# Regulatory Impact Analysis for Hydraulic Fracturing Rule

U.S. Bureau of Land Management

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## 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 Wate r 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 Cos ts

................................ ................................ ................................ ............ 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 Regulato ry 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

................................ ................................ ................................ ................................ ......... 1 03

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 land s

. 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 wel l, 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 th e 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 ne w 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, t he 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:

 S ubmit information about the proposed hydraulic fracturing operation to the BLM with the Application for Permit to Drill (APD) or a Notice of Intent (NOI) Sundr y (with a few exceptions, detailed below, for certain recently drilled wells that are fracked w ithin 90 days of the effective date of the rule) ;

 Design and implement a casing and cementing program that protect s and/or isolate s 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 ;

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

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

 D emonstrate 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 re turn s the cement behind the casing to surface ;

 P erform 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 ;

 M onitor annulus pressures during t he 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 ;

 S ubmit information to the BLM after the hydraulic fracturing operation in a Subsequent Report (SR) Sundr y ; and

 D isclos e the chemicals used to the BLM through FracFocus

– operat ors may with hold

formulations that are trade secrets.

This regulatory impact analysis examines the potential c osts and benefits of these requirements

. Various statute s and executive order s require Federal agenc ies 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 h ave 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 oper ators 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 )

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### 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, 8 00 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 $ 3 2 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_PROTEC TION_/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

.

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compliance costs represent about 0.13 to 0.21 percent of the cost of drilling a well. G iven 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 C EL 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 cement ed to surface, and (2) U se of rigid above

- ground storage tanks to manage recovered fluids. For both of these requirements, w e 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) U se a CEL to verify the cement

behind the intermediate casing string ( to demonstrate that it cemen ted 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) U se 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

oper ations 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

.

T he rule will reduce the risks associated with hydraul ic 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 al l

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 benefi ts 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

.

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## 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 th e 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 r ights 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 deci sion 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 mon etary 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;

distribution al 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

feasibl e; 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 elements 2 

### :

 A statement of t he need for the proposed action;

 An examination of alternative approaches; and

 An analysis of benefits and costs.

2 OMB Circular A

- 4.

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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 numbe r 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 compe tition, employment, investment, productivity, innovation, or on the ability of United States

- based enterprises to compete with foreign

based enterprises in domestic and export markets.

If OIRA determines that a rule is major, then the rule may become eff ective 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 propose d 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.

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### 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 . T he 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 w ill 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 abo ut hydraulic fracturing has centered on fluid or gas migrat ion; that is, the

likelihood that hydraulic fracturing fluids pumped into deep geologic formations , or oil or gas liberated by hydraulic fracturing

, will m igrate into shallower drinking water sources with potential contamination made more likely if the wel lbore 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 Natio nal Academy of Sciences issued report s in 2011 7 

### and in 2012 8 

### finding that there are at least three possible mechanisms for fluid migration into shallow drinking

- water aquifers that could help explain the increased methane concentrations observed in water wells that existed around shale gas wells in Pennsylvania:

1. The movement of gas

- rich solutions within the shale formations up into shallow drinking

water aquifers ; 2. The movement of gas through inadequately constructed, or leaky gas

- well casings ; and

3. The creation of new or enlarging of existing fractures above the shale formation as a result of hydraulic fracturing, which increases the connectivity of the entire fracture system, thus allowing the gas to absolve out of solution and migrate through the fracture systems and into shallow aquifers.

These reports have indicated that the movement of gas

- rich solutions within the shale formations up into shallow drinking

- water aquifers is the least likel y 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).

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against these gas

- rich solutions, whi ch 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

communicat ed with other wells in the ir vicinity

. These hydraulic fracturing operation s created

fractures that connected with exist ing fissures or fract ures 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 blowo ut 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 we re 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 frac t ure 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 m ajority of the overflow were

frac turing 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 Par ko 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 frac tur ing fl uid. 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.”

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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 p roviders, 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 provide d 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 repo rt, 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 safety

critical s tages 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.

Par t 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 Nov ember 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 memb ers 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 Government al 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 perform ing

“non

- routine ” fracturing operations. Conversely, an operator performing “routine” fracturing operations does not need the BLM’s approval. The regulation m ake s 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

, h ydraulic f

racturing 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 hydroca rbons

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 r esource 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 potentia l 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 recover ed

. As with all drilling and production

activities , there is a potential that they may pose a negative externality 11 

### to society, considering limitations in understanding the extent of potential damage or determining a causal relationship between the operat ion and the damage.

