# Economic Analysis for Hydraulic Fracturing Rule

U.S. Bureau of Land Managementi



### Table of Contents

1. Introduction

................................ ................................ ................................ ................................ ........... 1

2. Background

................................ ................................ ................................ ................................ ........... 3

2.1 Requirements for Economic Analysis

................................ ................................ .............................. 3

2.2 Need for Policy Action

................................ ................................ ................................ .................... 5

2.3 Summary of the Rule

................................ ................................ ................................ ....................... 8

2.4 Consideration of Alternative Approaches

................................ ................................ ........................ 9

2.5 Alternatives to Direct Regulation

................................ ................................ ................................ .. 11

2.6 Federal and Indian Oil and Gas Leasing Activity

................................ ................................ .......... 12

2.7 Industry Classifications

................................ ................................ ................................ .................. 15

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

..... 17

2.9 Industry Standards for Water Management Associated with Hydraulic Fracturing

...................... 20

2.10 Existing Regulations Related to the Rule’s Provisions

................................ ............................. 21

2.10.1 Existing BLM Regulations on Cementing Requirements

................................ ................. 21

2.10.2 Existing BLM Regulations on Pressure Testing Requirements

................................ ........ 22

2.10.3 Summary of Existing State Regulations

................................ ................................ ........... 22

3. Estimating Benefits and Costs

................................ ................................ ................................ ............ 27

3.1 Theoretical Framework

................................ ................................ ................................ .................. 27

3. 1.1 Measuring the Incremental Change

................................ ................................ ....................... 27

3.1.2 Costs Framework

................................ ................................ ................................ .................. 28

3.1.3 Benefits Framework

................................ ................................ ................................ .............. 33

3.2 Data

................................ ................................ ................................ ................................ ................ 35

3.3 Discounted Present Value

................................ ................................ ................................ .............. 47

3.4 Uncertainty

................................ ................................ ................................ ................................ ..... 48

3.5 Changes in the Economic Analysis from the Initial Proposed Rule

................................ .............. 49

4. Results

................................ ................................ ................................ ................................ ................. 50

4.1 Costs of the Revised Proposed Rule and Alternatives

................................ ................................ ... 53

4.2 Average Compliance Costs for Operators

................................ ................................ ..................... 62

4.3 BLM Administrative Burden

................................ ................................ ................................ ......... 63

4.4 Benefits of the Revised Proposed Rule and Alte rnatives

................................ ............................... 64

5. Economic Impact Analysis and Distributional Assessments

................................ .............................. 66ii

5.1 Energy System Impact Analysis

................................ ................................ ................................ .... 66

5.2 Employment Impact Analysis

................................ ................................ ................................ ........ 68

5.3 Small Business Impact Analysis

................................ ................................ ................................ .... 68

6. Statutory and Executive Order Reviews

................................ ................................ ............................. 70

6.1 Executive Order 12866 Regulatory Planning and Review

................................ ............................ 70

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

U.S.C. 601

- 612)

................................ ................................ ................................ ................................ ...... 70

6.3 Unfunded Mandates Reform Act of 1995 (P.L. 104

- 4)

................................ ................................ . 71

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

Distribution, or Use

................................ ................................ ................................ ................................ . 71

7. Conclusion

................................ ................................ ................................ ................................ .......... 73

8. References

................................ ................................ ................................ ................................ ........... 76

9. Appendix

................................ ................................ ................................ ................................ ............. 781



### 1. Introduction

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

drilled on Federal and Indian land s are stimulated using hydraulic fracturing operations

. Hydraulic fracturing is a well completion technique that involves sequentially pumping a fluid mixture down the well and into the target formation at high enough pressures to cause the rock within the target formation to fracture. In the fracturing proces s, 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 ab ility 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 t he 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 exac t formulation of the fluid varies depending on the service provider, rock formations, the well, and the requirements of the operator.

The increased use of hydraulic fracturing over the last decade has generated concerns from the public about surface and subsurface water quality and resources, including heightened calls for improved environmental safeguards for surface operations and the disclosure of chemicals and materials used in fracturing fluid. The BLM hosted public forums in 2011 where panelists an d the audience expressed support for improved surface operations and the disclosure of fracturing fluid components. The Secretary of Energy's Advisory Board Subcommittee on Natural Gas has also recommended public disclosure of the chemicals used in fractu ring fluids, broader use of water quality sampling before drilling new wells, and progressive standards for wellbore

construction. A number of states have passed legislation requiring the disclosure of fracturing

fluids or have updated standards for well construction

.

With this rule, t he BLM would update its existing regulations on hydraulic fracturing . The rule would require operators to submit a Notice of Intent (NOI) Sundr y prior to hydraulic fracturing operations. It wou ld require operators to conduct cement evaluation l og s (hereafter referred to as

a CEL or CEL s) on c asing string s that protect usable water and perform mechanical integrity

tests (or pressure tests) prior to hydraulic fracturing operations . It allows oper ators proposing hydraulic fracturing on a group of wells in the same geologic area to submit one NOI Sundr y and

cement evaluation logs for a type well. The rule would require operators to monitor pressures during hydraulic fracturing operations and to use storage tanks or lined pits to manage flowback

fluid . Finally, it would require operators to submit a Subsequent Report (SR) Sundr y after each hydraulic fracturing operation . The SR Sundry would include information about the operation,

certification tha t wellbore integrity was maintained, and disclosure of the chemical content of the hydraulic fracturing fluid used. The rule allows for chemical disclosure to the BLM through

FracFocus.

Many of the requirements above are currently conducted by operators as a matter of standard industry practice or in compliance with existing state regulations and/or other BLM regulations2

and requirements. As such, for many of the requirements, t he rule does not pose an additional burden to operators . However, there are some requirements that do pose an additional burden

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

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

. As a

result of the comments it received from the public , the BLM made changes to the proposed regulations, and likewise, to the accompanying economic analysis.

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

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



### 2. Background

2.1 Requirements for Economic Analysis

By statute and executive order, an agency proposing a significant regulatory action is required to provide a qualita tive and quantitative assessment of the anticipated costs and benefits of that action. Executive Order 12866 requires agencies to assess the benefits and costs of regulatory actions, and for significant regulatory actions, submit a detailed report of thei r 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 a ction taken or planned by another agency; Materially alter the budgetary impact of entitlements, grants, user fees, or loan programs or the rights and obligations of recipients thereof; or Raise novel legal or policy issues arising out of legal mandates, the President’s priorities, or the principles set forth in the Executive Order.

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

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

prop osed action; The potential benefits to society justify the potential costs, recognizing that not all benefits and costs can be described in monetary or even in quantitative terms, unless a statute requires another regulatory approach; The proposed action w ill maximize net benefits to society (including potential economic, environmental, public health and safety, and other advantages; distributional impacts; and equity), unless a statute requires another regulatory approach; Where a statute requires a specif ic regulatory approach, the proposed action will be

the most cost

- effective, including reliance on performance objectives to the extent feasible; and Agency decisions are based on the best reasonably obtainable scientific, technical, economic, and other in formation.

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

three elements 1 :

A statement of the need for the proposed action; An examination of alternative approaches; and An analysis of benefits and costs

.

1 OMB Circular A

- 4.4

When an agency publishes a general notice of proposed rulemaking, 5 U.S.C. 603 requires the agency to perform an initial regulatory flexibility analysis and make it available for public comment. The analysis must describe the impact of the rule on sma ll entities and contain the following information:

Description of the reasons why action by the agency is being considered; Succinct statement of the objectives of, and legal basis for, the proposed rule; Description of and, where feasible, an estimate of the number of small entities to which the proposed rule will apply; Description of the projected reporting, recordkeeping and other compliance requirements of the proposed rule, including an estimate of the classes of small entities which will be subject t o the requirement and the type of professional skills necessary for preparation of the report or record; and Identification, to the extent practicable, of all relevant Federal rules which may duplicate, overlap or conflict with the proposed rule.

The in itial regulatory flexibility analysis should also contain a description of any significant alternatives to the rule which would accomplish the stated objectives but which would minimize any significant economic impact of the rule on small entities.5



### 2.2 Need for Policy Action

Subject Reports and Recommendations

For a more detailed discussion of the environmental impacts associated with hydraulic fracturing and on the effects of this rule on the environment, please refer to the Environmental Assessment. Part of that document appears below

.

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

likelihood that hydraulic fracturing fluids pumped into deep geologic formations m igrate into

shallower freshwater fo rmations. Thus far, there have been no conclusive determinations made regarding claims that hydraulic fracturing fluids are the primary source of contamination to shallower freshwater formations. Most reports involve instances of abnormally high

concentr ations 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 2 and in 2012 3 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. Th e 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 i ndicated that the movement of gas

- rich solutions within the shale formations up into shallow drinking

- water aquifers is the most unlikely possibility. This is due primarily to the extensive distance between the shale formations and the shallow aquifers as well as high underground pressures exerted against the deep shale formations. The most likely possibility for gas contamination would be from leaky gas

- well casings. These leaks could occur at hundreds

of feet underground, with methane passing laterally through the well casing and vertically through fracture systems. There is also a possibility for gases to migrate through fractures above the shale formation that is created or enlarged as a result of hydraulic fracturing and thus expanding the overall u nderground fracture system. These new fractures could potentially relieve the pressures exerted against these gas

- rich solutions, which would allow the gas to come out of solution and migrate through the fracture system and potentially into shallow aquife rs or improperly plugged wells. However, these researchers have indicated that this possibility is

unknown.

2 Osborn et al (2011)

. 3 Warner et al (2012).6

The focus on fluid or gas migration is only one aspect of potential damage. According to the U.S. Environmental Protection Agency (EPA) , there ar e other potential impacts, including s tress on surface water and ground water supplies from the withdrawal of large volumes of water used

in dri lling and hydraulic fracturing, c ontamination of underground sources of drinking water and

surface waters result ing from spills, faulty well c onstruction, or by other means, and a dverse impacts from discharges into surface waters or from disposal into underground injection wells. 4

At the President’s direction, the Secretary of Energy’s Advisory Board convened a Na tural Gas Subcommittee to evaluate hydraulic fracturing issues. The subcommittee met with industry, service providers, state and Federal regulators, academics, environmental groups, and many others stakeholders. Initial recommendations were issued by the subcommittee on August 18, 2011. Among other things, the report recommended that more information be provided to the public, including disclosure of the chemicals used in fracturing fluids. The subcommittee also recommended the adoption of progressive s tandards 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, cementi ng, 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 defe ctive cementing jobs. The regulation of shale gas development should include inspections at safety

critical stages of well construction and hydraulic fracturing.” 5

Public Concern

The public and other groups have expressed strong concerns about the prevalence of hydraulic fracturing and the chemical content of the fluids used in the process. As a follow

- up to the Department of the Interior (DOI) forum on hydraulic fracturing on 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.

4 EPA 2012. “Natural Gas Extraction

– Hydraulic Fracturing.”

5 SEAB 2011, pp. 16

- 17. Available at http://www.shalegas.energy.gov

.7

Improving Government al Processes

The BLM has existing regulations for hydraulic fracturing, found in 43 CFR 3162.3

- 2. Under that regulatory provision, an operator must seek approval from the BLM before perform ing

“non

- routine ” fracturing operations. Conversely, an operator performing “routine” fracturing operations does not need the BLM’s approval. The regulations make a distinction between

“routine” and “non

- routine” fracturing operations, but it does not clearly define them. This omission makes the distinction functionally difficult to apply and confusing for both the agency

and the regulated public.

Also

, h yd raulic fracturing operations conducted now are vastly different than the operations conducted decades ago. Due to advances in horizontal drilling, hydraulic fracturing operations

are conducted on wells with longer lateral legs and require larger volumes o f water. The chemical content of the hydraulic fracturing fluids is also a growing concern to the public, such that many state regulatory authorities now require the chemical disclosure of fracturing fluids. The information that the BLM currently require s before and after fracturing operations is inadequate and does not reflect the complex nature of the operations.

As the resource manager, the lack of information restricts the BLM’s ability to make informed resource decisions about proposed hydraulic fracturing operations. It also restricts the BLM’s ability to respond effectively to events where environmental resources have been compromised. Knowing the hydraulic fracturing plans and designs and the ingredients of fracturing fluids used will help th e BLM better manage and protect the public’s resources. From a resource management perspective, the current regulation results in incomplete information being provided

to the BLM.

Externalities

Generally, there is greater potentia l for undesirable events or incidents to occur when operations are conducted in wells that are inadequately constructed, where the plans are inadequate, and when the fluids are not properly managed. This potential extends to hydraulic fracturing operations, where greater p ressures are placed on the well, drilling may extend laterally and for longer distances, and larger volumes of fluids are used and received as flowback

. If and when these events occur, there is the potential that they may pose a negative externality to so ciety, considering limitations in understanding the extent of damage or determining a causal relationship between the hydraulic fracturing operation and the damage.

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

i nadequately constructed may not sufficiently isolate well fluids from the subsurface water resources or may be more likely to fail during fracturing operations. Although wellbore integrity provisions exist in current BLM regulations, this rule would enhan ce those provisions to account for advances in technology and hydraulic fracturing operations . In addition, the chemical composition of hydraulic fracturing fluid may pose additional risk to the subsurface and surface environments if not managed and dispo sed of properly.8



### 2. 3 Summary of the Rule

The r ule would require operators to do the following with regards to hydraulic fracturing operations :
Submit a Notice of Intent (NOI) Sundry for approval prior to the commencement of hydraulic fracturing operations. The NOI Sundry will include information relevant to the hydraulic fracturing plans. If an operator plans to conduct hydraulic fracturing operations

on multiple we lls in a geographic area with the same geologic characteristics, it may submit o ne NOI Sundry for a group of wells based on plans for a type well.

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

water. If an operator plans to conduct hydraulic fracturing operations on multiple wells in a geogra phic area with the same geologic characteristics, it must conduct a cement evaluation log on the casing strings protecting usable water on the type well to demonstrate that the cementing operations of the type well resulted in proper cement bonding . The o perator may then use those results to indicate prop er cementing of the subsequent wells, as long as the cement operations monitoring data from the subsequent

wells do not indicate any problems. When an operator encounters a problem during the cementing pr ocess that indicates that a proper cement bond may not have been achieved , it must n otify the BLM, perform remediation activities, run a cement evaluation log, and certify that it correc ted all issues before conducting the hydraulic fracturing operation.

C onduct mechanical integrity test s prior to hydraulic fracturing.

Use storage tanks or lined pits when managing flowback

. M o nitor the hydraulic fracturing operations.

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

occurs (even if the operator submitted one NOI Sundry for hydraulic fracturing on a group of wells) . The SR Sundry will include information about the completed hydraulic fracturing operation. The o perator will disclose to the BLM the chemical components of the hydraulic fracturing fluids used , but the operator may do so in directly through

FracFocus . The operator will also certify that wellbore integrity was maintained prior to and during the hydrau lic fracturing operation

, that the chemicals used complied with all applicable laws , and that the operator managed all of the flowback in storage tanks or lined pits . The operator will submit documentation that supports the certification on wellbore integ rity.9



### 2 .4 Consideration of Alternative Approaches

In developing the rule, the BLM considered several alternatives. The alternatives primarily focused on two topic areas: verification of proper cementing behind casing strings through CELs and the management of flowback fluids from operations.

As a matter of standard industry practice, operators conduct a CEL (which may include a cement bond log or CBL ) on the production casing and, in some cases, on the intermediate casing when

intereste d in formations above the target zone . State regulations or conditions of approval (COA) for permits may also require operators to run logs on the intermediate or production casings. Also, operators may run a CEL or a temperature log on the surface casin g when the cement fails to return to the surface or there is some other indication of a problem with the cementing.

We examine d requirements for operators to conduct cement evaluation logs on:

C asing strings protecting usable water zones (including surface and intermediate casing s ) for all wells; and Casing strings pr otecting usable water zones , but allowing operators to use results from a type well to demonstrate proper cementing for subsequent wells in an area with the same geologic cha racteristics

.

Each of these scenarios would require the operator to conduct the CEL during the drilling of the well and, thus, prior to the hydraulic fracturing operation. However, both scenarios would require the operator to submit the results of the CE L with the Subsequent Reports Sundry after the hydraulic fracturing operation (unless the CEL is run to demonstrate successful corrective action). The BLM had considered requiring the submission of the CEL results prior to the hydraulic fracturing operati on for BLM’s approval. However, the BLM ultimately determined that such a requirement might create permitting delays and unintended costs to operators.

We also considered various approaches for the management of flowback from operations. Currently, stat e regulations ser ve as the standard in each particular state, but the BLM may address requirements in individual permits as long as the state standard is met or exceeded. 6
California require s the use of storage tanks while most other states have various requirements for lined pits. New Mexico enacted regulations requiring closed

- loop systems in 2008, but proposed a rule in 2012 that would allow for the use of lined pits. With this in mind, w e examine d the following requirements for operators to manage the flowback from operations: Use of storage tanks or lined pits;

Use of storage tanks; and

N ot establish requirements and thereby defer to state regulations

.

A lternative 1: Requires C E Ls on casing strings protecting usable water for all wells ; r equires the use of storage tanks to manage flowback.

6 The BLM has regulations for the disposal of produced water (different from flowback from hydraulic fracturing operations) in Onshore Oil and Gas Order No. 7. It specifies design requirements for lined pits and procedures for requesting approval to use un lined pits.10

Alternative 2: Requires CELs on casing strings protecting usable water for all wells ; does not establish requirements for storage tanks or lined pits.

The potential costs and benefits of each alternative are presented in Section 4 of this document. The costs and benefits, where appropriate, are broken out by activity or requirement, such that costs and benefits of further alternatives may be inferred, beyond those packaged as Alternative

1 or Alternative 2.11



### 2. 5 Alternative s to Direct Regulation

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

pr inciples 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 p ermits, or providing information upon which choices can be made by the public.”

The use of economic incentives, such as user fees or marketable permits, is not a good option for this particular subject area. User fees are monies paid to the government to recover the costs of providing the regulatory good or service or for access to t he resource. Marketable permits provide efficiencies when the compliance costs vary by producers, such as when there are efficiency gains in having certain producers attain more of the emissions reductions, but be compensated otherwise, through the sale o f pollution allowances to other producers where reductions are more costly than the price of a permit. This is not the case with the requirements in the subject rule . The unit costs of the requirements do not vary significantly across wells or producers. Also, a unit of potential environmental degradation and remediation costs are not uniform across wells, events, and geographic areas (unlike, for example, a ton of CO 2 which disperses in the atmosphere).

The rule promotes performance standards rather than design standards. It does not prescribe a single cement evaluation tool or process, but allows for the operator to determine the appropriate log based upon factors which may include the geology, downhole conditi ons, drilling plans, operator or service company experience, and advances in technology.

T he r ule also include s a provision that allows an operator to request a variance if it can attain the same standards established by the regulation but in a different manner. The BLM would consider alternatives if an operator could show that the objectives of the rule would be met using

an alternate a pproach. The variance request would be subject to BLM approval. From an efficiency standpoint, variances are important because they allow operators to use technology or other improvements to meet requirements in a more efficient or cost effective manner. This analysis does not quantify the benefits or costs of this provision; however, the provision would likely increase the net benefits of the proposal by reducing the costs.

