Oil and Gas and Sulphur Operations on the Outer Continental Shelf 

– Requirements for Exploratory Drilling on the Arctic Outer 

Continental Shelf

Initial Regulatory Impact Analysis

RIN: 1082-AA00

NOTICE OF PROPOSED RULEMAKING

DEPARTMENT OF THE INTERIOR

Bureau of Safety and Environmental Enforcement

(30 CFR Parts 250 and 254)

Bureau of Ocean Energy Management

(30 CFR Part 550)

February 09, 2015
2

Table of Contents

1. Introduction...........................................................................................................................................5

2. Need for Regulation..............................................................................................................................6

3. Alternatives...........................................................................................................................................9

4. Arctic OCS Economic Analysis .........................................................................................................10

a. Baseline Assumptions..................................................................................................................10

b. Costs.............................................................................................................................................13

c. Benefits ........................................................................................................................................14

d. Transfers.......................................................................................................................................17

e. Assumptions.................................................................................................................................18

i. Affected Population of Operators and Drilling Operations....................................................18

ii. Wage Rates and Loaded Wage Factors...................................................................................21

iii. Daily Rig Operating Costs......................................................................................................24

iv. BSEE Burden to Review Paperwork Submissions ...................................................................24

5. Section-by-Section Analysis of Costs.................................................................................................25

a. Additional Incident Reporting Requirements (§ 250.188)...........................................................26

b. Pollution Prevention Requirements (§ 250.300)..........................................................................27

c. Additional Requirements for Securing Wells (§ 250.402)...........................................................29

d. Additional BOP Pressure Testing Requirements (§ 250.447)......................................................30

e. Real-time Monitoring Requirements (§ 250.452)........................................................................31

f. Additional Information Requirements for APDs (§ 250.470)......................................................32

g. Incorporation of proposed draft API RP 2N, Third Edition (§ 250.470) .....................................34

h. Additional SCCE Requirements (§ 250.471)...............................................................................35

i. Equipment Requirements.........................................................................................................37

ii. Stump Testing Requirements...................................................................................................38

iii. Well Design Change Information Requirements.....................................................................40

iv. Test and Exercise Requirements..............................................................................................41

v. Records Maintenance Requirements.......................................................................................41

vi. Documentation Requirements .................................................................................................42

i. Relief Rig Requirements (§ 250.472)...........................................................................................43

j. Additional Auditing Requirements (§ 250.1920).........................................................................49

k. Real-time Location Tracking Requirements (§ 254.80)...............................................................50
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l. IOP Requirements (§ 550.204).....................................................................................................54

m. Planning Information Requirements to Accompany EPs (§ 550.220) .........................................55

n. Industry Familiarization with the New Rule ................................................................................56

6. Summary of the Cost Analyses...........................................................................................................57

7. Break-Even Analysis..........................................................................................................................60

a. Data ..............................................................................................................................................62

b. Method .........................................................................................................................................67

c. Results..........................................................................................................................................67

d. Qualitative Benefits......................................................................................................................69

e. Conclusion....................................................................................................................................73

8. UMRA ................................................................................................................................................73
4

Abbreviations

APD Application for Permit to Drill

API American Petroleum Institute

BBLs Barrels

BLS Bureau of Labor Statistics

BOEM Bureau of Ocean Energy Management

BOP Blowout preventer

BSEE Bureau of Safety and Environmental Enforcement

DOI Department of the Interior

EO Executive Order

EP Exploration Plan

GOM Gulf of Mexico

IOP Integrated Operations Plan

MODU Mobile Offshore Drilling Unit

OCS Outer Continental Shelf

OMB Office of Management and Budget

OSRP Oil Spill Response Plans

PPCS Pre-positioned capping stack

RFA Regulatory Flexibility Act

RIA Regulatory Impact Analysis

SCCE Source Control and Containment Equipment

SEMS Safety and Environmental Management Systems 

UMRA Unfunded Mandates Reform Act of 1995 
5

1. Introduction

Changes to Federal regulations must undergo several types of economic analyses. First, Executive Orders 

(E.O.) 12866 and 13563 direct agencies to assess the costs and benefits of available regulatory 

alternatives and, if regulation is necessary, to select a regulatory approach that maximizes net benefits 

(accounting for the potential economic, environmental, public health, and safety effects). E.O. 13563 

emphasizes the importance of quantifying both costs and benefits, reducing costs, harmonizing rules, and 

promoting flexibility. Under E.O. 12866, an agency must determine whether a regulatory action is 

significant and, thus, subject to the requirements of the E.O. and Office of Management and Budget 

(OMB) review. Section 3(f) of E.O. 12866 defines a “significant regulatory action” as any rule that:

(1) has an annual effect on the economy of $100 million or more, or adversely affects 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 (also referred to as “economically 

significant”); (2) creates serious inconsistency or otherwise interferes with an action taken or planned by 

another agency; (3) materially alters the budgetary impacts of entitlement grants, user fees, loan 

programs, or the rights and obligations of recipients thereof; or (4) raises novel legal or policy issues 

arising out of legal mandates, the President’s priorities, or the principles set forth in E.O. 12866.

In addition, the Regulatory Flexibility Act of 1980 (RFA) requires agencies to consider the economic 

impact of regulatory changes on small entities. Finally, the Unfunded Mandates Reform Act of 1995

(UMRA) (Public Law 104-4) requires agencies to prepare a written assessment of the costs, benefits, and 

other effects of proposed or final rules that include a Federal mandate likely to result in expenditure of 

$100 million or more annually (adjusted for inflation) by State, local, or tribal governments in aggregate 

or by the private sector.

In conducting analyses of the proposed rule, the Bureau of Ocean Energy Management (BOEM) and the 

Bureau of Safety and Environmental Enforcement (BSEE) provide the following summary:
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(1) We have determined that the proposed rule is a “significant regulatory action” within the 

definition of E.O. 12866 because the estimated annual costs or benefits exceed $100 million in at 

least one year of the analysis period; 

(2) We have determined that the proposed rule would affect operators and holders of Federal oil and 

gas leases that could conduct exploratory drilling on the Arctic Outer Continental Shelf (OCS), 

and an Initial RFA analysis has been prepared for this proposed rule to discuss the potential 

impacts to small entities; 

(3) We have determined that the proposed rule would not impose an unfunded mandate on State, 

local, or tribal governments as defined by the UMRA. We have determined that the proposed 

rule, if finalized, would impose a Federal mandate that may result in the expenditure by the 

private sector of $100 million or more (adjusted annually for inflation) in any one year.

This Initial Regulatory Impact Analysis (RIA) addresses requirements under the UMRA and E.O.s 13563 

and 12866. BOEM and BSEE are requesting comments on the assumptions and data sources used in this 

Initial RIA.

2. Need for Regulation

Although a comprehensive OCS oil and gas regulatory program exists, Department of the Interior (DOI)

engagement with partners and stakeholders reveals the need for new and revised regulatory measures for 

exploratory drilling by floating drilling vessels and jackup rigs ” (collectively known as mobile offshore 

drilling units or MODUs) on the Arctic OCS. The U.S. Arctic region, as recognized by the United States

and defined in the U.S. Arctic Research and Policy Act of 1984, encompasses an extensive marine and 

terrestrial area but this proposed rule focuses solely on the OCS within the Beaufort Sea and Chukchi Sea 

Planning Areas. BOEM and BSEE have undertaken extensive environmental and safety reviews of 

potential oil and gas operations on the Arctic OCS. These reviews, along with concerns expressed by 

environmental organizations and Alaska Natives, reinforce the need to develop additional measures 
7

specifically tailored to the operational and environmental conditions of the Arctic OCS. After considering 

the input provided by various partners and stakeholders and DOI’s direct experience from Shell’s 2012 

Arctic operations, BOEM and BSEE have concluded that additional exploratory drilling regulations 

would enhance existing regulations and would be appropriate for a more holistic Arctic OCS oil and gas 

regulatory framework.

This proposed rulemaking is intended to provide regulations to ensure Arctic OCS exploratory drilling 

operations are conducted in a safe and responsible manner that considers the unique conditions of Arctic 

OCS drilling and Alaska Natives’ cultural traditions and need to access subsistence resources. The Arctic 

region is known for its oil and gas resource potential, its vibrant ecosystems, and the Alaska Native 

communities. The region is characterized by extreme environmental conditions, geographic remoteness, 

and a relative lack of fixed infrastructure and existing operations. These are key factors in considering the 

feasibility, practicality, and safety of conducting offshore oil and gas activities on the Arctic OCS.

This proposed rule would add to, and revise existing regulations in 30 CFR parts 250, 254, and 550 for 

Arctic OCS oil and gas activities. The proposed rule would focus on Arctic OCS exploratory drilling 

activities that use MODUs, and related operations, during the Arctic OCS open-water drilling season.

This proposed rule would address several important issues and objectives, including ensuring that 

operators:

(1) Design and conduct exploration programs in a manner suitable for Arctic OCS conditions;

(2) Develop an integrated operations plan (IOP) that would address all phases of their proposed 

Arctic OCS exploration program and submit the IOP to DOI, acting through its designee, BOEM, at least 

90 days in advance of filing the Exploration Plan (EP);

(3) Have access to, and the ability to deploy, Source Control and Containment Equipment while 

drilling below, or working below, the surface casing;
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(4) Have access to a separate relief rig located so that it could timely drill a relief well, in the event of 

a loss of well control, under the conditions expected at the site;

(5) Have the capability to predict, track, report, and respond to ice conditions and adverse weather 

events;

(6) Effectively manage and oversee contractors; and

(7) Develop and implement Oil Spill Response Plans that are designed and executed in a manner 

suitable for the unique Arctic OCS operating environment and that have the necessary equipment, 

training, and personnel for oil spill response on the Arctic OCS.

The proposed rule would further the Nation’s interest in exploring frontier areas, such as those in the 

Arctic region, and would establish specific operating models and requirements for the extreme, changing 

conditions that exist on the Arctic OCS. The proposed regulations would require comprehensive planning 

of operations, especially for emergency response and safety systems. The proposed rule would seek to 

institutionalize a proactive approach to offshore safety. A goal of the proposed rule is to identify possible 

vulnerabilities early in the planning process so that corrections could be made to decrease the possibility 

of an incident occurring. The requirements in the proposed rule also are designed to ensure that those 

plans would be executed in a safe and environmentally protective manner despite the challenges presented 

by the Arctic. 1

The following provisions of the proposed rule were identified to have a cost to industry:

(1) Additional Incident reporting requirements;

(2) Additional pollution prevention requirements;

(3) Additional requirements for securing wells;

(4) Additional blowout preventer (BOP) pressure testing requirements;

 

1 An alternative for managing risk is to require operators to carry insurance to cover the social damages of a worstcase scenario. Requiring insurance would help address the concern that operators may not be considering the social 

damages from an oil spill. Requiring insurance, however, is outside the scope of this proposed rule. 
9

(5) Real-time monitoring requirements;

(6) Additional information requirements for Applications for Permit to Drill (APDs);

(7) Incorporation of proposed draft American Petroleum Institute (API) RP 2N, Third Edition;

(8) Additional SCCE requirements;

(9) Relief rig requirements;

(10) Additional Auditing requirements;

(11) Real-time location tracking requirements;

(12) IOP requirements;

(13) Additional requirements for EPs; and

(14) Industry familiarization with the rule.

3. Alternatives

BOEM and BSEE have considered three alternatives for dealing with the safety and environmental 

concerns raised by exploration activities on the Arctic OCS: 

(1) Promulgate the rule changes described in this proposed rule; or

(2) Promulgate the rule changes described in the proposed rule without including the 7-day BOP 

pressure testing requirement for Arctic OCS exploratory drilling operations (in Section 250.447 

of the proposed rule); or

(3) Take no regulatory action and continue to rely on existing oil and gas regulations, industry 

standards, and operator prudence.

BSEE has decided not to issue a proposed rule without the 7-day BOP testing requirement. The additional 

testing requirement is intended to help ensure that BOPs deployed in the Arctic OCS function properly 

and reduce the risk of blowouts. BSEE has determined that the total cost to industry of including this 

requirement is $135,061,879 over the 10-year analysis period (assuming 7 percent discounting). The cost 
10

summary tables in Section 6 of this analysis present the total costs of the proposed rule with and without 

the additional BOP pressure testing requirements. 

BOEM and BSEE have decided to move forward with this proposed rule, in lieu of taking no regulatory 

action, because relying on the regulatory status quo would not address the safety and environmental 

concerns raised by partners and stakeholders in the Arctic region and thus would not achieve the 

objectives of this proposed rule. In addition, the proposed rule would confer additional protections on the 

environment and Alaska Native cultural activities.

4. Arctic OCS Economic Analysis

BOEM and BSEE evaluated the potential cost impacts of the proposed rule against the baseline. The 

analysis reflects only the activities and capital investments required by the proposed rule that represent a 

change from the baseline. This section provides an overview of the analysis of costs and benefits and the 

assumptions used to conduct the analysis.

a. Baseline Assumptions 

The baseline refers to existing regulatory requirements, industry standards, and operator prudence. Thus, 

the economic analysis excluded activities or capital investments that existing regulations require as well 

as impacts resulting from the incorporation of industry standards with which industry voluntarily 

complies. The baseline also includes costs associated with requirements that BOEM or BSEE have 

previously routinely imposed in other regions under their existing regulatory authorities but does not 

include the costs described as follows:

i. Relief Rig Capital Costs: The proposed rule requires Arctic OCS operators to have access to a 

separate relief rig located such that it could timely drill a relief well if a loss of well control were 

to occur and drilling a relief well becomes necessary. Although a relief rig was required by DOI 

during Shell’s 2012 Arctic operations, and although BOEM and BSEE anticipate that we would 
11

exercise our existing authorities to require a relief rig for any future exploratory drilling on the 

Arctic OCS, we chose not to include the capital costs associated with staging a relief rig that may 

not be conducting exploratory drilling (i.e., a standby rig) in the baseline. Instead we 

conservatively chose to include such costs as part of the costs of the rule, in the detailed economic 

analysis contained in the Initial RIA. The costs are estimated at $276 million per year per standby rig. 

Based on Exploration Plans and other information, however, BOEM and BSEE believe that, in 

the future operators would likely designate a second operating rig to be a relief rig (instead of 

staging a dedicated standby relief rig) because, over time, the increased presence of multiple 

operating rigs on the Arctic OCS would make it easier for one operating rig to be designated as a 

relief rig for another operating rig. Nonetheless, because an operator may choose to deploy a 

dedicated standby relief rig, the economic analysis conservatively includes the estimated costs for 

a standby rig for 2015 and 2016. 

In addition, costs associated with documenting a relief rig plan are not included in the baseline for 

the analysis and are included in the economic analysis.

ii. Relief Rig Activity Costs: The proposed rule would establish a 45-day maximum limit on the time 

necessary to complete relief well operations under Section 250.472. This provision effectively 

would require the cessation of exploratory drilling or other work below the surface casing far 

enough in advance of the expected return of seasonal ice to allow for completion and 

abandonment of a relief well. BOEM and BSEE-approved plans for 2012 Arctic operations 

required drilling operations in zones that can support the flow of liquid hydrocarbons in 

measurable quantities into the well to be concluded 38 days before November 1, based on satellite 

imagery showing the five-year historical average of earliest encroachment of sea ice over the 

applicant’s drill site and the estimated time required to drill a relief well. Thus, the baseline for 
12

this analysis includes this 38-day requirement from 2012. Accordingly, the costs of the proposed 

45-day maximum timeframe include only the costs of the additional 7 days (45 days minus 38 

days) not included in the baseline during which drilling or working below the surface casing

could not take place. 