Relative to wells constructed with sufficient and demonstrated integrity, w ells 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 techn ology 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 requireme nts to reduce this risk.

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

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### 2. 3 Final Rule Requirement s and Discussion

This section describes the final requirements and the significance of the requirements. In parts, we reference industry guid ance 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 Sign ificance

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 o ne 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 s canner. * * * * * 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 fractu ring 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. Hy draulic 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 requiremen ts 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” (se ction 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

th e 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 Sign ificance

* * * * * Hydraulic fracturing fluid means the liq uid 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

sourc e 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 operat or 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 aquif ers 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 iso lated 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. r equires 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 Sign ificance protected from hydraulic fracturing operations.

* * * * * Subpart 3162

-- Requirements for Operat ing 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 inje ction.

* * * (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 r eport 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 se ction 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 porti ons 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

section. (2) An APD was submitted but not 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]. T o conduct hydraulic fracturing within 90 days after the effective date of this rule, the operator must comply with all paragraphs of this section, except (c) and (d). (4) Authorized drilling operations 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 f inal, 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 su bject to all of the requirements including the request for hydraulic fracturing.

### 13 Provision Sign ificance (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 dat e 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 s ubject 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 p ublication) 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 t he 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 P revent 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 re quest 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 f

or 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 Sign ificance (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 fractu ring 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 operatio n, 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

- rout ine 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 Requ est 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) Th e 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,

usab le 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

thei r operations. The process of providing it to the BLM will pose some additional administrative burden to operators and necessitate

BLM review.

### 15 Provision Sign ificance (3) Information concerning the source and loc ation 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 anticip ated 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 f luid 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, wi thin 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 flu ids 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 rec overed 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 Sign ificance (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 isola te 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

des igned 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 re quired, 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 requi re such additional tests, verifications, cementing or other protection or isolation operations, as the authorized officer deem s necessary. (2) Prior to starting hydraulic fracturing operations, the operator must determine and document that there is adequat e 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

rela ted 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 th e operator submit the report to the BLM at least 48

ho urs 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;

 T he operator must demonstrate that there is at least 200 feet of adequately bonded cement between the deepest usable water zone

an d the formation to be fractured, if the cement is no t circulated to

the surface. This is generally consistent with industry guidance and

12 API Guidance Document HF1 “Hydraulic Fracturing Oper ations

– Well Construction and Integrity Guidelines” at p. 10.

### 17 Provision Sign ificance

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 thi s 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 (For m 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; (ii i) 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 signe d 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 su bmit 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, th e 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 st ate 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 CEL s. 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 i ntermediate 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 Sign ificance 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 f lexibility 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 c asing 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 pre ssure 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 consist ent 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 T he 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 expo sed 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 operation s 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 m ake 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 Sign ificance

fracture treatmen t. 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 unabl e 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 Du ring 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 co rrective 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 opera tions, 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

Re port Sundry Notice (Form 3160

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

record th e 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 mo nitored 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 Sign ificance (h) Management of Recovered Fluids. Except as p rovided 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 closed

loop systems. The tanks must not exceed a 500 barrel ( bbl) capacity unless

approv ed 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 re asons 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 wate r 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 hydrolog ic

functions of a 100

- year floodplain ; and (vii) P it use and location compl ies with applicable l ocal, State (on Federal lands)

, tribal (on Indian lands), and other Federal statutes and regulations including those that are more stringent than these regulati ons

. (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 tha t 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 vent ed, unless Federal law, state regulations, or tribal regulations require vapor recovery or closed

loop 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 w here 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

th at 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 req uirement 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 Sign ificance 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 a lso 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 th rough 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 informat ion: (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 surf

ace 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 wit h such agreements or requirements include Colorado, Montana, North Dakota, Oklahoma, Texas, and Utah.

### 22 Provision Sign ificance (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 documen ting 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 prod uced 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 rec overed 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 Sign ificance (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 BLM

designated 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 s ubmit 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 th e 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 pr ovide a Section 3162.3

- 3(j) allows operators to withhold information from their chemical disclosure that would compro mise 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

inf ormation.

