 1.10 times 

the maximum pressure to which the casing strings or fracture tubing may be subjected (Section 

3.13(a)(7)(A)). The operator shall pressure test the casing (or fracture tubing) on which the 

pressure will be exerted during hydraulic fracturing treatments to at least the maximum pressure 

allowed by the completion method. In the event of a pressure test failure, no hydraulic fracturing 

treatment may be conducted until the district director has approved a remediation plan, and the 

operator has implemented the approved remediation plan and successfully re-tested the casing 

(or fracture tubing)(Section 3.13(a)(7)(B)). During hydraulic fracturing treatment operations, the 

operator shall monitor all annuli (Section 3.13(a)(7)(C)). It also has special requirements for 

minimum separation wells (Section 3.13(a)(7)(D)). 

The TRC prohibits the use of pits for the storage of “oil and gas wastes” and “oil field fluids” 

(Section 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 and concentration of hydraulic 

fracturing fluids following the operation (Section 3.29(c)(1)(A)).

 

48 The Texas Administrative Code for the TRC was accessed on May 27, 2014: 

http://info.sos.state.tx.us/pls/pub/readtac$ext.ViewTAC?tac_view=4&ti=16&pt=1&ch=3&rl=Y.
55

Utah 

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

Operating Practices.49 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.”50 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)).

 

49 Utah rules were accessed on May 27, 2014: http://oilgas.ogm.utah.gov/Rules/Rules.htm.

50 WOGCC rules were accessed on May 27, 2014: http://soswy.state.wy.us/Rules/default.aspx.
56

Table 4: State Regulations Covering Requirements in the Revised Proposed Rule

* FracFocus indicates that Colorado, Louisiana, Mississippi, Montana, North Dakota, Oklahoma, Pennsylvania, and Texas use 

FracFocus for the regulatory disclosure (FracFocus website: http://fracfocus.org/node/335). North Dakota and Utah require the 

disclosure to FracFocus in their regulations. 

State

Percent of well 

completions on 

Federal and 

Indian lands 

from FY10-13

CEL on 

Intermediate 

Casing

CEL on 

Production

Casing

MIT or 

Pressure Test 

on the Casing 

Proposed for 

Fracturing

Minimum 

Requirement 

for Storage 

Tanks

Minimum 

Requirement 

for Lined Pits

Chemical 

Disclosure*

California 4% May require May require Allowed No Generally For spill 

contingency 

plan

Colorado 10% No, unless 

using a 

production 

liner

Yes Yes In Surface 

Water Supply 

Areas

Yes Yes to 

FracFocus

Montana 1% No No Yes No Yes Yes to 

FracFocus

New Mexico 29% No No Yes Yes, unless 

approved to use 

lined pits

N/A unless 

approved

Yes

North Dakota 7% Yes Yes Yes No Yes Yes to 

FracFocus 

(regulations)

Oklahoma 1% No No Yes No Yes Yes to 

FracFocus 

(regulations)

Texas 1% CBL of temp 

log if cement 

not circulated 

to surface

CBL or temp 

log if cement 

not circulated 

to surface

Yes Yes, unless 

approved to use 

pits

N/A Yes to 

FracFocus

Utah 17% No No Yes No Yes Yes to 

FracFocus 

(regulations)

Wyoming 29% May require May require Yes No Yes Yes
57

3. Estimating Benefits and Costs

3.1 Theoretical Framework

This analysis estimates or describes the potential impacts that would occur as a result of the rule. 

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

baseline). In analyzing the potential costs and benefits of the rule, it is important to differentiate 

between the activities that an operator conducts (either voluntarily or in compliance with state or 

Federal requirements) and those new activities that the rule would compel. This incremental 

change is the basis for the 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.

We measured the incremental impacts by: estimating the number of hydraulic fracturing 

operations per year for future years; determining the applicability of the requirements on the 

operations; determining the unit cost of compliance per requirement; and calculating the total 

costs across all requirements and operations. We chose to use this approach since a requirement

in the rule may not pose an incremental compliance cost, depending on the operators’ voluntary 

compliance (generally determined as whether the requirement is consistent with industry 

guidance or best practice) or the regulatory requirements in the jurisdiction within which the 

operation will occur.

We describe our approach to estimating the number of hydraulic fracturing operations in Section 

2.7 of this report. We take the number of well completions on Federal and Indian lands for FY 

2010 to FY 2013, and assume that 90% of wells were completed using hydraulic fracturing and 

that 3% of those wells would be recompleted within the same zone. We then use the results from 

that 4-year period to forecast 3 future years of implementation, resulting in an estimate of about 

2,815 hydraulic fracturing operations on Federal and Indian lands per year. 

For the annual estimate of completions using hydraulic fracturing, we use the 3-year average of 

the implementation years within each state and reservation. Recognizing the decrease in well 

completions on Federal lands in FY 2013, and recognizing that previous levels of activity were 

higher, we also calculate costs using the FY 2012 level of activity on Federal lands (prior to the 

FY 2013 decrease) and present that estimate as an upper bound of potential costs.

We expect that operators are already in compliance with many of the rule’s requirements as a 

matter of company practice or standard industry practice as recommended in industry guidelines 

for hydraulic fracturing (described in Sections 2.9 and 2.10 of this report), or to meet state 

regulations (described in Section 2.11.2 of this report) or Federal regulations (described in 

Section 2.11.1 of this report). Where the rule’s requirements are consistent with industry 

guidance, state regulations, and/or Federal regulations, we consider the applicability of the 

requirement to be 0% and the incremental impact to be zero. We consider partial applicability in 

areas and in situations where the operator is expected to comply voluntarily, for example, when a 

requirement costs less than the alternative. 
58

3.2 Measuring the Incremental Costs

Application Requirement: The operator must submit an application to conduct a hydraulic 

fracturing operation with the APD or a NOI Sundry when it plans to hydraulically fracture a well 

for which it:51

 Has not yet submitted an APD; 

 Has submitted an APD, but the APD has yet to be approved; 

 Drilled the well 180 or more days prior to the effective date (or 3 months or more prior to 

publication), but did not hydraulically fracture it;

 Has an approved APD on the effective date (at least 3 months after publication), but does 

not conduct hydraulic fracturing within 90 days after the effective date (at least 6 months 

after publication);

 Has started drilling on the effective date (at least 3 months after publication), but does not 

conduct hydraulic fracturing within 90 days after the effective date (at least 6 months 

after publication);

 Drilled between 180 days prior to the effective date (or 3 months prior to publication) and 

the effective date (at least 3 months after publication), did not hydraulically fracture it by 

the effective date (at least 3 months after publication), and does not conduct hydraulic 

fracturing within 90 days after the effective date (at least 6 months after publication);

The operator may also submit an application for a group of wells as part of a master hydraulic 

fracturing plan, thus reducing the number of potential applications.

The application requirement is new and poses an incremental administrative burden to the 

operator and for the BLM to review. The information required in the application should be 

readily available or known to the operator. The information should not require any additional 

information gathering. A master hydraulic fracturing plan will allow for efficiencies in 

submission and review. Thus, we would expect there to be fewer applications than the number 

of hydraulic fracturing operations, because of the option to make one submission for a group of 

wells. 

We estimate the applicability of this requirement based on the number of well completions using 

hydraulic fracturing that we expect to occur. Since we assume that every hydraulic fracturing 

operation will require an application, our estimate is inclusive of all instances described in the 

first paragraph of this section (and particularly in bullets 3 through 6) where an operator would 

be required to submit an application to conduct hydraulic fracturing. 

The data are as follows:

 

51 We note again that the effective date of the rule will be 90 days after it is published in the Federal 

Register, and so 90 days after the effective date would be at least 180 days after it is published as final. 
59

(a) Applicability of requirement = 100% of operations. Although the BLM allows for the 

operator to submit a single NOI covering a group of wells, it is uncertain whether the 

operator will prefer that method over submitting an application with the APD. For the 

purpose of this analysis, we assume that the operator will submit an application for a 

single well, especially in the near-term future.

(b) Cost per application = $643. The cost per application includes the operator burden and the 

BLM burden. For both burdens, we estimate the compliance or review hours and the 

respective wage. The compliance cost for the operator is estimated to be about $496 per 

application (calculated as 8 hours at about $61.99 per hour). The review cost for the 

BLM is estimated to be about $147 per application (calculated as 4 hours at about $36.66

per hour).52 Some commenters asserted that the additional informational requirements 

would cause additional delays in the processing of APDs and thus constitute an 

opportunity cost to the operator. This argument is not supported. The supporting 

statement for the Paperwork Reduction Act estimates only 4 hours of additional review

time for the BLM to review this information. This hardly presents a measureable delay in 

processing time. Therefore, the analysis considers the compliance costs as formulated 

above, but it does not consider delay costs. 

Usable Water Requirement: The operator must isolate all usable water and other mineralbearing formations and protect them from contamination. Usable water is defined in the rule to 

mean generally those waters containing up to 10,000 parts per million (ppm) of total dissolved 

solids (TDS). Usable water includes, but is not limited to: (1) Underground water that meets the 

definition of “underground source- of drinking water” as defined at 40 CFR 144.3; (2) 

Underground sources of drinking water under the law of the State (for Federal lands) or tribe (for 

Indian lands); and (3) Water in zones designated by the State (for Federal lands) or tribe (for 

Indian lands) as requiring isolation or protection from hydraulic fracturing operations. The 

following geologic zones are deemed not to contain usable water: (A) Zones from which an 

operator is authorized to produce hydrocarbons; (B) Zones designated as exempted aquifers 

under 40 CFR 144.7; and (C) Zones that do not meet the definition of underground source of 

drinking water at 40 CFR 144.3 which the state (for Federal lands) or the tribe (for Indian lands) 

has designated as exempt from any requirement to be isolated or protected from hydraulic 

fracturing operations.

This requirement does not pose an incremental cost. The term usable water is defined in a 

manner consistent with existing BLM requirements in Onshore Oil and Gas Order No. 2, Drilling 

Operations on Federal and Indian Oil and gas leases (53 FR 46798) (Onshore Order 2). Onshore 

Order 2 section III.B. requires casing and cement to “protect and/or isolate all usable water 

zones.” Onshore Order 2 defines isolate as “using cement to protect, separate, or segregate 

usable water and mineral resources” (section II.I) and usable water as “generally those waters 

containing up to 10,000 ppm of total dissolved solids” (section II.Y). Onshore Order 2 has been 

in effect since 1988; therefore, the requirement to protect and/or isolate usable water generally 

containing up to 10,000 ppm of TDS has been in effect since that time. This rule corrects the 

 

52 The cost formulation for administrative requirements is detailed in the supporting statement for the Paperwork 

Reduction Act. 
60

inconsistency between the definition in Onshore Order 2 (the definition in effect) and the 

definition in the existing CFR 3162.5-2(d). The definition in the CFR, of a 5,000 ppm standard, 

was superseded by the Onshore Order 2 definition in 1998. 

(a) Applicability of requirement = 0%

(b) Incremental cost per requirement = $0

Cement Monitoring Requirement: During cementing operations on any casing used to isolate 

usable water zones, the operator must monitor and record the flow rate, density, and pump 

pressure and submit a cement operation monitoring report, including this information, to the 

authorized officer prior to commencing hydraulic fracturing operations. For wells drilled prior to 

the effective date of the rule, the operator is required to provide documentation that demonstrates 

that the well is adequately cemented.

This requirement does not pose an incremental cost. API Guidance Document HF1 stresses the 

importance of using data from reports, logs, and tests to evaluate the quality of a cement job, 

including drilling reports, drilling fluid reports, cement design and related laboratory reports, etc. 

Based on this information and our observations of field operations, we believe that operators 

monitor cementing operations as a matter of practice and can easily provide this information to 

the authorized officer prior to conducting hydraulic fracturing. The administrative burden of 

providing this information to the BLM is contained in the application requirement.

(a) Applicability of requirement = 0%

(b) Incremental cost per requirement = $0

Surface Casing Requirements: The operator must observe cement returns to the surface and 

document any indications of inadequate cement (such as, but not limited to, lost returns, cement 

channeling, gas cut mud, failure of equipment, or fallback from the surface exceeding 10 percent 

of surface casing setting depth or 200 feet, whichever is less). If there are indications of 

inadequate cement, then the operator must determine the top of the cement with a CEL, 

temperature log, or other method or device approved by the authorized officer.

This requirement does not pose an incremental cost. Onshore Order 2 requires the operator to 

return cement to the surface (section II.B.1.c). Documenting indications of adequate cement and 

taking corrective action are necessary responses when such issues arise.

(a) Applicability of requirement = 0%

(b) Incremental cost per requirement = $0

The BLM examined alternative approaches to the final rule that would pose an incremental cost, 

including requiring the operator to (1) run a CEL on the surface casing or (2) run a CEL on the 

surface casing of a type well. These requirements would have posed an incremental cost to the 

operator, since the operator typically does not run a CEL on the surface casing and the test would 

add another step to the drilling process. 

For the purpose of examining these alternatives, we use the following data:

(1) Alternative 1: The operator must run a CEL on the surface casing of every well.
61

(a) Applicability of alternative 1 = 100% of operations

(b) Cost per surface casing CEL = $58,932 – $127,600. The cost for a CEL on the surface 

casing includes the test ($6,000) and the cost of maintaining idle drilling equipment onsite ($52,932 – $121,600).53

 We received a number of public comments on the proposed 

rules suggesting that cement needs to harden for up to 72 hours before it reaches the

compressive strength for a CEL.54 Of course, currently under Onshore Order 2, the 

operator must already wait until the cement achieves a minimum of 500 psi compressive 

strength at the casing shoe prior to drilling out. This typically takes 8 hours. In 

calculating the additional burden of the alternative approach, we use an incremental delay 

time of 64 hours (or 72 hours less 8 hours) at a cost of $1,900 per hour. Next, we 

examined the potential for the operator to avoid the delays entirely. There are ways that 

the operator could avoid maintaining idle drilling equipment. For example, the operator 

might cement the surface casing, pressure test the surface casing, drill the intermediate 

hole, and then log the surface casing before setting the intermediate casing. Also, when 

drilling multiple wells successively, the operator may use a small drilling rig to drill the 

surface holes of wells in a successive manner, and use a large drilling rig to drill the well 

to total depth. In such a scenario, the operator could avoid the costs of maintaining idle 

drilling equipment. Using AFMSS well completion data over a 5-year period, which 

includes spud dates for wells in leases and agreements (referred to as cases55 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 a CEL requirement would not cause operators to maintain idle drilling equipment. 

As such we present that estimate as the lower bound and an estimate without that 

assumption as an upper bound. 

(2) Alternative 2: The operator must run a CEL on the type well, but may forego the CEL on 

subsequent wells with the same geologic characteristics.

(a) Applicability of alternative 2 = 8%. To estimate the number of logs that the alternative 

would compel, we examined the extent to which subsequent wells would likely fall under 

type well approval. Using AFMSS well completion data from a 5-year period,56 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 

 

53 We calculate the lower bound as ($1900 per hour) x (64 hours) x (1 – 0.5647). We calculate the upper bound as 

($1900 per hour) x (64 hours).