BSEE recognizes that the actual length of this limitation would depend on the operator’s specific 

plans for staging and deploying a relief rig and that, in some cases, the operator could 

demonstrate that it could complete a relief well in less than 45 days and thus would not need to 

cease drilling or working below the surface casing 45 days before the expected return of seasonal 

ice. However, BSEE has conservatively estimated the additional 7-day costs of the limitation, 

based on the proposed 45-day timeframe, since some operators may need to use the maximum 

amount of time. During this period, however, an operator may be able to conduct a number of 

different operations at the well site that do not involve work below the surface casing. Section 5.i 

below discusses the challenges associated with estimating cost impacts associated with the 

additional 7-day limitation (above the baseline) on work below the surface casing. 

iii. BOP Pressure Testing Requirements: We do not include the 7-day BOP pressure testing 

requirements in the baseline for the analysis because, although Shell agreed to this requirement as 

a condition of its 2012 operations, Shell did not end up conducting these BOP pressure tests 

during that operating season. Thus, we conservatively include the costs associated with the 

increased BOP pressure testing requirements in the analysis of the costs for Alternative 1. In 

addition, we analyzed the costs of the additional BOP pressure testing to help compare the costs 

for Alternative 1 (the proposed rule with additional BOP testing) and Alternative 2 (the proposed 

rule without additional BOP pressure testing) , as discussed below and illustrated in Exhibits 23 

and 24.
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b. Costs

The “Section-by-Section Analysis of Costs” section below describes how we quantified and monetized 

the potential economic costs of the proposed rule. The section identifies all provisions that could result in 

increased labor requirements or capital investments from industry or government.

2

For the purpose of 

transparency, we include footnotes presenting the information on data inputs and the details of the 

calculations for each rule provision for which monetization is feasible.

The analysis covers 10 years (2015 through 2024) to ensure it captures important benefits and costs that 

could result from the proposed rule.

3 A 10-year period was used for this analysis because of the 

uncertainty associated with predicting industry’s activities and the advancement of technical 

capabilities. For example, over time, the costs associated with a particular new technology may decrease

as the technology is adopted more broadly. In other cases, an existing technology may be replaced by a 

lower-cost alternative as business needs drive technological innovation. It is very difficult to predict, 

plan, or project costs associated with technological innovation due to unknown technological or business 

constraints that could drive a product into mainstream adoption or into obsolescence. The regulated 

community itself has difficulty in planning for technological innovation beyond a 10-year time 

frame. Extrapolating results beyond this 10-year time frame would produce more ambiguous results and,

therefore, be disadvantageous in determining actual costs and benefits likely to result from this proposed 

rule. BOEM and BSEE concluded that this 10-year analysis provides the best overall ability to 

reasonably forecast estimated costs and benefits likely to result from this proposed rule.

When summarizing the costs and benefits, the estimated annual effects are presented, as well as the 10-

year discounted totals using discount rates of 3 and 7 percent following the guidance in OMB Circular A4, “Regulatory Analysis,” September 17, 2003.

 

2 The recordkeeping costs for this proposed rule are included in these cost estimates and in the Paperwork Reduction 

Act statement for the proposed rule, which addresses recordkeeping requirements only. 

3 Circular A – 4, http://www.whitehouse.gov/omb/circulars_a004_a-4.
14

BOEM and BSEE welcome comments on this analysis, including potential sources of data or information 

on the costs and potential benefits of this proposed rule. The following proposed requirements would 

result in additional costs above the baseline: Incident Reporting Requirements; Additional Pollution 

Prevention Requirements; Additional Requirements for Securing Wells; Additional BOP Pressure Testing 

Requirements; Real-time Monitoring Requirements; Additional Information Requirements for APDs; 

Incorporation of proposed draft API RP 2N, Third Edition;

4 Additional SCCE Requirements; Relief Rig

Requirements; Additional Auditing Requirements; Real-time Location Tracking Requirements; IOP 

Requirements; Planning Information Requirements to Accompany EPs; and Industry Familiarization with 

the New Rule. Exhibits 23 and 24 present a summary of the costs of the proposed rule.

c. Benefits

Although many of the benefits of the proposed rule—based primarily on preventing or reducing the 

severity or duration of catastrophic oil spills—are difficult to quantify, BOEM and BSEE have 

determined that the benefits would justify the rule’s potential costs and that proceeding with this proposal

is appropriate. The probability of a catastrophic oil spill is very low; however, the Deepwater Horizon 

incident demonstrated that even such low probability events can have devastating economic and 

environmental results when they occur.

Moreover, this proposed rule would help achieve the National Arctic Strategy goals of protecting the 

unique and sensitive Arctic ecosystems and the subsistence needs, culture, and traditions of the Alaska

Native communities. The proposed requirements—which are specifically tailored to the Arctic OCS—

would provide additional clarity and specificity regarding the expectations of BOEM and BSEE for safe 

and responsible exploration of Arctic resources and the particular actions that lessees, owners, and 

operators must take to meet those expectations. The additional clarity and specificity provided by the 

 

4 API RP 2N, Third Edition, “Recommended Practice for Planning, Designing, and Constructing Structures and 

Pipelines for Arctic Conditions” would be incorporated by reference in Section 250.198 of the proposed rule.
15

proposed rule is intended to help the oil and gas industry plan and more effectively conduct exploratory 

drilling on the Arctic OCS, resulting in the development of oil and gas with lower risk and fewer delays 

than under the existing rules. According to BOEM’s 2011 Assessment of Undiscovered Technically 

Recoverable Oil and Gas Resources of the Nation’s Outer Continental Shelf (available at 

http://www.boem.gov/Oil-and-Gas-Energy-Program/Resource-Evaluation/ResourceAssessment/2011_National_Assessment_Factsheet-pdf.aspx), approximately 17.8 billion barrels of 

economically recoverable oil (at a price of $110 per barrel) and about 50.1 trillion cubic feet of 

economically recoverable natural gas (at a price of $7.83 per million cubic feet) are in the Beaufort Sea 

and Chukchi Sea Planning Areas combined. Thus, the impact of production in the Arctic region on U.S. 

energy independence and energy security could be substantial. The proposed rule would benefit society

and the environment by reducing the potential that incidents resulting in catastrophic oil spills would 

occur and, if an incident does occur, by reducing its severity or duration.5 The objective of the proposed 

rule is to ensure safe and responsible oil and gas drilling on the Arctic OCS resulting in increased safety 

for personnel; protection of the coastal, human, and marine environments and species; and reducing 

conflicts between OCS oil and gas activities and Alaska Natives’ ability to conduct subsistence activities.

The magnitude of these benefits, however, is uncertain and highly dependent on the actual reduction in 

the probability of incidents and the increased effectiveness of stopping a spill underway. A catastrophic 

oil spill is characterized as a low probability, high consequence event because it is an event that occurs 

infrequently but has large consequences when it does occur. For low probability, high consequence 

events, knowing with any certainty the probability of an event actually occurring is difficult, as is

precisely determining the reduction in the probability of occurrence that a proposed regulation actually 

would achieve. In addition, the consequences of an oil spill depend on several factors, including the type

 

5 Although this analysis focuses on the benefits of reducing the probability, duration, or severity of a catastrophic oil 

spill, BSEE recognizes that similar benefits would occur with regard to significant but non-catastrophic oil spills. 

Those additional benefits are not quantified in this analysis since the BOEM Economic Analysis Methodology for 

the Five Year OCS Oil and Gas Leasing Program for 2012–2017, on which this analysis is primarily based, 

addresses catastrophic oil spills. 
16

and amount of oil, the location of the spill, the areal distribution of the release, the sensitivity of the 

ecosystem affected, and the weather.

Break-even analysis is a method commonly used in regulatory analysis to estimate the minimum level of 

benefits that a regulation must achieve to be cost-beneficial, or to have benefits that are at least as large as 

its costs. For regulations that enhance safety and protect the environment, break-even analysis often is 

conducted by determining the minimum level of consequence reduction needed for a regulation to break 

even. If the proposed rule exceeds this threshold, it would be cost-beneficial. 

The break-even analysis that follows describes the reduction in expected spill duration needed to generate 

certain quantifiable benefits equal to or greater than the estimated control costs associated with this rule.

The proposed rule also has benefits beyond what we captured in the break-even analyses. Due to both the 

uncertainty and difficulty of measuring these benefits, we do not offer a quantitative assessment of them; 

instead, we present a qualitative discussion.

Because BOEM and BSEE used a conservative approach in the valuation of a catastrophic oil spill, that 

is, the valuation included only selected costs of a catastrophic oil spill, the resulting measures from 

incurring (or avoiding) such an oil spill can be considered a lower bound of the true cost (or benefit) to 

society. Although we capture the environmental damage associated with a catastrophic oil spill, the 

analysis is limited because it considers only the environmental amenities that researchers could identify 

and monetize.

Natural resource valuation is complex; many factors contribute to how society values a resource, 

including but not limited to use and non-use values of the resources. Many use values can be derived by 

behavior and market transactions (for example, using the harvest value of yields in the Arctic region).

Some use values, however, might not be related to a market and are, therefore, difficult to monetize. For 

example, Alaska Native communities place a high value on the cultural amenities related directly to the 
17

use of the region. Because communities do not trade cultural amenities in markets, we are unable to 

estimate a direct value for these resources.

Non-use values are even harder to estimate; common non-use values include existence values and bequest 

values. Individuals place an added value on ecosystem health and environmental amenities by simply 

knowing that these amenities will be preserved and protected in the region even if those same individuals 

do not intend to visit the region. Bequest values relate to individuals’ placing a value on the preservation 

of the regions’ environmental amenities for future generations even if the individuals do not intend to use 

the resource themselves. Capturing these complex values is difficult because they are not traded in 

markets. Because we are unable to monetize all aspects of the consequences of an oil spill, the estimate 

we used in the quantitative break-even analysis captures only a portion of the value to society from 

mitigating the consequences of a catastrophic oil spill.

Although several components of this rulemaking would improve the coordination and monitoring of 

drilling and other exploration operations and are designed to prevent a spill, the most expensive 

components of this proposed rule are designed to reduce the severity or duration of a catastrophic oil spill, 

should one occur. By requiring local availability of SCCE, which is designed to either cap a well blowout 

or capture the flow, and codifying requirements from the 2012 drilling season, the duration and severity 

of impacts from a well blowout will be reduced.

d. Transfers

We identified no transfer payments associated with the proposed rule. Transfer payments, as defined by 

OMB Circular A-4, are payments from one group to another that do not affect total resources available to 

society. Transfer payments are associated with a distributional effect but do not result in additional 

economic benefits or costs to society.
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e. Assumptions

We estimated the costs and benefits presented in this document using various data inputs. Some of these 

data inputs were common to many of the calculations, including the assumptions discussed below about 

the affected population of operators and drilling operations, wage rates and loaded wage factors, daily rig 

operating costs, and the burden for BSEE to review paperwork submissions.

i. Affected Population of Operators and Drilling Operations

Based on BOEM’s and BSEE’s knowledge of operators engaged in, or likely to be engaged in, Arctic 

OCS exploration activities, we made several assumptions about the number of operators, rigs, and 

wells operating on the Arctic OCS over the 10-year analysis period. We also made assumptions about 

the number of APDs, EPs, IOPs, and OSRPs that operators on the Arctic OCS would submit.

Operators, Rigs, and Wells 

BOEM and BSEE assume that three operators would operate on the Arctic OCS over the 10-year 

analysis period, with one operator conducting exploratory drilling beginning in 2015 and two more 

operators conducting exploratory drilling beginning in 2018. This is BOEM and BSEE’s best 

projection of the number of operators expected to conduct exploratory drilling on the Arctic OCS

based on current leases, plans and permits, and expectations. For the total number of exploratory 

wells on the Arctic OCS, we assume two wells in 2015, four wells from 2016 through 2019, and six 

wells from 2020 through 2024. 

SCCE and Resource Sharing

The proposed rule requires operators to have access to, and the ability to deploy promptly, SCCE 

while conducting Arctic OCS exploratory drilling or work below the surface casing. In the cost 

analysis, we assume that the operator conducting exploratory drilling beginning in 2015 already owns

the required SCCE and that additional operators will purchase or otherwise acquire access to the 
19

SCCE for operations in later years. We assume that the operator with two primary rigs in 2017 will 

use one set of SCCE equipment to satisfy the SCCE requirements for both of its rigs. We assume that, 

of the two operators entering in 2018, one will purchase the SCCE equipment, and the other will 

select the least-cost means to comply with the proposed rule and thus enter into resource sharing with 

an operator who has already purchased the SCCE equipment. We refer to this below as the central 

cost scenario.

Because the industry does not currently engage in resource sharing on the Arctic OCS, BOEM and 

BSEE have no details on how the process would be conducted and whether or to what degree, for 

example, an operator would charge for access to equipment. The SCCE resource-sharing assumptions 

presented in the cost analysis section represent the most likely scenario based on BSEE’s knowledge 

of the industry. BSEE also considered a low-cost scenario and a high-cost scenario that vary the 

assumptions for resource sharing and purchase of SCCE by operators. These alternative scenarios are 

discussed here but are not included in the cost analysis section. BOEM and BSEE request comment 

on the costs and resource-sharing assumptions associated with these SCCE requirements.

For the high-cost scenario, we assume no resource sharing of SCCE between operators. We assume 

that one entity already owns the equipment while the other two entities will each need to buy the 

equipment in their first year of operation (2018). We assume that each operator experiences the 

annual deployment cost of the equipment.

For the low-cost scenario, we assume that only the operator that currently owns the SCCE would have 

the equipment and that the other entities would engage in resource sharing of the equipment. Under 

this scenario, there is no capital cost for the equipment because the initial operator already owns the 

equipment. Exhibit 1 summarizes the assumptions for each of the three scenarios. All scenarios 

assume compliance with the requirements of the proposed rule, and the assumptions regarding 
20

resource sharing and purchase of SCCE vary as described above. We seek comments on the 

reasonableness of the assumptions presented in this section.

Exhibit 1. Source Control and Containment Equipment Assumptions (§ 250.471)

Scenario

Number of SCCE 

Purchased

Number of SCCE 

Deployed

Number of Operators 

Engaging in Resource 

Sharing

Low Cost Scenario 0 1 2

Central Cost Scenario 1 2 1

High Cost Scenario 2 3 0

Section 5.h below describes the capital and labor costs associated with the purchase and redeployment

of SCCE equipment. Exhibit 2 shows the difference in SCCE costs associated with Section 

250.471(a) among the three SCCE scenarios.

Exhibit 2. 10-Year Discounted Total Equipment Costs for Low, Central, and High SCCE Cost 

Scenarios (§250.471(a))

Discounting

Low Central High

Difference 

Low-Central

Difference 

High-Central

A B C A − B C − B

7% Discounting $9,018,279 $235,067,362 $461,116,446 −$226,049,084 $226,049,084

3% Discounting $10,543,331 $264,678,746 $518,814,161 −$254,135,415 $254,135,415

Submittals to BOEM and BSEE

We make the following assumptions about submittals to BOEM and BSEE:

(1) We assume that the number of wells drilled and the number of APDs submitted to BSEE will be 

equal to each other for each year of the analysis period;
21

(2) We assume that one EP will be submitted to BOEM in the first year of the analysis and two EPs

in each following year. These assumptions reflect the fact that EPs can be submitted years in 

advance and can cover multi-year operations; and

(3) We assume that two IOPs and two OSRPs will be submitted in each year of the analysis period.

We based all assumptions on our experience with recent and expected industry practices for operators 

on the Arctic OCS, including information submitted to BOEM and BSEE by lessees and operators 

and other available information related to planned or potential industry exploratory activities for the 

analysis period. We present these inputs in Exhibit 3. We seek comments on the reasonableness of the 

assumptions presented in Exhibit 3.

Exhibit 3. Assumptions about the Affected Population of Operators and Drilling Operations

Inputs1

2015 2016 2017 2018 2019 2020 2021 2022 2023 2024

Operators 1 1 1 3 3 3 3 3 3 3

Primary rigs 1 1 2 4 4 4 4 4 4 4

Standby relief rigs21 1 0 0 0 0 0 0 0 0

Exploratory wells 

drilled each year 

2 4 4 4 4 6 6 6 6 6

Applications for 

permit to drill 2 4 4 4 4 6 6 6 6 6

Exploration plans 1 2 2 2 2 2 2 2 2 2

Integrated 

operations plans 2 2 2 2 2 2 2 2 2 2

Oil spill response 

plans 2 2 2 2 2 2 2 2 2 2

1 These estimates are a maximum that BOEM and BSEE assume could be expected in any one year; they should not 

be viewed as additive. For example, in 2018, up to three operators and up to four wells could be expected.