### 24 Provision Sign ificance 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 f

rom 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 i nformation with no fewer than 10 b usiness 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 hydrau lic 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 pa ragraph (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 c hemical identity, and should be the same as or no less descriptive than the generic chemical name provided to the E nvironmental 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 alterna tives 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

rul e that could apply state

- or tribe

- wide, or within certain designated

### 25 Provision Sign ificance 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 lan ds, 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 autho rized 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 orde rs. (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 writ ten 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, ho wever, 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 prote ct 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, i t 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 informat ion , 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 th ose in the initial propo sed 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 CBL s (or other logs that evaluate the quality o f 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

cement ing.

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 sufficien tly 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 operator s must run a CEL on the cement behind each casing string protecting usable water . However, an operator demonstrat ing 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 t he effectiveness of the type

well approach and the usefulness of a CEL on the surface casing. Co mments on the economic analysis suggested that the application of the type well concept would be highly variable depending on the field, indicating that operat ors 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 co nsistent 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 origin al design

standards. If an operator witnesses inadequate cementing, the n 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 con sistent 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 require s 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 approv es the use a lined pit equipped with a leak

det ection 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 appr o ved by the BLM pursuant to Onshore Order No. 7.

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

chemicals us ed in the hydraulic fractur ing operations. T he initial, supplemental , and final rules

all would require the disclosure of chemicals aft er 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 polic y 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 Alternative s 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.

U ser 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

th e impacts of the project or to compensate the impacted parties. The difficulty in applying this approach in this context lies in determining an appropriate imp act 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 th e 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 ar eas (unlike, for example, a ton of carbon

dioxide which disperses in the atmosphere).

The r ule require s disclosure of hy draulic fracturing fluids, a requirement that is informational in nature, rather than direct regulation on the part of the BL M. OMB C ircular 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 resou rces 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 info rmed d ecisions 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 standp oint, 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 varia nces ; however, the provision would likely reduc e 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 progr am is one of the largest mineral leasing programs in

the Federal G overnment. At the end of fiscal year (FY) 2013 , t here were 4 7

, 427 Federal oil and gas leases covering 36,092,482 acres
, 9 3,598 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 ( b bl) of oil, 2 .67 trillion cubic feet of natural gas, and 2. 5 billion gallons (g al) 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 millio n bbl of oil, 238 billion cubic feet (Bcf) of natural gas, and 1 55 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 a ctivity 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 (b bl) 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 ( g al) 2,477,721,602 $2,076,639,138 $195,789,932

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

Indian Leases Oil ( b bl) 45,966,597 $4,137,453,205 $721,089,106

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

NGL ( g al) 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 “non

routine” 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 re

f ractured within the same zone. 17 

### By applying th at assumed prevalence to the number of well completions on Federal and Indian lands reported in Automated Fluid Minerals Support System ( AFMSS ) , we have estimate d 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, t he estimated number of well completions using hydraulic fracturing was generally about 3, 1 00 per year for FY 201 0, 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

estimate s 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 3 40 in FY 2010 to 5 2 0 in FY 2013 . The 4

- year average of the estimates is about 4 25 hydraulic fracturing well completions per year on Indian lands. T he data reveal differing trends for hydraulic fracturing on F ederal and Indian lands. While hydraulic fracturing peaked o n
F ederal lands in fiscal year FY 2011 and declined sharply in FY 2013, it has increased rather steadily on Indian lands over that per iod.

We estima te activity in the near

- term based on the activity from FY 2010 to FY 2013

. We

believe that the rule would impact about 2, 3 5 0, 2

, 1 35 , and 1, 9 50 hydraulic fracturing operations on Federal lands and about 600, 6 7 0 , and 7 5 0 operations on Ind ian 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 F ederal lands in FY 2013 was an aberration and that previous year totals might provide a better predictor of future activity. Estimated completions on F ederal and Indian lands combined were about 3,5 50 and
2,8 40 in FY 2012 and FY 2013, respectively. Estimated hydraulic fracturing operations on

F ederal and Indian lands were about 3, 350 per year for the four

- year period from FY 2010 to FY

2013.

17 Re

- completions are separa te 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 Natur al Gas Alliance

c onducted 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 Complet ions 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 e stimates 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

Boundar y ) 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 i m puted a zero value). The geographic loc ation identifies the state(s) within

which wells for the reservations were drilled between FY 20 1 2

- FY20 13. 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 inclu de 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, bus inesses 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 3 A through 3E ).