54 We received comments suggesting delay times of 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 an additional burden. 

55 A case is a lease, communization agreement, or unit participating area. 

56 The dataset included 17,475 Federal and Indian wells that were completed between January 2008 and December 

2012.
62

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.

(b) Cost per surface casing CEL = $58,932 to $127,600. 

CEL on Intermediate Casing that Protects Usable Water: If the operator does not cement the 

intermediate casing string to surface and the intermediate casing is used to isolate usable water,

then the operator must run a CEL to demonstrate that there is at least 200 feet of adequatelybonded cement between the zone to be hydraulically fractured and the deepest usable water zone.

This requirement might pose an additional burden to the operator. API Guidance Document HF1 

stresses the importance of using data from reports, logs, and tests to evaluate the quality of a 

cement job. According to the guidance, 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.”57 A cement bond log “measures 

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

formation.”58 Logs are important in “determining that the well drilling construction is adequate 

and achieves the desired design objectives.”59 It is industry practice to run logs on the 

production casing of wells. For the intermediate casing, if cement is not circulated to the 

surface, 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 (above any exposed USDW or 

any hydrocarbon bearing zone). State requirements of conditions of the drilling permit may also 

necessitate the running of logs on the intermediate casing.

Generally, we expect that the operator would log the intermediate casing or use another test to 

verify and ensure that the well was constructed according to design. Logging the casing may 

also be warranted if the operator plans to hang a production liner off of the intermediate casing, 

if the proposed fracturing is through the intermediate casing, for hole stability, for isolation 

through salt zones, or for isolation through disposal zones. 

Some states require logging of the intermediate casing through regulation in a manner that is 

consistent with this rule. As detailed earlier, North Dakota requires a CBL on the intermediate 

casing, Colorado requires a CBL if the operator uses a production liner, and Texas specifies that 

the operator must identify the top of cement (with a CBL or temperature log) if it does not 

cement to the surface. California and Wyoming may require it. Additionally, the BLM and 

states may require operators to log the intermediate casing as a condition of approval if, for 

example, any of the conditions in the previous paragraph apply. Industry guidance states that 

operators may run a CBL and/or other diagnostic tools to determine the adequacy of the cement 

integrity and that the cement reached the desired height. 

 

57 Ibid, p. 8.

58 Ibid, p. 9.

59 Ibid, p. 10.
63

The rule requires the operator to demonstrate that there is at least 200 feet of adequately bonded 

cement between the zone to be hydraulically fractured and the deepest usable water zone. When 

the operator does not circulate cement to the surface, it will most often comply with this 

requirement by running a CEL on the production casing (when the operator is conducting 

hydraulic fracturing through the production string). That process is described below. However, 

if the operator plans to conduct the fracturing operation through a production liner that is hung 

from the intermediate casing, then it must either circulate the cement behind the intermediate 

string to surface or run a CEL on the intermediate casing string. Although we believe that this 

requirement is consistent with prudent operations, the intent of the industry guidance, other state 

regulations, and conditions of approval that the BLM generally places on APDs where the 

operator uses a production liner hung from the intermediate casing, we recognize that, in some 

cases, the rule would compel the operator to run a CEL when it would not have done so 

otherwise. 

We do not have credible data on the prevalence of voluntary compliance or the prevalence of 

CEL requirements as conditions of approval, so we assume that the rule will compel new action 

for all operations in states without existing regulations requiring a CEL of the intermediate 

casing. We also recognize that, as a result of this assumption, the cost estimates will be 

overstated.

(a) Applicability of requirement = 0% in ND and CO; 2.5% in TX; 5% in other states. We 

attribute the appropriate percentages to each tribe based on geographic location (within ND, 

CO, or elsewhere). Based on field experience, we anticipate that only about 5 percent of 

wells have intermediate casing to protect usable water. 

(b) Incremental cost per requirement = $111,200. After the operator cements the intermediate 

casing, it must wait a number of hours for the cement to harden before commencing drilling 

operations. After that time, the operator will pressure test the casing, drill out, and perform a 

leak-off test. The BLM received some comments indicating that a CEL test necessitates that 

the cement harden for 72 hours. These comments do not take into consideration the time that 

the operator must wait to perform other well tests. We also note that operators generally use 

additives to speed up the hardening of cement behind intermediate casing. For the purpose of 

our analysis, we consider only the additional wait time required for the CEL, accounting for 

48 hours of additional time at a cost of $1,900 per hour. The cost for a CEL on the 

intermediate casing includes the test ($20,000) and the cost of maintaining idle drilling 

equipment on-site ($91,200). We believe that 48 hours is the upper bound of the potential 

cost. In addition, the operator could potentially avoid delays in part or entirely by running 

the CEL at some point while drilling the production casing.

CEL on Production Casing that Protects Usable Water: If the operator does not cement the 

production casing string to the surface, then the operator must run a cement evaluation log to 

demonstrate that there is at least 200 feet of adequately-bonded cement between the zone to be 

hydraulically fractured and the deepest usable water zone.

This requirement does not pose an incremental cost. API Guidance Document HF1 indicates 

that operators run a log to evaluate the quality of the cement bond on the production casing as a 
64

matter of industry practice. This is consistent with our observations of field operations. 

Colorado and North Dakota require a CBL in their regulations. Texas specifies that the operator 

must identify the top of cement (with a CBL or temperature log) if it does not cement to the 

surface. California and Wyoming may require it. In states that do not specify a requirement in 

their regulations, we would still expect the operator to run a CEL as a matter of practice.

(a) Applicability of requirement = 0%

(b) Incremental cost per requirement = $0

Corrective Action Requirement: On all casing strings where the operator cements to the 

surface, the operator must document any indications of inadequate cement (such as, but not 

limited to, lost returns, cement channeling, gas cut mud, failure of equipment, or fallback from 

the surface exceeding 10 percent of surface casing setting depth or 200 feet, whichever is less). 

If there are indications of inadequate cement, then the operator must:

 Notify the authorized officer within 24 hours of discovering the inadequate cement; 

 Submit a NOI to the authorized officer requesting approval of a plan to perform remedial 

action to achieve adequate cement. In emergencies or in situations of an immediate 

nature that may result in unnecessary delays, the operator may request oral approval 

from the authorized officer for actions to be undertaken to remediate the cement and 

follow-up with a written notice afterwards;

 Verify that the remedial action was successful with a CEL or other method approved in 

advance by the authorized officer; 

 Submit a Subsequent Report Sundry Notice for the remedial action including a signed 

certification that the operator corrected the inadequate cement job in accordance with the 

approved plan with the results from the CEL or other approved test. 

This requirement poses an administrative burden, but not an operational burden. The BLM and 

many state regulations and requirements have established protocols 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). We believe that this requirement will impose an 

administrative burden on the operator who observes indications of inadequate cementing, but not 

an operational burden. In the revised proposed rule, we had specified that the operator would 

have to run a CEL to demonstrate that the remedial action was successful, but the final rule’s 

requirement is that the operator may use a CEL or other approved test, presumably a temperature 

log, that would not result in delays. 

(a) Applicability of requirement = 3%. 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.60 We 

 

60 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).
65

use the midpoint of the range, or 3 percent, and apply it to the number of newly drilled wells 

for the activity data.

(b) Cost per response = $643. Burden includes the operator burden and the BLM burden. The 

compliance cost for the operator is estimated to be about $496 per application (calculated as 

8 hours at about $61.99 per hour). The review cost for the BLM is estimated to be about 

$147 per application (calculated as 4 hours at about $36.66 per hour).

Mechanical Integrity Test Requirement: If hydraulic fracturing through the casing is 

proposed, the operator must test the casing to not less than the maximum anticipated surface 

pressure that will be applied during the hydraulic fracturing process. If hydraulic fracturing 

through a fracturing string is proposed, then the operator must test the fracturing string to not less 

than the maximum anticipated surface pressure minus the annulus pressure applied between the 

fracturing string and the production or intermediate casing.

This requirement does not pose an incremental cost. Industry guidance and state regulations are 

consistent with this requirement. Industry guidance on hydraulic fracturing states that the 

production casing of a well should be pressure testing prior to completion. The BLM also 

reviewed state regulations in California, Colorado, Montana, New Mexico, North Dakota, 

Oklahoma, Texas, Utah, and Wyoming. From FY 2010 to FY 2013, the number of well 

completions on Federal and Indian lands in those states accounted for 99.3 percent of the total 

well completions on Federal and Indian lands nationwide. The state regulations in those states 

either require pressure tests on all casing strings or on the casing strings through which the 

completion operation will occur.

(a) Applicability of requirement = 0%

(b) Incremental cost per requirement = $0

Monitor Annulus Pressures and Reporting Requirement: During the operation, the operator 

must continuously monitor and record the annulus pressures at the bradenhead and between any 

intermediate casings and the production casing. The operator must submit a continuous record 

of all annuli pressure during the fracturing operation in the Subsequent Report Sundry Notice. If 

during any hydraulic fracturing operation any annulus pressure increases by more than 500 

pounds per square inch as compared to the pressure immediately preceding the stimulation, the 

operator must take immediate corrective action and orally notify the authorized officer as soon as 

practicable, but no later than 24 hours following the incident. Within 30 days after the hydraulic 

fracturing operations are completed, the operator must submit a report containing all details 

pertaining to the incident, including corrective actions taken, as part of a Subsequent Report 

Sundry Notice.

This requirement does not pose an incremental cost. API Guidance Document HF1 says that if 

the annular space is not cemented to the surface, then operators should monitor pressures in the 

annulus between the production casing and the intermediate casing. “Pressure is normally 

measured at the pump and in the pipe that connects the pump to the wellhead. If the annulus 

between the production casing and the intermediate casing has not been cemented to the surface, 

the pressure in the annular space should be monitored and controlled. Pressure behavior 
66

throughout the hydraulic fracture treatment should be monitored so that any unexplained 

deviation from the pretreatment design can be immediately detected and analyzed before 

operations continue...Unexpected or unusual pressure behavior during the hydraulic fracturing 

process could indicate some type of problem.”61 Based on this information and our observations 

of field operations, we believe that operators monitor annulus pressures during hydraulic 

fracturing operations as a matter of practice and can easily provide this information to the 

authorized officer after to conducting hydraulic fracturing. The administrative burden of 

providing this information to the BLM is contained in the post-fracturing reporting requirement.

(a) Applicability of requirement = 0%

(b) Incremental cost per requirement = $0

Storage Tank Requirement: The operator must manage recovered fluid in “rigid enclosed, 

covered, or netted and screened above-ground tanks.” The tanks may be vented, unless Federal 

law, or state regulations (on Federal lands) or tribal regulations (on Indian lands) require vapor 

recovery or closed-loop systems. The tanks are also limited in size to 500 bbl of capacity or less. 

Under certain circumstances, the operator may seek approval to use a lined pit equipped with a 

leak detection system.

This is a new requirement and could pose an incremental burden to the operator depending on 

the size and specifics of the operation, and whether the management of recovered fluids in tanks 

is already required by the state or tribe. Although API Guidance Document HF2 does not 

specify the use of rigid above-ground tanks to manage recovered fluids from hydraulic fracturing 

operations, our observations of field operations indicate that the use of rigid above-ground tanks 

for receiving recovered fluids is a common but not universal practice, regardless of the state’s 

requirements. These tanks are commonly referred to as “frac tanks,” constructed of steel, and 

have a holding capacity of up to 21,000 gallons, or 500 bbl, of fluid. The tanks are generally 

limited to that capacity or size due to their transportability on surface roads to and from a well 

site. Enclosed tanks are generally provided with anti-burst air vents to vent pressurized gas to 

prevent safety hazards, or they may be connected to a system that collects the pressurized gas for 

sale or combustion. Some tanks of the same size specifications, steel construction, and rigidity 

may have open tops that allow the operator to more easily inspect the flowback visually, pump 

out fluids, and vacuum out the proppants. 

The rule prohibits the use of above-ground semi-rigid tanks for managing recovered fluids. 

These tanks are “semi-rigid,” because they are constructed of steel sections and assembled onsite, and they can hold larger volumes of fluid, up to 40,000 bbl. These tanks are rarely used for 

managing flowback directly and are more often used for holding fresh water before the hydraulic 

fracturing operation and sometimes for holding water after it has been separated and treated after 

hydraulic fracturing operations.

The use of rigid above-ground tanks to manage recovered fluids tends to vary by operator and 

the regions in which they operate. These tanks are particularly prevalent in the Eastern U.S. and 

 

61 API Guidance Document HF1, p. 21.
67

are being incorporated into model standards for shale development.62 Among western states 

where development on Federal and Indian lands are most prevalent, New Mexico and Texas 

generally require storage tanks, but allow operators to apply for permits to use pits. Colorado 

requires storage tanks in Surface Water Supply Areas63 in its regulations, but the COGCC 

implemented a policy in June 2014 that prohibits the use of large volume semi-rigid tanks to 

manage flowback. 

Our observations of field operations in Colorado indicate that operators are predominantly using 

rigid steel tanks to manage flowback. In the Grand Junction field office (FO), we have observed

vented tanks and "closed pits" (two liners below the fluid and one on top of the fluid). In the 

Royal Gorge FO, all of the operations witnessed in the past year used rigid steel tanks for 

flowback. Water is then hauled to disposal facilities or disposal wells. These tanks are not totally 

closed systems, but allow for only very minor venting off. In Colorado, operators are required to 

run flowback fluids through a separator which captures the majority of the oil and gas in the 

water. In the Colorado River Valley FO, the flowback goes through separators with the gas 

going to sales, the oil to the oil tanks with pressure/vacuum seals, and the water to water tanks 

with pressure/vacuum seals. As mentioned before, the COGCC prohibits the use of largevolume open-topped semi-rigid tanks for managing flowback. It only allows these semi-rigid 

tanks to hold fresh water.

Our observations of field operations in Montana and North Dakota indicate that operators 

generally use open-topped rigid steel tanks during the initial flow back operations. These tanks 

allow the operator to use pumps to remove the fluid so that it may then vacuum out the proppant. 

Operators may use larger volume open-topped semi-rigid tanks to store freshwater to be used in 

the fracturing operations, but we have not observed operations recently where the operator used 

these types of tanks to manage recovered fluids. A previous hydraulic fracturing operation in 

2010 used large semi-rigid tanks to manage flowback for the first 3 wells out of 30. After those 

first wells, the operator realized that it was easier to return the fluid to steel rigid tanks and haul 

them to a disposal well. For shallow vertical gas wells in Montana, we have observed the use of 

earthen lined pits that were not equipped with leak detection systems. It has been our experience 

that pits are not permitted in North Dakota.