2 We refer to relief rigs that are not conducting exploratory drilling as “standby relief rigs,” and these rigs are 

assumed to incur different costs than relief rigs that are conducting exploratory drilling (i.e. “primary rigs” or 

“operating rigs”). 

ii. Wage Rates and Loaded Wage Factors

Many of the calculations in this analysis used wage rates for Arctic OCS oil and gas workers and for

BOEM and BSEE employees. For this analysis, we obtained median industry wage rates from the 
22

Bureau of Labor Statistics (BLS) May 2012 Occupational Employment Statistics for the industry 

labor categories. We also obtained wage rates for BOEM and BSEE personnel from the Office of 

Personnel Management 2012 General Schedule for the government labor categories. Exhibit 4

presents these wages.
23

Exhibit 4. Compensation Rates Used in the Analysis

Industry Occupation

Median Hourly 

Wage Rate

Estimated Hourly 

Compensation 

Rate

Details (Occupation Title, 

Occupation Code, 

NAICS/Location)

Senior Engineer $73.32 $104.22 Architectural and Engineering 

Managers, 11-9041, 211100

Clerical/Administrative 

Staff

$20.64 $29.34 Secretaries and Administrative 

Assistants, 43-6010, 211100

Manager $65.56 $93.19 General and Operations Managers, 

11-1021, 211100

Mid-Level Engineer $67.48 $95.92 Petroleum Engineers, 17-2171, State 

of Alaska

Skilled Laborer $40.00 $56.86 Based on BSEE’s knowledge of the 

industry

Environmental Specialist $47.03 $66.85 Environmental Scientists and 

Specialists, 19-2041, 211100

Electrician $36.69 $52.15 Electrician, 47-2111, State of Alaska

Government Occupation Hourly Rate

Estimated Hourly 

Compensation 

Rate

Details (GS Grade and 

Step, Locality)

BSEE Mid-level Engineer $48.53 $82.02 13.5, State of Alaska

BSEE Inspector $57.35 $96.92 14.5, State of Alaska

BSEE Senior Engineer $57.35 $96.92 14.5, State of Alaska

BSEE Administrative Staff $23.01 $38.89 7.5, State of Alaska

BSEE Program Analyst $40.81 $68.97 12.5, State of Alaska

BSEE Supervisory 

Engineer

$67.46 $114.01 15.5, State of Alaska

BOEM Regulatory Analyst $34.05 $57.54 11.5, State of Alaska

BOEM Petroleum Engineer $40.81 $68.97 12.5, State of Alaska

BOEM Geologist $18.57 $31.38 5.5, State of Alaska

BOEM Chief, Plans 

Section

$57.35 $96.92 14.5, State of Alaska

BOEM Regional 

Supervisor

$67.46 $114.01 15.5, State of Alaska

Sources: BLS May 2012 Occupational Employment Statistics; Office of Personnel Management 2012 General 

Schedule Locality Pay Tables.
24

To account for employee benefits, we multiplied the hourly wage rates by appropriate loaded wage 

factors to generate hourly compensation rates. For industry employees, we used a private-sector 

loaded wage factor of 1.42 derived from the 2012 BLS index for salary and benefits. For BOEM and 

BSEE employees, we used a Federal loaded wage factor of 1.69 derived from a U.S. Department of 

Labor analysis of overhead costs (in the absence of a similar estimate for BOEM or BSEE).6 We 

multiplied the hourly wage rates by the appropriate loaded wage factor to estimate the hourly 

compensation rates.

iii. Daily Rig Operating Costs 

Some requirements in the proposed rule affect rig operations. To monetize the impacts of these 

requirements, we estimated the daily operating costs for affected rigs. Based on BSEE estimates and 

cost estimation methodologies from the BOEM Economic Analysis Methodology for the Five-Year 

OCS Oil and Gas Leasing Program for 2012–2017 (the “BOEM Case Study”),

7 we assume that rigs on 

the Arctic OCS have a daily operating cost of $2,000,000. For the purposes of the analysis, we 

assume that the daily rig operating costs remain constant over the 10-year analysis period. We assume 

that the drilling season on the Arctic OCS lasts 138 days.

iv. BSEE Burden to Review Paperwork Submissions

For each paperwork submission, BOEM and BSEE estimate the labor hours needed on behalf of the 

industry to compile and submit the information. To estimate the corresponding burden for BSEE, we 

 

6 The 1.69 index is derived by using the BLS index for salary and benefits plus a U.S. Department of Labor analysis 

of overhead costs averaged over agency employees.

7

Source: U.S. Department of the Interior, Bureau of Ocean Energy Management, 2012. “Economic Analysis 

Methodology for the Five Year OCS Oil and Gas Leasing Program for 2012–2017,” BOEM OCS Study 2012–022, 

pages 67–73, available at 

http://www.boem.gov/uploadedFiles/BOEM/Oil_and_Gas_Energy_Program/Leasing/Five_Year_Program/2012-

2017_Five_Year_Program/PFP%20EconMethodology.pdf.
25

assume that for every hour that industry devotes to compile and submit information, BSEE will need 

one half hour to review the submission.8,9

5. Section-by-Section Analysis of Costs

The analysis presented in this document describes the potential costs of the proposed rule compared to the 

baseline (i.e., existing regulations and industry standards with which industry already complies). The 

following requirements would result in a change from the baseline: 

(1) Additional Incident Reporting Requirements;

(2) Pollution Prevention Requirements; 

(3) Additional Requirements for Securing Wells; 

(4) Additional BOP Pressure Testing Requirements; 

(5) Real-time Monitoring Requirements; 

(6) Additional Information Requirements for APDs; 

(7) Incorporation of proposed draft API RP 2N, Third Edition10; 

(8) SCCE Requirements; 

(9) Relief Rig Requirements; 

(10) Additional Auditing Requirements;

(11) Real-time Location Tracking Requirements; 

 

8 The submissions to BOEM under Part 550 of the proposed rule do not follow this standard review estimate because 

these submissions would require a more time-intensive review by several employees. 

9 BSEE based the one half-hour estimate on previous paperwork burden statements that assume that the government 

burden is half the industry burden (see the paperwork burden supporting statement 1014-0018).

10 API RP 2N, Third Edition, “Recommended Practice for Planning, Designing, and Constructing Structures and 

Pipelines for Arctic Conditions” would be incorporated by reference in Section 250.198 of the proposed rule.
26

(12) IOP Requirements; 

(13) Planning Information Requirements to Accompany EPs; and 

(14) Industry Familiarization with the New Rule.

These requirements and their associated costs to industry and government are presented in the sections 

below.

This Initial RIA closely mirrors the language of the proposed rule; however, the proposed rule regulatory 

text reflects what would become legally binding if adopted as a final rule.

a. Additional Incident Reporting Requirements (§ 250.188)

Proposed section 250.188(c) includes new incident reporting requirements for operators on the Arctic 

OCS. Operators would be required to provide an immediate oral report to the BSEE onsite inspector, if 

one is present, or to the Regional Supervisor of any sea ice movement or condition that has the potential 

to affect operations or trigger ice management activities, as well as the start and termination of such 

activities, and any “kicks” or operational issues that are unexpected and could result in the loss of well 

control. Operators would also be required to submit a follow-up written report regarding any ice 

management activities undertaken, within 24 hours following completion of those activities. These 

requirements would help ensure that BSEE is notified in sufficient time to oversee the safety of an 

operator’s reactions and to prepare in the event that a response would be necessary due to a safety or 

environmental incident resulting from an ice event.

These reporting requirements would result in labor costs to industry and to BSEE. We calculated the 

annual labor cost per rig by multiplying the time required for each report by the median hourly 

compensation rates for the labor categories most likely to complete these activities. The result was an 
27

annual labor cost to industry per rig of $1,146.

11 To estimate the cost to BSEE to review these reports, 

BOEM and BSEE multiplied the total hours assumed to review these reports by the hourly compensation 

rates for the labor categories most likely to complete these activities. The result was an annual labor cost 

to BSEE per rig of $533.

12 Exhibit 5 summarizes the annual costs for the incident reporting requirements.

We seek comments on the reasonableness of the assumptions in this section.

Exhibit 5. Additional Incident Reporting Requirements (§ 250.188)

Year

Number of 

Rigs

Industry 

Cost per Rig Annual Cost

Number of 

Rigs

Agency Cost 

per Rig Annual Cost

A B C = A × B D E F = D x E

2015–2016 1 $1,146 $1,146 1 $533 $533

2017 2 $1,146 $2,293 2 $533 $1,066

2018–2024 4 $1,146 $4,586 4 $533 $2,132

b. Pollution Prevention Requirements (§ 250.300)

Proposed sections 250.300(b)(1) and 250.300(b)(2) include revised pollution prevention requirements for 

exploratory drilling operations on the Arctic OCS. Operators would be required to capture all petroleumbased mud and cuttings from operations that utilize petroleum-based mud. In addition, these 

subparagraphs clarify the Regional Supervisor’s discretionary authority to require operators to capture all 

water-based muds and associated cuttings from Arctic OCS exploratory drilling operations after 

completion of the hole for the conductor casing to prevent their discharge into the marine environment, 

based on factors including, but not limited to: 

 

11 We assume that incidents for which there are new reporting requirements under the proposed rule would occur 

two times a year for each rig. We assume that industry senior engineers would spend 1.5 hours on the oral report and 

4 hours on the written report. We multiplied the time spent on reporting by the median hourly compensation rate for 

senior engineers for an annual cost per rig associated with incident reporting of $1,146 ((2 ice movement incidents × 

(1.5 hours + 4 hours)) × $104.22). 

12 Using assumptions similar to those for industry, we assume that the BSEE will review the oral and written reports 

as submitted (i.e. twice per year). We assume that for every hour spent on a submission, BSEE would spend 1⁄2 hour 

to review. We multiplied the total industry burden per rig associated with these incident-reporting requirements (11 

hours) by 1⁄2 to estimate 5.5 hours to review for a BSEE senior engineer. We multiplied the time spent on review by 

the compensation rate to estimate a $533 per rig cost to review (5.5 hours x $96.92).
28

(1) The proximity of the exploratory drilling operations to subsistence activities; 

(2) The extent to which discharged mud or cuttings may cause marine mammals to alter their 

migratory patterns in a manner that interferes with subsistence activities; or 

(3) The extent to which discharged mud or cuttings may adversely affect marine mammals, fish, or 

their habitat.

Addressing both environmental concerns and the concerns of Alaska Natives regarding the potential 

impacts of discharges of mud and cuttings, these pollution prevention requirements would help prevent or 

minimize the likelihood of environmental damage and interference with Alaska Natives’ subsistence 

activities from discharges of mud and cuttings.

These requirements would result in labor costs to industry associated with transporting and disposing of 

both water-based and petroleum-based mud and cuttings. We calculated the annual labor cost per rig by 

multiplying the time required for these activities by the median hourly compensation rates for the labor 

categories most likely to complete these activities. These calculations resulted in an annual labor cost of 

$4,245 per rig.

13 Exhibit 6 summarizes the annual cost for the pollution prevention requirements. We seek 

comments on the reasonableness of the assumptions in this section.

Exhibit 6. Pollution Prevention Requirements (§ 250.300)

Year

Number of Rigs Cost per Rig Annual Cost

A B C = A × B

2015–2016 1 $4,245 $4,245

2017 2 $4,245 $8,491 

2018–2024 4 $4,245 $16,981 

 

13 We assume that a skilled laborer on the rig crew and an industry senior engineer would spend, respectively, 60 

and 8 hours annually to transport and dispose of mud and cuttings. We multiplied the median hourly compensation 

rates by the number of hours assumed to be spent for these labor categories and summed the results to obtain an 

annual labor cost of $4,245 ((60 hours × $56.86) + (8 hours × $104.22)) per rig. 
29

c. Additional Requirements for Securing Wells (§ 250.402)

Proposed section 250.402(c) includes new requirements for securing wells for exploratory drilling 

operations on the Arctic OCS. Operators that move a drilling rig off a well prior to completion or

permanent abandonment would be required to ensure that any equipment left on, near, or in a well bore 

that has penetrated below the surface casing is positioned in a manner to protect the well head and prevent 

or minimize the likelihood of compromising the down-hole integrity of the well or well plug 

effectiveness. Additionally, in areas of ice scour, operators would be required to use a well cellar or an 

equivalent means of minimizing the risk of damage to the wellhead.

14 These new requirements would 

help reduce the risk associated with damage to the well or to equipment associated with ice floe or other 

potential sources of damage.

These requirements would result in labor costs to industry. We calculated the annual labor costs to 

industry associated with these requirements by multiplying the annual number of days of rig crew time 

assumed to be spent to conduct these activities by the daily rig operating cost. These calculations resulted 

in an annual labor cost of $3,000,000 per well. The well cellar requirements would result in capital and 

labor costs to industry for each well drilled. These capital and labor costs are estimated to be $2,000,000

per well.15 Exhibit 7 summarizes the annual costs of the additional requirements for securing wells.

BOEM and BSEE request comments on the costs associated with securing wells. We seek comments on 

the reasonableness of the assumptions in this section.

 

14 A well cellar is a hole excavated into the seafloor that can house well head equipment to provide protection 

against damage from ice scouring the seafloor.

15 We assume that the operator would move off each well once per year and that, for each occurrence, the rig crew

would spend 1.5 days to comply. We multiplied the number of days required per occurrence by the daily rig 

operating costs to obtain an annual labor cost of $3,000,000 (1.5 days × $2,000,000) per well. We assume a capital 

and labor cost to industry associated with the well cellar requirements of $2,000,000 per well. 
30

Exhibit 7. Annual Additional Requirements for Securing Wells (§ 250.402)

Year

Number 

of Wells

Labor Cost 

per Well

Well Cellar 

Capital and 

Labor Cost 

per Well Annual Cost

A B D E = (A × B) + (A × D)

2015 2 $3,000,000 $2,000,000 $10,000,000 

2016–2019 4 $3,000,000 $2,000,000 $20,000,000 

2020–2024 6 $3,000,000 $2,000,000 $30,000,000

d. Additional BOP Pressure Testing Requirements (§ 250.447)

Proposed section 250.447(b) includes new requirements for pressure testing of BOP systems on the Arctic 

OCS. Operators conducting Arctic OCS exploratory drilling operations would be required to begin testing 

the BOP system before midnight on the seventh day following the conclusion of the previous test. This 

requirement would represent an increased testing frequency relative to the existing baseline requirement 

to begin testing the BOP system before midnight on the 14th day following the conclusion of the previous 

test.

These requirements would result in annual operating costs to industry. We calculated the annual operating 

costs to industry associated with testing requirements by multiplying the assumed additional number of 

operational days spent annually on testing by the daily rig operating cost, resulting in an annual operating 

cost of $6,000,000 per rig. Although operators will perform these tests on each well, we assume that no 

rig will be drilling two wells simultaneously and, therefore, the cost of testing should be calculated per-rig 

rather than per-well.

16 Exhibit 8 summarizes the annual costs of the additional BOP pressure testing 

requirements. We seek comments on the reasonableness of the assumptions in this section.

 

16 Although the exact length of time actually required to perform each BOP test would depend on the specific 

circumstances applicable to each well, we assume that about 10 additional tests would be required each season under 

the proposed rule, and that a total of 3 additional operational days would be spent annually on testing as a result of 

the proposed requirement. We then multiplied that number of days by the daily rig operating cost to obtain an 

annual cost to industry, per rig, of $6,000,000 (3 days × $2,000,000). 
31

As an alternative to the proposed rule, BSEE considered not including these additional BOP pressuretesting requirements for Arctic OCS exploratory drilling operations. (See Alternative 2 in Section 3 of 

this analysis.) BSEE has decided not to issue a proposed rule without the 7-day BOP testing requirement.

The additional testing requirement is intended to ensure that BOPs deployed in the Arctic OCS function 

properly and reduce the risk of blowouts. See Section 6 of this analysis for the total costs of the proposed 

rule with and without the additional BOP pressure testing requirements.

Exhibit 8. Annual Additional BOP Pressure Testing Requirements (§ 250.447)

Year

Number of Rigs Cost per Rig Annual Cost

A B C = A × B

2015 1 $6,000,000 $6,000,000 

2016–2019 2 $6,000,000 $12,000,000 

2020–2024 4 $6,000,000 $24,000,000 

e. Real-time Monitoring Requirements (§ 250.452)

Proposed section 250.452 outlines new real-time monitoring requirements for Arctic OCS exploratory 

drilling operations. Paragraph (a) includes requirements for real-time data gathering and monitoring 

capability for data on the BOP control system, the fluid handling systems on the rig, and the well’s 

downhole conditions; and paragraph (b) includes requirements for onshore data transmission, monitoring, 

storage, and notification and availability to BSEE. These new requirements result, in part, from 

recommendations from investigations of the Deepwater Horizon incident and would help to improve 

safety and oversight of operations.