The 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 Circular A

- 4 states that “a

regu latory measure to improve the availability of information, particularly about the concealed characteristics of products, provides consumers a greater choice than a mandatory product standard or ban.” While consumers of resources produced by hydraulic frac turing cannot differentiate products downstream based upon the upstream conditions, the availability of

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

make informed d ecisions in other respects.12



### 2. 6 Federal and Indian Oil and Gas Leasing Activity

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

the Federal G overnment. There were 48,699 Federal oil and gas leases covering 37,792,212 acres at the end of fiscal year (FY) 201 2 . For FY 201 2 , there were 92,583 producible and

service drill holes and 99,015 producible and service completions on Federal leases. 7 Table 1 shows the number of inspection cases managed by the BLM. Most of thes e cases involve more

than one well.

Table 1: Federal and Indian Oil and Gas Cases 8

Producing Non

- Producing

FY 2010

Federal Cases 19,995 3,523

Indian Cases 2,576 392

Total Cases 22,571 3,915

FY 2011

Federal Cases 21,278 5,417

Indian Cases 2,879 493

Total Cases 24,157 5,910 Source: BLM, Automated Fluid Mineral Support System (AFMSS),

FY

- 201 1 Inspection and Enforcement Strategy

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

Natural Resources Revenue (ONRR) though the figures cited below were originally reported by the Minerals Management Service or the Bureau of Ocean Energy Management, Regulation

, and

Enforcement.

Table 2 shows the sales volume, sales value, and royalty generated from Federal and Indian oil and gas production in 2012. For FY 201 2 , onshore Federal oil and gas leases produced about

118 million barrels (Bbl) of oil, 2. 81 billion Mcf (thousand cubic feet) of natural gas, and 2. 84 billion gallons (Gal) of natural gas liquids, with a p roduction value of almost $23 billion and generating royalties of almost $ 2.6 billion. Oil and gas production from Indian leases was

almost 29 million barrels of oil, 25 6 million Mcf of natural gas, and 1 55 million gallons of natural gas liquids, with a p roduction value of $ 3.4 billion and generating royalties of $ 561

million for the Indian mineral owners

.

Figure 1 illustrates the oil and gas activity on federally

- administered lands in the Western U.S.

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

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

2012 is still under review.13

Table 2: Federal and Indian Oil and Gas Production and Royalties, Fiscal Year 201 2

Sales Volume Sales Value

($ million ) Royalty

($ million )

Federal Leases Oil ( B bl) 118,142,826 $ 10,442 $ 1,275 Gas (Mcf) 2, 806

, 572,692 $ 9,258 $ 976 NGL (Gal) 2,839,924,280 $2, 947 $ 298

Subtotal $ 22,648 $ 2,550

Indian Leases Oil ( B bl) 28,989,309 $ 2,441 $ 424 Gas (Mcf) 256,176,345 $ 762 $ 116 NGL (Gal) 155,313,421 $ 183 $ 21

Subtotal $ 3,386 $ 561
Source: ONRR, Federal Onshore Reported Royalty Revenue, Fiscal Year 201 2 and American Indian Reported Royalty Revenue, Fiscal Year 201 214 Figure 1:15



### 2. 7 Industry Classifications

Most crude oil and natural gas entities are classified under North American Industry Classification System (NAICS) 211. This rule directly affects entities classified within the Crude Petroleum and Natural Gas Extraction (211111), Natural Gas Liquid Extraction (211112), and the Drilling of Oil and Natural Gas Wells (213112) industries. Other industries 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 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 o f supplies, 78 percent of the total capital expenditures (excluding land and mineral rights), and 67 percent of the paid employees (see Tables 3 through 7).16

Note: Where range provided, employee data were estimated to be in middle of range Table 3 : Number of Firms by Firm Size and NAICS, 2007

NAICS NAICS Description SBA Size

Standard All Firms < 20 Employees 20

- 99

Employees 100

- 499

Employees > 500

Employees

211111 Crude Petroleum and Natural Gas

Extraction 500 5,964 4,905 820 197 42

211112 Natural Gas Liquid Extraction 500 296 171 114 11 0

213111 Drilling Oil and Gas Wells 500 2,109 1,454 439 180 36

Total firms 8,369 6,530 1,373 388 78
Percent of total 78.03% 16.41% 4.64% 0.93%

Table 4 : Total Value of Shipments and Receipts for Services ($1000) by Firm Size and NAICS, 2007

NAICS NAICS Description SBA Size

Standard All Firms < 20 Employees 20

- 99

Employees 100

- 499

Employees > 500

Employees

211111 Crude Petroleum and Natural Gas

Extraction 500 212,783,171 27,779,989 63,673,010 58,879,619 62,450,553

211112 Natural Gas Liquid Extraction 500 42,321,678 6,920,098 27,110,810 8,290,770 0

213111 Drilling Oil and Gas Wells 500 22,512,322 631,501 4,011,228 8,382,350 9,733,440

Total firms 277,617,171 35,331,588 94,795,048 75,552,739 72,183,993
Percent of total 12.73% 34.15% 27.21% 26.00%

Table 5 : Total Cost of Supplies ($1000) by Firm Size and NAICS, 2007

NAICS NAICS Description SBA Size

Standard All Firms < 20 Employees 20

- 99

Employees 100

- 499

Employees > 500

Employees

211111 Crude Petroleum and Natural Gas

Extraction 500 37,755,041 5,709,734 11,650,183 12,335,810 8,059,314

211112 Natural Gas Liquid Extraction 500 31,129,919 4,858,309 19,948,706 6,322,904 0

213111 Drilling Oil and Gas Wells 500 6,576,675 246,328 1,012,247 2,567,116 2,027,623

Total firms 75,461,635 10,814,371 32,611,136 21,225,830 10,086,937
Percent of total 14.33% 43.22% 28.13% 13.37%

Table 6 : Total Capital Expenditures (except land and mineral rights) ($1000) by Firm Size and NAICS, 2007

NAICS NAICS Description SBA Size

Standard All Firms < 20 Employees 20

- 99

Employees 100

- 499

Employees > 500

Employees

211111 Crude Petroleum and Natural Gas

Extraction 500 87,551,089 9,714,838 26,003,272 33,504,207 18,328,772

211112 Natural Gas Liquid Extraction 500 1,965,593 513,229 1,058,819 393,545 0

213111 Drilling Oil and Gas Wells 500 6,532,941 157,959 1,049,920 2,519,731 2,013,806

Total firms 96,049,623 10,386,026 28,112,011 36,417,483 20,342,578
Percent of total 10.81% 29.27% 37.92% 21.18%

Table 7 : Number of Paid Employees by Firm Size and NAICS, March, 2007

NAICS NAICS Description SBA Size

Standard All Firms < 20 Employees 20

- 99

Employees 100

- 499

Employees > 500

Employees

211111 Crude Petroleum and Natural Gas

Extraction 500 143,054 23,928 34,791 37,717 33,454

211112 Natural Gas Liquid Extraction 500 7,389 1,014 4,907 1,468 0

213111 Drilling Oil and Gas Wells 500 106,859 6,375 20,122 41,616 37,420

Total firms 257,302 31,317 59,820 80,801 70,874
Percent of total 12.17% 23.25% 31.40% 27.55%17



### 2. 8 Industry Standards for Well Construction and Integrity for Hydraulic Fracturing Operations

The American Petroleum Institute (API) published guidance on well construction and integrity for hydraulic fracturing operations in October 2009 (API Guidance Document HF1)

. 9 Topics covered in the guidelines include

, but are not limited to

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

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

because of varying geologic, environmental, and operational settings, the basic practices in constructing a reliable well are similar. These practices are the result of operators gaining knowledge based on years of experience and technology development and improvemen t. These experiences and practices are communicated and shared via academic training, professional and trade associations, extensive literature and documents and, very importantly, industry standards and recommended practices.” 10

Well Integrity and Protect ing 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 prod uction wells. Maintaining well integrity is essential for the two following reasons: 1) To isolate the internal conduit of the well from the surface and subsurface environment. This is critical in protecting the environment, including the groundwater, a nd in enabling well drilling and production; and 2) To isolate and contain the well’s produced fluid to a production conduit within the well.” 11

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

contents within the wel l from the groundwater aquifers. “The primary method used for protecting groundwater during drilling operations consists of drilling the wellbore through the groundwater aquifers, immediately installing a steel pipe (called casing), and cementing this ste el pipe into place.... The steel casing protects the zones from material inside the wellbore during subsequent drilling operations and, in combination with other steel casing and cement sheaths that are subsequently installed, protects the groundwater with multiple layers of protection for

the life of the well.” 12

Well Construction

, C ementing Guidanc e , Pressure Testing

, and Logging

Well design and construction generally have four components: conductor, surface, intermediate and production casing strings. T he following discussion provides a general description of the drilling process as it relates to drilling, setting casing, cementing casing, pressure testing, and well logging.

9 API Guidance Do cument HF1 “Hydraulic Fracturing Oper ations

– Well Construction and Integrity Guidelines.”

10 Ibid, p. 1.

11 Ibid, p. 1.

12 Ibid, p. 2.18

After the conductor pipe is installed and cemented, operators drill the surface hole to a predetermined length “based on consideration of the deepest groundwater resources

. ” 13 Some

s tate regulations dictate the minimum setting depth of surface casing , but the minimum recommended API standard is at least 100 feet below the deep est underground sources of drinking water (USDW) encountered. The operator will run the surface casing into the hole and cement the casing in place. The API recommends that operators cement the surface casing “from bottom to the top, completely isolating groundwater aquifers.” 14

After waiting for the cement to r each “ appropriate compressive stre ngth, ” 15 the operator should

pressure test (commonly known as a casing pressure test) the surface casing. This test should be conducted at a pressure that will d etermine if the casing integrity is adequate to meet the well design and construction objectives. The BLM and many states have regulations that dictate requirements for pressure tests. 16

After a successful pressure test, the operator will drill out of the surface casing and for a short interval into a new formation below the surface casing shoe. The operator should then perform a formation pressure integrity test (also known as a ‘shoe test’ or ‘leak

- off test’). “ If the test results of the formation pres sure integrity test are inadequate, remedial measures should be undertaken as appropriate.” 17

The operator will then drill an intermediate hole

, run casing , and cement the casing as appropriate . The goal is to “isolate subsurface formations that may cause borehole instability and to provide protection from abnormally pressured subsurface formations.” 18 According to the guidance, intermediate casing may not be required in some cases, and that operators may not need to cement the intermediate casing back to the surface in many cases. It states that “if the intermediate casing is not cemented to the surface, at a minimum, the cement should extend above any exposed USDW or any hydrocarbon bearing zone.” Operators may run a CEL and/or other diagnostic tools to determine the adequacy of the cement integrity and that the cement reached the desired height. After the cement has achieved the appropriate compressive strength, operators will also pressure test the intermediate casing, drill out for a short interval, and perform a formation integrity test. If the test results of the formation pressure integrity test are inadequate or indicate a failure, remedial measures should be undertaken as appropriate.

Operators will then drill the production hole, log the hole, run production casing to the total depth, and cement the production casing into place. “The purpose of the production casing is to provide the zonal isolation between the producing zone and all other subsurface formations, for pumping the hydraulic fract uring fluids and other stimulation techniques from the surface into the producing formation without affecting any other geologic horizon in the well.” 19 Cementing of the production casing must occur, but it may take different forms. The API guidance state s

13 Ibid, p. 11.

14 Ibid, p. 11.

15 Ibid, p. 11.

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

17 API Guidance Document HF1 , p. 11.

18 Ibid, p. 12.

19 Ibid, p. 12.19

that the production string cement does not need to be run to the surface in most cases; however, in wells where there is no intermediate casing, cementing to the surface should be considered. It describes the minimum standard as running the cement to at least 500 feet above the highest formation where the operator will conduct hydraulic fracturing. Operators should pressure test the production casing and run a CBL and/or other diagnostic tools to determine the adequacy of the cement integrity and that t he design and construction objectives were met

.

In horizontal wells, operators may choose an “open

- hole” completion as an alternative to setting the casing through the producing formation to the total depth of the well. In this case, the bottom

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

- hole section of the well. The producing portion of the well is the horizontal portion of the hole and it is entirely in the producing formation. Sometimes an operator will inst all a short section of casing that runs up the production casing

, but not back to surface nor to the bottom of the open hole section

. An operator may also choose to use a production liner which is not cemented into place. A production liner is a slotted or perforated steel casing installed in the production hole

. With an

open

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

formation

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

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

Source: API Guidance Document HF1, 2009

20 Ibid, p. 13.20

Well Logging

Well logging is a common practice of operators and may be conducted multiple times while drilling a well. “Well logs are critical data gathering tools used in formation evaluation, well design, and construction. Also, various types of mechanical integrity and hydraulic pressure tests can be used to assess well integrity during the construction of the well.” 21

A cement bond log “measures the presence of cement and the quality of the cement bond or seal between the casing and the formation.” 22 Logs are important in “determining that the well drilling construction is adequate and achieves the desired design obj ectives.” 23 As described above, it is industry practice to run logs on the production casing of wells and sometimes on the intermediate casing of wells. State requirements of conditions of the drilling permit may also necessitate the running of logs on th e intermediate casing.



### 2. 9 Industry Standards for Water Management Associated with Hydraulic Fracturing

The API published guidance on water management associated with hydraulic fracturing in June 2010 (API Guidance Document HF2 ). 24 Topics covered in the guidelines include

, but are not

limited to

, water use and management, obtaining water supply, and water management and disposal

.

Overall, 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.

Operators generally store fluids onsite in tanks or in lined surface impoundments ( or pits ) , prior to the hydraulic fracturing operation. Flowback , or the returned fluids from the operation

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

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

fluids or flowback water, the pits must comply with applicable rules, regulations, good industry practice, and liner specifications. However, it is important to recognize that storage impoundments containing fluids associat ed with fracturing operations will likely contain significantly larger volumes of fluids than from conventional operations. ” 25

21 Ibid, p. 8.

22 Ibid, p. 9.

23 Ibid, p. 10.

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

25 Ibid, p. 18.21



### 2. 1 0 Existing Regulations Related to the Rule’s Provisions

The development and production of oil and gas, including hydraulic fracturing operations, are regulated under a complex set of 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 revised proposed proposed rule. Accordingly, t he 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 Federa l 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 frac turing 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 compliance with the stricter of those rules.

Regardless of any d ifference in operational regulations, operators on Federal lands must comply with all Federal, state, and local permitting and reporting requirements. On Indian lands, they must comply with all Federal and tribal permitting and reporting requirements.

2.10.1 Existing BLM Regulations on Cementing Requirements

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

Onshore Oil and Gas Order No. 2

– Drilling Operations on Federal and Indian Oil and Gas

Leases. 26 The provisi ons in Onshore Order No. 2 are consistent with this rule, such that operators drilling in compliance with Onshore Order No. 2 would be in compliance with this rule. An excerpt from Onshore Order No. 2 reads as follows, with emphasis added:

The proposed c asing and cementing programs shall be conducted as approved to protect and/or isolate all usable water zones , lost circulation zones, abnormally pressured zones, and any prospectively valuable deposits of minerals. Any isolating medium other than cement

sh all receive approval prior to use. The casing setting depth shall be calculated to position the casing seat opposite a competent formation which will contain the maximum pressure to which it will be exposed during normal drilling operations. Determination of casing setting depth shall be based on all relevant factors, including: presence/absence of hydrocarbons; fracture gradients; usable water

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

26 43 CFR 3160 III(B), found at http://www.blm.gov/wy/st/en/programs/energy/Oil_and_Gas/docs/onshore_order_2.html

.22 other unusual characteristics. All indicati ons of usable water shall be reported.

2.10.2 Existing BLM Regulations on Pressure Testing Requirements

The BLM has existing pressure testing requirements in Onshore O rder No. 2 that require operators to pressure test all casing strings below the conductor casing ( Onshore Order 2, section III(B)(1)(h))

. Operators must also wait until cement achieves a minimum of 500 psi compressive strength at the casing shoe prior to drilling out ( Onshore Order 2, section III(B)). It also has pressure testing re quirements for liner seals ( Onshore Order 2, section III(B)(1)(b)).

2.10.3 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, Texas, Utah, and Wyoming. In 2011, the number of wellbore s started (or spudded) on F ederal lands in

th os e states accounted for 99.4 percent of the total number of wellbore s started on F ederal lands nationwide. Table 8 shows a summary of the findings.

California

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

“Field Rules” on its website that identify well construction information and requirement s 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 allo wed 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 sta te does not require an operator to obtain a pit permit as long as the sump is “for short

- term use (less than one year) or if significant quantities of hazardous or toxic materials are not present in the mud, fluids and cuttings from drilling and

associated operations” (Section 21565(b)(2)). The state has nine Regional Water Quality Control Boards that may also establish operating procedures. The Central Valley Regional Water Quality Control Board writes that “Produced water may be subject to Title 27 requi rements where the concentration of waste constituents threatens to impact the beneficial uses of good quality underlying groundwater. To comply with Title 27 regulations, the oil field sumps could be lined. However, the industry generally chooses to drill Class II injection wells and close the sumps.” 28 Flowback from hydraulic fracturing operations is likely to be treated like produced

27 California Code of Regulation was accessed on December 9, 2012: ftp://ftp.consrv.ca.gov/pub/oil/publications/PRC04_January_11.pdf

. 28 Groundwater Quality Protection Strategy

- A “Roadmap” for the Central Valley Region at p. 43, August 2010.
Accessed on March 29, 2013: http://www.waterboards.ca.gov/centralvalley/water_issues/groundwater_quality/final_draft_gwq_stra tegy_strike.pdf23

water and manage in lined sumps , if it is not re

- injected

. California has chemical disclosure provisions related to its Sp ill Contingency Plan Requirements (Section 1722.9) in the context of operators maintaining a plan, but the provisions are not for public disclosure.

Colorado

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

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

. ” 29
The COGCC does not require cement evaluation logs on the surface casing. It requires operators to run a cement bond log on all production casing or on the intermediate ca sing, if a production liner is used (Rule 317 ( O ) ). It requires pressure testing of the production casing prior to operations (Rule 317 ( J ) ). The rules also specify that the cement behind the surface and intermediate casing should be allowed to set for a m inimum of 8 hours or until it achieves 300 psi of compressive strength (Rule 317 ( H ) ). Pits must be lined to various specifications (Rule 904). The State has proposed a rule that would require management of flowback in storage tanks (CO House Bill 12

- 1173 ) unless the COGCC permits a lined pit. 30 Operators must disclose chemicals used after the hydraulic fracturing operation (Rule 205A).

Montana

We reviewed Montana’s rules governing oil and gas conservation. 31 We found no sections in the regulation that r equire 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 each casing string) has set for at least 8 hours (36.22.1001(2)). Production strings must be cemented and pressure tested (36.22.1001(1)). The r egulation require s operators to use lined pits or tanks. Specifically, it states, “Waste oil, oil sludge, tank bottoms, merchantable oil, petroleum products,
hazardous wastes, or hazardous or deleteri ous substances must not be stored, disposed of, or retained in earthen storage pits or in open vessels” (36.22.1207). It also requires the chemical

disclosure of well stimulation fluids (Section 36.22. 1015 ).