Our observations of field operations in Utah indicate that, for large fracturing operations, 

operators run flowback through a 4-phase separation unit that is provided by the service 

companies to capture and separate the solids and fluids with the flowback. The solids are 

captured and the fluids go to the production facilities. The larger open tanks are only used to 

further treat and clean the water after it has gone through the separation process for recycling and 

they are not used during the hydraulic fracture process. The 4-phase separators are required 

when the flowback rate is on the order of 300 to 400 barrels per hour, which is typical of high 

volume multistage jobs. Smaller 2-phase units are used for the vertical wells where the jobs are 

smaller, with flow back rates of up to 100 barrels per hour. The fluid is still captured in the 

 

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

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

63 A map of designated Surface Water Supply Areas, accessed on May 27, 2014, is available at 

http://cogcc.state.co.us/rulemaking/FinalDraftRules/CDPHE317B_Map.pdf. 
68

production units where it is separated and then either sent for recycling or disposal. The 

production units are sealed where the water is not exposed to the atmosphere. 

Our observations of field operations in Wyoming vary by the FO. In the Rawlins FO, the use of 

rigid steel tanks and lined pits are most common and the use of large semi-rigid tanks is rare. 

Rigid steels tanks are used in both closed-loop and open reserve/completion pit 

completions. Venting is allowed from the tanks by either open top or valves. Some operators 

direct the vapors to a flare pit. The use of large volume semi-rigid open-topped tanks is rare. 

We have observed occasional use of these tanks on private or state lands, but we are not aware of 

any use on Federal lands. We have observed operations where the operator stores the completion 

water in tanks, conducts the hydraulic fracturing, and returns the flowback to a lined reserve pit 

with an associated flare pit. Another variation is the use of a single lined pit to store fresh water 

before the hydraulic fracturing and the flowback after the hydraulic fracturing. Any produced 

hydrocarbons are run through a separator and sold or in most cases flared in a flare pit. These 

pits are lined, but do not have a leak detection system. In the Rock Springs FO, operators use 

rigid steel tanks for water storage and primarily return flowback using a closed-loop system. If 

they do not use a closed-loop system, then they run the flow back into a pit. Recently, in 2014, 

we have observed fewer well completions, with about 4-5 fracturing stages per well and a fluid 

volume of about 595 bbl per stage.

Our observations of field operations in California indicate that operators use rigid steel tanks that 

are part of a closed-loop system. According to one operator, it produces the flowback straight 

into the production system, because it is such a small amount relative to the field production and

there is no benefit to separating it out (or no harm to leaving it in). Some operators use large 

volume semi-rigid tanks to store fresh water prior to the hydraulic fracturing, but we are not 

aware of operators using these tanks for flowback. In general, we are not aware of pits being 

used for flowback. The typical job in California may use about 3,930 bbl of water, and only a 

small portion of that is recovered. Meaning, only a small number of rigid tanks would be 

required to handle the recovered fluids.

Our observations of field operations in the states mentioned lend evidence to the widespread use 

of steel rigid tanks to manage recovered fluids from hydraulic fracturing operations in those 

states. Further, by examining the volume of recovered fluids expected, and the relative costs of 

using rigid above-ground storage tanks versus a pit for these volumes, we believe that the use of 

these tanks is most often less costly for operations on Federal and Indian lands.

In the revised proposed rule, the BLM solicited comment concerning the incremental costs of a 

requirement to manage recovered fluids with tanks instead of lined pits. 

One commenter supported the broad use of rigid steel tanks, but recommended that the BLM not 

require closed-loop systems, citing concerns about costs, the pressurization of gas, ability to 

make visual inspections of the fluid, the advantage of maintaining flexibility depending on the 

operations or conditions, and the EPA’s regulations covering emissions from storage tanks. It 

also supported the option of potentially using larger volume semi-rigid (or “atmospheric”) tanks 
69

and lined impoundments (or pits), both with secondary containment and leak detection systems,

for large volume hydraulic fracturing operations.64

The commenter estimated the costs of rigid steel tanks, semi-rigid tanks, and pits over a 5-year 

period (using a present discounted value approach and a 10 percent discount rate) for multiple 

operations, with a cumulative total capacity of about 250,000 bbls. It estimated the costs of an 

engineered impoundment to be $2.3 million, semi-rigid tanks to be $2.42 million, and steel tanks 

to be $23 million, all over a 5-year period (see Table 5A). 

Table 5A: Commenter Cost Estimates for Managing Recovered Fluids

Engineered 

Impoundment

Semi-Rigid Steel 

Tanks Steel Tanks

Number of 

impoundments or 

tanks

1 6 500

Impoundment or tank 

capacity (bbls) 250,000 40,000 500

Total capacity (bbls) 250,000 240,000 250,000

Initial construction or 

set up-take down cost $2,970,000 $51,000 x 6 = $306,000 n/a

Annual operating or 

Rental Cost $20,000

$132,000 x 6 = 

$792,000

(assumes $11,000 

monthly rental fee)

$16,425 x 500 = 

$8,212,500

(assumes $45 daily 

rental fee)

5-Year net present 

value (NPV) (at 10%) $2,300,000 $2,420,000 $23,000,000

In reviewing these data, it would be inappropriate to conclude simply that using steel tanks 

would cost 10 times more than a pit. The commenter did not specify the number of hydraulic 

fracturing operations that a pit, or deployment of semi-rigid tanks or rigid steel tanks, might 

service over the 5-year period. We expect that while each method could service the same 

number of hydraulic fracturing operations at the same general location, pits are limited to a 

single geographic location and tanks are portable and can be deployed at different geographic 

locations over the 5-year period; thereby servicing a larger number of operations and reducing 

the per-operation cost of using tanks over that time period. 

We also note that the transportability and severability of 500 steel tanks allow an operator to 

service multiple operations in different locations at the same time. For example, 500 steel tanks 

could service 5 large operations (of 100 steel tanks each) concurrently in different geographic 

locations. 

 

64 The comment letter from ConocoPhillips, dated August 22, 2013, is available in the rulemaking docket at 

www.regulations.gov.
70

We received other comments about the incremental costs of requiring storage tanks, but the 

comments were less detailed than those described above. A commenter's analysis suggested a 

tank requirement would pose an incremental cost of $5,500 per operation or $19.6 million for the 

industry per year. Another commenter suggested that an open pit costs $447,000 and a closedloop system costs $267,000 (an $180,000 cost advantage). 

We did not receive comments on the prevalence of voluntary compliance among operators or 

across operations, though a commenter supported the broad use of storage tanks and the potential 

option to use larger tanks or pits. We would generally expect that an operator would choose to 

use steel tanks voluntarily (when otherwise not compelled to do so by regulation, condition of

approval, environmental consideration, or company practice) in situations where tanks would 

cost the same as or less than pits, and this may be largely dependent on the volume of recovered 

fluids expected.

The amount of water used to hydraulically fracture a well and the amount of fluid recovered 

from the operations vary depending on the formation and the operation itself. We examined data 

extracted from FracFocus65 for wells completed in 2013, shown in Figure 3. The data show that 

the average volume of water used for the hydraulic fracturing operations was 60,279 bbl (or 

more than 2.5 million gallons). We used the number of well completions on Federal and Indian 

lands from FY 2010 – FY 2013 to develop a weighted average for hydraulic fracturing 

operations on Federal and Indian lands. Shown in Figure 3, we would expect the average 

volume of water used for hydraulic fracturing operations on Federal and Indian lands to be

24,385 bbl (or more than 1 million gallons). 

The data extracted from FracFocus do not show the amount of fluid recovered from the 

operations. The EPA indicates that this amount may range widely from 15% to 80% of the 

original amount injected, depending on the site.66 Halliburton lists ranges for fluid recovery for 

popular producing areas that are more modest, as follows:67

 Bakken: 15 – 40%

 Eagle Ford: < 15%

 Permian Basin: 20 – 40%

 Marcellus: 10 – 40%

 Denver-Julesburg: 15 – 30%

We also provide the range of volumes expected to be recovered from hydraulic fracturing 

operations in Figure 3, which we estimate would range from 3,658 bbls (15% of the volume 

injected) to 9,754 bbls (40% of the volume injected) on average based upon data extracted from 

FracFocus.

 

65 Skytruth.org, “2013 Reports Data,” accessed on November 20, 2014.

66 EPA website, “Hydraulic Fracturing Research Study,” accessed on November 20, 2014 at 

http://www.epa.gov/ogwdw000/uic/pdfs/hfresearchstudyfs.pdf. 

67 Halliburton, “Produced and Flowback Water Recycling and Reuse: Economics, Limitations, and Technology,” 

accessed on November 25, 2014 at 

http://www.halliburton.com/public/multichem/contents/Papers_and_Articles/web/Feb-2014-Oil-Gas-FacilitiesArticle.pdf. 
71

Figure 3: Average Water Used in Hydraulic Fracturing Operations, 2013, and Estimated 

Recovered Fluids

State

Average Volume 

of Water Used 

(bbl) (Data 

extracted from

FracFocus)

Range of Recovered Fluids (bbl)

Low (15%) High (40%)

Alaska 2,343 351 937

Arkansas 203,648 30,547 81,459

California 2,375 356 950

Colorado 52,013 7,802 20,805

Kansas 35,373 5,306 14,149

Louisiana 89,333 13,400 35,733

Mississippi 111,500 16,725 44,600

Montana 50,058 7,509 20,023

New Mexico 19,110 2,866 7,644

North Dakota 56,535 8,480 22,614

Ohio 107,855 16,178 43,142

Oklahoma 78,600 11,790 31,440

Pennsylvania 128,122 19,218 51,249

South Dakota 61,227 9,184 24,491

Texas 61,412 9,212 24,565

Utah 8,885 1,333 3,554

Virginia 706 106 282

Washington 23,264 3,490 9,306

West Virginia 143,873 21,581 57,549

Wyoming 17,397 2,610 6,959

Weighted Average (based on the

operations in the dataset)

60,278 9,042 24,111

Weighted Average (based on average 

volume of the operations by state and 

the distribution of operations on Federal 

and Indian lands)

24,385 3,658 9,754

Note: There were no data in the FracFocus extraction for Alabama and Nevada which had a total of only 7 well completions 

from FY 2010 – FY 2013. 

We contacted service providers of tanks used for the management of fluids from hydraulic 

fracturing operations to better examine the per-operation incremental costs of using rigid steel 

tanks instead of a pit. We estimated the baseline cost of constructing and operating a pit based 

on the first commenter’s data. We estimated the 5-Year NPV (using a discount rate of 7%) of a 

pit to be about $2,460,000, generating an annualized cost of about $492,000 and, finally, a peroperation cost of about $98,400, assuming a pit could service 5 operations per year and 25 

operations over a 5-year period.

68

 Using AFMSS well completion data from January 2008 to 

December 2012, we found that operators completed an average of 5.067 wells in a case. 

 

68 We attempted to replicate the commenter’s derivation of the 5-Year NPV (at 10%) for the engineered 

impoundment in order to estimate an annualized value for a pit with a 7% discount rate. We roughly generated the 
72

Given the assumptions, and for a job lasting 14 days, the point at which the cost of using tanks 

and the cost of using a pit are roughly equal is when the job capacity is 32,368 bbl. Meaning, 

steel tanks would cost less for operations where the volume of recovered fluids is less than 

32,368 bbl and pits would cost less for operations where the volume of recovered fluids is 

greater than 32,368 bbl. For a job lasting 21 days, the point at which the cost of using tanks and 

the cost of using a pit are roughly equal is when the job capacity is 27,333 bbl. 

We derived that threshold using the following progression:

(1) Per-operation cost of pit = Cost of steel tanks for an operation

(2) Per-operation cost of pit = [ Cost of tank transport to and from site + Cost of tank rental ]

(3) Per-operation cost of pit = 

2 * [(Cost of tank transport $/hr/tank) * (hours) * (Job capacity/tank capacity)] 

+ [(Cost of rental $/day/tank) * (days) * (Job capacity/tank capacity)]

(4) [Per-operation cost of pit / 3.04 ] = Job capacity bbl; when the job duration is 14 days; or

[Per-operation cost of pit / 3.60 ] = Job capacity bbl; when the job duration is 21 days

(5) Job capacity bbl = 32,368; when the job duration is 14 days; or

Job capacity bbl = 27,333; when the job duration is 21 days

In Table 5B, we provide the general engineering costs for rigid steel tanks provided by service 

companies and then we calculate per-operation job costs based on a number of potential job 

capacities. In addition, for each job capacity, we estimate the cost of the tank deployment for 

that operation, and the incremental cost of per operation when employed instead of a pit. Other 

assumptions include that the transportation to and from the site for steel tanks will take 4 hours, 

and that the rental period is either 14 days or 21 days. 

According to the available information, rigid steel tanks are likely to be less costly than pits on 

smaller and medium volume jobs lasting 14 days (e.g., $68,000 and $7,200 advantage for jobs 

with a capacities of 10,000 and 30,000 bbl, respectively) and likely to be more costly than pits 

for higher volume jobs (e.g., $53,600 disadvantage for jobs with a capacity of 50,000 bbl). For 

jobs lasting 21 days, rigid steel tanks are likely to be less costly than pits on jobs up to the job 

capacity threshold described above. This concept is illustrated in Table 5B. 

 

commenter’s value by assigning one-third of the capital costs to initial construction (year 0) and two-thirds of the 

capital costs to the take down costs (year 5). 
73

Table 5B: General Engineering Costs For Steel Rigid Tanks Per-Operation and 

Incremental Costs, by Job Capacity

Engineering Costs

Job duration (days) 14 21

Tank capacity (bbl) 500

Transportation to site ($/hr/tank) $120

Rental ($/day/tank) $40

Transportation from site ($/hr/tank) $120

Job Capacity (10,000 bbl)

Tanks required 20 20

Costs per operation $30,400 $36,000

Incremental cost instead of a pit -$68,000 -$62,400

Job Capacity (30,000 bbl)

Tanks required 60 60

Costs per operation $91,200 $108,000

Incremental cost instead of a pit -$7,200 $9,600

Job Capacity (50,000 bbl)

Tanks required 100 100

Costs per operation $152,000 $180,000

Incremental cost instead of a pit $53,600 $81,600

To estimate voluntary compliance, we looked at the percent of operations (in the data extracted 

from FracFocus) where the job capacity (measured as the 40% of the water used) was less than 

the thresholds of 32,368 bbl and 27,333 bbl. 