These monitoring and associated reporting requirements would result in labor and equipment costs to

industry. We calculated the annual labor and equipment cost to industry associated with these 

requirements by multiplying the assumed average daily cost per rig to comply with these requirements by 

the number of operating days per year, resulting in an annual per-rig labor and equipment cost of 
32

$690,000.17,18 Exhibit 9 summarizes the annual costs of the real-time monitoring and associated reporting 

requirements. We seek comments on the reasonableness of the assumptions in this section.

Exhibit 9. Annual Real-time Monitoring Requirements (§ 250.452)

Year

Number of Rigs Cost per Rig Annual Cost

A B C = A × B

2015–2016 1 $690,000 $690,000

2017 2 $690,000 $1,380,000 

2018–2024 4 $690,000 $2,760,000 

f. Additional Information Requirements for APDs (§ 250.470)

Proposed section 250.470 would require operators to submit Arctic OCS-specific information with APDs

for Arctic OCS exploratory drilling. Paragraph (a) would require operators to submit a detailed 

description of how the drilling unit, equipment, and materials will be prepared for service in Arctic OCS

Conditions and in compliance with the requirements of proposed section 250.417.

19 Under paragraph (b), 

operators would be required to submit a detailed description of all operations necessary in Arctic OCS 

Conditions to transition the rig from being under way to commencing drilling operations and from 

concluding drilling operations to being under way, as well as any anticipated repair and maintenance 

plans for the drilling unit and equipment. Paragraph (c) would require operators to submit well-specific 

drilling objectives, timelines, and updated contingency plans for temporary abandonment of the well.

Under paragraph (d), operators would be required to submit information on weather and ice forecasting 

capability for all phases of drilling operations. The proposed informational requirements in the new 

 

17 The real-time monitoring estimate contains both the industry-reporting burden and the capital needs for the 

requirement. The PRA estimate for this provision only includes the industry-reporting burden and is a subset of this 

estimate.

18We assume that a rig on the Arctic OCS operates for 138 days per year and that the average daily cost associated 

with these monitoring requirements would be $5,000, including equipment and labor. We multiplied the average 

daily cost by the number of operating days per year to obtain an annual labor and equipment cost per rig of $690,000 

(138 days × $5,000). 

19 A definition of “Arctic OCS Conditions” is provided in Section 250.105 of the proposed rule.
33

section would be necessary to inform BSEE’s evaluation of APDs for Arctic OCS exploratory drilling 

operations.

The requirements under proposed section 250.470(a)-(d) would result in labor costs to industry and 

BSEE. We calculated the labor costs to industry by multiplying the annual number of hours assumed to 

be spent consolidating and reporting information by the median hourly compensation rates for the labor 

categories most likely to complete these activities, resulting in an annual labor cost of $1,491 per rig and 

$1,305 per well.

20 We calculated the labor costs to the Bureau by multiplying the annual number of hours 

assumed to be spent consolidating and reporting information by the hourly compensation rates for the 

labor categories most likely to complete these activities, resulting in an annual labor cost of $775 per rig 

and $678 per well.21 Exhibit 10 and Exhibit 11 summarize the annual costs associated with these 

information requirements. We seek comments on the reasonableness of the assumptions in this section.

Exhibit 10. Information Requirements under § 250.470(a) and (d) for Applications for Permit to 

Drill by Rig

Year

Number 

of Rigs

Industry 

Cost per 

Rig

Industry 

Annual Cost

Number of 

Rigs

Agency Cost 

per Rig

Agency 

Annual Cost

A B C = A × B D E F = D x E

2015–2016 1 $1,491 $1,491 1 $775 $775

2017 2 $1,491 $2,982 2 $775 $1,551

2018–2024 4 $1,491 $5,964 4 $775 $3,101

 

20 We assume that costs associated with consolidating and reporting information as required under section 

250.470(a) and (d) would be incurred per rig, while costs associated with section 250.470(b)-(c) would be incurred 

per well. We assume that consolidating and reporting the information required under section 250.470(a) and (d) 

would require 10 hours and 6 hours of managerial time per rig, respectively. We assume that consolidating and 

reporting the information required under section 250.470(b) and (c) would require 10 hours and 4 hours per well, 

respectively. We multiplied the number of hours by the median hourly compensation rate for an industry manager to 

obtain an annual labor cost to industry of $1,491 per rig (16 hours × $93.19) and $1,305 per well (14 hours × 

$93.19). 

21 We assume that for every hour industry spends to report and consolidate the information, BSEE spends 1⁄2 hour to 

review. We assume that 8 hours per rig (16 industry hours x 1⁄2) and 7 hours per well (14 industry hours x 1⁄2) would 

be required of a BSEE senior engineer to review the information. We multiplied the number of hours by the hourly 

compensation rate for a BSEE senior engineer to obtain an annual labor cost to BSEE of $775 per rig (8 hours × 

$96.92) and $678 per well (7 hours × $96.92).
34

Exhibit 11. Information Requirements under § 250.470(b) and (c) for Applications for Permit to 

Drill by Well

Year

Number 

of Wells

Industry 

Cost per 

Well

Industry 

Annual Cost

Number of 

Wells

Agency Cost 

per Well

Agency 

Annual Cost

A B C = A × B D E F = D x E

2015 2 $1,305 $2,609 2 $678 $1,357 

2016–2019 4 $1,305 $5,219 4 $678 $2,714 

2020–2024 6 $1,305 $7,828 6 $678 $4,071 

g. Incorporation of proposed draft API RP 2N, Third Edition (§ 250.470)

Section 250.470(g) would require operators to submit a detailed description of how the relevant aspects of 

proposed draft API RP 2N, Third Edition, “Planning, Designing, and Constructing Structures and 

Pipelines for Arctic Conditions” are addressed in planning exploratory drilling operations. The document 

also would be included in the list of documents incorporated by reference in Section 250.198 of the 

proposed rule. Proposed API RP 2N, Third Edition, is a voluntary consensus standard that will addresses 

the unique Arctic conditions that affect the planning, design, and construction of systems used in Arctic 

and sub-Arctic environments.

This requirement would result in labor costs to industry and BSEE. We calculated the labor costs to 

industry associated with this requirement by multiplying the time required for documentation by the 

median hourly compensation rate for the labor category of individuals most likely to perform this work, 

resulting in a labor cost to industry per rig of $1,918. We calculated the BSEE labor costs per rig 

associated with this requirement by multiplying the time required for review of submittals by the hourly 

compensation rate for the labor category of individuals most likely to perform this work, resulting in a 
35

labor cost to BSEE per rig of $969.

22 Exhibit 12 summarizes the annual costs associated with this 

requirement. We seek comments on the reasonableness of the assumptions in this section.

Exhibit 12. Annual Information Requirements for Applications for Permit to Drill Related to API 

RP 2N (§ 250.470(g))

Year

Number 

of Rigs

Industry 

Cost per 

Rig Annual Cost

Number of 

Rigs

Agency Cost 

per Rig Annual Cost

A B C = A × B D E F = D x E

2015–2016 1 $1,918 $1,918 1 $969 $969

2017 2 $1,918 $3,837 2 $969 $1,938 

2018–2024 4 $1,918 $7,674 4 $969 $3,877 

h. Additional SCCE Requirements (§ 250.471)

Proposed Section 250.471 describes SCCE requirements for exploration wells drilled on the Arctic OCS.

For operations using a MODU when drilling or working below the surface casing, paragraph (a) requires 

operators to have access to a capping stack, a cap and flow system, and a containment dome, positioned to 

ensure that the SCCE will arrive within specified periods after a loss of well control. This equipment must 

also be able to be deployed as directed by the Regional Supervisor pursuant to paragraph 250.471(g) of 

the proposed rule. Paragraph (a)(2) would require that the cap and flow system be designed to capture at 

least the amount of hydrocarbons equivalent to the calculated worst case discharge rate referenced in the 

BOEM-approved EP. Paragraph (a)(3) would require that the containment dome have the capacity to 

pump fluids without relying on buoyancy. Paragraph (b) would require operators to conduct a monthly 

stump test of dry-stored capping stacks, and if using a pre-positioned capping stack (PPCS), a stump test 

must be conducted prior to each installation on each well.

 

22 We assume that a mid-level engineer would spend 20 hours on the documentation associated with this 

requirement. We multiplied the number of hours by the median hourly compensation rate for mid-level engineers to 

obtain a labor cost to industry of $1,918 (20 hours × $95.92) per rig. We assume that a senior BSEE engineer would 

spend 10 hours on the review of submittals associated with this requirement. We multiplied the number of hours by 

the hourly compensation rate to obtain a cost to BSEE per rig of $969 (10 hours × $96.92). 
36

Paragraph (c) would require operators that propose to change their well design to include in their 

Application for Permit to Modify (as required by existing Section 250.465(a)) a reevaluation of their

SCCE capabilities and a demonstration that their SCCE capabilities will meet the criteria in proposed 

Section 250.470(f) under the changed well design. Paragraph (d) would require the operator to conduct 

tests or exercises of the SCCE when directed by the Regional Supervisor. Paragraph (e) would require the 

operator to maintain records pertaining to testing, inspection, and maintenance of the SCCE for 10 years, 

and to make them available to BSEE upon request. Paragraph (f) would require the operator to maintain 

records pertaining to use of the SCCE during testing, training, and deployment activities for at least 3 

years and to make them available to BSEE upon request.

These requirements would reflect the need for operators conducting exploratory drilling on the Arctic 

OCS to be able to correct or contain any loss of well control as quickly as possible to minimize the

impacts of oil pollution on the environment. The requirements would also address the need for Arctic 

OCS operators to plan for response redundancies and planning complexities given challenges associated 

with logistics and transit times to respond to a well control event on the Arctic OCS, difficulties 

associated with oil spill response operations in Arctic OCS Conditions, and limited ability on the Arctic 

OCS to summon additional source control and containment resources.

Additionally, Section 250.470(f) would require operators who propose to use a MODU to conduct 

exploratory drilling operations below the surface casing on the Arctic OCS to provide with their APD 

information concerning their required SCCE capabilities, including a statement that the operator owns, or 

has a contract with a provider for, SCCE capable of controlling or containing the identified worst-case 

discharge (WCD).

23 Specifically, operators would be required to include: a detailed description of SCCE 

capabilities; inventory of local and regional SCCE, supplies, and services owned by the operator or for 

which the operator has a contract with a provider; and, where necessary, proof of contracts or membership 

 

23 Calculation of the volume of oil associated with a WCD scenario varies from site to site. This information is 

required as part of the oil spill response plan for each facility under 30 CFR 254.47.
37

agreements for SCCE or related supplies and services. Operators also would be required to include a 

detailed description of procedures for SCCE inspection, testing, and maintenance. In addition, operators 

would be required to provide a detailed description of plans to ensure that personnel are trained to deploy 

and operate the equipment and that they would maintain ongoing proficiency in source control operations.

These APD documentation requirements for SCCE would help assure BSEE that operators conducting 

exploratory drilling are capable of controlling or containing a loss of well control under Arctic OCS 

Conditions.

i. Equipment Requirements 

The equipment requirements under proposed Section 250.471(a) would result in capital and labor costs to 

industry. We assume that one-time capital and labor costs for operators that purchase this equipment

would be $270,000,000 per SCCE purchased, and that the annual redeployment costs associated with 

these requirements would be $1,200,000 per SCCE deployed. BOEM and BSEE assume that operators 

would engage in resource sharing of SCCE due to the high costs of this equipment.

We assume that – over the course of the 10-year analysis period - one entity currently owns the 

equipment, one entity would purchase this equipment, and one entity would share the resources with 

another operator. We assume that only the entity that purchases the equipment experiences the capital 

SCCE costs, but both the entity that purchases the equipment and the entity that already owns the 

equipment experience an annual deployment cost. We assume that the operator with two primary rigs in 

2017 will use one set of equipment to satisfy the SCCE requirements for both of its rigs. We do not 

assume additional costs to the entity that engages in resource sharing. To estimate the SCCE capital and 

labor costs to industry, we accounted for the number of purchased SCCE and the number of deployed 
38

SCCE on the Arctic OCS.

24 Exhibit 13 summarizes the annual capital costs of the SCCE requirements

under proposed Section 250.471(a).

Exhibit 13. Source Control and Containment Equipment Requirements 

(Capital Costs - § 250.471)

Year

Number of 

SCCE 

Purchased

One-time 

Purchase Cost 

per SCCE

Number of 

SCCE 

Deployed

Annual 

Deployment 

Cost per 

SCCE

Cost Incurred in a 

Year

A B C D E = A × B + C × D

2015–2017 0 $270,000,000 1 $1,200,000 $1,200,000 

2018 1 $270,000,000 2 $1,200,000 $272,400,000 

2019–2024 0 $270,000,000 2 $1,200,000 $2,400,000 

1We assume that one operator experiences the upfront costs while two operators experience the deployment costs of the SCCE 

requirements.

Because the industry does not currently engage in resource sharing on the Arctic OCS, BOEM and BSEE 

do not have details on how the process will be conducted and whether, for example, an operator would 

charge for access to equipment. The SCCE resource sharing assumptions presented here represent the 

most likely scenario based on BSEE’s knowledge of the industry. BSEE also considered a low cost 

scenario and a high cost scenario that vary the assumptions for resource sharing and purchase of SCCE 

equipment by operators. See Section 4.e of this analysis for details on the costs associated with these 

scenarios. 

ii. Stump Testing Requirements

We calculated a labor cost to industry per stump test for dry-stored capping stacks by multiplying the 

number of hours spent conducting these tests by the median hourly compensation rate for the labor 

category of individuals most likely to perform this work, resulting in a labor cost to industry of $208 per 

stump test for a dry-stored capping stack. We calculated the labor cost per stump test for PPCSs by first 

 

24 We assume that one-time capital costs associated with the SCCE availability requirements would be $270,000,000 

per purchased SCCE. We assume that annual redeployment costs associated with these requirements would be 

$1,200,000 per deployed SCCE. 
39

multiplying the number of hours spent conducting these tests by the median hourly compensation rate for 

the labor category of individuals most likely to perform this work. We then multiplied the number of days 

of rig crew time assumed to be spent to conduct these activities by the daily rig operating cost and 

summed these costs to obtain a cost of $160,208 per stump test for a PPCS.

25 Exhibit 14 summarizes the 

stump test cost for the SCCE requirements.

 

25 We assume that a senior engineer would spend 2 hours for each stump test for a dry-stored capping stack. We 

multiplied the number of hours spent by the median hourly compensation rate for a senior engineer to obtain a labor 

cost per stump test for a dry-stored capping stack of $208 (2 hours × $104.22). We assume that each rig with a drystored capping stack would conduct monthly tests (July – November) and that the operator entering in 2015 would 

use a dry-stored capping stack. Accounting for the frequency of testing for rigs with dry-stored capping stacks, we 

obtained an annual labor cost per rig of $1,042 (5 tests × 2 hours × $104.22). We assume a senior engineer and the 

entire rig crew would spend 2 hours on the stump tests for a PPCS. We calculated the labor costs to industry by first 

multiplying the time spent by a senior engineer by the median hourly compensation rate for senior engineers and 

then multiplying the hours of time for the entire rig crew by the daily operating cost for a rig on the Arctic OCS; the 

sum of these costs resulted in a labor cost to industry per stump test for a PPCS of $160,208 (2 hours × $104.22 + 

0.08 days × $2,000,000). We assume one stump test for each PPCS before installation on a well for each new well in 

the industry and one stump test before deployment. We assume that the number of rigs using PPCSs would be the 

difference between the total number of rigs and the number of rigs using dry-stored capping stacks, and that each rig 

installing a PPCS would install one on each well. 
40

Exhibit 14. Stump Tests within the Source Control and Containment Equipment Requirements (§

250.471(b))

Year

Number of 

Rigs with 

Dry-Stored 

Capping 

Stacks

Cost per 

DryStored 

Capping 

Stack

Number 

of Wells 

with 

PPCSs

Cost per 

Installation of 

PPCS

Number 

of New 

PPCSs

Cost per 

Deployment 

PPCS 

Annual 

Cost

A B C D E F

G = (A × B)

+ (C × D) + 

(E × F)

2015–2016 1 $1,042 0 $160,208 0 $160,208 $1,042

2017 2 $1,042 0 $160,208 0 $160,208 $2,084 

2018–2019 2 $1,042 2 $160,208 2 $160,208 $642,918 

2020–2024 2 $1,042 4 $160,208 4 $160,208 $1,283,752 

iii. Well Design Change Information Requirements

We assume that the requirement to submit a reevaluation of SCCE in the event of any changes to well 

design would result in labor costs to both the industry and BSEE. We calculated the labor costs to 

industry associated with this requirement by multiplying the time required for documentation by the 

median hourly compensation rate for the labor category of individuals most likely to perform this work, 

resulting in a labor cost to industry per well of $959. We calculated the per-well labor costs for BSEE 

associated with this requirement by multiplying the time required for review of submittals by the hourly 

compensation rate for the labor category of individuals most likely to perform this work. This calculation 

resulted in a per-well labor cost to BSEE of $410.