New Mexico

We reviewed the New Mexico Oil Co nservation Commission (NMOCC) regulations, namely “Chapter 15 Oil and Gas.” 32 We found no sections in the regulation that require operators to conduct cement evaluation logs on any of the casing strings. However, after cementing casing strings and before conducting any tests, the regulations require operators to let the cement stand for a minimum of 18 hours, except in some counties where 8 hours is allowed (19.15.16.10(G)). Operators must pressure test the casing strings (19.15.16.10(I)).

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

. 30 The introduced Colorado House Bill was accessed on March 16, 201 3: http://www.leg.state.co.us/clics/clics2012a/csl.nsf/fsbillcont3/2E1C7B05EB7436E787257981007F436A?open&file =1173_01.pdf

. 31 Montana rules were accessed on December 9, 2012: http://www.mtrules.org/gateway/ChapterHome.asp?Chapter=36.22

. 32 NMOCC rules were accessed on December 9, 2012: http://www.emnrd.state.nm.us/OCD/documents/SearchablePDFofOCDTitle19Chapter15created3

- 2

- 2012.pdf

.24

New Mexico has 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 app roved method (19.15.17.8). The regulations also have disclosure provisions after the well completion (19.15.16.19(B)).

North Dakota

We reviewed the North Dakota Rules and Regulations, particularly Section II General Rules. 33
All strings of surface casi ng must set for at least 12 hours before drilling the plug or initiating tests (43

- 02

- 03

- 21). Each casing string must be pressure tested (43

- 02

- 03

- 21). If any well appears to have defective casing or cementing, the operator must report the defect to the director and must receive approval from the director before attempting remedial work (43

- 02

- 03

- 22). The director is authorized to require a pressure test to verify the casing integrity. The regulations require operators to run cement evaluation logs on t he intermediate and production casings (43

- 02

- 03

- 31).

The regulations have a specific section for hydraulic fracturing operations at 43

- 02

- 03

- 27.1. For hydraulic fractur ing performed through an intermediate casing, an operator must use a cement

evaluatio n log to verify adequate cementing of the intermediate casing (43

- 02

- 03

- 27.1(2)(c)). The intermediate casing and the wellhead must be pressure tested (43

- 02

- 03

- 27.1(2)(d) and (e)).

The rules allow operators to use “lined earthen pits” to temporarily retain oil, water, cement, solids, or fluids generated in well completion, servicing, or plugging operations ( 43

- 02

- 03

- 19.3).

The rules also have a provision for public disclosure to FracFocus ((43

- 02

- 03

- 27.1(1)(g)).

Texas

The Texas Railroad Commissio n (TRC) is the state regulatory authority. 34 The TRC does not appear to have logging requirements on casing strings under normal circumstances. If cement does not circulate to surface behind the surface casing, then the operator must receive approval from the district director for procedures to be u sed to perform additional cementing operations (§3.13(b)(2)(B)). The TRC require s operators to conduct a temperature survey log or cement bond log on the surface casing for alternate casing programs where the cement is not circulated to the ground surface (§3.13(b)(2)(G)(iii))

.

The TRC requires operators to pressure test all strings of casing before drilling the cement plug (§3.13(b)(1)(D)). The TRC prohibits the use of pits for the storage of “oil and gas wastes” and “oil field fluids” (§3.8(d)(2)) ; h owever, an operator may request a permit to use a pit , lined or

unlined

. The TRC requires operators to disclose the chemical content of hydraulic fracturing fluids following the operation (§3.29).

Utah

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

. 34 The Texas Administrative Code for the TRC was accessed on December 9, 2012: http://info.sos.state.tx.us/pls/pub/readtac$ext.ViewTAC?tac_view=4&ti=16&pt=1&ch=3&rl=Y

.25

We reviewed Utah Oil and Gas Conservation rules, p articularly rule R649

- 3, Drilling and Operating Practices. 35 We found no evidence of requirements for operators to run logs to evaluate the cement behind casing strings. The regulations require operators to perform a pressure test on casing before drillin g out of any casing string, suspending drilling operations or completing the well (R649

- 3

- 13 Casing Tests).

Utah has specific regulations regarding hydraulic fracturing at R649

- 3

- 39. The section reiterates provisions described previously. Operators must conduct pressure tests on the well’s casing string set (per R649

- 3

- 13). Utah requires lined pits or storage tanks (R649

- 3

- 16). Operators must disclose the chemicals used to FracFocus after the completion (R649

- 3

- 39(1)).

Wyoming

We reviewed the Wyoming Oil and Gas Conservation Commission (WOGCC) rules, particularly Chapter 3 of the code, titled “Operational Rules, Drilling Rules.” 36 The regulations do not require operators to conduct cement ev aluation logs under normal circumstances. However, th e Supervisor may require operators run “cased hole bond logs” for casing strings to demonstrate cementing across and above the productive intervals or above the last casing shoe in the well, “if there is a demonstrated reason to believe an inadequate cemen t 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 format ion, 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 us e storage tanks or lined pits to

manage flowback (at Section 45(j)) and it requires operators to disclose the contents of hydraulic fracturing fluids proposed for the operation (Section 45(d)) and, after the operation, the contents of the fluids actually u sed (at Section 45(h)).

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

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

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

State Percent of

wellbore s started on

F ederal lands

in 2011 CEL on

Surface Casing CEL on

Intermediate Casing CEL if

Inadequate

Cement

Job Mechanical

Integrity

Test or

Pressure

Tests Minimum

Requirement for Storage

Tanks Minimum

Requirement

for Lined

Pits Chemical

Disclosure

California 13% Authority

to request Authority to

request No, but

authority to

request Depends on

the field

rule No Generally No

Colorado 14% No No, unless using a production

liner No Yes No Yes Yes

Montana 1% No No No Yes No Yes Yes

New

Mexico 22% No No No Yes Yes, unless approved to use lined pits N/A unless

approved Yes

North

Dakota 4% No Yes No, but authority to
request

pressure

test Yes No Yes Yes

Texas 1% No No No Yes Yes , unless approved to use pits N/A Yes

Utah 13% No No No Yes No Yes Yes
Wyoming 32% Authority

to request Authority to

request No, but

authority to

request Yes No Yes Yes27



### 3. Estimating Benefits and Costs

3.1 Theoretical Framework

This analysis estimates the potential costs and benefits that would occur as a result of the rule. As such, it estimates the impacts in relation to the current operating environment ( or the

base line )

.

In analyzing costs and benefits of the rule, it is important to dif ferentiate between the activities that operators currently conduct and those additional activities that the rule would compel. This change in behavior is the basis of the cost an d benefit estimates.

OMB Circular A

- 4 recognizes that not all benefits and costs can be described in monetary or even in quantitative terms. In those cases, it directs agencies to present any relevant quantitative information along with a description of the unquantified effects.

3.1.1 Measuring the Incremental Change

Many of the provisions in the rule are conducted voluntarily by operators as a matter of company practice or standard industry practice. Operators have a vested interest in ensur ing that wells are constructed properly to avoid problems that might jeopardize their investment. As a matter of industry practice, operators typically do the following:

Develop a plan for the hydraulic fracturing operation ; Monitor the cementing processes ;
Cement casing protecting water zones ; Conduct pressure tests on casing strings during the drilling process or before hydraulic fracturing operations ; Maintain drill logs identifying usable water zones ;
Run CBLs and/or other evaluation logs on the productio n casing and sometimes on the intermediate casing, if there are formations of interest higher than the producing

zone or to maintain compliance with state regulations, state permit requirements , or
F ederal permit requirements ; Monitor annulus pressures dur ing the hydraulic fracturing operation ; and Manage the flowback of fluids.

Some practices required in the rule are already conducted by operators in order to compl y with existing applicable state regulations or requirements

. Such s tate regulations often dictate how an operator cements a well, what tests or logs it conducts, how it handles flowback , or whether it

must disclose the chemical contents of the hydraulic fracturing fluid . In addition to regulations, states may place requi rements in the drilling permits as conditions of approval. For example, as a condition of approval for a particular permit, a state may r equire an operator to use tanks to

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

S ome of the provisions in the rule are also consistent with existing F ederal requirements. As such, operators on F ederal and Indian lands are already in compliance with those provisions , and therefore the rule does not pose an additional burden . For example, t he BLM has casing and cementing requirements to protect and/or isolate usable water zones , found in Onshore Order No. 2, that are consistent with the final rule. Operators on F ederal and Indian leases that are drilling in compliance with Onshore Order No. 2 would also be in compliance with this rule , and so accordingly, the rule poses no additional burden for casing and cementing operations, but it does require testing and reporting to evaluate the protection/isolation of those zones

. Like state regulatory authorities, t he BLM or a tribe may also place requirements on operators as a condition of approval for the drilling permit.

Where appropriate and possible, the analysis does not consider impacts in areas where operators already adhere to th e rule’s provisions as a matter of voluntary practice or regulatory compliance

with existing F ederal , tribal, or state regulations or requirements in conditions of approval

.

3.1.2 Costs Framework

T o examine the costs of the rule, the analysis considers t he number of hydraulic fracturing operation s that would be subject to the various requirements (referred to as “subject activity”)

and the cost s of the various requirements

. While the rule would apply t o all hydraulic fracturing operation s on F ederal and Indi an lands, specific provisions in the rule may only apply to a subset of those operations. For example, the r ule requires SR Sundry submissions for all hydraulic fracturing operations, but the number of required NOI Sundry requests and the CELs conduct ed

would be fewer

.

The three key component s to the cost formulation are the estimate d number of hydraulic fracturing operations , the applicability of provisions to those operations, and the compliance

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

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

total costs.

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

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

Pressure Testing Requirement: The pressure testing requirement is consistent with standard industry practice, state regulations, and BLM regulation Onshore Order No. 2 . As such, the requirement does not pose an additional burden to operators.

Pit liner or storage tank requirement: The requirement to manage flowback in lined pits or storage tanks is consistent with almost all existing state regulations in states where new oil and gas activity is occurring on BLM

- managed lands. As such, the requirement would only pose an

additional burden to operators on F ederal and Indian lease hold s in states or on Indian lands without existing requirements and who are not voluntarily in compliance.29

Storage tank requirement: We examine a n alternative that would requir e operators to manage
flowback in storage tank s ( or often referred to as “closed

- loop” systems )

. Closed

- loop systems in which fluids are never exposed to the elements have been acknowledged as an environmentally

- sound method of waste storage. 37 A report from members of the US House Committee on Natural Resources expressed support for prohibiting the use of open pits in favor

of closed

- loop systems, writing, “ t he use of pits to capture or dispose of flowback water can result in greater surface disturbance and a higher risk of leaks an d spills, which threatens soils, groundwater, surface water and wildlife. Pits can also be a significant source of hazardous and toxic air pollution.” 38

Closed

- tank storage is regarded as a best management practice by many oil and gas companies 39

( as well as by many states ) and minimize s the potential for spill. 40 The practice is particularly prevalent in the Eastern U.S. and is being incorporated into standards for model shale development. 41 Colorado has proposed legislation to mandate closed

- loop systems unless the COGCC grants a permit for a lined pit

. Several other states, including New Mexico and Texas generally require closed

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

The prevalence of closed

- loop systems is uncertain

, and the BLM request s comment and information in the preamble of the proposed rule about the us e of closed

- loop systems or storage

tanks. We are particular ly interest ed in the prevalence o f closed

- loop systems in western states without such requirements but where they are voluntarily used as best practice.

The use of storage tanks to manage flowback also tends to vary by operators and the regions in which they operate. It has been documented that about 60 to 70 percent of flo wback is recycled in Marcellus Shale wells, 42 but it is unclear the extent to which that recycling is done with

closed

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

- loops systems. For example, EOG Resources manages all flowback in lined storage tanks for wells in the Marcellus Shale, but injects it into permitted disposal wells in

37 NRDC writes , “ Flowback and produced water should be collected at the well and either recycled or directly routed to disposal. In the event that storage of wastewater is necessary, it should be done in closed tanks.” Hammer, R. and VanBriesen, J., “In Fracking’s Wake: New Rules are Needed to Protect Our Health and Environment from Contaminated Wastewater”, NRDC, May 2012.

38 Letter from Reps. Markey, Holt, Sablan, Napolitano, Tonko, Grijalva to Sec. Salazar, U.S. House of Representatives Committee on Natural Resources, September 10, 2012.

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

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

40 Presentati on “Shale Gas Flowback Water Treatment, Reuse, and Disposal” by Dave Yoxtheimer, P.G. Accessed
March 16, 2013, http://www.acus.or g/files/EnergyEnvironment/BrusselsWorkshop/Yoxtheimer_Produced%20and%20Flowback%20 Water.pdf

41 Center for Sustainable Shale Development website. Accessed March 29, 2013, http://0371 86e.netsolhost.com/site/performance

- standards/

42 Data from two sources: 1) Marcellus Shale Coalition. Accessed March 16, 2013, http://www.prnewswire.com/news

- releases/marcellus

- shale

- coalition

- releases

- the

- facts

- on

- flowback

- water

treatment

- 83561557.html . 2) Presentation “Shale Gas Flowback Water Treatment, Reuse, and Disposal” by Dave
Yoxtheimer, P.G.30

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

the Piceance Basin but it us es centralized open pits. 44

Though tanks are reported to be more expensive than open pits upfront, companies and states make an economic argument for favoring closed

- loop systems over open pits. The New York Department of Environmental Conservation, for e xample, writes, “ Tanks, while initially more expensive, experience fewer operational issues associated with liner system leakage. In addition, tanks can be easily covered to control odors and air emissions from the liquids being stored. Precipitation load ing in a surface impoundment with a large surface area can, over time, increase the volumes of liquid needing treatment. Lastly, above ground tanks also can be dismantled and

reused.” 45

It also found that closed

- loop tank system can offer the following ad vantages , depending on the design : 46

Eliminates the time and expense associated with reserve pit construction and reclamation; Reduces the surface disturbance associated with the well pad; Reduces the amount of water and mud additives required as a result o f re

- circulation of drilling mud; Lowers mud replacement costs by capturing and re

- circulating drilling mud; Reduces the wastes associated with drilling by separating additional drilling mud from the cuttings; and Reduces expenses and truck traffic associa ted with transporting drilling waste due to the

reduced volume of the waste.

Other groups have argued that closed

- loop system requirements are expensive to build and

obtain

. For example , the Independent Petroleum Association of New M exico (IPANM) argued that the New Mexico rules restricting pits increased industry drilling costs by more than $200,000 per well. 47

The BLM believes that the additional upfront cost of using a closed

- loop system (instead of an open pit) will vary depending on the design or s etup . Different operations are likely to have differing capacity requirements due to the volume of fluid using in the operation, the expected volume of flowback, and the purpose of the storage tank (e.g. whether it just captures the

flowback or is used to as part of a water management system for t he site to recycle flowback for use in operations on subsequent wells).

43 EOG Resources website. Accessed March 16, 2013, http://www.eogresources.com/responsibility/water_management.html

44 WPX Energy website. Image depicts a water management sys tem with an open pit. Accessed March 16, 2013, http://www.wpxenergy.com/environment/water.aspx

45 Revised Draft SGEIS on the Oil, Gas and Solution Mining Regulator Program, New York Departme nt of Environmental Conservation at p. 7

- 61, September 2011. http://www.dec.ny.gov/energy/75370.html

46 Ibid at 5

- 39.

47 IPANM brief on New Mexico’s Pit Rule. Accessed March 16, 2013, http://www.ipanm.org/images/library/File/Pit

- Rule.pdf31

The BLM contacted two companies that rent large volume storage tanks used for hydraulic fracturing. The length of the rental would vary dep ending on the design. 48 One company serving eastern operations quoted a price of $220 per 300 bbl tank for a 10

- day rental. A second company serving operations in Colorado quoted a price of $50 per 500 bbl tank per day. We also contacted a company that s ells storage tanks for use in multiple fracturing operations. The

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

5 0,000 gallon tank would cost about $ 25,000 or a single 210,000 gallon tank would cost about $105 ,000. According to the company
, the tanks could be reused for 5 to 7 years.

If pits are designed to hold only flowback from an operation before being trucked off

- site, then the replacement tanks required would need to be of a capacity to hold only that f lowback, or about 15 to 40 percent of the volume of fluid injected. 49 Assuming a 1.2 million gallon fracturing job and different amounts of flowback

, 50 renting storage tanks to handle the flowback only would cost between about $6,000 to $17,000 per operatio n

. 51 Or consequently , though it makes less sense logistically , a company might purchase storage tanks for $100,000 to $250,000, depending on the flowback expected, and reuse the tanks for multiple hydraulic fracturing operations

.

For companies that use a centralized pit and recycle the flowback (and produced water) for use in operations on multiple wells , we would expect them to require tanks with sufficient total capacity to handle all of the fluid used in the operations. Assuming a 1.2 million gal lon fracturing job, w e estimate that the rental of storage tanks could cost about $ 42,000 per well. Purchasing storage tanks to meet that capacity could cost about $600,000, but the operator could use those storage tanks for multiple hydraulic fracturing operations.

The use of storage tanks instead of pits does not necessarily mean that the operator would avoid costs associated with digging pits. Often, operators will construct berms and other barriers as secondary containment for storage tanks. Operato rs are expected, however, to experience longer term cost savings from avoided remediation of spill events, though such cost savings is difficult to quantify for the average operation.

The BLM request s comment and information in the preamble to the proposed rule about the costs of using closed

- loop systems or storage tanks instead of open pits.

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

conduct CELs on the casing strings that protect usable water. The applicable casing strings include the surface casing and sometimes the intermediate casing. Operators do not typically run CELs to evaluate the cement behind the surface casing, so the rule would requ ire an additional step in the drilling process. Not all wells require intermediate casing, and wells that require

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

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

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

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

51 For company 1, costs calculated assuming two rental periods required. For company 2, costs calculated assuming a rental period of 14 days.32

intermediate casing may do so for reasons other than to protect usable water. 52 The rule would only compel CELs on intermediate casing that p rotects usable water , and further, on those intermediate casings where the operator would not otherwise conduct a CEL in compliance with state regulations or conditions of approval or do so voluntarily

. 53

Subsequent wells under a type well approval: Under the rule, t he number of wells requiring NOI Sundry submissions and subject to the CEL requirements should reflect that number of CEL s on single wells and on type well s, but not subsequent ly drilled wells under a type well approval

.

Requiring a CEL when there is an indication of inadequate cementing: Under the rule, operators on all wells (single wells, type wells, and subsequent wells to a type well) are required to run a CEL when there is an indication of inadequate cementing o f a casing stri ng that protects usable water. The BLM and many state re gulations and requirements have established protocol

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

and /or t ake action as directed by the regulatory a uthority. For example, Onshore Order 2 requires that operators perform remedial cementing if cement is not circulated back to the surface for the surface casing ( section III.B.1.c). Onshore Order 2 also requires an additional pressure

test and/or remedia l action as specified by the authorized officer if a pressure test indicates that casing strings do not meet minimum standards (section III.B.1.h). Onshore Order 2 lists other minimum standards and corrective actions, including some tha t require logging o r testing, remedial cementing , and actions specified by the authorized officer

. Subject activity for th e requirement to conduct a CEL under the revised proposed rule should reflect the prevale nce of inadequate cement jobs.

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

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

the c osts of the CEL and the costs to maintain idle drilling equipment if the drilling process is delayed.