Where the job capacity exceeded the threshold, we assumed that the operators would not have 

voluntarily used storage tanks. We then calculated the average job capacity for operations above 

this threshold based on the distribution of operations on Federal and Indian lands. We estimate 

that the average job capacity for operations exceeding the thresholds is either 47,575 bbl or

55,631 bbl. See Table 5C. We note again that operators may choose to use steel tanks 

irrespective of costs, for example in adherence to condition of approvals, environmental 

considerations, company practice, etc.
74

Table 5C: Estimated Voluntary Compliance of a Steel Tank Requirement and the Average 

Volume of Recovered Fluids for Operations Where the Operator is Not Expected to 

Voluntarily Comply 

State

Job Duration of 14 Days Job Duration of 21 Days

Estimated 

Voluntary 

Compliance 

(%)

Average 

volume of 

recovered 

fluids for 

operations 

exceeding the 

threshold (40% 

recovery rate)

Estimated 

Voluntary 

Compliance 

(%)

Average 

volume of 

recovered 

fluids for 

operations 

exceeding the 

threshold (40% 

recovery rate)

Alaska 100.0% 0 100.0% 0

Arkansas 2.9% 83,926 2.9% 83,926

California 100.0% 0 100.0% 0

Colorado 84.7% 58,980 71.7% 45,616

Kansas 100.0% 0 95.6% 27,597

Louisiana 49.3% 53,781 30.4% 47,650

Mississippi 66.7% 130,775 66.7% 130,775

Montana 91.8% 37,257 79.6% 32,260

New Mexico 96.7% 79,352 96.1% 72,616

North Dakota 86.8% 50,455 75.1% 40,842

Ohio 0.0% 43,142 0.0% 43,142

Oklahoma 68.5% 63,084 61.9% 57,248

Pennsylvania 12.4% 55,208 7.1% 53,780

South Dakota 100.0% 0 100.0% 0

Texas 68.2% 57,699 64.3% 54,663

Utah 100.0% 0 100.0% 0

Virginia 100.0% 0 100.0% 0

Washington 100.0% 0 100.0% 0

West Virginia 3.3% 58,566 0.0% 57,549

Wyoming 93.3% 39,880 92.3% 38,629

Weighted Average (based 

on distribution of 

operations in FracFocus)

70.3% 57,283 65.4% 53,398

Weighted Average (based 

on distribution of 

operations on Federal 

and Indian lands)

93.5% 55,631 90.6% 47,757
75

Based on that average job capacity, we then calculated an average incremental cost of using 

tanks instead of a pit for only those operations where we do not estimate that the operator will 

voluntarily comply. Assuming job durations lasting 14 days, we estimate the average 

incremental cost to be $71,840 per operation that exceeds the threshold of 32,368 bbl. Assuming 

job durations last 21 days, we estimate the average incremental cost to be $74,400 per operation 

that exceeds the threshold of 27,333 bbl. Due to the variability of job durations across the U.S., 

we use the average incremental cost of $74,400 per operation as a basis for the cost estimates, 

recognizing that this is likely to both overestimate and constrain the potential costs.

With respect to the applicability of the requirement, we estimate that the rule will have no impact 

in states with existing requirements for use of tanks. We also assume that the rule will have no

impact where operators are expected to voluntarily comply with the use of tanks regardless of the 

rule (the rates of assumed voluntary compliance are in Table 5C). We assume that for all other 

states, the rule will compel action on 100% of the operations, even though we expect that 

operators are already in compliance with the rule as a matter of voluntary practice. 

(a) Applicability of requirement = 0% in NM and TX based on state regulations; 0% in AK, CA, 

SD, UT, based on estimated voluntary compliance; 97.1% in AR, 28.3% in CO, 4.4% in KS, 

69.6% in LA, 33.3% in MS, 20.4% in MT, 24.9% in ND, 100% in OH, 38.1% in OK, 92.9% 

in PA, and 7.7% in WY, based on estimated voluntary compliance; 100% in AL and NV, 

based on lack of validating data. We attribute the appropriate percentages to each tribe based 

on geographic location. 

(b) Incremental cost per operation = $74,400. This incremental cost is only for those operations 

where the use of storage tanks is not required by state regulations and where the operator is 

not expected to use storage tanks voluntarily. Operations that are most likely to incur this 

cost are in states where 0.8% of all oil and gas activity on public lands occurs (further 

discussion in the Section 4.1). Incremental average costs across all operations on public and 

Indian lands are $5,544 (see Table 10 in Section 4.4).

Under the rule, the operator may apply for a permit to use a lined pit that is equipped with a leak 

detection system. While Onshore Order 7 requires leak detection systems for produced water 

disposal pits, which may be used on a long-term basis, there has been no requirement for leak 

detection systems on temporary pits until now. According to analogous EPA data, the cost of 

equipping a pit with a leak detection system might range from $2 to $9 per foot, depending on 

the sophistication of the system (EPA 2012, p. vii). Assuming 2,000 feet of piping and that a 

centralized pit might service 5 operations, the per-operation cost of equipping a centralized pit 

with a leak detection system might be between $800 and $3,600. Additional cost information for 

leak detection systems is available in the EPA Notice of Proposed Rulemaking for Liners and 

Leak Detection for Hazardous Waste and Land Disposal Units.69 The notice suggests that costs 

of a leak detection system would be about $6,100 for a half-acre pit and $6,520 for an acre pit.70 

Again, that cost could be spread across multiple hydraulic fracturing operations and, assuming 

the pit services 5 completions, the per-operation cost might be $1,200 to $1,300. However, 

according to the specifications listed in Onshore Order 7, the engineers also believe that the per-

 

69 52 FR 20267, May 29, 1987.

70 Adjusted from 1987 dollars to 2014 dollars.
76

operation costs of including a leak detection system could be higher and generally comparable to 

using storage tanks. 

The BLM examined an alternative approach to the final rule. That alternative would have 

required the operator to manage recovered fluids in a lined pit, at a minimum. The requirement 

to manage recovered fluids 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. 

We examined regulations in 9 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 use lined pits or tanks to ensure the protection of groundwater. 

One exception, California, does not appear to have a state-wide minimum requirement for lined 

pits, but such requirements may be contained within rules specific to particular fields within the 

state. Further, according to Resources for the Future (RFF), Alabama, Arkansas, Kansas, 

Louisiana, Mississippi, Pennsylvania, and South Dakota also have existing pit liner 

requirements.71 Considering the low level of oil and gas development on Federal lands in other

states, the impact of this provision is likely to be very small. We do not have data on the pit liner 

requirements on Indian lands or the voluntary use of lined pits in general, as is recommended as

a minimum standard by industry guidance.72 We estimated the unit cost of lining a pit to be 

$6,000, 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.

(a) Applicability of requirement (alternative) = 0% in AL, AR, CO, KS, LA, MS, MT, ND, NM, 

OK, PA, SD, TX, UT, WY; 20% in CA; 50% in AK, NV, OH, and Indian lands.

(b) Incremental cost per operation (alternative) = $6,000

Post-Fracturing Reporting Requirement: The operator must submit information to the BLM 

after the hydraulic fracturing operation in a Subsequent Report (SR) Sundry. The operator must 

disclose the chemicals used to the BLM, and it may use FracFocus for that disclosure. The 

operator may only withhold information from the disclosure if that information is a trade secret. 

If the operator withholds information that is a trade secret, then the operator must submit an 

affidavit that substantiates its claim. If the operator relies on facts supplied by another entity, 

then the operator must include an affidavit from a responsible official of that entity that 

substantiates the claim that the information is a trade secret. 

This is a new requirement and poses an incremental burden to the operator and the BLM to 

review. The information required in the application should be all readily available or known to 

the operator or to its contractor. The information should not require any additional information 

gathering. Unlike the application, which may be a master hydraulic fracturing plan for a group 

of wells, the operator will submit a unique SR sundry for each operation. The chemical 

disclosure and potential affidavit submission are included in the post-fracture report. Regarding 

the chemical disclosure, the operator may post to FracFocus or submit the information directly to 

 

71 The RFF findings cited are available on its website under flowback/wastewater storage and disposal, accessed on 

May 27, 2014: http://www.rff.org/centers/energy_economics_and_policy/Pages/Shale_Maps.aspx

72 API, HF2
77

the BLM. Incidentally, the disclosure requirement only poses an incremental burden to the 

operator in states that do not already require disclosure to FracFocus. We note that Colorado, 

Montana, North Dakota, Oklahoma, Texas, and Utah require disclosure to FracFocus already and 

so the Federal requirement would not pose an incremental burden to those operations. If the 

operator withholds information that is a trade secret, the rule might require two affidavits per 

claim for confidentiality, depending on the circumstances.

(a) Applicability of requirement = 100% of operations.

(b) Cost per requirement = $723. Burden includes the operator burden ($558 per SR Sundry) 

and the BLM burden ($165 per SR Sundry). We estimate that the operator will require 9 

hours at about $61.99 per hour to comply with the SR Sundry and that the BLM will require 

4.5 hours at about $36.66 per hour to review the SR Sundry. The bases for these estimates are 

explained in the supporting statement for the Paperwork Reduction Act.

Variance Requests: The operator may submit a variance for BLM’s approval.

Operators taking advantage of this provision will incur an incremental administrative cost. 

Previously, we estimated that we might receive variances on 10% of the applications, primarily 

because of previously proposed requirement to run a CEL on the surface casing and the type well 

provision. Since the final rule does not contain those provisions, we believe that we might

receive fewer variance requests. However, there is still the potential that operators will request a 

variance (or permit) for the storage tank requirement or for a CEL on the intermediate casing 

(e.g., the operator may request to use a temperature log or other test).

(a) Applicability of requirement = 10% of operations. 

(b) Cost per request = $643. Burden includes the operator burden and the BLM burden. The 

compliance cost for the operator is estimated to be about $496 per application (calculated as 

8 hours at about $61.99 per hour).73 The review cost for the BLM is estimated to be about 

$147 per application (calculated as 4 hours at about $36.66 per hour).

3.3 Benefits Framework

The potential benefits of the rule are more challenging to monetize than the potential costs;

however, the rule will reduce the risks associated with hydraulic fracturing operations on Federal 

and Indian lands. The final rule includes operational requirements (regarding casing and 

cementing programs and pressure testing prior to completion operations and monitoring annulus 

pressures during completion operations). The majority of these requirements are consistent with 

voluntary industry guidance and some are required by state regulations, which are highly 

variable from state to state. However, this rule will make these best practices mandatory on all 

Federal and Indian lands, and increase the assurance that operators conduct hydraulic fracturing 

in an environmentally sound and safe manner. 

 

73 Note, though, that operators would presumably expect cost savings from implementing a variance that would 

exceed the costs of applying for a variance. Thus the net cost of the operator-specific variance provision could be 

zero, or negative (i.e., a net benefit for operators).
78

The final rule also includes fluid management requirements mandating the use of rigid aboveground storage tanks to manage recovered fluids that exceed industry guidance (although reflect 

the voluntary practices of some operators) and are consistent with regulations in Texas and New 

Mexico, but exceed those of other states. 

The use of storage tanks in lieu of pits would reduce the potential risk to surface and 

groundwater resources. We expect that this rule, which incorporates many of the best practices 

currently used by companies to manage recovered fluid, will provide environmental benefits and 

provide the best possible avoidance of surface and groundwater spills and contamination. 

Compared to pits, tanks better isolate recovered fluids from contamination by surface sediments 

and allow for visual inspection to ensure that no leaks are occurring.

The tank requirement also specifies the use of “enclosed” or “covered” tanks where the operator 

may release any pressurized gas through a relief valve (unless another Federal, state, or tribal law 

or requirement requires a closed-loop system). Although the rule allows for the release of 

pressure, the rule should provide some benefit of limiting air emissions, since an enclosed tank

may lessen evaporation and provide enhanced protection to on-site workers. 

In addition, the rule will provide for increased public access to detailed information about the 

hydraulic fracturing operations taking place, including the chemicals used during the operations 

and the location and nature of the operation. These disclosures will increase public awareness

and understanding of these operations. 

The primary challenge in monetizing benefits lies in the quantification of a baseline risk 

associated with specific operating practices and in the measurement of the change in that risk 

that we can attribute to the rule’s requirements. For example, the risk of spills associated with 

the use of pits versus the risk of spills associated with the use of storage tanks is unknown, 

though it is generally recognized that tanks carry less risk onsite. In an initial analysis for the 

proposed rule, we attempted to value the reduction in risk, but we do not feel that the available 

information represented modern hydraulic fracturing operations nor were we able to distinguish 

between the risks posed by wells that were hydraulically fractured and wells with conventional 

completion techniques.

Operators are required to notify the BLM when undesirable events occur, but there are 

limitations in using the BLM data on undesirable events for this analysis. Undesirable events 

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

hydraulic fracturing flowback fluids, or other substances. Undesirable events would also include 

“frack hits,” which are unplanned surges of pressurized fluids into other wells. These events 

have the potential to adversely affect public lands, Indian lands, and other important resources. 

There are several limitations in using these data. First, the data do not specify whether the 

undesirable events occur in conjunction with or as a result of hydraulic fracturing operations. 

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 
79

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

risk across all operations.

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

about the true value or extent of any potential 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.

Also, the valuation of the damage may take many and highly variable forms. For example, in 

addition to the cost of environmental and potential public health damage, an undesirable incident 

occurring during hydraulic fracturing might require costly 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, in addition to the costs of 

environmental and health damage, the operator would lose revenue and society would not benefit 

from the produced resources. 

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.74 The fracture path of the first horizontal well 

intercepted a second vertical 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. 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. The information the operator will provide with its APD or NOI Sundry will help 

the BLM determine that the confining zone is adequate in protecting against these type of 

occurrences.

This “frack hit” 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, although it is also

true that there may be some residual contamination even after remediation, which might have 

lingering impacts, e.g., to the ecosystem.

 

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

NMNM0631.
80

Aside from the environmental damage, there were several economic impacts, including the 

shutting-in of the impacted wells for a period of time, wellbore damage to the second wells, and 

unrecovered resources. In other scenarios, entire fracturing stages may be lost or forgone.

Since relative risk is unknown, we provide a qualitative discussion of benefits. Field experience 

tells us that the remediation of a minor incident, such as the surface remediation after a minor 

spill, might cost about $15,000 and range upwards. Remediation efforts of larger spills are much 

more complicated and can reach the hundreds of thousands of dollars or more. The remediation 

of a major incident will likely be more complex. As with the example incident, there were 

surface impacts, possible subsurface impacts to multiple wells, and potentially stranded 

resources (from lost fracturing stages of permanent plugging of wells). The Federal Remediation 

Technologies Roundtable (FRTR) makes a number of case studies available on its website

(though none are hydraulic fracturing incidents) concerning contamination to aquifers where the 

remediation costs may be $1 million.

3.4 Discounted Present Value

There is a time dimension to estimates of potential costs and benefits. While the incremental 

costs of the rule are likely to occur within a comparatively short period of time, the incremental 

benefits will continue into the future. The further in the future that the benefits and costs are 

expected to occur, the smaller the present value associated with the stream of costs and benefits. 

For this analysis, we expect that the potential incremental costs posed to an operation will occur 

within a short timeframe, starting generally with the APD submission and ending with the 

Subsequent Report Sundry. As such, we generally use undiscounted costs for the requirements. 

However, in order to determine the incremental cost of the storage tank requirement, we adjusted 

the 5-year data provided by a commenter to annualize the costs of constructing and operating a 

pit based on the net present value of costs using a 7 percent discount rate.

3.5 Uncertainty

The costs and benefits provided in this analysis are indeed estimates and come with uncertainty. 

Generally, the primary sources of uncertainty are:

 Number of hydraulic fracturing operations on Federal and Indian lands occurring 

in the future. Section 2.7 describes the method we used to estimate operations that will 

occur in the future. We also consider an upper bound estimate which should constrain 

the costs.

