9916 Federal Register / Vol. 80, No. 36 / Tuesday, February 24, 2015 / Proposed Rules 

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 

[Docket ID: BSEE–2013–0011; 15XE1700DX 

EX1SF0000.DAQ000 EEEE500000] 

RIN 1082–AA00 

Oil and Gas and Sulphur Operations 

on the Outer Continental Shelf— 

Requirements for Exploratory Drilling 

on the Arctic Outer Continental Shelf 

AGENCY: Bureau of Safety and 

Environmental Enforcement (BSEE); 

Bureau of Ocean Energy Management 

(BOEM), Interior. 

ACTION: Proposed rule. 

SUMMARY: The Department of the 

Interior (DOI), acting through BOEM 

and BSEE, proposes to revise and add 

new requirements to regulations for 

exploratory drilling and related 

operations on the Outer Continental 

Shelf (OCS) seaward of the State of 

Alaska (Alaska OCS). The Alaska OCS 

has the potential to be an integral part 

of the Nation’s ‘‘all of the above’’ 

domestic energy strategy. This proposed 

rule focuses solely on the OCS within 

the Beaufort Sea and Chukchi Sea 

Planning Areas (Arctic OCS). The Arctic 

region is characterized by extreme 

environmental conditions, geographic 

remoteness, and a relative lack of fixed 

infrastructure and existing operations. 

The proposed rule is designed to ensure 

safe, effective, and responsible 

exploration of Arctic OCS oil and gas 

resources, while protecting the marine, 

coastal, and human environments, and 

Alaska Natives’ cultural traditions and 

access to subsistence resources. 

DATES: Submit comments by April 27, 

2015. BOEM and BSEE may not fully 

consider comments received after this 

date. You may submit comments to the 

Office of Management and Budget 

(OMB) on the information collection 

burden in this proposed rule by March 

26, 2015. The deadline for comments on 

the information collection burden does 

not affect the deadline for the public to 

comment to BOEM and BSEE on the 

proposed regulations. 

ADDRESSES: You may submit comments 

on the rulemaking by any of the 

following methods. For comments on 

this proposed rule, please use 

Regulation Identifier Number (RIN) 

1082–AA00 in your message. For 

comments specifically related to the 

draft Environmental Assessment 

conducted under the National 

Environmental Policy Act of 1969 

(NEPA), please refer to NEPA in the 

heading of your message. See also, 

Public Availability of Comments under 

Procedural Matters. 

• Federal eRulemaking Portal: http:// 

www.regulations.gov. In the Search box, 

enter BSEE–2013–0011, then click 

search. Follow the instructions to 

submit public comments and view 

supporting and related materials 

available for this rulemaking. BOEM 

and BSEE will post all submitted 

comments. 

• Mail or hand-carry comments to the 

DOI, BSEE: Attention: Regulations and 

Standards Branch, 381 Elden Street, 

HE3314, Herndon, Virginia 20170–4817. 

Please reference ‘‘Oil and Gas and 

Sulphur Operations on the Outer 

Continental Shelf—Requirements for 

Exploratory Drilling on the Arctic Outer 

Continental Shelf,’’ 1082–AA00 in your 

comments, and include your name and 

return address. 

• Send comments on the information 

collection of this rule to: Interior Desk 

Officer 1082–AA00, Office of 

Management and Budget; 202–395–5806 

(fax); email: OIRA_Submission@

omb.eop.gov. Please also send copies to 

BSEE by one of the means previously 

described. 

FOR FURTHER INFORMATION CONTACT: 

Mark E. Fesmire, BSEE, Alaska Regional 

Office, mark.fesmire@bsee.gov, (907) 

334–5300; John Caplis, BSEE, Oil Spill 

Response Division, john.caplis@

bsee.gov, (703) 787–1364; or David 

Johnston, BOEM, Alaska Regional 

Office, david.johnston@boem.gov, (907) 

334–5200. To see a copy of either 

information collection request 

submitted to OMB, go to http://

www.reginfo.gov (select Information 

Collection Review, Currently Under 

Review). 

SUPPLEMENTARY INFORMATION: 

Executive Summary 

Although there is currently a 

comprehensive OCS oil and gas 

regulatory program, DOI engagement 

with stakeholders reveals the need for 

new and revised regulatory measures for 

exploratory drilling conducted by 

floating drilling vessels and ‘‘jackup 

rigs’’ (collectively known as mobile 

offshore drilling units or MODUs) on 

the Arctic OCS. The United States (U.S.) 

Arctic region, as recognized by the U.S. 

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 

specifically tailored to the operational 

and environmental conditions of the 

Arctic OCS. After considering the input 

provided by various 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 would take into account 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, who 

rely on the Arctic’s resources for 

subsistence and cultural traditions. 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 a number 

of important issues and objectives, 

including ensuring that each operator: 

1. Designs and conducts exploration 

programs in a manner suitable for Arctic 

OCS conditions; 

2. Develops an integrated operations 

plan (IOP) that would address all phases 

of its 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. Has access to, and the ability to 

promptly deploy, Source Control and 

Containment Equipment (SCCE) while 

drilling below, or working below, the 

surface casing; 

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Federal Register / Vol. 80, No. 36 / Tuesday, February 24, 2015 / Proposed Rules 9917 

4. Has 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. Has the capability to predict, track, 

report, and respond to ice conditions 

and adverse weather events; 

6. Effectively manages and oversees 

contractors; and 

7. Develops and implements an Oil 

Spill Response Plan (OSRP) that is 

designed and executed in a manner 

suitable for the unique Arctic OCS 

operating environment and has 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 in order to decrease the 

possibility of an incident occurring. The 

requirements in the proposed rule are 

also designed to ensure that those plans 

would be executed in a safe and 

environmentally protective manner 

despite the challenges presented by the 

Arctic. 

Table of Contents 

List of Acronyms and References 

I. Introduction 

A. Resource Potential 

B. Integrated Arctic Management 

C. Overview of Proposed Regulations 

D. Potential Costs and Benefits of 

Proposed Rule 

II. Background 

A. Statutory and Regulatory Overview 

B. Factual Overview of the Alaska OCS 

Region 

C. Partner and Stakeholder Engagement 

in Preparation for This Proposed Rule 

D. Expected Benefits Justifying Potential 

Costs 

III. Proposed Regulations for Arctic OCS 

Exploratory Drilling 

A. Measures That Address 

Recommendations 

B. IOP Requirement 

C. SCCE and Relief Rig Capabilities 

D. Planning for the Variability and 

Challenges of the Arctic OCS Conditions 

E. Arctic OCS Oil Spill Response 

Preparedness 

F. Reducing Pollution From Arctic OCS 

Exploratory Drilling Operations 

G. Oversight, Management, and 

Accountability of Operations and 

Contractor Support 

IV. Section-By-Section Discussion 

A. Definitions (§§ 250.105, 254.6, and 

550.105) 

B. Additional Regulations Proposed by 

BOEM 

C. Additional Regulations Proposed by 

BSEE 

D. Arctic Exploratory Drilling Process 

Flowchart 

V. Conclusion 

VI. Procedural Matters 

A. Regulatory Planning and Review (E.O. 

12866 and E.O. 13563) 

B. E.O. 12866 

C. E.O. 13563 

D. Regulatory Flexibility Act 

E. Unfunded Mandates Reform Act of 

1995 (UMRA) 

F. Takings Implication Assessment 

G. Federalism (E.O. 13132) 

H. Civil Justice Reform (E.O. 12988) 

I. Consultation With Indian Tribes (E.O. 

13175) 

J. E.O. 12898 

K. Paperwork Reduction Act (PRA) 

L. National Environmental Policy Act of 

1969 (NEPA) 

M. Data Quality Act 

N. Effects on the Nation’s Energy Supply 

(E.O. 13211) 

O. Clarity of Regulations 

P. Public Availability of Comments 

LIST OF ACRONYMS AND REFERENCES

60-Day report 

Report to the Secretary of the Interior, review 

of Shell’s 2012 Alaska offshore oil and gas 

exploration program 

MODU Mobile offshore drilling units 

AIS ............................... Automatic Identification System ...................... NARA ......................... National Archives and Records Administration. 

Alaska OCS ................. OCS Seaward of the State of Alaska ............. National Arctic Strategy.President’s National Strategy for the Arctic 

Region issued May 2013. 

ANCSA ........................ Alaska Native Claims Settlement Act ............. NEPA .......................... National Environmental Policy Act of 1969. 

APD ............................. Application for Permit to Drill .......................... NOAA ......................... National Oceanic and Atmosphere Administration. 

API ............................... American Petroleum Institute .......................... NPDES ....................... National Pollutant Discharge Elimination System. 

APM ............................. Application for Permit to Modify ...................... OCS ............................ Outer Continental Shelf. 

Arctic OCS ................... OCS within the Beaufort Sea and Chukchi 

Sea Planning Areas.

OCSLA ....................... Outer Continental Shelf Lands Act. 

ASP ............................. Audit Service Provider .................................... OMB ........................... Office of Management and Budget. 

BOEM .......................... Bureau of Ocean Energy Management .......... OPA ............................ Oil Pollution Act of 1990. 

BOP ............................. Blowout Preventer ........................................... OSRP ......................... Oil Spill Response Plan. 

BP ................................ BP Exploration (Alaska), Inc. .......................... PPCS .......................... Pre-Positioned Capping Stack. 

BSEE ........................... Bureau of Safety and Environmental Enforcement.PRA ............................ Paperwork Reduction Act. 

CAP ............................. Corrective Action Plan .................................... RFA ............................ Regulatory Flexibility Act. 

CFR ............................. Code of Federal Regulations .......................... RIA ............................. Regulatory Impact Analysis. 

CWA ............................ Clean Water Act .............................................. RIN ............................. Regulation Identifier Number. 

DOCD .......................... Development Operations Coordination Documents.ROV ............................ Remotely Operated Vehicle. 

DOI .............................. Department of the Interior ............................... RP .............................. Recommended Practice. 

DPP ............................. Development and Production Plans ............... SCCE ......................... Source Control and Containment Equipment. 

EA ................................ Environmental Assessment ............................ Secretary .................... Secretary of the Interior. 

E.O. ............................. Executive Order .............................................. SEMS ......................... Safety and Environmental Management Systems. 

EP ................................ Exploration Plan .............................................. SIDs ............................ Shut-in Devices. 

EPA ............................. Environmental Protection Agency ................... UMRA ......................... Unfunded Mandates Reform Act of 1995. 

ESA ............................. Endangered Species Act ................................ U.S. ............................ United States. 

IC ................................. Information Collection ..................................... USCG ......................... U.S. Coast Guard. 

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9918 Federal Register / Vol. 80, No. 36 / Tuesday, February 24, 2015 / Proposed Rules 

LIST OF ACRONYMS AND REFERENCES—Continued 

60-Day report 

Report to the Secretary of the Interior, review 

of Shell’s 2012 Alaska offshore oil and gas 

exploration program 

MODU Mobile offshore drilling units 

ICAS ............................ Inupiat Community of the Arctic Slope ........... USFWS ...................... U.S. Fish and Wildlife Service. 

Initial RIA ..................... Initial Regulatory Impact Analysis ................... WCD ........................... Worst-Case Discharge. 

IOP .............................. Integrated Operations Plan ............................. Working Group ........... Interagency Working Group on Coordination 

of Domestic Energy Development and Permitting in Alaska. 

ISO .............................. International Organization for Standardization.

I. Introduction 

The Arctic region is known for its oil 

and gas resource potential, its thriving 

and diverse ecosystems, and the Alaska 

Native communities who rely on the 

Arctic’s resources for subsistence and 

cultural traditions. The Arctic region is 

also 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. 

In May 2013, President Obama issued 

a document entitled, ‘‘National Strategy 

for the Arctic Region (National Arctic 

Strategy).’’ The President affirmed that 

emerging economic opportunities exist 

in the region, but that ‘‘ . . . we must 

exercise responsible stewardship, using 

an integrated management approach and 

making decisions based on the best 

available information, with the aim of 

promoting healthy, sustainable, and 

resilient ecosystems over the long 

term.’’ 

In keeping with the Nation’s 

comprehensive ‘‘all of the above’’ 

energy strategy to continue to expand 

safe and responsible domestic energy 

production, the National Arctic Strategy 

is intended, among other things, to 

‘‘reduce our reliance on imported oil 

and strengthen our Nation’s energy 

security’’ by working with stakeholders 

to enable ‘‘environmentally responsible 

production of oil and natural gas.’’ To 

provide responsible stewardship of the 

Arctic’s environment and resources, the 

National Arctic Strategy emphasizes the 

need for integrated and balanced 

management techniques. 

Furthermore, the National Arctic 

Strategy acknowledges the potential 

international implications of Arctic oil 

and gas activities for ‘‘other Arctic states 

and the international community as a 

whole.’’ The U.S. has committed to do 

its part to ‘‘keep the Arctic region 

prosperous, environmentally 

sustainable, operationally safe, secure, 

and free of conflict[.]’’ One primary 

objective outlined in the 

implementation plan for the National 

Arctic Strategy is to ‘‘reduce the risk of 

marine oil pollution while increasing 

global capabilities for preparedness and 

response to oil pollution incidents in 

the Arctic.’’ (http://

www.whitehouse.gov/sites/default/files/

docs/implementation_plan_for_the_

national_strategy_for_the_arctic_region_

-_fi....pdf). The National Arctic Strategy 

is an example of the types of action the 

U.S. is taking to implement its 

obligations under international 

agreements, such as the Arctic Council’s 

Agreement on Cooperation on Marine 

Oil Pollution Preparedness and 

Response in the Arctic (available at: 

www.arctic-council.org/eppr/agreementon-cooperation-on-marine-oil-pollutionpreparedness-and-response-in-thearctic/). 

A. Resource Potential 

The Alaska OCS region is estimated to 

contain a vast amount of undiscovered, 

technically recoverable oil and gas. 

According to BOEM’s 2011 Assessment 

of Undiscovered Technically 

Recoverable Oil and Gas Resources of 

the Nation’s Outer Continental Shelf 

(mean estimates available at: 

www.boem.gov/Oil-and-Gas-EnergyProgram/Resource-Evaluation/ResourceAssessment/2011_National_

Assessment_Factsheet-pdf.aspx), there 

are approximately 23.6 billion barrels of 

technically recoverable oil and about 

104.4 trillion cubic feet of technically 

recoverable natural gas in the Beaufort 

Sea and Chukchi Sea Planning Areas 

combined. Most of the Alaska OCS 

resource potential is located off the 

Arctic coast within the Chukchi Sea and 

Beaufort Sea Planning Areas. This 

resource potential has received 

considerable attention from the oil and 

gas industry and the U.S. government, 

and has precipitated the sale of 

hundreds of leases and the initiation of 

subsequent exploration activities. The 

Alaska OCS region, particularly the 

Beaufort Sea and Chukchi Sea Planning 

Areas, has the potential to be an integral 

part of the ‘‘all of the above’’ domestic 

energy strategy articulated in the 

National Arctic Strategy. 

B. Integrated Arctic Management 

As ocean and seasonal conditions 

continue to change in the Arctic, there 

will be an increasing number of 

stakeholders vying for access to the 

Arctic OCS and the waters above it. 

Both commercial and recreational 

activities are increasing as more areas of 

water open up for longer periods of time 

due to the increase of melting sea ice. 

The decrease in summer sea ice raises 

legitimate concerns regarding changes to 

the environment and the Arctic 

resources that Alaska Natives depend on 

for survival and cultural traditions. 

Consistent with the Outer Continental 

Shelf Lands Act (OCSLA), BOEM and 

BSEE, the Bureaus responsible for 

managing oil and gas resources on the 

Arctic OCS, are proposing regulations 

that take into account the needs of the 

multiple users who have an interest in 

the future of the U.S. Arctic region (see 

43 U.S.C. 1332(6)). 

The U.S. has maintained a 

longstanding interest in the orderly 

development of oil and gas resources on 

the Arctic OCS, while also seeking to 

ensure the protection of its environment 

and communities. The U.S. has 

proceeded cautiously to ensure that 

laws, regulations, and policies 

concerning Arctic OCS oil and gas 

development are created and 

implemented based on a thorough 

examination of the multiple factors at 

play in the unique Arctic environment. 

BOEM and BSEE have conducted 

extensive research on potential oil and 

gas activities in the Arctic OCS in 

anticipation of operations (see, e.g., 

www.bsee.gov/Technology-andResearch/Technology-AssessmentPrograms/Categories/Arctic-Research/), 

and have also evaluated the potential 

environmental effects of such activities 

(see, e.g., http://www.boem.gov/

akstudies/). These research projects, 

along with other initiatives, form the 

basis for the most recent National 

policies and directives regarding Alaska 

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Federal Register / Vol. 80, No. 36 / Tuesday, February 24, 2015 / Proposed Rules 9919 

1Tribes, State and local governments, and Federal 

agencies are ‘‘partners.’’ ‘‘Stakeholders’’ are nongovernmental organizations, industry, and other 

entities. 

2This proposed rule uses and defines terms that 

may be similar to terms used in other programs by 

other Federal agencies; however, the terms and 

definitions used in this proposed rule are intended 

to apply only to the BSEE and BOEM regulatory 

programs covered by this proposed rule, unless 

otherwise noted. 

OCS oil and gas development, all of 

which have guided this proposed rule. 

Coordinating the future uses of the 

Arctic region will require integrated 

action between and among Federal, 

state, and tribal governmental entities. 

On July 15, 2011, President Obama 

signed Executive Order (E.O.) 13580, 

establishing an Interagency Working 

Group on Coordination of Domestic 

Energy Development and Permitting in 

Alaska (Working Group), chaired by the 

Deputy Secretary of DOI. The Working 

Group is composed of representatives 

from the DOI, Department of Defense, 

Department of Commerce, Department 

of Agriculture, Department of Energy, 

Department of Homeland Security, the 

Environmental Protection Agency 

(EPA), and the Office of the Federal 

Coordinator for Alaska Natural Gas 

Transportation Projects. It is charged 

with facilitating ‘‘coordinated and 

efficient domestic energy development 

and permitting in Alaska while ensuring 

that all applicable [health, safety, and 

environmental protection] standards are 

fully met’’ (E.O. 13580, sec. 1). 

The Working Group was involved in 

coordinating Federal regulatory and 

oversight efforts for the 2012 Alaska 

OCS drilling season and played an 

important role in BOEM’s and BSEE’s 

reviews of plans and permits for Shell’s 

2012 operations. The Working Group’s 

report entitled, ‘‘Managing for the 

Future in a Rapidly Changing Arctic, A 

Report to the President’’ (March 2013), 

was the result of substantial 

collaboration and has also played a 

significant role in shaping U.S. Arctic 

policies. 

C. Overview of Proposed Regulations 

Although there is currently a 

comprehensive OCS oil and gas 

regulatory program, DOI engagement 

with partners and stakeholders 1 reveals 

the need for new and enhanced 

regulatory measures for Arctic OCS 

exploratory drilling by MODUs. For 

purposes of this rulemaking, exploratory 

drilling is considered to be ‘‘[a]ny 

drilling conducted for the purpose of 

searching for commercial quantities of 

oil, gas, and sulphur, including the 

drilling of any additional well needed to 

delineate any reservoir to enable the 

lessee to decide whether to proceed 

with development and production’’ (30 

CFR 250.105 and 30 CFR 550.105 (one 

of the definitions of ‘‘exploration’’)).2

This proposed rule focuses on Arctic 

OCS exploratory drilling activities that 

use MODUs (e.g., jack-ups and anchored 

drillships) and related operations during 

the Arctic open-water drilling season 

(generally late June to early November). 

After the requirements for exploratory 

drilling are finalized and applied to 

those activities, DOI will be able to 

assess whether it should apply similar 

requirements to development drilling. 

BOEM and BSEE will then be in a 

position to consider developing 

requirements appropriate for 

development drilling activities and 

publish a rulemaking for public notice 

and comment in the Federal Register. 

The requirements may be the same as 

the final requirements for exploratory 

drilling, or BOEM and BSEE may 

modify these requirements. 

The Arctic region is known for its 

challenging environmental conditions, 

geographic remoteness, and relative lack 

of existing infrastructure. This proposed 

rule builds on and would codify input 

received from partners and 

stakeholders, key components of Shell’s 

2012 Arctic exploratory drilling 

program, as well as the additional 

measures DOI required to ensure Shell’s 

drilling operations were conducted 

safely. 

Though its actual drilling operations 

were conducted without incident, Shell 

experienced a number of challenges 

during its 2012 exploratory drilling 

program. In 2013, DOI released a 

‘‘Report to the Secretary of the Interior, 

Review of Shell’s 2012 Alaska Offshore 

Oil and Gas Exploration Program’’ (60- 

Day Report) (available at: http://

www.doi.gov/news/pressreleases/

upload/Shell-report-3-8-13-Final.pdf). 

The 60-Day Report identified a number 

of lessons learned and recommended 

practices to ensure future Arctic oil and 

gas exploration activities continue to be 

carried out in a safe and responsible 

manner. 

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 

specifically tailored to the operational 

and environmental conditions of the 

Arctic OCS. Arctic OCS operations can 

be complex, and there are challenges 

and operational risks throughout every 

phase of an exploratory drilling 

program. Experience gained during the 

2012 Arctic drilling season has led 

BOEM and BSEE staff to conclude that 

enhanced and more specific 

requirements can help ensure that oil 

and gas activities in the Arctic OCS are 

conducted in a safe and 

environmentally responsible manner. 

After considering the input provided by 

various stakeholders and DOI’s direct 

experience from Shell’s 2012 Arctic 

operations, BOEM and BSEE have 

concluded that additional exploratory 

drilling regulations are necessary and 

appropriate as a part of the Arctic OCS 

oil and gas regulatory framework. 

This proposed rule is a combination 

of prescriptive and performance-based 

requirements that address a number of 

important issues and objectives, 

including, but not limited to, ensuring 

that operators: 

1. Design and conduct exploration 

programs in a manner suitable for Arctic 

OCS Conditions (e.g., using equipment 

and processes that are capable of 

performing effectively and safely under 

extreme weather and sea conditions and 

in remote locations with relatively 

limited infrastructure); 

2. Develop an 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 EP; 

3. Have access to, and the ability to 

promptly deploy, SCCE while drilling 

below or working below the surface 

casing; 

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 OSRPs that 

are designed and executed in a manner 

suitable for the unique Arctic OCS 

operating environment and that describe 

the availability of the necessary 

equipment, training, and personnel for 

oil spill response on the Arctic OCS. 

D. Potential Costs and Benefits of 

Proposed Rule 

The Initial Regulatory Impact 

Analysis (RIA) for this proposed rule 

estimates that, if implemented as 

proposed, the new regulations would 

result in economic costs ranging from 

$1.1 to 1.2 billion (at discount rates of 

7 percent and 3 percent, respectively) 

over 10 years. The above estimated cost 

range reflects the increase in costs over 

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9920 Federal Register / Vol. 80, No. 36 / Tuesday, February 24, 2015 / Proposed Rules 

the baseline costs. As discussed in part 

VI.B.3, the baseline is calculated by 

estimating the costs associated with 

current regulatory requirements and 

industry standards. In general, this 

includes the requirements imposed by 

DOI during the 2012 drilling season. 

However, even though DOI required the 

availability of a relief rig in 2012, we 

have conservatively chosen not to 

include the costs of staging a standby 

relief rig in the baseline. Although 

BOEM and BSEE expect that over time, 

as the number of operating rigs on the 

Arctic OCS increases, operators will use 

a second operating rig as a relief rig, in 

lieu of a dedicated standby relief rig, we 

have included the capital and activity 

costs for a standby rig for the first two 

years (2015–2016) of the 10-year time 

period in the economic costs of the 

proposed rule. 

While the economic and other 

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 it is 

appropriate to proceed with this 

proposal. Although the probability of a 

catastrophic oil spill is low, the 

Deepwater Horizon oil spill 

demonstrated that even such low 

probability events can have devastating 

economic and environmental results 

when they occur. The benefits of the 

proposed rule include reducing such 

risks associated with Arctic offshore 

operations. 

Reducing the risks of Arctic offshore 

operations is particularly important 

because of the unique significance to 

Alaska Natives of the fish and marine 

mammals in the lands and waters 

around the Arctic OCS; those resources 

are critical components of the Alaska 

Natives’ livelihood, and they rely on 

fishing and hunting for traditional 

cultural purposes and for subsistence. 

Similarly, many other Americans place 

a very high value on protecting the 

health of the ecosystem, including the 

sensitive environment and wildlife, of 

this largely frontier area. Thus, the 

impact of a catastrophic oil spill, while 

a remote possibility, would have 

extremely high cultural and societal 

costs, and prevention of such a 

catastrophe would have 

correspondingly high cultural and 

societal benefits. 

The proposed requirements— 

specifically tailored to the Arctic OCS— 

would provide additional specificity 

regarding BOEM’s and BSEE’s 

expectations for safe and responsible 

development of Arctic resources and 

would outline the particular actions that 

lessees, owners and operators must take 

in order to meet those expectations. 

BSEE and BOEM do not anticipate that 

these proposed requirements, or their 

associated costs, would prevent lessees 

and operators from conducting 

exploratory drilling on their leases. In 

fact, the additional clarity and 

specificity provided by the proposed 

rule should help the oil and gas 

industry to plan better and to more 

effectively conduct exploratory drilling 

on the Arctic OCS, which in turn should 

result in development and production of 

oil and gas with lower risk and fewer 

delays than under the current rules. 

Since the potential economically 

recoverable oil and gas resources from 

the Arctic OCS are abundant, as 

discussed later in this proposed rule, 

the positive impact of such production 

on U.S. energy independence and 

energy security could be substantial. 

Thus, this proposed rule would help 

achieve the National Arctic Strategy 

goals of protecting the unique and 

sensitive Arctic ecosystems, as well as 

the subsistence, culture and traditions 

of the Alaska Native communities, 

while reducing reliance on imported oil 

and strengthening National energy 

security. 

II. Background 

A. Statutory and Regulatory Overview 

1. Outer Continental Shelf Lands Act 

(OCSLA) 

The OCSLA, 43 U.S.C. 1331 et seq., 

was first enacted in 1953, and 

substantially amended in 1978, when 

Congress established a National policy 

of making the OCS ‘‘available for 

expeditious and orderly development, 

subject to environmental safeguards, in 

a manner which is consistent with the 

maintenance of competition and other 

National needs’’ (43 U.S.C. 1332(3)). In 

addition, Congress emphasized the need 

to develop OCS mineral resources in a 

safe manner ‘‘by well-trained personnel 

using technology, precautions, and 

techniques sufficient to prevent or 

minimize the likelihood of blowouts, 

loss of well control, fires, spillages, 

physical obstruction to other users of 

the waters or subsoil and seabed, or 

other occurrences which may cause 

damage to the environment or to 

property, or endanger life or health’’ (43 

U.S.C. 1332(6)). The Secretary of the 

Interior (Secretary) administers the 

OCSLA’s provisions relating to the 

leasing of the OCS and regulation of 

mineral exploration and development 

operations on those leases. The 

Secretary is authorized to prescribe 

‘‘such rules and regulations as may be 

necessary to carry out [OCSLA’s] 

provisions . . . and may at any time 

prescribe and amend such rules and 

regulations as [s]he determines to be 

necessary and proper in order to 

provide for the prevention of waste and 

conservation of the natural resources of 

the [OCS] . . .’’ which ‘‘shall, as of their 

effective date, apply to all operations 

conducted under a lease issued or 

maintained under the provisions of 

[OCSLA]’’ (43 U.S.C. 1334(a)). 

Prior to commencing exploration for 

oil and gas on an OCS lease tract, the 

statute and BOEM regulations require 

lessees to submit an EP to the Secretary 

for approval (43 U.S.C. 1340(c)(1); 30 

CFR 550.201(a)). An EP must include 

information such as a schedule of 

anticipated exploration activities, 

equipment to be used, the general 

location of each well to be drilled, and 

any other information deemed pertinent 

by the Secretary (43 U.S.C. 1340(c)(3); 

30 CFR 550.211 through 550.228)). 

However, approval of an EP does not 

automatically permit the lessee to 

proceed with exploratory drilling. The 

lessee must submit to the Secretary an 

Application for Permit to Drill (APD) 

which must be approved before a lessee 

may drill a well (43 U.S.C. 1340(d); 30 

CFR 250.410). 

The Secretary delegated most of the 

responsibilities under the OCSLA to 

BOEM and BSEE, both of which are 

charged with administering and 

regulating aspects of the Nation’s OCS 

oil and gas program. BOEM and BSEE 

work to promote safety, protect the 

environment, and conserve offshore 

resources through vigorous regulatory 

oversight. BOEM manages the 

development of the Nation’s offshore 

energy resources in an environmentally 

and economically responsible way. 

BOEM’s functions include leasing; 

exploration, development and 

production plan administration; 

environmental analyses to ensure 

compliance with NEPA; environmental 

studies; resource evaluation; economic 

analysis; and management of the OCS 

renewable energy program. BSEE 

performs offshore regulatory oversight 

and enforcement to ensure safety and 

environmentally sound performance 

during operations, and the conservation 

of offshore resources, by, among other 

things, evaluating drilling permits, and 

conducting inspections to ensure 

compliance with laws, regulations, lease 

terms, and approved plans and permits. 

BOEM evaluates EPs, and BSEE 

evaluates APDs, to determine whether 

the operator’s proposed activities meet 

the OCSLA’s standards and each 

Bureau’s regulations governing offshore 

exploration. The regulatory 

requirements include, but are not 

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limited to, determining whether the 

proposed drilling operation: 

i. Conforms to OCSLA, as amended, 

its applicable implementing regulations, 

lease provisions and stipulations, and 

other applicable laws; 

ii. Is safe; 

iii. Conforms to sound conservation 

practices and protects the rights of the 

U.S. and mineral resources of the OCS; 

iv. Does not unreasonably interfere 

with other uses of the OCS; and 

v. Does not cause undue or serious 

harm or damage to the human, marine, 

or coastal environments (30 CFR 

250.101 and 250.106; 30 CFR 550.101 

and 550.202). 

Based on these evaluations, BOEM 

and BSEE will approve the lessee’s (or 

operator’s) EP and APD, require the 

lessee (or operator) to modify its 

submissions, or disapprove the EP or 

APD (30 CFR 250.410; 30 CFR 550.233). 

2. The Oil Pollution Act of 1990 (OPA) 

and Clean Water Act (CWA) 

Congress passed the OPA, 33 U.S.C. 

2701 et seq., following the Exxon Valdez 

oil spill. The OPA amended the CWA, 

33 U.S.C. 1251 et seq., by, among other 

things, adding OSRP provisions for 

offshore facilities. The OPA provides for 

prompt federally coordinated responses 

to offshore oil spills and for 

compensation of spill victims. It also 

calls for the issuance of regulations 

prohibiting owners and operators of 

offshore facilities from operating or 

handling, storing, or transporting oil 

until: 

i. They have prepared and submitted 

‘‘a plan for responding, to the maximum 

extent practicable, to a worst case 

discharge, and to a substantial threat of 

such a discharge, of oil . . .;’’ 

ii. The plan ‘‘has been approved by 

the President;’’ and 

iii. The ‘‘facility is operating in 

compliance with the plan’’ (OPA 

§ 4202(a), codified at 33 U.S.C. 

1321(j)(5)(A)(i) and (F)(i)–(ii)). 

E.O. 12777 (October 18, 1991) 

authorized the Secretary to carry out the 

functions of 33 U.S.C. 1321(j)(5) and 

(j)(6)(A). This includes the promulgation 

of regulations governing the obligation 

to prepare and submit OSRPs, the 

review and approval of OSRPs, and the 

periodic verification of spill response 

capabilities related to these plans. Those 

applicable regulations are administered 

by BSEE and are found at 30 CFR parts 

250 and 254. E.O. 12777 also authorized 

the Secretary to implement 33 U.S.C. 

1321(j)(1)(C), which provides for the 

issuance of regulations ‘‘establishing 

procedures, methods, and equipment 

and other requirements for equipment to 

prevent discharges of oil and hazardous 

substances from . . . offshore facilities, 

and to contain such discharges. . . .’’ 

B. Factual Overview of the Alaska OCS 

Region 

1. The Arctic OCS Oil and Gas Resource 

Potential Has Attracted Significant 

Attention Over the Past Three Decades 

There has been a renewed interest in 

the oil and gas potential of the Alaska 

OCS since the first exploratory wells 

were drilled in the late 1970s. The 

majority of exploratory drilling north of 

the Arctic Circle has occurred where the 

greatest oil and gas resource potential 

exists, namely the Beaufort Sea and 

Chukchi Sea Planning Areas (defined in 

this proposed rule as the Arctic OCS). 

A total of 30 exploratory wells have 

been drilled on the Beaufort OCS since 

the first Federal OCS leases were 

offered, and more wells have been 

drilled beneath the near-shore Beaufort 

Sea under the jurisdiction of the State 

of Alaska (see BOEM Alaska Region 

Web site at: http://www.boem.gov/

About-BOEM/BOEM-Regions/AlaskaRegion/Historical-Data/Index.aspx). The 

Chukchi Sea Planning Area has a more 

limited history of leasing and 

exploration. Only a total of five 

exploratory wells have been drilled (see 

BOEM Alaska Region Web site at: 

www.boem.gov/About-BOEM/BOEMRegions/Alaska-Region/Historical-Data/

Index.aspx) and no site was considered 

commercially viable for development 

during that time. 

There have been only three 

exploratory wells drilled on the Arctic 

OCS since 1994—the 2003 exploratory 

well near Prudhoe Bay in the Beaufort 

Sea and Shell’s two ‘‘top hole’’ wells 

drilled in 2012 (see BOEM Assessment 

of Undiscovered Technically 

Recoverable Oil and Gas Resources of 

the Nation’s Outer Continental Shelf 

(2011)). 

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3BP has transferred its interests in the Northstar 

project to Hilcorp. Hilcorp is now the operator of 

that project. 

Except for the Northstar project, 

operated by BP Exploration (Alaska), 

Inc. (BP) from State submerged lands in 

the Beaufort Sea, no production has yet 

resulted from any of the leases.3

There are currently no active Alaska 

OCS leases located anywhere outside of 

the Beaufort Sea and Chukchi Sea 

Planning Areas. The oil and gas 

industry’s interest in offshore oil and 

gas exploration on the Arctic OCS 

remains high despite the pace of 

exploration and the challenges of 

operating in this unique environment. 