After cementing casing, operators must wait for a period of time for the cement to harden before conducting any well tests and drilling the plug. The BLM requires operators to wait unt il the

cement at the casing shoe reaches a compressive strength of 500 psi. States generally have compressive strength standards similar to the BLM. For example, t he state of Montana requires operators to wait 8 hours and New Mexico requires operators to wait anywhere from 8 to 18

hours.

While waiting for the cement behind the surface casing to set, o perators will install other required equipment on the well, including blowout preventers. A fter the cement has hardened sufficiently and the operator has satisfied F ederal or state requirements, operators would normally conduct a pressure tes t on the surface casing, drill through the plug, drill for an

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

52 Other reasons may include to control pressure durin g lost circulation zones, for hole stability (e.g., against clay swelling), for isolation through salt zones, or for isolation through disposal zones.

53 North Dakota requires cement bond logs to be run on this string, while Colorado requires it in some cas es. In addition, some states and the BLM may place requirements to conduct logs on the intermediate casing as conditions of approval in the individual drilling permits.33

operators then drill the intermediate hole. The process is generally the same fo r the intermediate casing; however

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

circumstances described before.

We received many comments on the initial pr oposed rule suggesting that, by requiring CBLs, the rule would force all operators to maintain idle drilling equipment while the cement reached

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

idea that an o perator would need to wait an additional amount of time before pressure testing the casing or drilling through the plug

.

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

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

, and then drill the intermediate hole. They may then run a CEL at any point in time before they set the intermediate casing , for example, while replacing a drill bit. In any of these scenarios, there

could still be ancillary delays associated with the availability of the logging company and the time required to run the log

.

Operators drilling multiple wells on a pad should also be able to run a CEL and avoid potential drilling delays. W hen drill ing multiple well s on a pad, an operator may use a small er drilling rig (sometimes called a “double” rig) to sequentially drill a casing hole, set casing, and cement casing of each well, one by one

. 54 After the surface holes have all been sequentially drilled, cased, and c emented, the operator will remove the small drilling rig from the pad, and bring in a large drilling rig to drill the subsequent sections of each well. If an operator is drilling multiple wells in this fashion, then it may continue the drilling process wh ile the cement sets on the first well, and log that well at the operator’s convenience. Thus, in those situations, the operator would incur no additional costs associated with maintaining idle drilling equipment.

3.1.3 Benefits Framework

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

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

health risk posed by hydraulic fracturing operations, particular ly in its treatment of flowback fluids, well construction, and hydraulic fracture design.

The primary cha llenge in monetizing benefits lies in the quantif ication of a risk that is largely

unknown. Risk is the product of the likelihood of an incident oc curring and the impact that will be incurred. Or in this context, risk is the probability of an incident occurring from hydraulic fracturing times the cost of the damage.

Thus, t he potential and monetized benefit would be the red uction in risk attributed to the rule

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

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

54 A double rig may also drill the intermediate hole depending on the depth, but for th e purpose of this illustration we describe it as drilling the surface hole.34

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

benefits

.

Though operators are required to remediate damage when it occurs, there may be uncertainty about the true value or extent of the damage or limitations in connecting an incident wi th an operation. Even if the damage is internalized , and as long as the compliance costs are less than the damage costs , the overall benefit to society would be less than if the incident was avoided,

since resources would have been unnecessarily dedicated to the remediation.

Operators are required to notify the BLM when undesirable events occur. Undesirable events may include accidents, or accidental spills or releases of hydrocarbon fluids, produced water, hydraulic fracturing flowback fluids, or other substances. These events have the potential to adversely affect public lands and other important resources.

The re are limitation s in using the BLM data on undesirable events for this analysis

. First, the

data do not specify whether the undesirable even ts occur as a result of hydraulic fracturing operations . In addition, the available data cannot be readily matched with particular provisions

in the rule. The data provide figures for the incidence of spills, accidents, injuries, and other impacts on a w ell, but the pit liner information is generally not specified in the incident reports for spills or leaks . As such , there is difficulty in quantifying the level of risk reduction that

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

risk.

Damage, in general, is unknown, particularly when attemp ting to generalize damage costs which may vary by expected magnitude and reversibility of effects. Also, the valuation of the damage may also take many and highly variable forms . For example, an undesirable incident occurring during hydraulic fracturing might require the remediation of surface or subsurface areas. The incident might also require that the operator shut

- in temporarily or plug the well before it may produce all of the mineral resources. In this case, the opera tor would lose revenue and society would not benefit from the produced resources. Such would be the same for spills.

Measuring various implications of incidents: The following is an example o f 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. 55 The fracture path of the first well intercepted the fracture path of the second well, pushing produced fluids through the second well and its associated equipment such as the separator and an open top fiberglass tank. T he open top fiberglass tank overflow ed into an unlined firewall. The firewall

was over

- topped a nd fluids ran into a pasture. The fluids also entered a second facility via flow

lines and over

- topped an open fiberglass tank to overflow into an unlined containment berm

. The majority of fluids, 1,220 barrels consisting primarily of fracturing fluids, were contained within unlined firewalls and inside two 210 barrel open top fiberglass tanks. About 60 barrels of oil ran into a pasture on the well location of the second well.

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

NMNM0631.35

In order to control the event, the fracturing job had to be shut in. The active wells in the area were also shut in. The surface damage included less than 0.1 acre of pasture land, and the removal and disposal of the material inside the two firewalls. Vacuum trucks picked up all of the standing fluids. The impacted surface material was removed for sampling, site delineation, and remediation. The fracturing operation was in the 9 th stage of an 11

- stage job.

This incident illustrates the difficulty in estimating benefits. The environmental damage included potential surface contamination and subsequent remediation efforts

, and most of the environmental damage appears to have been remediated by the operator.

Aside from the environmental damage, there were several economic impacts. T he well conducting the hydraulic fractur ing operation was shut

- in. The incident affected other wells

which were also shut in. It is unclear what damage was done to the wellbore of the second we ll or how long it would be shut

- in until it could produce again . The well causing the incident was

i n the 9 th stage of an 11

- stage fracturing job. This means the operator had completed two stages and was on the third, leaving 8 stages remaining to be fractur ed

. 56 It is uncertain at this time if the operator would have to forego stages of the operation

, and if so, what t he volume of the unrecoverable resources from those foregone stages w ould be. T he unrecovered resources

reduce social benefit.

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

rule. Thi s incident may or may not have been avoided had the rule been in place , as t he rule would require operators to provide information about the proposed lengths, heights, and

directions of fracture s. Ideally, these and other information would have indicated that the fracture plan was inadequate.



### 3. 2 Data

Number of Hydraulic Fracturing Operations : This analysis divides the number of hydraulic fracturing operations into three c ategories, since provisions of the rule may apply differentially. Estimates are provided in Table 9

.

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

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

estimated future applications for permit to drill ( APD ) approvals using Energy Information Administration ( EIA ) commodity price projections in the Annual Energy Outlook (AEO) 2012. We then estimate d the number of well completions by examining the relationship between the number of approved APDs and number of well completions. The well completion data came from the BLM’s Automated Fluid Minerals Support System (AFMSS). APD data came from BLM oil and gas statistics. We estimate the

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

57 According to a survey by the API and ANGA, 94% of gas well completions in 2010 and the first half of 2011 were with hydraulic fracturing (Shires and Lev

- On 2012, p. 8). This figure may not represent the oil and gas well completions on Federal and Indian lands since activity on non

- federal and non

- Indian lands may be driving that figure.36

number of hydraulic fracturing operations on newly drilled wells on F ederal and Indian

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

Hydraulic fracturing operations on existing wells: Operators may conduct hydraulic fracturing operations on previously producing wells

. O ften, the operator will drill deeper

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

, between 2003 and
2011, on Federal and Indian lands the average number of well completions on deepened wells was 28 per year. The range was 18 to 54 completions.

Refractu ring operations: Operators may also conduct refracturing operations which are designed to identify and recomplete u nderperforming wells. The American Petroleum Institute (API) and the American Natural Gas Alliance (ANGA) conducted a nationwide survey and estimates that the refracture rate ranges from 1.6 percent to 2.3 percent for

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

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

. 59 We applied the 3.0

percent refracture rate to the annual totals for the operations on newly drilled wells and operations on existing wells to estimate the number of refracturing operations. As such,

we estimate annual the number of refracturing operations on Federal and In dian lands to range between about 100 and 120 over the next 10 years.

S ubject Activity for Specific Requirements in the Revised Proposed Rule : Many of the requirements of this rule are currently conducted by operators as a matter of general practice, standard industry practice, or in compliance with existing state or F ederal regulations, requirements, or conditions of approval for specific drilling permits. Estimates are provided in

Table 10

.

Protection of usable water: The BLM’s existing regulation, Onshore Order No. 2 , has provisions for the protection of usable water that are consistent with the provisions in this

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

this provision of rule.

Mechanic al integrity tests (or pressure tests): As described previously, operators conduct pressure tests on casing strings when drilling wells as a matter of standard practice. The BLM has pressure testing requ irements in Onshore Order No. 2 and other requireme nts for operators to “demonstrate the mechanical integrity of the downhole equipment” in 43 CFR 3162.4

- 2(b). In addition, w e examined the regulations in 8 states where new drilling activity is most prevalent on F ederal lands and found that those states

ha ve existing requirements for operators to conduct pressure tests when drilling wells

. As such, there should be no additional subject activity related to compliance with this provision of the rule.

58 Shires and Lev

- On 2012, p. 23.

59 Calculated from the survey information for the Mid

- Continent, Southwest, and Rocky Mountain regions. The survey data is listed in Table 9 on p. 20.

60 After proposing the rule in May 2012, we received public comments suggesting that the rule’s provisions would require operators to conduct additional cementing. A response to those commen ts are in the preamble.37

Cement evaluation logs on casing strings that protect usa ble water : The rule would require operators to run cement evaluation logs on the casing strings that protect usable water. Practically, this provision applies to new wells and not wells approved as a group conforming to a successful type well , existing wells

, or wells being refracture d

. 61

o CELs on the surface casing: To estimate the number of logs that the rule would compel, we examined the extent to which subsequent wells would likely fall

under type well approval . Using AFMSS well completion data f rom the past 5

years, 62 we looked at 3 different poten tial groupings of wells within geologic and geographic area s : by case, by field, and by township. We found that operators completed an average of 5. 067 wells in a case, 12.572 wells in a field (or pool ),

and 13.289 wells in a township

. The distribution of wells in each category is positively skewed, meaning the average is greater than the median (of midpoint value of the data) or that some of the observations have a large number of wells

and those obse rvations are pushing the average higher. For the purpose of analyzing the application of the type well rule provision , we believe that the field grouping is most appropriate, because it is based on geologic characteristics.

o CELs on intermediate casing: Not all wells require intermediate casing and

w ells that require intermediate casing may do so for reasons other than to protect
usable water. 63 The rule would only compel cement evaluation logs on intermediate casing protecting u sable water. Based on field experience, we anticipate that only about 5 percent of wells have intermediate casing to protect usable water. Further, the rule would only compel CELs on these wells where the operators do not otherwise conduct these logs. A s detailed earlier, s tate regulations in North Dakota require logs on the interm ediate casing

. 64

A ccordingly, we further re duce the ex pected number of CELs compelled by 4

percent

. 65

o CELs where there is an indication of inadequate cementing: The number of

wells where there is an in dication that the initial cement jobs require repairs is generally believed to be between 1 and 5 percent. 66 We use the midpoint of the

61 Operators proposing to hydraulically fracture an existing well (one drilled prior to the effective date of the rule) cannot practically comply with the cement evaluation log requirement of the rule, as it pertains to logging the

s urface casing and possibly the intermediate casing. Operators proposing to refracture a well also cannot practically comply with the cement evaluation log requirement of the rule, as it pertains to logging the surface casing and possibly deeper casing str ings.

62 The dataset included 17,475 Federal in Indian wells that were completed between January 2008 and December

2012.

63 Other reasons may include to control pressure during lost circulation zones, for hole stability (e.g., against clay swelling), for isolation through salt zones, or for isolation through disposal zones.

64 Colorado require s them when operators use a product ion liner

. 65 In 2011, the number of wellbores started on Federal lands in North Dakota represented about 4% of the wellbores

started on Federal lands nationwide.

66 Percent range cited by George King, a petroleum engineer for Apache Corporation (Behr 2012). That range is consistent with a survey of enforcement actions conducted by the Energy Institute (Groat & Grimshaw , Ch. 6, section 3, p. 16).38 range, or 3 percent , and apply it to the number of newly drilled wells for the activity data.

Lining Pits: The rule would require operators to use a lined pit or a storage tank to

manage flowback from hydraulic fracturing operations

. As described in Section 2, this requirement is consistent with industry practice. W e also examined regulations in 8 states where new drilling activity is most prevalent on F ederal lands and found that those

states either have existing minimum requirements for lined pits or storage tanks or that operators do so to be consistent with the protecti on of groundwater

. According to

R esources for the Future (R FF )

, Arkansas, Kansas, Louisiana, Mississippi, Nevada, and Oklahoma also have existing pit liner requirements. 67 Considering the low level of oil and gas development on F ederal lands in the remain ing states, the impact of this provision is likely to be very small. For example, in 2011, only 5 wellbore s were spudded on F ederal lands in states without current pit liner requirements. 68 This

represents about 0.15% of the wellbore s spudded on F ederal l ands. We apply that percentage to the number of hydraulic fracturing operations on new and existing wells to get the activity data. However, even that number is potentially exaggerated, since multiple wells on a lease may use the same reserve pit and/or the BLM or the state might require the pits to be lined as a condition of approval. Also, those operators are likely to voluntarily use storage tanks or lined pits (which is standard industry practice)

.

NOI Sundries: The revised proposed rule would require NOI Sundry submissions for hydraulic fracturing operations on type wells, existing wells and refracture d wells. Although the BLM currently receives NOI Sundries for “non

- routine” hydraulic fracturing operations, for this analysis, we co nsider the NOI Sundry burden as a new burden, since the submission of NOI Sundries currently is inconsistent.

SR Sundries: The revised proposed rule would require SR Sundry submissions for hydraulic fracturing operations on all wells. Although the BLM c urrently receives SR Sundries for all hydraulic fracturing operations, for this analysis, we consider the SR Sundry burden as a new burden, since the information required by the rule is substantially

different.

Variance Requests: The revised proposed r ule allows operators to request for variances.

The BLM has no basis with which to estimate the number of variances that it would receive. For the purpose of this analysis, we assume that operators could potentially request variances on 10 percent of the NOI Sundries.

Subject Activity for Specific Requirements in the Alternatives: We adjusted the subject activity data for the alternatives.

67 The RFF findings cited are available on its website under flowback/wastewater storage and disposal, accessed

h ere on December 9, 2012: http://www.rff.org/centers/energy_economics_and_policy/Pages/Shale_Maps.aspx

68 Represents wellbores in Nevada and Ohio which were either not in the RFF study or that the RFF found no evidence of regulations. In 2010, only 4 wellbo res were spudded on Federal lands in states (again Nevada and Ohio) without current pit liner requirements.39

Alternative 1 does not have the type well provisions; therefore, operators would be required to submit NOI Sundries for all operations and conduct CELs on all wells with casing strings protecting usable water

. The prevalence and cost of tank usage is a source of uncertainty and we have requested comments and information regarding stor age tanks in the preamble of the proposed rule. We were not able to find data on the prevalence of voluntary storage tank usage in States without mandatory requirements. Thus, the number of operations where this alternative approach would compel the use of storage tanks is unknown at this time

.

Alternative 2 would not require lined pits. Estimates are provided in Table 11 and Table 12

.

For both alternatives, there is no activity data for the requirement to conduct a CEL in the event

of an inad equate cement job. This is not because there would be no inadequate cement jobs, but simply that CELs are required on all casing strings that protect usable water, and so that requirement category encompasses the inadequate cementing category.40 Table 9: Estimated Number of Hydraulic Fracturing Operations by Type , Years 1

– 10

HF Type 1 2 3 4 5 6 7 8 9 10

HF on New Wells 3,434 3,525 3,608 3,628 3,663 3,685 3,724 3,764 3,832 3,911
HF on Existing Wells 28 28 28 28 28 28 28 28 28 28
Refracturing Operations 104 107 109 110 111 111 113 114 116 118

Total 3,566 3,659 3,745 3,765 3,802 3,825 3,864 3,906 3,975 4,057

Table 10: Estimated Activity Data for Specific Requirements in the Rule , Years 1

– 10
Requirement 1 2 3 4 5 6 7 8 9 10
Surface Casing Logs 273 280 287 289 291 293 296 299 305 311
Intermediate Casing Logs 13 13 14 14 14 14 14 14 15 15
Logs for Inadequate Cementing 103 106 108 109 110 111 112 113 115 117
Lining Pits 5 5 5 5 6 6 6 6 6 6
NOI Sundry 405 415 424 426 430 433 437 441 449 457
SR Sundry 3,566 3,659 3,745 3,765 3,802 3,825 3,864 3,906 3,975 4,057
Variance Requests 41 41 42 43 43 43 44 44 45 4641 Table 11: Estimated Activity Data for Specific Requirements in the Alternative 1, Years 1

– 10
Requirement 1 2 3 4 5 6 7 8 9 10
Surface Casing Logs 3,434 3,525 3,608 3,628 3,663 3,685 3,724 3,764 3,832 3,911
Intermediate Casing Logs 165 169 173 174 176 177 179 181 184 188
Logs for Inadequate Cementing 0 0 0 0 0 0 0 0 0 0
Storage Tanks Unk Unk Unk Unk Unk Unk Unk Unk Unk Unk
NOI Sundry 3,566 3,659 3,745 3,765 3,802 3,825 3,864 3,906 3,975 4,057
SR Sundry 3,566 3,659 3,745 3,765 3,802 3,825 3,864 3,906 3,975 4,057
Variance Requests 357 366 374 377 380 382 386 391 398 406

Table 12: Estimated Activity Data for Specific Requirements in the Alternative 2, Years 1

– 10
Requirement 1 2 3 4 5 6 7 8 9 10
Surface Casing Logs 3,434 3,525 3,608 3,628 3,663 3,685 3,724 3,764 3,832 3,911
Intermediate Casing Logs 165 169 173 174 176 177 179 181 184 188
Logs for Inadequate Cementing 0 0 0 0 0 0 0 0 0 0
No Tanks or Pit Liner Req. 0 0 0 0 0 0 0 0 0 0
NOI Sundry 3,566 3,659 3,745 3,765 3,802 3,825 3,864 3,906 3,975 4,057
SR Sundry 3,566 3,659 3,745 3,765 3,802 3,825 3,864 3,906 3,975 4,057
Variance Requests 357 366 374 377 380 382 386 391 398 40642

Activity Costs : Activity costs vary by the requirements, as follows :

Cement evaluation logs: The costs associated with conducting these logs include the cost of the log itself and cost of maintaining any idle drilling equipment on

- site , where appropriate

.

o Log costs: The costs of running a log varies depending on the type of test and

whether it is for the surface casing or intermediate casing

. Although the rule allows for a suite of CELs, operators will generally choose to use a CBL to log casing strings protecting usable water. 69 In estimating compliance costs, we

estimate that it cost s $6,0 00 to run a CBL on the surface casing and about $20,000

to run a CBL on the intermediate casin g. 70 For a CBL required when there is an indication of inadequate cementing, we estimate a cost of $ 7,000 to run a CBL, since it is unknown what length of casing the CBL would apply. 71

o Maintaining idle drilling equipment for CELs on the surface casing

– Lower

bound of costs : The length of additional time required to cement behind the surface casing to reach compressive strength is a matter of debate. There may be no additional time required if an operator avoids having to idle the equipment or if additional compressive strength in the cement is not required. We received a number of comments suggesting that 24 hours is an appropriate amount of time

for the surface casing cement to reach compressive strength for a CEL. 72 Using AFMSS well completion data for the past 5 years, which include s spud dates for

wells i n leases and agreements (referred to as cases in AFMSS )

, w e 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 comple ted were spudded in this manner. On these wells, we expect the CEL provision will not cause operators to maintain idle drilling equipment. F or the lower bound estimate, we attribute a lower bound cost of $19,850 to maintaining idle drilling equipment for a CEL on the surface casing

. 73

o Maintaining idle drilling equipment for CELs on the surface casing

– Upper

bound of costs: Due to the uncertainty in operators’ ability to avoid having to

69 Other CELs may be more expensive and/or require more time, under present technologic and economic

conditions.