26 Exhibit 15 summarizes the annual costs associated 

with this requirement. We seek comments on the reasonableness of the assumptions in this section.

 

26 We assume that a mid-level engineer would spend 10 hours on the documentation associated with this 

requirement. We multiplied the number of hours by the median hourly compensation rate for mid-level engineers to 

obtain a labor cost to industry of $959 (10 hours × $95.92) per well. We assume that a mid-level BSEE engineer 

would spend 5 hours on the review of submittals associated with this requirement, or half hour for every hour the 

industry spends to consolidate the information. We multiplied the number of hours by the hourly compensation rate 

to obtain a cost to BSEE per well of $410 (5 hours × $82.02).
41

Exhibit 15. Information Requirements Associated with Well Design Changes (§250.471(c))

Year

Number 

of Wells

Industry 

Cost per 

Well Annual Cost

Number of 

Wells

Agency Cost 

per Well Annual Cost

A B C = A × B D E F = D x E

2015 2 $959 $1,918 2 $410 $820 

2016–2019 4 $959 $3,837 4 $410 $1,640 

2020–2024 6 $959 $5,755 6 $410 $2,461 

iv. Test and Exercise Requirements 

We also assume that the labor and equipment costs associated with the requirements for Regional 

Supervisor-initiated tests and exercises would be $500,000 per rig and that these tests would be conducted 

annually for all rigs in operation, including both the entity that purchased the SCCE equipment and the 

entities that are sharing the equipment.

27 Exhibit 16 summarizes the Regional Supervisor-initiated test and 

exercise costs within the SCCE requirements. We seek comments on the assumptions in this section.

Exhibit 16. Regional Supervisor-initiated Tests and Exercises within the Source Control and 

Containment Equipment Requirements (§ 250.471(d))

Year

Number of Rigs Cost per Rig Annual Cost

A B C = A × B

2015–2016 1 $500,000 $500,000 

2017 2 $500,000 $1,000,000 

2018–2024 4 $500,000 $2,000,000 

v. Records Maintenance Requirements 

We calculated the labor costs associated with the SCCE records maintenance requirements by multiplying 

the amount of time assumed to be spent on records maintenance by the median hourly compensation rate 

for the labor category of individuals most likely to perform these activities, resulting in an annual labor 

 

27 We assume that Regional Supervisor-initiated tests and exercises for SCCE would be conducted annually and that 

labor and equipment costs associated with these activities would be $500,000 per rig. 
42

cost to industry per well of $1,174. We calculated the labor costs to BSEE associated with these records 

maintenance requirements by multiplying the amount of time required to review records by the hourly 

compensation rate for the labor category of individuals most likely to perform this work, resulting in an 

annual labor cost to BSEE per well of $1,938.

28 Exhibit 17 summarizes the record maintenance 

requirements within the SCCE requirements for both the industry and the government. We seek 

comments on the assumptions in this section.

Exhibit 17. Record Maintenance Requirements within the Source Control and 

Containment Equipment Requirements (§250.471(e))

Year

Number of 

Wells

Industry Cost 

per Well

Annual 

Industry 

Cost

Number of 

Wells

Agency Cost 

per Well

Annual 

Agency 

Cost

A B C = A × B D E F = D × E

2015 2 $1,174 $2,347 2 $1,938 $3,877 

2016–2019 4 $1,174 $4,694 4 $1,938 $7,754 

2020–2024 6 $1,174 $7,042 6 $1,938 $11,630 

vi. Documentation Requirements 

We calculated the labor costs to industry associated with SCCE documentation by multiplying the 

number of hours assumed to be spent on these activities by the median hourly compensation rate for the 

labor category of individuals most likely to conduct this work, resulting in a labor cost to industry per 

APD of $5,755. We calculated the labor costs to BSEE by multiplying the number of hours assumed to be 

spent reviewing the submittals by the hourly compensation rate for the labor category of individuals most

 

28 We assume that administrative staff would spend 40 hours per well on this required SCCE records maintenance. 

We multiplied the number of hours by the median hourly compensation rate for administrative staff to obtain an 

annual labor cost per well associated with these record maintenance requirements of $1,174 (40 hours × $29.34). We 

also assume that a BSEE Inspector would spend 20 hours per well to review these records, assuming that agency 

review takes 1⁄2 hour for every hour of industry burden. We multiplied the number of hours by the hourly 

compensation rate for a BSEE Inspector to obtain an annual labor cost per well of $1,938 (20 hours × $96.92). 
43

likely to conduct this work, resulting in an estimated labor cost to BSEE per APD of $2,461.

29 Exhibit 18

summarizes the APD document requirements regarding SCCE for both the industry and the government.

We seek comments on the assumptions in this section.

Exhibit 18. APD Documentation Requirements for Source Control and 

Containment Equipment (§ 250.470(f))

Year

Number of 

APDs

Industry Cost 

per APD

Annual 

Industry 

Cost

Number of 

APDs

Agency Cost 

per APD

Annual 

Agency 

Cost

A B C = A × B D E F = D × E

2015 2 $5,755 $11,510 2 $2,461 $4,921 

2016–2019 4 $5,755 $23,021 4 $2,461 $9,842 

2020–2024 6 $5,755 $34,531 6 $2,461 $14,764 

i. Relief Rig Requirements (§ 250.472)

Proposed section 250.472 describes the relief rig requirements for the Arctic OCS. Operators on the 

Arctic OCS, when conducting exploratory drilling or working below the surface casing, would be 

required to have a relief rig, different from their primary drilling rig, staged in a location such that it can 

arrive on site, drill a relief well, kill and abandon the original well, and abandon the relief well prior to 

expected seasonal ice encroachment at the drill site, but no later than 45 days after the loss of well 

control. The 45-day maximum timeframe for completing a relief well would effectively limit the number 

of days an operator can drill or work below the surface casing at the end of each drilling season. This 

limitation on certain operations may result in some costs to operators from foregone activity, even though 

there are some operations that can be done at the well site at the end of the season that do not involve 

work below the surface casing. The relief rig must also comply with all other requirements of Part 250 for 

 

29 We assume that industry mid-level engineers would spend 60 hours on these SCCE documentation requirements. 

We multiplied the number of hours by the median hourly compensation rate for mid-level engineers to obtain a labor 

cost of $5,755 (60 hours × $95.92) per APD. We also assume that a mid-level BSEE engineer would spend 30 hours 

to review these submittals. We multiplied the number of hours by the hourly compensation rate for mid-level 

engineers to obtain a labor cost to BSEE of $2,461 (20 hours x $82.02) per APD. 
44

drilling operations and be able to drill a relief well under anticipated Arctic OCS Conditions. Paragraph 

(a) also authorizes the Regional Supervisor to direct an operator, in the event of a loss of well control, to 

drill a relief well using the relief rig described in the operator’s APD. 

Proposed Section 250.470(e) requires operators submitting APDs for exploratory drilling on the Arctic 

OCS to submit a detailed description with the APD of how they would comply with the requirements 

under proposed Section 250.472. Both the relief rig requirements and the SCCE requirements (discussed 

above) are fundamental to safe and responsible operations on the Arctic OCS, where existing 

infrastructure is sparse, the geography and logistics make it challenging to bring equipment and resources 

into the region, and the time available to mount response operations is limited by changing weather and 

ice conditions, particularly at the end of the drilling season. 

To estimate the capital costs associated with the relief rig requirements, BOEM and BSEE assume that 

the operator conducting exploratory drilling beginning in 2015 will have a standby relief rig30

independent of their one primary rig in 2015 and 2016. We assume that a standby relief rig will be used 

during only one or two drilling seasons because, over time, we expect that the presence of multiple 

operating rigs on the Arctic OCS will make it easier for one operating drilling rig to be designated as a 

relief rig for another operating rig. In the third year of the analysis period, we assume that the first 

operator would operate an additional primary rig, at which point the two primary rigs will serve as relief 

rigs for each other (i.e., beginning in 2017, no standby relief rig is assumed). For the two operators 

conducting exploratory drilling beginning in 2018, we assume that these operators will rely on each 

other’s primary rigs as their respective relief rigs. For the first operator, there is a cost to the standby

relief rig for the first two years of the analysis period. We do not estimate any additional costs from this 

requirement for the two operators that begin to drill in 2018. To estimate the cost of operating a standby 

 

30 We refer to relief rigs that are not conducting exploratory drilling as “standby relief rigs,” and these rigs are 

assumed to incur different costs than relief rigs that are conducting exploratory drilling (i.e. “primary rigs” or 

“operating rigs”). 
45

relief rig, we multiplied the number of operating days in a drilling season by the daily rig operating cost to 

estimate an annual per rig cost of $276,000,000. 31 

The BOEM and BSEE estimate the cost assuming that there will be a standby relief rig separate from the 

primary drilling rig in 2 years of the analysis period based on the expected plans of current operators. We 

recognize that operator plans change and evolve over time and predictions of the next 10 years are not 

known with certainty. Exploratory Plans suggest that in the future operators will not use a dedicated 

standby relief rig, but instead will designate a second operating rig to serve as a relief rig. If, however, an 

operator chooses to deploy a dedicated standby relief rig to comply with regulatory requirements, it could 

incur costs of approximately $276 million per rig, per season. The BOEM and BSEE request comment 

on the costs and resource sharing assumptions associated with the relief rig requirements.

The proposed 45-day maximum limit on the time necessary to complete the required relief rig activities 

under Section 250.472 would effectively require the cessation of exploratory drilling below or working 

below the surface casing far enough in advance of the expected return of seasonal ice to allow for 

completion and abandonment of a relief well. Conditions of the EP approval for Shell’s 2012 Arctic 

operations required drilling operations in zones capable of liquid hydrocarbons flowing in measurable 

quantities into the well to be concluded 38 days prior to November 1, based on satellite imagery showing 

the five-year historical average of earliest encroachment of sea ice over Shell’s drill site and the time 

estimated for Shell to complete relief well operations.

We recognize that the requirement to have the capability to drill a relief well to permanently kill an outof-control well may lead to a reduction in the number of days during which operators can perform work 

below the surface casing during the drilling season. There will be costs and benefits associated with this 

requirement. Those costs (including “opportunity costs”) may also include costs resulting from a 

 

31 We conservatively assume that a standby relief rig would cost the same amount as the primary rig to operate. We 

multiplied the number of operating days by the daily rig operating cost to obtain an annual cost per standby relief rig 

of $276,000,000 (138 days x $2,000,000).
46

reduction in the number of wells that can be drilled during the term of the lease under which the operator 

is conducting exploratory drilling operations.

This Initial RIA for the proposed rule discusses the challenges associated with estimating opportunity 

costs. Because the Arctic OCS is a frontier area for drilling operations, there are very few data points that 

would provide the basis for accurate estimates. Any attempt to calculate opportunity costs would have to 

take into account the significant number of uncertainties associated with exploratory drilling, the nature of 

the economic benefits sought to be achieved by such operations (e.g. booking reserves), and a variety of 

other factors. These factors will often depend upon the decisions an operator makes on how to conduct 

drilling operations during each drilling season and the nature of the opportunities for other productive use 

of the assets. 

Data available to BOEM and BSEE indicate that the estimated daily operating cost of a drilling rig 

located in the Arctic OCS is approximately $2 million. This estimate includes all of the costs associated 

with operating a rig (e.g., including the costs of the rig crew). This figure is based upon an analysis of the 

daily costs of rigs currently operating in the Gulf of Mexico, adjusted significantly upward to account for 

the harsh operating conditions in the Arctic. The actual operating costs for a rig operating in the Arctic 

OCS will likely vary greatly from season to season. Industry data presented in the course of this 

rulemaking indicated that the fixed costs of drilling in the Arctic for one season are $1.2 billion, which, 

amortized over an entire 100-day season of drilling, is equivalent to $12 million per day in sunk costs.32 

Any calculation of opportunity costs should include an estimated return on investment. Such a 

calculation could be based on the OMB Circular A-4 estimate of the average before-tax rate of return to 

 

32 During a meeting conducted with OMB pursuant to E.O. 12866, Shell stated that its total costs for a 100-day 

drilling season were $1.5 billion and that 80% of those costs ($1.2 billion) were “sunk.” Dividing these costs by 100 

(the assumed length of the drilling season) yields an estimate of $12 million per day. These costs have not been 

independently validated by BOEM and BSEE, and it is not known if the industry figure provided already included 

the expected return on capital.
47

private capital in the U.S. economy (7 percent) or could be based on the industry stated average return on 

capital (10 percent).

Any calculation of opportunity costs should also estimate the number of days per season that the operator 

could not conduct work below the surface casing. While the proposed rule would impose a maximum 

period of 45-days for a relief rig to deploy and complete a relief well and, thus, a maximum of 45-days 

during which work below the surface casing would not occur, the actual number of days during which an 

operator would not be able to conduct drilling or other work below the surface casing is subject to a 

number of variables. As discussed previously, we estimate that it would take 20 days to prepare and 

transport a rig from the nearest U.S. deep water port (Dutch Harbor) to the farther well location (Beaufort 

leases), 20 days to drill the relief well, and five days to plug the uncontrolled well, test it, and move off 

the well site. Further, the actual time needed for completing a relief well operation would vary depending 

on a number of factors. For example, the estimated actual time needed would depend on how an operator 

proposes to stage a relief rig; e.g., if it chooses to deploy a dedicated standby relief rig or to designate a 

second operating rig as a relief rig. In the latter case, a relief rig operating in the near vicinity of the 

primary rig, as proposed by Shell in its revised Exploration Plan for 2015,33 may be able to reach the site 

of a blowout and complete a relief well in as little as 25 days, assuming no transit time for the rig. 

Moreover, other work, which will likely have significant economic benefit, may continue under the 

proposed rule during the period that work below the surface casing is not allowed, providing economic 

benefits from other activities that could be conducted during this period (for example, in 2012, Shell 

drilled top holes during the period it was not allowed to drill into hydrocarbon bearing zones). If the 

alternative work was of similar economic value, there would be no opportunity cost. However, it is likely 

the alternative work would have a lesser value than the forgone work, and thus only partially offset the 

opportunity cost. 

 

33 http://www.boem.gov/EP-PUBLIC-VERSION/
48

The Initial RIA assumes that, during 10 years of exploratory drilling operations, primary rigs (up to four 

per season during 2018-2024) will conduct a total of 32 drilling campaigns. During those drilling 

campaigns, costs associated with each rig will be highly variable. Current estimates of these costs range 

from $ 2 million to $12 million per day. The breadth of this range, combined with the number of 

significant additional variables (number of days affected; rate of return), makes it difficult to estimate a 

range of annual opportunity costs. Additional data related to operating costs, forecasted positioning of 

relief rigs, the economic effect of operating two rigs in theater during the same season, and other 

significant variables may provide the basis for meaningful estimates of annual opportunity costs 

associated with the requirement that a relief rig be able to deploy and complete a relief well within 45 

days of the end of the drilling season. We encourage comments on such estimated costs, as well as 

benefits, with supporting data, including data on the uses to which a primary rig could be put during the 

time it is not working below the surface casing. Any such estimates should, if appropriate, include 

estimated return on capital that would be forgone as a result of these requirements. 

The documentation requirements under proposed Section 250.470(e) would result in labor costs to 

industry and BSEE. We assume that all entities must report on their chosen method for complying with 

the relief rig requirements for each primary rig. We assume that the relief rig documentation requirements 

would be a one-time cost for each rig. We calculated the labor costs to industry associated with the relief 

rig documentation requirements by multiplying the number of hours assumed to be spent documenting 

compliance by the median hourly compensation rates for the labor categories of the individuals most 

likely to perform this work, resulting in a one-time labor cost to industry per rig associated with relief rig 

documentation of $14,591.