2. Challenges to Arctic Oil and Gas 

Operations 

The challenges to conducting 

operations and responding to 

emergencies in the extreme and variable 

environmental and weather conditions 

in the Arctic are severe. Both the 

Beaufort Sea and Chukchi Sea Planning 

Areas experience sub-freezing 

temperatures during most of the year, 

extended periods of low-light visibility, 

significant fog cover in the summer, 

strong winds and currents, strong 

storms that produce freezing spray and 

dangerous sea states, snow, and 

significant ice cover. During the fall 

(September–November), conditions 

become increasingly inhospitable as air 

temperatures decrease, wind speeds 

increase, storms become more frequent, 

and sea ice begins to form, all of which 

make Arctic OCS exploratory drilling 

operations more challenging (see 

Environmental Assessments for Shell 

Offshore, Inc.’s Revised Outer 

Continental Shelf Lease Exploration 

Plan, Camden Bay, Beaufort Sea, Alaska 

(2011) and Shell Gulf of Mexico, Inc.’s 

Revised Chukchi Sea Exploration Plan 

Burger Prospect (2011)); BOEM Alaska 

Region Web site at: http://www.boem.

gov/About-BOEM/BOEM-Regions/

Alaska-Region/Environment/

Environmental-Analysis/EnvironmentalImpact-Statements-and—MajorEnvironmental-Assessments.aspx). 

Other challenges to conducting 

operations and responding to 

emergencies on the Arctic OCS include 

the geographical remoteness and 

relative lack of established 

infrastructure to support oil and gas 

operations. 

C. Partner and Stakeholder Engagement 

in Preparation for This Proposed Rule 

DOI used the recommendations from 

the 60-Day Report as a basis for a series 

of discussions with multiple partners 

and stakeholders who provided valuable 

input regarding potential approaches to 

regulating oil and gas operations on the 

Arctic OCS. BOEM and BSEE recognize 

the importance of the Arctic region to a 

number of partners and stakeholders 

with varying positions on oil and 

natural gas development in the region. 

Both Bureaus engaged in discussions 

with Alaska Native and State partners, 

and with environmental and industry 

stakeholders, in advance of publishing 

this proposed rule. Those discussions 

addressed the recommendations from 

the 60-Day Report, as well as 

information regarding operating 

conditions and challenges in the Arctic. 

The then-Acting Assistant Secretary for 

Land and Minerals Management, along 

with DOI staff from headquarters and 

the Alaska Region, held three listening 

sessions and a series of meetings in 

Alaska over the course of several weeks 

in June 2013. Representatives of DOI 

also met with conservation 

organizations, the Mayor of the North 

Slope Borough, the Alaska Eskimo 

Whaling Commission, the Inupiat 

Community of the Arctic Slope (ICAS), 

the Native Village of Barrow, two Alaska 

Native Claims Settlement Act (ANCSA) 

corporations, oil and gas industry 

representatives, State of Alaska officials, 

and other local government 

representatives. 

DOI considered the suggestions and 

concerns of all partners and 

stakeholders to produce a proposed rule 

that balances maximizing oil and gas 

resource exploration on the Arctic OCS, 

in furtherance of the Nation’s energy 

security, with appropriate safeguards to 

protect human safety and the unique 

Arctic environment, as well as the 

cultural sensitivities and subsistence 

needs of the Alaska Native communities 

that might be affected by oil and gas 

development in the Arctic. 

1. Alaska Natives 

DOI heard a variety of perspectives 

from Alaska Natives during its outreach 

in advance of the rulemaking, including 

interest in the potential economic 

opportunities from oil and gas 

development. However, the overriding 

concern expressed by Alaska Natives is 

the potential for adverse impacts from 

oil and gas operations on the marine 

environment and its resources, 

including marine mammals, such as 

bowhead whales. Alaska Natives 

requested that the DOI evaluate the 

extent to which oil and gas activities 

may adversely affect marine resources of 

the waters overlying the Arctic OCS and 

the subsistence harvest practices of 

Alaska Natives. In particular, the marine 

mammal fauna of the Beaufort and 

Chukchi Seas are among the most 

diverse in the world and are of high 

scientific and public interest, and many 

are also important for subsistence. 

Future exploratory drilling could 

affect subsistence users in the Arctic 

region. Subsistence harvests differ 

among Alaska Native coastal 

communities. However, the bowhead 

whale is the most important marine 

mammal species to a majority of Arctic 

coastal communities because it is the 

preferred meat and it provides a unique 

and powerful cultural basis for sharing 

and community cooperation. 

Subsistence practices are a highly 

valued aspect of Alaska Native culture. 

These practices are an important facet of 

Alaska Native economies because they 

provide viable and essential means for 

families to support themselves in this 

remote environment. The sharing of 

subsistence resources also helps 

maintain traditional family and 

community organizations. In addition to 

their dietary benefits, subsistence 

resources provide special foods for 

religious and social occasions, and 

materials for personal and family use. 

Subsistence hunting also links Alaska 

Native communities to the larger market 

economy. Many households within the 

communities earn money from selling 

art work from the crafting of whale 

baleen and walrus ivory, and from 

clothing made from fur-bearing 

mammals. 

The Alaska Eskimo Whaling 

Commission, the North Slope Borough, 

and others requested that DOI consider 

marine mammals’ health as a critical 

part of this proposed rule. Throughout 

the rule, BOEM and BSEE have 

proposed elements designed to increase 

safety of oil and gas exploration in ways 

that would help protect marine 

mammals by reducing the likelihood 

and/or severity of oil spills. The Alaska 

Eskimo Whaling Commission and its 

whaling captains have worked with 

BOEM to help document traditional 

knowledge pertaining to bowhead 

whales, including movement and 

behavior. Bowhead hunters are 

concerned that the effects of offshore oil 

and gas exploration might displace 

migrating bowhead whales. 

Accordingly, BSEE proposes to revise 

§ 250.300(b) in order to: (i) Require 

operators to capture all petroleum-based 

mud and associated cuttings that result 

from Arctic OCS exploratory drilling 

operations to prevent their discharge 

into the marine environment; and (ii) 

clarify the Regional Supervisor’s 

discretion to require operators to 

capture water-based mud and associated 

cuttings from Arctic OCS exploratory 

drilling (after completion of the hole for 

the conductor casing) to prevent their 

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4BOEM’s Environmental Studies Program has 

made significant investments into studying 

potential impacts from operations related to oil and 

gas exploration. For example, BOEM has funded 

bowhead whale studies incorporating Traditional 

Ecological Knowledge and tagging data to learn 

more about bowhead whale migration through the 

Chukchi Sea in the fall and winter (Quakenbush et 

al., 2010). 

discharge into the marine environment, 

based on factors such as the proximity 

of exploratory drilling operations to 

subsistence hunting and fishing 

locations or the extent to which such 

discharges might cause marine 

mammals to alter their migratory 

patterns in a manner that interferes with 

subsistence activities or that might 

otherwise adversely affect marine 

mammals, fish, or their habitat(s). 

Given the importance of subsistence 

hunting and other activities to the 

Alaska Native communities, operators 

are encouraged to work directly with 

interested parties to help mitigate 

potential impacts to subsistence 

activities. In addition, BOEM will 

continue to fund and support studies to 

better understand impacts from OCS 

operations on marine mammals and 

subsistence activities.4

The North Slope Borough also 

expressed concern that oil and gas 

development not overwhelm local 

infrastructure, energy supplies, and 

services, and that local residents be 

provided the capacity—both in terms of 

training and resources—to protect their 

communities and important subsistence 

use areas. For this reason, DOI proposes 

to require operators to provide 

information about their plans to 

minimize the impact of their 

exploratory drilling operations on 

community infrastructure and their 

plans to provide the communities with 

oil spill cleanup training and resources. 

2. Environmental Organizations 

DOI also met directly with 

environmental organizations to review 

and discuss recommendations for Arctic 

oil and gas regulations. The PEW 

Charitable Trusts requested that BSEE 

revise 30 CFR 250.447 in order to 

require blowout preventer (BOP) 

pressure testing every 7 days for drilling 

and completion operations (an increase 

from every 14 days). BSEE proposes to 

amend the language in § 250.447 in 

order to require operators on the Arctic 

OCS to pressure test the BOP system 

every 7 days during exploratory drilling 

operations. This proposed requirement 

is also a safety measure included in 

Shell’s 2012 Arctic exploratory drilling 

program. Additionally, BSEE is 

proposing to add a new § 250.471, 

which would require that a capping 

stack be available and positioned to 

arrive at the well within 24 hours after 

a loss of well control and a cap and flow 

system and that a containment dome be 

available and positioned to arrive at the 

well within 7 days after a loss of well 

control. 

The Wilderness Society requested that 

BSEE consider implementing Arcticspecific provisions for OSRPs. BSEE 

proposes to add several requirements for 

OSRPs in this rule. In particular, BSEE 

proposes to require that operators 

conducting exploratory drilling on the 

Arctic OCS account for how they would 

increase oil encounter rates and the 

effectiveness of spill response 

techniques and equipment when sea ice 

is present. BSEE also proposes to add 

new provisions to 30 CFR part 254 for 

Arctic OCS exploratory drilling 

operators to, among other things, 

account for enhanced oil spill response 

training and exercises, as well as 

address the maintenance of response 

capabilities in the face of seasonal gaps 

in operations. 

3. Oil and Gas Operators 

DOI held further meetings throughout 

the summer of 2013 with individual oil 

and gas companies to hear their 

perspectives on possible regulations for 

Arctic OCS operations. The oil and gas 

operators emphasized a preference for 

performance-based rules as opposed to 

prescriptive rules, and also stressed the 

need for early engagement with the 

agencies in order to achieve up-front 

regulatory consistency. While elements 

of the proposed rule are prescriptive in 

nature, BOEM and BSEE endeavored to 

identify opportunities where 

performance-based requirements were 

feasible and would achieve the Bureaus’ 

goals. For these reasons, among others, 

BOEM proposes to add a new 

requirement that operators submit an 

IOP for their proposed Arctic 

exploratory drilling operations and 

describe at an early point in the 

planning process how their exploratory 

drilling program would be designed and 

conducted in an integrated manner 

suitable for Arctic OCS Conditions. The 

IOP process is intended to facilitate the 

prompt sharing of information among 

the relevant Federal agencies (e.g., 

BOEM, BSEE, U.S. Fish and Wildlife 

Service (USFWS), U.S. Coast Guard 

(USCG), National Oceanic and 

Atmospheric Administration (NOAA), 

U.S. Army Corps of Engineers, EPA) and 

the State of Alaska. The IOP process 

would also provide the relevant 

agencies an early opportunity to engage 

in a meaningful and constructive 

dialogue with operators and each other. 

The goal of the IOP and the enhanced 

and early dialogue is to have a wellplanned, safe operation. Early 

communication on planning is also 

anticipated to minimize the potential for 

project delays. 

D. Expected Benefits Justifying Potential 

Costs 

The initial RIA for this proposed rule 

estimates that it would result in 

economic costs ranging from $1.1 to 1.2 

billion, discounted at 7 percent and 3 

percent respectively, over 10 years. The 

above estimated cost range reflects the 

increase in costs over the baseline costs, 

as discussed elsewhere in this notice. 

While many of the economic and 

other 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 of the 

proposed rule would justify its potential 

costs and that it is appropriate to 

proceed with this proposal. The 

probability of a catastrophic oil spill is 

very low; however, the Deepwater 

Horizon oil spill demonstrated that even 

such low probability events can have 

devastating economic and 

environmental results. As of October 

2014, by its own account, BP spent over 

$14 billion for cleanup and response 

operations related to the Deepwater 

Horizon oil spill. The benefits of the 

proposed rule would accrue from a 

relief rig, increased safety measures, and 

other requirements that are expected to 

reduce the potential for an incident 

resulting in an oil spill associated with 

Arctic offshore operations and, if an 

incident occurs, to reduce the duration 

of a spill. 

The Arctic OCS and its surrounding 

land and waters have a unique 

significance to Alaska Natives, who rely 

on them for traditional cultural 

purposes and depend on them for 

subsistence. Similarly, many other 

Americans place a very high value on 

protecting the ecosystem, including the 

sensitive environment and wildlife, of 

this largely frontier area. Thus, 

prevention of a catastrophic oil spill, 

and reduction of the duration of a spill 

if one occurs, would have extremely 

important, even though largely 

unquantifiable, cultural and societal 

benefits for the Nation. 

Moreover, as explained elsewhere, 

this proposed rule would help achieve 

the National Arctic Strategy goals of 

protecting the unique and sensitive 

Arctic ecosystems, as well as the 

subsistence needs, culture and 

traditions of the Alaska Native 

communities, while reducing reliance 

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9924 Federal Register / Vol. 80, No. 36 / Tuesday, February 24, 2015 / Proposed Rules 

on imported oil and strengthening 

National energy security. The proposed 

requirements—which are specifically 

tailored to the Arctic OCS—would 

provide additional clarity and 

specificity regarding BOEM’s and 

BSEE’s expectations for safe and 

responsible development of Arctic 

resources and the particular actions that 

lessees, owners and operators must take 

in order to meet those expectations. 

This additional clarity and specificity is 

intended to help the oil and gas 

industry to plan better and to more 

effectively conduct exploratory drilling 

on the Arctic OCS, resulting in the 

development and production of oil and 

gas with lower risk and fewer delays 

than have occurred under the current 

rules. According to BOEM’s 2011 

Assessment of Undiscovered 

Technically Recoverable Oil and Gas 

Resources of the Nation’s Outer 

Continental Shelf, there are 

approximately 17.8 billion barrels of 

economically recoverable oil and about 

50.1 trillion cubic feet of economically 

recoverable natural gas 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. 

III. Proposed Regulations for Arctic 

OCS Exploratory Drilling 

The existing OCS oil and gas 

regulatory regime is extensive and 

covers all offshore facilities or 

operations in any OCS region, as 

appropriate and applicable. BOEM and 

BSEE use these regulations in their 

respective oversight of OCS leasing, 

exploration, development, production, 

and decommissioning. Depending on 

the type of activity, operators are subject 

to the same regulatory requirements, 

such as: application procedures and 

information requirements for 

exploration, development, and 

production activities; pollution 

prevention and control; safety 

requirements for casing and cementing 

and the use of a BOP and diverter 

systems; design, installation, use and 

maintenance of OCS platforms to ensure 

structural integrity and safe and 

environmentally protective operations; 

decommissioning; development and 

implementation of Safety and 

Environmental Management Systems 

(SEMS); and preparation and 

submission of OSRPs (see generally 30 

CFR parts 250, 254, and 550). 

The existing regulations also contain 

provisions that apply to specific regions 

or atypical activities or operating 

conditions, especially, for example, 

where drilling occurs in deep water or 

in a ‘‘frontier’’ area (typically 

characterized by its remote location and 

limited infrastructure and operational 

history, such as the Arctic OCS region). 

In these cases, BOEM and BSEE have 

special requirements, such as 

information and design requirements for 

deep-water development projects 

(§§ 250.286 through 250.295); use of 

appropriate equipment, third-party 

audits, and contingency plans in 

frontier areas or other areas subject to 

subfreezing conditions (§§ 250.417(c) 

and 250.418(f)); the placement of subsea 

BOP systems in mudline cellars when 

drilling occurs in areas subject to icescouring (§ 250.451); and emergency 

plans and critical operations and 

curtailment procedures information in 

the Alaska OCS Region (§§ 550.220 and 

550.251). 

Though there is currently a 

comprehensive OCS oil and gas 

regulatory program, there is a need for 

new and amended regulatory measures 

for Arctic OCS exploratory drilling by 

MODUs. These proposed regulations, in 

combination with existing regulations 

(which would continue to apply to 

Arctic OCS operations unless otherwise 

expressly stated), are intended to ensure 

that exploratory drilling operations are 

well planned from the outset and then 

conducted safely and responsibly in 

relation to the unique Arctic 

environment and the local communities 

that are closely connected to the region 

and its resources. The key elements of 

the proposed rule are: 

A. Measures That Address 

Recommendations—The proposed rule 

addresses recommendations contained 

in several recent reports on OCS oil and 

gas activities (e.g., the Arctic Council, 

Arctic Offshore Oil and Gas Guidelines 

(2009); the National Commission on the 

BP Deepwater Horizon Oil Spill and 

Offshore Drilling (2011); Ocean Energy 

Safety Advisory Committee 

Recommendations (2013); DOI’s 60-Day 

Report (2013); the Working Group’s 

report entitled, ‘‘Managing for the 

Future in a Rapidly Changing Arctic, A 

Report to the President’’ (March 2013); 

the National Arctic Strategy (May 2013); 

and the Arctic Council, Arctic Offshore 

Oil and Gas Guidelines: Systems Safety 

Management and Safety Culture (March 

2014)). 

B. IOP Requirement - During 

exploratory drilling operations on the 

Arctic OCS, operators may face 

substantial environmental challenges 

and operational risks throughout every 

phase of the endeavor, including 

preparations, mobilization, in-theater 

drilling operations, emergency response 

and preparedness, and demobilization. 

Thorough advanced planning is critical 

to mitigating these challenges and risks. 

One of the key components of this 

proposed rule is a requirement that 

operators explain how their proposed 

Arctic OCS exploratory drilling 

operations would be fully integrated 

from start to finish in a manner suitable 

for Arctic OCS Conditions and that they 

provide this information to DOI at an 

early stage of the planning process. 

This rule proposes to require that 

operators develop and submit an IOP to 

DOI, acting through its designee, BOEM, 

at least 90 days in advance of filing their 

EP. The purpose of the IOP is to 

describe, at a strategic or conceptual 

level, how exploratory drilling 

operations will be designed, executed, 

and managed as an integrated endeavor 

from start to finish. The IOP is intended 

to be a concept of operations that would 

include a description of the various 

aspects of an operator’s proposed 

exploratory drilling activities and 

supporting operations and how the 

operator’s program would be designed 

and conducted in a manner that 

accounts for the challenges presented by 

Arctic OCS Conditions. The primary 

issues DOI would expect operators to 

address relative to Arctic OCS 

Conditions include, but are not limited 

to: 

1. Vessel and equipment design and 

configurations; 

2. The overall schedule of operations, 

including contractor work on critical 

components; 

3. Mobilization and demobilization 

operations and maintenance 

schedule(s); 

4. In-theater drilling program 

objectives and timelines for each 

objective; 

5. Weather and ice forecasting and 

management capabilities; 

6. Contractor management and 

oversight; and 

7. Preparation and staging of spill 

response assets. 

DOI recognizes that other Federal 

agencies have primary oversight 

responsibility for some of the previously 

listed activities. Upon receipt of the 

IOP, DOI would engage with members 

of the Working Group and promptly 

distribute the IOP to the State of Alaska 

and Federal government agencies 

involved in the review, approval, or 

oversight of various aspects of OCS 

operations. 

However, the IOP process would not 

require agencies to review or approve 

the IOP or an operator’s planned 

activities. The IOP is a conceptual, 

informational document designed to 

ensure that an operator pays thorough 

and early attention to the full suite of 

regulated activities, and to give 

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regulatory agencies a preview of an 

operator’s approach to regulatory 

compliance and integrated planning. 

Thus, the IOP would enable relevant 

agencies to familiarize themselves, early 

in the planning process, with the 

operator’s overall proposed program 

from start to finish. This, in turn, would 

allow DOI and those agencies to 

coordinate and provide early input to 

the operator regarding potential issues 

presented by the proposed activities 

with respect to any future plan 

approvals and permitting requirements, 

including aspects of the program that 

might require additional details or 

refinement. The proposed IOP 

requirement—and the proposed rule in 

general—would not, however, interfere 

with or supplant operators’ obligations 

to comply with all other applicable 

Federal agency requirements. Each 

agency that receives an IOP would 

continue to review the relevant details 

of an operator’s planned activities for 

compliance with that agency’s 

regulatory requirements in the 

appropriate manner and at the 

appropriate time under its own 

regulatory program. 

C. SCCE and Relief Rig Capabilities— 

In Arctic OCS exploratory drilling, there 

is a need for operators to demonstrate 

that they would have access to, and 

could deploy, well control and 

containment resources that would be 

adequate to promptly respond to a loss 

of well control. This equipment is 

already readily available and accessible 

in the Gulf of Mexico due to the level 

of activity in that area. Ensuring that 

operators have all necessary 

redundancies in place is critical, as 

there is no guarantee that a single 

measure could control or contain a 

worst-case discharge (WCD). Therefore, 

BSEE proposes to require operators who 

use a MODU for Arctic OCS exploratory 

drilling to have access to, and the ability 

to deploy, SCCE (e.g., a capping stack, 

cap and flow system, and containment 

dome) within the timeframes discussed 

elsewhere in this proposed rule and that 

the SCCE be capable of functioning in 

Arctic OCS Conditions. BSEE also 

proposes that operators have access to a 

separate relief rig that would be staged 

at a location such that it could arrive on 

site and be capable of drilling a relief 

well under anticipated Arctic OCS 

Conditions within specified timeframes. 

This equipment is fundamental to safe 

and responsible operations on the Arctic 

OCS, where existing infrastructure is 

sparse, the geography and logistics make 

bringing equipment and resources into 

the region challenging, and the time 

available to mount response operations 

is limited by changing weather and ice 

conditions, particularly at the end of the 

drilling season. Operators may request 

approval of alternative compliance 

measures under existing regulations, if 

they can demonstrate that such 

alternative equipment or procedures 

could provide a level of safety and 

environmental protection equal to or 

surpassing the protection provided by 

the proposed SCCE and relief rig 

requirements (30 CFR 250.141). This 

provision enables operators to request 

approval for innovative technological 

advancements that may provide them 

additional flexibility, provided that the 

operator can establish that such 

technology provides at least the same 

level of protection as the proposed 

requirements. 

D. Planning for the Variability and 

Challenges of the Arctic OCS 

Conditions—Reliable weather and ice 

forecasting play a significant role in 

ensuring safe operations on the Arctic 

OCS. Advanced forecasting and tracking 

technology, information sharing among 

industry and government, and local 

knowledge of the operating environment 

are essential to managing the substantial 

challenges and risks that Arctic OCS 

Conditions pose for all offshore 

operations. In light of the threats posed 

by ice and extreme weather events, 

BOEM and BSEE propose to require that 

operators include in their IOPs, EPs, and 

APDs, at appropriate levels of 

specificity for each document, a 

description of their weather and ice 

forecasting capabilities for all phases of 

their exploration program and their alert 

procedures and thresholds for activating 

ice and weather management systems. 

Once operations commence, operators 

would also be required to: 

1. Notify BSEE immediately of any sea 

ice movement or condition that has the 

potential to affect operations or trigger 

ice management activities; and 

2. Notify BSEE of the start and 

termination of ice management 

activities and submit written reports 

after completing such activities. 

E. Arctic OCS Oil Spill Response 

Preparedness—Operators need to be 

prepared for a quick and effective 

response in the event of an oil spill on 

the Arctic OCS and be ready to 

coordinate activities with the Federal 

government and other stakeholders. The 

OSRPs and related activities should be 

tailored to the unique Arctic OCS 

operating environment to ensure that 

operators have the necessary equipment, 

training, and personnel for the Arctic 

OCS. Among other things, this 

rulemaking would establish specific 

planning requirements to maximize the 

application of oil spill response 

technology and ensure a coordinated 

response system that is designed to 

address the challenges inherent to the 

Arctic region. 

F. Reducing Pollution from Arctic 

OCS Exploratory Drilling Operations— 

Partners, primarily Alaska Natives, and 

stakeholders have expressed concern 

that mud and cuttings from exploratory 

drilling could adversely affect marine 

species (e.g., whales and fish) and their 

habitat and compromise the 

effectiveness of subsistence hunting 

activities. Existing environmental 

analyses support these concerns and 

also demonstrate that such discharges 

could affect water quality, benthic 

habitat, and marine organisms within 

the localized area (see, e.g., Shell Gulf 

of Mexico, Inc.’s Revised Chukchi Sea 

Exploration Plan, Burger Prospect 

Environmental Assessment (2011)). 

BSEE proposes to require the capture of 

all petroleum-based mud and associated 

cuttings from Arctic OCS exploratory 

drilling operations to prevent their 

discharge into the marine environment. 

The new provision would also clarify 

the Regional Supervisor’s discretionary 

authority to require that operators 

capture all water-based mud 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. This discretion 

would be exercised based on various 

factors such as the proximity of 

exploratory drilling operations to 

subsistence hunting and fishing 

locations or the extent to which such 

discharges might cause marine 

mammals to alter their migratory 

patterns in a manner that interferes with 

subsistence activities or might adversely 

affect marine mammals, fish, or their 

habitat(s). 

G. Oversight, Management, and 

Accountability of Operations and 

Contractor Support—An effective risk 

management framework at the 

beginning of a project incorporates 

many components, including planning, 

vessel design, contractor selection, and 

an assessment of regulatory 

requirements for all facets of the project. 

DOI proposes to require that operators 

provide an explanation, at a conceptual 

level, of how they would apply their 

oversight and risk management 

protocols to both personnel and 

contractors to support safe and 

responsible exploratory drilling on the 

Arctic OCS. It should be noted that 

these proposed regulations, and DOI’s 

existing regulations concerning OCS oil 

and gas operations, would require 

varying levels of information about 

operator safety and oversight 

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management at progressive stages of the 

planning and approval process. This 

would start with the most general 

information and narrow down to 

increasing levels of detail with 

successive regulatory submittals, as the 

project would proceed from planning to 

implementation. 

In addition, the proposed rule would 

require Arctic OCS operators to: 

1. Report threatening sea ice 

conditions and ice management 

activities, and unexpected operational 

issues that could result in a loss of well 

control; 

2. Increase their BOP pressure testing 

frequency; 

3. Conduct real-time monitoring of 

various aspects of well operations, e.g., 

the BOP control system; 

4. Increase their SEMS auditing 

frequency; and 

5. Enhance their oil spill 

preparedness and response capabilities 

for Arctic OCS operations. 

A summary of the major provisions of 

this rulemaking follows. 

IV. Section-By-Section Discussion 

This portion of the preamble provides 

an explanation of the specific regulatory 

changes proposed in this rule and why 

they are necessary. At the outset, this 

discussion addresses the proposed 

definitions of the terms Arctic OCS and 

Arctic OCS Conditions for use in both 

BOEM’s and BSEE’s regulations in order 

to provide context for the rest of the 

proposed provisions. Since this is a 

joint BOEM and BSEE proposed rule, 

the remainder of the Section-by-Section 

discussion is organized according to 

how operators would seek to comply 

with the proposed regulations, rather 

than the order in which they would 

appear in the Code of Federal 

Regulations. After introducing the 

definitions of Arctic OCS (for purposes 

of proposed §§ 250.105, 254.6, and 

550.105) and Arctic OCS Conditions (for 

purposes of proposed §§ 250.105 and 

550.105), the Section-by-Section 

discussion provides an explanation of 

the remainder of BOEM’s proposed 

regulations (i.e., proposed §§ 550.105, 

550.200, 550.204, 550.206, and 

550.220), and then follows with the 

remainder of BSEE’s proposed 

regulations (i.e., proposed §§ 250.105, 

250.188, 250.198, 250.300, 250.402, 

250.418, 250.447, 250.452, 250.470, 

250.471, 250.472, 250.473, and 

250.1920; proposed §§ 254.6, 254.55, 

254.65, 254.70, 254.80, and 254.90). 

Although BSEE permitting and 

operational requirements appear earlier 

in Title 30 of the CFR at Part 250, with 

the BOEM requirements following in 30 

CFR part 550, in practice the IOP and EP 

phases governed by the 30 CFR part 550 

regulations would precede the drilling 

approval and oversight phases governed 

by 30 CFR part 250 (operations). 

Requirements to prepare for an oil spill, 

which are contained in 30 CFR part 254, 

may be met at any time before handling, 

storing, or transporting oil in operations 

BSEE permits under Part 250. Finally, 

the Section-by-Section discussion 

includes a process flowchart of BOEM’s 

and BSEE’s current regulatory 

framework for Arctic OCS exploratory 

drilling and how the proposed 

requirements would be integrated into 

that framework. 

A. Definitions (§§ 250.105, 254.6, and 

550.105) 

Arctic OCS 

For the purposes of this proposed 

rulemaking, Arctic OCS is defined as the 

Beaufort Sea and Chukchi Sea Planning 

Areas, as described in the Proposed 

Final OCS Oil and Gas Leasing Program 

for 2012–2017 (June 2012), available at 

www.boem.gov/uploadedFiles/BOEM/

Oil_and_Gas_Energy_Program/Leasing/

Five_Year_Program/2012–2017_Five_

Year_Program/PFP%2012–17.pdf (see 

pp.21–24). This definition would appear 

in §§ 250.105, 254.6, and 550.105. As 

described previously, BOEM and BSEE 

have determined that these areas are 

both the subject of current exploration 

and development interest and subject to 

conditions that present significant 

challenges to such operations. 

Arctic OCS Conditions 

Sections 250.105 and 550.105 would 

be revised to add a definition for Arctic 

OCS Conditions. The definition is 

necessary because these proposed 

regulations are designed largely around 

the particular challenges presented by 

Arctic OCS Conditions. The term Arctic 

OCS Conditions would be defined to 

describe both the environmental 

conditions and functional 

characteristics (e.g., geographic 

remoteness, limited infrastructure, 

subsistence hunting areas) that oil and 

gas operators can reasonably expect to 

encounter during exploratory drilling 

operations and when responding to a 

loss of well control on the Arctic OCS. 

Depending on the time of year, relevant 

environmental conditions and the 

proposed definition include, but are not 

limited to, the following: ‘‘extreme cold, 

freezing spray, snow, extended periods 

of low light, strong winds, dense fog, sea 

ice, strong currents, and dangerous sea 

states.’’ This definition would not affect 

or alter any other existing Federal 

regulatory requirements. 

It is crucial for OCS oil and gas 

operators to have a clear understanding 

of the conditions they would likely 

encounter during exploratory drilling 

operations and when responding to a 

loss of well control on the Arctic OCS. 

Offshore oil and gas exploration 

involves inherent risks to human safety 

and the environment. If not effectively 

addressed, Arctic OCS Conditions could 

multiply these risks. Thus, the proposed 

definition also recognizes that ‘‘the 

Arctic’s remote location, limited 

infrastructure, and existence of 

subsistence hunting and fishing areas 

are also characteristic of the Arctic 

region’’ and must be considered to 

ensure safe operations and minimize 

impacts to the environment and to other 

users of the area. Addressing these 

factors would enable industry to 

proactively safeguard people, facilities, 

equipment, and the environment. 

B. Additional Regulations Proposed by 

BOEM 

Definitions (§ 550.200) 

The acronym ‘‘IOP’’—meaning 

Integrated Operations Plan—would be 

inserted into the proper alphabetical 

location within existing § 550.200, for 

purposes of the IOP provisions at 

proposed § 550.204, as discussed next. 

When must I submit my IOP for 

proposed Arctic exploratory drilling 

operations and what must the IOP 

include? (§ 550.204) 

This proposed rule would require the 

operator to develop an IOP for each 

proposed exploratory drilling program 

on the Arctic OCS, and to submit the 

IOP to DOI, 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 

§ 550.204. Operators may also choose to 

address the requirements in §§ 550.211 

through 550.228, which could facilitate 

the later formal review of the operator’s 

EP. The IOP should be detailed enough 

to allow DOI, other relevant Federal 

agencies, and the State of Alaska to: 

1. Familiarize themselves with the 

proposed operations as an integrated 

project from start to finish; and 

2. Provide constructive feedback to 

the operator concerning the conceptual 

plans reflected in its IOP. 

DOI recognizes that when the IOP is 

submitted, operators might not possess 

all the detailed and specific information 

that may be more readily available later 

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in the planning process; e.g., contracts 

for vessels may not be finalized, precise 

dates of drilling may be uncertain, or 

the exact staging location of assets, such 

as the relief rig or SCCE, may be 

unknown. For BOEM’s and BSEE’s 

purposes, operators would submit more 

detailed information through the EPs 

and APDs, as appropriate. 

Though BOEM would review the IOP 

to ensure that the operator’s submission 

addresses each of the elements listed in 

§ 550.204, the IOP would not require 

approval by DOI or the other relevant 

agencies. Instead, the IOP would be an 

informational document intended to 

facilitate early review of important 

concepts related to an operator’s 

proposed exploratory drilling program. 

This review would assist DOI and other 

relevant agencies in developing an 

understanding of, and familiarity with, 

the operator’s overall proposed 

exploratory drilling program early in the 

planning process. 

DOI recognizes that the information 

requirements of § 550.204 could 

implicate other Federal agencies’ and 

the State of Alaska’s statutory and 

regulatory mandates. For example, the 

USCG administers laws and regulations 

governing maritime safety, security, and 

environmental protection and is also 

responsible for inspecting the vessels to 

which those laws and regulations apply. 

In acknowledging the USCG’s principal 

jurisdiction over vessel safety and 

security, DOI has determined that 

information, early in the process, 

pertaining to the safety of operations, 

vessel mobilization, demobilization, and 

tow plans, is also essential to DOI’s 

statutory and regulatory responsibilities 

related to Arctic OCS oil and gas 

activities. The IOP process is intended 

to facilitate the sharing of information 

among the relevant Federal agencies and 

the State of Alaska and to provide the 

relevant agencies an early opportunity 

to engage in a meaningful and 

constructive dialogue with operators, 

consistent with the policies articulated 

in E.O. 13580 (Interagency Working 

Group on Coordination of Domestic 

Energy Development and Permitting in 

Alaska, discussed earlier). 

Upon receipt, DOI would engage 

fellow members of the Working Group 

and distribute the IOP to other Federal 

government agencies involved in the 

review, approval, or oversight of aspects 

of OCS operations (e.g., BOEM, BSEE, 

USFWS, USCG, NOAA, and EPA), as 

well as the State of Alaska. Early 

engagement by these entities would 

allow them to become familiar with the 

operator’s overall proposed exploratory 

drilling program and could provide a 

meaningful opportunity to offer early 

feedback to the operator concerning its 

proposed activities and any identifiable 

issues that might affect future 

permitting decisions. DOI would also 

encourage the assembly of an 

interagency coordination team to 

facilitate and coordinate agency review 

and feedback. Any feedback could be 

provided individually by the relevant 

Federal agencies or the State of Alaska, 

or collectively through DOI. 

BOEM also plans to promptly post 

each IOP on its Web site. BOEM would 

not solicit public input on the IOP; 

instead, the IOP would be informational 

only, affording the public an early 

opportunity to view key concepts of a 

proposed exploratory program. This 

effort responds to stakeholder concerns 

that BOEM does not provide the public 

with sufficient time to participate 

meaningfully in BOEM’s administrative 

process for proposed exploratory 

drilling activities on the Arctic OCS. 

Typically, the public first becomes 

aware of an operator’s plans for 

exploratory drilling when the operator 

submits its EP. BOEM acknowledges 

that public review periods for EPs are 

relatively short in duration. However, 

this is a result of the OCSLA provision 

that requires BOEM to approve, 

disapprove, or require modifications to 

an EP within 30 days of BOEM deeming 

the EP submitted (43 U.S.C. 1340(c)(1)), 

thus placing modification of the length 

of the review period outside the 

discretion or authority of the agency 

absent Congressional action. An early 

opportunity to view the IOP and the key 

concepts of the proposed exploratory 

drilling program, however, will enhance 

existing public engagement 

opportunities. 