70 Estimates were listed in the appen dix to the comment from Devon.

71 Calculated as: ($6,000) x (100%) + ($20,000) x (5%). We do not consider costs to maintain idle drilling equipment, since operators must current remediate to satisfaction.

72 We received a comments suggesting delay times up to 72 hours; however, many comments were not specific about whether the cited times were specific to cement behind the surface casing or the intermediate casing, or if the suggested times included both. Most comments were not specific as to whether the su ggest times included the initial amount of time required for the cement to reach compressive strength sufficient for the casing pressure test. That

initial time should not be considered as additional burden. We still believe that there could be efficienc ies made by operators on these wells, for example, by drilling the intermediate hole and logging the surface casing before setting the intermediate casing.

73 Calculated as the product: ($1900 per hour) x (24 hours) x (1

- 0.5647)43 maintain idle drilling equipment, we calculated an upper bound for the CEL requirement on the surface casing. We account for 24 hours of additional time for operators to maintain idle drilling equipment, at a cost of $1,900 per hour. Overall, we attribute an upper bound cost of $45,600 to maintaining idle drilling equi pment for a CEL on the surface casing. 74

o Maintaining idle drilling equipment for CELs on the intermediate casing: For this analysis, we account for 48 hour s of additional time at a cost of $1,900 per hour. Since operators generally use additives to speed up the hardening of

cement behind intermediate casing, we believe that 48 hours is the upper bound of the potential cost

. Overall, we attribute a cost of $ 91,200 to maintaining idle drilling equipment for a CEL on the intermediate casing

. 75

Lining Pits : We estimated the costs to be about $6,000 per pit , using prices q uoted by suppliers of about $0.24 per square foot of lining. The amount of lining required varies by well and the cost of lining depends on the thickness and other properties that vary by the use of the pit.

Storage Tanks: As described earlier, w e received general price quo tes from two firms

that rent storage tanks for hydraulic fracturing operations. The per

- well costs of requiring storage tanks is likely to vary depending on the operator’s design. If the operator uses the tanks for managing flowback and then trucks the f lowback from the site, then the costs of renting storage tanks might be between $6,000 and $17,000 per well. If the operator uses the tanks as part of a centralized recycling system for use on multiple wells, then the costs of renting storage tanks might be about $42,000 per well. Instead of renting,

o perators might choose to purchase storage tanks for use on multiple sites. We quoted one firm that sells 50,000 gallon tanks for $25,000. A hydraulic fracturing job using 1.2 million gallons of fluid would require 24 tanks of this size at an initial cost of $600,000. However, the operator might reuse th ese tanks for up to 5 to 7 years.

Depending on the design of the closed

- loop system, operators may also benefit from other cost saving s. For example, the closed

- loop system may eliminate the time and expense associated with reserve pit construction and reclamation. Recycling may reduce the amount of water needed, expenses and truck traffic associated with transporting water to the site and drilling waste f rom the site, surface disturbance, and the volume of waste. Operators are expected to experience fewer operational issues associated with liner system leakage. Also, tanks may be dismantled and reused in future operations.

NOI Sundries, SR Su ndries, and Variance Requests: The sundries and variance requests are all anticipated to require 8 hours to prepare at a cost of about $ 60 per hour. As such, the cost for each sundry or variance request is estimated to be about $ 480

. 76

74 Calculated as the product: ($1900 per hour) x (24 hours).

75 Calculated as the product: ($1900 per hour) x (48 hours).

76 The cost formulation for administrative requirements is detailed in the supporting statement for the Paperwork Reduction Act in the pre amble of the final rule. It calculates costs of $59.78 per hour or $478.24 per request.44

Average Compliance Costs by Well Type or Fracturing Operation

The average compliance costs will vary by well type or hydraulic fracturing operation. The estimates also reflect the likelihood that the particular type of well would be subject to the requirement s . For example, the rule would compel only some operators of a type well to conduct a CEL on the intermediate casing, since not all wells have intermediate casing and only a portion of wells with intermediate casing protect usable water.

Operators on a single well or the typ e well for a group of we lls are expected to see compliance costs ranging from $ 32,107 to $ 57,858 . The majority of the costs are associated with conducting CELs on the surface casing and/or the intermediate casing. Compliance costs for the CEL requirement alone range from $ 29,737 to $ 54,959 . In Year 1 , only 2 73 wells are estimated to be subject to the CEL requirement in the rule, but 3,434 wells would be subject under Alternatives 1

and 2.

Average compliance costs for subsequent wells are only relevant f or the rule, and not for the

alternative s , since the alternatives do not consider the type well concept . Average compliance costs are expected to be $ 697 per subsequent well

. Existing wells and refracture operations have average compliance costs of $1,01 3 and $1,004, respectively, and would apply to about 132

wells in Year 1 . Average compliance costs by well type and fracturing operation are also provided

. 77

Table 13: Average Compliance Costs by Well Type or Fracturing Operation

Requirement Well Type o r Fracturing Operation

Type Well or Single Well Subsequent

Well under Type Well Approval Existing

Well Re

Fracture Operation Low High

Count of Hydraulic Fracturing Operations (in Year 1) 273 3,161 28 104
CEL on Surface Casing $25,850 $51,600 $0 $0 $0

CEL on Intermediate Casing $3,149 $3,149 $0 $0 $0

CEL if Inadequate Cementing $210 $210 $210 $0 $0

Lining Pits $9 $9 $9 $9 $0

NOI Sundry $38 $38 $0 $478 $478

SR Sundry $478 $478 $478 $478 $478

Variance Requests $4 $4 $0 $48 $48

Total $29,737 $55,488 $697 $1,013 $1,004

77 As mentioned earlier, o perators proposing to hydraulically fracture an existing well (one drilled prior to the effective date of the rule) cannot practically comply with the cement evaluation log requirement of the rule, as it pertains to logging the surface casing and possibly the intermediate casing. Operators proposing to refracture a well also cannot practically comply with the cement evaluation log requirement o f the rule, as it pertains to logging the surface casing and possibly deeper casing strings.45

Costs to the BLM to Maintain Capacity: The BLM will require additional staffing in order to incorporate the NOI Sundry approvals into the BLM’s processing of APDs. We calculate the administrative burden per NOI Sundry as being 8 hours (to include possible complexity with the type well approval ), per SR Sundry as being 4 hours, and per Variance Request as being 1 hour. Full time employee ( FTE ) requirements to maintain capacity are calculated using 2,080 hours per year at an hourly wage of $28.45. The BLM wages are based on Office of Personnel Management data for a GS grade 12, step 1

, with no locality adjustment.

Benefits : We describe the process of developing a possible risk calculation. However, we provide a qualitative discussion (rather than a quantitative analysis) of benefits in the results

section because of uncertainty about the magnitude of damages and the amount of risk reduction that we can attribute to the rule’s implementation

.

Likelihood of a Min or Incident associated with Hydraulic Fracturing: The BLM

does not track undesir able events by whether they were caused by hydraulic fracturing. The Energy Institute conducted a survey of violations that occurred on shale wells and tight sands and shales in four states, including Louisiana, Michigan, New Mexico, and

Texas. Of those states, only New Mexico listed violations (categorized as “fracturing,” “ground water contamination (complaints only),” and “surface spill frac fluid”) specifically related to hydraulic fracturing operations. Another category listed and

related to the rule was “casing and cementing.” Violations in these categories represented 2.7 percent of the total violations. 78

Likelihood of a Major Incident associated with Hydraulic Fracturing: As stated

above , the BLM does not track undesirable events by whether they were caused by hyd raulic fracturing . That one incident described before represents 0.028 percent of the total hydraulic fracturing operations that we estimate will occur in Year 1

. 79 There are likely other incidents that occurred in 2012 that were as sociated with hydraulic fracturing operations and for which this rule would be relevant in addressin g.

Damage from a Minor Incident from Hydraulic Fracturing: We include surface remediation for damage from a minor incident for purposes of a qualitative discussion

. For the incident described above, we estimated the remediation costs of the surface environment to be about $15,000, but we note that the affected surface area is generally

considered to be small. Remediation ef forts of larger spills are much more complicated

and can reach the hundreds of thousands of dollars.

Damage from a Major Incident from Hydraulic Fracturing: We include several costs

that may comprise this formulation. As with the example incident, the re were surface, possible subsurface impacts (including impacts on the second well), and resources unrecovered.

78 Groat 2012, Ch. 6, section 3, pp. 16

- 17.

79 Calculated as 1 / 3566.46 o Subsurface Remediation Damage: The Federal Remediation Technologies

Roundtable (FRTR) makes a number of case studies available on its website. 80 It provides a description of the contamination event and source, and remediation efforts and costs. This analysis assumes a cost of $1 million to remediate contamination to an aquifer , but we note that the FRTR does not list any case

studies of contami nation events resulting from hydraulic fracturing operations

.

o Surface Remediation Damage: We believe remediation efforts could range from $15,000 to hundreds of thousands of dollars for an incident that affect s the

surface environment.

o Value of Stra nded (or Unrecovered) Resource: We believe that these costs

would be v ariable depending on the damage and the particular well or wells. In the example incident, the operator could lose a number of stages

, be required to

shut in the well for a period of t ime, or plug the well entirely

.

80 http://www.frtr.gov/

.47



### 3. 3 Discounted Present Value

There is a time dimension to estimates of potential costs and benefits . The potential events described, if they occur at all, may be in the distant future. The further in the future the benefits and costs are expected to occur, the smaller the present value associated with the stream of costs and benefits. As such, future costs and benefits must be discounted. 81 The discount factor is

then used to convert the stream of costs and benefits into “present discounted values.” When the estimated benefits and costs have been discounted, they can be added to determine the overall

value of net benefits.

The OMB’s basic guidance on the appropriate discount rate to use is provided in OMB Circular

A

- 94. The OMB’s Circular A

- 94 states that a real discount rate of 7 percent should be used as a

base

- case for regulatory analysis. The OMB considers the 7 percent rate as an estimate of the average before

- tax rate of return to private capital in the U.S. economy. It is a broad measure that reflects the returns to real estate and small business capital as well as corporate capital. It approximates the opportunity cost of capital, and it is the appropriate discount rate whenever the main effect of a regul ation is to displace or alter the use of capital in the private sector.

OMB Circular A

- 4 also states that a 3 percent discount rate should be used for regulatory analyses and provides an explanation of the use of the discount rate as follows : “ The effe cts of regulation do not always fall exclusively or primarily on the allocation of capital. When regulation primarily and directly affects private consumption (e.g., through higher consumer prices for goods and services), a lower discount rate is appropri ate. The alternative most often

used is sometimes called the ‘ social rate of time preference. ’ This simply means the rate at which

‘ society ’ discounts future consumption flows to their present value.”

The analysis also examines potential costs and benefits using 10 and 12 percent discount rates.

The consideration of h igher discount rates are appropriate for this analysis , since the rule imposes costs on the oil and gas industry and the opportunity cost of not having that available capital is generally higher than 3 and 7 percent. The higher rates also serve as a sensitivity test.

81 Discount factor = 1/(1+ r ) t where r is the discount rate and t is ti me measured in years during which benefits and costs are expected to occur.48



### 3. 4 Uncertainty

The costs and benefits provided in this analysis are indeed estimates and come with uncertainty.

We describe the primary sources of uncertainty below: Type well applicability: The estimates for the rule rely largely on the concept of the type well. In terms of cost calculations, the uncertainty lies in an average number of

wells that would be covered u nder a type well approval. While we are confident that the average number of wells that an operator completes in a field is a good measure with which to base the estimate, the measure is positively skewed by a fewer number of firms with a high numbers of wells. This does not suggest a problem with the data, but rather that the experiences of operators will vary, and that the likely scenario is that the typical operator completes fewer wells than the average. In terms of benefit calculations, there is

unc ertainty about the effectiveness of the type well concept, and how reliably the CEL results on casing strings of a type well assure adequate cementing for subsequent wells in the same geologic area. Length of delay time to run a CEL: A large source of un certainty is the amount of time that the CEL requirement might delay drilling operations. We received comments suggesting that the CEL would delay drilling operations for up to 72 hours. The CEL on the surface casing, in particular, poses a new step in t he drilling process for operators. A large source of uncertainty is the extent to which operators would be subject to delays, and if so, how they will be able to incorporate this new requirement and minimize or eliminate potential delays through operating efficiencies

. Percent of wells encountering problems during the cementing process : Cementing problems

, and downhole conditions in general, are not a widely reported measure. This analysis uses 3 percent as the basis for calculating the potential costs and benefits.

Benefits of specific provisions for well integrity and NOI Sundry submission : Further uncertainty lies in the estimation of benefits and the cumulative effect of the rule’s provisions on mi tigating the potential risks of hydraulic fracturing operations. This rule has specific provisions that w ould help operators and the BLM better identify potential issues in wellbore integrity and fracturing design, before operations begin. However, it is difficult to attribute benefits to one single test (for instance the CEL) when

that is only one part of the overall evaluation of wellbore integrity.49



### 3. 5 Changes in the Economic Analysis from the Initial Proposed Rule

The BLM received many commen ts about the economic analysis that it conducted for the initial proposed rule

. We reviewed these comments and made changes to the economi c analysis, where appropriate. We describe those changes in this section.

We refined the estimation of costs and benefits in several ways. The revised analysis includes an examination of costs for maintaining idle drilling equipment. We also account for existing state regulations, understanding that operators are already in compliance with many of the rule ’ s

pr ovisions. This improvement resulted in updated estimates for the pit liner and mechanical integrity test requirements. In response to comments, we revised the estimated number of hydraulic fracturing operations to include refracture jobs. We also revise d the formulation of administrative costs to be consistent with the Paperwork Reduction Act analysis assumptions in the proposed preamble.

We provide a qualitative discussion of the benefits for the rule. Also, recognizing the limitations in being able to estimate all of the benefits of the rule, we present the costs and benefits separately rather than as net benefits.

In response to public comments, we included additional discount rates.

The s mall b usiness impacts a nalysis was refined and expanded. T he costs associated with the CEL provisions represent the majority of the potential costs and these provisions will affect operators drilling new wells. We took a closer look at the operators completing new wells on

federal and tribal lan ds in the past 5 years and researched those companies filing annual reports with the Securities and Exchange Commission (SEC) . The result is an expanded pool of companies and a more in depth look at the potential impacts.

In addition to changes stemming from public comments, this analysis examines the provisions

contained in the revised proposed rule.50



### 4. Results

Where appropriate, this analysis monetizes costs and benefits expected to occur over a 10

- year period . This period of analysis was chosen because 10 years is the length of the primary lease

term on BLM

- managed lands. The analysis presents a range of expected outcomes due to uncertainty about the generalization of costs and benefits across all hydraulic fracturing operations.

Table 1 4 and T able 1 5 show a summary of incremental costs and benefits, respectively, for the

rule and the alternatives examined. To annualize the incremental costs and benefits , the analysis

calculates the annualized value (AV)

. 82 When monetized, the results are prese nted in 2012

dollars.

Table 14: Summary of Costs ($ million )

Annualized Value Revised Proposed Rule Alternative 1 * Alternative 2

Undiscounted 12

- 20 119

- 213 119

- 213

Discounted at 3% 12

- 19 118

- 213 118

- 213

Discounted at 7% 12

- 19 118

- 212 118

- 212

Discounted at 10% 12

- 19 117

- 211 117

- 211

Discounted at 12% 12

- 19 117

- 211 117

- 211
* Does not represent total costs, because the cost of requiring storage tanks is unknown.

The annualized value s of the costs do not vary significantly across different discount rates. This

is expected for several reasons.

When comparing annualized values across a range of possible discount rates, it is important to recognize three effects. First is the effect of discounting within any given year: a higher discount rate results in a smaller real value for a cost in that yea r. This is shown in Table 16 by comparing the undiscounted and discounted rows for any of the year columns. For example, in

Year 1 , the undiscounted cost is $11.19 million, while discounting at 3 percent reduces this to $10.86 million in real terms, and discounting at 12 percent reduces it to $9.99 million.

The second effect is the impact of compounded discounting: the farther in the future a cost is to be incurred, the smaller the real value of that cost. This is shown in Table 16 by comparing the

ef fect of a given discount rate in two different years. For example, in Year 1 the effect of discounting at 3 percent (as discussed in the previous paragraph) is to reduce the undiscounted costs by $0.33 million, a change of 3 percent

. In Year 2 , the reduc tion is $0.66 million, a change

of 6 percent , and in Year 10 the reduction is $3.26 million, a change of 26 percent

.

82 AV = [PDV ] * [ (r(1+r)^n) / ((1+r)^n

– 1)] , where PDV is the present discounted value of the benefits, costs, or

net benefits over “n” years and “r” is the discount rate

.51

From these first two effects, we see that real costs are driven down by using a higher discount rate and by delaying costs.

The third e ffect is related to how the annualized value (AV) compares to the average cost over a stream of payments. For a given (real) lump sum, the AV is an annual nominal payment such that a discounted stream of these payments equals the real value of the lump su m. When the discount rate is zero, the AV is simply the average cost: the sum of the costs in the original schedule divided by the number of years in the schedule.

When the original cost schedule is front

- loaded (nominal costs are higher in early years)

, discounting has less of an effect, as the time for compounding is limited. Thus, any real lump

sum is not much less than the sum of the undiscounted costs. In a hypothetical stream of AV payments, payments made in later years contribute little to total real value, but the stream must nonetheless tally to a real

- value amount relatively close to the undiscounted total. This forces the AV value up relative to the average cost.

When the original cost schedule is back

- loaded (nominal costs are higher in later years), discounting has more of an effect, given the longer time for compounding. Thus, any real lump sum is significantly less than the sum of the undiscounted costs. This forces the AV value down relative to the average cost.