34

 

34 We assume that industry senior engineers would spend 140 hours to document compliance with relief rig 

requirements. We multiplied the number of hours by the median hourly compensation rate for senior engineers to 

obtain a one-time, per-rig labor cost to industry of $14,591 (140 hours × $104.22). 
49

We calculated the labor costs to BSEE associated with the relief rig documentation requirements by 

multiplying the number of hours assumed to be spent reviewing submittals by the hourly compensation 

rates for the labor categories of individuals most likely to perform this work. This calculation resulted in a 

one-time labor cost to BSEE of $5,741 per rig related to relief rig documentation.

35 Exhibit 19

summarizes the annual costs of the relief rig documentation requirements for both the industry and BSEE.

Exhibit 19. Relief Rig Documentation Requirements (§250.470(e))

Year

Number of 

New Rigs

One-time Industry 

Cost per Rig

Industry 

Annual 

Cost

Number of 

New Rigs

One-time 

Agency Cost per 

Rig

Agency 

Annual

Cost

A B C = A × B D E F = D × E

2015 1 $14,591 $14,591 1 $5,741 $5,741

2016 0 $14,591 $0 0 $5,741 $0

2017 1 $14,591 $14,591 1 $5,741 $5,741

2018 2 $14,591 $29,182 2 $5,741 $11,483 

2019–2023 0 $14,591 $0 0 $5,741 $0 

j. Additional Auditing Requirements (§ 250.1920)

Proposed section 250.1920 would increase the audit frequency and facility coverage for Arctic OCS 

exploratory drilling operations. While operators are generally required to conduct their SEMS audit every 

3 years after their initial audit, BSEE believes it would be critical to perform a SEMS audit of Arctic OCS 

exploratory drilling operations and all related infrastructure each year in which drilling is conducted, 

because of the particularly challenging conditions and high-risk nature of those activities.

We account for the costs associated with the increased audit frequency by assuming that the incremental 

burden of additional audits will be incurred two out of every three years. 36 We calculate the cost of these 

 

35 We assume that a BSEE mid-level engineer would spend 70 hours to review these submittals (1⁄2 hour for every 

hour of industry review burden). We multiplied the number of hours by the hourly compensation rate for mid-level 

engineers to obtain a one-time labor cost to BSEE of $5,741 (70 hours × $82.02) per rig. 

36 For simplification, we assume that the audit costs occur in the first two out of every three years. This is a

conservative assumption; however, this does not imply that audits will necessarily happen in this sequence. 
50

audits by multiplying the total cost per audit for a high activity operator by the number of operators. We 

assume that the audit cost per operator to industry will be $129,000.37 We assume that the audit cost per 

operator to BSEE will be $17,754.38 Exhibit 20 summarizes these costs. We seek comments on the 

reasonableness of the assumptions in this section.

Exhibit 20. Additional Auditing Requirements (§ 250.1920)

Year

Number of 

Audits

Industry 

Cost per 

Audit

Industry 

Annual Cost

Number of 

Audits

Agency Cost 

per Audit

Agency 

Annual Cost

A B C = A × B D E F = D × E

2015 1 $129,000 $129,000 1 $17,754 $17,754 

2016 1 $129,000 $129,000 1 $17,754 $17,754 

2017 0 $129,000 $0 0 $17,754 $0 

2018 3 $129,000 $387,000 3 $17,754 $53,262 

2019 3 $129,000 $387,000 3 $17,754 $53,262 

2020 0 $129,000 $0 0 $17,754 $0 

2021 3 $129,000 $387,000 3 $17,754 $53,262 

2022 3 $129,000 $387,000 3 $17,754 $53,262 

2023 0 $129,000 $0 0 $17,754 $0 

2024 3 $129,000 $387,000 3 $17,754 $53,262 

k. Real-time Location Tracking Requirements (§ 254.80)

Proposed Section 254.80 describes additional information requirements for the emergency response 

action plan section of the response plan for operators conducting exploratory drilling on the Arctic OCS.

 

37 This cost estimate originates from 30 CFR 250, Subpart S - Safety and Environmental Management Systems 

(SEMS), OMB Control Number 1014-0017. 

38 In 30 CFR 250, Subpart S - Safety and Environmental Management Systems (SEMS), OMB Control Number 

1014-0017, BSEE estimates that the burden for BSEE to review audits is 28,527 hours, with 10 percent of the hours 

for clerical support, 80 percent of the hours for a mid-level engineer, and 10 percent of the hours for a supervisory 

engineer. Because this regulation covers audits for 130 operators, we estimate that one audit would take 219 hours 

(28,527 hours ÷ 130 operators). To estimate the cost, we assume that a clerk would spend 22 hours (10% x 219), a 

mid-level engineer would spend 176 hours (80% x 219) and a supervisory engineer would spend 22 hours (10% x 

219). To estimate the per-audit cost to BSEE, we multiplied the corresponding hourly compensation rates by the 

allocated hours to estimate a $17,754 per-audit cost (22 hours x $38.89 + 176 hours x $82.02 + 22 hours x $114.01).
51

Only proposed Section 254.80(c) would impose a new burden on the industry and BSEE, not already 

covered by other existing regulations and subsequent paperwork burden supporting statements. Paragraph 

(c) requires operators to describe how they would maintain an effective tracking and management system 

that is able to locate in real time all response equipment and personnel conducting response activities, or 

transiting to and from the response site(s), and to maintain a current picture of resources entering and 

exiting staging areas and the operational status of those resources. This system would be essential to 

provide the Unified Command with information necessary to ensure that sufficient personnel and 

equipment would be available to meet the response needs.

These information requirements would result in labor costs to industry and BSEE. We calculated the labor 

costs to industry by multiplying the number of hours assumed to be spent on including this information in 

the response plan by the median hourly compensation rate for the labor category of individuals most 

likely to perform this work, resulting in a labor cost to industry of $401 per OSRP. We calculated the 

labor costs to BSEE by multiplying the number of hours assumed to be spent associated with these 

information requirements by the hourly compensation rate for the labor category of individuals most 

likely to perform this work, resulting in a labor cost to BSEE per OSRP of $246.

39

In addition to the reporting costs, BOEM and BSEE estimated the cost for complying with proposed 

Section 254.80(c) by using an Automatic Identification System (AIS) to track both equipment and 

personnel during the drilling season. Operators have the flexibility to choose which system would monitor 

their equipment and personnel during the drilling season; however, we use the AIS as a representative 

system. BOEM and BSEE estimated the cost per entity to have AIS devices on vessels and tracking 

devices on equipment and personnel based on the costs incurred by the initial operator. We recognize that 

 

39 We assume that industry environmental specialists would spend 6 hours to include the required information in the 

response plan. We multiplied the number of hours by the median hourly compensation rate for environmental 

specialists to obtain a labor cost to industry per OSRP of $401 (6 hours × $66.85). We also assume that a BSEE 

mid-level engineer would spend 3 hours on these information requirements or 1⁄2 hour for every hour of industry 

burden. We multiplied the number of hours by the hourly compensation rates for mid-level engineers to obtain a 

labor cost to BSEE of $246 (3 hours × $82.02) per OSRP. We assume that a total of two OSRPs would be submitted 

by operators on the Arctic OCS each year. 
52

this cost will vary based on implementation for each operator. We do not, however, have the additional 

information needed to determine the specific costs of each of the expected operators, which will vary by 

their size (e.g., vessels, equipment, and personnel). Using information on the current tracking systems, we 

estimated cost per system including the purchase of tracking devices, the purchases of AIS devices, the 

installation of the tracking device and the AIS units, the monthly fee for tracking devices, and the annual 

fee for AIS services. Exhibit 21 presents the unit costs, the number of units, and the total cost for the AIS 

system.40 We considered all costs to be upfront costs, except for the monthly fee for tracking devices and 

the annual fee for the AIS. BOEM and BSEE assume that operators would need to replace the AIS 

(including the main unit and tracking devices) every 8 years. BOEM and BSEE request comment on how 

often operators would need to replace the real-time tracking system.

 

40 We assume that an electrician will need to install the AIS unit onto vessels and that it will take 12 hours per 

device to install. We multiplied the hours spent by the electrician to install the device to obtain a cost per device 

installation of $626 (12 hours x $52.15). We assume that a crew member would install the tracking devices on the 

equipment and it would take 1⁄2 hour per tracking device. We multiplied that by the median hourly compensation rate 

for a rig crew member to estimate an installation cost of $28 per device (1/2 hour x $56.86).
53

Exhibit 21: Automatic Identification System Costs per Entity (§ 254.80(c))

AIS Cost Inputs per Entity Unit Cost

Number 

of Units Total Cost

Purchase tracking/locator devices – personnel $150 100 $15,000

Purchase tracking/locator devices - equipment $100 187 $18,700

Purchase AIS (small vessels) $1,000 6 $6,000

Purchase AIS (larger vessels) $3,000 4 $12,000

Tracking device installation (rig crew installer) $28 187 $5,316

AIS installation (electrician) $626 10 $6,258

Monthly fee for tracking/locator devices – personnel

1

$10 100 $5,000

Monthly fee for tracking/locator devices – equipment $10 187 $9,350

AIS annual fee (per user name) $1,000 25 $25,000

Upfront Cost2$63,274

Annual Cost $39,350

1. We assume that the monthly tracking fees for both personnel and equipment occur during the five-month drilling 

season only.

2. We assume that operators pay the upfront cost at the start of every lifecycle or every 8 years. 

We estimated the AIS costs by multiplying the upfront costs by the number of operators each year. As 

shown in Exhibit 3, we assume new operators in 2015 and 2018. We also estimate the upfront cost to 

replace the AIS device and tracking units in 2022 for the original operator based on the 8-year lifecycle 

cost of AIS.

41 We estimate the recurring cost of AIS by multiplying the recurring cost by the number of 

operators each year. Exhibit 22 presents details on the AIS costs. We seek comments on the 

reasonableness of the assumptions in this section.

 

41 We assume that training costs for AIS are already accounted for under SEMS requirements.
54

Exhibit 22. Real-time Location Tracking Requirements (§ 254.80(c))

Year

Number of

New AIS

Upfront 

Industry 

Cost per 

Operator Annual Cost

Number of 

Active AIS

Annual 

Industry 

Cost per 

Operator Annual Cost

A B C = A × B D E F = D × E

2015 1 $63,274 $63,274 1 $39,350 $39,350 

2016–2017 0 $63,274 $0 1 $39,350 $39,350 

2018 2 $63,274 $126,549 3 $39,350 $118,050 

2019–2021 0 $63,274 $0 3 $39,350 $118,050 

2022 1 $63,274 $63,274 3 $39,350 $118,050 

2023–2024 0 $63,274 $0 3 $39,350 $118,050 

l. IOP Requirements (§ 550.204)

Proposed Section 550.204 would require operators proposing to conduct exploratory drilling operations 

on the Arctic OCS to develop an IOP for each proposed exploratory drilling program on the Arctic OCS, 

and to submit the IOP to DOI, acting through its designee, BOEM, at least 90 days in advance of filing its 

EP. The IOP would need to describe how the proposed exploratory drilling program would be designed 

and conducted in an integrated manner suitable for Arctic OCS Conditions and would address each of the 

information requirements identified in proposed Section 550.204. In the IOP, operators would be required 

to include information on several aspects of operations: vessels and equipment (including general 

maintenance schedule), schedule and objectives of the exploratory drilling program (including contractor 

work on critical components, plans for abandonment, and timelines for each objective), mobilization and 

demobilization operations (including tow plans suitable for Arctic OCS Conditions), weather and ice 

forecasting capability, work to be performed by contractors, operational safety, preparations and plans for 

staging of oil spill response assets, efforts to minimize impacts of exploratory drilling operations on local 

community infrastructure, and the extent to which the project will rely on local community workforce and 

spill cleanup response capacity. We assume the operator has previously gathered virtually all of this 

information in developing its approach for conducting exploratory operations and that the operator would 
55

be merely providing existing information under the umbrella of the IOP. The IOP process is intended to 

facilitate the sharing of information among the relevant Federal agencies and the State of Alaska, as well 

as to provide the public an early view of the operator’s plans. The IOP process also provides the relevant 

agencies an early opportunity to engage in a meaningful and constructive dialogue with operators and 

each other.

These information requirements would result in labor costs to industry and BOEM. We calculated the 

labor costs to industry by multiplying the time assumed to be spent to compile and include the required 

information by the median hourly compensation rate for the labor category of individuals most likely to 

conduct this work, resulting in a labor cost to industry of $8,633 per IOP. We calculated the labor costs to 

BOEM by multiplying the time assumed to be spent reviewing the submittals by the hourly compensation 

rates for the labor categories of individuals most likely to conduct this work, resulting in a labor cost to

BOEM of $53,951 per IOP.

42 We seek comments on the reasonableness of the assumptions in this 

section.

m. Planning Information Requirements to Accompany EPs (§ 550.220)

Proposed Section 550.220 includes additional information requirements for planning information that

must accompany EPs for operators proposing to conduct exploration activities in the Alaska OCS Region.

Paragraph (a) requires operators to have emergency plans to respond to a fire, explosion, personnel 

evacuation, or loss of well control, as well as a loss or disablement of a drilling unit, vessel, offshore 

vehicle, or aircraft. Paragraph (c) would require operators proposing exploration activities on the Arctic 

OCS to submit additional planning information to accompany EPs, including information on suitability 

 

42 We assume that mid-level engineers would spend 90 hours to compile and include the required information in the 

IOP. We multiplied the number of hours by the median hourly compensation rate for mid-level engineers to obtain a 

cost to industry of $8,633 (90 hours × $95.92) per IOP. We also assume that several BOEM employees would 

review these documents, including, a regulatory analyst (120 hours), a petroleum engineer (120 hours), a geologist 

(160 hours), a BOEM Chief (160 hours) and a Regional Supervisor (160 hours). We multiplied the number of hours 

by the hourly compensation rate for each respective labor category to obtain a cost to BOEM of $53,951 per IOP 

(120 hours x $57.54 + 120 hours x $68.97 + 160 hours x $31.38 + 160 hour x $96.92 + 160 hours x $114.01). We 

assume that operators on the Arctic OCS would submit a total of two IOPs each year. 
56

for Arctic OCS Conditions, ice and weather management, SCCE capabilities, deployment of a relief rig, 

resource sharing, and anticipated end of season dates. These information requirements will help to ensure, 

through thorough advanced planning, that operators are capable of operating safely in the extreme and 

challenging Arctic OCS Conditions.

These information requirements would result in labor costs to industry and BOEM. We calculated the 

labor costs to industry by multiplying the time assumed to be spent to compile and include the required 

information by the median hourly compensation rate for the labor category of individuals most likely to 

conduct this work, resulting in a labor cost to industry of $4,316 per EP. We calculated the labor costs to 

BOEM by multiplying the time assumed to be spent reviewing the submittals by the hourly compensation 

rate for the labor categories of individuals most likely to conduct this work, resulting in a labor cost to 

BOEM of $10,790 per EP.

43 We then accounted for the number of EPs that are expected to be submitted 

each year for operations on the Arctic OCS to obtain a total labor cost to industry of $82,012 and to 

BOEM of $205,013. We seek comments on the reasonableness of the assumptions in this section.

n. Industry Familiarization with the New Rule

When the new regulation takes effect, industry would need to read and interpret the rule. Through this 

review, operators would familiarize themselves with the structure of the new rule and identify any new 

provisions relevant to their operations. Operators would also evaluate whether any new action must be 

taken to achieve compliance with the rule.

 

43 We assume that mid-level engineers would spend 45 hours to compile and include the required information for the 

EP. We multiplied the number of hours by the median hourly compensation rate for mid-level engineers to obtain a 

cost to industry of $4,316 (45 hours × $95.92) per EP. We also assume that several BOEM employees would review 

these documents including a regulatory analyst (24 hours), a petroleum engineer (24 hours), a geologist (32 hours), a 

BOEM Chief (32 hours) and a Regional Supervisor (32 hours). We multiplied the number of hours by the hourly 

compensation rate for each respective labor category to obtain a cost to BOEM of $10,790 per EP (24 hours x 

$57.54 + 24 hours x 68.97 + 32 hours x 31.38 + 32 hour x $96.92 + 32 hours x 114.01). We assume that operators 

on the Arctic OCS would submit one EP in the first year and a total of two EPs in each year after.
57

Reviewing the new regulations would require staff time, imposing a one-time labor cost on industry. We 

estimated the one-time labor cost for industry familiarization with the rule at $1,042 per operator.