Paragraph (a), Vessels and Equipment 

Operators must plan to adapt their 

exploratory drilling operations to Arctic 

OCS Conditions. Although generally the 

equipment for extracting oil and gas 

from the OCS is the same for the 

offshore Arctic as anywhere else on the 

OCS, the equipment might need to be 

modified, procedures might need to be 

adjusted, or personnel might need to be 

specifically trained for work conditions 

on the Arctic OCS. For example, cranes 

might need to be modified for 

operations under ice loading that could 

be anticipated during Arctic OCS 

operations, and be de-rated to account 

for reduced strength in extreme cold 

temperatures. Accordingly, this 

provision would require that operators 

submit, ‘‘[i]nformation describing how 

all vessels and equipment will be 

designed, built, and/or modified to 

account for Arctic OCS Conditions’’ and 

is designed to ensure that the operator 

is planning to deploy vessels and 

equipment capable of operating safely 

on the Arctic OCS. Operators would 

need to submit information sufficient to 

allow DOI and other relevant agencies 

(e.g., the USCG) to understand the 

function of each vessel within the 

proposed fleet of vessels and how the 

vessels would be capable of performing 

their identified roles in the proposed 

exploratory drilling program safely and 

effectively. 

Paragraph (b), Exploratory Drilling 

Program Schedule 

The proposed rule would require the 

IOP to include an exploratory drilling 

program schedule of operations 

including importantly, contractor work 

on critical components of the program 

(e.g., inspection and testing of critical 

equipment such as BOPs or SCCE). 

Thorough advanced planning regarding 

the proposed schedule for operations is 

an important component of the IOP, 

particularly in light of the limits that 

returning sea ice can place on the 

drilling season on the Arctic OCS, and 

for elements of operations for which 

operators are relying upon outside 

contractor deliverables. Furthermore, it 

is important for BOEM and other 

relevant agencies to have information 

regarding how the timing of proposed 

operations aligns with expected 

seasonal ice encroachment, as well as 

how the timing of proposed operations 

may interact with seasonal marine 

mammal migrations and subsistence 

activities, for purposes of understanding 

the potential environmental impacts. 

This will help BOEM and other relevant 

agencies develop an understanding of 

how the operator proposes to conduct 

operations safely. 

The proposed schedule would need to 

include, for example, when an operator 

intends to enter waters overlying the 

Alaska OCS (including transit time to 

the proposed drilling site), when 

drilling is expected to commence and 

conclude, dates of operations, and when 

the operator plans to leave the vicinity 

of drilling operations. The schedule 

would also need to include the critical 

dates for completion or activation of 

components under construction, repair, 

or storage by outside contractors. This 

provision would help assure DOI and 

other relevant agencies that the operator 

and its contractors have developed a 

reasonable schedule for executing each 

phase of the exploration program and 

are capable of conducting exploratory 

drilling activities safely in Arctic OCS 

Conditions. 

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Paragraph (c), Mobilization and 

Demobilization 

This provision would require 

operators to include in their IOP a 

description of their mobilization and 

demobilization operations, including 

tow plans suitable for Arctic OCS 

Conditions, as well as their general 

maintenance schedules for vessels and 

equipment. This element is designed to 

help DOI and other relevant agencies 

understand the extent to which 

operators: 

1. Have accounted for the conditions 

likely to be encountered on the Arctic 

OCS; and 

2. Are prepared to handle the 

substantial environmental challenges 

and associated operational risks present 

throughout the mobilization and 

demobilization of personnel and 

equipment. 

The requested information would 

facilitate coordination between DOI and 

the USCG. Similarly, having 

information about where vessels would 

come from and go to before and after 

entering the waters overlying the Alaska 

OCS would aid, for example, DOI’s and 

other relevant agencies’ early 

understanding of potential 

environmental issues, such as aquatic 

invasive species that might be carried 

on vessels. 

This provision would also require 

consideration of how repairs to, and 

maintenance of, vessels and equipment 

might affect the larger exploratory 

drilling program. This information 

could facilitate DOI’s and other relevant 

agencies’ understanding of potential 

environmental considerations and safety 

aspects of the projected operational 

schedules. 

Paragraph (d), Exploratory Drilling 

Program Objectives, Timelines, and 

Contingency Plans 

This provision would require 

operators to include in their IOP a 

description of their ‘‘exploratory drilling 

program objectives and timelines for 

each objective, including general plans 

for abandonment of the well(s)’’ under 

a variety of circumstances. This 

description would help DOI and other 

relevant agencies familiarize themselves 

with the operator’s plans for a welldesigned, safe operation with clear 

objectives for employees and contractors 

that would allow ample flexibility in 

light of the difficult and variable 

conditions on the Arctic OCS. 

A fully developed exploration 

program includes, among other things: 

the operator’s general plan of how many 

wells it plans to drill in a particular 

season; the timing and sequence of 

those operations; locations of the wells; 

necessary equipment and resources, 

including information on support 

vessels; and the operator’s contingency 

plans in the event that temporary 

abandonment would become necessary. 

To the extent that relevant information 

submitted with the IOP has not 

changed, the operator could later 

incorporate that information into its EP. 

Thorough advanced planning of the 

operator’s objectives, as well as clear 

timelines for the accomplishment of 

each objective, are essential, particularly 

in light of the limited seasonal drilling 

window on the Arctic OCS. 

Given the uncertainties created by the 

challenging Arctic OCS Conditions, it is 

equally essential for an operator to 

acknowledge and plan for contingencies 

and delays that might arise. For 

example, an operator would need to 

provide general information regarding 

how it would safely respond to 

unanticipated ice encroachment at the 

drill site, including safe and secure 

temporary abandonment of the well and 

relocation of the drilling rig, as 

necessary. DOI would need to be 

provided with information that explains 

how the operator has considered these 

elements of its exploration program, 

well in advance of operations. Also, if 

an operator plans to drill multiple wells, 

DOI must be provided with information 

regarding the anticipated objectives and 

timelines for each well. Similarly, an 

operator would be expected to indicate 

whether it intends to abandon the 

well(s) at the end of the season and, if 

the operator intends to abandon the 

well, whether such abandonment would 

be temporary or permanent. 

Paragraph (e), Weather and Ice 

Forecasting and Management 

One of the key drivers of this 

proposed rule is DOI’s need to 

understand how operators would 

account for the variable conditions on 

the Arctic OCS and how those 

conditions might affect drilling 

activities. One important component of 

an operator’s overall program is 

accounting for adverse weather and ice 

conditions and developing a plan to 

respond to those conditions. 

Consequently, this provision would 

require operators to describe their 

weather and ice forecasting capabilities 

for all phases of the exploration 

program, including a description of how 

they would respond to and manage ice 

hazards and weather events. The 

challenges presented by Arctic OCS 

Conditions are not limited to the period 

of active drilling operations, but would 

create difficulties throughout all phases 

of an exploratory drilling program, 

including mobilization and 

demobilization. Accordingly, it is 

important for DOI and other relevant 

agencies to understand the operator’s 

plans for implementing ice and weather 

forecasting and management systems 

that would be operational around the 

clock from start to finish. 

Paragraph (f), Contractors 

This provision would require 

operators to provide in their IOP a 

description of work to be performed by 

contractors supporting their exploratory 

drilling program (including 

mobilization and demobilization), how 

such work would be designed or 

modified to account for Arctic OCS 

Conditions, and operators’ strategy for 

contractor management, oversight, and 

risk management. This information is 

designed to help DOI and other relevant 

agencies understand the operator’s 

strategies for developing, early in the 

planning process, a rigorous and 

effective operational management and 

oversight system for its contractors that 

is specifically tailored for operations on 

the Arctic OCS. Information regarding 

the nature and timeline of operational 

elements for which the operator would 

rely on contractors would aid in a full 

understanding of the various inputs and 

contingencies that might affect the 

planned execution of the proposed 

operations. 

The IOP would need to describe, for 

example, what types of operations the 

operator would contract out and how 

the operator would oversee the 

contractor to ensure the contractor’s 

work product would be suitable for 

Arctic OCS operations. At the IOP stage, 

the specific names of contractors would 

not be necessary but could be provided, 

if known. The focus of this proposed 

requirement is to facilitate DOI’s and 

other relevant agencies’ understanding 

of how the operator plans to rely on 

contractors and how it plans to manage 

its contractor relationships in order to 

ensure safe and responsible drilling 

operations. 

Paragraph (g), Safety 

BOEM proposes to require that 

operators include in their IOP a 

description of how they ‘‘will ensure 

operational safety while working in 

Arctic OCS Conditions,’’ including but 

not limited to, the safety principles 

applicable to operators and their 

contractors, the accountability structure 

within operators’ organizations for 

implementing these principles, how 

operators would communicate these 

principles to their employees and 

contractors, and how operators would 

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determine successful implementation of 

these principles. 

The OCSLA provides that all 

operations taking place on the OCS 

‘‘should be conducted in a safe manner 

by well-trained personnel using 

technology, precautions, and techniques 

sufficient to prevent or minimize the 

likelihood of blowouts, loss of well 

control, fires, spillages, physical 

obstruction to other users of the waters 

or subsoil and seabed, or other 

occurrences which may cause damage to 

the environment or to property, or 

endanger life or health’’ (43 U.S.C. 

1332(6)). Also, operators are required to 

demonstrate through their EPs and 

APDs that they have planned and are 

prepared to conduct activities in a 

manner that conforms to the OCSLA 

and applicable implementing 

regulations, and that their activities will 

be conducted safely (see 43 U.S.C. 

1340(c)(1); 30 CFR 250.106, 250.107, 

550.202 paragraphs (a) and (b)). The 

proposed safety information 

requirement would help DOI and other 

relevant agencies (e.g., USCG) 

familiarize themselves with the 

operator’s early consideration of how its 

proposed exploratory drilling program 

would proceed in a safe manner with 

appropriate caution and respect for the 

extreme and unpredictable conditions 

found offshore in the Arctic and would 

be consistent with DOI’s and other 

relevant agencies’ safety requirements. 

This proposed safety information 

element is also intended to complement 

BSEE’s SEMS program by requiring 

operators to identify and assess, early in 

the planning stages of their proposed 

exploratory drilling program, their 

guiding principles for safe Arctic OCS 

operations, and optimal strategies for 

implementing those principles 

throughout their workforce. 

Proposed 30 CFR 550.204(g) would 

not require an operator to provide the 

same level of detail, if not available, 

concerning safety of operations as 

would be available at the time of the EP 

and APD, or to duplicate the detail 

provided in its USCG Safety 

Management System program or its 

BSEE SEMS program. Instead, the IOP 

would need to provide a general 

understanding of the principles that 

operators would follow to manage risks 

to ensure safety of all exploratory 

drilling activities and personnel vis-a`- 

vis the conditions likely to be 

encountered on the Arctic OCS. For 

example, it is reasonably expected that 

operators would experience freezing 

spray, extended periods of low light, 

strong winds, and dense fog during 

operations. Operators would need to 

provide a general description of how 

they would account for these 

conditions, and any guiding principles 

they would follow to minimize risk to 

operations, personnel, vessels, and other 

equipment. 

Paragraph (h), Staging of Oil Spill 

Response Assets 

BOEM proposes to require that 

operators include in their IOP 

information regarding their 

‘‘preparations and plans for staging of 

oil spill response assets.’’ This provision 

would facilitate DOI’s, and other 

relevant agencies’ (e.g., USCG), early 

understanding of the potential effects on 

local communities from staging spill 

response assets near coastal 

communities, the safety and 

environmental implications of plans for 

mobilization and demobilization of 

related vessels and equipment, the 

potential environmental impacts of the 

vessels staged in the area for response, 

and anticipated response times based on 

where the equipment will be located. 

This information would be especially 

relevant to the USCG, which is the 

Federal On Scene Coordinator 

responsible for developing the North 

Slope Sub-Area Contingency Plan for 

Oil and Hazardous Substances 

Discharges/Releases. The USCG and all 

appropriate governmental entities at the 

State and local levels would have an 

early understanding of the proposed 

activities. 

Paragraph (i), Impact of Exploratory 

Drilling on Local Community 

Infrastructure 

BOEM proposes to require that 

operators include in their IOP, a 

description of their ‘‘efforts to minimize 

impacts of [their] exploratory drilling 

operations on local community 

infrastructure, including but not limited 

to housing, energy supplies, and 

services.’’ This provision would 

facilitate DOI’s and other relevant 

agencies’ early understanding of the 

potential socioeconomic implications of 

the proposed exploratory drilling 

program, including the extent to which 

the proposed activities might strain the 

limited infrastructure of coastal 

communities in the Arctic, or reduce the 

availability of housing, energy, food, 

and health care to local communities 

through increased demand and higher 

costs caused by the presence of persons 

supporting the exploratory drilling 

program. 

Paragraph (j), Local Community 

Workforce and Response Capacity 

BOEM proposes to require that 

operators include in their IOP ‘‘[a] 

description of whether and to what 

extent your project will rely on local 

community workforce and spill cleanup 

response capacity.’’ This provision 

would encourage operators to engage in 

early planning toward providing local 

communities, which would incur the 

greatest risk of offshore exploration 

activities, with the capacity—both in 

terms of training and resources—to 

protect their communities and 

important subsistence use areas. It is 

intended to provide DOI and other 

relevant agencies with early insight into 

whether the proposed operations are 

being planned safely, with appropriate 

environmental safeguards and respect 

for the other users of area resources. 

This provision would also allow DOI to 

develop an early understanding of 

industry’s efforts to promote local 

communities’ ability to participate in 

and obtain benefit from future Arctic 

OCS oil and gas development. 

How do I submit the IOP, EP, DPP, or 

DOCD? (§ 550.206) 

DOI recognizes that operators may 

consider some of the information 

required by proposed § 550.204 to be 

proprietary or commercial in nature. 

Pursuant to the proposed revisions to 

§ 550.206, operators would be able to 

request the nondisclosure of this 

information using established DOI 

processes. As is currently the case with 

EPs, Development and Production Plans 

(DPPs), and Development Operations 

Coordination Documents (DOCDs), 

operators requesting the nondisclosure 

of portions of an IOP should provide 

BOEM with two separate versions of the 

IOP; a public version from which 

potentially exempt information is 

redacted, and a BOEM version with 

such information present, but clearly 

marked as proprietary. 

If I propose activities in the Alaska OCS 

Region, what planning information must 

accompany the EP? (§ 550.220) 

As described previously, drilling 

operations, especially on the Arctic 

OCS, can be complex, and operators 

may face substantial environmental 

challenges and operational risks 

throughout every phase of the endeavor. 

One of the main goals of this rulemaking 

is to ensure, through thorough advanced 

planning, that operators are capable of 

operating safely in the extreme and 

challenging Arctic OCS Conditions. 

BOEM first proposes to amend the 

existing ‘‘Emergency Plans’’ provision at 

§ 550.220(a) to add fire, explosion, and 

personnel evacuation to the events for 

which emergency plans are required, 

and to replace the terms ‘‘blowout’’ with 

‘‘loss of well control’’ and ‘‘craft’’ with 

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‘‘vessel, offshore vehicle, or aircraft’’ for 

clarification purposes. 

BOEM next proposes to create a new 

§ 550.220(c), which would set forth 

additional information requirements for 

EPs that are proposing exploration 

activities on the Arctic OCS. BOEM 

proposes to add a new performancebased provision at § 550.220(c)(1) that 

would require an operator to describe 

how its proposed activities would be 

designed and conducted in a manner 

suitable for Arctic OCS Conditions and 

how these activities would be managed 

and overseen as an integrated endeavor. 

This description may be summarized 

from the operator’s IOP or, if 

appropriate, updated with any 

information not available at the time of 

the IOP. 

BOEM also proposes to add 

§ 550.220(c)(2), which would require 

operators to include, as part of their EP 

submissions, more detailed and updated 

information concerning their weather 

and ice forecasting and management 

plans for all phases of their exploratory 

drilling activities, including: a 

description of how they would respond 

to and manage ice hazards and weather 

events; their ice and weather alert 

procedures; their procedures and 

thresholds for activating their ice and 

weather management systems; and 

confirmation that their ice and weather 

management and alert systems would be 

operated continuously throughout the 

planned operations. As described 

previously, DOI needs to be certain that 

adequate forecasting equipment and 

procedures are in place to predict and 

follow developing weather and ice 

conditions that might pose a risk to 

operations. Also, it is essential that 

operators develop and describe their 

pre-established thresholds for triggering 

varying levels of responsive actions in 

the face of weather and ice threats, as 

well as the procedures and equipment 

necessary to respond to these hazards. 

Furthermore, operators need to 

demonstrate that they would be capable 

of responding to and managing these 

conditions to prevent or minimize the 

risks associated with ice and adverse 

weather. 

BOEM next proposes to require 

preliminary information concerning 

SCCE capabilities, deployment of a 

relief well rig, and sharing of SCCE and 

spill response and cleanup assets. The 

proposed informational requirements 

concerning SCCE and relief well rigs 

relate to the operator’s preliminary 

plans for complying with BSEE’s 

proposed regulations at 30 CFR 250.471 

and 250.472, which will be described 

later. 

Requiring information about how an 

operator intends to satisfy the proposed 

BSEE regulations at proposed 30 CFR 

250.471 and 250.472 would allow 

consideration of these issues at an early 

planning stage, and would further 

inform BOEM’s review of proposed EPs 

under § 550.202, and other applicable 

laws. It would likewise reduce the risk 

of discrepancy between reviews and 

approvals conducted at the EP stage and 

an operator’s later-submitted APD. 

While BOEM anticipates that elements 

of the SCCE description required by 

proposed § 550.220(c)(3) and the relief 

well rig description required by 

proposed § 550.220(c)(4) may be general 

at the EP stage, they must be detailed 

enough for BOEM to confirm that the 

operator would have plans in place for 

how it would conduct its operations 

safely, in conformance with applicable 

regulations. The description would also 

need to be detailed enough to enable 

BOEM to evaluate the potential 

environmental implications of proposed 

SCCE and relief well rig staging and 

operations. Proposed § 550.220(c)(4) 

would set forth some of the information 

expected to be available about the relief 

well rig when the EP is submitted. 

The proposed § 550.220(c)(5) 

provision would add an informational 

requirement concerning any agreements 

the operator might have with third 

parties for the sharing of assets (e.g., 

SCCE, relief rigs, and oil spill response 

resources) and/or any agreements to 

assist each other in response and 

cleanup efforts in the event of a loss of 

well control or other emergency. A 

cooperative, consortium-based model 

should offer: 

1. Logistical, operational, and 

commercial efficiencies; 

2. Less duplication of personnel and 

equipment; 

3. Reduced monetary cost of 

exploration; 

4. Reduced environmental footprint; 

5. Reduced social costs and 

interference with other users of the 

OCS; and 

6. A coordinated response and 

cleanup effort in the event of a loss of 

well control. 

BOEM’s environmental impact 

analyses have repeatedly shown that the 

presence of vessels, aircraft, and other 

equipment within the Arctic region 

could result in adverse impacts to 

subsistence activities and to 

environmental resources (e.g., noise 

impacts on marine mammals, increased 

risk of bird or marine mammal 

collisions, increased risk of fuel spills, 

and increased air emissions). The 

potential effects would be compounded 

if multiple operators—each fielding its 

own fleet of drilling, resupply, and 

emergency response vessels—were to 

engage in activities simultaneously. 

Avoiding duplication of relief well rigs, 

oil spill response assets, and other 

emergency response vessels and 

equipment would be an effective means 

to minimize environmental and social 

impacts. 

BOEM and BSEE strongly encourage 

operators proposing exploratory drilling 

activities on the Arctic OCS to enter into 

mutual aid agreements for the sharing of 

vessels, relief well rigs, and other assets 

or services associated with responding 

to an oil spill or other emergency. 

Notice of these arrangements would 

inform BOEM’s and BSEE’s safety and 

environmental review of proposed 

activities to ensure operators are fully 

prepared to respond to a loss of well 

control. Also, BOEM and BSEE expect 

that operators, when planning a 

response to a loss of well control, would 

ensure that an effective and immediate 

removal, mitigation, or prevention of a 

discharge could be achieved, to the 

greatest extent practicable, using private 

sector capability. 

Finally, proposed § 550.220(c)(6) 

would add an informational 

requirement concerning the conclusion 

of on-site operations at the end of the 

season. An operator would include a 

projected date, and information used to 

determine the date, when on-site 

operations would be completed based 

on ice conditions that will likely exist 

in the relevant operational area (using 

current Federal ice and weather 

forecasts or other reliable forecasting 

systems). An operator would also 

provide a projected date, and supporting 

information, on when the operator 

would stop drilling operations into 

zones capable of flowing liquid 

hydrocarbons to the surface. That date 

would need to be consistent with the 

relief rig planning requirements under 

proposed 30 CFR 250.472 and with the 

estimated timeframe for deployment of 

a relief rig under proposed 

§ 550.220(c)(4). 

There is no single, definitive ‘‘end of 

drilling season’’ in the Arctic OCS. The 

projected end-of-season dates in any 

specific EP should be based on a variety 

of factors, including the operator’s 

equipment, procedures, and capability 

to effective ly manage and mitigate risk 

that are reasonably likely to occur. 

Other factors include, but are not 

limited to, the prevailing meteorologic 

and oceanic conditions, which vary 

from year to year, and the location of 

proposed drilling. For example, in a 

year when the encroachment of sea ice 

is projected to occur later, an operator 

may be able to justify a later end of 

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season and avoid the need to cease 

drilling operations earlier than 

necessary. By contrast, in a year when 

the onset of sea ice is projected to occur 

earlier, the operator would need to plan 

to conclude on-site operations earlier. 

In projecting when to conclude onsite operations, BOEM and BSEE expect 

operators to be flexible and fully 

responsive to the latest ice and weather 

forecasts and the best available 

information for ensuring optimal timing 

for the end of on-site operations. Of 

course, after an EP is approved, an 

operator may request approval to revise 

its EP if available information regarding 

its operations and anticipated 

meteorologic and oceanic conditions 

change. 

For example, BOEM’s approval for 

Shell’s 2012 Arctic operations required 

drilling operations in zones where 

measurable quantities of liquid 

hydrocarbons were capable of flowing 

into the well to be concluded 38 days 

prior to November 1, based on satellite 

imagery showing the five-year historical 

average of earliest sea ice encroachment 

over Shell’s drill site and estimates of 

the time needed to drill a relief well. 

The purpose of this drilling hiatus was 

to reduce project risk by assuring a 

greater opportunity for response and 

cleanup in the unlikely event of a late 

season oil spill. 

BOEM and BSEE invite comments on 

what kinds of Arctic weather and ice 

forecasting options are currently (or 

expected to be) available for use by 

operators. In addition, comments may 

address other factors that should be 

considered in determining when on-site 

operations are expected to be 

completed, or when drilling into certain 

hydrocarbon zones should cease each 

year, given an operator’s response and 

cleanup capabilities. 

C. Additional Regulations Proposed by 

BSEE 

Authority 

The authority citation for 30 CFR part 

250 would be amended to add reference 

to 33 U.S.C. 1321(j)(1)(C). This statutory 

provision, in addition to section 5 of the 

OCSLA (43 U.S.C. 1334), provides 

authority to DOI for the portions of the 

proposed revisions to § 250.300 related 

to preventing discharge of petroleumbased mud and cuttings from operations 

that use petroleum-based mud. For 

further explanation of those provisions, 

see the discussion under that section. 

Definitions (§ 250.105) 

This section would be revised to add 

definitions for Arctic OCS, Arctic OCS 

Conditions, Cap and Flow System, 

Capping Stack, Containment Dome, and 

Source Control and Containment 

Equipment. For an explanation of the 

definitions of Arctic OCS and Arctic 

OCS Conditions, see the discussion of 

definitions at the beginning of the 

Section-by-Section analysis. The 

remaining definitions are necessary 

because these proposed regulations 

would require the defined systems and 

equipment under identified 

circumstances. In addition, the 

definition of District Manager would be 

revised for activities on the Alaska OCS 

such that District Manager would mean 

Regional Supervisor, because the 

Regional Supervisor in BSEE’s Alaska 

OCS region performs the District 

Manager’s duties. 

Cap and Flow System—this term 

would be defined to mean an integrated 

suite of equipment and vessels, 

including a capping stack and 

associated flow lines, that, when 

installed or positioned, is used to 

control the flow of fluids escaping from 

the well by conveying the fluids to the 

surface to a vessel or facility equipped 

to process the flow of oil, gas, and 

water. A cap and flow system is a high 

pressure system that includes the 

capping stack and piping necessary to 

convey the flowing fluids through the 

choke manifold to the surface 

equipment. When a responsible party 

has been able to successfully cap a well, 

but conditions will not allow the well 

to be shut in (e.g., due to damage, 

equipment failure or pressure 

constraints), the cap and flow system 

allows the well cap to be used as a 

connection for the flow lines that 

transport well fluids to the surface for 

capture and disposition. In some 

circumstances, this can relieve the 

pressure on the capping device or 

tubulars at the well head or in the well 

while maintaining or reestablishing 

control of the produced fluids, or a 

portion thereof. 

Capping Stack—this term would be 

defined to mean a mechanical device 

that can be installed on top of a subsea 

or surface wellhead or BOP to stop the 

flow of fluids into the environment. A 

capping stack’s primary function is to 

stop the uncontrolled flow of fluids 

from a well to the environment in the 

event that other intervention methods, 

such as a BOP, would fail. The capping 

stack is attached to a connector or pipe 

stub located on or in the well to achieve 

a pressure-tight seal that would either 

stop the flow or direct it into a conduit 

that would transmit the fluids to a 

surface facility that is able to store, 

process, or properly dispose of the 

fluids. Capping stacks may be deployed 

from the surface to the well head, as 

needed, or prepositioned below the riser 

system when the BOP is located on the 

deck of a MODU. The pre-positioned 

capping stack may be created by 

adapting an auxiliary subsea 

intervention device to meet the 

requirements of this proposed rule. 

Containment Dome—this term would 

be defined to mean a non-pressurized 

container that can be used to collect 

fluids escaping from the well or 

equipment below the sea surface or from 

seeps by suspending the device over the 

discharge or seep location. A 

containment dome, also known as a 

‘‘sombrero,’’ ‘‘cofferdam,’’ or ‘‘hat,’’ 

captures fluids after they have escaped 

the well, subsea equipment, or a seep, 

but before they have reached the 

surface. It consists of a structure that has 

the ability to capture fluids rising 

through the water column and to convey 

the fluids to a surface vessel or facility 

for processing or disposal. If a cap and 

flow system is unable to stop or control 

the flow of fluids to the environment, or 

the well system is so damaged that a 

capping stack cannot make a successful 

connection, the containment dome 

system would be needed to capture the 

hydrocarbons flowing to the 

environment. 

Source Control and Containment 

Equipment (SCCE)—SCCE would be 

defined to mean the capping stack, cap 

and flow system, containment dome, 

and/or other subsea and surface devices, 

equipment, and vessels whose collective 

purpose is to control a spill source and 

stop the flow of fluids into the 

environment or to contain fluids being 

discharged into the environment for 

proper processing or disposal. This 

definition is useful for referring 

collectively to the various independent 

elements of an operator’s SCCE in 

portions of the proposed rule that would 

apply to any such equipment and its 

capabilities as a unified system, rather 

than a specific type of SCCE (see, e.g., 

proposed § 250.470(f)). The SCCE serves 

the purpose of stopping or minimizing 

the flow of hydrocarbons into the 

environment after a loss of well control 

event has occurred. The term ‘‘surface 

devices’’ within the definition of SCCE 

refers to equipment mounted or staged 

on a barge, vessel, or facility. The 

purpose of this equipment is to separate, 

treat, store and/or dispose of fluids 

conveyed to the surface by the cap and 

flow system or the containment dome. 

The SCCE, however, does not include a 

BOP or similar equipment that is used 

in ordinary operations and functions to 

maintain well control under normal 

operational conditions or to prevent a 

loss of well control. Finally, ‘‘subsea 

devices’’ includes, but is not limited to, 

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remotely operated vehicles (ROV), 

anchors, buoyancy equipment, 

connectors, cameras, controls and other 

subsea equipment necessary to facilitate 

the deployment, operation and retrieval 

of the SCCE. 

What incidents must I report to BSEE 

and when must I report them? 

(§ 250.188) 

The current regulation requires 

operators to provide oral and written 

notification to the BSEE District 

Manager (who in the Alaska OCS region 

is the Regional Supervisor) of, among 

other things, any injuries, fatalities, 

losses of well control, fires and 

explosions, and incidents affecting 

operations. BSEE proposes to add a new 

paragraph (c) to this section that would 

require operators on the Arctic OCS 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 these activities, 

and any ‘‘kicks’’ or operational issues 

that are unexpected and could result in 

the loss of well control. 

Sea ice, if not properly managed, can 

have a major effect on exploratory 

drilling operations. Spring and summer 

thawing can produce large ice masses 

on the waters overlying the Arctic OCS, 

which could cause substantial damage 

to exploratory drilling equipment and 

render operations unsafe, leading to 

injury, loss of life, or environmental 

harm. For example, if the well is not 

properly protected, sea ice that is 

moving through the surrounding water 

could cause a loss of well control by 

damaging the well head and triggering 

the discharge of hydrocarbons into the 

marine environment. Ice management 

activities, as described in an operator’s 

ice management plan, could include 

physically changing the direction of an 

ice floe or using ice breaking techniques 

in order to minimize the likelihood of 

damage to the exploratory drilling 

equipment. 

It is essential for operators to remain 

in close communication with BSEE 

about sea ice in the area that has the 

potential to affect operations. Just as the 

operator needs to have sufficient time to 

act in the event that ice poses an 

operational hazard, BSEE would need 

sufficient time to oversee the safety of 

an operator’s reactions and prepare to 

respond if a response is necessary due 

to a safety or environmental incident 

resulting from an ice event. 

The proposed paragraph (c) would 

require the operator to immediately 

notify the BSEE inspector on location or 

the Regional Supervisor of any event 

that, pursuant to the hazard thresholds 

identified in its EP, would trigger a 

heightened observation requirement, or 

could potentially result in the need to 

physically manage ice, initiate 

operations to secure the well, or move 

the drilling rig to avoid a threat caused 

by floating ice. This provision would 

also require immediate oral notification 

of the commencement and completion 

of any ice management activities. 

The oral report required by this 

provision could be a simple direct oral 

notification of the basic facts 

surrounding the relevant circumstances, 

and would not need to contain all of the 

detail required of oral reports pursuant 

to § 250.189. The proposed provision 

would also require a follow-up written 

report regarding any ice management 

activities undertaken by the operator 

that must be submitted within 24 hours 

following completion of those activities. 

BSEE proposes this tighter 24-hour 

timeline (as opposed to, and in lieu of, 

the standard 15 day window under 

§ 250.190) due to the immediacy of the 

threats and concerns presented by 

circumstances requiring ice 

management activities, and the need for 

BSEE to remain abreast of those events 

in its regulatory and safety oversight 

role. The written report may be 

submitted via email or other electronic 

means to the inspector or Regional 

Supervisor and must conform to the 

content requirements set forth in 

§ 250.190. 

Finally, BSEE proposes to require that 

operators submit an immediate oral 

report of any ‘‘kicks’’ or operational 

issues that are unexpected and could 

result in the loss of well control. 

Operators on the Alaska OCS currently 

have to report kicks at the end of every 

day on the well activity report Form 

BSEE–0133, as required by § 250.468. 

However, the proposed requirements of 

this section mean operators would not 

be allowed to wait until the end of the 

day or some time later to fill out a form. 

If a kick occurred, they would have to 

provide an immediate oral report. The 

nature of Arctic OCS Conditions, as 

defined in this proposed rule, 

demonstrates that responding to a spill 

in the Arctic region would be a difficult 

task. Reporting kicks right away is a 

safety measure that can improve the 

ability of both inspectors and operators 

to potentially prevent a loss of well 

control. 

Documents incorporated by reference. 

(§ 250.198) 

The proposed rule would add 

subsection (h)(89) to existing § 250.198 

as a reference to the American 

Petroleum Institute (API) proposed draft 

Recommended Practice (RP) 2N, 

Recommended Practice for Planning, 

Designing, and Constructing Structures 

and Pipelines for Arctic Conditions, 

Third Edition. This document will be a 

voluntary consensus standard 

addressing the unique Arctic OCS 

Conditions that affect the planning, 

design, and construction of systems 

used in Arctic and sub-Arctic 

environments. This API document— 

which is virtually identical to a 

standard previously issued by the 

International Organization for 

Standardization (ISO), ‘‘Petroleum and 

Natural Gas Industries Arctic Offshore 

Structures,’’ First Edition (2010) (ISO 

19906)—would be appropriate for 

certain aspects of drilling operations, 

such as accounting for the severe 

weather and thermal effects on 

structures, maintenance procedures, and 

safety. Since this proposed rule is 

focused on the exploratory drilling 

phase of operations on the Arctic OCS, 

certain portions of API RP 2N, Third 

Edition (such as those related to issues 

regarding structural and pipeline 

integrity) would not be relevant to the 

exploration stage. However, many 

elements of that document, when 

published, could be effectively applied 

to equipment used in exploratory 

drilling operations on the Arctic OCS. 

Therefore, proposed §§ 250.198(h)(89) 

and 250.470(g) would incorporate 

appropriate elements of API RP 2N, 

Third Edition, for purposes of APD 

information requirements. 

A voluntary consensus standard 

indicates acceptance and recognition 

across the industry that certain 

technology is feasible. For example, API 

standards are created with input from 

oil and gas operators, drilling 

contractors, service companies, 

consultants, and regulators. Even 

though the development of a consensus 

standard does not necessarily represent 

a unanimous agreement by the 

developing body’s members, the API 

process provides a means for industry 

and regulatory bodies to provide input 

into the development of protocols for 

the highly specialized equipment and 

procedures used in oil and gas 

operations. In the National Technology 

Transfer and Advancement Act of 1995 

(Pub. L. 104–113, 15 U.S.C. 3701 note), 

Congress directed Federal agencies to 

use technical standards that are 

developed or adopted by voluntary 

consensus standards bodies in lieu of 

government-unique standards, unless 

inconsistent with applicable law or 

otherwise impractical (see OMB 

Circular A–119 (Revised), February 

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5To access a standard at that API Web site, first 

log-in or create a new account, accept API’s ‘‘Terms 

and Conditions,’’ then click on the ‘‘Browse 

Documents’’ button, and then select the applicable 

category (e.g., ‘‘Exploration and Production’’) for 

the particular standard(s) you wish to review. 

6Copies of the ISO standards referred to in this 

proposed rule may also be viewed, upon request, 

at BSEE’s Regional Offices for Alaska (3801 

Centerpoint Dr., Suite 500, Anchorage, AK; 907– 

334–5300), the Pacific (760 Paseo Camarillo, 

Camarillo, CA; 805–384–6300), and the Gulf of 

Mexico (1201 Elmwood Park Blvd., Nw Orleans, 

LA; 1–800–672–2627) and at BSEE’s Houston office 

(701 San Jacinto St., Rm. 115, Houston, TX; 713– 

220–9201). 