When the original cost schedule is relatively constant over time (neither front

- loaded nor back

loaded) the AV will be relatively similar to the average cost. This is expected with compliance

cost s related to this rule. The total compliance costs for the rule are expected to be relatively similar over future years, owing to similar activity data (i.e. the number of hydraulic fracturing operations) and that the compliance costs for a single operati on are contained within a short

timeframe.52 Table 15: Summary of Non

- Monetized Benefits

Non

- Monetized Benefits Rule Alternative

1 Alternative

2 Percent of individual hydraulic fracturing plans reviewed by the BLM 11% 100% 100%

Percent of hydraulic fracturing operations using unlined pits 0% 0% 0.15%

Percent of individual wells where wellbore integrity is demonstrated with CELs on casing strings that protect

usable water 8% 96% 96%

Percent of wells where wellbore integrity is demonstrated with pressure

tests 100% 100% 100%

Percent of hydraulic fracturing operations where chemical content of

fluids are disclosed 100% 100% 100%

Non

- Monetized

Benefits Estimated

Baseline Rule Alternative

1 Alternative

2

Likelihood of Minor

Incident 2.70% N/A N/A N/A

Likelihood of Major

Incident 0.03% N/A N/A N/A53



### 4. 1 Costs of the Revised Proposed Rule and Alternatives

Estimated Costs of Revised proposed Rule

Annualized costs to the industry are estimated to be between about $12 and $ 20 million when

undiscounted and when using discount rates of 3, 7, 10, and 12 percent.

Table 16 and Table 17 show lower and upper bound estimates, respectively. The tables provide a range for potential costs for each year of the 10

- year pe riod . In a given year, requirement costs are provided separately and also totaled at the bottom of the table. The net present value s for the total costs are also provided, using discount rates of 3, 7, 10, and 12 percent. We also present the

annualized value in the right column of each table for each of those discount rates.

The net present value of total costs over the 10

- year period are estimated to be between $102 to $166 million when discounted at 3 percent , between $ 84 and $ 136 million when discounted at 7
percent , between $ 73 and $ 119 million when discounted at 10 percent , and between $ 67 and $ 109 million when discounted at 12 percent

.

The largest cost burden lies with the CEL requirement, which is also the source of the gre atest amount of uncertainty when developing estimates. Drilling methods, procedures, and requirements vary across operations, locations, and states, so it is challenging to place an exact dollar figure on the appropriate cost.

The estimated costs for t he CEL requirement are driven to a large extent by the amount of time operators might have to maintain idle drilling equipment on

- site. The lower bound of the estimated CEL requirement includes the annual costs of conducting CELs on the surface casing,

as suming that operators using a small rig to drill the surface holes of wells would likely avoid the costs of maintaining idle drilling equipment. The estimate possibly represents the lowest possible cost; however, there is a chance it could be even lower d epending on the ability of the operators on other wells to maximize efficiencies and reduce delays . The upper bound of the estimated CEL requirement does not account for the potential of operators to reduce delays below 24 hours per CEL on the surface cas ing and 48 hours on the intermediate casing . While the estimate possibly represents the maximum total cost, it may underestimate the total costs if

CELs r esult in the delays assumed.

We have assumed delay times to account for additional compressive stren gth requirements for cement bonding and ancillary delays that could occur. However, there are several ways for operators to reduce the amount of idle time. Table 1 8 shows the sensitivity of the upper bound

total estimates to assumed idle times. If operators are able to reduce the assumed delays by 25

percent , then the upper bound costs estimates would be reduced by 19 percent

. On the other hand, if the assumptions underestimate the delay times by 25 percent , then the upper bound

estimate would be i ncreased by 19 percent

.

The administrative compliance costs are non

- trivial and are based on a per submission cost of $478. It is likely that operators, over time, will be able to gain efficiencies and reduce costs below the estimates provided.54

The cost s provided are estimates of the direct costs and not the overall costs to society. There is uncertainty about the effect that the rule would have across all potential hydraulic fracturing operations. The rule has a provision for type well approval of the NOI Sundry and log requirements (unless the operator encounters problems with improper cementing) and affords operators drilling many wells in a geologic area greater efficienc y than it does for operators drilling a single well or few wells. If one assum es that operators cannot derive efficiencies to avoid the costs of idle rig time, it could favor activity in develop ment fields over exploratory

areas.

There is als o flexibility in how the various BLM authorized officers might treat applications for

varia nces, and to what extent that will allow operators to potentially reduce costs. The revised proposed rule includes a provision allowing the BLM to approve a variance that would apply to all lands within the boundaries of a State, a tribe, or on a field, o r a basin. The BLM must determine that the variance would meet or exceed the effectiveness of the revised proposed rule.

State and tribes would be invited work with the BLM to craft variances that would allow technologies, processes or standards required or allowed by the State or tribe to be accepted as compliance with the rule. Such broad variances would allow the BLM and the States and tribes to improve efficiency and reduce costs for operators and for the agencies. There are well

construction method s, such as the use of a “frac string,” that reduce the pressures placed on the intermediate casing and surface casing strings during hydraulic fracturing operations. This is one potential area where an operator might receive a variance.55 Table 16: Lower Bound of Cost Estimates for Specific Requirements in the Rule, Years 1

– 10 ($MM)

Requirement 1 2 3 4 5 6 7 8 9 10 Total AV
CEL on Surface Casing 7.06 7.25 7.42 7.46 7.53 7.58 7.66 7.74 7.88 8.04 75.61
CEL on Intermediate Casing 1.46 1.50 1.53 1.54 1.56 1.56 1.58 1.60 1.63 1.66 15.61
CEL if Inadequate Cementing 0.72 0.74 0.76 0.76 0.77 0.77 0.78 0.79 0.80 0.82 7.72
Lining Pits 0.03 0.03 0.03 0.03 0.03 0.03 0.03 0.03 0.03 0.04 0.33
NOI Sundry 0.19 0.20 0.20 0.20 0.21 0.21 0.21 0.21 0.21 0.22 2.06
SR Sundry 1.70 1.75 1.79 1.80 1.82 1.83 1.85 1.87 1.90 1.94 18.24
Variance Requests 0.02 0.02 0.02 0.02 0.02 0.02 0.02 0.02 0.02 0.02 0.21

Nominal Total (Undiscounted) 11.19 11.48 11.75 11.82 11.93 12.00 12.13 12.26 12.48 12.74 119.79 11.98

Real Total (Discounted at 3%) 10.86 10.82 10.76 10.50 10.29 10.05 9.86 9.68 9.57 9.48 101.88 11.94

Real Total (Discounted at 7%) 10.46 10.03 9.59 9.02 8.51 8.00 7.55 7.14 6.79 6.48 83.56 11.90

Real Total (Discounted at 10%) 10.17 9.49 8.83 8.07 7.41 6.78 6.22 5.72 5.29 4.91 72.90 11.86

Real Total (Discounted at 12%) 9.99 9.15 8.37 7.51 6.77 6.08 5.49 4.95 4.50 4.10 66.92 11.84

Table 17: Upper Bound of Cost Estimates for Specific Requirements in the Rule , Years 1

– 10 ($ million )

Requirement 1 2 3 4 5 6 7 8 9 10 Total AV
CEL on Surface Casing 14.10 14.47 14.81 14.89 15.04 15.13 15.28 15.45 15.73 16.05 150.93
CEL on Intermediate Casing 1.46 1.50 1.53 1.54 1.56 1.56 1.58 1.60 1.63 1.66 15.61
CEL if Inadequate Cementing 0.72 0.74 0.76 0.76 0.77 0.77 0.78 0.79 0.80 0.82 7.72
Lining Pits 0.03 0.03 0.03 0.03 0.03 0.03 0.03 0.03 0.03 0.04 0.33
NOI Sundry 0.19 0.20 0.20 0.20 0.21 0.21 0.21 0.21 0.21 0.22 2.06
SR Sundry 1.70 1.75 1.79 1.80 1.82 1.83 1.85 1.87 1.90 1.94 18.24

Variance Requests 0.02 0.02 0.02 0.02 0.02 0.02 0.02 0.02 0.02 0.02 0.21

Nominal Total (Undiscounted) 18.22 18.70 19.14 19.25 19.44 19.55 19.76 19.97 20.33 20.75 195.11 19.51

Real Total (Discounted at 3%) 17.69 17.63 17.52 17.10 16.77 16.38 16.06 15.77 15.58 15.44 165.93 19.45

Real Total (Discounted at 7%) 17.03 16.34 15.63 14.68 13.86 13.03 12.30 11.62 11.06 10.55 136.10 19.38

Real Total (Discounted at 10%) 16.57 15.46 14.38 13.15 12.07 11.04 10.14 9.32 8.62 8.00 118.73 19.32

Real Total (Discounted at 12%) 16.27 14.91 13.63 12.23 11.03 9.91 8.94 8.07 7.33 6.68 108.99 19.2956 Table 18: Sensitivity of Upper Bound Estimate to Various Idle Times

Effect on Upper Bound

Estimate Percent Change in Hours of Idle Time

- 50%

- 25% 0% 25% 50%

Upper Bound Estimate ($MM) (Undiscounted) 12.20 15.86 19.51 23.17 26.82

Percent Change in Upper

Bound Estimate - 37%

- 19%

--- 19% 37%57

Estimated Costs of Alternative 1

Alternative 1 requires logs to evaluate the cement behind casing strings protecting usable water. It requires the use of storage tanks to manage flowback

.

We were not able to estimate the total costs of the storage tank requirement, due to the lack of

a vailable data on the prevalence of storage tank use. Ther efore, the annualized costs of

Alternative 1 are unknown but expected to be higher than those presented below and in Table 20

and Table 21.

For the remaining requirements, the a nnualized costs to t he industry are estimated to be between about $117 and $213 million. Table 20 and Table 21 show lower and upper bound estimates, respectively , for the quantifiable costs . The tables provide a range for potential costs for each

year of the 10

- year period

. In a given year, requirement costs are provided separately and also totaled at the bottom of the table. The net present values for the total costs are also provided, using discount rates of 3, 7, 10, and 12 percent. We also present the annualized value in the right

column of each table for each of those discount rates.

The net present value of total costs over the 10

- year period are estimated to be between $1.0 to $1.8 billion when discounted at 3 percent , between $0.8 and $1.5 billion when discounted at 7

percent , between $0.7 and $1.3 billion when discounted at 10 percent , and between $0.7 and $1.2

billion when discounted at 12 percent

.

The annualized costs are between $118 and $213 million when undiscounted, between $118 and $213 millio n when using a 3 percent discount rate, between $118 and $212 million when using a 7 percent discount rate, between $117 and $211 million when using a 10 percent discount rate, and between $117 and $211 million when using a 3 percent discount rate.

Like the rule provisions, the largest cost burden with Alternative 1 lies with the cement evaluation log requirement. The cost of the CEL requirement is estimated to be between roughly $100 million and $200 million per year. Alternative 1 does not have provi sions allowing for type well approval. As such, operators would be required to run CELs (or CBLs as originally proposed) on all casing strings in a well that protect usable water.

Also, like the cost estimates described in the previous section, these r esults attempt to constrain the potential costs. The results are highly dependent on the potential delays associated with running CELs. Other compliance costs are generally the same, except for the total costs to submit NOI Sundry requests, since this al ternative would require submissions for each propose d hydraulic fracture operation.

The cost of requiring storage tanks is unknown due to the lack of data about the prevalence of storage tank use, particularly on BLM

- managed leases. As described previous ly , the costs of renting storage tanks for managing flowback may vary based on the design. The costs could be $6,000 and $17,000 per well for recovery of the flowback alone . Or, if the operator uses the

storage tanks as part of a centralized recycling system for use on multiple wells, then the costs of renting tanks may be about $42,000 per well. Instead of renting, operators might choose to58

purchase storage tanks for use on multiple sites. The initial investme nt might be about $600,000

, but the operator might reuse the tanks for up to 5 to 7 years.

This estimate does not account for cost savings that operators are likely to experience. Closed

loop system s may eliminate the time and expense associated with res erve pit construction and reclamation. Operators are expected to experience fewer operational issues associated with liner system leakage. Also, tanks may be dismantled and reused in future operations.

Estimates for Alternative 1 describe direct costs t o the industry and not costs to society. It is far more likely under this scenario that the industry would be adversely impacted, with harmful effects on employment, exploration and production activities, and production.59 Table 20: Lower Bound of C ost Estimates for Specific Requirements in Alternative 1, Years 1

– 10 ($million)

Requirement 1 2 3 4 5 6 7 8 9 10 Total AV
CEL on Surface Casing 88.78 91.11 93.26 93.77 94.69 95.26 96.26 97.31 99.05 101.09 950.58
CEL on Intermediate Casing 18.33 18.81 19.26 19.36 19.55 19.67 19.88 20.09 20.45 20.87 196.28
CEL if Inadequate Cementing 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00
Storage Tanks Unk Unk Unk Unk Unk Unk Unk Unk Unk Unk Unk
NOI Sundry 1.70 1.75 1.79 1.80 1.82 1.83 1.85 1.87 1.90 1.94 18.24
SR Sundry 1.70 1.75 1.79 1.80 1.82 1.83 1.85 1.87 1.90 1.94 18.24
Variance Requests 0.17 0.17 0.18 0.18 0.18 0.18 0.18 0.19 0.19 0.19 1.82

Nominal Total (Undiscounted) 110.69 113.60 116.28 116.91 118.06 118.77 120.02 121.32 123.49 126.04 1,185.17 118.52

Real Total (Discounted at 3%) 107.47 107.07 106.41 103.88 101.84 99.47 97.58 95.77 94.64 93.78 1,007.92 118.16

Real Total (Discounted at 7%) 103.45 99.22 94.92 89.19 84.18 79.14 74.74 70.61 67.17 64.07 826.69 117.70

Real Total (Discounted at 10%) 100.63 93.88 87.36 79.85 73.31 67.04 61.59 56.60 52.37 48.59 721.22 117.38

Real Total (Discounted at 12%) 98.83 90.56 82.76 74.30 66.99 60.17 54.29 49.00 44.53 40.58 662.02 117.17

Table 21: Upper Bound of Cost Estimates for Specific Requirements in Alternative 1, Years 1

– 10 ($million)

Requirement 1 2 3 4 5 6 7 8 9 10 Total AV
CEL on Surface Casing 177.21 181.87 186.16 187.18 189.02 190.16 192.15 194.24 197.71 201.79 1,897.51
CEL on Intermediate Casing 18.33 18.81 19.26 19.36 19.55 19.67 19.88 20.09 20.45 20.87 196.28
CEL if Inadequate Cementing 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00
Storage Tanks Unk Unk Unk Unk Unk Unk Unk Unk Unk Unk Unk
NOI Sundry 1.70 1.75 1.79 1.80 1.82 1.83 1.85 1.87 1.90 1.94 18.24
SR Sundry 1.70 1.75 1.79 1.80 1.82 1.83 1.85 1.87 1.90 1.94 18.24
Variance Requests 0.17 0.17 0.18 0.18 0.18 0.18 0.18 0.19 0.19 0.19 1.82

Nominal Total (Undiscounted) 199.13 204.35 209.18 210.32 212.39 213.67 215.91 218.25 222.16 226.74 2,132.10 213.21

Real Total (Discounted at 3%) 193.33 192.62 191.43 186.87 183.21 178.94 175.55 172.29 170.26 168.71 1,813.23 212.57

Real Total (Discounted at 7%) 186.10 178.49 170.75 160.45 151.43 142.38 134.46 127.03 120.84 115.26 1,487.19 211.74

Real Total (Discounted at 10%) 181.02 168.89 157.16 143.65 131.88 120.61 110.80 101.82 94.22 87.42 1,297.46 211.16

Real Total (Discounted at 12%) 177.79 162.91 148.89 133.66 120.52 108.25 97.67 88.15 80.11 73.00 1,190.95 210.7860

Estimated Costs of Alternative 2

Alternative 2 requires logs to evaluate the cement behind casing strings protecting usable water. It does not establish requirements for storage tanks or lined pits.

Annualized costs to the industry are estimated to be between about $117 a nd $213 million. The annualized costs vary only slightly under the various discount rates examined. We attribute the uniformity to the fact that the cost per operation is expected to remain relatively constant over time, the costs for an operation are co nfined within a short time period, and the number of hydraulic fracturing operations on Federal and Indian leases is expected to increase only slightly in future years, meaning the total industry costs are expected to be relatively consistent in future

yea rs.

Table 22 and Table 23 show lower and upper bound estimates, respectively. The tables provide a range for potential costs for each year of the 10

- year period . In a given year, requirement costs are provided separately and also totaled at the bottom of the table. The net present values for the total costs are also provided, using discount rates of 3, 7, 10, and 12 percent. We also present the annualized value in the right column of each table for each of those discount rates.

The net present value of total costs over the 10

- year period are estimated to be between $1.0 to $1.8 billion when discounted at 3 percent , between $0.8 and $1.5 billion when discounted at 7

percent , between $0.7 and $1.3 billion when discounted at 10 percent , and between $0.7 and $1.2

billion when discounted at 12 percent . Again, the annualized costs are estimated to be between $117 and $213 million in all discount rate scenarios examined.61 Table 22: Lower Bound of Cost Estimates for Specific Requirements in Alte rnative 2 , Years 1

– 10 ($ million )

Requirement 1 2 3 4 5 6 7 8 9 10 Total AV
CEL on Surface Casing 88.78 91.11 93.26 93.77 94.69 95.26 96.26 97.31 99.05 101.09 950.58
CEL on Intermediate Casing 18.33 18.81 19.26 19.36 19.55 19.67 19.88 20.09 20.45 20.87 196.28
CEL if Inadequate Cementing 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00
No Tanks/Pit Liner Req. 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00
NOI Sundry 1.70 1.75 1.79 1.80 1.82 1.83 1.85 1.87 1.90 1.94 18.24

SR Sundry 1.70 1.75 1.79 1.80 1.82 1.83 1.85 1.87 1.90 1.94 18.24
Variance Requests 0.17 0.17 0.18 0.18 0.18 0.18 0.18 0.19 0.19 0.19 1.82

Nominal Total (Undiscounted) 110.69 113.60 116.28 116.91 118.06 118.77 120.02 121.32 123.49 126.04 1,185.17 118.52

Real Total (Discounted at 3%) 107.47 107.07 106.41 103.88 101.84 99.47 97.58 95.77 94.64 93.78 1,007.92 118.16

Real Total (Discounted at 7%) 103.45 99.22 94.92 89.19 84.18 79.14 74.74 70.61 67.17 64.07 826.69 117.70

Real Total (Discounted at 10%) 100.63 93.88 87.36 79.85 73.31 67.04 61.59 56.60 52.37 48.59 721.22 117.38

Real Total (Discounted at 12%) 98.83 90.56 82.76 74.30 66.99 60.17 54.29 49.00 44.53 40.58 662.02 117.17

Table 23: Upper Bound of Cost Estimates for Specific Requirements in Alternative 2 , Years 1

– 10 ($ million )

Requirement 1 2 3 4 5 6 7 8 9 10 Total AV
CEL on Surface Casing 177.21 181.87 186.16 187.18 189.02 190.16 192.15 194.24 197.71 201.79 1,897.51
CEL on Intermediate Casing 18.33 18.81 19.26 19.36 19.55 19.67 19.88 20.09 20.45 20.87 196.28
CEL if Inadequate Cementing 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00
No Tanks/Pit Liner Req. 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00
NOI Sundry 1.70 1.75 1.79 1.80 1.82 1.83 1.85 1.87 1.90 1.94 18.24
SR Sundry 1.70 1.75 1.79 1.80 1.82 1.83 1.85 1.87 1.90 1.94 18.24
Variance Requests 0.17 0.17 0.18 0.18 0.18 0.18 0.18 0.19 0.19 0.19 1.82

Nominal Total (Undiscounted) 199.13 204.35 209.18 210.32 212.39 213.67 215.91 218.25 222.16 226.74 2,132.10 213.21

Real Total (Discounted at 3%) 193.33 192.62 191.43 186.87 183.21 178.94 175.55 172.29 170.26 168.71 1,813.23 212.57

Real Total (Discounted at 7%) 186.10 178.49 170.75 160.45 151.43 142.38 134.46 127.03 120.84 115.26 1,487.19 211.74

Real Total (Discounted at 10%) 181.02 168.89 157.16 143.65 131.88 120.61 110.80 101.82 94.22 87.42 1,297.46 211.16

Real Total (Discounted at 12%) 177.79 162.91 148.89 133.66 120.52 108.25 97.67 88.15 80.11 73.00 1,190.95 210.7862



### 4.2 Average Compliance Costs for Operators

The provisions of the rule would result in compliance costs ranging from $3,138 to $5,110 for all hydraulic fracturing operations expected to occur. We derive these estimates by averaging the total estimated costs (undisco unted) over the 10

- year period by the total number of hydraulic fracturing operations expected to occur. The CEL requirements represent the bulk of that portion, $2,591 to $4,564.