44 We 

seek comments on the reasonableness of the assumptions in this section.

6. Summary of the Cost Analyses

Exhibits 23 and 24 summarize the cost analysis. We present the costs for Alternative 1, the proposed rule 

with the BOP pressure testing requirements, and Alternative 2, the proposed rule without the BOP 

pressure testing requirements. Exhibit 23 summarizes the 10-year average annual costs (undiscounted) for 

the proposed rule by provision. Exhibit 24 summarizes the costs for both alternatives using discount rates 

of 3 percent and 7 percent. Similar to the analyses presented above, summations in Exhibit 23 and Exhibit 

24 might not add because of rounding.

 

44 We assume that for each operator on the Arctic OCS, a senior engineer would spend 10 hours to review the new 

regulation. We multiplied the number of hours by the median hourly compensation rate for a senior engineer to 

obtain a one-time labor cost to industry per operator of $1,042 (10 hours × $104.22).
58

Exhibit 23. 10-Year Average Annual Costs by Provision (with no discounting)

Provision

10-year Average Annual 

Costs: Alternative 1

(with 7-day BOP testing 

requirement)

10-year Average Annual 

Costs: Alternative 2

(without 7-day BOP testing 

requirement)

(a) Additional Incident Reporting

Requirements $5,374 $5,374

(b) Pollution Prevention Requirements $13,585 $13,585

(c) Additional Requirements for 

Securing Wells $24,000,000 $24,000,000

(d) Additional BOP Pressure Testing 

Requirements $19,200,000 $0

(e) Real-time Monitoring 

Requirements $2,208,000 $2,208,000

(f) Additional Information 

Requirements for APDs $16,771 $16,771

(g) Incorporation of proposed draft 

API RP 2N, Third Edition $9,240 $9,240

(h) Additional SCCE Requirements $31,471,823 $31,471,823

(i) Relief Rig Requirements $55,208,133 $55,208,133

(j) Additional Auditing Requirements $249,482 $249,482

(k) Real-time Location Tracking 

Requirements $121,044 $121,044

(l) IOP Requirements $125,167 $125,167

(m) Planning Information 

Requirements to Accompany EPs $28,702 $28,702

(n) Industry Familiarization with the 

New Rule $313 $313

TOTAL $132,657,635 $113,457,635
59

Exhibit 24. Summary of Monetized Costs1,2

Year

Industry Costs: 

Alternative 1

(with 7-day BOP 

testing 

requirement)

Industry Costs: 

Alternative 2

(without 7-day 

BOP testing 

requirement)

Government 

Costs

Total Costs: 

Alternative 1

(with 7-day BOP 

testing 

requirement)

Total Costs: 

Alternative 2

(without 7-day 

BOP testing 

requirement)

A B C D = A + C E = B + C

2015 $294,689,955 $288,689,955 $155,932 $294,845,887 $288,845,887 

2016 $304,631,665 $298,631,665 $171,956 $304,803,620 $298,803,620 

2017 $35,717,099 $23,717,099 $162,221 $35,879,320 $23,879,320 

2018 $322,562,375 $298,562,375 $225,779 $322,788,154 $298,788,154 

2019 $52,406,644 $28,406,644 $214,296 $52,620,941 $28,620,941 

2020 $62,678,863 $38,678,863 $172,010 $62,850,873 $38,850,873 

2021 $63,065,863 $39,065,863 $225,271 $63,291,135 $39,291,135 

2022 $63,129,138 $39,129,138 $225,271 $63,354,409 $39,354,409 

2023 $62,678,863 $38,678,863 $172,010 $62,850,873 $38,850,873 

2024 $63,065,863 $39,065,863 $225,271 $63,291,135 $39,291,135 

Undiscounted 

10-year total

$1,324,626,328 $1,132,626,328 $1,950,018 $1,326,576,346 $1,134,576,346 

PV 10-year 

total with 3% 

discounting

$1,221,896,314 $1,057,816,579 $1,701,450 $1,223,597,763 $1,059,518,028 

PV 10-year 

total with 7% 

discounting

$1,110,686,488 $975,624,608 $1,441,797 $1,112,128,285 $977,066,405 

Annualized 

with 3% 

discounting

$143,243,524 $124,008,373 $199,462 $143,442,986 $124,207,835 

Annualized 

with 7% 

discounting

$158,136,768 $138,906,995 $205,279 $158,342,048 $139,112,275 

1Totals might not add because of rounding.

2The total 10-year costs of the proposed rule are discounted using 3 and 7 percent discount rates. Discounting makes 

costs occurring in different periods comparable by expressing them in present value terms. Costs discounted at a 

higher rate are worth less in present value terms than costs discounted at a lower rate. This effect is observed for the 

proposed rule, with total costs with 3 percent discounting estimated at $1.2 billion, and total costs with 7 percent 

discounting estimated at $1.1 billion. In addition to the total costs, we also estimate the annualized costs using 3 

and 7 percent discount rates. Annualizing total costs results in an estimate of the costs that would be incurred in 

each period (such as each year for 10 years) so that the sum of all these periodic costs would equal the total cost. 

The impact of discounting annualized costs is the opposite of what is observed for total costs, with higher discount 

rates resulting in higher annualized costs. This opposite effect is observed because a higher discount rate reduces 

costs in future years more than a lower discount rate, resulting in a higher annualized cost needed to equal the same 

total cost than if a lower discount rate was used. This effect is observed in the annualized cost estimates for the 
60

proposed rule, with annualized costs of $143 million and $158 million with 3 percent and 7 percent discounting, 

respectively. The reader should note that the costs to industry and the Government vary during the 10-year analysis 

period. These changes occur due to a variety of factors including, but not limited to, new rigs entering the theaters, 

different equipment requirements and other similar factors that occur throughout the analysis period.

7. Break-Even Analysis

In the preceding section, we presented our estimate that the proposed rule would result in economic costs 

of $1.2 billion under 3 percent discounting and $1.1 billion under 7 percent discounting over 10 years 

under Alternative 1, the proposed rule. Although the economic and other benefits of the proposed rule—

based primarily on preventing or reducing the duration of catastrophic oil spills—are difficult to quantify, 

BOEM and BSEE have determined that it is appropriate to proceed with this proposed rule. Although the 

probability of a catastrophic spill is very small, the Deepwater Horizon oil spill demonstrated that such 

low probability events can have devastating economic and environmental consequences.

45 We use double 

the value of the cleanup cost estimates in the Gulf of Mexico to estimate the costs of cleanup in the Arctic 

OCS region because the costs of a spill in the Arctic OCS region are estimated to be much greater on a 

per-barrel basis than for a comparable spill in the Gulf of Mexico.

46 In addition, a spill in the Arctic OCS 

would impact both subsistence hunting and culture and traditions of Alaska Native communities, which 

the Deepwater Horizon oil spill did not have. 

Moreover, this proposed rule would help achieve the National Arctic Strategy goals of protecting the 

unique and sensitive Arctic ecosystems and the culture and traditions of the Native communities. The 

proposed requirements—specifically tailored to the Arctic region—would provide additional clarity 

 

45 By its own account, BP has spent over $14 billion to date in cleanup operations related to the Deepwater Horizon

spill. As explained in this Initial RIA, the costs and other consequences of a major spill in the waters of the Arctic 

OCS likely would be greater than the costs and impacts for a comparable spill in the Gulf of Mexico, where 

response equipment and resources are more readily available than in the Arctic region. 

46 See pages 62 and 63 of the BOEM Case Study for details on the Gulf of Mexico spill containment and clean-up 

cost assumptions. This approach of doubling the GOM cost estimate is consistent with the methodology used to 

estimate natural resource damages in the Beaufort and Chukchi Seas in the BOEM Case Study, which states, “While

doubling of the GOM values may appear arbitrary, BOEM believes that damages from a catastrophic oil spill likely 

are somewhere in-between the Cook Inlet and the GOM per-barrel damages, so doubling the GOM values may 

overstate the damages in the Arctic, although the costs for any particular spill will vary widely.... Labor, materials, 

and transportation drive cleanup costs and each of these will be significantly more expensive in the Arctic.” (BOEM 

Case Study, p. 68).
61

regarding BOEM’s and BSEE’s expectations for the safe and responsible exploration of Arctic resources 

and the specific actions that lessees, owners, and operators must take in order to meet those expectations. 

This additional clarity and specificity would help the oil and gas industry to plan and to conduct 

exploratory drilling more effectively in the Arctic OCS, which, in turn, would result in development of oil 

and gas with lower risk and fewer delays than under the existing rules.

The proposed rule would benefit society and the environment by reducing the probability of incidents 

resulting in oil spills and, if an incident occurs, by reducing the duration and/or severity of the spills. The 

objective of the proposed rule is to ensure safe and responsible oil and gas drilling on the Arctic OCS 

resulting in increased safety for personnel, protection of the marine environment and species, and removal 

of impediments to the Alaska Native subsistence use. The magnitude of these benefits, however, is 

uncertain and highly dependent on the actual reduction in the probability of incidents and the 

effectiveness of stopping or containing a spill already underway. A catastrophic oil spill is characterized 

as a low probability, high consequence event because it is an infrequent event but has large consequences 

when it does occur. For low probability, high consequence events, it is difficult to know with any 

certainty the probability of an event actually occurring, or to determine the reduction in the probability of 

occurrence that a proposed regulation would actually achieve. In addition, the consequences of an oil spill 

depend on several factors, including the type of oil, the amount of oil, the location of the spill, the areal 

distribution of the release, the sensitivity of the ecosystem affected, and the weather, among other factors.

Due to these uncertainties, BOEM and BSEE could not perform a standard cost-benefit analysis to 

estimate the net benefits of the proposed rule.

As discussed above, we conducted a break-even analysis of the proposed rule because of the difficulties 

associated with estimating the benefits of reducing the probability and consequences of low probability, 

high consequence events. For the proposed rule, we estimated a break-even number of avoided days of 

spilled oil if a catastrophic oil spill were to occur. In this section, we describe the data, methods, and 
62

results of the break-even analysis. We also provide a qualitative discussion of the benefits of the proposed 

rule.

a. Data

To estimate the potential consequences of a catastrophic oil spill, we used data from the BOEM Case 

Study to provide the estimated volume of oil (in barrels) and the duration (in days) of a catastrophic spill 

occurring in the Chukchi and Beaufort Seas under high- and low-severity oil spill scenarios. These 

examples are hypothetical outcomes based on expected exploration and drilling on the Arctic OCS.

Exhibit 25 presents the estimates for the volume and duration of a potential catastrophic spill on the 

Arctic OCS.
63

Exhibit 25. Total Volume and Duration of Potential Catastrophic Oil Spills in Arctic OCS

Location

Total Volume of Oil (BBLs) Duration (Days)

Low High Low High

Chukchi Sea 1,400,000 2,200,000 40 75

Beaufort Sea 1,700,000 3,900,000 60 300

To conduct the break-even analysis of the number of avoided days of spilled oil, we collected worst- case 

discharge data from two existing Shell OSRPs. The worst-case discharge data include discharge totals for 

the Chukchi and Beaufort Seas with discharge amounts of 25,000 and 16,000 BBLs per day, respectively.

These estimates do not reflect the expected volume of oil spilled if there were an oil spill but, instead,

define a worst-case scenario for a spill on the Arctic OCS. We used the Shell worst-case discharge 

estimates to estimate the number of avoided days of spilled oil needed to break-even, rather than the 

BOEM Case Study total catastrophic oil spill volume estimates presented in Exhibit 25, because Shell’s 

OSRPs provide daily worst-case discharge estimates. 

Next, we estimated the social cost of a barrel of oil spilled. Using the BOEM Case Study, we divided the 

per-barrel costs into three components: natural resource damages, value of lost hydrocarbons, and 

containment and cleanup costs. Natural resource damages relate to the natural resources on the Arctic 

OCS that would be damaged by an oil spill. The value of the lost hydrocarbons reflects the lost usable oil.

Finally, spill containment and cleanup costs include all the resources (capital and labor) needed to contain 

the spill and clean up the site. These costs are all included in the social cost of a barrel of oil as per the 

directive of OMB Circular A-4, which is to include costs regardless of where, when, or to whom the 

costs accrue.

47

 

47 Using both natural resource damages and containment and cleanup costs is consistent with the natural resource 

damages assessment methods described in the BOEM Case Study. This also accounts for any temporal or spatial 

distribution in the accrual of cleanup costs. For example, the cleanup on the coast may occur at a later time and 

different place than the initial spill. 
64

The BOEM Case Study used a “benefit transfer” method to estimate avoided costs specific to the Arctic 

OCS because no incidents have occurred on the Arctic OCS. Benefit transfer allows for previously 

estimated values to be customized and adapted to match a new context. The method is recommended by 

OMB Circular A-4 as a next best alternative when collecting primary data is not possible. Because we 

have values on catastrophic spills in a nearby region (the Valdez oil spill) and in other regions (the Gulf 

of Mexico (GOM)), we used the results of the BOEM Case Study benefit transfer to provide a next-best 

estimate of the cost of a potential catastrophic oil spill by transferring known values to the Arctic OCS.

The BOEM Case Study developed these costs by first estimating the cost of a barrel of oil spilled for the 

GOM catastrophic spills based on historical data and the cost of a barrel of oil spilled for the Exxon 

Valdez oil spill in Alaska’s Prince William Sound. As noted above, many site-specific characteristics 

influence the severity of an oil spill. The Exxon Valdez oil spill occurred in a highly sensitive region close 

to populated areas that support economic activity, including recreation, tourism, and commercial fishing.

The Chukchi and Beaufort Seas likely would have some similar environmental qualities (although not 

identical) but the northern areas of Alaska do not support the same level of economic activity. For 

example, no significant commercial fishing occurs in the region, and the region supports relatively little

tourism or recreation. In the BOEM Case Study, BOEM explained that the Exxon Valdez created an upper 

bound for a spill occurring in the northern seas of Alaska. In comparison to the Arctic OCS, the GOM 

varies greatly in climate, environment, and economic activity. Because the GOM already supports a 

variety of rigs and oil operations, the region has ready access to labor and capital in the event of an 

incident, thus minimizing the overall cost of an incident. If a spill occurs on the Arctic OCS, resources 

and labor would need to be deployed to the region, which would add to the cost of a cleanup.

To estimate the cleanup and resource costs, the BOEM Case Study doubled the estimated cost for the 

GOM to reach an estimate that was greater than the GOM cost while still being lower than the Exxon 

Valdez cost. Based on regional differences, BOEM determined that doubling the GOM value would be 

the next-best estimate for costs in the Arctic OCS region. We used the natural resource damage cost of 
65

$1,284 per barrel and the cleanup and containment cost of $5,714 per barrel as estimated for the Chukchi 

Sea and Beaufort Sea in the BOEM Case Study. Consistent with the BOEM Case Study, we used the 

$100 value of lost hydrocarbons per barrel, which is the value applied across all regions analyzed in the 

Case Study.

In addition to the per-barrel cost, the BOEM Case Study also estimated subsistence losses and value of 

life and non-fatal injuries for the Arctic OCS. The BOEM Case Study used an $8.5 million value for a 

statistical life (VSL) based on the Regulatory Analysis presented in the 2010 Drilling Safety Rule and 

assumed 8 deaths per incident based on the two historical incidents in the GOM. BOEM assumed an 

injury valued at $45,000 with 10 injuries for a catastrophic blowout. Using the annual local population 

harvests for whales and value per kilogram harvested, the BOEM Case Study estimated the loss of 

subsistence in the Beaufort Sea and Chukchi Sea at $20.9 million and $68.6 million, respectively.48 Using 

historical data from the GOM, the BOEM Case Study estimated the value of life lost and non-fatal injury 

per incident at $68.45 million and used this estimate as a proxy for all regions. The BOEM Case Study 

estimated these costs on a per-incident basis because these costs are not dependent on the volume of oil 

spilled. Exhibit 26 summarizes the cost of a catastrophic oil spill on the Arctic OCS.