1998, available at www.standards.gov/

standards_gov/nttaa.cfm). 

BSEE frequently uses standards (e.g., 

codes, specifications, RPs) developed 

through a consensus process, facilitated 

by standards development organizations 

and with input from the oil and gas 

industry, as a means of establishing 

requirements for activities on the OCS. 

BSEE may incorporate these standards 

into its final regulations without 

publishing the standards in their 

entirety in the Code of Federal 

Regulations, a practice known as 

incorporation by reference. The legal 

effect of incorporation by reference is 

that the incorporated standards become 

regulatory requirements. Material 

incorporated in a final rule, like any 

other properly issued regulation, has the 

force and effect of law, and BSEE holds 

operators, lessees and other regulated 

parties accountable for complying with 

the documents incorporated by 

reference in its final regulations. BSEE 

currently incorporates by reference over 

100 consensus standards in its offshore 

regulations governing oil and gas 

operations (see 30 CFR 250.198). 

Federal regulations at 1 CFR part 51 

govern how BSEE and other Federal 

agencies incorporate various documents 

by reference. Agencies may only 

incorporate a document by reference in 

a final rule by publishing the document 

title, edition, date, author, publisher, 

identification number and other 

specified information in the Federal 

Register. The Director of the Federal 

Register must approve each publication 

incorporated by reference in a final rule. 

Incorporation by reference of a 

document or publication in a final rule 

is limited to the specific edition 

approved by the Director of the Federal 

Register. 

Availability of Incorporated Documents 

for Public Viewing 

When a copyrighted industry 

standard is incorporated by reference 

into our regulations, BSEE is obligated 

to observe and protect that copyright. 

We typically provide members of the 

public with Web site addresses where 

these standards may be accessed for 

viewing—sometimes for free and 

sometimes for a fee. The decision to 

charge a fee is made by each standards 

development organization. The API 

provides free online public access to at 

least 160 key industry standards, 

including a broad range of technical 

standards. Those standards represent 

almost one-third of all API standards 

and include all that are safety-related or 

are incorporated into Federal 

regulations. These standards are 

available for review, and hard copies 

and printable versions will continue to 

be available for purchase through API. 

BSEE proposes to incorporate, with 

certain exclusions discussed later in this 

proposed rule, draft proposed API RP 

2N, Third Edition, which is available for 

free public viewing during the API 

balloting process on API’s Web site at 

http://mycommittees.api.org/standards/

ecs/sc2/default.aspx (click on the title 

of the document to open). When 

finalized by API, that standard will be 

available for free public viewing on 

API’s Web site at: http://

publications.api.org.5

In addition, as explained later in this 

proposed rule, BSEE is considering 

incorporating by reference ISO 19906 in 

lieu of API RP 2N, Third Edition. ISO 

standards are available for purchase 

from ISO at ISO’s publications Web site 

at: http://www.iso.org/iso/home/store/

catalogue_ics.htm or from commercial 

vendors.6

For the convenience of the viewing 

public who may not wish to purchase or 

view incorporated documents online, 

they may be inspected, upon request, at 

our office, 381 Elden Street, Room 3313, 

Herndon, Virginia 20170 (phone: 703– 

787–1587); or at the National Archives 

and Records Administration (NARA). 

For information on the availability of 

materials at NARA, call 202–741–6030, 

or go to: www.archives.gov/federalregister/cfr/ibr-locations.html. 

If API RP 2N, Third Edition, is 

incorporated into the final rule, it would 

continue to be made available for public 

viewing, when requested, at the 

addresses indicated in the prior 

paragraph. Specific information on 

where incorporated documents can be 

inspected or obtained is also found at 

§ 250.198, Documents incorporated by 

reference. 

Pollution prevention. (§ 250.300) 

This section would revise BSEE’s 

pollution prevention regulation as it 

pertains to Arctic OCS exploratory 

drilling operations. Spent mud and 

cuttings are generated during 

exploratory drilling. Drilling mud may 

be entirely water-based or may include 

petroleum (i.e., oil) as a component. 

Cuttings generated using petroleumbased mud would be oil-contaminated, 

and the discharge of the mud or cuttings 

into the environment would result in 

discharge of that oil into the 

environment. The proposed rule would 

add provisions in paragraphs (b)(1) and 

(b)(2) requiring that, during exploratory 

drilling operations on the Arctic OCS, 

the operator must capture all petroleumbased mud, and associated cuttings from 

operations that use petroleum-based 

mud, to prevent their discharge into the 

marine environment. These 

subparagraphs would also clarify the 

Regional Supervisor’s discretionary 

authority to require operators to also 

capture all water-based mud 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: 

1. The proximity of the exploratory 

drilling operations to subsistence 

hunting and fishing locations; 

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. 

BSEE regulates discharges of mud and 

cuttings from OCS facilities under the 

OCSLA, which contemplates the 

imposition of environmental safeguards 

for oil and gas activities on the OCS and 

mandates that they be conducted in a 

manner that prevents or minimizes the 

likelihood of damage to the 

environment. The President has also 

delegated authority to the Secretary 

(further delegated to BSEE) to regulate 

discharges of oil under Section 311 of 

the CWA, 33 U.S.C. 1321, which calls 

for the issuance of regulations 

establishing procedures, methods, and 

equipment to prevent discharges of oil 

and hazardous substances from offshore 

facilities, and to contain such 

discharges. BSEE’s pollution prevention 

regulations are intended to complement 

requirements imposed by the EPA under 

the CWA. For example, in November 

2012, the EPA issued general National 

Pollutant Discharge Elimination System 

(NPDES) permits authorizing certain 

discharges from oil and gas exploratory 

facilities to Federal waters in the 

Beaufort Sea and the Chukchi Sea, 

including certain discharges of waterbased drilling fluids and drill cuttings, 

subject to effluent limitations and other 

requirements. Of note, the EPA NPDES 

permits do not allow the discharge of 

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oil-based drilling fluids, or the 

discharge of water-based drilling fluids 

and drill cuttings during the fall 

bowhead whale hunt in the Beaufort 

Sea. BSEE’s proposed regulations clarify 

the Regional Supervisor’s authority to 

impose operational measures that 

complement EPA’s discharge limitations 

by considering potential impacts to 

specific components of the Arctic 

environment, such as subsistence 

activities, marine resources, and coastal 

areas. 

The discharge of mud and cuttings 

has the potential to affect marine 

mammals, fish, and their habitat, as well 

as subsistence activities present in the 

Arctic region. As noted earlier, 

subsistence hunting is central to the 

food supply and cultural traditions of 

many Alaska Natives. BSEE proposes to 

clarify its authority to limit discharges 

of any mud and cuttings having the 

potential to adversely impact marine 

wildlife or to disrupt subsistence 

hunting activities. 

For example, existing environmental 

analyses show that the release of drill 

cuttings and drilling mud would result 

in increased turbidity and 

concentrations of total suspended solids 

in the water column, which could 

displace marine mammals from the drill 

sites and could adversely affect habitat 

and prey within and around the drill 

site (see Shell Gulf of Mexico, Inc.’s 

Revised Chukchi Sea Exploration Plan 

Burger Prospect Environmental 

Assessment (2011)). In addition, 

subsistence hunters, who rely on 

traditional ecological knowledge, have 

expressed concern to BOEM and BSEE 

that whales are capable of detecting the 

odors from mud and cuttings and will 

avoid areas where these discharges 

occur, resulting in similar effects. 

Hunting farther away from shore to find 

displaced whales can increase transit 

time, reduce the likelihood of successful 

harvests, increase exposure to adverse 

weather and dangerous sea states, and 

increase safety concerns for subsistence 

hunters. Finally, the farther away 

whales are harvested from a community, 

the greater the length of towing time 

necessary to bring the animals back to 

shore for processing. This increased tow 

time could negatively affect the viability 

of the meat and blubber for food because 

of spoilage. 

Marine mammal migrations and 

subsistence hunting patterns vary 

greatly in different areas of the Arctic 

region and at different times of the year. 

These proposed rules would therefore 

clarify the Regional Supervisor’s 

discretion to require the capture of 

water-based mud and cuttings, taking 

into account location- and seasonspecific circumstances (such as 

subsistence hunting). In addition, other 

relevant circumstances, such as 

applicable provisions of a NPDES 

general permit, can be considered when 

exercising that discretionary authority. 

BSEE invites comments on the potential 

costs to the industry of limiting or 

prohibiting the discharge of mud and 

cuttings that otherwise would not be 

prohibited by the NPDES general 

permits. 

When and how must I secure a well? 

(§ 250.402) 

The current regulation requires, 

among other things, that operators 

install a downhole safety device at an 

appropriate depth whenever there is an 

interruption in drilling operations. 

BSEE proposes to add a new paragraph 

(c)(1), which would require exploratory 

drilling operators on the Arctic OCS to 

ensure that any equipment left on, near, 

or in a temporarily abandoned well that 

has penetrated below the surface casing 

be secured in a way that would protect 

the well head and prevent or minimize 

the likelihood of the integrity of the well 

or plugs being compromised. The 

primary concern this proposed language 

is designed to address is the possibility 

that ice floes could sever, dislodge, or 

drag any exploration-related equipment, 

obstructions or protrusions left on the 

well or the adjacent seafloor. The 

proposed language, however, is drafted 

to encompass damage from any 

foreseeable source. The provision in 

paragraph (c)(1) is designed to be 

performance-based, would allow 

operators to devise optimal strategies for 

identifying and accounting for threats to 

the integrity of equipment left on the 

OCS, and would be limited only to 

exploration wells that have penetrated 

below the surface casing. However, for 

exploration wells located in an area 

subject to ice scour, based on a shallow 

hazards survey, proposed paragraph 

(c)(2) would require a mudline cellar or 

equivalent means of protection. The 

BSEE Regional Supervisor will evaluate, 

during the APD process, whether a 

proposed equivalent approach is 

sufficiently protective. 

There are a number of problems that 

could occur if operators did not adhere 

to this proposed requirement. For 

example, if an ice floe were to contact 

equipment left on, near, or in a well that 

had penetrated hydrocarbons, the 

impact could damage the well and 

potentially compromise the cement, 

casing, or safety valves and plugs inside 

the well and could result in the 

discharge of hydrocarbons. 

What additional information must I 

submit with my APD? (§ 250.418) 

BSEE proposes to add a new 

paragraph (k) to this section, providing 

that the information identified in 

proposed § 250.470 must be submitted 

with an APD for exploratory drilling on 

the Arctic OCS. The information 

required in the proposed section would 

be necessary to inform BSEE’s 

evaluation of APDs for Arctic OCS 

exploratory drilling operations (see 

discussion of proposed § 250.470). 

When must I pressure test the BOP 

system? (§ 250.447) 

The current regulation requires 

operators to pressure test a BOP system 

when it is installed, at specified time 

intervals, and prior to drilling out each 

string of casing or a liner. BSEE 

proposes to revise paragraph (b) of this 

section to require a BOP pressure test 

frequency of one test every 7 days for 

Arctic OCS exploratory drilling 

operations. However, there is some 

debate over whether more frequent 

testing, beyond the 14-day test 

frequency prescribed by existing 

regulations, would be necessary or 

advisable. 

The effectiveness of hydrostatic 

pressure testing of BOPs has been 

questioned in the past. The industry has 

argued that increasing the number of 

pressure tests: (1) may reduce the 

reliability of the equipment by 

degrading the sealing capability of the 

elements within the BOP stack; and (2) 

does not necessarily demonstrate the 

future performance of the equipment. 

Furthermore, the industry has claimed 

that the requirement for operators to 

stop drilling operations to perform a 

pressure test could ultimately increase 

the likelihood of an incident occurring. 

Due to these safety and cost concerns, 

the industry has sought to reduce the 

current testing frequency for this 

equipment (i.e., to longer than every 14 

days). 

Ensuring the proper functioning of a 

BOP, which is a critical line of defense 

against loss of well control, is essential 

to Arctic OCS drilling operations. BSEE 

is concerned that the integrity of BOPs 

could be compromised by Arctic 

conditions; in particular, BSEE is 

concerned about the possible effects of 

extreme weather conditions on BOPs 

maintained on surface vessels or 

facilities (such as jackup rigs). At this 

time, pressure tests and functional tests 

are the primary methods for ensuring 

the performance of BOPs. A 7-day BOP 

testing cycle was proposed by Shell in 

2012, and ultimately approved by BSEE, 

and we propose to require a similar 

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testing frequency for all Arctic OCS 

exploratory drilling operations. BSEE 

specifically requests comments on the 

appropriateness of the proposed 7-day 

testing frequency to demonstrate the 

reliability of the equipment under 

Arctic conditions. BSEE also requests 

that commenters identify any additional 

safety issues that might arise from this 

increased testing and that would be 

unique to Arctic operations. In addition, 

BSEE invites comments on all potential 

drilling impacts related to the proposed 

7-day testing frequency. 

Note that the only proposed changes 

to the existing BOP testing regulation 

are the phrases specific to exploratory 

drilling on the Arctic OCS. The 

remaining language is identical to the 

wording currently at § 250.447(b) and is 

duplicated in this proposed rule for 

readability. 

What are the real-time monitoring 

requirements for Arctic OCS exploratory 

drilling operations? (§ 250.452) 

BSEE proposes to add a new 

performance-based section in Part 250 

that would require real-time data 

gathering on the BOP control system, 

the fluid handling systems on the rig, 

and, if a downhole sensing system is 

installed, the well’s downhole 

conditions during Arctic OCS 

exploratory drilling operations. In 

addition, this section would require 

operators to transmit immediately the 

data during operations to an onshore 

location, identified to BSEE prior to 

well operations, where it must be stored 

and monitored by personnel who would 

be capable of interpreting the data and 

have the authority, in consultation with 

rig personnel, to initiate any necessary 

action in response to abnormal events or 

data. Such personnel must also have the 

capability for continuous and reliable 

contact with rig personnel, to ensure the 

ability to communicate information or 

instructions between the rig and 

onshore facility in real-time, while 

operations are underway. 

This section would be added, in part, 

based on multiple recommendations 

from various Deepwater Horizon 

investigation reports. Having the realtime, well-related data available to 

onshore personnel would increase the 

level of oversight of well conditions 

during operations. Onshore personnel 

could review data and help rig 

personnel conduct operations in a safe 

manner. Also, onshore personnel would 

be able to assist the rig crew in 

identifying and evaluating abnormalities 

that might arise during operations. This 

section would also require that the realtime monitoring data be available to 

BSEE upon request, to enable BSEE to 

perform its oversight role and to 

monitor responses to events as they 

unfold. Finally, this section would, 

consistent with §§ 250.466 and 250.467, 

require that the data gathered be stored 

at a designated location for 

recordkeeping purposes after operations 

have concluded, to enable BSEE to 

perform audits, investigations, or other 

types of analyses, as part of its 

regulatory oversight functions. 

The following undesignated centered 

heading would be inserted above 

proposed § 250.470: 

Additional Arctic OCS Requirements 

What additional information must I 

submit with my APD for Arctic OCS 

exploratory drilling operations? 

(§ 250.470) 

BSEE proposes to add § 250.470, 

which would require operators to 

provide Arctic OCS-specific information 

with their APDs for exploratory drilling. 

The proposed informational 

requirements in the new section would 

be necessary to inform BSEE’s 

evaluation of APDs for Arctic OCS 

exploratory drilling operations. 

Paragraph (a), Fitness for Service 

This provision would require 

operators to submit a detailed 

description of the environmental, 

meteorologic and oceanic conditions 

expected at the well site(s); how their 

equipment, materials, and drilling unit 

will be prepared for service in the 

conditions, and how the drilling unit 

will be in compliance with the 

requirements of § 250.417. For this 

proposed requirement, BSEE would 

expect the operator to identify the 

specific drilling units proposed for use 

during its operations, verify that the 

identified equipment and materials are 

fit for service, and that the drilling units 

conform to the fitness for service 

requirements of § 250.417. It is 

important that operators provide this 

level of detail to ensure that the 

equipment, materials, and drilling units 

proposed for use in Arctic OCS 

exploratory drilling are capable of 

performing their respective tasks under 

Arctic OCS Conditions. 

The information requested by this 

proposed section for drilling units is not 

in addition to the requirements of 

§ 250.417, but rather is designed to 

make clear that, to satisfy the fitness 

requirements of § 250.417, operators 

would need to provide details regarding 

Alaska OCS Conditions. Further, BSEE 

does not currently have an existing 

provision for drilling equipment and 

materials that requires the same level of 

detail found in § 250.417 for drilling 

units. 

BSEE’s current regulations concerning 

fitness for other types of equipment and 

material are more general and 

performance-based than the 

requirements proposed in this rule for 

Arctic OCS operations. Additionally, 

since SCCE is a new suite of equipment 

and materials proposed by this rule, 

there are no existing fitness for service 

regulations covering these items. 

Therefore, the information required 

under proposed paragraph (a) for 

equipment and materials would be new. 

Paragraph (b), Well-specific Transition 

Operations 

This provision would require 

operators to submit ‘‘[a] detailed 

description of all operations necessary 

in Arctic OCS Conditions to transition 

the rig from being under way to 

conducting drilling operations and from 

ending drilling operations to being 

under way, as well as any anticipated 

repair and maintenance plans for the 

drilling unit and equipment.’’ BSEE 

does not intend for this provision to 

require operators to resubmit any 

information already submitted to 

BOEM. Rather, BSEE would expect 

operators to have a fairly detailed plan 

when they submit their APD, including 

information such as the identity of 

equipment and vessels to be used, dates 

of planned operations, and a description 

of how the equipment and vessels 

would be designed for and be capable of 

performing in Arctic OCS Conditions. 

For transition operations, BSEE would 

need details about all of the activities 

necessary to begin and end drilling 

operations, and to move from one 

drilling location to the next. Examples 

of the types of activities BSEE would 

expect an operator to describe include, 

but are not limited to: recovering the 

subsea equipment, including the marine 

riser and the lower marine riser 

package; recovering the BOP; recovering 

the auxiliary sub-sea controls and 

template; laying down the drill pipe and 

securing the drill pipe and marine riser; 

securing the drilling equipment; 

transferring the fluids for transport or 

disposal; securing ancillary equipment 

like the draw works and lines; refueling 

or transferring fuel; offloading waste; 

recovering the ROVs; picking up the oil 

spill prevention booms and equipment; 

and offloading the drilling crew. 

Finally, BSEE would require 

information regarding any specific 

repair and maintenance plans for the 

drilling unit and equipment associated 

with commencement or completion of 

drilling operations. All of the required 

information would facilitate BSEE’s 

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understanding of an operator’s program 

and ensure that the operator complies 

with lease stipulations, EP conditions, 

and other permitting requirements. 

Paragraph (c), Well-specific Drilling 

Objectives and Contingency Plans 

This provision would require 

operators to submit ‘‘[w]ell-specific 

drilling objectives, timelines, and 

updated contingency plans for 

temporary abandonment of the well.’’ 

Whereas the corresponding provisions 

of the proposed IOP and current EP 

regulations (e.g., § 550.211) relate more 

broadly to the objectives and timelines 

of the overall proposed exploratory 

drilling activities, this provision would 

require an operator to provide ‘‘wellspecific’’ information at the APD stage. 

This information would include the 

operator’s detailed schedule of the 

following: 

1. When they will spud the particular 

well (i.e., begin drilling operations at the 

well site) identified in the APD; 

2. How long will it take to drill the 

well; 

3. Anticipated depths and geologic 

targets, with timelines; 

4. When the operator expects to set 

and cement each string of casing; 

5. When and how the operator would 

log the well; 

6. The operator’s plans to test the 

well; 

7. When and how the operator would 

abandon the well, including specifically 

addressing plans for how to move the 

rig off location and how the operator 

would meet the requirements of 

proposed § 250.402(c); 

8. A description of what equipment 

and vessels would be involved in the 

process of temporarily abandoning the 

well due to ice; and 

9. An explanation of how these 

elements would be integrated into the 

operator’s overall program. 

Examples of the information the 

operator would be required to provide 

include, but are not limited to: the 

location(s) to which the rig would be 

moved; the operator’s plans for safely 

securing the well prior to leaving the 

drill site; how temporary abandonment 

would affect the operator’s seasonal 

drilling plans, including its remaining 

schedule of operations at each well; and 

how crew logistics, such as 

transportation to and from a drilling rig, 

would be affected. 

It should be noted that the 

contingency plans proposed in this 

section of the rule are different from the 

contingency plans required for ‘‘icing or 

ice-loading’’ under existing 

§ 250.417(c)(2). That phrase refers to ice 

build-up on the vessel or equipment 

itself, whereas the focus of proposed 

§ 250.470(c) is on ice management, 

meaning the contingency plans for 

response to the presence of ice in the 

water, such as temporary abandonment 

of a well until the ice in the water 

passes, or management through some 

other technique. For oil and gas 

exploration, ice management is an 

Arctic OCS-specific issue that does not 

occur elsewhere on the OCS. However, 

icing and ice-loading can occur during 

operations on other parts of the OCS, 

outside of the Arctic. 

Paragraph (d), Weather and Ice 

Forecasting and Management 

This performance-based provision 

would require an operator to submit: a 

detailed description of its ‘‘weather and 

ice forecasting capability for all phases 

of the drilling operation, including how 

[it] will ensure continuous awareness of 

potential weather and ice hazards at, 

and during transition between, wells;’’ 

its ‘‘plans for managing ice hazards and 

responding to weather events;’’ and 

verification that it has the capabilities 

described in its EP. Verification could 

be provided, for example, by providing 

appropriate supporting documents (e.g., 

contracts) for the forecasting and ice 

management capabilities. 

BSEE needs to know the details for 

how the operator would implement the 

policies and/or plans for managing ice 

and weather events, identified to BOEM, 

for the drilling operations proposed in 

the APD. It is anticipated that the 

operator may not know the specific 

details about each vessel and piece of 

equipment that contributes to its 

weather and ice forecasting and 

management capabilities when 

describing those capabilities to BOEM, 

in connection with the IOP and the EP. 

Also, more detailed plans for managing 

ice hazards or weather events may be 

necessary and appropriate given the 

timing and location of the specific well 

at issue than may have been available or 

appropriate for the IOP and EP. Further, 

BSEE anticipates that weather and ice 

monitoring and forecasting capabilities 

may evolve between the approval of the 

EP and the submittal of the APD, which 

could yield better data, especially when 

operations commence. Therefore, this 

proposed provision would require the 

operator to submit the specific detailed 

information to BSEE in connection with 

its APD and also to describe, in more 

detail and closer in time to 

commencement of drilling, how it 

would implement its weather and ice 

forecasting and management plan. 

BSEE would expect operators to 

identify the specific weather and ice 

forecasting equipment and vessels that 

they intend to utilize, including the 

name of the contractor that would 

deliver satellite imagery, if applicable. 

Such information should also be 

specific to the location and operations 

associated with the well that is the 

subject of the particular APD. 

Finally, BSEE would require that an 

operator’s weather and ice management 

capabilities would be uninterrupted for 

the entirety of their operations while on 

the Arctic OCS. This provision proposes 

that there would be no gap in weather 

and ice monitoring activities, including 

during transit between wells. This is to 

ensure that, upon arrival at a new well 

location, there are no unexpected 

weather or ice hazards that would 

interfere with drilling operations at the 

new location, or would pose a threat to 

the safety or integrity of the drilling 

equipment or personnel. The purpose of 

this proposed requirement is to ensure 

that hazards to drilling operations are 

avoided or managed before they could 

become a danger or an interruption to 

operations. 

Paragraph (e), Relief Rig Plan 

Paragraph (e) would require operators 

to provide, with their APD, information 

concerning how they would comply 

with the relief rig requirements of 

proposed § 250.472. See the discussion 

of that provision for an explanation of 

the nature of, and need for, those 

requirements. 

Paragraph (f), SCCE Capabilities 

Paragraph (f) would require operators 

who propose to use a MODU to conduct 

exploratory drilling operations on the 

Arctic OCS to provide with their APD 

information concerning their required 

SCCE capabilities when they are drilling 

below or working below the surface 

casing, including a statement that the 

operator owns, or has a contract with a 

provider for, SCCE capable of 

controlling and/or containing its 

identified WCD. Ensuring that an 

operator would be capable of 

responding to a loss of well control is 

one of the key goals of this proposed 

rule. In other parts of the OCS (e.g., the 

Gulf of Mexico), there are several wellestablished contractors readily available 

to operators and extensive operations 

and infrastructure within the region 

from which resources could be drawn to 

respond to an event. However, resources 

are limited in the Arctic region due to 

the remote location and relative lack of 

infrastructure and operations. Therefore, 

operators proposing to conduct 

exploratory drilling on the Arctic OCS 

must demonstrate that they would have 

access to, and be capable of promptly 

deploying, adequate SCCE. Operators 

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must also describe how they would 

inspect, test, and maintain this 

equipment in order to ensure that it 

would remain fully functional and 

ready for use. These proposed 

requirements would help assure BSEE 

that operators conducting exploratory 

drilling under Arctic OCS Conditions 

are capable of: (1) Regaining control 

after a loss of well control event or (2) 

containing escaping fluids from a loss of 

well control event. The information 

requirements of paragraph (f) would 

include: 

1. A detailed description of the 

operator’s or its contractor’s SCCE 

capabilities. The description must 

include operating assumptions and 

limitations and information 

demonstrating that the operator would 

have access to and the ability to deploy 

such equipment necessary to regain 

control of the well. This description 

would allow BSEE to verify the location 

and availability of this equipment for 

compliance with proposed § 250.471. 

2. An inventory of the equipment, 

supplies, and services the operator owns 

or has a contract for locally and 

regionally, including the identification 

of each supplier. This information is 

important because BSEE would need to 

verify the existence, condition, and 

location of the equipment that the 

operator describes in its plans. 

3. Where SCCE capabilities are 

obtained through contracting, proof of 

contracts or membership agreements 

with cooperatives, service providers, or 

other contractors, including information 

demonstrating the availability of the 

personnel and/or equipment on a 24- 

hour per day basis during operations 

below the surface casing. In an effort to 

minimize the environmental and social 

footprint of, and economic impediments 

to, Arctic OCS operations, BSEE is 

encouraging operators to share 

resources, especially standby 

equipment. This provision would 

facilitate the identification of those 

assets, and would allow BSEE to verify 

the contractual basis of any agreements 

necessary to provide the services 

required. 

4. A description of the procedures for 

inspecting, testing, and maintaining 

SCCE. SCCE is intended to be standby 

equipment. However, BSEE needs to be 

assured that the equipment would 

remain able to function if it were 

needed. This provision would allow 

BSEE to verify that the operator, or 

contractor, has procedures in place for 

inspecting, testing, and maintaining the 

equipment so that it would be ready for 

use, if necessary. Operators are already 

required under existing regulations at 

§ 250.1916 to retain the information 

requested by this proposed new 

paragraph. The proposed provision 

would require that operators who 

propose to conduct exploratory drilling 

on the Arctic OCS submit this 

information in conjunction with their 

APD. 

5. A description of the operator’s plan 

to ensure that personnel are trained to 

deploy and operate the equipment and 

that they would maintain ongoing 

proficiency in source control operations. 

Standby crews who are not used 

regularly to perform their dedicated 

functions would not develop the 

necessary skills unless they are properly 

trained, and would not maintain those 

skills unless that training is reinforced 

by practice. It is therefore imperative 

that the operator demonstrate that these 

personnel have a plan for acquiring, and 

the ability to maintain, the proficiency 

necessary to respond when called upon. 

This requirement would allow BSEE to 

review those plans and verify that the 

proficiencies have been acquired and 

would be maintained. 

Paragraph (g), API RP 2N, Third Edition 

Paragraph (g) would require that 

operators explain how they utilized API 

RP 2N, Third Edition, in planning their 

Arctic OCS exploratory drilling 

operations. The API is updating this RP 

by adopting the entirety of ISO standard 

‘‘Petroleum and natural gas industries 

Arctic offshore structures,’’ First Edition 

(2010) (ISO 19906). Since the 

requirements of this proposed rule are 

limited only to exploratory drilling 

operations, operators would not be 

expected to provide an explanation of 

how they utilized the entire API RP 2N, 

Third Edition. This performance-based 

requirement would be limited to those 

portions of that document that are 

specifically relevant for exploratory 

drilling operations. BSEE proposes to 

exclude the following sections of API 

RP 2N, Third Edition, from 

incorporation: 

1. sections 6.6.3 through 6.6.4; 

2. the foundation recommendations in 

section 8.4; 

3. section 9.6; 

4. the recommendations for 

permanently moored systems in section 

9.7; 

5. the seismic analysis 

recommendations for pile foundations 

in section 9.10; 

6. section 12; 

7. section 13.2.1; 

8. sections 13.8.1.1, 13.8.2.1, 13.8.2.2, 

13.8.2.4 through 13.8.2.7; 

9. sections 13.9.1, 13.9.2, 13.9.4 

through 13.9.8; 

10. sections 14 through 16; and 

11. section 18. 

Sections 6.6.3 and 6.6.4 would be 

excluded because they address different 

types of conditions for ice gouging and/ 

or scouring than are anticipated to occur 

during the Alaska Arctic open water 

drilling season. The foundation criteria 

of section 8.4, the piled structure 

criteria of section 9.6, the requirements 

for permanently moored systems in 

section 9.7, and the requirements for 

seismic analysis of pile foundations in 

section 9.10 would be excluded because 

this rule only applies to MODUs drilling 

on a temporary basis, as opposed to the 

more permanent types of structures 

addressed in those provisions. 

Similarly, section 12 would be excluded 

because it applies only to fixed concrete 

structures and is outside the scope of 

this proposed rule. Section 13.2.1 

(design philosophy for floating 

structures) would be excluded because 

similar ice forecasting and management 

issues are covered separately under 

proposed § 250.470(d). Sections 

13.8.1.1, 13.8.2.1, 13.8.2.2, 13.8.2.4 

through 13.8.2.7, 13.9.1, 13.9.2, and 

13.9.4 through 13.9.5, would be 

excluded because they cover vessel 

design and procedures requirements 

under USCG jurisdiction. Sections 

13.9.6 (inspection and maintenance), 

13.9.7 (operations and planning for 

safety of personnel, the environment, 

and equipment), and 13.9.8 (ice 

management plans) would be excluded 

because similar requirements are 

addressed by other provisions of this 

proposed rule. Section 14 would be 

excluded because it relates only to 

subsea production systems while this 

proposed rule applies to MODUs 

engaged in exploratory drilling activities 

and because this rule proposes a 

different set of requirements for BOPs 

from that set forth in section 14.3.3. 

Section 15 (topsides design and 

operation) would be excluded because it 

does not generally apply to MODUs, and 

any parts that could be utilized for 

MODUs fall under USCG jurisdiction. 

Section 16 (ice engineering topics) 

would be excluded because it applies to 

structures that will remain in the ice 

and does not apply to MODUs. Section 

18 (escape, evacuation and rescue) 

would be excluded because its 

provisions are already addressed under 

existing 30 CFR part 250 Subpart S and 

USCG rules. 

BSEE recognizes that, when applied 

to MODUs, many of the structural 

criteria of API RP 2N, Third Edition, are 

regulated by the USCG and may be 

covered by Class requirements for 

marine structures. Classification is a 

determination made by private 

organizations (in accordance with USCG 

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7Copies of ISO 19905–1 may be purchased from 

ISO on its Web site (at http://www.iso.org/iso/ 

home/store/catalogue_ics.htm) or from commercial 

vendors. Copies of the ISO standards referred to in 

this proposed rule may also be viewed, upon 

request, at BSEE’s Herndon, VA, office (at the 

address previously) indicated or at BSEE’s Regional 

Offices for Alaska, the Pacific, and the Gulf of 

Mexico. 

requirements) that a vessel has been 

constructed and maintained in 

compliance with industry standards to 

be fit for a particular service, in this case 

Ice Class 3. Therefore, application of 

API RP 2N, Third Edition, for the 

purposes of this proposed rule would be 

limited to the non-marine structural 

components of MODUs. For example, 

Class requirements do not cover the 

derrick, plumbing, pipes, tubing, and 

pumps that are all also structural 

components of a MODU and that fall 

under BSEE jurisdiction. If incorporated 

in the final rule, BSEE would expect 

operators to comply with API RP 2N, 

Third Edition, for MODU components 

within BSEE jurisdiction. BSEE and the 

USCG have signed a Memorandum of 

Agreement for MODUs outlining the 

allocation of responsibilities between 

the agencies for fixed offshore facilities 

available at: www.bsee.gov/BSEENewsroom/Publications-Library/ 

Interagency-Agreements/; click on the 

link for 2013 BSEE/USCG MOA: OCS– 

08. 

BSEE specifically requests comment 

on proposed draft API RP 2N, Third 

Edition, and on the extent to which 

BSEE should incorporate its provisions 

when finalized into the regulations. As 

an alternative to incorporation of API 

RP 2N, Third Edition, BSEE is 

considering incorporation by reference 

of ISO 19906, the ISO Arctic standard 

on which API RP 2N, Third Edition, is 

based. If BSEE incorporates the ISO 

standard in lieu of the API standard, the 

final rule would exclude the sections of 

the ISO standard corresponding to the 

excluded sections of API RP 2N 

previously discussed. BSEE requests 

comments on whether and to what 

extent BSEE should incorporate ISO 

19906 in lieu of proposed draft API RP 

2N, Third Edition. 

BSEE is also considering 

incorporating the ISO standard 

‘‘Petroleum and natural gas industries— 

Site-specific assessment of mobile 

offshore units—Part 1: Jack-ups,’’ First 

Edition (2012) (ISO 19905–1), into the 

final rule, with application limited only 

to Arctic OCS exploratory drilling 

operations. ISO 19905–1 may be better 

suited than API RP 2N (or ISO 19906) 

to guide structural components for jackup rigs. The API RP 2N (or ISO 19906) 

and ISO 19905–1 documents together 

would provide the most comprehensive 

structural requirements for the use of a 

jack-up rig in Arctic conditions. BSEE 

requests comments on the extent to 

which ISO 19905–1 should be 

incorporated into these proposed Arctic 

regulations.7

What are the requirements for Arctic 

OCS source control and containment? 

(§ 250.471) 

BSEE proposes to require operators to 

continue to adhere to all applicable 

source control and containment 

requirements in the current regulations, 

and to meet additional SCCE 

requirements for Arctic OCS exploratory 

drilling operations. BSEE is required to 

ensure that offshore oil and gas 

operations are conducted safely and in 

a manner that protects the environment 

from harm as a result of those 

operations. As stated earlier, the waters 

and surrounding environment of the 

Arctic region support a wide variety of 

marine mammals and other wildlife, 

including several Endangered Species 

Act (ESA) listed species and designated 

critical habitat. Furthermore, U.S. 

obligations under Article 4 of the Arctic 

Council’s Agreement on Cooperation on 

Marine Oil Pollution Preparedness and 

Response in the Arctic, require that, for 

‘‘areas of special ecological 

significance,’’ each party ‘‘shall 

establish a minimum level of prepositioned oil spill combating 

equipment, commensurate with the risk 

involved, and programs for its use[.]’’ 