### 35

Note: Where range provided, employee data were estimated to be in middle of range Table 3 A : 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 guid ance, 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 rel iable 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 a nd 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 isola te 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 flu id 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 drill ing 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

s ubsequent 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

, C ementing Guidanc e , Pr essure Testing

, and Logging

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

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

18 API Guidance Docume nt HF1 “Hydraulic Fracturing Oper ations

– Well Construction and Integrity Guidelines.”

19 Ibid, p. 1.

20 Ibid, p. 1.

21 Ibid, p. 2.

### 37

drilling process as it relates to dr illing, 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

s tate 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 r each “ appropriate compressive stre ngth, ” 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 opera tor 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 opera tor 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 

### Acc ording 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 a re 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 o f 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 aff ecting 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. Ope rators 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

th e 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 Hydrau lic 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, ceme nt 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 . F or 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 hy drocarbon 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 comple te, 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 thi s, 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 b ehavior 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 f low 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, th is guidance document is less prescriptive than the one on well construction and integrity; however, it describes the consid erations and best practices for managing water associated with hydraulic fracturing.

35 Ibid, p. 16.

36 Ibid, p. 21.

37 API Guidance Document HF 2 “ Water Management Associated with Hydraulic Fracturing .”

### 41

Operators generally store fluids onsite in tanks or in l ined 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 F ederal regula tions. “ 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 F ederal, state, and local laws. Several F ederal agencies implement F ederal 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 t ribal lands. Operators on tribal lands will comply with both tribal and Federal regulations governing drilling and completion requirements by assuring that they are in comp liance 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

Sectio n 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 b y 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 la nd 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 publi c 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 Re gister 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 revis ion 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 o r 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, setba cks 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, th e 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 cons idered 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 a dditional 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 leas es, 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 leasin g. 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 wildl ife 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 an d 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 fo r 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 mitigatio n 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 woul d 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 respons ible 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 in formation 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 pro posal 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;

an d 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 lease s 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 o ffice 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

a uthorized 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 pr ior 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 t o 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 thei r 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 prevent ion 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 o f 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 a t 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 critica l 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. Th e 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 util ize 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

l ogging 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, temperat ures, 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 info rmation 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 the ir 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 e nsure there will not be any potential issues with existing wells.

The operator’s APD must also include a surface use plan of operat i o n s , 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 s tate

- 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 operator s to incorporate BMPs into their plan s

.

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 B ook. 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 Informa tion 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 informa tion 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 grad e, 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 inform ation 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 conflic ts, 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 succes sful (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 facili ties.

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 inform ation 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 pro poses 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 an d 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 con struction 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 informatio n 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 res erve 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 pla n 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 p lan 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, se eding 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 b ond 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 wi th 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 in spection, 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 rep resentative 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

f acilities; 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,

th e 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 an d 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. Regard less 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 issu es 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, recreat ion 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 analysi s. 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 pub lic 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 conditio ns 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 requiremen ts 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 prospecti vely 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 casin g 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 su rface 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 stre ngth 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 c an 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 th e 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

t he 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 comp ly 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 techn ical 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 revie w 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 operati ons. 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 insp ect 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 a bove, 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 ope rator’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 al ong 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 approve d 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. Roya l ties 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

pipeli nes; 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 plugg ed 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 w ell 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 inspec tions 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 sur face 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

T he BLM reviewed existing state regulations for consistency with the BLM rule

. We examined existing state regulation s 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 F ederal and Indian lands in th os e states accounted for 99.3 percent of the total well completions on F ederal and Indian lands nationwide. Table 4 shows a summary of the findings.

California

We r eviewed 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 C ode , a d ivision 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 l ong 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 C ode 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 Reg ional 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 threa tens 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 Commis sion (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 o n 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

interme diate 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 st imulation 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 prohibit s operators from conducting any tests until the cement (for ea ch 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 r egulation require s operators to use lined pits or tanks. Specifically, it states, “Waste oil, oil slu dge, 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 dis closure 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/wat er_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 comparativ e ly 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). Th e 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 fractur ing 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 r eview, 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,

u pdated 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 sh ow 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 )). O perators 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 s urface ( Section 3.13(b)(2)( H ))

. The TRC requires operators to pressure test the surface in intermediate strings of casing before drilling the cement plu g ( 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

press ure 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 appro ved 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 annu li ( 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 operator s 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 describe d 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)).