The provisions in Alternative 1 would result in higher compliance costs per operation since CELs are required for each well. We also expect that the storage tank requirements would be costly; however, we were not able to calculate an average cost for this requirement. The

estimated costs of the alternative range from $31,047 to $55,845. Compliance costs for Alternative 2 are roughly the same.

Average compliance cost s per operation for each of the policy options are shown below.

Table 24: Average Compliance Costs in 2013 Across All Operations

for the Rule, Alternativ e 1, and Alternative 2

Requirement Average Across All Operations

Rule Alternative 1 Alternative 2

Low High Low High Low High

Count of Hydraulic Fracturing Operations (in Year 1) 3,566 3,566 3,566
CEL on Surface Casing $1,980 $3,953 $24,894 $49,692 $24,894 $49,692

CEL on Intermediate Casing $409 $409 $5,140 $5,140 $5,140 $5,140

CEL if Inadequate Cementing $202 $202 $0 $0 $0 $0

Lining Pits or Tank Req. $9 $9 Unk Unk $0 $0

NOI Sundry $54 $54 $478 $478 $478 $478

SR Sundry $478 $478 $478 $478 $478 $478

Variance Requests $5 $5 $48 $48 $48 $48

Total $3,138 $5,110 $31,038 $55,836 $31,038 $55,83663



### 4.3 BLM Administrative Burden

The processing of NOI Sundry, SR Sundry, and variance requests associated with the rule would pose additional burden to the BLM ; however, it is unclear the extent to which the BLM can meet the additional burden with existing capacity.

An additional 8.44 full

- time equivalent ( FTE ) of workload is estimated to be required to meet the

administrative burden of the rule in Year 1 . Alternatives 1 and 2 would require about 21 FTE in

Year 1 , since the NOI Sundry requests would be far greater. There are opportunities for the BLM to experience efficien cies in the processing of these sundry requests or in the processing of other permits, and those efficiencies would reduce the required capacity in future years.

Table 25: BLM Administrative Burden and FTE Requirements for Year 1

Requirement Revised Proposed Rule Alternative 1 Alternative 2

Annual

Burden Cost ($) Equivalent

FTE Required Annual

Burden Cost ($) Equivalent

FTE Required Annual

Burden Cost ($) Equivalent

FTE Required
NOI Sundry 92,189 1.56 811,682 13.72 811,682 13.72

SR Sundry 405,841 6.86 405,841 6.86 405,841 6.86
Variance Requests 1,152 0.02 10,146 0.17 10,146 0.17

Total 499,183 8.44 1,227,669 20.75 1,227,669 20.7564



### 4

. 4 Benefits of the Revised Proposed Rule and Alternatives

Benefits of the Revised Proposed Rule

The rule provisions, as described in the revised proposed rule, would require an operator to conduct tests on a well before it conducts hydraulic fracturing operations on that well. It would compel operators to conduct an estimated 293 CELs per year on su rface casings, 14 CELs per year on intermediate casings, and 110 CELs per year on casing strings where there is an initial indication of inadequate cementing.

Relative to the alternatives, the rule would not compel as many CELs. Therefore, the rule mig ht

not reduce as much of the risk (of conducting hydraulic fracturing operations on wells with inadequate formation protection) as the alternatives would

. The rule would ensure that operators demonstrate wellbore integrity with pressure tests on 100 perc ent of the wells and with CELs on the casing strings that protect usable water on only 8 percent of wells. The level of risk

reduction across subsequent wells relies on the replication of adequate cementing across multiple wells in a geographic area with the same geologic characteristics.

The rule would compel an estimated 110 CELs to demonstrate that inadequate cementing was corrected by operators. As such, it requires a verification of proper remedial cementing on the very wells that pose greater risk

.

Under the rule, operators would submit an average of 432 NOI Sundry applications per year covering about 3,816 hydraulic fracturing operations. 83 T he BLM would receive individual hydraulic fracturing plans for 11 percent of the proposed operations, and the remaining 89

percent of operations would be for subsequent wells to a type well. The type well provision, relative to the alternatives, reduces burden on the industry and the BLM. The submission of NOI Sundry applicat ions would provide the BLM with the necessary information needed to make informed decisions about the public’s resources and thus improve the public welfare.

The rule is estimated to compel only 6 additional lined pits per year , simply because most of the states where the BLM manages oil and gas resources already require lined pits. For those 6 pits, the requirement would immediately remove sources of harm to the environment and the public

from the saturation of the surface envir onment with fracturing fluids

.

The rule would compel an estimated 3,816 SR Sundry reports and public disclosures of the chemical content of the hydraulic fracturing fluids annually . The increase in information about additives could aid water users when they consider the potent ial effects of hydraulic fracturing operations and constituent chemicals.

Without implementing the rule, we estimate that the likelihood of an incident resulting from a hydraulic fracturing operation could be between 0.03 and 2.70 percent. T he rule wou ld potentially reduce the risks associated with hydraulic fracturing operations ; however, it is uncertain by what amount

. Damage from an incident that occurs could cost between $ 15 ,000

83 The average is for the 10

- year period, 2013

- 2022.65

and $1 million for remediation plus any lost revenue from unrecoverabl e resources, including spilled or stranded resources.

Benefits of Alternative 1

Alternative 1 would compel operators to conduct CELs on the casing strings protecting usable

water in 96 percent of the wells proposed for hydraulic fracturing operations. The remaining 4

percent of operations are estimated to be on existing wells or refracturing jobs, where CELs are impractical. The rule would compel an average of 3,677 CELs per year on surface c asings, 177 CELs per year on intermediate casings, and 0 CELs per year on casing strings where there is an initial indication of inadequate cementing. The requirement to run a CEL when there is inadequate cementing would have no practical effect under Alt ernative 1 , since operators would conduct those logs regardless. Compared with the rule

, Alternative 1 would compel significantly

more CELs. As such

, it is likely to offer more risk reduction than the rule does

.

Under Alternative 1 , operators would su bmit an average of 3,816 NOI Sundry applications per year covering all of the hydraulic fracturing operations. There is uncertainty about the added benefit of receiving so many NOI Sundry applications if information for a large majority of the hydraulic f

racturing operations are relatively the same.

It is likely that the alternative would compel operators on a substantial number of hydraulic fracturing operations to use storage tanks instead of pits; however, that number is not known at

this time

. This would immediately remove sources of harm to the environment and the public.

Alternative 1 would compel 3,816 SR Sundry reports and public disclosures of the chemical content of the hydraulic fracturing fluids. The increase in information about additives could aid water users when they consider the potential effects of hydraulic fracturing operations and

constituent chemicals.

Overall, this alternative would reduce the risks associated with hydraulic fracturing operations. Generally speaking, it could offer greater risk reduction than the rule, since it would require operators to conduct CELs on all casing strings that protect usable water. Also, the BLM would receive individual applications for all hydraulic fracturing operations. There could be som e variability in the operations across hydraulic fracturing jobs on subsequent wells even if they are under a type well approval. The nature of hydraulic fracturing necessitates some degree of variability in plans, including the well depth, fluid mixture, and subsurface conditions. Since the BLM would receive and review each proposed operation individually, this alternative potentially offers greater risk reduction

.

Benefits of Alternative 2

Possibly 5 or 6 hydraulic fracturing operations may use unlined pits without the regulation.
However, even that number could overestimate the effect, since states currently without minimum requirements for pit liners or storage tanks are likely to adopt s uch regulations in the

near future.66



### 5. Economic Impact Analysis and Distributional Assessments

5.1 Energy System Impact Analysis

Executive Order 13211 requires that agencies prepare and submit to the Administrator of the Office of Information and Regulatory Affairs (OIRA), OMB, a Statement of Energy Effects for certain actions identified as significant energy actions. Section 4(b) of Executive Order 13211

define s 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 ru lemaking, 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) tha t is designated by the Administrator of OIRA as a significant energy action.

The additional burden posed by this rule would vary by the type of well proposed for hydraulic fracture. As such, we estimate the additional cost burden under a number of well types (in Table 13) and the average cost per hydraulic fracturing operation (in Table 24)

.

A key consideration is the extent to which the costs of the requirements might impact investment, production, employment, and a number of other factors. That is , to what extent, if any, would an operator choose to invest in other areas, non

- Federal and non

- Indian lands, when faced with the cost requirements of the rule. Since the bulk of the costs would apply to hydraulic fracturing operations on wells that are yet to be drilled (and not on existing wells and to refracturing operations), operators will be able to account for any cost increases up front when making investment decisions.

The BLM believes that the additional cost per hydraulic fracturing operatio n is insignificant when compared with the drilling costs in recent years, the production gains from hydraulically fractured well operations

, and the net incomes of entities within the oil and natural gas industries.

Table 26 shows the average compliance costs, by well type or operation, as a percent of the total costs of drilling a well. For a single well or a type well, the compliance costs represent about 0.4

to 1. 4 percent of the costs of drilling a well. For a subsequent well to a type we ll, the costs represent between 0. 01 and 0. 02 percent of the total drilling costs. For existing wells and

refracture operations, the percentages are even lower, at about 0.01 to 0.03 percent. When averaging the compliance costs across all operations, the costs represent between 0.04 and 0.13 percent of the costs of drilling a well.

Since the estimated compliance costs are not substantial when compared with the total costs of drilling a well

, we believe that the rule is unlikely to have an effect on the investment decisions of firms, and the rule is unlikely to affect the supply, distribution, or use of energy.67 Table 26: The Average Compliance Costs of the Rule as a Percent of Total Drilling Costs

Activity Well Type or Fracturing Operation

Average Across All Operations Type Well or Single

Well Subsequent

Well under Type Well Approval Existing

Well Re

Fracture Operation Low High Low High Percent of Drilling Costs for a Crude Oil, Natural Gas, and Dry Well (2007$) (1) 0.7128% 1.3301% 0.0167% 0.0243% 0.0241% 0.0752% 0.1225% Percent of Drilling Costs

for a Crude Oil Well (2007$) (1) 0.7434% 1.3871% 0.0174% 0.0253% 0.0251% 0.0784% 0.1277% Percent of Drilling Costs

for a Natural Gas Well (2007$) (1) 0.7611% 1.4202% 0.0178% 0.0259% 0.0257% 0.0803% 0.1308%

Percent of Drilling Costs

for a horizontal well in the

Bakken Three Forks (reported in 2010) (2) 0.5507% 1.0275% 0.0129% 0.0188% 0.0186% 0.0581% 0.0946% Percent of Drilling Costs

for a horizontal well in the Marcellus Shale (reported in 2011) (3) 0.3913% 0.7301% 0.0092% 0.0133% 0.0132% 0.0413% 0.0672%

Notes: (1) Average drilling costs in 2007 range from $3.9 million to about $4.2 million. (EIA 2012) (2) Costs of $5.4 million cited by Investopedia from Continental Resources. (Investopedia 2010) (3) Costs of $7.6 million cited by Marcellus Drilling News from a University of Pittsburgh Study (Marcellus 2011)68



### 5.2 Employment Impact Analysis

Executive Order 13563 reaffirms the principles established in Executive Order 12866, but calls for additional consideration of the regulatory impact on employment. It states, “Our regulatory system must protect public health, welfare, safety, and our envi ronment while promoting economic growth, innovation, competitiveness, and job creation.” An analysis of employment impacts is a standalone analysis and the impacts should not be included in the estimation of

benefits and costs.

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

- time

tests on a well or make a one

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

- time event.

Compliance with the operational requirements is expected to shift resources from firms in the

crude oil and natural gas extraction industries (NAICS codes: : 211111

- Crude Petroleum and Natural Gas Extraction, 211112

- Natural Gas Liquid Extraction) to f irms providing support services for drilling oil and gas wells (NAICS code: 213111

- Drilling Oil and Gas Wells)

. For

e xample, the requirement for a CE L on the surface casing represents a burden to the operator but a benefit to the company running the log

.

Of principal interest is the extent to which the financial burden is expected to change operators’ investment decisions. If the financial burden is not significant and all other factors are equal, then one would expect operators to maintain existing levels of investm ent and employment. As with the results in the Section 5.1, the BLM believes that the proposed rule would result in an additional cost per well stimulation that is small and will not alter the inv estment or employment

decisions of firms.

Firms in the s upport services for oil and gas drilling industry are likely to benefit from the rule, since they would likely carry out the operational requirements of the rule. Though we do not know the incremental revenue gains from performing these services, the oper ational requirements themselves are likely to require additional capacity.



### 5.3 Small Business Impact Analysis

The Regulatory Flexibility Act as amended by the Small Business Regulatory Enforcement Fairness Act (SBREFA) generally requires an agency to prepare a regulatory flexibility analysis of any rule subject to notice and comment rulemaking requirements under the Administrative Procedure Act or any other statute, unless the agency certifies that the rule will not have a significant economic impact o n a substantial number of small entities. Small entities include small businesses, small governmental jurisdictions, and small not

- for

- profit enterprises.

The BLM reviewed the Small Business Administration (SBA) size standards for small

businesses and th e 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 concludes69

that about 99 percent of the entities operating in the relevant sectors 84 are small busin esses in that they employ fewer than 500 employees. Also, within these relevant sectors, small firms account

for 74 percent of the total value of shipments and receipts for services, 86 percent of the total cost of supplies, 78 percent of the total capita l expenditures (excluding land and mineral rights),

and 67 percent of the paid employees (see tables in Section 2. 7 ).

Small entities represent the overwhelming majority of entities operating in the onshore crude oil and natural gas extraction industry. As such, the rule is likely to affect a significant number of small entities. To examine the economic impact of the rule on small entities, the BLM performed a screening analysis for impacts on a sample of expected affected small entities by comparing co mpliance costs 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 well s for hydraulic fracture completions. Using AFMSS data for well completions, we compiled a list of firms that completed wells within the past 5 years. We expect that these firms are most likely to be impacted. From that list, we researched for company

a nnual report filings with the Securities and Exchange Commission (SEC) to determine annual company net incomes and employment figures. From the original list, we found 55 company filings. Of those, 33 were small businesses.

Using the net income data f or the companies that filed SEC Form 10

- K, we used the estimated compliance costs per type of well or fracturing operation and the average costs across all operations to calculate the percent of compliance costs as a portion of annual company net

incomes for 2011. We used the absolute values of the percentages in the average, so that the negative net incomes would not negate the positive net incomes, and vice versa. Averaging

results for the small businesses that we examined , t he average costs of the rule are expected to represent between 0.0 41 and 0.0 66 percent of the company net incomes. The results of those findings are in Table 29 and also in the Appendix.

Table 27: Compliance Costs as a Share of Company Net Income

Descriptive Statistic Type of Well or Operation, and Average across All Operations (%)

Type well or single well (lower bound) Type well

or single

well (upper bound) Subsequent

well under type well approval Existing

well Re

fracture operation Average

across all operations (lower bound) Average

across all operations (upper bound) Average of absolute

values 0.3838% 0.7161% 0.0090% 0.0131% 0.0130% 0.0405% 0.0660%

Minimum value

- 2.4855%

- 4.6377%

- 0.0583%

- 0.0847%

- 0.0839%

- 0.2622%

- 0.4271%

Maximum value 2.1196% 3.9549% 0.0497% 0.0722% 0.0715% 0.2236% 0.3642%

84 NAICS codes: 211111

- Crude Petr oleum and Natural Gas Extraction, 211112

- Natural Gas Liquid Extraction

, and 213111

- Drilling Oil and Gas Wells

.70



### 6. Statutory and Executive Order Reviews

6.1 Executive Order 12866 Regulatory Planning and Review

In accordance with the criteria in Executive Order 12866, the Office of Management and Budget has determined that this rule is a significant regulatory action.

The rule will not have an annual effect on the economy of $100 million or more or adversely affect in a material way the economy, a sector of the economy, productivity, competition, jobs, the environment, public health or safety, or state, local, or tribal governments or communities.



### 6.2 Regulatory Flexibility Act and Small Business Regulatory Enforcement Fairness Act of 1996 (5 U.S.C. 601

- 612)

The Regulatory Flexibility Act as amended by the Small Business Regulatory Enforcement Fairness Act (SBREFA) g enerally requires an agency to prepare a regulatory flexibility analysis of any rule subject to notice and comment rulemaking requirements under the Administrative Procedure Act or any other statute, unless the agency certifies that the rule will not have a significant economic impact on a substantial number of small entities (SISNOSE). Small entities include small businesses, small governmental jurisdictions (including tribal governments) , and

small not

- for

- profit enterprises.

The BLM reviewed the SBA size standards for small businesses and the number of entities fitting those size standards as reported by the U.S. Census Bureau in the 2007 Economic Census. Using the Economic Census data, the BLM concludes that about 99 percent of the entities operatin g in the relevant sectors are small businesses in that they employ fewer than 500 employees.

We also examined potential impacts on small businesses that are most likely to be impacted by the rule and, more specifically, the requirements that would pose a burden to operators. Using AFMSS data for well completions, we compiled a list of firms that completed wells within the past 5 years. We expect that these firms are most likely to be financially impacted by the CEL requirements. From that list, we res earched for company annual report filings with the SEC to determine annual company net incomes and employment figures. From the original list, we found 55 company filings. Of those, 33 firms were classified as small businesses.

Using the net income data for the small businesses that filed SEC Form 10

- K, we used the estimated compliance costs per well type or fracturing operation, and the average costs across all operations to calculate the percent of compliance costs as a portion of annual company net

in comes for 2011. Averaging results for the small businesses that we examined, the average costs of the rule are expected to represent between 0.041 and 0.066 percent of the company net

incomes.71

Therefore, after considering the economic impact of the rul e on these small entities, the screening analysis indicates that this rule will not have a significant economic impact on a

substantial number of small entities.



### 6.3 Unfunded Mandates Reform Act of 1995 (P.L. 104

- 4)

Under the Unfunded Mandates Act, agenc ies 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.

Th is rule 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 tha t apply to such governments, nor does it impose obligations upon

them.