The Arctic contains areas of ecological 

significance to the Nation as a whole, 

and especially to Alaska Native 

communities. 

Therefore, it is imperative that any 

loss of well control during oil and gas 

exploratory drilling operations is 

corrected and/or contained as quickly as 

possible to minimize the impact of oil 

pollution on the environment. To 

accomplish this task, it would be 

necessary to have all equipment needed 

to cap and/or contain the release of 

fluids readily available in the event of 

a loss of well control during Arctic OCS 

exploratory drilling operations. Further, 

operations on the Arctic OCS are 

distinct from operations on any other 

part of the OCS. The logistics and the 

transit times necessary to respond to a 

well control event on the Arctic OCS, 

coupled with the difficulties associated 

with oil spill response operations in 

Arctic OCS Conditions, require the 

operator to plan for and be prepared for 

contingencies that would be more 

straightforward to address in other 

theaters. There is limited ability in the 

Arctic region to summon additional 

source control and containment 

resources. Accordingly, operators 

working there must plan for response 

redundancies and planning 

complexities not required elsewhere. 

The proposed requirements would 

apply to all exploratory drilling 

operations using a MODU on the Arctic 

OCS, regardless of the BOP 

configuration employed by the 

operation. These provisions are 

designed to ensure that each operator 

using a MODU would have access to, 

and could promptly and effectively 

deploy and operate, surface and subsea 

control and containment equipment in 

the event of a loss of well control. In 

particular, BSEE would require each 

operator to have the ability, in the event 

of a loss of well control, to cap the well 

and to capture, contain, and process or 

properly dispose of any fluids escaping 

from the well. All SCCE must be 

mobilized (i.e., begin transit) to the well 

immediately upon a loss of well control. 

The rule would specifically provide that 

the SCCE is only necessary when 

drilling below or working below the 

surface casing. 

This new section would require 

compliance with the following source 

control and containment requirements 

for all exploration wells drilled on the 

Arctic OCS. 

Paragraph (a), Drilling Below or 

Working Below the Surface Casing 

Paragraph (a) would require that the 

operator, when using a MODU to drill 

below or work below the surface casing, 

have access to a capping stack 

positioned to arrive at the well within 

24 hours after a loss of well control, and 

a cap and flow system and a 

containment dome positioned to arrive 

at the well within 7 days after a loss of 

well control. These technologies are 

important because they have, either 

individually or in sequence, been 

proven to be effective at reacquiring 

control of wells and/or containing the 

flow of hydrocarbons after primary well 

control measures (such as well design 

and a BOP) have failed to prevent a well 

control event. The SCCE is intended to 

provide redundancy in the event of a 

loss of well control. Some of the well 

control events for which this equipment 

would be deployed could require a 

relief well to permanently plug and 

abandon the uncontrolled well. 

On the Arctic OCS, the exploratory 

drilling operator would not be 

considered to have the required SCCE 

unless it is secured in advance and has 

the capability of arriving at the well 

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within the required timeframes. In the 

event that a BOP or other prevention 

mechanism fails to stop the flow of 

fluids, capping stacks would be 

necessary to provide an additional 

means to control flow from the well, 

where a stub or connector is accessible. 

Capping stacks are the preferred 

immediate first level redundancy, with 

the goal of controlling the well and 

stopping the discharge of fluids, and 

should be positioned so that they will 

arrive at the well within 24 hours after 

a loss of well control. Incidents in 

which the connectors or tubulars are not 

damaged would lend themselves to the 

use of a capping stack. 

If the tubulars are damaged and the 

pressure cannot be managed with the 

capping stack, the remainder of the cap 

and flow system must be used as a 

secondary response. It must be 

positioned so that it will arrive at the 

well within 7 days of a loss of well 

control and designed to capture the 

WCD identified in the EP. If the cap and 

flow system were unable to stop or 

control the flow of fluids to the 

environment, or the well system were 

damaged to the point that the capping 

stack could not make a connection, the 

containment dome system, which also 

must be positioned to arrive at the well 

within 7 days of a loss of well control, 

would need to be used to capture the 

hydrocarbons flowing to the 

environment, as a tertiary response. 

Thus, the SCCE system, as a whole, 

would provide a level of redundancy 

and flexibility necessary to operate on 

the Arctic OCS. 

BSEE specifically requests comment 

on all of the proposed timeframes for 

arrival of SCCE at the well in the event 

of a loss of well control. In particular, 

BSEE invites comments on whether 

such timeframes are appropriate, from a 

logistical and feasibility perspective, to 

address a loss of well control. BSEE also 

requests comment on whether the cap 

and flow system and containment dome 

could be available and positioned to 

arrive at the well within 3 days, or some 

shorter amount of time than 7 days. 

Paragraph (b), Stump Test 

Paragraph (b) would require monthly 

stump tests of dry-stored capping stacks, 

and stump tests prior to installation for 

pre-positioned capping stacks. The 

presence of the equipment alone is not 

sufficient to ensure the reliability of the 

system. Testing of the equipment must 

be done on a regular basis. This 

proposed rule would impose a 

requirement that any capping stack that 

is dry stored must be stump tested 

(function and pressure tested to 

prescribed minimum and maximum 

pressures on the deck in a stand or 

stump where it could be visually 

observed) monthly. The rule would also 

require that pre-positioned capping 

stacks be tested prior to each 

installation on a well to assure BSEE 

that no damage was done during the 

prior deployment or transit. 

Paragraph (c), Reevaluating SCCE for 

Well Design Changes 

Paragraph (c) would require a 

reevaluation of the SCCE capabilities if 

the well design changes because some 

well design changes may impact the 

WCD rate. If the operator proposes a 

change to a well design that impacts the 

WCD rate, the operator must provide the 

new WCD rate through an Application 

for Permit to Modify (APM), as required 

by § 250.465(a). The operator must then 

verify that the SCCE would either be 

modified to address the new rate or that 

the previously proposed system would 

be adequate to handle the new WCD to 

demonstrate ongoing compliance with 

the SCCE capability requirements 

previously addressed. 

Paragraph (d), SCCE Tests or Exercises 

Paragraph (d) would require the 

operator to conduct tests or exercises of 

the SCCE when directed by the Regional 

Supervisor. Similar to the requirement 

that equipment be tested periodically, 

BSEE has concluded that there is a need 

to ensure that personnel are prepared 

and that they, and the SCCE, would be 

capable of performing as intended. 

Therefore, BSEE proposes to require that 

operators conduct tests and exercises 

(including deployment), at the direction 

of the Regional Supervisor, to verify the 

functionality of the systems and the 

training of the personnel. 

Paragraphs (e) and (f), SCCE Records 

Maintenance 

Paragraph (e) would require the 

operator to maintain records pertaining 

to testing, inspection, and maintenance 

of the SCCE for at least 10 years, and 

make them available to BSEE upon 

request. This information would 

facilitate a review of the effectiveness of 

the operator’s inspection and 

maintenance procedures and provide a 

basis of review for performance during 

any drill, test, or necessary deployment. 

Because of the limited drilling season 

on the Arctic OCS, the 10-year record 

retention requirement is necessary in 

order to ensure the availability of a 

meaningful longitudinal data set. 

Additionally, the limited drilling season 

means that this equipment would be 

infrequently used and might be stored 

for long periods of time between 

seasons. Thus, a 10-year record 

retention requirement is necessary to 

ensure enough cumulative data is 

gathered to assess overall equipment 

performance and trends. 

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. The use 

of the equipment during testing and 

training activities and actual operations 

must be recorded, along with any 

deficiencies or failures. These records 

would allow BSEE to address any issues 

arising during the usage and to 

document any trends or time-dependent 

problems that would develop over the 

record retention period. In the event 

that the equipment is used in a well 

control incident, the records are 

necessary to document the effectiveness 

of the response and functioning of the 

equipment. 

Paragraphs (g) and (h), Mobilizing and 

Deploying SCCE 

Paragraph (g) would require operators 

to mobilize (i.e., initiate transit of) SCCE 

to a well immediately upon a loss of 

well control and deploy (i.e., position 

for use) and use SCCE. Paragraph (h) 

would give the Regional Supervisor the 

authority to require the operator to 

deploy and use SCCE independent of an 

operator’s determination of whether or 

not to deploy and use SCCE. Requiring 

immediate mobilization would prevent 

operators from delaying the transit of 

SCCE equipment to the well in the hope 

that other source control or containment 

methods will be successful. This 

provision would ensure that all SCCE is 

available and ready for use. Also, this 

provision is being proposed to clarify 

the Regional Supervisor’s discretion to 

require the deployment and use of SCCE 

in the event of a loss of well control or 

for purposes of SCCE training and 

exercises. The Regional Supervisor’s 

authority is specifically addressed here 

to allow the Regional Supervisor to act 

in a timely manner should a loss of well 

control occur. 

What are the relief rig requirements for 

the Arctic OCS? (§ 250.472) 

As demonstrated by past loss of well 

control events around the globe, in some 

cases it may be necessary to drill a relief 

well to permanently plug an 

uncontrolled well. The SCCE is an 

interim solution designed to minimize 

environmental harm from well control 

events, but the ultimate solution may 

need to be accomplished by a relief 

well. Arctic OCS exploratory drilling 

operations would take place in a region 

that has little or no infrastructure, that 

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is subject to variable and sometimes 

extreme weather, and in which 

transportation systems could be 

interrupted for significant periods of 

time. Also, Arctic OCS exploratory 

drilling operations are complicated by 

the fact that they currently take place 

only during the ‘‘open water season,’’ or 

that period of time in the summer and 

early fall when ice hazards can be 

physically managed and there is no 

continuous ice layer over the water. 

Outside of that window, ice 

encroachment may complicate or 

prevent drilling and transit operations, 

and for that reason it is critical to ensure 

that drilling (including relief well 

drilling if necessary) and other 

operations affected by sea ice are 

concluded before ice encroachment. 

Furthermore, if there is a loss of well 

control during the drilling season, it is 

also important to ensure that, if a relief 

rig is necessary to stop the uncontrolled 

flow of oil, the relief rig is available and 

able to complete all necessary 

operations in as short a time as possible. 

Thus, while conducting exploratory 

drilling operations below the surface 

casing on the Arctic OCS, it is essential 

to position or designate a relief rig in a 

location that would enable it to transit 

to the well site, drill a relief well, plug 

the original well, plug the relief well, 

and demobilize from the site prior to 

expected seasonal ice encroachment. 

This 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. 

The proposed rule would establish a 

45-day maximum limit on the time 

necessary to complete relief well 

operations. This timeframe is necessary 

to acknowledge the relative lack of 

infrastructure and active operations 

from which response resources could be 

drawn in the region, as well as the grave 

threats of a prolonged loss of well 

control to the Arctic environment. If an 

operator were to use a pure standby rig 

(i.e., a rig that is not otherwise operating 

in the Arctic), Dutch Harbor is the 

nearest deep-water port where the 

standby rig could be stationed. BSEE 

estimates that it would take 20 days to 

get the rig ready and to transit from the 

nearest U.S. deep-water port (Dutch 

Harbor) to the farthest well location 

(Beaufort leases), 20 days to drill the 

relief well, and 5 days to plug the 

uncontrolled well, test it, and move off 

the well site. If, on the other hand, an 

operator were to use a second drilling 

rig to serve as a relief rig for another 

drilling rig, the time required to 

complete relief well operations could be 

much shorter than 45 days because the 

second rig would already be operating 

in the Arctic OCS and would require 

shorter transit time than a standby relief 

rig staged in Dutch Harbor or at another 

location. 

BSEE considered imposing 

prescriptive geographic limitations on 

the staging of relief rigs in proximity to 

exploratory drilling operations, but 

chose instead to propose a performancebased requirement to provide operators 

the flexibility to choose how best to 

comply with the relief rig obligations. 

Operators would need to demonstrate 

their ability to complete relief well 

operations within a maximum of 45 

days, subject to BSEE’s review in the 

APD process (see proposed 

§ 250.470(e)). The proposed rule would 

also authorize the Regional Supervisor 

to direct an operator to begin drilling 

the relief well. 

The relief rig could be stored in 

harbor, staged idle offshore, or actively 

working, as long as it would be capable 

of physically and contractually meeting 

the proposed 45-day maximum 

timeframe. However, any relief rig must 

be a separate and distinct rig from the 

primary drilling rig to account for the 

possibility that the primary rig could be 

destroyed or incapacitated during the 

loss of well control incident. 

Of course, an operator’s actual 

timeframe to drill a relief well would be 

based on consideration of the distance 

between anticipated exploratory drilling 

sites, the availability of adequate staging 

locations for relief rigs, the length and 

complexity of rig transit under Arctic 

OCS Conditions, and the time necessary 

to complete the requisite operations 

once on-site. Thus, BSEE specifically 

requests comment on whether the 

maximum time limit for deploying a 

relief rig and drilling a relief well 

should be more or less than 45 days. 

The proposed rule expressly provides 

that the relief rig would only be 

necessary when drilling below or 

working below the surface casing (i.e., 

where contact with hydrocarbons 

capable of flowing into the well could 

occur). BSEE recognizes that the 

proposed relief rig requirement may 

effectively limit the number of days an 

operator can work below the surface 

casing at the end of each drilling season. 

The actual length of this limitation 

would depend on the operator’s plans 

for staging and deploying a relief rig and 

could extend up to 45 days before the 

end of the drilling season (e.g., the 

projected return of sea ice). 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. 

Such work can significantly advance an 

exploratory drilling project and can help 

an operator prepare to conduct work 

below the surface casing during the 

following drilling season. BSEE requests 

comments on the different types of work 

(above the surface casing) that could be 

performed during the time period set 

aside for a relief well to be drilled, if 

needed, as well as the economic benefits 

and costs associated with this work. 

While a relief well is the most 

reliable, and in some circumstances the 

only available, solution to kill and 

permanently plug an out-of-control 

well, there could be circumstances in 

which control could be regained 

without intervention by a relief well. 

Accordingly, BSEE also requests 

comment on whether there are any 

alternative technological methods, in 

addition to a relief well, to kill and 

permanently plug an out-of-control well 

before seasonal ice encroachment. 

Comments should include, where 

possible, specific technological 

solutions, descriptions of the conditions 

under which an alternative method 

could successfully kill and permanently 

plug a well, and any research that 

would demonstrate the effectiveness of 

such an alternative. 

For example, some stakeholders have 

proposed that the use of subsea shut-in 

devices (SIDs) located on the seafloor 

could help significantly reduce the risk 

of a release of hydrocarbons if the BOP 

system fails. SID equipment is 

specifically designed to act as a 

redundant safety system and ensure the 

safe and timely shut-in of a well in an 

emergency. Although BSEE believes that 

timely access to a relief rig is the surest 

way to permanently resolve a WCD 

event in the Arctic, the use of SIDs 

could reduce the risk of a release of 

hydrocarbons and potentially justify 

giving operators more flexibility in the 

staging of relief rigs. 

Thus, BSEE requests comments on 

alternative compliance approaches and 

specifically requests data on the 

performance of SIDs, including 

operational issues (such as timeframes 

needed to activate such alternatives). In 

particular, BSEE requests comments on 

appropriate staging requirements for a 

relief rig assuming that an SID has been 

installed at the exploration well. 

Comments are also requested on the 

need for an operator to have an inseason relief well drilling capability if 

an SID is used at a location that is not 

subject to ice scouring. 

BSEE also requests information or 

data comparing the relative safety and 

environmental risk levels, as well as the 

costs, of the equipment and procedures 

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8 It is likely that Arctic Conditions could have an 

adverse impact on the performance of some 

equipment and result in this equipment being 

operated below the rated maximum performance 

level. 

that would be required under the 

proposed regulations to the risks and 

costs of equipment and procedures 

under any suggested alternative 

approach. 

In any case, BSEE’s existing 

regulations allow operators the 

flexibility to develop new technological 

solutions and to seek approval for the 

use of those solutions to fulfill their 

regulatory obligations. Under 30 CFR 

250.141, operators may request approval 

to use alternative equipment or 

procedures for any specified 

requirement, provided that the operator 

is able to demonstrate an equivalent or 

improved level of safety and 

environmental protection. This 

performance-based provision is a key 

part of BSEE’s regulatory program, 

which is a combination of prescriptive 

and performance-based requirements, 

because it gives operators the ability to 

comply with regulatory requirements 

through a variety of methods if they can 

make the necessary demonstrations to 

BSEE. It also serves to encourage the 

development and utilization of 

alternative technologies to satisfy the 

specific requirements contained in the 

regulations. 

What must I do to protect health, safety, 

property, and the environment while 

operating on the Arctic OCS? (§ 250.473) 

BSEE proposes to add a new § 250.473 

that would require performance-based 

measures in addition to those listed in 

§ 250.107 to protect health, safety, 

property, and the environment during 

exploratory drilling operations on the 

Arctic OCS. 

Paragraph (a) would require that all 

equipment and materials proposed for 

use in exploratory drilling operations on 

the Arctic OCS be rated or de-rated for 

service under conditions that could be 

reasonably expected during operations. 

Arctic OCS Conditions place strains on 

operating equipment not experienced 

elsewhere on the OCS. This necessitates 

that such equipment be rated or de-rated 

for use under such conditions in order 

to ensure that it could operate safely 

and effectively.8 For example, cranes 

must be designed to withstand ice loads 

that can be anticipated to build up 

during Arctic OCS operations and 

operational limitations of components 

under extreme cold temperatures (e.g., 

reduced tensile strength) must be 

understood and accounted for. Also, 

capping and containment equipment 

must be specifically designed to 

withstand the demands of regional 

conditions. The Arctic Council made 

similar recommendations for equipment 

and materials in its 2009 report on 

Arctic oil and gas operations (see Arctic 

Council—Arctic Offshore Oil and Gas 

Guidelines (2009)). 

BSEE’s existing regulation at 

§ 250.418(f) requires that operators 

include in their APD ‘‘evidence that the 

drilling equipment, BOP systems and 

components, diverter systems, and other 

associated equipment and materials are 

suitable for operating’’ in areas subject 

to subfreezing conditions, while 

proposed § 250.473(a) would establish a 

requirement for use of appropriately 

rated or de-rated equipment and 

materials. Operators may ensure that 

proposed materials and equipment are 

rated or de-rated appropriately by 

referencing manufacturer specifications 

and would not need to obtain 

equipment or material rating by an 

independent third-party rating entity. 

Upon finalization of this provision, 

failure to use appropriately rated or derated equipment and materials could 

subject an operator or its contractor to 

enforcement action by BSEE. 

Paragraph (b) would require operators 

to employ measures to address human 

factors associated with weather 

conditions that can be reasonably 

expected during Arctic OCS exploratory 

drilling operations. This provision is 

designed to ensure safety of the 

workforce and protection of the 

environment by requiring operators to 

account for weather conditions that 

might impact decision-making and 

personnel health and safety. On the 

Arctic OCS, the workforce would 

encounter harsh environmental 

conditions, including extreme cold, 

snow, ice, and freezing spray, which 

could cause, among other medical 

conditions, frost bite and breathing 

difficulties that can impair performance 

and judgment. Measures that operators 

would be required to use to address 

human factors include, but are not 

limited to, provision of proper attire and 

equipment, construction of protected 

work spaces, and management of shifts. 

What are the auditing requirements for 

my SEMS program? (§ 250.1920) 

In 2013, BSEE published an update to 

Subpart S, which established additional 

measures operators must take to manage 

safety and to protect the environment 

during their OCS operations. The 

requirements under this subpart are 

designed to be performance-based to 

allow operators to tailor their 

management systems to their particular 

operations, including operations on the 

Arctic OCS. For example, a hazards 

analysis for a facility on the Arctic OCS 

would account for the types of hazards 

expected on the Arctic OCS, like ice 

floe. Similarly, Job Safety Analyses must 

account for Arctic OCS Conditions, such 

as ice, extreme cold, snow, and freezing 

spray. BSEE would not consider an 

operator’s SEMS to be effective under 

§ 250.1924 if it were not specifically 

tailored to the Arctic OCS Conditions 

reasonably anticipated at the facility in 

question. 

Similarly, existing §§ 250.1914 and 

250.1924 give BSEE broad authority to 

require that operators on the Arctic OCS 

provide BSEE with information such as 

the names of contractors and the 

specific scope of their duties and 

timelines for performance in support of 

an operator’s drilling activities. For 

example, if an operator planned to use 

a contractor for waste disposal, 

cementing, or logging, BSEE would 

expect the operator to inform BSEE of 

this intent, along with any other 

operations contracted out, and the 

names of those contractors. Because the 

existing performance-based SEMS 

regulations are adequate to cover Arctic 

OCS operations when properly 

implemented, no major modifications 

are needed to Subpart S for the Arctic 

OCS. However, additional provisions 

are necessary to bolster auditing 

expectations for Arctic OCS exploratory 

drilling operations. 

This rule proposes to increase the 

audit frequency and facility coverage for 

intermittent 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. This Arctic 

OCS audit would require operators to 

ensure that all safety systems are in 

place and functional prior to 

commencing or resuming, activities for 

a new drilling season, as well as to 

conduct the offshore portion of the audit 

while drilling is under way. An operator 

conducting Arctic OCS exploratory 

drilling operations may not combine its 

Arctic OCS facility audit(s) with audits 

of its non-Arctic OCS facilities to satisfy 

the facility sampling requirements 

incorporated into Subpart S. 

As with SEMS audits in other OCS 

regions, there would be an onshore and 

offshore portion. However, for Arctic 

OCS exploratory drilling operations, an 

operator would be required to submit a 

separate audit report and corrective 

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9942 Federal Register / Vol. 80, No. 36 / Tuesday, February 24, 2015 / Proposed Rules 

action plan (CAP) for the onshore and 

offshore portions of its audit. To provide 

an opportunity for BSEE to review the 

onshore portion of the audit report and 

CAP prior to commencement of drilling, 

they must be submitted no later than 

March 1st in any year in which drilling 

is planned. The operator would also be 

required to start and close the offshore 

portion of the audit within 30 days after 

first spudding of the well or entry into 

an existing wellbore for any purpose 

from that facility. The operator would 

be required to submit the audit report 

and CAP from the offshore portion of 

the audit within 30 days of the close of 

that portion of the audit. This is 

designed to enable the auditors to 

analyze offshore operations while they 

are actively underway, and to ensure 

that BSEE is made aware of any issues 

surrounding those operations as soon as 

practicable. To ensure that any critical 

problems that are revealed by the audit 

are addressed, BSEE would be able to 

order all or part of the operations to be 

shut down, if necessary. 

Oil Spill Response 

Part 254—Oil-Spill Response 

Requirements for Facilities Located 

Seaward of the Coast Line 

Definitions. (§ 254.6) 

This section would include a revised 

definition of Adverse weather 

conditions and add new definitions of 

Arctic OCS and Ice intervention 

practices. These definitions are 

necessary because they are important in 

establishing the standard for response 

capability based on environmental 

conditions unique to the Arctic region. 

Adverse weather conditions—The 

current regulations contain a definition 

for the term ‘‘adverse weather 

conditions,’’ which means conditions 

under which spill response activities are 

difficult but nevertheless required to 

proceed. The concept reflects the fact 

that operators are required to pursue oil 

spill response activities in all but the 

most severe conditions where such 

activities would become particularly 

dangerous or impossible. This term is 

important, especially for Arctic OCS 

exploratory drilling, because it describes 

the difficult conditions in which a 

response is still expected to occur and 

excludes conditions that present too 

much of a risk to responder health and 

safety for a response to proceed. 

Operators are expected to consider the 

delays and challenges resulting from 

adverse weather when developing their 

OSRP. The resulting response strategies 

should reflect the right type and amount 

of resources necessary to effectively 

respond to a WCD scenario that would 

include adverse weather conditions on 

the Arctic OCS and should factor in 

anticipated disruptions or delays that 

could result from operational periods 

where conditions would exceed safe 

operating parameters and prohibit spill 

response activities from occurring. 

BSEE proposes to add more specific 

weather terms, i.e., extreme cold, 

freezing spray, snow, and extended 

periods of low light, to this definition 

for clarity regarding the weather 

conditions in which we expect lessees 

or operators to be able to conduct 

response operations on the Arctic OCS. 

The addition of this terminology is 

intended to ensure that operators 

procure equipment that could respond 

in these difficult, but feasible, 

conditions and utilize spill response 

technology that would be suitable for 

weather conditions encountered within 

the Arctic region. With this outcome in 

mind, we considered establishing 

quantitative descriptions specific to ice 

and temperature. For example, to ensure 

that identified response capabilities 

would be able to operate in certain 

levels of ice, one option considered was 

to include 30 percent ice coverage as a 

condition under which BSEE would 

expect response activities to proceed. 

However, BSEE concluded that using 

qualitative terms would allow the 

maximum flexibility in determining the 

appropriate performance-based 

approach necessary to respond quickly 

and effectively to an operator’s WCD to 

the maximum extent practicable, under 

conditions reasonably anticipated 

during operations. This could encourage 

research and development, including 

Federally funded projects, to continue 

to enhance the standard response 

capabilities. 

Arctic OCS — For an explanation of 

the definition of Arctic OCS, see the 

definitions discussion at the beginning 

of the Section-by-Section analysis. 

Ice intervention practices—This new 

term describes the equipment, vessels, 

and procedures used to increase the 

effectiveness of response techniques and 

equipment in encountering and 

mitigating the impacts of spilled oil 

when sea ice is present. After oil 

spreads over a broad area, the ability to 

recover, burn, or disperse oil depends 

on the rate at which the oil can be 

identified, tracked, and encountered 

(i.e., encounter rate). When ice is 

present during efforts to mitigate the 

impacts of spilled oil, the ice could act 

as a barrier that would obscure, limit, or 

prevent access to the oil, and could also 

interfere with the proper operation of 

response equipment. Accordingly, ice 

presents unique and significant 

challenges, and it is important that 

operators develop equipment and 

strategies to respond to such challenges. 

The other purpose of this definition is 

to specifically differentiate terminology 

used to describe tactics for responding 

to oil in water containing sea ice from 

terminology used to describe resources 

and tactics employed to manage ice 

during drilling operations. An operator’s 

OSRP must address ice intervention 

practices specifically intended to 

increase the effectiveness of an oil spill 

response operation. This term relates to 

a new requirement for the ‘‘emergency 

response action plan’’ section of OSRPs 

for Arctic OCS facilities, proposed at 

§ 254.80(a). Please refer to the 

discussion related to that provision for 

further explanation of the need for, and 

importance of, this item in operators’ 

OSRPs. 

Spill response plans for facilities 

located in Alaska State waters seaward 

of the coast line in the Chukchi and 

Beaufort Seas. (§ 254.55) 

The OSRPs for facilities in State 

waters seaward of the coast line must be 

submitted to BSEE for approval and 

must comply with the requirements in 

Subpart D. The proposed provision 

would require the OSRP for any facility 

conducting exploratory drilling from a 

MODU in Alaska State waters seaward 

of the coast line within the Beaufort or 

Chukchi Seas to address the additional 

requirements set forth in the new 

proposed Subpart E, discussed in detail 

later. BSEE has determined that the 

considerations justifying the various 

provisions of proposed Subpart E would 

also apply to these operations. 

Some requirements in Subpart E 

address planning and exercises related 

to the use of source control and subsea 

containment equipment such as capping 

stacks or containment domes. Operators 

would be required to have access to and 

use this equipment when conducting 

exploratory drilling from a MODU on 

the Arctic OCS, pursuant to proposed 

regulations in Part 250, but those 

conducting similar activities in State 

waters are not currently subject to the 

same requirements. The State of Alaska, 

however, has State requirements for 

source control. As such, a response plan 

covering operations in State waters of 

the Beaufort or Chukchi Seas must 

address how the source control 

procedures selected to comply with 

State law would be integrated into the 

planning, training, and exercise 

requirements of proposed §§ 254.70(a), 

254.90(a), and 254.90(c). 

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Federal Register / Vol. 80, No. 36 / Tuesday, February 24, 2015 / Proposed Rules 9943 

Subpart E—Oil-Spill Response 

Requirements for Facilities Located on 

the Arctic OCS 

Purpose (§ 254.65) 

This rulemaking proposes to create a 

new Subpart E, in order to provide 

owners and operators of exploratory 

drilling facilities on the Arctic OCS with 

additional requirements for oil spill 

response preparedness that would 

address the challenging conditions that 

operators would likely encounter on the 

Arctic OCS. The main purpose for the 

proposed language is to establish 

specific planning requirements that 

would maximize oil spill response 

technology application and emphasize a 

complete response system that would be 

designed to address the environmental 

and logistical challenges inherent to 

spill response activities in the Arctic 

OCS region. This would include 

planning for a WCD that occurs late in 

the drilling season. 

BSEE chose to create a new subpart 

instead of incorporating the specific 

requirements throughout its existing 

regulatory provisions. This is similar to 

the approach that was taken to address 

requirements specific to State waters in 

Subpart D. It is important to note that 

Subpart E would add requirements for 

operations on the Arctic OCS and that 

all other applicable requirements in Part 

254 would still apply. BSEE chose to 

reserve §§ 254.66 through 254.69; 

§§ 254.71 through 254.79; and §§ 254.81 

through 254.89 within proposed 

Subpart E. 

What are the additional requirements 

for facilities conducting exploratory 

drilling from a MODU on the Arctic 

OCS? (§ 254.70) 

BSEE proposes to add § 254.70 that 

would address general oil spill response 

planning requirements for operators 

using MODUs to conduct exploratory 

drilling on the Arctic OCS. These 

requirements include incorporating the 

support mechanisms for capping stacks, 

cap and flow systems, containment 

domes, and other similar subsea and 

surface devices and equipment and 

vessels, required by proposed § 250.471, 

into oil spill response incident action 

planning. They would also require 

operators to address the influence of 

adverse weather conditions on 

responders’ health and safety during 

spill response activities. Finally, they 

would require operators, prior to 

resuming seasonal exploratory drilling 

activities, to review their OSRPs, and 

modify as necessary, to address changes 

to the location or status of response 

resources or the arrangements for 

supporting logistical infrastructure 

arising from extended periods of time 

without drilling. 

Paragraph (a) would address the need 

to integrate emergency well control and 

containment equipment and personnel 

into spill response planning to ensure 

coordination during a loss of well 

control event. Regaining control over 

the well and containing discharged 

liquids is the first line of response to a 

well control incident, following failure 

of primary prevention devices. 

Accordingly, it is critical that those 

efforts be integrated and coordinated 

with the spill response efforts designed 

to remove or treat oil in the water that 

would proceed at the same time. 

Although requirements for well control 

and containment equipment operability 

and safe use fall under regulations based 

on the OCSLA, its integration with the 

oil spill response activities is 

imperative. Active information sharing 

through coordinated planning efforts 

will ensure that oil spill response and 

source control and containment 

operations would be synergistic and 

mutually understood when called upon 

to function together in the event of a 

loss of well control. 

Paragraph (b) would address 

responder health and safety by ensuring 

that the correct resources would be 

available to protect responders from 

hazards specific to the Arctic region. It 

is critical for operators to address in 

their OSRPs the influence of adverse 

weather conditions, including extreme 

cold, snow, ice, freezing spray, and 

extended periods of low light, on spill 

response personnel. These conditions 

could impair human decision-making 

and physical abilities and create risks to 

personnel, operations, and the 

environment. Accordingly, this 

provision would require that operators 

describe in their OSRPs the steps they 

would take to address those factors to 

ensure that their planned oil spill 

response activities could be conducted 

in a safe and effective manner. The 

types of considerations that BSEE would 

expect to be addressed include, but are 

not limited to, proper attire and 

equipment, protected work spaces, and 

proper shift management. The objective 

would be to ensure that the equipment 

needed to protect human health against 

adverse weather conditions would be 

available immediately when a response 

is required. 

Paragraph (c) would address specific 

challenges to maintaining preparedness 

to respond to a spill when drilling is 

seasonal and there are extended periods 

without any risk of an oil discharge. 

One of the substantial challenges 

presented by operations on the Arctic 

OCS is the seasonal drilling limitation 

resulting from the prevalence of sea ice 

on portions of the waters overlying the 

Arctic OCS during all but the summer 

and early fall months. This limitation 

precludes active exploratory drilling 

operations from MODUs on the OCS for 

up to 8 months of the year, potentially 

leaving associated response equipment, 

materials, and personnel idle for 

extended periods of time or leading to 

their use in other regions of the OCS or 

elsewhere. 

It is important for operators to ensure 

that their spill response capabilities 

would not deteriorate or lose their 

effectiveness due to such extended 

periods of inactivity and to ensure that 

they would remain capable and 

adequate to conduct a quick and 

effective response to an oil spill during 

active exploratory drilling operations. 

While BSEE encourages owners or 

operators with approved OSRPs to 

commit to a continuous exercise, 

training, and equipment maintenance 

regime that inherently builds response 

skills over time, the Arctic OCS seasonal 

drilling limitations challenge the 

practicality of continuously maintaining 

these capabilities while there is not a 

risk of a discharge. To address this 

challenge, BSEE would require that 

owners or operators, in connection with 

seasonal exploratory drilling activities, 

review and submit modifications to 

their OSRP as appropriate, to 

demonstrate that all required resources 

would be ready, before oil is handled, 

stored, or transported, to respond to a 

spill to the maximum extent practicable. 

This OSRP review and update would 

address resource allocations, changes, 

and, most importantly, the reestablishment of resource readiness well 

before there is a risk of discharge. BSEE 

would review and approve proposed 

OSRPs for resource maintenance during 

extended periods without drilling 

activity through established OSRP 

approval, modification, revision, and 

update processes described in §§ 254.2, 

254.30, and 254.53, and the proposed 

update described in this section. 

What additional information must I 

include in the ‘‘Emergency response 

action plan’’ section for facilities 

conducting exploratory drilling from a 

MODU on the Arctic OCS? (§ 254.80) 

BSEE also proposes to create a new 

§ 254.80 that would focus on additional 

information requirements for the 

emergency response action plan section 

of an OSRP when the operator proposes 

to conduct exploratory drilling 

operations from a MODU on the Arctic 

OCS. The additional requirements 

would include specifics regarding ice 

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9944 Federal Register / Vol. 80, No. 36 / Tuesday, February 24, 2015 / Proposed Rules 

9The Unified Command is a response construct 

under the incident command system headed by 

Federal authorities and coordinated with the State 

and other parties. 

intervention practices, staging 

considerations, and tracking abilities. 