 Delays and costs associated with the CEL on the intermediate casing. Sources of 

uncertainty are: (1) The prevalence by which the operator will run a log on the 

intermediate casing as a matter of practice; and (2) The ways in which operators may run 

logs on the intermediate casing while avoiding delays. 

 Storage tank costs. We estimated voluntary compliance based on the average volume of 

recovered fluids and a number of cost assumptions, including the per-operation cost of a 

pit. In some areas, field observations indicate that the use of storage tanks is higher than 
81

the estimated voluntary compliance. As such, we believe the compliance costs of this 

requirement are still likely to be overestimated.

 Benefits of specific provisions. We are unable to estimate the incremental benefits of 

the rule because we are unable to ascribe incremental benefits to the particular provisions 

of the rule. That said, the rule’s provisions are consistent with best management practices 

of the industry at large and of several firms within the industry. 
82

4. Results

4.1 Costs of the Rule

We estimate that the rule will impact 2,814 hydraulic fracturing operations per year in the nearterm on Federal and Indian lands. We estimate that the incremental cost of the rule could reach

about $32 million per year. These estimates are based on expectations about the future well 

completions on Federal and Indian lands. In order to meet a $100 million per year threshold, we 

estimate that the number of hydraulic fracturing operations on Federal and Indian lands would 

have to be about 3.11 times higher than we anticipate, or about 8,765 operations per year.

The estimated per-operation compliance costs of about $11,400 represent about 0.13 to 0.21

percent of the cost of drilling a well. The compliance costs, shown in Table 10 in Section 4.4, 

were developed by dividing the total costs of the rule by the number of hydraulic fracturing 

operations expected to occur, per year. Because we believe that operators would have 

undertaken some of the rule’s requirements voluntarily or as a result of state requirements, we 

expect that some of the compliance costs will be borne by a relatively small number of 

operations. This is particularly the case with respect to the requirement to use rigid aboveground tanks, which we estimate to be less costly than lined pits for operations with recovered 

fluids below a certain volume. In those cases where fluid volumes exceed a certain threshold, we 

estimate that the compliance with the storage tank requirement could cost an operator $74,400 

(representing approximately 0.8 to 1.4 percent of the cost of drilling a well). Through our 

analysis we estimate that this is only a small subset of total operations. These operations are 

those where the volumes of recovered fluids are expected to be very high and typically occur in 

states (Arkansas, Louisiana, Mississippi, Ohio, Oklahoma, and Pennsylvania) which represent

only about 0.8% of estimated hydraulic fracturing activities on Federal and Indian land (from FY 

2010 to FY 2013).

The costs of drilling a well may vary by reservoir or formation, depth and length, site-specific 

characteristics as well as operator efficiencies. The EIA suggests costs of about $5.4 million 

(EIA, January 31, 2012) which we believe may be a lower bound estimate of the costs for

drilling a well to be completed with hydraulic fracturing. The EIA figures were last updated in 

2007, were not specific to horizontal wells or hydraulically fractured wells, and included costs of 

drilling exploratory or development wells. We adjusted the EIA figures to 2015 

dollars. Meanwhile, horizontal wells drilled in the Bakken formation have been reported to cost 

$5.6 million (Investopedia 2010; cited by Investopdia from Continental Resources) and, most 

recently, between $7 -9 million per well (Oil Patch Hotline 2015; cited from various 

companies).

As discussed in Section 2.7, well completions decreased on Federal lands from FY 2012 to FY 

2013, but increased steadily on Indian lands on an annual basis since FY 2010. If we use the FY 

2012 level of activity on Federal lands as a basis for the estimate, the rule could potentially 

impact up to 3,775 hydraulic fracturing operations per year on Federal and Indian lands at an 

incremental cost of about $45 million per year. 
83

Many of the rule’s requirements are consistent with industry guidance and some are required by 

existing BLM regulations and state regulations. So to the extent that industry is already in 

voluntary compliance, the cost of several provisions may be overestimated. Where the rule’s 

requirements are consistent with industry practice or state regulations, there will not be an 

incremental cost. There are two requirements in particular that may pose relatively larger costs. 

First, the rule requires the operator to run a CEL on the intermediate casing if that casing string 

protects usable water and if the operator chooses not to cement the casing to the surface. 

Industry guidance suggests that operator may run a cement bond log on the intermediate casing. 

We believe that operators will generally run logs on the intermediate casing particularly if they 

plan to conduct hydraulic fracturing through a production liner that is hung from the intermediate 

casing, and that states or that the BLM may specify this as a condition of approval even if it is 

not in regulation. Since we do not have validating data, we have assumed that the rule would 

compel CELs in all areas, except those states that require them in regulation. As such, we expect 

that the costs associated with this requirement are overstated.

Second, the rule requires the operator to manage recovered fluids in rigid above-ground storage 

tanks. Industry guidance suggests that operators may use storage tanks or pits to manage 

recovered fluids. Some states require the use of tanks by regulation and some states have 

adopted the practice as a policy through guidance or as a standard condition of approval for 

drilling operations. Our observations of field operations indicate that operators almost always

use storage tanks, which indicates that they may be doing so voluntarily. We estimated the 

voluntary use of storage tanks in states that do not have regulations requiring their use. Still, in 

some areas, our field observations indicate that the use of storage tanks is higher than the 

estimated voluntary compliance. As such, we also expect that the costs associated with this 

requirement are overstated.

4.2 Cost Breakout According to Federal and Tribal Lands 

On Federal lands, we estimate that the final rule would impact 2,144 hydraulic fracturing 

operations per year in the near-term future and that the rule poses an incremental cost of about 

$22 million per year. The rule could potentially impact up to 3,105 operations per year on 

Federal lands at an incremental cost of about $35 million per year. Tables 7A and 7B depict the 

annual incremental costs associated with the rule’s requirements, attributed to operations on 

Federal lands within a state. It accounts for consistencies between a state’s requirements and the 

rule’s requirements. 

On Indian lands, we estimate that that the final rule would impact 670 hydraulic fracturing 

operations per year in the near-term future and that the rule poses an incremental cost of about 

$10 million per year. The estimate accounts for the steady increase in activity on Indian lands 

over the past few years. Table 8 depicts the annual incremental costs associated with the rule’s 

requirements, attributed to operations on Indian lands within a reservation or Bureau of Indian 

Affairs (BIA) agency.

75

 The highest total costs are associated with operations in the Fort 

 

75 A BIA “agency” may serve multiple tribes.
84

Berthold, Uintah and Ouray, and Jicarilla Apache reservations, due to the volume of activity 

within those reservations. 
85

Table 7A: Estimated Annual Incremental Costs Associated with Activity on Federal Lands

Federal Lands, by 

State

Number of 

operations per 

year

Application 

(Sundry)

Remedial 

Action 

Reporting 

(Sundry)

CEL on 

Intermediate 

Casing Storage Tank

Post-Fracture 

Reporting 

(Sundry)

Variance 

Requests 

(Sundry) Total Costs

ALASKA 9 $5,787 $174 $50,040 $0 $6,507 $579 $63,086

ALABAMA 1 $643 $19 $5,560 $74,400 $723 $64 $81,410

ARKANSAS 3 $1,929 $58 $16,680 $216,727 $2,169 $193 $237,756

CALIFORNIA 188 $120,884 $3,627 $1,045,280 $0 $135,924 $12,088 $1,317,803

COLORADO 59 $37,937 $1,138 $0 $1,242,257 $42,657 $3,794 $1,327,783

KANSAS 0 $0 $0 $0 $0 $0 $0 $0

LOUISIANA 2 $1,286 $39 $11,120 $103,565 $1,446 $129 $117,584

MISSISSIPPI 6 $3,858 $116 $33,360 $148,651 $4,338 $386 $190,709

MONTANA 1 $643 $19 $5,560 $15,178 $723 $64 $22,187

NORTH DAKOTA 173 $111,239 $3,337 $0 $3,204,929 $125,079 $11,124 $3,455,708

NEW MEXICO 732 $470,676 $14,120 $4,069,920 $0 $529,236 $47,068 $5,131,020

NEVADA 0 $0 $0 $0 $0 $0 $0 $0

OHIO 2 $1,286 $39 $11,120 $148,800 $1,446 $129 $162,819

OKLAHOMA 15 $9,645 $289 $83,400 $425,196 $10,845 $965 $530,340

PENNSYLVANIA 12 $7,716 $231 $66,720 $829,411 $8,676 $772 $913,526

SOUTH DAKOTA 4 $2,572 $77 $22,240 $0 $2,892 $257 $28,038

TEXAS 23 $14,789 $444 $63,940 $0 $16,629 $1,479 $97,281

UTAH 579 $372,297 $11,169 $3,219,240 $0 $418,617 $37,230 $4,058,553

WYOMING 335 $215,405 $6,462 $1,862,600 $1,919,148 $242,205 $21,541 $4,267,361

TOTAL 2,144 $1,378,592 $41,358 $10,566,780 $8,328,262 $1,550,112 $137,859 $22,002,963
86

Table 7B: Potential Upper Bound Estimate (Using FY 2012 Level of Activity) - Estimated Annual Incremental Costs Associated 

with Activity on Federal Lands

Federal Lands, by 

State

Number of 

operations per 

year

Application 

(Sundry)

Remedial 

Action 

Reporting 

(Sundry)

CEL on 

Intermediate 

Casing Storage Tank

Post-Fracture 

Reporting 

(Sundry)

Variance 

Requests 

(Sundry) Total Costs

ALASKA 1 $643 $19 $5,560 $0 $723 $64 $7,010

ALABAMA 1 $643 $19 $5,560 $74,400 $723 $64 $81,410

ARKANSAS 7 $4,501 $135 $38,920 $505,697 $5,061 $450 $554,764

CALIFORNIA 222 $142,746 $4,282 $1,234,320 $0 $160,506 $14,275 $1,556,129

COLORADO 365 $234,695 $7,041 $0 $7,685,148 $263,895 $23,470 $8,214,248

KANSAS 1 $643 $19 $5,560 $3,274 $723 $64 $10,283

LOUISIANA 4 $2,572 $77 $22,240 $207,130 $2,892 $257 $235,168

MISSISSIPPI 0 $0 $0 $0 $0 $0 $0 $0

MONTANA 15 $9,645 $289 $83,400 $227,664 $10,845 $965 $332,808

NORTH DAKOTA 127 $81,661 $2,450 $0 $2,352,751 $91,821 $8,166 $2,536,849

NEW MEXICO 956 $614,708 $18,441 $5,315,360 $0 $691,188 $61,471 $6,701,168

NEVADA 0 $0 $0 $0 $0 $0 $0 $0

OHIO 3 $1,929 $58 $16,680 $223,200 $2,169 $193 $244,229

OKLAHOMA 15 $9,645 $289 $83,400 $425,196 $10,845 $965 $530,340

PENNSYLVANIA 0 $0 $0 $0 $0 $0 $0 $0

SOUTH DAKOTA 5 $3,215 $96 $27,800 $0 $3,615 $322 $35,048

TEXAS 39 $25,077 $752 $108,420 $0 $28,197 $2,508 $164,954

UTAH 517 $332,431 $9,973 $2,874,520 $0 $373,791 $33,243 $3,623,958

WYOMING 827 $531,761 $15,953 $4,598,120 $4,737,718 $597,921 $53,176 $10,534,649

TOTAL 3,105 $1,996,515 $59,895 $14,419,860 $16,442,177 $2,244,915 $199,652 $35,363,014
87

Table 8: Estimated Annual Incremental Costs Associated with Activity on Tribal Lands

Reservation or BIA 

Agency

Number of 

operations per 

year

Application 

(Sundry)

Remedial 

Action 

Reporting 

(Sundry)

CEL on 

Intermediate 

Casing Storage Tank

Post-Fracture 

Reporting 

(Sundry)

Variance 

Requests 

(Sundry) Total Costs

ANADARKO 6 $3,858 $116 $33,360 $170,078 $4,338 $386 $212,136

ARDMORE 0 $0 $0 $0 $0 $0 $0 $0

BLACKFEET 4 $2,572 $77 $22,240 $60,710 $2,892 $257 $88,749

CHEYENNE & 

ARAPAHO 1 $643 $19 $5,560 $28,346 $723 $64 $35,356

CONCHO 14 $9,002 $270 $77,840 $396,850 $10,122 $900 $494,984

CROW 0 $0 $0 $0 $0 $0 $0 $0

EASTERN NAVAJO 19 $12,217 $367 $105,640 $0 $13,737 $1,222 $133,182

FIVE CIVILIZED 

TRIBES 0 $0 $0 $0 $0 $0 $0 $0

FORT BELKNAP 0 $0 $0 $0 $0 $0 $0 $0

FORT BERTHOLD 334 $214,762 $6,443 $0 $6,187,550 $241,482 $21,476 $6,671,713

FORT PECK 0 $0 $0 $0 $0 $0 $0 $0

JICARILLA APACHE 93 $59,799 $1,794 $517,080 $0 $67,239 $5,980 $651,892

MUSKUGEE 0 $0 $0 $0 $0 $0 $0 $0

OKMULGEE 2 $1,286 $39 $11,120 $56,693 $1,446 $129 $70,712

PAWNEE 9 $5,787 $174 $50,040 $255,118 $6,507 $579 $318,204

SHAWNEE 0 $0 $0 $0 $0 $0 $0 $0

SHIPROCK 4 $2,572 $77 $22,240 $0 $2,892 $257 $28,038

SOUTHERN UTE, 

BIA 0 $0 $0 $0 $0 $0 $0 $0

TAHLAQUAH 1 $643 $19 $5,560 $28,346 $723 $64 $35,356

TALIHINA 1 $643 $19 $5,560 $28,346 $723 $64 $35,356

TURTLE MOUNTAIN 2 $1,286 $39 $0 $37,051 $1,446 $129 $39,950

UINTAH AND 

OURAY 176 $113,168 $3,395 $978,560 $0 $127,248 $11,317 $1,233,688

UTE MOUNTAIN 

UTE 0 $0 $0 $0 $0 $0 $0 $0

WIND RIVER 4 $2,572 $77 $22,240 $22,915 $2,892 $257 $50,954

TOTAL 670 $430,810 $12,924 $1,857,040 $7,272,005 $484,410 $43,081 $10,100,270
88

4.3 Cost Breakout by Activity 

Tables 9A and 9B show the incremental costs by requirement for operations on Federal and 

Indian lands. We estimate that the largest incremental costs are associated with the operational 

requirements for a CEL on certain intermediate casing and storage tanks to manage recovered 

fluids. Of course, as mentioned previously, we do not have a clear picture about the prevalence 

of voluntary compliance with these requirements irrespective of the rule, and so these estimates 

are likely overstated. We estimate that the CEL requirement will impact a fraction of the 

operations, but could cost operators about $12.4 million annually (and potentially up to $16.3

million). We also estimate that the incremental annual cost of requiring storage tanks (instead of 

allowing pits) could cost operators about $15.6 million (and potentially up to $23.7 million).