W yoming

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 ev aluation logs under normal cir cumstances. 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 bel ieve an inadequate cement job was performed” (at Ch. 3

Sec tion 22(a)(i)). Operators are required to pressure test the production string (at Ch. 3 Sec tion 22(a)(v)). T he 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 Sec tion 6(a)).

Sect ion 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, t he 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

meth ods” (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, t he 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 MI T 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 re quire 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 dif ferentiate

between the activities that an operator conduct s (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 agencie s to present any relevant quantitative information along with a description of the unquantified effects.

We measure d the incremental impact s by: estimating the number of hydraulic fracturing operations per year for future years ; determin ing the applicabil ity of the requirements on the operations ; determin ing 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 with in 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 decre ase 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 voluntari ly, for example, when a requirement cost s less than the alternative.

### 58



### 3. 2 Measuring the Incremental C osts

Application R equirement : The operator must s ubmit an application to conduct a hy draulic fracturing operation w ith the APD or a NOI Sundry when it plans to hydraulically fracture a well

for which it: 51



###  H as not yet submitted an APD;

 H as submitted an APD

, but the APD has yet to be approved;

 D rilled 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 ;

 H as 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) ;

 H as 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) ;

 D rilled 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 t he effective date (at least 6 months after publication) ;

The operator may also submit an application for a group of wells as part of a m aster hydraulic fracturing plan, thus reducing the number of potential applications.

Th e 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

informati on gathering. A master hydraulic fracturing plan will allow for efficie ncies in submission and review. Thus, w e would expect there to be fewer applications than the number of hydraulic fracturing operations, because of the option to make one submission f or a group of

wells.

We estimate the applicability of this requirement based on the number of well completions using hydraulic fracturing that we exp ect to occur. Since we assume that every hydraulic fracturing operation will require an application, ou r 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

R egister , and so 90 days after the effective date would be at least 180 days after it is published as final.

### 59

(a) Ap plicability 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 burde ns, we estimate the compliance or review hours and the respective wage. The compliance cost for the operator is estimated to be about $4 96 per application (calculated as 8 hours at about $6 1.99 per hour). The review cost for the BLM is estimated to be about $ 1 4 7 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 processi ng of APDs and thus constitute an opportunity cost to the operator. Th is argument is not supported. T he supporting statement for the Paperwork Reduction Act estimates only 4 hours of additional review

time for the BLM to review this information. This ha rdly 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 mi neral

bearing 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) U nderground water that meets the definition of “underground source

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

U nderground sources of drinking water under the law of the State (for Federal lands) or tribe (for Indian lands); and (3) W ater 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

op erator 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 tr ibe (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 existi ng 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

zon es.” 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 10,00 0 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 monitori ng 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 w ell 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 o perators 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 C asing 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 othe r 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 (sec tion II.B.1.c). Documenting indications of adequate cement and taking co rrective 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% o f operations (b) Cost per surface casing CEL = $ 58,932

– $1 27

, 6 00. The cost for a CEL on the surface casing includes the test ($6,000) and the cost of maintaining idle drilling equipment on

site ($5 2

, 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 reach es 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 ps i 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 p er hour . Next, we examined the potential for the operator to avoid the delays entirely. There a re ways that the operator could avoid maintaining idle drilling equipment. For example, the operator might cement the surface casing, pressure test the surfac e casing, drill t he intermediate hole, and then log the surface casing before setting the intermediate casing. Also, w hen drilling multiple wells successively, the operator may use a small drilling rig to drill the

surface holes of wells in a successive m anner, 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 well s in leases and agreements (referred to as cases 55 

### 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 a nd 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 th e 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 categor y 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 cit ed 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 ap plication 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 P rotects U sable W ater : If the operator does not cement the

interm ediate 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 adequately

bonded cement between th e 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 qualit y of a cement job. According to the guidance, w ell 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 desi red design objectives.” 59 

### I t 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 th e 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.

Genera lly, 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 regula tion 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 o f 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 C B L 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

T he 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 wi th this requirement by running a CEL on the production casi ng (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 throug h 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 consist ent 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

cas es, 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 r ule 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

operat ions. 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 consid eration 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 U sable 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 fr actured and the deepest usable water zone.