### 6. 4 Executive Order 13211 Actions Concerning Regulations that Significantly Affect Energy Supply, Distribution, or Use

Under Executive Order 13211 , agencies are required to prepare and submit to OMB a Statement of Energy Effects for significant energy actions. This Statement is to include a detailed statement of “any adverse effects of energy supply, distribution, or use (including a shortfall in

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 Execu tive 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 t he additional cost per hydraulic fracturing operation is insignificant when compared with the drilling costs in recent years, the production gains from hydraulically fractured well operations

, and the net incomes of entities within the oil and natural gas industries. For a single well or a type well, the compliance costs represent about 0.4 to 1.5 percent of the costs of drilling a well. For a subsequent well to a type well, the costs represent between 0.04 and 0.08 percent of the total drilling costs. F or existing wells and refracture operations, the percentages are even lower, at about 0.01 to 0.03 percent. When averaging the compliance costs across all operations, the costs represent between 0.04 and 0.13 percent of the costs of drilling a

well.72

Si nce 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, distri bution, or use of energy. As such, the rule is not a “significant energy action” as defined in Executive Order 13211.73



### 7. Conclusion

Combined with horizontal drilling, hydraulic fracturing has grown in significance over the past decade, al lowing oil and g as operators to produce from shale and tight formations that previously were uneconomic. The well completion technique involves injecting fluids

-- containing water, proppants, and chemicals

-- into the reservoir rock with sufficient pressure to fracture the rock and thus access the resources that were previously trapped. The technique has been under scrutiny because it is resource intensive and many are concerned about potential surface and subsurface damage to freshwater aquifers.

A report conducted by t he 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 activity confirm that operators take prompt action to repair defect ive cementing jobs.

The BLM has existing regulations on hydraulic fracturing that were conceived before the operations grew in prevalence and magnitude to where they are today. It requires NOI Sundry applications for “non

- routine” fracturing operations

, but is unclear about what that means. This omission makes the regulation functionally difficult to apply. Also, from a resource management perspective, the current regulation results in incomplete information being provided

to the BLM. The lack of info rmation restricts the BLM’s ability to make informed resource decisions about proposed hydraulic fracturing operations. It also restricts the BLM’s ability to respond effectively to events where environmental resources have been compromised.

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 of the rule would help the BLM better manage and protect the public’s resources. The rule also seeks to minimize the risks associated with hydraulic fracturing by placing requirements to help ensure wellbore integrity and proper management of flowback

.

This an alysis attempts to measure the potential costs and benefits that would occur as a result of the rule. As such, it attempts to measure the impacts in relation to the current operating environment. An important aspect of this analysis and the rule itself i s the distinction between the activities that operators currently conduct and those additional activities that the rule would compel. This change in behavior is the basis of the cost and benefit estimates. Operators conduct many of the activities require d by the rule as a matter of standard industry practice or to comply with other state and F ederal regulations or conditions of approvals for permits.

Potential costs of the rule are easier to estimate because the requirements are clear. The challenge l ies in estimating the potential unintended consequences of the rule. The rule has a requirement that would add an additional step to the drilling process. A large source of uncertainty is whether operators would be able to incorporate that step into thei r current process74

without incurring costs associated with drilling delays. The benefits are more uncertain, because much of the potential damage from hydraulic fracturing may occur in the subsurface environment, making it difficult to first identify and t hen to assign responsibility to an operation.

The compliance costs of the rule are estimated to be between $12 and $20 million per year. The estimated costs of the alternatives are much higher, generally between $115 and $215 million per year. Th is ru le would impose fewer costs than the alternatives, primarily because it would require fewer cement evaluation logs. The rule would require operators on a single or a type

well to conduct cement evaluation logs on casing strings that protect usable water. Operators may seek and receive approval to forego the requirement on subsequent wells under a type well approval. The usefulness of this exemption relies on its functional application. The rule would also require operators to run logs on wells where the re is an indication of an inadequate cement job. This will likely apply to between 1 and 5 percent of wells. Operators are currently required to take remedial action when there is inadequate cementing, so the proposed rule would require that the operator run a log.

Among the alternatives examined, the BLM explored the option of requiring operators to manage flowback in storage tanks rather than pits. We were unable to estimate total compliance costs for this alternative requirement, since the prevalence of voluntary storage tank use, in general, is unknown. We believe that managing flowback in storage tanks could cost operators between $6,000 and $17,000 per well if trucking the flowback off

- site and $42,000 per well if recycling

flowback to use as flui d for subsequent hydraulic fracturing operations on

- site.

OMB Circular A

- 4 recognizes that not all benefits and costs can be described in monetary or even in quantitative terms. The potential benefits of the rule are more challenging to monetize

than the costs, but that does not mean that rule is without benefits. The rule is designed to reduce the environmental and safety risk s posed by hydraulic fracturing operations, particularly in its

treatment of flowback fluids, well construction, and hydraulic fr acture design.

The rule requires operators to take steps to ensure that wellbore integrity is maintained prior to and throughout the hydraulic fracturing process. It also requires operators to provide the BLM with information about the fracturing plan and design. We estimate that operators would submit an average of 432 NOI Sundry applications per year covering about 11 percent of hydraulic fracturing operations. The requirement should help the BLM to make informed decisions about fracturing proposals and potentially avoid other surface or subsurface damage.

The rule would compel operators to demonstrate wellbore integrity by conduct ing pressure tests
on 100 percent of wells and by conducting CELs on the casing strings that protect usable water

for about 8 percent of the wells. The rule would compel 110 CELs to demonstrate that inadequate cementing was corrected by operators. As such, it requires a verification of proper remedial cementing on the very wells that pose greater risk. Relative to the alternatives, the rule provisions would not compel as many CELs. Therefore, there is a chance that the rule would not reduce as much risk as the alternatives. However, t he estimated costs of the alternatives far exceed the estimated costs of the proposed rule.75

The rule would compel an estimated 3,816 SR Sundry reports and public disclosures of the chemical content of the hydraulic fracturing fluids annually . The increas e in information about additives could aid water users when they consider the potential effects of hydraulic fracturing operations and constituent chemicals.

Overall, the rule is likely to reduce the risks associated with hydraulic fracturing operations , but it is unclear by how much . W ithout any policy intervention, w e estimate the likelihood of an incident resulting from a hydraulic fracturing operation to be between 0.03 and 2.70 percent. Damage from an incident could cost between $ 15 ,000 and $1 mil lion for remediation plus any lost revenue from unrecoverable resources, including s pilled or stranded resources.76



### 8. References

American Petroleum Institute (2009). Hydraulic Fracturing Operations

– Well Construction and Integrity Guidelines. API Guida nce Document HF1. First Edition.

American Petroleum Institute. (July 19, 2010). Freeing Up Energy. Hydraulic Fracturing: Unlocking America’s Natural Gas Resources.

American Petroleum Institute (2010). “Water Management Associated with Hydraulic

Frac turing. API Guidance Document HF2. First Edition.”

Behr, P. (October 1, 2012). Safety of shale gas wells is up to the states

– and the ‘cement job’. EnergyWire . Retrieved from http://www.eenews.net/energywire/2012/10/01/archive/1?terms=hydraulic+fracturing+10

%2F01%2F2012

Bureau of Labor Statistics (2010). “Industries at a Glance: Mining, Quarrying, and Oil and Gas Extraction: NAICS 21.” January 28, 2012. Retrieved from http://www.bls.gov/iag/tgs/iag21.htm

Downey, M. (2009). Oil 101 . Wooden Table Press, LLC.

Ex ecutive 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 servic e costs to move higher. Retrieved from http://www.investopedia.com/stock

- analysis/2 010/mondaymarch

- 15

- oil

- service

- costs

- to

move

- higher

- clr

- xco

- sd

- bexp0315.aspx?partner=YahooSA#axzz2EleoUQQw77

Marcellus Drilling News ( September 2011). How much does it cost to drill a single Marcellus well? $7.6M. Retrieved from http://marcellusdrilling.com/2011/09/how

- much

- does

- it

cost

- to

- drill

- a

- single

- marcellus

- well

- 7

- 6m/

National Energy Technology Laboratory (2009). Modern Shale Gas Dev elopment in the United States: A Primer. U.S. Department of Energy.

Osborn, S., et al (2011). Methane contamination of drinking water accompanying gas

- well drilling and hydraulic fracturing. Proceedings of the National Academy of Sciences.

Secretary of Energy Advisory Board (2011). Shale Gas Production Subcomm ittee Second Ninety Day Report. November 18, 2011. Retrieved from http://www.shalegas.energy.gov/resources/111811_final_report.pdf

Shires, T. and Lev

- On, M ( September 21, 2012). Characterizing Pivotal Sources of Methane Emissions from Natural Gas Production: Summary and Analysis of API and ANGA Survey Responses.”

U .S. Census Bureau (2010). "Mining: Subject Series: General Summary: Industry Statistics by Employment Size: 2007 Economic Census." January 28, 2012. Retrieved from http://factfinder2.census.gov/faces/tableservices/jsf/pages/productview.xhtml?pid=ECN_ 2007_US_21SG13&prodType=table

U.S. Energy Information Administration ( January 23, 2012 ). Annual Energy Outlook with Projecti ons to 2035.

U.S. Energy Information Administration ( January 31, 2012 ). Costs of Crude Oil and Natural

Gas Wells Drilled. Retrieved from http://www.eia.gov/dnav/ng/ng_enr_wellcost_s1_a.htm

U.S. Environmental Protection Agency ( January 31, 2012 ). Natural Gas Extraction

– Hydraulic Fracturing. Retrieved from http://www.e pa.gov/hydraulicfracture/#providing

U.S. Small Business Administration (2010). "Table of Small Business Size Standards Matched to North American Industry Classification System Codes." Retrieved November 5, 2010.

U.S. Office of Personnel Management (20 09). “Salaries & Wages: Salary Table 2009

- GS.” January 31, 2012. Retrieved from http://www.opm.gov/flsa/oca/09tables/html/gs_h.asp

Warner, N., et al (2012). Geochemical evidence for po ssible natural migration of Marcellus Formation brine to shallow aquifers in Pennsylvania. Proceedings of the National Academy of Sciences, Vol. 109, July 24, 2012.78



### 9

. Appendix

A

- 1 Estimation of Type Well Applicability

A

- 2 Sample of Small Businesses79 Appendix A

- 1 Estimation of Type Well Applicability

Descriptive Statistic Grouping Method
By Case By Field By Township

Total Wells 17,475 17,475 17,475

Count of Grouping Category (e.g. # cases) 3,449 1,390 1,315

Average 5.067 12.572 13.289

Standard Deviation 27.608 62.011 55.103

Median 1 2 2

Low 1 1 1

High 1,048 1,446 1,04880 Appendix A

- 2 Sample of Small Businesses

Includes companies that completed wells with the past 5 years and filed SEC 10

- K forms in 2012 Shaded companies are small businesses

Company Number

of Employees 2011

Company

Net Income ($) Comments Explaining

Company Losses Per Unit Compliance Costs as a Share of Company Net Income by Well Type (%)

Type well or single well (lower bound) Type well or

single well (upper bound) Subsequent

well under type well approval Existing well Refracture operation Average

across all operations (lower bound) Average

across all operations (upper bound)

1 2 2,535,599 1.2663% 2.2818% 0.1210% 0.0399% 0.0396% 0.1237% 0.2015%

2 5

- 1,196,440 Paid down accounts payable - 2.6836%

- 4.8358%

- 0.2563%

- 0.0847%

- 0.0839%

- 0.2622%

- 0.4271%

3 6

- 5,268,905

- 0.6094%

- 1.0981%

- 0.0582%

- 0.0192%

- 0.0191%

- 0.0596%

- 0.0970%

4 11

- 11,600,158

- 0.2768%

- 0.4988%

- 0.0264%

- 0.0087%

- 0.0087%

- 0.0270%

- 0.0441%

5 19 162,388,000 0.0198% 0.0356% 0.0019% 0.0006% 0.0006% 0.0019% 0.0031%

6 20 10,384,496 0.3092% 0.5572% 0.0295% 0.0098% 0.0097% 0.0302% 0.0492%

7 23

- 4,104,338

- 0.7823%

- 1.4097%

- 0.0747%

- 0.0247%

- 0.0245%

- 0.0764%

- 0.1245%

8 23 11,687,000 0.2747% 0.4951% 0.0262% 0.0087% 0.0086% 0.0268% 0.0437%

9 32

- 27,841,000

- 0.1153%

- 0.2078%

- 0.0110%

- 0.0036%

- 0.0036%

- 0.0113%

- 0.0184%

10 42

- 1,764,000 Losses the past 3 years due to expanding the company (buying acreage, exploratory drilling, drilling advances) - 1.8201%

- 3.2799%

- 0.1739%

- 0.0574%

- 0.0569%

- 0.1779%

- 0.2897%

11 62 1,753,000 1.8316% 3.3005% 0.1750% 0.0578% 0.0573% 0.1790% 0.2915%

12 77 392,678,000 0.0082% 0.0147% 0.0008% 0.0003% 0.0003% 0.0008% 0.0013%

13 96 12,691,000 0.2530% 0.4559% 0.0242% 0.0080% 0.0079% 0.0247% 0.0403%

14 104 13,743,000 0.2336% 0.4210% 0.0223% 0.0074% 0.0073% 0.0228% 0.0372%

15 113

- 31,758,000

- 0.1011%

- 0.1822%

- 0.0097%

- 0.0032%

- 0.0032%

- 0.0099%

- 0.0161%

16 145 65,179,000 0.0493% 0.0888% 0.0047% 0.0016% 0.0015% 0.0048% 0.0078%

17 146 79,390,000 0.0404% 0.0729% 0.0039% 0.0013% 0.0013% 0.0040% 0.0064%

18 153

- 132,915,000

- 0.0242%

- 0.0435%

- 0.0023%

- 0.0008%

- 0.0008%

- 0.0024%

- 0.0038%81 Company Number

of Employees 2011

Company

Net Income ($) Comments Explaining

Company Losses Per Unit Compliance Costs as a Share of Company Net Income by Well Type (%)

Type well or single well (lower bound) Type well or

single well (upper bound) Subsequent

well under type well approval Existing well Refracture operation Average

across all operations (lower bound) Average

across all operations (upper bound)

19 163 72,061,000 0.0446% 0.0803% 0.0043% 0.0014% 0.0014% 0.0044% 0.0071%

20 169 36,629,000 0.0877% 0.1580% 0.0084% 0.0028% 0.0027% 0.0086% 0.0140%

21 170

- 57,480,023 Blame losses and variability of net income on "dry hole

costs" - 0.0559%

- 0.1007%

- 0.0053%

- 0.0018%

- 0.0017%

- 0.0055%

- 0.0089%

22 186 105,554,000 0.0304% 0.0548% 0.0029% 0.0010% 0.0010% 0.0030% 0.0048%

23 188 1,403,000 2.2885% 4.1239% 0.2186% 0.0722% 0.0715% 0.2236% 0.3642%

24 305

- 76,761,000 Estimates of reserves decline, lowering market prices making drilling uneconomic - 0.0418%

- 0.0754%

- 0.0040%

- 0.0013%

- 0.0013%

- 0.0041%

- 0.0067%

25 305

- 76,661,000

- 0.0419%

- 0.0755%

- 0.0040%

- 0.0013%

- 0.0013%

- 0.0041%

- 0.0067%

26 313 30,707,000 0.1046% 0.1884% 0.0100% 0.0033% 0.0033% 0.0102% 0.0166%

27 317

- 228,063,000 Company factors field

reserves into net earnings calculation. - 0.0141%

- 0.0254%

- 0.0013%

- 0.0004%

- 0.0004%

- 0.0014%

- 0.0022%

28 333 35,809,000 0.0897% 0.1616% 0.0086% 0.0028% 0.0028% 0.0088% 0.0143%

29 352 194,332,000 0.0165% 0.0298% 0.0016% 0.0005% 0.0005% 0.0016% 0.0026%

30 365 62,314,000 0.0515% 0.0928% 0.0049% 0.0016% 0.0016% 0.0050% 0.0082%

31 395 110,698,000 0.0290% 0.0523% 0.0028% 0.0009% 0.0009% 0.0028% 0.0046%

32 462 73,132,000 0.0439% 0.0791% 0.0042% 0.0014% 0.0014% 0.0043% 0.0070%

33 477 90,046,000 0.0357% 0.0643% 0.0034% 0.0011% 0.0011% 0.0035% 0.0057%

34 529 122,408,000 0.0262% 0.0473% 0.0025% 0.0008% 0.0008% 0.0026% 0.0042%

35 592 548,137,000 0.0059% 0.0106% 0.0006% 0.0002% 0.0002% 0.0006% 0.0009%

36 609 429,072,000 0.0075% 0.0135% 0.0007% 0.0002% 0.0002% 0.0007% 0.0012%

37 639 215,400,000 0.0149% 0.0269% 0.0014% 0.0005% 0.0005% 0.0015% 0.0024%

38 692 491,600,000 0.0065% 0.0118% 0.0006% 0.0002% 0.0002% 0.0006% 0.0010%

39 761 42,048,000 0.0764% 0.1376% 0.0073% 0.0024% 0.0024% 0.0075% 0.0122%

40 824 529,932,000 0.0061% 0.0109% 0.0006% 0.0002% 0.0002% 0.0006% 0.0010%82 Company Number

of Employees 2011

Company

Net Income ($) Comments Explaining

Company Losses Per Unit Compliance Costs as a Share of Company Net Income by Well Type (%)

Type well or single well (lower bound) Type well or

single well (upper bound) Subsequent

well under type well approval Existing well Refracture operation Average

across all operations (lower bound) Average

across all operations (upper bound)

41 876 267,200,000 0.0120% 0.0217% 0.0011% 0.0004% 0.0004% 0.0012% 0.0019%

42 880 206,679,000 0.0155% 0.0280% 0.0015% 0.0005% 0.0005% 0.0015% 0.0025%

43 1,200 292,000,000 0.0110% 0.0198% 0.0011% 0.0003% 0.0003% 0.0011% 0.0018%

44 1,643 539,000,000 0.0060% 0.0107% 0.0006% 0.0002% 0.0002% 0.0006% 0.0009%

45 1,835 479,769,000 0.0067% 0.0121% 0.0006% 0.0002% 0.0002% 0.0007% 0.0011%

46 1,876 453000000 0.0071% 0.0128% 0.0007% 0.0002% 0.0002% 0.0007% 0.0011%

47 2,550 1,091,123,000 0.0029% 0.0053% 0.0003% 0.0001% 0.0001% 0.0003% 0.0005%

48 3,304 881,914,000 0.0036% 0.0066% 0.0003% 0.0001% 0.0001% 0.0004% 0.0006%

49 3,322 2946000000 0.0011% 0.0020% 0.0001% 0.0000% 0.0000% 0.0001% 0.0002%

50 4,800

-

2,649,000,000 Company cited loss due

to settlement

agreement. - 0.0012%

- 0.0022%

- 0.0001% 0.0000% 0.0000%

- 0.0001%

- 0.0002%

51 5,200 4,704,000,000 0.0007% 0.0012% 0.0001% 0.0000% 0.0000% 0.0001% 0.0001%

52 5,299 11,750,000 0.2733% 0.4924% 0.0261% 0.0086% 0.0085% 0.0267% 0.0435%

53 8,120 660,000,000 0.0049% 0.0088% 0.0005% 0.0002% 0.0002% 0.0005% 0.0008%

54 8,147 434,186,000 0.0074% 0.0133% 0.0007% 0.0002% 0.0002% 0.0007% 0.0012%

55 11,300 6,771,000,000 0.0005% 0.0009% 0.0000% 0.0000% 0.0000% 0.0000% 0.0001%