4.4 Compliance Costs Per-Operation

The rule would result in compliance costs of about $11,400 per hydraulic fracturing operation. 

Compliance costs are estimated to be slightly higher on Indian lands, due to the uncertainly about 

the voluntary use of storage tanks in Oklahoma and North Dakota, where many of the tribes are 

located. Average compliance costs to meet the requirements for a CEL on certain intermediate 

casing and for storage tanks represent the bulk of the per-operation compliance costs. The 

results are in Table 10. 

Of the estimated per-operation compliance costs, the administrative burden represents about 

$1,450. We estimate that the operator will assume about $1,118 and the BLM will assume $331

of that amount. The administrative burden figures are in Tables 11A and 11B. 

We note that the per-operation compliance costs and administrative burden are calculated by 

dividing the total annual costs for each requirement by the estimated number of hydraulic 

fracturing operations expected to occur annually. Because each requirement might not apply to 

each operation (e.g. the operator might not claim trade secrets and thus not submit an affidavit) 

and we average the costs over all of the operations, the per-operation costs shown in Tables 10 

and 11B, may be lower than the costs described in section 3.2 of this report. Overall, the 

estimated per-operation compliance costs represent about 0.13 to 0.21 percent of the cost of 

drilling a well.

We estimate that the administrative burden placed on the BLM will be about $932,000 per year 

(or about $331 per HF operation). The BLM’s burden includes the review of information 

associated with the application, subsequent report, remedial action report (when applicable), and 

variance request (when applicable); however, it is unclear the extent to which the BLM will meet 

the additional burden with existing capacity. The review of information associated with the rule 

will require about 25,400 hours per year of workload. That additional burden represents about 
89

12.20 full-time equivalent (FTE) of workload or, as a practical matter, about 13.80 staffed 

positions.76 See Table 11C. 

This estimated administrative burden does not reflect all of the potential workload that may 

result from this rule. In addition to the administrative burden, the BLM is likely to face 

additional challenges while implementing various aspects of the rule. The rule includes 

provisions that cover different stages of operations, from cementing of the casing, tests on the 

casing, monitoring pressures during the operations, and flowback requirements, which may place 

an additional burden on inspectors monitoring compliance. While BLM inspectors generally try 

to be present during cementing and other important well operations, there may be an increased 

need for them to witness and confirm operator compliance with all aspects of the rule. 

 

76 FTE is calculated as the total hourly burden divided by 2,080 hours (or 40 hours per week x 52 weeks). The 

number of positions staffed takes into account leave and holidays and is calculated as the total hourly burden divided 

by 1,840 hours (or 40 hours per week x 46 weeks). 
90

Table 9A: Estimated Annual Incremental Costs, by Requirement

Jurisdiction

Number of 

operations 

per year

Application 

(Sundry)

Remedial 

Action 

Reporting 

(Sundry)

CEL on 

Intermediate 

Casing

Storage 

Tank

PostFracture 

Reporting 

(Sundry)

Variance 

Requests 

(Sundry) Total Costs

Federal lands 2,144 $1,378,592 $41,358 $10,566,780 $8,328,262 $1,550,112 $137,859 $22,002,963

Indian lands 670 $430,810 $12,924 $1,857,040 $7,272,005 $484,410 $43,081 $10,100,270

Total 2,814 $1,809,402 $54,282 $12,423,820 $15,600,266 $2,034,522 $180,940 $32,103,233

Table 9B: Potential Upper Bound Estimate (Using FY 2012 Level of Activity) - Estimated Annual Incremental Costs, 

by Requirement

Jurisdiction

Number of 

operations 

per year

Application 

(Sundry)

Remedial 

Action 

Reporting 

(Sundry)

CEL on 

Intermediate 

Casing

Storage 

Tank

PostFracture 

Reporting 

(Sundry)

Variance 

Requests 

(Sundry) Total Costs

Federal lands 3,105 $1,996,515 $59,895 $14,419,860 $16,442,177 $2,244,915 $199,652 $35,363,014

Indian lands 670 $430,810 $12,924 $1,857,040 $7,272,005 $484,410 $43,081 $10,100,270

Total 3,775 $2,427,325 $72,820 $16,276,900 $23,714,182 $2,729,325 $242,733 $45,463,284

Table 10: Average Per-Operation Compliance Costs, by Requirement

Jurisdiction

Number of 

operations 

per year

Application 

(Sundry)

Remedial 

Action 

Reporting 

(Sundry)

CEL on 

Intermediate 

Casing Storage Tank

Post-Fracture 

Reporting 

(Sundry)

Variance 

Requests 

(Sundry) Total Costs

Federal lands 2,144 $643 $19 $4,929 $3,884 $723 $64 $10,263

Indian lands 670 $643 $19 $2,772 $10,854 $723 $64 $15,075

Total 2,814 $643 $19 $4,415 $5,544 $723 $64 $11,408
91

Table 11A: Annual Administrative Burden, by Requirement

Party 

Assuming 

Burden

Application 

(Sundry)

Remedial 

Action 

Reporting 

(Sundry)

PostFracture 

Reporting 

(Sundry)

Variance 

Requests 

(Sundry)

Total 

Costs

Operators $1,395,744 $41,872 $1,570,212 $139,574 $3,147,403

BLM $413,658 $12,410 $464,310 $41,366 $931,744

Total $1,809,402 $54,282 $2,034,522 $180,940 $4,079,146

Table 11B: Average Per-Operation Administrative Burden, by Requirement

Party 

Assuming 

Burden

Application 

(Sundry)

Remedial 

Action 

Reporting 

(Sundry)

PostFracture 

Reporting 

(Sundry)

Variance 

Requests 

(Sundry)

Total 

Costs

Operators $496 $15 $558 $50 $1,118

BLM $147 $4 $165 $15 $331

Total $643 $19 $723 $64 $1,450

Table 11C: Workload Required for BLM to Review Information Associated with the Rule

Metric

Burden Activities

Applications Total

Remedial 

Action 

Reports

Variance 

Requests

Subsequent 

Reports

Number of HF operations 2,814

Percent of operations where activity 

applies 100% 3% 10% 100%

Number of activities 2,814 84 281 2,814 5,994

Hourly BLM burden for each activity 4 4 4 4.5

Total hours 11,256 338 1,126 12,663 25,382

BLM hourly wage $36.66

BLM wage for each activity (rounded) $147 $147 $147 $165

Total wages $413,658 $12,410 $41,366 $464,310 $931,744

Total FTE (Total hours / 2080) 5.412 0.162 0.541 6.088 12.203

Total positions (Total hours / 1840) 6.117 0.184 0.612 6.882 13.795
92

4.5 Examination of Alternative Approaches 

In the initial proposal, the BLM proposed that operators must run a CBL on the cement behind 

each casing string protecting usable water. To comply with such a requirement, operators would 

have had to run a CBL on the surface casing, intermediate casing (if protecting usable water), 

and production casing. While CBLs (or other logs that evaluate the quality of the cement behind 

a casing string) are common on the intermediate and production casings, they are relatively 

uncommon on the surface casing, where operators generally consider cement returns to the 

surface (without cement loss) as evidence of adequate cementing.

In the supplemental proposal, the BLM proposed that operators must run a CEL on the cement 

behind each casing string protecting usable water. However, an operator may demonstrate that 

the casing and cementing program was successful by running successful logs on a “type well” 

and then foregoing the logs on subsequent wells replicating the type well design in the same 

geologic area.

For the final rule, the BLM requires that operators run a CEL to verify the cement behind each 

casing string that protects usable water, unless the operator returns the cement to the surface. 

This approach is consistent with industry practices and limits the burden on operators. A CEL is 

required when the operator does not return the cement to surface in order to locate the top of the 

cement – to demonstrate that the casing and cementing program meets the original design 

standards. If an operator witnesses inadequate cementing, then the BLM requires the operator to 

take remedial action and to demonstrate that the remedial action was successful. It may do so 

with a CEL or other test, where appropriate. This is consistent with Onshore Order 2. 

We estimate that the alternatives explored in the initial proposal and the supplemental proposal 

would pose significant annual incremental costs to operators, while the approach in the final rule 

would pose no additional cost to operators. We estimate that the initial proposal would have 

posed about $166 - $359 million in annual incremental costs to operators. Delays in the drilling 

process would have been the primary costs, though there is a potential that operators drilling 

multiple wells successively might be able to avoid delays. We estimate that the supplemental

proposal would have posed about $13 - $29 million in annual incremental costs to operators. 

This estimate accounts for delays in the drilling process for type wells, which we estimate would 

represent about 8% of all operations. The final proposal is consistent with industry practice and 

does not pose an incremental cost to operators. See Table 12A.

The next area where we considered alternatives was with the management of flowback fluids. In 

the initial proposal, the BLM required operators to manage flowback into lined pits or tanks. We 

believed that those requirements were generally being met by operators in the field, since many 

states have minimum requirements for pits to be lined or for flowback to be contained in storage 

tanks. We maintained that proposal in the supplemental proposal, but asked for comment on the 

costs and benefits of requiring flowback to be managed in storage tanks only. We received 

comments about that request (detailed in the preamble to the final rule) and about the potential 

cost burdens (discussed later in this report). 
93

For the final rule, the BLM requires operators to manage recovered fluids in rigid above-ground 

storage tanks, unless an operator applies for and receives approval to use a lined pit with a leak 

detection system. The rule lays out the conditions under which an operator may receive such an 

approval.

We estimate that the alternatives proposed in the initial and supplemental proposals, for a 

minimum requirement for a lined pit, would have resulted in annual incremental costs ranging 

from $0 - $2.2 million. We generally believe that operators will line pits at a minimum, as is 

recommended by industry guidance. In addition to environmental benefits, lined pits also protect 

the integrity of the water or chemical content of the fluid, allowing operators to recycle the fluid 

and reuse it in subsequent operations. The upper bound of the estimate assumes that operators 

would use lined pits voluntarily on half of all operations in areas where we did not find evidence 

of a minimum requirement for lined pits. See Table 12B.

In a separate matter, if the BLM supplemented the initial and supplemental proposals by 

requiring leak detection systems on pits, we would expect the costs to be somewhat less than or 

roughly comparable to the costs estimated for the final proposal requiring storage tanks.

Finally, the BLM gave consideration to several policy options for requiring the disclosure of 

chemicals using in the hydraulic fracturing operations. The initial, supplemental, and final rules

all require the disclosure of chemicals after the hydraulic fracturing operations are complete. 

Although it was never proposed, the BLM also considered requiring chemical disclosure 

(chemical name and not the volume or percent) prior to the start of operations. Ultimately, the 

BLM did not carry that policy option forward for the reasons detailed in the preamble discussion.
94

Table 12A: Incremental Annual Cost of Alternative Approaches to the CEL Requirements

Jurisdiction

Number of 

operations per 

year Initial Proposal (CBL on Surface Casing)

Revised Proposal (CBL on Surface 

Casing of Type Well)

Final Proposal 

(Cement the 

Surface Casing to 

Surface)

Federal lands 2,144 $126,350,208 - $273,574,400 $10,108,017 - $21,885,952 $0

Indian lands 670 $39,484,440 - $85,492,000 $3,158,755 - $6,839,360 $0

Total 2,814 $165,834,648 - $359,066,400 $13,266,772 - $28,725,312 $0

Table 12B: Incremental Annual Cost of Alternative Approaches to the Management of Recovered 

Fluids

Jurisdiction

Number of 

operations per 

year Initial and Revised Proposals (Lined Pits)

Final Proposal 

(Storage Tanks)

Federal lands 2,144 $0 - $258,600 $8,328,262

Indian lands 670 $0 - $1,935,000 $7,272,005

Total 2,814 $0 - $2,193,600 $15,600,266
95

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. 

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 of this rule 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. 

For the average hydraulic fracturing operation, the compliance costs represent about 0.13 to 0.21

percent of the cost 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.

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. 
96

This proposed rule would require operators to conduct one-time tests on a well or make a onetime installation of a mitigation control feature. In addition, operators would be required to 

perform administrative tasks related to a one-time event. 

Compliance with few of the operational requirements is expected to pose an additional cost to 

the operator and is likely 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). 

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 hydraulic fracturing operation that is small and will not alter the 

investment or employment decisions of firms. 

5.3 Small Business Impact Analysis

The BLM reviewed the Small Business Administration (SBA) size standards for small 

businesses and the number of entities fitting those size standards as reported by the U.S. Census 

Bureau in the 2007 Economic Census. Using the Economic Census data, the BLM concludes 

that about 99 percent of the entities operating in the relevant sectors77 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 2.8). 

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. We compiled a list of firms 

that completed wells according to AFMSS. We expect that these firms are most likely to be 

impacted by the rule. 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 

 

77 NAICS codes: 211111 - Crude Petroleum and Natural Gas Extraction, 211112 - Natural Gas Liquid Extraction, 

and 213111 - Drilling Oil and Gas Wells.
97

small businesses. For the purposes of this analysis, the BLM assumes that all entities (all lessees 

and operators) that may be affected by this rule are small entities, even though that is not actually 

the case.

Using the net income data for the small businesses that filed SEC Form 10-K, we used the 

estimated compliance costs per hydraulic fracturing operation 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 about 0.15 percent of the 

company net incomes. The results of those findings are in Table 13 and also in the Appendix.

Table 13: Small Business' Company Net Income and Compliance Costs as a Share of Net Income

Descriptive Statistic

Company Net 

Income

Hydraulic 

Fracturing 

Operation on 

Federal 

Lands

Hydraulic 

Fracturing 

Operation on 

Indian Lands

Hydraulic 

Fracturing 

Operation 

(without 

distinction)

Average of absolute values 67,288,696 0.132% 0.195% 0.147%

Average 27,566,704 0.005% 0.008% 0.006%

Minimum value -228,063,000 -0.858% -1.260% -0.954%

Maximum value 392,678,000 0.731% 1.074% 0.813%

There would be some increased costs associated with the enhanced recordkeeping requirements 

and some new operational requirements. Specifically, there will be increased costs for operators 

to manage recovered fluids in above-ground tanks until they have approved plans for disposal of 

produced water pursuant to Onshore Order No. 7. Operators that do not routinely run a CEL to 

ensure that the producing zone is isolated from usable water, or that do not routinely run an MIT 

prior to hydraulic fracturing operations will face increased costs. Submission of hydraulic 

fracturing plans for prior approval, and submission of detailed reports after hydraulic fracturing 

operations will be new costs. Maintaining access to information on chemicals that was withheld 

from submission may also pose a cost. The application, reporting and data retention 

requirements are not overly burdensome because they are for information readily available to the 

operator or its service contractors. The BLM expects that the costs of compliance with this rule 

would be minor in comparison to overall operations costs. 

The BLM has taken steps to reduce costs on small entities by not promulgating a general 

requirement to run a CEL on surface casings, by allowing submission of chemical data through 

FracFocus, by providing for approval of a master hydraulic fracturing plan, by clarifying that 

isolating and protecting usable water means 200 feet of competent cement between the fractured 

zone and the usable water zone, by clarifying that expensive modeling of fissure propagation is 

not required, and by allowing for both operation-specific and for state or tribal variances. 