This requirement does not pose an incremental cost. API Guidance Document HF1 indicates

that o perator s run a log to evaluate the quality of the cement bond on the production casing as a

### 64

matter of industry practi ce. 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 th e 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 discoveri ng 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 operat or 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 t he 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 appr oved test.

This requirement poses an administrative burden

, but not an operational burden. The BLM and many state regulations and requirements have established protocol s 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 O rder 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 th at 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 en forcement 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 = $6 43 . Burden inc ludes the operator burden and the BLM burden. The compliance cost for the operator is estimated to be about $4 96 per application (calculated as 8 hours at about $6 1.99 per hour). The review cost for the BLM is estimated to be about $1 4 7 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 applie d 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 numb er 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 o r 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 no tify 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 incide nt, 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 intermediat e 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 d esign can be immediately detected and analy zed before operations continue... Unexpected or unusual pressure behavior during the hydraulic fracturing process coul d indicate some type of problem .” 61 

### Based on this information and our observations of field operat ions, we believe that o perators 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 m anage recovered fluid in “ rigid enclo sed, 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, t he o perator 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 m anage 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 requirement s

. 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 ro ads 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

m ay have open tops that allow the operator to more easily inspect the flowback vis ually , pump out fluids

, and vac u um out the proppants.

The rule pr ohibits the use of above

- ground semi

- rigid tanks for managing recovered fluids.

These tanks are “ semi

- rigi d ,” because they are constructed of steel sections and assembled on

site , and the y can hold larger volumes of fluid, up to 40,000 bbl . T hese 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 se parated 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. The se 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 Areas 63 

### in its regulations

, but the COGCC implemented a policy in June 2014 that prohibits the use of large volume semi

- rigid tanks to manage flo wback.

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 t op 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

, b ut allow for only very minor ve nting 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 wi th 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 large

volume open

- top ped 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

- to p p ed 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

- top ped 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 experi ence 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 an d 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 recy cling and they are not u sed during the hydraulic fracture process. The 4

- phase separa tors are required

when the flow back 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 prod uction 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 tan ks is rare. Rigid s teels 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

- top ped 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 F ederal lands. We have observed operations where the operator stores the completion water in tanks, conducts the hydr aulic 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 p roduced 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 retur n 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 frac turing stages per well and a fluid

volume of a b out 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 produce s 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 operatio ns 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 support ed the broad use of rigid steel tanks

, but recommend ed 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 support ed 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 sys tems, 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

operat ions, 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 f

racturing 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 red ucing 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 ste el 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 describ ed 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 closed

loop system costs $2 67,000 (an $180,000 cost advantage).

We did not receive comments on the prevalence of voluntary compliance among operat or s 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 tank s voluntarily (when otherwise not compelled to do so by regulation, condition o f approval, environmental consideration, or company practice) in situations where tanks would

cos t 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 th e operations var y depending on the formation and the operation itself. We examined data

extracted from FracFocus 65 

### 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 gall ons). W e use d 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 S kytruth.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

- Facilities

Article.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

tank s instead of a pit

. We estimated the baseline cost of constructing and operating a pit based

on the first commenter’s data . W e 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 $ 4 92 ,000 and, finally, a per

operation cost of about $ 9 8

, 4 00 , assuming a pit c ould service 5 operations per year and 25 operation s 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 th e 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 us ing 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 f ollowing 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 ca pacity 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 capacit ies . 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, r igid steel tanks are likely to be less costly than pits on

small er and medium volume jobs lasting 14 days (e.g.

, $68,000 and $ 7,200 advantage for jobs with a capacit ies of 10,000 and 3 0,000 bbl , respectively ) and likely to be more costly than pits for higher vo lume jobs (e.g., $53,600 disadvantage for jobs with a capacity of 50,000 bbl)

. For jobs lasting 21 days, r igid 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 Tab le 5B

.

commenter’s value by assigning one

- third of the capital costs to initial construction (year 0) and tw o

- thirds of the capital costs to the take down costs (year 5).