Sea ice could reduce the effectiveness 

of spill response techniques by limiting 

access to spilled oil and decreasing oil 

encounter rates. Therefore, in paragraph 

(a), BSEE would require Arctic OCS 

exploratory drilling operators to 

describe their ice intervention practices 

and how they would improve the 

effectiveness of spill response 

equipment and response strategies in 

the presence of sea ice. Increasing oil 

encounter rates when sea ice is present 

maximizes efficiency in removing or 

mitigating the adverse impacts from oil 

in the water as quickly and effectively 

as possible. The necessary practices and 

equipment would work to mitigate the 

impacts of ice on response operations 

and extend the period in which oil spill 

response activities could occur. They 

would also ensure that appropriate ice 

management vessels would be included 

when determining equipment 

requirements that would enhance all 

response options and strategies 

included in the plan. 

Operators must ensure that they 

would have the capability to initiate a 

rapid response to the site of an offshore 

oil spill, as well as to sustain and, when 

necessary, repair response equipment 

on-site without having to rely on shorebased assets that could become 

inaccessible due to weather conditions 

or other factors. Due to the remote 

locations where Arctic OCS exploratory 

drilling operations would occur, and the 

limited infrastructure and logistical 

support capabilities in the coastal 

communities, operators would need to 

consider strategic staging locations and 

support mechanisms for effectively 

deploying and resupplying oil spill 

response resources. For the Arctic OCS, 

initial response capabilities, in many 

instances, would need to be based 

offshore to effectively meet the 

requirements in Part 254. Pursuant to 

paragraph (b)(1), operators would be 

required to describe how they would 

maintain assets in close proximity to 

exploratory drilling operations to ensure 

that adequate response times would be 

achievable and response operations 

would be sustainable. The weather 

conditions that are common to the area 

(e.g., dense fog, high sea states) often 

preclude access to the area by small 

vessels and aircraft for days at a time. 

The ability to mount and maintain an 

expeditious response once a release 

occurs would be negatively impacted if 

response assets or supporting materials 

were significantly delayed from arriving 

at the spill site due to inclement 

weather. Accordingly, operators must 

establish an offshore resource 

management system to ensure that 

vessels and equipment would be readily 

available, along with sufficient 

personnel and berthing, to carry out 

response activities. 

The limited support and response 

capabilities and capacities that exist in 

most Alaska coastal communities 

mandate that operators provide for 

nearly all aspects of an oil spill response 

on the Arctic OCS. Paragraph (b)(2) 

would require operators to identify how 

they intend to ensure an immediate and 

uninterrupted flow of supplies, 

response equipment, personnel, and 

shore-based support services to sustain 

the response activities until terminated 

by the Unified Command.9 The 

components of the logistics supply 

chain include, but are not limited to: 

Personnel and equipment transport 

services; airfields and types of aircraft 

that can be supported; capabilities to 

mobilize supplies (e.g., response 

equipment, fuel, food, fresh water) and 

personnel to the response sites; onshore 

staging areas, storage areas that may be 

used en route to staging areas, and camp 

facilities to support response personnel 

conducting offshore, nearshore and 

shoreline response; and management of 

recovered fluid and contaminated debris 

and response materials (e.g., oiled 

sorbents), as well as waste streams 

generated at offshore and on-shore 

support facilities (e.g., sewage, food, and 

medical). Operators must also plan to 

implement mitigation measures to 

reduce the impacts that surged 

personnel, equipment, and increased 

activity would have on communities 

where staging areas, camp facilities, and 

waste handling sites are established. 

In paragraph (c), BSEE proposes to 

require 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. 

Part 254 requires operators to describe 

all equipment they plan to use to 

respond quickly and effectively to an oil 

spill to the maximum extent practicable. 

For oil spill response planning, BSEE 

would not consider it adequate 

preparedness for an operator to assume 

that the Federal On-Scene Coordinator 

would call upon assets under the 

control of other entities during a 

response. As previously mentioned in 

the Part 550 discussion, it is important 

to note that an effective and immediate 

removal or mitigation of a discharge 

must be achieved to the maximum 

extent practicable by private sector 

efforts. 

What are the additional requirements 

for exercises of your response personnel 

and equipment for facilities conducting 

exploratory drilling from a MODU on 

the Arctic OCS? (§ 254.90) 

BSEE proposes to create a new 

§ 254.90 that would require operators to 

incorporate the additional requirements 

contained within proposed §§ 254.70 

and 254.80 into their oil spill response 

training and exercise activities; would 

require operators to provide notice of 

the commencement of covered 

operations; and would clarify the 

authority of the Regional Supervisor to 

conduct exercises, prior to and during 

exploratory drilling operations, to test 

response preparedness. These 

requirements are all essential to 

ensuring and verifying an operator’s 

readiness to conduct response activities 

on the Arctic OCS. 

As described previously with respect 

to proposed § 254.70(a), it is essential 

that the relevant support mechanisms 

(personnel, materials, and vessels) for 

capping stacks, cap and flow systems, 

and containment domes, and other 

similar subsea and surface devices and 

equipment and vessels, be integrated 

and coordinated with the spill response 

planning and activities that would take 

place alongside them, and that those 

arrangements are suitable for 

deployment on the Arctic OCS. 

Accordingly, proposed § 254.90(a) 

would require that operators incorporate 

the required personnel and equipment 

into spill-response training and 

exercises to ensure the necessary and 

appropriate level of coordination 

between source control and subsea 

containment activities and spill 

response activities. 

Similarly, to ensure that these training 

and exercise activities would accurately 

reflect and test the full scope of 

response capabilities necessary for 

Arctic OCS operations, proposed 

§ 254.90(a) would also require that 

operators incorporate other proposed 

response plan features from proposed 

§§ 254.70 and 254.80 into those 

activities. As outlined in proposed 

§ 254.90(c), the Regional Supervisor 

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Federal Register / Vol. 80, No. 36 / Tuesday, February 24, 2015 / Proposed Rules 9945 

may direct operators to deploy response 

resources, as part of announced or 

unannounced exercises, to verify an 

operator’s preparedness for responding 

to a spill on the Arctic OCS. These 

exercises might include the deployment 

of capping stacks, cap and flow systems, 

containment domes, or other supporting 

equipment in order to test their 

integration and coordination with other 

oil spill response activities. However, 

SCCE is not required to be deployed 

under the annual and triennial 

equipment deployment requirements 

outlined in § 254.42(b)(2). 

Finally, proposed § 254.90(b) would 

require operators planning to conduct 

exploratory drilling from a MODU on 

the Arctic OCS to provide 60-days’ 

notice before handling, storing, or 

transporting oil to give BSEE adequate 

opportunity to verify that the operator’s 

personnel and equipment are in 

compliance with existing regulations. 

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9946 Federal Register / Vol. 80, No. 36 / Tuesday, February 24, 2015 / Proposed Rules 

D. Arctic Exploratory Drilling Process 

Flowchart 

BILLING CODE 4310–VH–; 4310–MR–P 

BILLING CODE 4310–VH–; 4310–MR–C 


mstockstill on DSK4VPTVN1PROD with PROPOSALS2EP24FE15.006</GPH>

•:• Integrated 0Qerations Plan (550.204] •!• -- Indicates proposed new provisions; all 

\11 existing applicable regulations continue to 

apply unless otherwise noted; all citations , OSRP Submitted for AQQroval are to Title 30 of the CFR 

ExQioration Plan 

• 550.211-228 requirements . In compliance with Part 254; 

•!• Arctic Suitability [550.220(c)(l)] •!• Including new Subpart E 

•!• Ice and Weather [550.220(c)(2)] 

•:• SCCE, Relief Rig [550.220(c)(3)-(4)J 

•!• Resource Sharing [550.220(c)(5)] 

r-"""' " ..I 

\11 " "0 

EPApproval OSRP Approval SEMS in place [Part 250, SubpartS] iii" 

::> 

::> 

I :r 

$> 

~ "0 

"' 

~ " 5' 

' SEMS Onshore Audit $> 

APD Submission •!• (Report and CAP by March 1) '" ::> 

BOEM- BSEE 250.410-418 requirements [250.1920(b)-(e)] c. . '!? 

•!• Arctic Suitability [250.470(a)] "' 

Arctic OCS "0 

•!• Transition Operations [250.470(b)] ~ 

~ 

•!• Objectives, Timelines, and ' 

c;· 

Exploration ::> 

Contingency Plans [250.470(c)] 

Planning, 

•!• Weather and Ice [250.470(d)] •!• Notification of RS (60 days before ..__ •!• Relief rig plans [250.470(e)] drilling) [254.90(b)] 

Permitting, and •!• SCCE Capabilities [250.470(f)] 

•!• API RP2N description [250.470(g)] 

Operations I 

Flowchart ~ 

APD Approval 

I 

I "' I 

Commence EKQioration Drilling Drilling 0Qerations Reguirements: 

•!• Start with well cellar (or f<~ . Compliance with all generally applicable law and regs -- equivalent) if ice scour [250.402] •!• Properly rated/de-rated equipment and materials [250.473(a)] 

•!• Address human factors in weather conditions [250.473(b)] ~ 

t •!• Offshore Portion of SEMS Audit with report and CAP [250.1920(b)-(e)] 5' 

O'Q 

•!• Capture of Mud and Cuttings (as required) [250.300(b)] 0 

'tl 

•!• Real-time operational monitoring [250.452] "' 

•!• Weather and Ice tracking and forecasting [250.470(d)] ~ a· 

Drilling or Working Below Surface •!• Reporting of ice, ice management, and kicks [250.188(c)] ~ 

Casing 

·~ •:• Monthly Capping Stack stump tests [250.471(b)] 

•!• SCCE Staged [250.471(a)] •!• 7-day BOP pressure testing [250.447(b)] -- •!• Relief Rig Staged [250.472] •!• Personnel training [250.470(f)(5); 254.70(a); 254.90(a)] 

•!• Drills and exercises (SCCE and OSR) [250.471(d) & (g); 254.90(a) & (c)] 

I 

•!• Protection of well and equipment upon TA (250.402(c)] 

J, ........ 

Offseason " 0 

•!• Spill response readiness and ~ 

iE"""""""""""-

Conclusion of on-site operations 

maintenancel[~&.70(c)] (including abandonment) ~ •!• Maintenance of data and records •!• Transition per APD (250.470(b)] 5' 

.. [250.452(b); 250.471(e) & (f)] 

;-
Federal Register / Vol. 80, No. 36 / Tuesday, February 24, 2015 / Proposed Rules 9947 

V. Conclusion 

Overall, the proposed rule would 

further the Nation’s energy goals in 

prudently exploring frontier areas, such 

as those in the Arctic OCS, by 

establishing operating models and 

requirements tailored specifically to the 

extreme, unpredictable, and rapidly 

changing conditions that exist in the 

Arctic region. The proposed regulations 

reflect the need for earlier and more 

comprehensive planning of operations, 

particularly with respect to emergency 

response and safety systems. The 

proposed Arctic OCS exploratory 

drilling rule would institutionalize a 

proactive approach to safety. 

Vulnerabilities would be identified in 

the planning phase and corrections 

would be made to reduce the likelihood 

of an incident occurring. The proposed 

rule would also ensure that those plans 

would be carried forward and executed 

in a manner that would ensure safety 

and environmental protection under the 

challenges presented to operations by 

Arctic OCS Conditions. 

Finally, the proposed rule would 

integrate emergency response, 

comprehensive operational and safety 

planning, contractor oversight, and 

upfront mutual aid agreements. The 

proposed combination of prescriptive 

and performance-based requirements 

would precipitate robust consideration 

of how safe exploration of the Arctic 

region is to be achieved. 

VI. Procedural Matters 

A. Regulatory Planning and Review 

(E.O. 12866 and E.O. 13563) 

Changes to Federal regulations must 

undergo several types of economic 

analyses. First, E.O. 12866 and E.O. 

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 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. 

B. E.O. 12866 

E.O. 12866 provides that OMB’s 

Office of Information and Regulatory 

Affairs will review all significant rules. 

Pursuant to the procedures established 

to implement § 6 of E.O. 12866, OMB 

has determined that this proposed rule 

is significant because the estimated 

annual costs or benefits exceed $100 

million in at least one year of the 

analysis period. The following 

discussion summarizes the economic 

analysis; a more detailed Initial RIA can 

be found in the regulatory docket for 

this proposed rule at 

www.regulations.gov (in the Search box, 

use BSEE–2013–0011). BOEM and BSEE 

request comments on the assumptions 

used in the Initial RIA and on other 

possible alternatives to consider, 

including alternatives to the specific 

provisions contained in the proposed 

rule. 

1. Need for Regulation 

This proposed rule seeks to enhance 

requirements for safe, effective, and 

responsible Arctic OCS oil and gas 

activities. Although there is currently a 

comprehensive OCS oil and gas 

regulatory program, DOI engagement 

with partners and stakeholders, 

including environmental groups and 

Alaska Natives, reveals the need for new 

and enhanced regulatory measures for 

Arctic OCS exploratory drilling. The 

current rulemaking focuses primarily on 

reasonably foreseeable Arctic OCS 

exploratory drilling activities that use 

MODUs, and on related operations 

during the Arctic open-water drilling 

season (generally late June to early 

November). After the proposed 

requirements for exploratory drilling are 

finalized and applied to those activities, 

DOI will be able to assess whether it 

should apply similar requirements to 

development drilling. 

This proposed rule builds on input 

received from partners and 

stakeholders, key components of Shell’s 

2012 Arctic exploratory drilling 

program, and the additional measures 

BOEM and BSEE required Shell to 

perform under existing regulatory 

authorities. After considering the input 

received and our direct experience from 

Shell’s 2012 Arctic operations, BOEM 

and BSEE have concluded that 

additional exploratory drilling 

regulations would enhance and clarify 

existing regulations and would be 

appropriate as a part of the Arctic OCS 

oil and gas regulatory framework. 

The proposed rule would further the 

Nation’s interest in exploring frontier 

areas, such as those in the Arctic OCS 

region, safely and responsibly, and 

would establish specific operating 

models and requirements that account 

for both the extreme, changing 

conditions that exist on the Arctic OCS 

and Alaska Natives’ cultural traditions 

and need to access subsistence 

resources. 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 potential 

vulnerabilities early in the planning 

process so that corrections can be made 

to decrease the potential 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 the Arctic OCS presents. 

In particular, this proposed rule 

would address several important 

objectives, including ensuring that 

operators: 

i. Design and conduct exploration 

programs in a manner suitable for Arctic 

OCS conditions; 

ii. Develop an IOP that would address 

all phases of their proposed Arctic OCS 

exploration program and submit the IOP 

to BOEM at least 90 days in advance of 

filing an EP; 

iii. Have access to and the ability to 

promptly deploy SCCE while drilling 

below or working below the surface 

casing; 

iv. 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; 

v. Have the capability to predict, 

track, report, and respond to ice 

conditions and adverse weather events; 

vi. Effectively manage and oversee 

contractors; and 

vii. Develop and implement OSRPs 

designed and executed in a manner 

suitable for the unique Arctic OCS 

operating environment and have the 

necessary equipment, training, and 

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10As explained in the Initial RIA, we used a 10- 

year period for this analysis because of the 

uncertainty associated with predicting industry’s 

activities and the advancement of technical 

capabilities. For example, the costs associated with 

a particular new technology may decrease as the 

technology is adopted more broadly over time. In 

other cases, an existing technology may be replaced 

by a lower-cost alternative. 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. 

11Although Shell included a relief rig 

requirement in its Beaufort Sea and Chukchi Sea 

EPs for the 2012 season (which BOEM approved 

and which were subsequently incorporated in 

Shell’s APDs, as approved by BSEE), BOEM would 

have required that a relief rig be included in Shell’s 

EPs under the authority currently found in 30 CFR 

550.213 and 550.220 in any event. 

personnel for oil spill response on the 

Arctic OCS. 

The following provisions of the 

proposed rule are expected to result in 

additional costs, above the baseline, to 

the affected industry: 

i. Additional Incident reporting 

requirements; 

ii. Additional pollution prevention 

requirements; 

iii. Additional requirements for 

securing wells; 

iv. Additional BOP pressure testing 

requirements; 

v. Real-time monitoring requirements; 

vi. Additional information 

requirements for APDs; 

vii. Incorporation of proposed draft 

API RP 2N, Third Edition; 

viii. Additional SCCE requirements; 

ix. Relief rig requirements; 

x. Additional auditing requirements; 

xi. Real-time location tracking 

requirements; 

xii. IOP requirements; 

xiii. Additional requirements for EPs; 

and 

xiv. Industry familiarization with the 

rule. 

2. Alternatives 

As explained in the Initial RIA, BOEM 

and BSEE have considered three 

alternatives for dealing with the safety 

and environmental concerns that 

exploratory drilling activities on the 

Arctic OCS have raised: 

i. Promulgate the rule changes 

described in this proposed rule; or 

ii. 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 

§ 250.447 of the proposed rule); or 

iii. 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 would 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 approximately $135.1 

million over the 10-year analysis period 

(with 7 percent discounting). The cost 

summary tables below present the total 

costs of the proposed rule with and 

without the additional BOP pressure 

testing requirements. 

BOEM and BSEE also 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 in the Arctic 

region that partners and stakeholders 

have raised, 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. 

3. 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 the proposed rule requires 

that represent a change from the 

baseline. The analysis covers 10 years 

(2015 through 2024) to ensure it 

captures important benefits and costs 

that could result from the proposed 

rule.10 When summarizing the costs and 

benefits, we present the estimated 

annual effects and the 10-year 

discounted totals using discount rates of 

3 and 7 percent, per OMB Circular A– 

4, ‘‘Regulatory Analysis.’’ BOEM and 

BSEE welcome comments on this 

analysis, including comments on the 

assumptions, the baseline, the methods 

used, and on the potential sources of 

data or information on the costs and 

potential benefits of this proposed rule. 

i. Assumptions 

The baseline refers to existing 

regulatory requirements, industry 

standards, and operator prudence. 

According to OMB’s Circular A–4, the 

baseline should be ‘‘the best assessment 

of the way the world would look absent 

the proposed action.’’ 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 only 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: 

a. 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 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.11 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. These costs are estimated at 

$276 million per year per standby rig. 

Based on EPs 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. 

b. Relief Rig Activity Costs: The 

proposed rule would establish a 45-day 

maximum limit on the time necessary to 

complete the relief well operations 

activities. 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 Shell’s 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 5-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, 

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12 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. 

13http://www.boem.gov/EP–PUBLIC–VERSION/. 

the baseline for this analysis includes 

this 38-day requirement from 2012. 

Accordingly, the potential 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 work below the surface 

casing could not take place. 

We recognize that the requirement to 

have the capability to drill a relief well 

to permanently kill an out-of-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 

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. 

The 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.12

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 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 2015,13

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. 

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. 

c. 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 ultimately did not 

conduct 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. 

Based on BOEM’s and BSEE’s 

knowledge of operators engaged in, or 

likely to be engaged in, Arctic OCS 

exploration activities, we also made 

several assumptions about the number 

of operators, rigs, and wells operating 

on the Arctic OCS over the 10-year 

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 

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9950 Federal Register / Vol. 80, No. 36 / Tuesday, February 24, 2015 / Proposed Rules 

14We assume a 138-day drilling season for all 

purposes other than the prior discussion of 

opportunity costs, which uses a 100-day drilling 

season as assumed in the industry presentation to 

OMB. See n.13. 15The 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. 

BOEM and BSEE by lessees and 

operators and other available 

information related to planned or 

potential industry exploratory activities 

for the analysis period. Exhibit 1 

presents these assumptions. We seek 

comments on the reasonableness of 

these assumptions. 

Exhibit 1. Assumptions About the 

Affected Population of Operators and 

Drilling Operations 

Inputs 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 

Operators ......................................................... 1 1 1 3 3 3 3 3 3 3 

Primary rigs ...................................................... 2 2 2 4 4 4 4 4 4 4 

Standby relief rig 1 ............................................ 1 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 

1Standby relief rigs are rigs that are not conducting exploratory drilling and are assumed to incur different costs than relief rigs that are conducting exploratory drilling (i.e., ‘‘primary rigs’’). 

Other data inputs and assumptions 

common to many of the calculations 

include the following: 

d. SCCE and Resource Sharing: The 

proposed rule requires operators to have 

access to, and the ability to promptly 

deploy, 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. We 

also assume that the operator with two 

primary rigs in 2017 will use one set of 

SCCE to satisfy the SCCE requirements 

for both of its rigs. Finally, we assume 

that, of the two operators entering in 

2018, one will purchase the SCCE and 

the other will select the least-cost means 

to comply with the proposed rule and 

enter into resource sharing with an 

operator who has already purchased the 

SCCE. 

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 

represent the most likely scenario based 

on BSEE’s knowledge of the industry. 

BOEM and BSEE also considered a lowcost scenario and a high-cost scenario 

that vary the assumptions for resource 

sharing and purchase of SCCE by 

operators. The Initial RIA for the 

proposed rule discusses the costs 

associated with these scenarios. 

e. Daily Rig Operating Costs: Based on 

BSEE estimates and cost estimation 

methodologies from the BOEM Case 

Study, we assume that rigs on the Arctic 

OCS have a daily operating cost of $2 

million. For the purposes of the 

analysis, we assume that the daily rig 

operating costs remain constant over the 

10-year analysis period. We also assume 

that the drilling season on the Arctic 

OCS lasts 138 days.14

f. BSEE Burden to Review Paperwork 

Submissions: For each paperwork 

submission, we assume that for every 

hour that industry devotes to compile 

and submit information, BSEE will need 

one half hour to review the 

submission.15

g. Wage Rates and Loaded Wage 

Factors: For this analysis, we obtained 

median industry wage rates from the 

Bureau of Labor Statistics 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. To 

account for employee benefits, we 

multiplied the hourly wage rates by 

appropriate loaded wage factors to 

generate hourly compensation rates. The 

Initial RIA for the proposed rule 

includes details on wage rates and 

loaded wage factors used in the 

analysis. 

4. Costs 

The analysis presented in the Initial 

RIA describes the potential costs of the 

proposed rule compared to the baseline. 

Exhibit 2, which follows, summarizes 

these proposed requirements and their 

associated costs to industry and 

government. Please see the Initial RIA 

for details on the exact assumptions and 

calculations. 

i. Additional Incident Reporting 

Requirements: 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, 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 also would be 

required to submit a follow-up written 

report regarding any ice management 

activities undertaken within 24 hours, 

following completion of those activities. 

ii. Pollution Prevention Requirements: 

Operators would be required to capture 

all petroleum-based mud and cuttings 

from operations that use petroleumbased mud. In addition, these 

subparagraphs clarify the Regional 

Supervisor’s discretionary authority to 

require operators to capture all waterbased 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. 

iii. Additional Requirements for 

Securing Wells: 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 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. 

iv. Additional BOP Pressure Testing 

Requirements: 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 

proposed requirement would represent 

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an increased testing frequency 

(compared to the current requirement 

for testing every 14 days). 

v. Real-time Monitoring 

Requirements: These proposed new 

real-time monitoring requirements for 

Arctic OCS exploratory drilling 

operations include 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. They 

also include onshore data transmission, 

monitoring, storage, and notification 

and availability of data to BSEE. 

vi. Additional Information 

Requirements for APDs: This provision 

would require operators to submit 

Arctic OCS-specific information with 

APDs for Arctic OCS exploratory 

drilling. This includes a detailed 

description of how the drilling unit, 

equipment, and materials will be 

prepared for service in Arctic OCS 

Conditions. Operators would be 

required to submit a detailed 

description of all operations necessary 

in Arctic OCS Conditions to transition 

the rig from being underway to 

commencing drilling operations and 

from concluding drilling operations to 

being underway, as well as any 

anticipated repair and maintenance 

plans for the drilling unit and 

equipment. Operators would also be 

required to submit well-specific drilling 

objectives, timelines, and updated 

contingency plans for temporary 

abandonment of the well. Finally, 

operators would be required to submit 

information on weather and ice 

forecasting capability for all phases of 

drilling operations. 

vii. Incorporation of Proposed Draft 

API RP 2N, Third Edition: This 

provision 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 the planning of 

exploratory drilling operations. API RP 

2N is a voluntary consensus standard 

that addresses the unique Arctic 

conditions that affect the planning, 

design, and construction of systems 

used in Arctic and sub-Arctic 

environments. 

viii. Additional SCCE Requirements: 

There are several proposed SCCE 

requirements, including equipment, 

stump testing, well design change 

information requirements, test and 

exercise, records maintenance, and 

documentation. Because the industry 

does not currently engage in resource 

sharing on the Arctic OCS, BOEM and 

BSEE do not have details on how that 

process would be conducted and 

whether, for example, an operator 

would charge for access to equipment. 

The SCCE resource sharing assumptions 

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 for 

these proposed requirements that vary 

the assumptions for resource sharing 

and purchase of SCCE by operators. See 

Section 4.e of the Initial RIA for details 

on the costs associated with these 

scenarios. 

ix. Relief Rig Requirements: When 

conducting exploratory drilling or 

working below the surface casing, 

operators on the Arctic OCS 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. In estimating the costs of this 

provision, BSEE included relief rig 

equipment capital costs and relief rig 

documentation costs, but did not 

include potential costs of the maximum 

7 additional days (above the baseline) 

that drilling or work below the surface 

casing could not take place each season 

as a result of the maximum 45-day 

timeframe. ISOBSEE lacks data on how 

such a limitation would affect future 

exploratory drilling operations. BSEE 

requests information on the potential 

costs, if any, due to the cessation of 

drilling or other work below the surface 

casing up to 7 days (beyond the 

baseline) earlier than would otherwise 

occur without the proposed relief rig 

requirement. Any such comments 

should account for the benefits of other 

operations (such as maintenance and, in 

some cases, drilling a second top hole) 

that could continue on the site after 

drilling or work below the surface 

casing ceases. 

x. Additional Auditing Requirements: 

This provision would increase the 

SEMS audit frequency and facility 

coverage for Arctic OCS exploratory 

drilling operations. 

xi. Real-time Location Tracking 

Requirements: This proposed provision 

describes additional information 

requirements for the emergencyresponse action plan section of the 

OSRP for operators conducting 

exploratory drilling on the Arctic OCS. 

Operators would be required 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. 

xii. IOP Requirements: The proposed 

rule 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 BOEM at least 90 

days in advance of filing an EP. 

xiii. Planning Information 

Requirements to Accompany EPs: This 

includes proposed additional 

information requirements for planning 

information that must accompany EPs 

for operators proposing to conduct 

exploration activities in the Arctic OCS 

Region. 

xiv. Industry Familiarization with the 

New Rule: Assuming 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 also would evaluate whether 

they must take any new action to 

achieve compliance with the rule. 

EXHIBIT 2—10-YEAR AVERAGE ANNUAL COSTS BY PROVISION (WITH NO DISCOUNTING) 

Provision 

10-year average 

annual costs: alternative 1 (with 7- 

day BOP testing 

requirement) 

1-year average 

annual costs: alternative 2 (without 7-day BOP 

testing requirement) 

a. Additional Incident Reporting Requirements ........................................................................................... $5,374 $5,374 

b. Additional Pollution Prevention Requirements ........................................................................................ $13,585 $13,585 

c. Additional Requirements for Securing Wells ........................................................................................... $24,000,000 $24,000,000 

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9952 Federal Register / Vol. 80, No. 36 / Tuesday, February 24, 2015 / Proposed Rules 

EXHIBIT 2—10-YEAR AVERAGE ANNUAL COSTS BY PROVISION (WITH NO DISCOUNTING)—Continued 

Provision 

10-year average 

annual costs: alternative 1 (with 7- 

day BOP testing 

requirement) 

1-year average 

annual costs: alternative 2 (without 7-day BOP 

testing requirement) 

d. Additional BOP Pressure Testing Requirements .................................................................................... $19,2000,000 $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 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 

We also estimated the costs for 

Alternative 1, the proposed rule with 

the additional BOP pressure testing 

requirement, and Alternative 2, the 

proposed rule without the additional 

BOP pressure testing requirements. 

Exhibit 3 summarizes the costs for both 

alternatives using discount rates of 3 

percent and 7 percent. Alternative 1, the 

proposed rule, would result in 

economic costs of $1.2 billion with 3- 

percent discounting and $1.1 billion 

with 7-percent discounting over 10 

years. This estimate assumes the cost 

associated with staging a standby relief 

rig as outlined in Section VI.B.3.(i.e., 

Relief Rig Capital Costs. 

EXHIBIT 3—SUMMARY OF MONETIZED COSTS 1 2

Year 

Industry costs: 

alternative 1 

Industry costs: 

alternative 2 

Government 

costs 

Total costs: 

alternative 1 

Total costs: 

alternative 2 

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. 

2For explanation of the 3-percent and 7-percent discounting methodology, see n. 2 in Exhibit 24 of the Initial RIA. 

5. Benefits 

Many of the potential benefits of the 

proposed rule—based primarily on 

preventing or reducing the duration or 

severity of catastrophic oil spills—are 

difficult to quantify. The proposed rule 

would benefit society and the 

environment by reducing the potential 

for an incident resulting in an oil spill 

and, if an incident does occur, by 

reducing the duration or severity of the 

spill. 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 of species; 

and reducing potential conflicts 

between OCS oil and gas activities and 

the 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 effectiveness of stopping or 

containing a spill already underway. 

The following break-even analysis 

describes the reduction in the duration 

of a catastrophic oil spill that would be 

needed to generate certain quantifiable 

benefits equal to or greater than the 

estimated costs associated with this 

proposed rule. In addition, because the 

probability and length of a catastrophic 

oil spill would be reduced, other 

benefits—beyond what we captured in 

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Federal Register / Vol. 80, No. 36 / Tuesday, February 24, 2015 / Proposed Rules 9953 

16A catastrophic oil spill is a low-probability, 

high-consequence event because it is an event that 

occurs infrequently, but has large consequences 

when it does occur. For such events, it is difficult 

to know with any certainty the probability of the 

event actually occurring, or to precisely 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 and amount 

of oil, the location of the spill, the areal distribution 

of the release, the sensitivity of the ecosystem 

affected, and the weather. 

the break-even analyses—would result 

from the proposed rule. Due to 

challenges in measuring these 

additional benefits, we do not offer a 

quantitative assessment of them; 

instead, we present a qualitative 

discussion. 

i. Break-Even Analysis: BOEM and 

BSEE conducted a break-even analysis 

of the proposed rule (Alternative 1) 

because of the difficulties associated 

with estimating the benefits of reducing 

the probability and consequences of a 

catastrophic oil spill and the 

uncertainty and measurement problems 

associated with several categories of 

benefits.16

For the proposed rule, using the 

estimated discounted costs at 3 and 7 

percent and the potential benefits (in 

terms of avoided costs of incidents), we 

calculated a break-even number of 

avoided days of spilled oil if a 

catastrophic oil spill were to occur. 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’s 

achieving positive net benefits, should a 

catastrophic spill occur (i.e., it is costbeneficial). We also show the estimated 

total cost of a catastrophic oil spill 

relative to the total cost of the proposed 

rule. Exhibit 4 presents the total cost of 

a catastrophic spill and the 10-year cost 

of the rule. 

EXHIBIT 4—TOTAL COST OF A CATASTROPHIC OIL SPILL COMPARED TO THE 10-YEAR COST OF THE RULE

Location 

Cost of a spill 

($ 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 

Quantifiable costs of a catastrophic oil 

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. Thus, quantifiable costs 

of an oil spill are more than the cost of 

the proposed rule; however, the 

probability of a catastrophic oil spill is 

very low. A catastrophic spill resulting 

from exploratory drilling on the Arctic 

OCS, for example, is considered 

unlikely due to the nature of the 

geology, shallow water depth, and 

simplicity of the wells. However, due to 

the limited drilling history on the Arctic 

OCS, projections cannot be made with 

certainty. Exhibit 5 presents a summary 

of the results of the break-even analysis 

for the proposed rule; a full description 

of the results and methodology is 

contained in the Initial RIA. 

EXHIBIT 5—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 

Chukchi Sea .......................................... $177.5 $1,112 $1,224 6.3 6.9 

Beaufort Sea .......................................... 113.6 1,112 1.224 9.8 10.8 

Over the 10-year cost analysis period, 

the number of avoided/reduced days of 

a catastrophic oil spill needed to breakeven 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 could be between 40 

and 75 days and an incident in the 

Beaufort Sea could 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 benefits of 

the proposed rule under the 

circumstances. However, we invite 

comments on the assumptions, data, 

and methods used in this break-even 

analysis, as described fully in the Initial 

RIA. We also invite comments on 

whether there is a better alternative 

method for evaluating the costs and 

benefits of the proposed rule. 

ii. Qualitative Benefits: Because 

BOEM and BSEE used a conservative 

approach in the valuation of an oil spill 

in the break-even analysis, the 

identified cost of a catastrophic oil spill 

can be considered a lower bound of the 

true cost of such an event to society and 

of the potential benefits from preventing 

such an event. Although the break-even 

analysis captures some of 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 

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9954 Federal Register / Vol. 80, No. 36 / Tuesday, February 24, 2015 / Proposed Rules 

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. For example, many nonnative Alaskans, and many other 

Americans who do not live in Alaska, 

place a very high value on protecting 

the health of the ecosystem, including 

the sensitive environment and wildlife, 

of this largely frontier area. Thus, the 

impact of a catastrophic oil spill, would 

have extremely high cultural and 

societal costs, and prevention of such a 

catastrophe would have 

correspondingly high cultural and 

societal benefits. 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 break-even 

analysis captures only a portion of the 

value to society. 

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 environment 

and species, protection of Alaska 

Natives’ cultural values, and removal of 

impediments to 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 § 550.204 would facilitate 

interagency coordination between DOI 

and other relevant Federal agencies, as 

recommended in the 60-Day Report. 

Exhibit 6 presents the provisions of 

the proposed rule along with their 

primary qualitative benefits, such as 

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. 

EXHIBIT 6—EXAMPLES OF QUALITATIVE

BENEFITS BY PROVISION

Provision Primary benefits 

a. Additional Incident 

Reporting Requirements.

Improves oversight of 

operations by Federal agencies. 

b. Pollution Prevention Requirements.Minimizes natural resource impacts. 

EXHIBIT 6—EXAMPLES OF QUALITATIVE

BENEFITS BY PROVISION—Continued 

Provision Primary benefits 

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 

API RP 2N, Third 

Edition.

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 Reduces risk of a 

spill. 

m. Planning Information Requirements 

to Accompany EPs.

Improves oversight of 

operations by Federal agencies. 

n. Industry Familiarization with the 

New Rule.

General. 

6. 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 10-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 10-year study period. 

In addition to the quantifiable 

benefits, there are significant qualitative 

benefits, including protection of Alaska 

Native communities’ cultural resources 

and subsistence needs and other 

unquantifiable environmental, cultural, 

and societal benefits. Accordingly, 

BOEM and BSEE have determined that 

the benefits of the proposed rule justify 

its potential costs and that it is 

appropriate to proceed with this 

proposed rule. 