Therefore, the BLM has determined under that the rule would not have a significant economic 

impact on a substantial number of small entities. 
98

6. Statutory and Executive Order Reviews

6.1 Executive Order 12866 Regulatory Planning and Review

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.

After reviewing the requirements of the final rule, we have determined that it 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, if a rule would have a significant economic impact, either detrimental or 

beneficial, on a substantial number of small entities (see 5 U.S.C. 601 – 612). Congress enacted 

the RFA to ensure that government regulations do not unnecessarily or disproportionately burden 

small entities. Small entities include small businesses, small governmental jurisdictions, 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 
99

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. For the 

purposes of this analysis, the BLM assumes that all entities (all lessees and operators) that may 

be affected by this rule are small entities, even though that is not actually the case.

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 about 0.15 percent of the company net incomes. 

Therefore, the BLM has determined that the rule would not have a significant economic impact 

on a substantial number of small entities. 

We have also determined that the final rule does not meet the criteria for a major rule under 

SBREFA. Specifically, and based on the available information, we have determined that the rule 

will not: have an annual effect on the economy of $100 million or more; result in a major 

increase in costs or prices for consumers, individual industries, Federal, State, or local 

government agencies, or geographic regions; or have significant adverse effects on competition, 

employment, investment, productivity, innovation, or on the ability of United States-based 

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

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 on energy supply, distribution, or use (including a shortfall in 
100

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 the average hydraulic fracturing operation, the compliance costs represent about 0.13 to 0.21

percent of the cost 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. As such, the 

rule is not a “significant energy action” as defined in Executive Order 13211. 
101

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 an existing regulation on hydraulic fracturing that was promulgated before 

hydraulic fracturing technology was combined with horizontal drilling technology to become the

prevalent and large-scale operations that they are today. The BLM’s existing regulation requires

NOI Sundry notices for “non-routine” fracturing operations, but is unclear about what that 

means, and does not specify performance standards for wells to be hydraulically fractured. 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. 

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 will help the BLM 

better manage and protect the public’s resources, and to carry out the Secretary’s responsibilities 

on Indian lands. The rule also seeks to minimize the risks associated with hydraulic fracturing 

by placing requirements to help ensure wellbore integrity and proper management of recovered 

fluids.

This analysis attempts to measure the potential costs and benefits that will 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. Operators conduct many of the activities required by the rule as a matter of standard 

industry practice, to comply with other state and Federal regulations, to comply with conditions 

of approvals for permits, or as a matter of company or voluntary practice.

Most of the operational requirements are consistent with industry guidance concerning hydraulic 

fracturing, with best management practices of companies, or with state regulations. Only two 

requirements extend beyond industry guidance – requirements for storage tanks and for a CEL 

on the intermediate casing that protects usable water. Although industry guidance does not 
102

recommend fluid recovery to be managed in storage tanks, many companies implement the use 

of tanks voluntarily or as a best practice. Additionally, Texas and New Mexico require the use 

of tanks unless pits are permitted and Colorado requires tanks in certain areas. For many 

operations, particularly with the volumes of recovered fluids that we would expect to result from 

operations on Federal and Indian lands, the use of storage tanks makes economic sense. With 

regard to using a CEL to demonstrate that there is 200 feet of adequately bonded cement between 

the zone to be fractured and the deepest usable water zone, operators run CELs on the production 

casing as a matter of practice. For operations that are conducted through a production liner hung 

from the intermediate casing, the operators are also expected to run a CEL on the intermediate

and/or production casing to determine the top of cement to assure 200 feet of adequately bonded 

cement between the deepest usable water zone and the hydraulic fracture zone. Although 

industry guidance does not specifically address this scenario, we believe that the rule’s 

therequirements are consistent with industry practice.

We estimate that the rule will impact about 2,800 hydraulic fracturing operations per year, but 

that it could impact up to 3,800 operations per year based on previous levels of activity on 

Federal lands and growing activity on Indian lands. We estimate that the compliance cost could 

reach about $11,400 per well, or between about $32 and $45 million per year. We believe that 

the actual costs of the rule are likely much less than these estimates, since many operators are 

already in compliance with these standards as a matter of operating practice, though we do not 

have exact data on the prevalence of voluntary compliance.

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 the 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 

places requirements on operators that are generally consistent with industry practice or the best 

management practices of companies.
103

8. References

American Petroleum Institute (2009). Hydraulic Fracturing Operations – Well Construction and 

Integrity Guidelines. API Guidance Document HF1. First Edition.

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 Land Management (1998). Onshore Oil and Gas Order No. 2: Drilling operations. 

Available on the web at

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

Bureau of Land Management (2007). Onshore Oil and Gas Order No. 1: Approval of 

Operations. Available on the web at 

http://www.blm.gov/style/medialib/blm/wo/MINERALS__REALTY__AND_RESOURC

E_PROTECTION_/energy/onshore_order_videos.Par.62610.File.dat/Onshore_Order_No

_1_The_Order.pdf

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
104

Oil Patch Hotline (March 5, 2015). Oil Patch Hotline, Vol. 19, No. 5. Retrieved from 

http://www.oph.hotlineprinting.com

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 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 (2012). Field Demonstration of Innovative Condition 

Assessment Technologies for Water Mains: Leak Detection and Location. Retrieved from 

http://nepis.epa.gov/Adobe/PDF/P100EK7Q.pdf

U.S. Environmental Protection Agency (May 20, 2014). Natural Gas Extraction - Hydraulic 

Fracturing: Providing Regulatory Clarity and Protections against Known Risks. 

Retrieved from http://www2.epa.gov/hydraulicfracturing#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.

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.
105

9. Appendix

A-1 Sample of Small Businesses

A-2 Cost Spreadsheets
106

Appendix A-1

Sample of Small Businesses

Includes companies that recently completed wells and filed SEC 10-K forms in 2012

Shaded companies are small businesses

2011 Company 

Net Income ($)

Comments Explaining Company 

Losses

Per Unit Compliance Costs as a Share of Company 

Net Income (%)

Hydraulic 

Fracturing 

Operation on 

Federal Lands

Hydraulic 

Fracturing 

Operation on 

Indian Lands

Hydraulic 

Fracturing 

Operation 

(without 

distinction)

2,535,599 0.4043% 0.5941% 0.4495%

-1,196,440 Paid down accounts payable -0.8569% -1.2591% -0.9526%

-5,268,905 -0.1946% -0.2859% -0.2163%

-11,600,158 -0.0884% -0.1299% -0.0983%

162,388,000 0.0063% 0.0093% 0.0070%

10,384,496 0.0987% 0.1451% 0.1098%

-4,104,338 -0.2498% -0.3670% -0.2777%

11,687,000 0.0877% 0.1289% 0.0975%

-27,841,000 -0.0368% -0.0541% -0.0409%

-1,764,000 Losses the past 3 years due to 

expanding the company (buying 

acreage, exploratory drilling, 

drilling advances)

-0.5812% -0.8540% -0.6461%

1,753,000 0.5848% 0.8593% 0.6502%

392,678,000 0.0026% 0.0038% 0.0029%

12,691,000 0.0808% 0.1187% 0.0898%

13,743,000 0.0746% 0.1096% 0.0829%

-31,758,000 -0.0323% -0.0474% -0.0359%

65,179,000 0.0157% 0.0231% 0.0175%

79,390,000 0.0129% 0.0190% 0.0144%

-132,915,000 -0.0077% -0.0113% -0.0086%

72,061,000 0.0142% 0.0209% 0.0158%

36,629,000 0.0280% 0.0411% 0.0311%

-57,480,023 Blame losses and variability of net 

income on "dry hole costs"

-0.0178% -0.0262% -0.0198%

105,554,000 0.0097% 0.0143% 0.0108%

1,403,000 0.7307% 1.0737% 0.8124%

-76,761,000 Estimates of reserves decline, 

lowering market prices making 

drilling uneconomic

-0.0134% -0.0196% -0.0148%

-76,661,000 -0.0134% -0.0197% -0.0149%

30,707,000 0.0334% 0.0491% 0.0371%
107

2011 Company 

Net Income ($)

Comments Explaining Company 

Losses

Per Unit Compliance Costs as a Share of Company 

Net Income (%)

Hydraulic 

Fracturing 

Operation on 

Federal Lands

Hydraulic 

Fracturing 

Operation on 

Indian Lands

Hydraulic 

Fracturing 

Operation 

(without 

distinction)

-228,063,000 Company factors field reserves 

into net earnings calculation.

-0.0045% -0.0066% -0.0050%

35,809,000 0.0286% 0.0421% 0.0318%

194,332,000 0.0053% 0.0078% 0.0059%

62,314,000 0.0165% 0.0242% 0.0183%

110,698,000 0.0093% 0.0136% 0.0103%

73,132,000 0.0140% 0.0206% 0.0156%

90,046,000 0.0114% 0.0167% 0.0127%

122,408,000 0.0084% 0.0123% 0.0093%

548,137,000 0.0019% 0.0027% 0.0021%

429,072,000 0.0024% 0.0035% 0.0027%

215,400,000 0.0048% 0.0070% 0.0053%

491,600,000 0.0021% 0.0031% 0.0023%

42,048,000 0.0244% 0.0358% 0.0271%

529,932,000 0.0019% 0.0028% 0.0022%

267,200,000 0.0038% 0.0056% 0.0043%

206,679,000 0.0050% 0.0073% 0.0055%

292,000,000 0.0035% 0.0052% 0.0039%

539,000,000 0.0019% 0.0028% 0.0021%

479,769,000 0.0021% 0.0031% 0.0024%

453000000 0.0023% 0.0033% 0.0025%

1,091,123,000 0.0009% 0.0014% 0.0010%

881,914,000 0.0012% 0.0017% 0.0013%

2946000000 0.0003% 0.0005% 0.0004%

-2,649,000,000 Company cited loss due to 

settlement agreement.

-0.0004% -0.0006% -0.0004%

4,704,000,000 0.0002% 0.0003% 0.0002%

11,750,000 0.0873% 0.1282% 0.0970%

660,000,000 0.0016% 0.0023% 0.0017%

434,186,000 0.0024% 0.0035% 0.0026%

6,771,000,000 0.0002% 0.0002% 0.0002%
108

Appendix A-2

Cost Spreadsheets

Detail of Tables 7A, 7B, and 8

Table 7A: Estimated Annual Incremental Costs Associated with Activity on Federal Lands

Federal Lands, by 

State

Number of 

operations 

per year

Application (Sundry) Remedial Action Reporting (Sundry) CEL on Intermediate Casing

Applicability Unit cost Subtotal Applicability Unit cost Subtotal Applicability Unit cost Subtotal

ALASKA 9 100.0% $638 $5,742 3.0% $638 $172 5.0% $111,200 $50,040

ALABAMA 1 100.0% $638 $638 3.0% $638 $19 5.0% $111,200 $5,560

ARKANSAS 3 100.0% $638 $1,914 3.0% $638 $57 5.0% $111,200 $16,680

CALIFORNIA 188 100.0% $638 $119,944 3.0% $638 $3,598 5.0% $111,200 $1,045,280

COLORADO 59 100.0% $638 $37,642 3.0% $638 $1,129 0.0% $111,200 $0

KANSAS 0 100.0% $638 $0 3.0% $638 $0 5.0% $111,200 $0

LOUISIANA 2 100.0% $638 $1,276 3.0% $638 $38 5.0% $111,200 $11,120

MISSISSIPPI 6 100.0% $638 $3,828 3.0% $638 $115 5.0% $111,200 $33,360

MONTANA 1 100.0% $638 $638 3.0% $638 $19 5.0% $111,200 $5,560

NORTH DAKOTA 173 100.0% $638 $110,374 3.0% $638 $3,311 0.0% $111,200 $0

NEW MEXICO 732 100.0% $638 $467,016 3.0% $638 $14,010 5.0% $111,200 $4,069,920

NEVADA 0 100.0% $638 $0 3.0% $638 $0 5.0% $111,200 $0

OHIO 2 100.0% $638 $1,276 3.0% $638 $38 5.0% $111,200 $11,120

OKLAHOMA 15 100.0% $638 $9,570 3.0% $638 $287 5.0% $111,200 $83,400

PENNSYLVANIA 12 100.0% $638 $7,656 3.0% $638 $230 5.0% $111,200 $66,720

SOUTH DAKOTA 4 100.0% $638 $2,552 3.0% $638 $77 5.0% $111,200 $22,240

TEXAS 23 100.0% $638 $14,674 3.0% $638 $440 2.5% $111,200 $63,940

UTAH 579 100.0% $638 $369,402 3.0% $638 $11,082 5.0% $111,200 $3,219,240

WYOMING 335 100.0% $638 $213,730 3.0% $638 $6,412 5.0% $111,200 $1,862,600

TOTAL 2,144 $1,367,872 $41,036 $10,566,780
109

Table 7A: Estimated Annual Incremental Costs Associated with Activity on Federal Lands (continued)

Federal Lands, by 

State

Number of 

operations 

per year

Storage Tank Post-Fracture Reporting (Sundry)

Applicability Unit cost Subtotal Applicability Unit cost Subtotal

ALASKA 9 0.0% $74,400 $0 100.0% $718 $6,462 

ALABAMA 1 100.0% $74,400 $74,400 100.0% $718 $718 

ARKANSAS 3 97.1% $74,400 $216,727 100.0% $718 $2,154 

CALIFORNIA 188 0.0% $74,400 $0 100.0% $718 $134,984 

COLORADO 59 28.3% $74,400 $1,242,257 100.0% $718 $42,362 

KANSAS 0 4.4% $74,400 $0 100.0% $718 $0 

LOUISIANA 2 69.6% $74,400 $103,565 100.0% $718 $1,436 

MISSISSIPPI 6 33.3% $74,400 $148,651 100.0% $718 $4,308 

MONTANA 1 20.4% $74,400 $15,178 100.0% $718 $718 

NORTH DAKOTA 173 24.9% $74,400 $3,204,929 100.0% $718 $124,214 

NEW MEXICO 732 0.0% $74,400 $0 100.0% $718 $525,576 

NEVADA 0 100.0% $74,400 $0 100.0% $718 $0 

OHIO 2 100.0% $74,400 $148,800 100.0% $718 $1,436 

OKLAHOMA 15 38.1% $74,400 $425,196 100.0% $718 $10,770 

PENNSYLVANIA 12 92.9% $74,400 $829,411 100.0% $718 $8,616 

SOUTH DAKOTA 4 0.0% $74,400 $0 100.0% $718 $2,872 

TEXAS 23 0.0% $74,400 $0 100.0% $718 $16,514 

UTAH 579 0.0% $74,400 $0 100.0% $718 $415,722 

WYOMING 335 7.7% $74,400 $1,919,148 100.0% $718 $240,530 

TOTAL 2,144 $8,328,262 $1,539,392 
110

Table 7A: Estimated Annual Incremental Costs Associated with Activity on Federal Lands (continued)

Federal Lands, by 

State

Number of 

operations 

per year

Variance Requests (Sundry)