### 73

Table 5B: General E ngineering 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 ( 1 0,000 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

th e 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 threshold s 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 adhere nce to condition of approval s , environmental

consideration s, 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 last ing 14 days, w e est imate th e average incremental cost to be $71,840 per operation that exceeds the threshold of 32,368 bbl

. Assuming job durations last 21 days, w e estimate th e average incremental cost to be $74,400 per operation

that exceeds the threshold of 27,333 bbl

. D ue 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 w ill 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% i n 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) Incre mental 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 voluntar ily. 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 ab out $6,100 for a half

- acre pit and $6,5 20 for an acre pit. 70


### Again, that cost could be spread across multiple hydraul ic fracturing operations and, assuming the pit services 5 completions, the per

- operation cost might be $1,200 to $1,300. However,

accordin g 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 r ules 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 o the r 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 gener al , as is recommended a s 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 co st 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) Incre mental cost per operation (alternative) = $ 6

, 000

Post

- Fractur ing Reporting Requirement: The operator must s ubmit information to the BLM after the hydraulic fracturing operation in a Subsequent Report (SR) Sundry

. The operator must

disclose the chemical s used to the BLM , and it may use FracFocus for that disclosure

. T he

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 respons ible 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 subm it 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, t he 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, t he 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 F racFocus 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 c ircumstances

. (a) Applicability of requirement = 100 % of operations. (b) Cost per requirement = $7 23 . Burden includes the operator burden ($558 per SR Sundry )

and the BLM burden ($16 5 per SR Sundry)

. We estimate that the operator will require 9 hours at about $6 1.99 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.

Varia nce R equests : 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

be cause 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 th at we might

receive fewer variance requests . However, there is still the potenti al 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 = $6 43 . 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 t o be about $14 7 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 ; h owever, 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 complet ion 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 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

.

T he 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 benefit s 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 a re 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 F ederal, 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 provid e 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 cha llenge in monetizing benefits lies in the quantif ication of a baseline risk associated with specific operating practices and in the measurement of the change in that risk

that we can attribute to th e 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 represent ed modern hydraulic fracturing operations nor were we able to distinguish between the risks posed by wells that were hyd raulic ally fractur ed 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

ma y 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 in to other wells. These events have the potential to adversely affect public lands , Indian lands, and other important resources.

The re are several limitation s in using these data

. First, the data do not specify whether the

undesirable events occur in c onjunction 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 fo r 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 cost s 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 variabl e 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 requ ire 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 opera tor would lose revenue and society would not benefit

from th e produced resources.

The following is an example of an event that occurred in 2012 when a hydraulic fracturing operation on one F ederal well affected another F ederal well. The incident occurred on November 20, 2012, in Lea County, New Mexico. 74 

### The fr acture 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. T he open top fiberglass tank overflow ed 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 ha d 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 9 th 

### stage of a n 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 remediatio n 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 ev ent, 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 ma y 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 r ange 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 im pacts , 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 w ebsite (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 p resent value associated with the stream of costs and benefits.

For this analysis, we expect that the po tential incremental costs posed to an operation will occur within a short timeframe, starting generally with the APD submission and ending with the

Su bsequent 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 operation s on F ederal 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 uppe r bound estimate which should constrain

the costs.

 Delays and costs associated with the CEL on the intermediate casing. Sources of uncertainty are : (1) T he prevalence by which the operator will run a log on the intermediate casing as a matter of practice ; and (2) T he 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 overestimate d

.

 Benef its 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 near

term 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 expe ctations 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. 1 1 times higher than we anticipate, or about 8 ,7 6 5 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 st ate 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 above

ground 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 , w e estimate that the compliance with the storage tank requirement could cost an operator $7 4

, 40 0 ( represent ing approxim ately 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. The se operations are those where the volumes of recovered fluids are expected to be very high and typically oc cur 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 t o 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 20 15

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 Federa l 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

M any 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 cons istent with industry practice or state regulations, there will not be an incremental cost. There are two requirements in particular that may pose relatively large r 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 tha t states or that the BLM may specify this as a condition of approval even if it is not in reg ulation. 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

us e storage tanks, which indicates that they may be d oing so voluntarily

. We estimated the voluntary use of storage tanks in states that do not have regulations requiring their use. Still, i n some areas, our field observations indicate that the use of storage tanks is higher than the estimated voluntary com pliance. 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 b etween 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 7 A: 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 overs tated . 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 tank s (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 cos ts 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 cert ain 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, t he administrative burden represents about $1, 4 50

. We estimate that the operator w ill assume about $ 1, 118 and the BLM will assume $ 3 31

of that amount

. The administrative burden fig ures are in Tables 11A and 11B.