C.E.O. 13563 

E.O. 13563 reaffirms the principles of 

E.O. 12866 while calling for 

improvements in the Nation’s regulatory 

system to promote predictability, to 

reduce uncertainty, and to use the best, 

most innovative, and least burdensome 

tools for achieving regulatory ends. In 

addition, E.O. 13563 directs agencies to 

consider regulatory approaches that 

reduce burdens and maintain flexibility 

and freedom of choice for the public 

where these approaches are relevant, 

feasible, and consistent with regulatory 

objectives. It also emphasizes that 

regulations must be based on the best 

available science and that the 

rulemaking process must allow for 

public participation and an open 

exchange of ideas. We developed this 

proposed rule in a manner consistent 

with these requirements. BOEM and 

BSEE worked closely with engineers 

and technical staff to ensure this 

rulemaking follows sound engineering 

principles and options through research, 

standards development, and interaction 

with industry. 

D. Regulatory Flexibility Act 

The Regulatory Flexibility Act (RFA), 

5 U.S.C. 601–612, requires agencies to 

analyze the economic impact of 

proposed regulations when a significant 

economic impact on a substantial 

number of small entities is likely and to 

consider regulatory alternatives that will 

achieve the agency’s goals while 

minimizing the burden on small 

entities. In addition, the Small Business 

Regulatory Enforcement Fairness Act of 

1996, 5 U.S.C. 601note, requires 

agencies to produce compliance 

guidance for small entities if the rule 

has a significant economic impact. For 

the reasons explained in this section, 

BOEM and BSEE have concluded that 

the proposed rule is likely to have a 

significant economic impact on a 

substantial number of small entities 

and, therefore, a regulatory flexibility 

analysis is required. This Initial 

Regulatory Flexibility Analysis assesses 

the impact of the proposed rule on small 

entities, as defined by the applicable 

Small Business Administration size 

standards. 

1. Description of the Reasons Why 

Action by the Agency Is Being 

Considered 

Although a comprehensive OCS oil 

and gas regulatory program exists, 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 

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17See 5 U.S.C. 601. 

18See www.boem.gov/uploadedFiles/BOEM/

About_BOEM/BOEM_Regions/Alaska_Region/

Leasing_and_Plans/Leasing/Alaska_Lease_

Holdings_by_Owner_or_Partial_Owner.pdf. 

known as MODUs) on the Arctic OCS. 

The U.S. Arctic region, as recognized by 

the U.S. 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 

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 and 

clarify existing regulations and would 

be appropriate for a more holistic Arctic 

OCS oil and gas regulatory framework. 

This proposed rulemaking is intended 

to ensure that 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. 

Extreme environmental conditions, 

geographic remoteness, and a relative 

lack of fixed infrastructure and existing 

operations characterize the region. 

These factors are key 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: 

i. Design and conduct exploration 

programs in a manner suitable for Arctic 

OCS conditions; 

ii. Develop an IOP that would address 

all phases of the proposed Arctic OCS 

exploration program and submit the IOP 

to BOEM at least 90 days in advance of 

filing the EP; 

iii. Have access to and the ability to 

promptly deploy SCCE, while drilling 

below or working below the surface 

casing; 

iv. 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; 

v. Have the capability to predict, 

track, report, and respond to ice 

conditions and adverse weather events; 

vi. Effectively manage and oversee 

contractors; and 

vii. Develop and implement OSRPs 

designed and executed in a manner 

suitable for the unique Arctic OCS 

operating environment and 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 can 

be made to decrease the potential for 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 the Arctic presents. 

2. We identified the following 

provisions of the proposed rule as 

having a cost to industry: 

i. Additional incident reporting 

requirements; 

ii. Pollution prevention requirements; 

iii. Additional requirements for 

securing wells; 

iv. Additional BOP pressure testing 

requirements; 

v. Real-time monitoring requirements; 

vi. Additional information 

requirements for APDs; 

vii. Incorporation of proposed draft 

API RP 2N; 

viii. Additional SCCE requirements; 

ix. Relief rig requirements; 

x. Additional auditing requirements; 

xi. Real-time location tracking 

requirements; 

xii. IOP requirements; 

xiii. Additional requirements for EPs; 

and 

xiv. Industry familiarization with the 

rule. 

3. Succinct Statement of the Objectives 

of, and Legal Basis for, the Proposed 

Rule 

The objectives and legal basis are 

described in part II, Background, of the 

proposed rule. 

4. Description of and, Where Feasible, 

an Estimate of the Number of Small 

Entities to Which the Proposed Rule 

Will Apply 

The RFA defines small entities as 

small businesses, small nonprofits, and 

small governmental jurisdictions. We 

have identified no small nonprofits or 

small government jurisdictions that the 

proposed rule would impact, so this 

analysis focuses on impacts on small 

businesses (hereafter referred to as 

‘‘small entities’’). A small entity is one 

that is ‘‘independently owned and 

operated and which is not dominant in 

its field of operation.’’ 17 The definition 

of small business varies from industry to 

industry to capture industry size 

differences properly. 

The proposed rule would affect 

operators and holders of Federal oil and 

gas leases that could conduct 

exploratory drilling on the Arctic OCS. 

According to BOEM’s list of 

leaseholders on the Arctic OCS as of 

May 2014, 10 businesses hold leases on 

the Arctic OCS.18 Three of these 

businesses are anticipated to conduct 

exploratory drilling on the Arctic OCS 

over the next 10 years, although any 

business holding a lease could conduct 

exploratory drilling on the Arctic OCS 

and would thus be subject to the 

requirements of this proposed rule. 

Businesses subject to this rule fall 

under North American Industry 

Classification System codes 211111 

(Crude Petroleum and Natural Gas 

Extraction) and 213111 (Drilling Oil and 

Gas Wells). For these classifications, a 

small business is defined as one with 

fewer than 500 employees. Based on 

this criterion, only one business 

currently holding a Federal oil and gas 

lease on the Arctic OCS is considered 

small. Although BOEM and BSEE do not 

expect a small entity to conduct 

exploratory drilling on the Arctic OCS 

during the 10-year analysis period, any 

business holding a lease could operate 

on the Arctic OCS. Using the number of 

businesses holding such leases as the 

universe subject to this rule, 10 percent 

(1 of 10) of the firms are considered 

small. Thus, the proposed rule would 

affect a ‘‘substantial number’’ of small 

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19See the Initial RIA for the proposed rule for 

details on baseline assumptions. We state all costs 

in 2012 constant dollars. 

20Totals might not add because of rounding. 

21As explained in the initial RIA, proposed 

§ 254.80(c) does not require any specific real-time 

tracking system, so we used AIS as a representative 

system for costs analysis purposes. 

22These totals are derived, respectively, as 

follows: ($270,000,000 + $1,200,000 + $500,000) 

and ($160,208 + $160,208 + $959 + $1,174 + 

$5,755). 

entities, defined by BOEM and BSEE as 

10 percent or more of the potentially 

affected entities. Thus, although we do 

not expect that a small entity would 

conduct exploratory drilling during the 

analysis period, to be conservative, we 

have conducted this RFA analysis to 

demonstrate the likely effects the 

proposed rule would have on a 

hypothetical small operator. 

5. Description of the Projected 

Reporting, Recordkeeping and Other 

Compliance Requirements of the 

Proposed Rule, Including an Estimate of 

the Classes of Small Entities That Will 

Be Subject to the Requirement and the 

Type of Professional Skills Necessary 

for Preparation of the Report or Record 

BOEM and BSEE have estimated the 

incremental costs for small oil and gas 

leaseholders that decide to engage in 

exploratory drilling on the Arctic OCS. 

This analysis reflects only costs 

associated with activities and capital 

investments required by the proposed 

rule that represent a change from the 

baseline. The baseline for this proposed 

rule includes existing regulations, 

standard industry practices, operator 

prudence, and assumptions based on 

requirements for Shell’s 2012 Arctic 

OCS operations that were imposed by 

BOEM or BSEE under their existing 

regulatory authorities.19 Cost estimates 

included in this analysis for the 

provisions of the proposed rule are 

those presented in detail in the Initial 

RIA. 

i. Total Cost Estimates by Provision 

BOEM and BSEE assessed the costs 

associated with the proposed regulation 

by estimating the cost for a hypothetical 

small operator. We assumed that this 

operator would conduct an exploratory 

drilling program with one rig, two wells, 

two APDs, and one OSRP, IOP, and EP 

each. For each provision, we estimated 

the per-rig, per-well/APD, per-OSRP, 

per-IOP, and per-EP cost, where 

applicable. Following is a summary of 

the unit costs using the estimates 

developed in the RIA.20 Please refer to 

the Initial RIA for details on the cost 

estimates. 

For the incident reporting activities, 

we estimated the per-rig cost at $1,146, 

including both the costs for ice 

movement activity oral reports ($313 

per rig) and the costs associated with 

written reports ($834 per rig). For the 

pollution prevention requirements, we 

estimated the costs per rig to capture 

and transport mud and cuttings to be 

$4,245. For the additional requirements 

for securing wells, we included both the 

capital costs ($2,000,000) and the labor 

and operational costs ($3,000,000) for a 

total per-well cost of $5,000,000. 

We assessed the costs for Alternative 

1 (the proposed rule with the additional 

BOP pressure-testing requirements) and 

Alternative 2 (the proposed rule without 

the additional BOP pressure-testing 

requirements). For the additional BOP 

pressure-testing requirements included 

under Alternative 1, BSEE included the 

per-rig labor cost of $6,000,000. These 

costs are not included in the cost 

estimates for Alternative 2. (See Section 

6 following for details on the 

alternatives.) For the proposed real-time 

monitoring requirements, we estimated 

a per-rig labor cost of $690,000. For the 

proposed additional information 

requirements for the APDs, we 

estimated a per-rig labor cost of $1,491 

and a per-well labor cost of $1,305. For 

the proposed incorporation of draft API 

RP2N, Third Edition, we estimated a 

per-rig labor cost of $1,918. For the 

enhanced auditing requirements, we 

estimated a per-rig labor cost of 

$129,000. For the proposed real-time 

tracking requirements, we estimated a 

per-OSRP labor cost of $401. 

In addition, we included a cost of 

$102,624 ($63,274 upfront cost plus 

$39,350 annual cost) per rig to account 

for the purchase, operation, and 

maintenance of an Automatic 

Identification System (AIS) as an 

example of costs to comply with the 

real-time tracking requirements for oil 

spill response resources.21 For the 

proposed IOP requirements, we 

estimated a per-IOP labor cost of $8,633. 

For the proposed planning information 

requirements to accompany the EPs, we 

estimated a per-EP labor cost of $4,316. 

Finally, we estimated a per-operator 

cost of $1,042 for the time needed for an 

operator to become familiar with the 

rule. 

The proposed SCCE requirements 

have several different cost components 

for both rigs and wells. We estimated a 

one-time capital cost per rig of 

$270,000,000 and an annual 

redeployment cost of $1,200,000 per rig. 

For the aggregate cost of the SCCE, we 

varied the assumptions for purchase and 

redeployment costs based on whether 

the operator purchases the equipment or 

engages in resource sharing, as 

discussed later. For the Regional 

Supervisor-initiated tests, we estimated 

a per-rig cost of $500,000. For the stump 

tests, we assumed that the operator 

would use a pre-positioned capping 

stack (PPCS) and estimated that each 

PPCS stump test costs $160,208 per 

well. We assumed one stump test before 

installation on each well and one stump 

test before deployment. Although the 

operator could instead use a dry-stored 

capping stack, we conservatively 

assumed that the operator would use a 

PPCS, which results in higher costs. For 

the proposed information requirements 

for the well design change, we estimated 

a per-well labor cost of $959. We also 

estimated a per-well labor cost of $1,174 

to maintain the SCCE records and a perwell labor cost of $5,755 for the APD 

documents. The total SCCE 

requirements sum to $271,700,000 per 

rig and $328,305 per well.22

For the proposed relief rig 

requirements, we included the costs 

associated with the proposed 

information documentation 

requirements for the relief rig. We 

estimated the labor cost associated with 

the documentation requirements for the 

relief rig to be $14,591 per rig. As 

discussed in the Initial RIA, we do not 

include costs associated with the 

proposed 45-day maximum limit on the 

time necessary to complete the required 

relief rig activities under Section 

250.472 because we lack information 

regarding potential costs, if any, above 

the baseline that might accrue from the 

cessation of drilling or other work below 

the surface casing under this proposed 

requirement. 

We present the least-cost means to 

comply with the proposed rule, and 

thus assume that a small entity would 

not incur the costs of a standby relief rig 

and would enter into a resource sharing 

agreement to comply with the relief rig 

requirements. If, however, a small entity 

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. 

Exhibit 7 presents the unit costs per 

provision for a small operator. These 

estimates include the full cost of the 

proposed SCCE requirements, assuming 

no resource sharing with another 

operator, and costs associated with the 

enhanced BOP pressure testing 

requirements under Alternative 1. 

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Federal Register / Vol. 80, No. 36 / Tuesday, February 24, 2015 / Proposed Rules 9957 

23See 77 FR 50856 (August 22, 2012). The final 

RIA for that rulemaking can be viewed at 

www.regulations.gov/#!documentDetail;D=BSEE– 

2012–0002–0047. The data in the source document 

are from the Office of Natural Resources Revenue. 

The data source reports the total 2009 small 

business revenue to be $4,113,000,000. We 

calculated the average revenue per small business 

by dividing the total small business revenue by the 

number of small businesses ($4,113,000,000/90) to 

obtain an average of $45,700,000 per operator. 

24As stated earlier, BOEM and BSEE do not 

expect an actual small operator to conduct 

exploratory drilling on the Arctic OCS during the 

10-year period of this analysis, although we have 

prepared this analysis to be conservative (since one 

current Arctic OCS lessee is a small entity). Thus, 

this analysis considers the average annual revenue 

of small OCS operators. 

EXHIBIT 7—UNIT COST OF THE PROPOSED RULE BY PROVISION (WITH NO RESOURCE SHARING) 

Provision Cost per rig Cost per well/APD Cost per operator 

(EP/IOP/OSRP) 

a. Additional Incident Reporting Requirements ....................................... $1,146 .................................... ....................................

b. Pollution Prevention Requirements ..................................................... 4,245 .................................... ....................................

c. Additional Requirements for Securing Wells ....................................... .................................... 5,000,000 ....................................

d. Additional BOP Pressure Testing Requirements ................................ 6,000,000 .................................... ....................................

e. Real-time Monitoring Requirements .................................................... 690,000 .................................... ....................................

f. Additional Information Requirements for APDs ................................... 1,491 1,305 ....................................

g. Incorporation of draft API RP 2N, Third Ed. ....................................... 1,918 .................................... ....................................

h. Additional SCCE Requirements .......................................................... 271,700,000 328,305 ....................................

i. Relief Rig Requirements ....................................................................... 14,591 .................................... ....................................

j. Additional Auditing Requirements ........................................................ 129,000 .................................... ....................................

k. Real-time Location Tracking Requirements ........................................ 102,624 .................................... 401 

l. IOP Requirements ................................................................................ .................................... .................................... 8,633 

m. Planning Information Requirements to Accompany Eps ................... .................................... .................................... 4,316 

n. Industry Familiarization with the New Rule ......................................... .................................... .................................... 1,042 

Total Annual Cost Per Rig/Well/Operator 1 ...................................... 278,645,016 5,329,610 14,393 

1Totals might not add because of rounding. 

ii. Total Cost Burden for Small Entities 

We calculated the cost to a single 

small operator under different 

alternatives and differing assumptions 

regarding resource sharing of the SCCE. 

We assumed that the SCCE purchase 

cost would be $270,000,000 and the 

annual redeployment cost would be 

$1,200,000. 

We estimated the highest-cost 

scenario for a small operator to present 

the most conservative estimate possible 

of the potential for a significant 

economic impact. Under this highestcost scenario, the small operator would 

need to purchase and deploy the SCCE 

(i.e., no resource sharing) and would be 

subject to the additional BOP pressuretesting requirements under Alternative 

1. We also estimated the costs of 

Alternative 2 (i.e., no additional BOP 

pressure-testing requirements) assuming 

no resource sharing of SCCE. Under the 

lowest-cost scenario, the small operator 

would employ resource sharing of SCCE 

and would not be subject to the 

additional BOP pressure-testing 

requirements (as in Alternative 2). We 

also estimated the costs of Alternative 1 

assuming resource sharing of SCCE. 

Next, we estimated the average annual 

revenue of an affected small operator. 

We used an annual revenue estimate of 

$45.7 million for the small operator as 

calculated in the final RIA for BSEE’s 

‘‘Oil and Gas and Sulphur Operations 

on the Outer Continental Shelf: Oil and 

Gas Production Safety Systems’’ 

rulemaking (77 FR 50856, Aug. 22, 

2012).23 We used this estimate of 

average annual revenue to calculate the 

ratio of total costs of the proposed rule 

as a percentage of average annual 

revenue to determine if the proposed 

rule would result in a significant 

economic impact on small entities. 

Exhibit 8 presents estimates of the 

total first-year costs to a small operator 

under each scenario and the total firstyear costs as a percentage of average 

annual revenue. Under all scenarios, the 

first-year costs as a percentage of 

revenue surpass the 1-percent threshold 

used to define a significant economic 

impact. Even under the lowest-cost 

scenario, assuming that the operator 

would engage in resource sharing of the 

SCCE and would not be subject to the 

additional BOP pressure-testing 

requirements (as in Alternative 2), the 

small operator would experience a total 

first-year cost equal to 29 percent of 

their average annual revenue. For the 

scenarios that assume no resource 

sharing of SCCE, the total first-year costs 

as a percentage of revenue are greater 

than 100 percent, indicating that the 

total first-year costs the small operator 

would experience would be greater than 

its total average annual revenue.24

EXHIBIT 8—FIRST-YEAR COSTS AS A PERCENTAGE OF AVERAGE ANNUAL REVENUE PER OPERATOR

Scenario 

Total first-year cost Total first-year cost as 

percent of revenue 

A B = A/$45.7 million 

Alternative 1 with No Resource Sharing of SCCE .......................................................................... $289,318,628 633 

Alternative 2 with No Resource Sharing of SCCE .......................................................................... 283,318,628 620 

Alternative 1 with Resource Sharing of SCCE ................................................................................ 19,318,628 42 

Alternative 2 with Resource Sharing of SCCE ................................................................................ 13,318,628 29 

Exhibit 9 presents estimates of the 

total annual ongoing costs (the costs in 

the second year and after) to a small 

operator under each scenario, or the 

costs incurred on an annual basis after, 

and not including, the first-year of the 

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9958 Federal Register / Vol. 80, No. 36 / Tuesday, February 24, 2015 / Proposed Rules 

25Conversely, oil and gas exploration has 

inherent financial risk in that the exploration 

activities might not yield an economically viable 

discovery of oil or natural gas. 

26The proposed revision to 30 CFR 250.300(b) 

that would prohibit the discharge of petroleumbased mud and associated cuttings may overlap 

with existing EPA general permits for the Beaufort 

and Chukchi Seas under the National Pollution 

Discharge Elimination System regulations (40 CFR 

part 122) while those permits remain in effect. 

However, the proposed rule would not add any 

regulatory burden to any small entity in that regard. 

analysis period. Exhibit 9 also presents 

the total annual ongoing costs as a 

percentage of average annual revenue. 

Under all scenarios, the annual ongoing 

costs as a percentage of revenue surpass 

the 1-percent threshold used to define a 

significant economic impact. Under 

Alternative 1, a small operator would 

experience total annual ongoing costs 

equal to 42 percent of their average 

annual revenue, and under Alternative 

2, total annual ongoing costs to small 

operators would be equal to 29 percent 

of average annual revenue. Costs after 

the first year do not vary based on SCCE 

resource-sharing assumptions because 

we assumed that SCCE capital costs (if 

any) would be incurred in the first year. 

BOEM and BSEE conclude that the 

proposed rule would have a ‘‘significant 

economic impact’’ on small operators 

because costs are greater than 1 percent 

of revenue in every year of the analysis 

period. Although costs are anticipated 

to be lower for operators after the first 

year, during which the operator is 

assumed to purchase capital equipment, 

annual costs are still estimated to be 

well above the 1-percent threshold in 

the subsequent years of the 10-year 

analysis period. 

EXHIBIT 9—ANNUAL ONGOING COSTS AS A PERCENTAGE OF AVERAGE ANNUAL REVENUE PER SMALL OPERATOR

Scenario 

Total annual ongoing 

cost 

Total annual ongoing 

cost as percent of 

revenue 

A B = A/$45.7 million 

Alternative 1 with No Resource Sharing of SCCE .......................................................................... $19,125,311 42 

Alternative 2 with No Resource Sharing of SCCE .......................................................................... 13,125,311 29 

Alternative 1 with Resource Sharing of SCCE ................................................................................ 19,125,311 42 

Alternative 2 with Resource Sharing of SCCE ................................................................................ 13,125,311 29 

The conclusion that the rule would 

have a ‘‘significant economic impact’’ 

on small operators is based on past 

revenue of operators and does not 

account for any potential increase in 

revenue that operators might experience 

if Arctic OCS exploratory drilling 

operations lead to production. Operators 

conducting exploratory drilling on the 

Arctic OCS that experience a significant, 

economically viable discovery of oil or 

natural gas and that proceed to the 

production phase could experience a 

significant increase in revenue. Thus, 

the analysis presented in this section 

could understate the revenue, resulting 

in an overstatement of the impact of the 

rule when expressed as the ratio of costs 

to annual revenue.25

6. Identification of All Relevant Federal 

Rules That May Duplicate, Overlap, or 

Conflict With the Proposed Rule 

The proposed rule does not conflict 

with any relevant Federal rules or 

duplicate or overlap with any Federal 

rules in any way that would 

unnecessarily add cumulative 

regulatory burdens on small entities 

without any gain in regulatory 

benefits.26 However, BOEM and BSEE 

request comments identifying any 

Federal rules that may duplicate, 

overlap, or conflict with the proposed 

rule. 

7. Description of Significant 

Alternatives to the Proposed Rule 

Several provisions of the proposed 

rule are performance based, which will 

enable operators to devise optimal 

strategies for reducing the cost burden 

of the proposed rule. In addition, 

operators might be able to reduce costs 

through resource sharing. BOEM and 

BSEE strongly encourage operators 

proposing exploratory drilling activities 

on the Arctic OCS to enter into mutual 

aid agreements for the sharing of 

vessels, relief well rigs, and other assets 

or services associated with responding 

to an oil spill or other emergency. 

BOEM and BSEE have considered 

three major regulatory alternatives for 

dealing with the safety and 

environmental concerns raised by 

exploration activities on the Arctic OCS: 

i. Promulgate the rule changes 

proposed in this proposed rule for the 

Arctic OCS; or 

ii. Promulgate the rule changes 

described in the proposed rule without 

including the 7-day BOP pressuretesting requirement for Arctic OCS 

exploratory drilling operations (in 

§ 250.447 of the proposed rule); or 

iii. Take no regulatory action and 

continue to rely on existing OCS oil and 

gas regulations, industry standards, and 

operator prudency. 

BSEE has decided not to issue a 

proposed rule without the 7-day BOP 

testing requirement. Although 

maintaining the testing frequency at 14 

days would reduce the total costs of the 

proposed rule, the additional testing 

requirement is intended to help ensure 

that BOPs deployed in the Arctic OCS 

function properly and reduce the risk of 

blowouts. 

BOEM and BSEE also 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 partners and 

stakeholders have raised 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. Further, the projected 

potential for impacts on small entities is 

mitigated by the fact that the agencies 

do not anticipate any small entity 

independently pursuing exploration 

drilling on the Arctic OCS during the 

10-year analysis period. 

E. Unfunded Mandates Reform Act of 

1995 (UMRA) 

This proposed rule would not impose 

an unfunded Federal mandate on State, 

local, or tribal governments but would, 

if finalized, create a Federal 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. Accordingly, DOI has 

prepared written statements satisfying 

the applicable requirements of the 

UMRA, 2 U.S.C. 1501 et seq. Those 

requirements are addressed in the Initial 

RIA and initial RFA analyses for this 

proposed rule and in the proposed rule 

itself. 

Among other things, the proposed 

rule, Initial RIA, and/or Initial RFA: 

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Federal Register / Vol. 80, No. 36 / Tuesday, February 24, 2015 / Proposed Rules 9959 

1. Identify the provisions of Federal 

law (OCSLA, CWA, and OPA) under 

which this rule is being proposed; 

2. Include a quantitative assessment 

of the anticipated costs to the private 

sector (i.e., expenditures on labor and 

equipment) of the proposed rule; and 

3. Include qualitative and quantitative 

assessments of the anticipated benefits 

of the proposed rule. 

Since all of the anticipated 

expenditures by the private sector 

analyzed in the Initial RIA and the 

Initial RFA analyses would be borne by 

the offshore oil and gas exploration 

industry in the Arctic region, the Initial 

RIA and Initial RFA analyses satisfy the 

UMRA requirement to estimate any 

disproportionate budgetary effects of the 

proposed rule on a particular segment of 

the private sector (i.e., the offshore oil 

and gas industry). 

As discussed in the Regulatory 

Planning and Review section of this 

proposed rule, and explained fully in 

the Initial RIA, BOEM and BSEE 

considered three major regulatory 

alternatives for dealing with the safety 

and environmental concerns raised by 

exploration activities on the Arctic OCS. 

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 region, BOEM and BSEE have 

determined that it is not practical to 

accurately estimate such effects. Since 

the proposed rule would not impose any 

requirements on any entities, other than 

companies and their contractors 

engaged in Arctic OCS exploration 

activities, any budgetary effects in that 

area would be at least indirect, 

secondary results of actions or decisions 

taken by regulated (or unregulated) 

entities, based on a variety of 

circumstances (such as the price of oil, 

each entity’s overall financial health, 

and the prospects of success of any 

exploratory drilling). Because each of 

those factors is variable and 

unpredictable, it is not practical to 

estimate how those factors might affect 

an entity’s future decisions, or what 

indirect impacts, if any, such decisions 

could have on future regional budgets. 

Similarly, BOEM and BSEE have 

determined that it is not reasonably 

feasible to accurately estimate the 

potential effects, if any, of the proposed 

rule on the National economy (e.g., 

productivity, economic growth, 

employment, international 

competitiveness). The proposed rule, if 

finalized, would only affect 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 

economic impacts. 

F. Takings Implication Assessment 

Under the criteria in E.O. 12630, this 

proposed rule would not have 

significant takings implications. The 

proposed rule is not a governmental 

action capable of interference with 

constitutionally protected property 

rights. A Takings Implication 

Assessment is not required. 

G. Federalism (E.O. 13132) 

Under the criteria in E.O. 13132, this 

proposed rule would not have 

federalism implications. This proposed 

rule would not substantially and 

directly affect the relationship between 

the Federal and State governments. To 

the extent that State and local 

governments have a role in OCS 

activities, this proposed rule would not 

affect that role. A Federalism 

Assessment is not required. 

H. Civil Justice Reform (E.O. 12988) 

This proposed rule complies with the 

requirements of E.O. 12988. 

Specifically, this rule: 

1. Meets the criteria of § 3(a) requiring 

that all regulations be reviewed to 

eliminate errors and ambiguity and be 

written to minimize litigation; and 

2. Meets the criteria of § 3(b)(2) 

requiring that all regulations be written 

in clear language and contain clear legal 

standards. 

I. Consultation With Indian Tribes (E.O. 

13175) 

Under the criteria in E.O. 13175, 

Consultation and Coordination with 

Indian Tribal Governments (dated 

November 6, 2000), DOI’s Policy on 

Consultation with Indian Tribes 

(Secretarial Order 3317, Amendment 2, 

dated December 31, 2013), and the 

Alaska Native Corporation Consultation 

Policy (dated August 12, 2012), we 

evaluated and determined that the 

subject matter of this rulemaking would 

have tribal implications for Alaska 

Natives. As described earlier, future 

Arctic OCS exploratory drilling 

activities conducted pursuant to this 

proposed rule could affect Alaska 

Natives, particularly their ability to 

engage in subsistence and cultural 

activities. 

BOEM and BSEE are committed to 

regular and meaningful consultation 

and collaboration with tribes on policy 

decisions that have tribal implications 

including, as an initial step, through 

complete and consistent 

implementation of E.O. 13175, together 

with related orders, directives, and 

guidance. Therefore, BOEM and BSEE, 

in coordination with the Office of the 

Secretary of the Interior’s Senior Alaska 

Representative, engaged in listening 

sessions, Government-to-Government 

Tribal consultations, and Governmentto-ANCSA Corporations consultations to 

discuss the subject matter of the 

proposed rule and solicit input in the 

development of the proposed rule. 

Government-to-Government 

consultation was held in Barrow 

between BOEM, BSEE, and the ICAS on 

June 6, 2013, to both provide 

background to and obtain information 

from ICAS leaders and council 

members. The following day, June 7, 

2013, BOEM and BSEE met with leaders 

and council members of the Native 

Village of Barrow in a separate 

Government-to-Government 

consultation. All Alaska Native input 

provided during the meetings was 

subsequently provided to DOI in writing 

and has been included in the 

administrative record for this proposed 

rule. 

BOEM and BSEE also held public 

listening sessions in South-central 

Alaska (Anchorage) and on the North 

Slope (Barrow) on June 6 and 7, 2013. 

The BOEM Alaska Region notified 

Alaska Native Tribes and ANCSA 

Corporations of the June 6 and 7, 2013, 

public listening sessions and 

Government-to-Government 

consultations through phone calls, 

emails, newspaper announcements, and 

BOEM’s Web site. 

A series of follow-on meetings and 

listening sessions were held June 17–20, 

2013, in Anchorage resulting, in part, in 

Government-to-Government 

consultation between BOEM, BSEE, and 

the Native Village of Nuiqsut and 

Government-to-ANCSA Corporation 

consultations between BOEM, BSEE, 

and the NANA Regional Corporation 

and the Cully Corporation (ANCSA 

Village Corporation) from Point Lay. 

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9960 Federal Register / Vol. 80, No. 36 / Tuesday, February 24, 2015 / Proposed Rules 

Among the most frequent input DOI 

received through listening sessions and 

tribal consultation were comments 

relating to impacts on, and protection 

of, subsistence hunting and fishing areas 

and species, including consideration of 

mammal and fish migratory patterns, 

hunting and fishing seasons, and 

impacts of pollutants and equipment 

movements. Concerns also included the 

relative lack of infrastructure, such as 

roads, housing, and equipment, in 

coastal communities near proposed 

Arctic OCS oil and gas exploration 

areas, and inclusion of local Alaska 

Natives in monitoring and other 

activities. Commenters also requested 

that we incorporate traditional 

knowledge of the Arctic OCS into our 

decision-making for proposed 

regulations. We reviewed all comments 

received to date and have, where 

appropriate, crafted proposed measures 

to address Alaska Native concerns. DOI 

intends to continue consultation with 

affected tribes and ANCSA Corporations 

following publication of the proposed 

rule. 

J. E.O. 12898 

E.O. 12898 requires Federal agencies 

to make achieving environmental justice 

part of their mission by identifying and 

addressing disproportionately high and 

adverse human health or environmental 

effects of their programs, policies, and 

activities on minority populations and 

low-income populations in the U.S. DOI 

has determined that this proposed rule 

does not have a disproportionately high 

or adverse human health or 

environmental effect on native, 

minority, or low-income communities 

because its provisions are designed to 

increase environmental protection and 

minimize any impact of exploration 

drilling on subsistence hunting 

activities and Alaska Native community 

resources and infrastructure. 

K. Paperwork Reduction Act (PRA) 

This rule contains new information 

collection (IC) requirements for both 

BOEM and BSEE regulations, and a 

submission under the PRA is required. 

Therefore, an IC request for each Bureau 

is being submitted to OMB for review 

and approval under 44 U.S.C. 3501 et 

seq. The PRA provides that an agency 

may not conduct or sponsor, and a 

person is not required to respond to, an 

IC unless it displays a currently valid 

OMB control number. The IC aspects 

affecting each Bureau are discussed 

separately. Instructions on how to 

comment follow those discussions. 

BOEM Information Collection—30 CFR 

Part 550 

This proposed rule adds new 

requirements for submitting EPs and 

other information before conducting oil 

and gas exploration drilling activities on 

the Arctic OCS. The title of the 

collection for the rulemaking is 30 CFR 

550, Subpart B, Arctic OCS Activities— 

New. The burdens for the current 

planning requirements under 30 CFR 

550, Subpart B, regulations are 

approved by OMB under Control 

Number 1010–0151 (190,480 hours, 

$3,713,665 non-hour costs; expiration 

12/31/14; current collection can be 

viewed at www.reginfo.gov/public/). 

When final regulations become 

effective, the new IC burdens for this 

rulemaking will be consolidated into the 

existing collection for Subpart B. 

Respondents for this rulemaking are 

Federal oil, gas, or sulphur lessees and/ 

or operators on the Arctic OCS. 

Submissions are mandatory and 

generally on occasion. BOEM collects 

the information to ensure that planned 

operations will be safe; will not 

adversely affect the marine, coastal, or 

human environments; will respond to 

the special conditions on the Arctic 

OCS; and will conserve the resources of 

the Arctic OCS. BOEM uses the 

information to ensure, through 

advanced planning, that operators are 

capable of safely operating in the unique 

environmental conditions of the Arctic 

and to make informed decisions on 

whether to approve EPs as submitted or 

whether modifications are necessary. 

BOEM also plans to share the 

preliminary information submitted in 

the IOP with other relevant agencies to 

provide them the opportunity to engage 

in constructive dialogue/feedback with 

operators, and each other, early in the 

process. 

The proposed rule adds new 

requirements under § 550.204 for 

operators to develop an IOP for each 

exploratory drilling program on the 

Arctic OCS, and to submit it to BOEM 

at least 90 days in advance of filing their 

EP. The IOP addresses all phases of the 

operator’s proposed Arctic exploration 

drilling activities at a strategic or 

conceptual level, showing how 

operations will be designed, executed, 

and managed as an integrated endeavor 

from start to finish. 

The proposed rule also revises the IC 

for plans submission by expanding the 

requirements under § 550.220 to address 

the specific conditions (e.g., ice 

management procedures) associated 

with oil and gas activity on the Arctic 

OCS. The rule provisions are intended 

to ensure that operators on the Arctic 

OCS design and conduct their 

exploration drilling activities in a 

manner suitable for the area’s unique 

conditions. 

BOEM estimates that the new 

requirements will add a total of 270 

burden hours to the already approved 

burdens for plans. Because not all EPs 

submitted to BOEM will involve Arctic 

OCS exploration drilling, we are 

separating the Arctic-specific 

requirements and burdens from the 

national EP requirements. The burden 

table that follows this paragraph 

outlines the new and expanded 

requirements and burdens associated 

with this rulemaking. BOEM has not 

identified any non-hour cost burdens 

associated with these requirements. 

BURDEN BREAKDOWN

Citation 30 CFR Part 550 Subpart B Reporting & Recordkeeping Requirement Hour burden 

Average 

number of 

annual responses 

Burden 

hours 

Arctic Integrated Operations Plan (IOP) 

New 2041 ................................... For New Arctic OCS Exploration Activities: Submit IOP, including 

all required information.