Applicability Unit cost Subtotal Total Costs

ALASKA 9 10.0% $638 $574 $62,990

ALABAMA 1 10.0% $638 $64 $81,399

ARKANSAS 3 10.0% $638 $191 $237,724

CALIFORNIA 188 10.0% $638 $11,994 $1,315,801

COLORADO 59 10.0% $638 $3,764 $1,327,154

KANSAS 0 10.0% $638 $0 $0

LOUISIANA 2 10.0% $638 $128 $117,563

MISSISSIPPI 6 10.0% $638 $383 $190,645

MONTANA 1 10.0% $638 $64 $22,177

NORTH DAKOTA 173 10.0% $638 $11,037 $3,453,865

NEW MEXICO 732 10.0% $638 $46,702 $5,123,224

NEVADA 0 10.0% $638 $0 $0

OHIO 2 10.0% $638 $128 $162,798

OKLAHOMA 15 10.0% $638 $957 $530,180

PENNSYLVANIA 12 10.0% $638 $766 $913,398

SOUTH DAKOTA 4 10.0% $638 $255 $27,996

TEXAS 23 10.0% $638 $1,467 $97,036

UTAH 579 10.0% $638 $36,940 $4,052,386

WYOMING 335 10.0% $638 $21,373 $4,263,793

TOTAL 2,144 $136,787 $21,980,129
111

Table 7B: Upper Bound - Estimated Annual Incremental Costs Associated with Activity on Federal Lands

Federal Lands, by 

State

Number of 

operations 

per year

Application (Sundry) Remedial Action Reporting (Sundry) CEL on Intermediate Casing

Applicability

Unit 

cost Subtotal Applicability

Unit 

cost Subtotal Applicability

Unit 

cost Subtotal

ALASKA 1 100.0% $638 $638 3.0% $638 $19 5.0% $111,200 $5,560

ALABAMA 1 100.0% $638 $638 3.0% $638 $19 5.0% $111,200 $5,560

ARKANSAS 7 100.0% $638 $4,466 3.0% $638 $134 5.0% $111,200 $38,920

CALIFORNIA 222 100.0% $638 $141,636 3.0% $638 $4,249 5.0% $111,200 $1,234,320

COLORADO 365 100.0% $638 $232,870 3.0% $638 $6,986 0.0% $111,200 $0

KANSAS 1 100.0% $638 $638 3.0% $638 $19 5.0% $111,200 $5,560

LOUISIANA 4 100.0% $638 $2,552 3.0% $638 $77 5.0% $111,200 $22,240

MISSISSIPPI 0 100.0% $638 $0 3.0% $638 $0 5.0% $111,200 $0

MONTANA 15 100.0% $638 $9,570 3.0% $638 $287 5.0% $111,200 $83,400

NORTH DAKOTA 127 100.0% $638 $81,026 3.0% $638 $2,431 0.0% $111,200 $0

NEW MEXICO 956 100.0% $638 $609,928 3.0% $638 $18,298 5.0% $111,200 $5,315,360

NEVADA 0 100.0% $638 $0 3.0% $638 $0 5.0% $111,200 $0

OHIO 3 100.0% $638 $1,914 3.0% $638 $57 5.0% $111,200 $16,680

OKLAHOMA 15 100.0% $638 $9,570 3.0% $638 $287 5.0% $111,200 $83,400

PENNSYLVANIA 0 100.0% $638 $0 3.0% $638 $0 5.0% $111,200 $0

SOUTH DAKOTA 5 100.0% $638 $3,190 3.0% $638 $96 5.0% $111,200 $27,800

TEXAS 39 100.0% $638 $24,882 3.0% $638 $746 2.5% $111,200 $108,420

UTAH 517 100.0% $638 $329,846 3.0% $638 $9,895 5.0% $111,200 $2,874,520

WYOMING 827 100.0% $638 $527,626 3.0% $638 $15,829 5.0% $111,200 $4,598,120

TOTAL 3,105 $1,980,990 $59,430 $14,419,860
112

Table 7B: Upper Bound - Estimated Annual Incremental Costs Associated with Activity on Federal Lands (continued)

Federal Lands, by 

State

Number of 

operations 

per year

Storage Tank Post-Fracture Reporting (Sundry)

Applicability Unit cost Subtotal Applicability Unit cost Subtotal

ALASKA 1 0.0% $74,400 $0 100.0% $718 $718 

ALABAMA 1 100.0% $74,400 $74,400 100.0% $718 $718 

ARKANSAS 7 97.1% $74,400 $505,697 100.0% $718 $5,026 

CALIFORNIA 222 0.0% $74,400 $0 100.0% $718 $159,396 

COLORADO 365 28.3% $74,400 $7,685,148 100.0% $718 $262,070 

KANSAS 1 4.4% $74,400 $3,274 100.0% $718 $718 

LOUISIANA 4 69.6% $74,400 $207,130 100.0% $718 $2,872 

MISSISSIPPI 0 33.3% $74,400 $0 100.0% $718 $0 

MONTANA 15 20.4% $74,400 $227,664 100.0% $718 $10,770 

NORTH DAKOTA 127 24.9% $74,400 $2,352,751 100.0% $718 $91,186 

NEW MEXICO 956 0.0% $74,400 $0 100.0% $718 $686,408 

NEVADA 0 100.0% $74,400 $0 100.0% $718 $0 

OHIO 3 100.0% $74,400 $223,200 100.0% $718 $2,154 

OKLAHOMA 15 38.1% $74,400 $425,196 100.0% $718 $10,770 

PENNSYLVANIA 0 92.9% $74,400 $0 100.0% $718 $0 

SOUTH DAKOTA 5 0.0% $74,400 $0 100.0% $718 $3,590 

TEXAS 39 0.0% $74,400 $0 100.0% $718 $28,002 

UTAH 517 0.0% $74,400 $0 100.0% $718 $371,206 

WYOMING 827 7.7% $74,400 $4,737,718 100.0% $718 $593,786 

TOTAL 3,105 $16,442,177 $2,229,390 
113

Table 7B: Upper Bound - Estimated Annual Incremental Costs Associated with Activity on Federal Lands (continued)

Federal Lands, by 

State

Number of 

operations 

per year

Variance Requests (Sundry)

Applicability Unit cost Subtotal Total Costs

ALASKA 1 10.0% $638 $64 $6,999

ALABAMA 1 10.0% $638 $64 $81,399

ARKANSAS 7 10.0% $638 $447 $554,689

CALIFORNIA 222 10.0% $638 $14,164 $1,553,765

COLORADO 365 10.0% $638 $23,287 $8,210,361

KANSAS 1 10.0% $638 $64 $10,273

LOUISIANA 4 10.0% $638 $255 $235,125

MISSISSIPPI 0 10.0% $638 $0 $0

MONTANA 15 10.0% $638 $957 $332,648

NORTH DAKOTA 127 10.0% $638 $8,103 $2,535,497

NEW MEXICO 956 10.0% $638 $60,993 $6,690,987

NEVADA 0 10.0% $638 $0 $0

OHIO 3 10.0% $638 $191 $244,197

OKLAHOMA 15 10.0% $638 $957 $530,180

PENNSYLVANIA 0 10.0% $638 $0 $0

SOUTH DAKOTA 5 10.0% $638 $319 $34,995

TEXAS 39 10.0% $638 $2,488 $164,539

UTAH 517 10.0% $638 $32,985 $3,618,452

WYOMING 827 10.0% $638 $52,763 $10,525,841

TOTAL 3,105 $198,099 $35,329,946
114

Table 8: Estimated Annual Incremental Costs Associated with Activity on Tribal Lands

Reservation or BIA 

Agency 

Number of 

operations 

per year

Application (Sundry) Remedial Action Reporting (Sundry) CEL on Intermediate Casing

Applicability

Unit 

cost Subtotal Applicability

Unit 

cost Subtotal Applicability Unit cost Subtotal

ANADARKO 6 100.0% $638 $3,828 3.0% $638 $115 5.0% $111,200 $33,360

ARDMORE 0 100.0% $638 $0 3.0% $638 $0 5.0% $111,200 $0

BLACKFEET 4 100.0% $638 $2,552 3.0% $638 $77 5.0% $111,200 $22,240

CHEYENNE & 

ARAPAHO 1 100.0% $638 $638 3.0% $638 $19 5.0% $111,200 $5,560

CONCHO 14 100.0% $638 $8,932 3.0% $638 $268 5.0% $111,200 $77,840

CROW 0 100.0% $638 $0 3.0% $638 $0 5.0% $111,200 $0

EASTERN NAVAJO 19 100.0% $638 $12,122 3.0% $638 $364 5.0% $111,200 $105,640

FIVE CIVILIZED 

TRIBES 0 100.0% $638 $0 3.0% $638 $0 5.0% $111,200 $0

FORT BELKNAP 0 100.0% $638 $0 3.0% $638 $0 5.0% $111,200 $0

FORT BERTHOLD 334 100.0% $638 $213,092 3.0% $638 $6,393 0.0% $111,200 $0

FORT PECK 0 100.0% $638 $0 3.0% $638 $0 5.0% $111,200 $0

JICARILLA APACHE 93 100.0% $638 $59,334 3.0% $638 $1,780 5.0% $111,200 $517,080

MUSKUGEE 0 100.0% $638 $0 3.0% $638 $0 5.0% $111,200 $0

OKMULGEE 2 100.0% $638 $1,276 3.0% $638 $38 5.0% $111,200 $11,120

PAWNEE 9 100.0% $638 $5,742 3.0% $638 $172 5.0% $111,200 $50,040

SHAWNEE 0 100.0% $638 $0 3.0% $638 $0 5.0% $111,200 $0

SHIPROCK 4 100.0% $638 $2,552 3.0% $638 $77 5.0% $111,200 $22,240

SOUTHERN UTE, BIA 0 100.0% $638 $0 3.0% $638 $0 0.0% $111,200 $0

TAHLAQUAH 1 100.0% $638 $638 3.0% $638 $19 5.0% $111,200 $5,560

TALIHINA 1 100.0% $638 $638 3.0% $638 $19 5.0% $111,200 $5,560

TURTLE MOUNTAIN 2 100.0% $638 $1,276 3.0% $638 $38 0.0% $111,200 $0

UINTAH AND 

OURAY 176 100.0% $638 $112,288 3.0% $638 $3,369 5.0% $111,200 $978,560

UTE MOUNTAIN UTE 0 100.0% $638 $0 3.0% $638 $0 5.0% $111,200 $0

WIND RIVER 4 100.0% $638 $2,552 3.0% $638 $77 5.0% $111,200 $22,240

TOTAL 670 $427,460 $12,824 $1,857,040
115

Table 8: Estimated Annual Incremental Costs Associated with Activity on Tribal Lands (continued)

Reservation or BIA 

Agency

Number of 

operations 

per year

Storage Tank Post-Fracture Reporting (Sundry)

Applicability Unit cost Subtotal Applicability Unit cost Subtotal

ANADARKO 6 38.1% $74,400 $170,078 100.0% $718 $4,308 

ARDMORE 0 38.1% $74,400 $0 100.0% $718 $0 

BLACKFEET 4 20.4% $74,400 $60,710 100.0% $718 $2,872 

CHEYENNE & 

ARAPAHO 1 38.1% $74,400 $28,346 100.0% $718 $718 

CONCHO 14 38.1% $74,400 $396,850 100.0% $718 $10,052 

CROW 0 20.4% $74,400 $0 100.0% $718 $0 

EASTERN NAVAJO 19 0.0% $74,400 $0 100.0% $718 $13,642 

FIVE CIVILIZED 

TRIBES 0 38.1% $74,400 $0 100.0% $718 $0 

FORT BELKNAP 0 20.4% $74,400 $0 100.0% $718 $0 

FORT BERTHOLD 334 24.9% $74,400 $6,187,550 100.0% $718 $239,812 

FORT PECK 0 20.4% $74,400 $0 100.0% $718 $0 

JICARILLA APACHE 93 0.0% $74,400 $0 100.0% $718 $66,774 

MUSKUGEE 0 38.1% $74,400 $0 100.0% $718 $0 

OKMULGEE 2 38.1% $74,400 $56,693 100.0% $718 $1,436 

PAWNEE 9 38.1% $74,400 $255,118 100.0% $718 $6,462 

SHAWNEE 0 38.1% $74,400 $0 100.0% $718 $0 

SHIPROCK 4 0.0% $74,400 $0 100.0% $718 $2,872 

SOUTHERN UTE, BIA 0 28.3% $74,400 $0 100.0% $718 $0 

TAHLAQUAH 1 38.1% $74,400 $28,346 100.0% $718 $718 

TALIHINA 1 38.1% $74,400 $28,346 100.0% $718 $718 

TURTLE MOUNTAIN 2 24.9% $74,400 $37,051 100.0% $718 $1,436 

UINTAH AND 

OURAY 176 0.0% $74,400 $0 100.0% $718 $126,368 

UTE MOUNTAIN UTE 0 0.0% $74,400 $0 100.0% $718 $0 

WIND RIVER 4 7.7% $74,400 $22,915 100.0% $718 $2,872 

TOTAL 670 $7,272,005 $481,060 
116

Table 8: Estimated Annual Incremental Costs Associated with Activity on Tribal Lands (continued)

Reservation or BIA 

Agency

Number of 

operations 

per year

Variance Requests (Sundry)

Applicability Unit cost Subtotal Total Costs

ANADARKO 6 10.0% $638 $383 $212,072

ARDMORE 0 10.0% $638 $0 $0

BLACKFEET 4 10.0% $638 $255 $88,706

CHEYENNE & 

ARAPAHO 1 10.0% $638 $64 $35,345

CONCHO 14 10.0% $638 $893 $494,835

CROW 0 10.0% $638 $0 $0

EASTERN NAVAJO 19 10.0% $638 $1,212 $132,980

FIVE CIVILIZED 

TRIBES 0 10.0% $638 $0 $0

FORT BELKNAP 0 10.0% $638 $0 $0

FORT BERTHOLD 334 10.0% $638 $21,309 $6,668,156

FORT PECK 0 10.0% $638 $0 $0

JICARILLA APACHE 93 10.0% $638 $5,933 $650,901

MUSKUGEE 0 10.0% $638 $0 $0

OKMULGEE 2 10.0% $638 $128 $70,691

PAWNEE 9 10.0% $638 $574 $318,108

SHAWNEE 0 10.0% $638 $0 $0

SHIPROCK 4 10.0% $638 $255 $27,996

SOUTHERN UTE, BIA 0 10.0% $638 $0 $0

TAHLAQUAH 1 10.0% $638 $64 $35,345

TALIHINA 1 10.0% $638 $64 $35,345

TURTLE MOUNTAIN 2 10.0% $638 $128 $39,929

UINTAH AND OURAY 176 10.0% $638 $11,229 $1,231,813

UTE MOUNTAIN UTE 0 10.0% $638 $0 $0

WIND RIVER 4 10.0% $638 $255 $50,911

TOTAL 670 $42,746 $10,093,135