We note that the per

- operation compliance costs an d administrative burden are calculated by dividing the tot al 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 $3 31 per HF operation). Th e 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. T he review of information associat ed 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.

Th is estimated admini strative 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

pro visions 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 BL M 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 an d 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 Post

Fracture 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 Post

Fracture 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) Post

Fracture 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) Post

Fracture 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

Total Applications 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, intermedi ate 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 ca sing, 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 limi ts 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 witn esses 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 es timate 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 co st to operators. We estimate that the initial proposal would have posed about $1 66

- $3 59 million in annual incremental costs to operators. Delays in the drilling

process would have been the primary cost s , 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 $1 3

- $2 9 million in annual incremental costs to operators. This estimate accounts for delays in the drilling process for type wells, which we estimate would

repre sent 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

th e 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 flo wback 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 alternative s 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 l ined 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 detecti on 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,

distributi on, 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 f actors. 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 believ e 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, compet itiveness, 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 m ake a one

time installation of a mitigation control feature. In addition, operators would be required to perform administrative tasks related to a one

- time event.

Compliance with few of the operational requirements is expected to pose an additional cos t to the operator and is likely t o shift resources from firms in the crude oil and natural gas extrac tion industries (NAICS codes: 211111

- Crude Petroleum and Natural Gas Extraction, 211112

- Natural Gas Liquid Extraction) to firms providing support servi ces 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 an d 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

inv estment 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 sectors 77 

### are small businesses in tha t 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 expenditur es (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, th e 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 cos ts to entity net incomes.

The firms most likely to be affected by the rule are those conducting hydraulic fracturing

activities on F ederal and Indian lands. More specifically, the firms most impacted are expected to be those drilling new wells for hydrau lic 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 Petr oleum 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 incom es, and vice versa. Averaging results for the small businesses that we

examined , the average costs of the rule are expected to represent about 0. 1 5 percent of the company net incomes. The results of those findings are in Table 1 3 and also in the Appendix

.

Table 1 3 : 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% 0.19 5 % 0.147%

Average 27,566,704 0.005% 0.008% 0.006%

Minimum value

- 228,063,000

- 0.85 8 %

- 1.2 60 %

- 0.95 4 %

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 a pproved 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 oper ations 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

fr om 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. T he BLM expects that the costs of comp liance 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 expens ive 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 ar ising 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 h ave 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 B usiness 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

o f 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 For m 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 s mall 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 o f 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 econ omy 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 geog raphic regions; or have s ignificant 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 r ule does not contain a F ederal 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, th e 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 ap ply 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 o n energy supply , distribution, or use (including a shortfall in

### 100

s upply, 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 t he 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 o il 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 acti on” as defined in Executive Order 13211.

### 101



## 7. Conclusion

Combined with horizontal drilling, hydraulic fracturing has grown in significance over the past decade, al lowing 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 sub surface 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 t hat 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 ac tivity confirm that operators take prompt action to repair defective cementing jobs.

The BLM has an existing regulation on hydraulic fracturing that w as promulgated before hydraulic fracturing technology was combined with horizontal drilling technology t o become the prevalen t and large

- scale operations that they are today. The BLM’s existing regulation require s 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.

Th is 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 h elp 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 w ill 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 rul e as a matter of standard industry practic e, to comply with other state and F ederal 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 econo mic 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 operation s 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 betwe en the deepest usable water zone and the hydraulic fracture zone. A lthough industry guidance does not specifically address this scenario , we believe that the rule’s

the requirements are consistent with industry practice.

We estimate that the rule will imp act 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 $ 11,40 0 per well, or between about $ 3 2 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 pr actice, 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 challe nging 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 risk s 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 Fr acturing 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.eene ws.net/energywire/2012/10/01/archive/1?terms=hydraulic+fracturing+10

%2F01%2F2012

Bureau of Land Management (1998). On shore 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/b lm/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

- to

mo ve

- 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 Subcomm ittee Second Ninety Day Re port. 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 Piv otal 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

h ttp://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 a nd 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

A LASKA 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)

Total Costs

Applicability Unit cost Subtotal

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)

Total Costs

Applicability Unit cost Subtotal

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)

Total Costs

Applicability Unit cost Subtotal

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