Exhibit 26. Cost of a Catastrophic Oil Spill on the Arctic OCS

Cost Per Barrel of Oil Spilled

Cleanup and containment cost $5,714

Natural resource damages $1,284

Value of lost hydrocarbons $100

Total Cost per Barrel of Oil Spilled $7,098

One-time Cost per Spill

Total estimated Chukchi Sea subsistence losses (1.5 years) $68,574,252

Total estimated Beaufort Sea subsistence losses (1.5 Years) $20,850,495

 

48 BOEM notes that subsistence damages capture only a fraction of the cultural damages for Alaska Natives in this 

region. These losses relate to the value of the harvest but fail to capture the cultural value of the region for Alaska 

Natives. The cultural value likely exceeds the market value attached to the subsistence harvest. 
66

Lives lost and non-fatal injuries $68,450,000

One-time Cost per Spill in the Chukchi Sea $137,024,252

One-time Cost per Spill in the Beaufort Sea $89,300,495

Next, we estimated the (quantifiable) total cost of a catastrophic spill by summing the variable costs and 

the one-time costs of a spill. To estimate the variable costs, we multiplied the cost per barrel of oil spilled 

(as shown in Exhibit 26) by the volume of oil spilled under each spill scenario (as shown in Exhibit 25).

49

We summed the variable costs with the one-time costs presented in Exhibit 26 for the Beaufort Sea and 

the Chukchi Sea. Exhibit 27 summarizes the catastrophic oil spill cost at the two locations under the 

high- and low-volume spill cases.

Exhibit 27. Catastrophic Oil Spill Costs ($ millions)

Location

Total Variable Costs

Total OneTime Costs Total Spill Costs

Low High Low/High Low High

A B C D = A + C E = B + C

Chukchi Sea $9,937.2 $15,615.6 $137.0 $10,074.2 $15,752.6

Beaufort Sea $12,066.6 $27,682.2 $89.3 $12,155.9 $27,771.5

Next, using the Shell OSRPs, we estimated the daily cost of an oil spill under the worst-case discharge.

For this aspect of the analysis, we did not include the one-time per-spill costs (as presented in Exhibit 26)

and only included the incremental costs of an additional day of discharge. To estimate the daily cost of a 

spill at each location, we multiplied the barrels of oil spilled per day (as estimated in the Shell OSRP and 

presented in Exhibit 28) by the cost per barrel of oil spilled (as shown in Exhibit 26). Exhibit 28

summarizes this calculation for both the Chukchi and Beaufort Seas.

 

49 For example, for the Chukchi Sea low-volume case, we estimated the total cost of the spill to be the cost per barrel 

of oil multiplied by the number of barrels of oil spilled plus the total per-spill cost ($7,098 × 1,400,000 BBLs + 

$137,024,252). The total cost of the Chukchi low-volume case is, thus, $10,074,224,252. This process is repeated 

for both seas and for the high- and low-volume cases.
67

Exhibit 28. Cost of Oil Spilled Per Day

Location

Barrels of Oil per Day

Cost per Barrel of Oil 

Spilled Cost of Spill per Day

A B C = A × B

Chukchi Sea 25,000 $7,098 $177,450,000

Beaufort Sea 16,000 $7,098 $113,568,000

b. Method

According to our analysis, the total quantifiable cost of a catastrophic spill would be between $10.07

billion and $15.75 billion in the Chukchi Sea and between $12.16 billion and $27.77 billion in the 

Beaufort Sea. We estimated the daily quantifiable cost of a worst-case discharge oil spill at $177.5 million 

for the Chukchi Sea and $113.6 million for the Beaufort Sea. We used the worst-case discharge estimates 

from Shells’ OSRPs to estimate the number of avoided days of spilled oil needed to break-even, rather 

than the BOEM Case Study total catastrophic oil spill volume estimates (as presented in Exhibit 25), 

because the OSRPs provide daily worst-case discharge estimates. In addition, although some provisions 

lower the overall risk of a spill, other provisions focus on a faster containment and cleanup after a spill 

has occurred. We estimated the break-even number of avoided days of spilled oil by dividing the total net 

costs (i.e., costs minus cost savings) of the proposed rule by the per-day cost of spilled oil.

c. Results

Using the estimated discounted costs at 3 and 7 percent and the quantifiable potential benefits (in terms of 

avoided costs of incidents) of the proposed rule, we calculated the break-even number of avoided days of 

spilled oil. This estimate reflects the number of avoided days of spilled oil needed for the proposed rule to 

achieve at least zero net benefits. Any avoided days of spilled oil greater than these break-even points 

result in the proposed rule achieving positive net benefits, should a catastrophic spill occur. We also show 

the estimated total cost of a catastrophic oil spill relative to the total cost of the proposed rule. Exhibit 29

presents the (quantifiable) total cost of a spill and the 10-year cost of the rule.
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Exhibit 29. Total Cost of a Catastrophic Oil Spill Compared to the 10-year Cost of the Rule

Location

Cost of a Spill1

($ millions)

10-year Cost of the Rule

($ millions)

Low High 7% Discounting 3% Discounting

Chukchi Sea $10,074.2 $15,752.6 $1,112 $1,224

Beaufort Sea $12,155.9 $27,771.5 $1,112 $1,224

1.Discounting does not apply to the cost of a spill because it is unknown if and when a spill would occur. 

As presented in Exhibit 29, quantifiable costs of a spill in the Chukchi Sea range from $10.07 billion to 

$15.75 billion and in the Beaufort Sea from $12.16 billion to $27.77 billion. Quantifiable costs of a spill 

are more than the cost of the rule; however, the probability of a spill is very low. A catastrophic spill 

resulting from exploratory drilling on the Arctic OCS is highly unlikely due to the nature of the geology, 

the shallow water depth, and the simplicity of the wells. BOEM used available information to analyze the 

statistical probability of a catastrophic spill. However, due to the limited drilling history on the Arctic 

OCS, projections cannot be made with certainty. At the same time, the unquantifiable nature of many of 

the benefits sought to be achieved through this proposed rule (e.g., protection of the unique Arctic 

ecosystem, natural resources and Alaska Native cultural traditions) make the benefits side of the equation 

equally uncertain, and underestimated. Exhibit 30 presents the results of the break-even analysis for the 

avoided days of spilled oil.

Exhibit 30. Break-even Results: Number of Days of Oil Spill Prevented

Location

Cost of Spill 

per Day ($ 

millions)

10-Year Cost of the Rule

($ millions)

Break-even 

Number of Days

7% 

Discounting 3% Discounting

7% 

Discounting

3% 

Discounting

C = A × B1 D E F = D / C G = E / C

Chukchi Sea $177.5 $1,112 $1,224 6.3 6.9

Beaufort Sea $113.6 $1,112 $1,224 9.8 10.8

1 A, B and C in this exhibit represent the same values as in Exhibit 28.
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As presented in Exhibit 30, over the ten-year cost analysis period, the number of avoided or reduced days 

of a catastrophic oil spill needed to break-even is between 6.3 and 6.9 days for the Chukchi Sea and 9.8

and 10.8 days for the Beaufort Sea. To provide context, the BOEM Case Study estimates that the duration 

of a catastrophic incident in the Chukchi Sea would be between 40 and 75 days and an incident in the 

Beaufort Sea would be between 60 and 300 days. One of the key goals of the proposed SCCE and relief 

rig provisions is to reduce the duration of such a spill should one occur.

BOEM and BSEE believe that this break-even analysis is an appropriate way to evaluate the costs and 

befits of the proposed rule under the circumstances. However, we invite comments on the assumptions, 

data and methods used in this break-even analysis. We also invite comments on whether there is a better 

alternative method for evaluating the costs and benefits.

d. Qualitative Benefits

We based the break-even analyses on the quantifiable avoided consequences of an oil spill, as represented 

by the number of fewer days of a catastrophic oil spill needed to justify the cost of the rule. In addition to 

reducing the quantifiable consequences of a catastrophic oil spill, there are other benefits from the 

proposed rule. A catastrophic spill resulting from exploratory drilling on the Arctic OCS is highly 

unlikely due to the nature of the geology, the shallow water depth, and the simplicity of the wells. Despite 

the low likelihood of a catastrophic spill, the consequences would be severe and warrant efforts to reduce 

the risk further. For example, a catastrophic spill on the Arctic OCS would be very damaging to Alaska 

Natives’ subsistence needs, and a humanitarian disaster for the region, while also potentially impeding 

future exploration and development in the region. In addition, many other non-quantifiable costs, mean 

that a spill of significant magnitude would be devastating to the region. Due to the uncertainty of these 

costs (and the corresponding benefits resulting from the proposed rule’s prevention or minimization of 

those costs), we do not present a quantitative assessment of these costs/benefits and, instead, present a 

qualitative discussion.
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BOEM and BSEE have sought to quantify the benefits of the proposed rule to the extent possible. The 

break-even analysis presented above sought to assess the cost-effectiveness of the provisions of the rule in 

aggregate. Because BOEM and BSEE used a conservative approach in the valuation of an oil spill, the 

identified cost of an oil spill can be considered a lower bound of the true cost to society. Although we 

capture the environmental damage associated with a catastrophic oil spill, the analysis is limited because 

it only considers the environmental amenities that researchers could identify and monetize. Natural 

resource valuation is complex; many factors contribute to how society values a resource, including both 

use and non-use values of the resources. Many use values can be estimated by behavior and market 

transactions (for example, using the harvest value of yields in the Arctic OCS region). Many other use 

values, however, might not be related to a market and are, therefore, difficult to monetize. For example, 

Alaska Native communities place a high value on the cultural amenities related directly to the use of the 

region. Because communities do not trade cultural amenities in markets, we are unable to estimate a direct 

value of these resources.

Non-use values are much harder to estimate; common non-use values include existence values and 

bequest values. Individuals place a value on environmental amenities by knowing that preservation and 

protection of the region exists even if those individuals do not intend to visit the region. Bequest values 

relate to individuals placing a value on the preservation of regions for future generations even if they do 

not intend to use the resource themselves. Capturing these complex values is difficult because they are not 

traded in markets. Because we are unable to monetize all aspects of the consequences of an oil spill, the 

estimate we used captures only a portion of the value to society. Exhibit 31 presents the provisions of the 

proposed rule along with their primary benefits; improving oversight of operations by Federal agencies, 

minimizing natural resource and ecosystem impacts, reducing the risk of a spill, improving containment 

of a spill, and a general benefit.

The objective of the proposed rulemaking is to ensure safe and responsible oil and gas drilling on the 

Arctic OCS, which would result in increased safety for personnel, protection of the marine and coastal
71

environments and species, and removal of impediments to the Alaska Natives’ subsistence use. In 

addition, the proposed rule achieves better coordination among BSEE, BOEM, and other government 

agencies. For example, the information required in proposed Section 550.204 would facilitate interagency 

coordination between DOI and other relevant Federal agencies, as recommended in the DOI “Report to 

the Secretary of the Interior, Review of Shell’s 2012 Alaska Offshore Oil and Gas Exploration Program” 

(available at http://www.doi.gov/news/pressreleases/upload/Shell-report-3-8-13-Final.pdf). 
72

Exhibit 31. Qualitative Benefits by Provision

Provision Primary Benefit

(a) Additional Incident Reporting

Requirements

Improves oversight of 

operations by Federal agencies

(b) Pollution Prevention Requirements Minimizes natural resource 

impacts

(c) Additional Requirements for 

Securing Wells Reduces risk of a spill

(d) Additional BOP Pressure Testing 

Requirements Reduces risk of a spill

(e) Real-time Monitoring 

Requirements Reduces risk of a spill

(f) Additional Information 

Requirements for APDs

Improves oversight of 

operations by Federal agencies

(g) Incorporation of proposed draft 

API RP 2N Reduces risk of a spill

(h) Additional SCCE Requirements Improves containment of a spill

(i) Relief Rig Requirements Improves containment of a spill

(j) Additional Auditing Requirements Improves oversight of 

operations by Federal agencies

(k) Real-time Location Tracking 

Requirements

Improves oversight of 

operations by Federal agencies

(l) IOP Requirements Improves oversight of 

operations by Federal agencies

(m) Planning Information 

Requirements to Accompany EPs

Improves oversight of 

operations by Federal agencies

(n) Industry Familiarization with the 

New Rule General
73

e. Conclusion

The proposed rule would reduce both the overall risk of oil spills on the Arctic OCS and the consequences 

of a spill if one were to occur. We conducted a break-even analysis of the benefits of the proposed rule. In 

addition, we included a qualitative discussion of potential benefits of the proposed rule that could not be 

quantified or monetized. The break-even analysis showed that for the Chukchi Sea, a minimum reduction 

of 6.3 to 6.9 days for a catastrophic oil spill would result in a cost-beneficial rule over the ten-year study 

period. For the Beaufort Sea, we estimated that a minimum reduction of between 9.8 and 10.8 days for a 

catastrophic oil spill would result in a cost-beneficial rule over the ten-year study period. Although the 

benefits of the proposed rule—based primarily on preventing or reducing the duration or severity of 

catastrophic oil spills50—are difficult to quantify, BOEM and BSEE have determined that it is appropriate 

to proceed with this proposed rule.

8. UMRA

This proposed rule would not impose an unfunded Federal mandate on State, local, or tribal governments 

but would, if finalized, create a private-sector mandate that could require expenditures exceeding $100 

million in a single year by offshore oil and gas exploration companies operating on the Arctic OCS. The 

Initial RIA, the initial Regulatory Flexibility Act analysis for this proposed rule, and the proposed rule 

itself address applicable requirements of the UMRA, 2 U.S.C. 1501 et seq. 

Among other things, the proposed rule, the Initial RIA, and/or the initial RFA: 

 

50 “Catastrophic event” is defined in our analysis consistent with the BOEM Case Study, which defines it as “any 

high-volume, long-duration oil spill from a well blow-out, regardless of its cause (e.g. a hurricane, human error, 

terrorism).” See Section 7 for additional details on assumptions about spill duration and magnitude that were 

included in calculating the benefits for the proposed rule. 
74

(1) Identify the provisions of the Federal law (OCSLA and OPA) under which this rule is being 

proposed; 

(2) Includes a quantitative assessment of the anticipated costs to the private sector (i.e., 

expenditures on labor and equipment) of the proposed rule (included in Sections 5 and 6 above); 

and 

(3) Include qualitative and quantitative assessments of the anticipated benefits of the proposed 

rule (included in Section 7 above). 

In addition, because all anticipated expenditures by the private sector analyzed in the Initial RIA and the 

initial RFA analysis would be borne by the offshore oil and gas exploration industry in the Arctic OCS 

Region, the Initial RIA and initial RFA analysis satisfy the UMRA requirement to estimate any 

disproportionate budgetary effects of the proposed rule on a particular segment of the private sector. 

In addition, the Initial RIA describes BOEM’s and BSEE’s consideration of three major regulatory 

alternatives for dealing with the safety and environmental concerns raised by exploration activities on the 

Arctic OCS (included in Section 3 above). BOEM and BSEE have decided to move forward with this 

proposed rule, in lieu of the other alternatives, because those alternatives would not as efficiently or 

effectively address the safety, environmental or sociocultural concerns raised by various stakeholders on 

the Arctic OCS or achieve the objectives of this proposed rule.

BOEM and BSEE have determined that the proposed rule would not impose any unfunded mandates or 

any other requirements on State, local, or tribal governments; thus, the proposed rule would not have 

disproportionate budgetary effects on such governments. Assuming, however, that the proposed rule 

might result in budgetary effects on the Arctic OCS area, BOEM and BSEE have determined that 

accurately estimating such effects is not reasonably feasible. Because the proposed rule would not 

impose any requirements on any entities, other than companies engaged in Arctic OCS exploration 

activities, any budgetary effects in that area would be at least secondary results of actions or decisions 
75

taken by regulated (or unregulated) entities, based on a variety of circumstances (such as the price of oil, 

each entities’ overall financial health, and the prospects of success of any exploratory drilling) at the time.

Because each of those factors is variable and unpredictable, it is not feasible to estimate how those factors 

would affect an entity’s future decisions, or what impacts, if any, such decisions could have on future 

regional budgets.

Similarly, BOEM and BSEE have determined that accurately estimating the potential effects, if any, of 

the proposed rule on the national economy (e.g., productivity, economic growth, employment, 

international competitiveness) is not reasonably feasible. The proposed rule, if finalized, would affect 

only exploratory drilling activities on the Arctic OCS, and any potential impact on the national economy 

would depend on individual business decisions made by regulated entities (e.g., whether or not to hire 

new employees). Moreover, any such decisions would likely be either local or regional in effect and 

unlikely to have any significant national costs.