90 2 180 

Contents of Exploration Plans (EP) 

206 .............................................

220 .............................................

General requirements for plans. .....................................................

Submit Alaska-specific information. ................................................

Burdens already covered 

under plans in 1010–0151. 

0 

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BURDEN BREAKDOWN—Continued 

Citation 30 CFR Part 550 Subpart B Reporting & Recordkeeping Requirement Hour burden 

Average 

number of 

annual responses 

Burden 

hours 

Expanded 220 ............................ For New Arctic OCS Exploration Activities: Submit required Arctic-specific information with EP, including confirmations.15 2 30 

Expanded 220 ............................ For Existing Arctic OCS Exploration Activities: Revise and resubmit Arctic-specific information, as required.30 2 60 

Total Burden for Proposed 

Rule.

......................................................................................................... .................... 6 270 

1 Industry already compiles this information internally for planning and contract oversight; therefore, the burden expected is minimal, just to prepare and submit to BOEM. 

BSEE Information Collection—30 CFR 

Parts 250 and 254 

The title of the collection of 

information for this rule is 30 CFR part 

250, subparts A, D, S and 30 CFR part 

254, Arctic Oil & Gas Exploratory 

Drilling Operations—New. The 

proposed regulations establish 

requirements for safe, responsible, and 

environmentally protective Arctic OCS 

oil and gas exploration, and the 

information is used in our efforts to 

protect life and the environment, 

conserve natural resources, and prevent 

waste. 

Potential respondents comprise 

Federal OCS oil, gas, and sulphur 

operators and lessees on the Arctic OCS. 

The frequency of response varies 

depending upon the requirement. 

Responses to this collection of 

information are mandatory; they are 

submitted on occasion, annually, or as 

a result of situations encountered, 

depending upon the requirement. The 

IC does not include questions of a 

sensitive nature. BSEE will protect 

proprietary information according to the 

Freedom of Information Act (5 U.S.C. 

552) and DOI’s implementing 

regulations (43 CFR part 2), 30 CFR part 

252, and 30 CFR 250.197, which address 

disclosure of data and information to be 

made available to the public. 

As discussed earlier in the preamble, 

the proposed rule encompasses multiple 

subparts and focuses on Arctic OCS 

exploratory drilling activities and 

related operations. This proposed rule 

revises several existing collections 

under BSEE regulations. The 

requirements and burdens for these 

regulations are currently approved by 

OMB under 30 CFR part 250, subpart A, 

1014–0022, expiration 8/3/2017 (84,391 

hours, $1,371,458 non-hour cost 

burdens); subpart D, 1014–0018, 

expiration 10/31/17 (102,512 hours); 

subpart S, 1014–0017, expiration 3/31/ 

16 (651,728 hours, $9,444,000 non-hour 

cost burdens); and 30 CFR part 254, 

1014–0007, expiration 12/31/2015 

(60,198 hours); current collections can 

be viewed at www.reginfo.gov/public/. 

When final regulations are promulgated, 

the new IC burdens for these subparts/ 

parts will be incorporated into the 

respective collections of information for 

those regulations. 

The following table provides a 

breakdown of the paperwork and nonhour cost burdens for this proposed 

rule. For the current requirements 

retained in the proposed rule, we used 

the OMB approved estimated hour and 

non-hour cost burdens, where 

discernible. However, there are several 

new requirements in the proposed rule 

as follows: 

1. Subpart A: 

In § 250.188(c), we have added 

immediate oral reporting of anysea ice 

movement/conditions, start and 

termination of ice management 

activities, or kicks or unexpected 

operational issues, and submission of a 

written report within 24 hours after 

completing ice management activities 

(+11 hours). 

2. Subpart D: 

In § 250.452(a) and (b), we have added 

real-time data gathering, monitoring, 

and storing related to the BOP control 

system, fluid handling, and downhole 

conditions, etc.; notify BSEE of location 

of data; make data available to BSEE 

upon request (+288 hours). 

In § 250.470, we have added 

information requirements including, but 

not limited to, detailed descriptions of: 

Environmental, meteorologic, and 

oceanic conditions expected at well 

site(s), and, how drilling units and 

equipment will be prepared for service; 

transitioning rig from being underway to 

drilling and vice versa, along with 

anticipated repair and maintenance 

plans; specific drilling objectives, 

timelines, and updated contingency 

plans for temporary abandonment; 

weather and ice forecasting and 

management; compliance with relief 

well rig requirements; SCCE 

capabilities, including, but not limited 

to, submit equipment statement 

showing capable of controlling WCD, 

explanation of your or your contractor’s 

SCCE capabilities; inventory of supplies 

and services, along with relevant 

supplier information; proof of contracts 

or membership agreements to provide 

SCCE or supplies, services; description 

of procedures for inspecting, testing, 

and maintaining SCCE; how all 

personnel operating SCCE received 

training to deploy and operate— 

including dates of prior and planned 

training; and how the operator 

incorporated API RP 2N, Third Edition, 

into its planned drilling operations 

(+324 hours). 

In § 250.471(c), (e), and (f), we 

propose to add requirements that 

operators: Submit a reevaluation of 

SCCE capabilities, including any new 

WCD rate, and demonstrate compliance 

with proposed § 250.470(f); maintain all 

SCCE inspection and maintenance 

records for at least 10 years; make 

records available to BSEE upon request; 

maintain all records relating to use of 

SCCE during testing, training, and 

deployment activities for at least 3 

years; and make records available to 

BSEE upon request (+100 hours). 

In § 250.472(c), we propose to add a 

provision stating that operators may 

request approval for alternative 

compliance measures for relief rig 

requirements in accordance with 

existing § 250.141 (+0 hours). 

3. Subpart S: 

In § 250.1920(b), (c), (d), and (e), the 

additional non-hour cost burdens 

pertaining to Audit Service Provider 

(ASP) audits every year in the Arctic in 

which exploration drilling is conducted 

would apply (+$129,000 non-hour cost). 

4. 30 CFR part 254: 

Operators currently submit 

information with their spill response 

plans (§§ 254.20–29) that is related to 

the requirements in this rulemaking 

under proposed §§ 254.70, 254.80, and 

254.90; therefore, we believe that the 

current burden sufficiently covers the 

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9962 Federal Register / Vol. 80, No. 36 / Tuesday, February 24, 2015 / Proposed Rules 

proposed modifications. We have added 

a new requirement in § 254.80(c) for 

submitting a description of the system 

used to maintain real time monitoring 

(+12 hours). 

BURDEN TABLE

Citation 30 CFR parts 

250 and 254 Reporting and recordkeeping requirements Hour burden Average number of annual responses Annual burden hours 

30 CFR Part 250, Subpart A 

188(c); 190 ..................... NEW—Provide BSEE immediate oral report of sea ice movement/conditions; 

start and termination of ice management 

activities; kicks or unexpected operational issues. 

Oral 1.5 ..................... 2 notifications .............. 3. 

188(c); 190 ..................... NEW—Submit a written report within 24 

hours after completing ice management 

activities. 

Written 4 ................... 2 reports ..................... 8. 

Subtotal ................... ...................................................................... ................................... 4 responses ................ 11 hours. 

30 CFR Part 250, Subpart D 

418 .................................. Additional information that is to be submitted with an APD is covered under the specific requirement listed in this burden table under 30 CFR 250.470. 0. 

452(a), (b) ....................... NEW—Immediately transmit real-time data 

gathering and monitoring to record, 

store, and transmit data relating to the 

BOP control system, fluid handling, 

downhole conditions; prior to well operations, notify BSEE of monitoring location and make data available to BSEE 

upon request. 

12 .............................. 1 transmittal ................ 12. 

452(b) ............................. NEW—Store and monitor all information relating to § 250.452(a); make data available to BSEE upon request. 1 ................................ 2 wells × 138 drilling 

days = 276.

276. 

452(b) ............................. Store and retain all monitoring records per 

requirements of §§ 250.466 and 467. 

Burden covered under 30 CFR 250, Subpart 

D, 1014–0018. 

0. 

470(a); 417; 418 ............. NEW—Submit detailed descriptions of environmental, meteorologic, and oceanic 

conditions expected at well site(s); how 

drilling unit, equipment, and materials will 

be prepared for service; how the drilling 

unit will be in compliance with § 250.417. 

10 .............................. 1 submittal .................. 10. 

470(b); 418 ..................... NEW—Submit detailed description of 

transitioning rig from being underway to 

drilling and vice versa. 

4 ................................ 2 each well—underway to drilling; drilling to underway = 4.16. 

470(b); 418 ..................... NEW—Submit detailed description of any 

anticipated repair and maintenance plans 

for the drilling unit and equipment. 

2 ................................ 2 submittals ................ 4. 

470(c); 418 ..................... NEW—Submit well specific drilling objectives, timelines, and updated contingency 

plans etc., for temporary abandonment. 

4 ................................ 2 submittals ................ 8. 

470(d); 418 ..................... NEW—Submit detailed description concerning weather and ice forecasting for 

all phases; including how to ensure continuous awareness of weather/ice hazards at/between each well site; plans for 

managing ice hazards and responding to 

weather events; verification of capabilities. 

6 ................................ 1 submittal .................. 6. 

470(e); 418; 472 ............. NEW—Submit a detailed description of 

compliance with relief rig plans. 

140 ............................ 1 explanation .............. 140. 

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Federal Register / Vol. 80, No. 36 / Tuesday, February 24, 2015 / Proposed Rules 9963 

BURDEN TABLE—Continued 

Citation 30 CFR parts 

250 and 254 Reporting and recordkeeping requirements Hour burden Average number of annual responses Annual burden hours 

470(f); 471(c); 418 .......... NEW—SCCE capabilities; submit equipment statement showing capable of controlling WCD; detailed description of your 

or your contractor’s SCCE capabilities including operating assumptions and limitations; inventory of local and regional 

supplies and services, along with supplier relevant information; proof of contract or agreements for providing SCCE 

or supplies, services; detailed description 

of procedures for inspecting, testing, and 

maintaining SCCE; and detailed description of your plan ensuring all members of 

the team operating SCCE have received 

training to deploy and operate, include 

dates of prior and planned training. 

60 .............................. 2 submittals ................ 120. 

470(g); 418 ..................... NEW—Submit a detailed description of utilizing best practices of API RP 2N during 

operations. 

20 .............................. 1 submittal .................. 20. 

471(c); 470(f); 465(a) ..... NEW—Submit with your APM, a reevaluation of your SCCE capabilities if well design changes; include any new WCD 

rate and demonstrate that your SCCE 

capabilities will comply with § 250.470(f). 

10 .............................. 2 submittals ................ 20. 

471(e) ............................. NEW—Maintain all SCCE testing, inspection, and maintenance records for at 

least 10 years; make available to BSEE 

upon request. 

20 .............................. 2 records ..................... 40. 

471(f) .............................. NEW—Maintain all records pertaining to 

use of SCCE during testing, training, and 

deployment activities for at least 3 years; 

make available to BSEE upon request. 

20 .............................. 2 records ..................... 40. 

472(c) ............................. Request approval for alternative compliance for relief rig requirements.Burden covered under 30 CFR 250, Subpart A, 

1014–0022 

0. 

Subtotal ................... ...................................................................... ................................... 297 responses ............ 712 hours 

30 CFR Part 250, Subpart S 

1920(b), (c), (e) .............. ASP audit for High Activity Operator ..........

NOTE: An audit once every 3 years in 

POCSR and GOMR; an audit in the Arctic in every year in which drilling is conducted. 

1 operator × $129,000 audit for high activity = $129,000. 

1920(c) ........................... Submit to BSEE after completed audit, an 

audit report of findings and conclusions, 

including deficiencies and required supporting information/documentation. 

Burden covered under 30 CFR 250, Subpart S, 

1014–0017. 

0 

1920(d) ........................... Submit/resubmit a copy of your CAP that 

will address deficiencies identified in 

audit. 

.

Subtotal ................... ...................................................................... ................................... 1 response .................. 0 

$129,000 Non Hour Cost Burdens. 

30 CFR Part 254, Subpart E 

55; 70; 80; 90 ................. Submit spill response plan for OCS facilities with all information required in regulations and related documents. Burden covered under 30 CFR 254, 1014– 

0007. 

0. 

80(c) ............................... NEW—Submit a description of system 

used to maintain real-time location tracking for all response resources. 

6 ................................ 2 descriptions ............. 12. 

90(a) ............................... Include in your training and exercise activities the requirements of this section. Burden covered under 30 CFR 254, 1014– 

0007. 

0. 

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9964 Federal Register / Vol. 80, No. 36 / Tuesday, February 24, 2015 / Proposed Rules 

BURDEN TABLE—Continued 

Citation 30 CFR parts 

250 and 254 Reporting and recordkeeping requirements Hour burden Average number of annual responses Annual burden hours 

90(b) ............................... Notify BSEE 60 days prior to handling, 

storing, or transporting oil. 

Subtotal ................... ...................................................................... ................................... 2 responses ................ 12 hours. 

Total Hour Burden ... ...................................................................... ................................... 304 Responses ........... 735 Hours. 

...................................................................... ................................... $129,000 Non-Hour Cost Burdens. 

Note: For FY 2015, we calculated the burden with 2 rigs (same operator), each rig drilling 1 well. 

Commenting on Information Collections 

As part of our continuing effort to 

reduce paperwork and respondent 

burdens, BOEM and BSEE invite the 

public to comment on any aspect of the 

reporting and recordkeeping burdens. If 

you wish to comment on the IC aspects 

of these regulations, you may send your 

comments directly to by email to OMB 

(OIRA_submission@omb.eop.gov) or by 

fax 202–395–5806, with a copy to BSEE 

(see Addresses section). Please identify 

your comments with RIN: 1082–AA01. 

To see a copy of either IC request 

submitted to OMB, go to 

www.reginfo.gov (select Information 

Collection Review, Currently Under 

Review). You may obtain a copy of the 

supporting statement for the new IC by 

contacting each Bureau’s Information 

Collection Clearance Officer: Cheryl 

Blundon, BSEE, (703) 787–1607, and 

Arlene Bajusz, BOEM, (703) 787–1025. 

The OMB is required to make a 

decision concerning the ICs contained 

in these proposed regulations between 

30 and 60 days after publication of this 

document in the Federal Register. 

Therefore, a comment to OMB is best 

assured of having its full effect if OMB 

receives it by March 26, 2015. 

BOEM and BSEE specifically solicit 

comments on the following questions: 

1. Is the proposed collection of 

information necessary for the Bureaus to 

properly perform their functions, and 

will it be useful? 

2. Are the estimates of the burden 

hours of the proposed collection 

reasonable? 

3. Do you have any suggestions that 

would enhance the quality, clarity, or 

usefulness of the information to be 

collected? 

4. Is there a way to minimize the IC 

burden on those who are to respond, 

including through the use of appropriate 

automated electronic, mechanical, or 

other forms of information technology? 

In addition, the PRA requires agencies 

to estimate the total annual reporting 

and recordkeeping non-hour cost 

burden resulting from the collection of 

information. BSEE has identified one 

non-hour cost burden in the BSEE 

Burden Table. We solicit your 

comments on any non-hour costs. For 

reporting and recordkeeping only, your 

response should split the cost estimate 

into two components: (1) Total capital 

and startup cost component and (2) 

annual operation, maintenance, and 

purchase of services component. Your estimates should consider the 

costs to generate, maintain, and disclose 

or provide the information. You should 

describe the methods you use to 

estimate major cost factors, including 

system and technology acquisition, 

expected useful life of capital 

equipment, discount rate(s), and the 

period over which you incur costs. 

Generally, your estimates should not 

include equipment or services 

purchased: (1) Before October 1, 1995; 

(2) to comply with requirements not 

associated with the IC; (3) for reasons 

other than to provide information or 

keep records for the Government; or (4) 

as part of customary and usual business 

or private practices. 

L. National Environmental Policy Act of 

1969 (NEPA) 

BOEM and BSEE developed a draft 

Environmental Assessment (EA) to 

determine whether this proposed rule 

would have a significant impact on the 

quality of the human environment 

under the NEPA. The draft EA is 

available for review and public 

comment in conjunction with this 

proposed rule at www.regulations.gov 

(in the Search box, enter BSEE–2013– 

0011). 

M. Data Quality Act 

In developing this rule, we did not 

conduct or use a study, experiment, or 

survey requiring peer review under the 

Data Quality Act (Pub. L. 106–554, app. 

C § 515, 114 Stat. 2763, 2763A–153– 

154). 

N. Effects on the Nation’s Energy Supply 

(E.O. 13211) 

Although this proposed rule is a 

significant regulatory action under E.O. 

12866, it is not a significant energy 

action under the definition of that term 

in E.O. 13211 because: 

1. It is not likely to have a significant 

adverse effect on the supply, 

distribution or use of energy; and 2. It has not been designated as a 

significant energy action by the 

Administrator of OIRA. 

Thus, a Statement of Energy Effects is 

not required. 

Due to the inherent practical 

difficulties of exploration and 

production in the area, to date there has 

been relatively little exploration 

activity, and very little production of oil 

and gas, on the Arctic OCS. The only 

existing oil production from the Arctic 

OCS is through the Northstar Island 

facility. Since the proposed rule does 

not apply to development or production 

activities, it would not reduce or inhibit 

production of oil and gas and would 

have no adverse impact on oil and gas 

supplies or prices. 

O. Clarity of this Regulation 

We are required by E.O. 12866, E.O. 

12988, and by the Presidential 

Memorandum of June 1, 1998, to write 

all rules in plain language. This means 

that each rule we publish must: 

1. Be logically organized; 

2. Use the active voice to address 

readers directly; 

3. Use clear language rather than 

jargon; 

4. Be divided into short sections and 

sentences; and 

5. Use lists and tables wherever 

possible. 

If you believe we have not met these 

requirements, send us comments by one 

of the methods listed in the ADDRESSES

section. To better help us revise the 

rule, your comments should be as 

specific as possible. For example, you 

should tell us the numbers of the 

sections or paragraphs that you find 

unclear, which sections or sentences are 

too long, or the sections where you 

believe lists or tables would be useful. 

P. Public Availability of Comments 

BOEM and BSEE encourage you to 

participate in this proposed rule by 

submitting written comments as 

discussed in the ADDRESSES and DATES

sections of this proposed rule. Before 

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Federal Register / Vol. 80, No. 36 / Tuesday, February 24, 2015 / Proposed Rules 9965 

including your address, phone number, 

email address or other personal 

identifying information in your 

comment on this proposed rule, you 

should be aware that your entire 

comment—including your personal 

identifying information—may be made 

publicly available at any time. While 

you can ask us in your comment to 

withhold your personal identifying 

information from public review, we 

cannot guarantee that we will be able to 

do so. 

List of Subjects 

30 CFR Part 250 

Continental shelf, Environmental 

impact statements, Environmental 

protection, Government contracts, 

Incorporation by reference, 

Investigations, Mineral royalties, Oil 

and gas development and production, 

Oil and gas exploration, Oil and gas 

reserves, Penalties, Pipelines, Public 

lands—mineral resources, Public 

lands—rights of-way, Reporting and 

recordkeeping requirements, Sulphur 

development and production, Sulphur 

exploration, Surety bonds. 

30 CFR Part 254 

Continental shelf, Intergovernmental 

relations, Oil and gas exploration, Oil 

pollution, Pipelines, Public lands— 

mineral resources, Reporting and 

recordkeeping requirements. 

30 CFR Part 550 

Administrative practice and 

procedure, Environmental impact 

statements, Environmental protection, 

Federal lands, Government contracts, 

Oil, Oil and gas exploration, Oil and gas 

development, Outer continental shelf, 

Penalties, Pipelines, Public lands— 

mineral resources, Public lands—rightof-way, Reporting and recordkeeping 

requirements, Sulphur development and 

production, Energy, Oil and gas 

reserves, Natural gas, Natural resources, 

Continental shelf, Offshore structures, 

Petroleum, Bonds, Surety bonds. 

Dated: February 18, 2015. 

Janice M. Schneider, 

Assistant Secretary, Land and Minerals 

Management. 

For the reasons stated in the 

preamble, BOEM and BSEE amend 30 

CFR parts 250, 254, and 550 as follows: 

TITLE 30—MINERAL RESOURCES

CHAPTER II—BUREAU OF SAFETY AND

ENVIRONMENTAL ENFORCEMENT, 

DEPARTMENT OF THE INTERIOR

PART 250—OIL AND GAS AND SULPHUR

OPERATIONS IN THE OUTER CONTINENTAL

SHELF

■ 1. The authority citation for 30 CFR 

part 250 is revised to read as follows: 

Authority: 30 U.S.C. 1751, 31 U.S.C. 9701, 

33 U.S.C. 1321(j)(1)(C), 43 U.S.C. 1334. 

■ 2. Amend § 250.105 by: 

■ a. Revising the definition of ‘‘District 

Manager’’ and 

■ b. Adding new definitions for ‘‘Arctic 

OCS’’, ‘‘Arctic OCS conditions’’, ‘‘Cap 

and flow system’’, ‘‘Capping stack’’, 

‘‘Containment dome’’ and ‘‘Source 

control and containment equipment 

(SCCE)’’ in alphabetical order, to read as 

follows: 

§ 250.105 Definitions. 

* * * * * 

Arctic OCS means the Beaufort Sea 

and Chukchi Sea Planning Areas, as 

described in the Proposed Final OCS Oil 

and Gas Leasing Program for 2012–2017 

(June 2012). 

Arctic OCS conditions means, for the 

purposes of this part, the conditions 

operators can reasonably expect during 

operations on the Arctic OCS. Such 

conditions, depending on the time of 

year, include, but are not limited to: 

Extreme cold, freezing spray, snow, 

extended periods of low light, strong 

winds, dense fog, sea ice, strong 

currents, and dangerous sea states. 

Remote location, relative lack of 

infrastructure, and the existence of 

subsistence hunting and fishing areas 

are also characteristic of the Arctic 

region. 

* * * * * 

Cap and flow system means an 

integrated suite of equipment and 

vessels, including a capping stack and 

associated flow lines, that, when 

installed or positioned, is used to 

control the flow of fluids escaping from 

the well by conveying the fluids to the 

surface to a vessel or facility equipped 

to process the flow of oil, gas, and 

water. A cap and flow system is a high 

pressure system that includes the 

capping stack and piping necessary to 

convey the flowing fluids through the 

choke manifold to the surface 

equipment. 

Capping stack means a mechanical 

device that can be installed on top of a 

subsea or surface wellhead or blowout 

preventer to stop the uncontrolled flow 

of fluids into the environment. 

* * * * * 

Containment dome means a nonpressurized container that can be used 

to collect fluids escaping from the well 

or equipment below the sea surface or 

from seeps by suspending the device 

over the discharge or seep location. The 

containment dome includes all of the 

equipment necessary to capture and 

convey fluids to the surface. 

* * * * * 

District manager means the BSEE 

officer with authority and responsibility 

for operations or other designated 

program functions for a district within 

a BSEE Region. For activities on the 

Alaska OCS, any reference in this part 

to District Manager means the BSEE 

Regional Supervisor. 

* * * * * 

Source control and containment 

equipment (SCCE) means the capping 

stack, cap and flow system, containment 

dome, and/or other subsea and surface 

devices, equipment, and vessels whose 

collective purpose is to control a spill 

source and stop the flow of fluids into 

the environment or to contain fluids 

escaping into the environment. ‘‘Surface 

devices’’ refers to equipment mounted 

or staged on a barge, vessel, or facility 

to separate, treat, store and/or dispose of 

fluids conveyed to the surface by the 

cap and flow system or the containment 

dome. ‘‘Subsea devices’’ includes, but is 

not limited to, remotely operated 

vehicles, anchors, buoyancy equipment, 

connectors, cameras, controls and other 

subsea equipment necessary to facilitate 

the deployment, operation and retrieval 

of the SCCE. The SCCE does not include 

a blowout preventer. 

* * * * * 

■ 3. Amend § 250.188 by adding a new 

paragraph (c) to read as follows: 

§ 250.188 What incidents must I report to 

BSEE and when must I report them? 

* * * * * 

(c) On the Arctic OCS, in addition to 

the requirements of paragraphs (a) and 

(b) of this section, you must provide to 

the BSEE inspector on location, if one 

is present, or to the Regional Supervisor 

both of the following: 

(1) An immediate oral report if any of 

the following occur: 

(i) Any sea ice movement or condition 

that has the potential to affect your 

operation or trigger ice management 

activities; 

(ii) The start and termination of ice 

management activities; or 

(iii) Any ‘‘kicks’’ or operational issues 

that are unexpected and could result in 

the loss of well control. 

(2) Within 24 hours after completing 

ice management activities, a written 

report of such activities that conforms to 

the content requirements in § 250.190. 

■ 4. Amend § 250.198 by adding 

paragraph (h)(89) to read as follows: 

§ 250.198 Documents incorporated by 

reference. 

* * * * * 

(h) * * * 

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9966 Federal Register / Vol. 80, No. 36 / Tuesday, February 24, 2015 / Proposed Rules 

(89) API RP 2N, Third Edition, 

‘‘Recommended Practice for Planning, 

Designing, and Constructing Structures 

and Pipelines for Arctic Conditions;’’ 

incorporated by reference at 

§ 250.470(g); 

* * * * * 

■ 5. Amend § 250.300 by revising 

paragraphs (b)(1) and (b)(2) to read as 

follows: 

§ 250.300 Pollution prevention. 

* * * * * 

(b)(1) The District Manager may 

restrict the rate of drilling fluid 

discharges or prescribe alternative 

discharge methods. The District 

Manager may also restrict the use of 

components which could cause 

unreasonable degradation to the marine 

environment. No petroleum-based 

substances, including diesel fuel, may 

be added to the drilling mud system 

without prior approval of the District 

Manager. For Arctic OCS exploratory 

drilling, you must capture all 

petroleum-based mud to prevent its 

discharge into the marine environment. 

The Regional Supervisor may also 

require you to capture, during your 

Arctic OCS exploratory drilling 

operations, all water-based mud from 

operations after completion of the hole 

for the conductor casing to prevent its 

discharge into the marine environment, 

based on various factors including, but 

not limited to: 

(i) The proximity of your exploratory 

drilling operation to subsistence 

hunting and fishing locations; 

(ii) The extent to which discharged 

mud may cause marine mammals to 

alter their migratory patterns in a 

manner that impedes subsistence users’ 

access to, or use of, those resources, or 

increases the risk of injury to 

subsistence users; or 

(iii) The extent to which discharged 

mud may adversely affect marine 

mammals, fish, or their habitat. 

(2) Approval of the method of 

disposal of drill cuttings, sand, and 

other well solids shall be obtained from 

the District Manager. For Arctic OCS 

exploratory drilling, you must capture 

all cuttings from operations that utilize 

petroleum-based mud to prevent their 

discharge into the marine environment. 

The Regional Supervisor may also 

require you to capture, during your 

Arctic OCS exploratory drilling 

operations, all cuttings from operations 

that utilize water-based mud after 

completion of the hole for the conductor 

casing to prevent their discharge into 

the marine environment, based on 

various factors including, but not 

limited to: 

(i) The proximity of your exploratory 

drilling operation to subsistence 

hunting and fishing locations; 

(ii) The extent to which discharged 

cuttings may cause marine mammals to 

alter their migratory patterns in a 

manner that impedes subsistence users’ 

access to, or use of, those resources, or 

increases the risk of injury to 

subsistence users; or 

(iii) The extent to which discharged 

cuttings may adversely affect marine 

mammals, fish, or their habitat. 

* * * * * 

■ 6. Amend § 250.402 by adding a new 

paragraph (c) to read as follows: 

§ 250.402 When and how must I secure a 

well? 

* * * * * 

(c) For Arctic OCS exploratory 

drilling operations, in addition to the 

requirements of paragraphs (a) and (b) of 

this section: 

(1) If you move your drilling rig off a 

well prior to completion or permanent 

abandonment, you must 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: 

(i) Protect the well head; and 

(ii) Prevent or minimize the 

likelihood of compromising the downhole integrity of the well or the 

effectiveness of the well plugs. 

(2) In areas of ice scour, you must use 

a well mudline cellar or an equivalent 

means of minimizing the risk of damage 

to the well head. 

■ 7. Amend § 250.418 by adding a new 

paragraph (k) to read as follows: 

§ 250.418 What additional information 

must I submit with my APD? 

* * * * * 

(k) For Arctic OCS exploratory 

drilling operations, you must provide 

the information required by § 250.470. 

■ 8. Amend § 250.447 by revising 

paragraph (b) to read as follows: 

§ 250.447 When must I pressure test the 

BOP system? 

* * * * * 

(b) Before 14 days have elapsed since 

your last BOP pressure test, or for Arctic 

OCS exploratory drilling operations 

before 7 days have elapsed since your 

last BOP pressure test. You must begin 

to test your BOP system before midnight 

on the 14th day (or for Arctic OCS 

exploratory drilling operations, the 7th 

day) following the conclusion of the 

previous test. However, the District 

Manager may require more frequent 

testing if conditions or BOP 

performance warrant; and 

* * * * * 

■ 9. Add new § 250.452 to read as 

follows: 

§ 250.452 What are the real-time 

monitoring requirements for Arctic OCS 

exploratory drilling operations? 

(a) When conducting exploratory 

drilling operations on the Arctic OCS, 

you must have real-time data gathering 

and monitoring capability to record, 

store, and transmit data regarding all 

aspects of: 

(1) The BOP control system; 

(2) The well’s fluid handling systems 

on the rig; and 

(3) The well’s downhole conditions as 

monitored by a downhole sensing 

system, when such a system is installed. 

(b) During well operations, you must 

immediately transmit the data identified 

in paragraph (a) of this section to a 

designated onshore location where it 

must be stored and monitored by 

qualified personnel who have the 

capability for continuous contact with 

rig personnel and who have the 

authority, in consultation with rig 

personnel, to initiate any necessary 

action in response to abnormal data or 

events. Prior to well operations, you 

must notify BSEE where the data will be 

monitored during those operations, and 

you must make the data available to 

BSEE, including in real time, upon 

request. After well operations, you must 

store the data at a designated location 

for recordkeeping purposes as required 

in §§ 250.466 and 250.467. 

■ 10. Add new undesignated centered 

heading ‘‘ADDITIONAL ARCTIC OCS 

REQUIREMENTS’’ and §§ 250.470 

through 250.473 in Subpart D to read as 

follows: 

Additional Arctic OCS Requirements 

§ 250.470 What additional information 

must I submit with my APD for Arctic OCS 

exploratory drilling operations? 

In addition to all other applicable 

requirements included in this part, you 

must provide with your APD all of the 

following information pertaining to your 

proposed Arctic OCS exploratory 

drilling: 

(a) A detailed description of: 

(1) The environmental, and 

meteorologic and oceanic conditions 

you expect to encounter at the well 

site(s); 

(2) How your equipment, materials, 

and drilling unit will be prepared for 

service in the conditions in paragraph 

(a)(1) of this section, and how your 

drilling unit will be in compliance with 

the requirements of § 250.417. 

(b) A detailed description of all 

operations necessary in Arctic OCS 

Conditions to transition the rig from 

being under way to conducting drilling 

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operations and from ending drilling 

operations to being under way, as well 

as any anticipated repair and 

maintenance plans for the drilling unit 

and equipment. The description should 

include, but not be limited to: 

(1) Recovering the subsea equipment, 

including the marine riser and the lower 

marine riser package; 

(2) Recovering the BOP; 

(3) Recovering the auxiliary sub-sea 

controls and template; 

(4) Laying down the drill pipe and 

securing the drill pipe and marine riser; 

(5) Securing the drilling equipment; 

(6) Transferring the fluids for 

transport or disposal; 

(7) Securing ancillary equipment like 

the draw works and lines; 

(8) Refueling or transferring fuel; 

(9) Offloading waste; 

(10) Recovering the ROVs; 

(11) Picking up the oil spill 

prevention booms and equipment; and 

(12) Offloading the drilling crew. 

(c) Well-specific drilling objectives, 

timelines, and updated contingency 

plans for temporary abandonment of the 

well, including but not limited to the 

following: 

(1) When you will spud the particular 

well (i.e., begin drilling operations at the 

well site) identified in the APD; 

(2) How long you will take to drill the 

well; 

(3) Anticipated depths and geologic 

targets, with timelines; 

(4) When you expect to set and 

cement each string of casing; 

(5) When and how you would log the 

well; 

(6) Your plans to test the well; 

(7) When and how you intend to 

abandon the well, including specifically 

addressing your plans for how to move 

the rig off location and how you will 

meet the requirements of § 250.402(c); 

(8) A description of what equipment 

and vessels will be involved in the 

process of temporarily abandoning the 

well due to ice; and 

(9) An explanation of how these 

elements will be integrated into your 

overall program. 

(d) A detailed description of your 

weather and ice forecasting capability 

for all phases of the drilling operation, 

including: 

(1) How you will ensure continuous 

awareness of potential weather and ice 

hazards at, and during transition 

between, wells; 

(2) Your plans for managing ice 

hazards and responding to weather 

events; and 

(3) Verification that you have the 

capabilities described in your BOEMapproved EP. 

(e) A detailed description of how you 

will comply with the requirements of 

§ 250.472. 

(f) A statement that you own, or have 

a contract with a provider for, source 

control and containment equipment 

(SCCE) that is capable of controlling 

and/or containing a worst case 

discharge, as described in your BOEMapproved EP, when proposing to use a 

MODU to conduct exploratory drilling 

operations on the Arctic OCS. The 

following information must be included 

in your SCCE submittal: 

(1) A detailed description of your or 

your contractor’s SCCE capabilities, 

including operating assumptions and 

limitations, reflecting that you have 

access to, and the ability to deploy in 

accordance with § 250.471, all SCCE 

necessary to regain control of the well, 

including the ability to evaluate the 

performance of the well design to 

determine how a full shut-in can be 

achieved without having reservoir fluids 

discharged into the environment; 

(2) An inventory of the local and 

regional SCCE, supplies, and services 

that you own or for which you have a 

contract with a provider. You must 

identify each supplier of such 

equipment and services and provide 

their locations and telephone numbers; 

(3) Where applicable, proof of 

contracts or membership agreements 

with cooperatives, service providers, or 

other contractors that will provide you 

with the necessary SCCE or related 

supplies and services if you do not 

possess them. The contract or 

membership agreement must include 

provisions for ensuring the availability 

of the personnel and/or equipment on a 

24-hour per day basis while you are 

drilling below or working below the 

surface casing; 

(4) A detailed description of the 

procedures for inspecting, testing, and 

maintaining your SCCE; and 

(5) A detailed description of your plan 

to ensure that all members of your 

operating team who are responsible for 

operating the SCCE have received the 

necessary training to deploy and operate 

such equipment in Arctic OCS 

Conditions and demonstrate ongoing 

proficiency in source control operations. 

You must also identify and include the 

dates of prior and planned training. 

(g) Where it does not conflict with 

other requirements of this subpart, and 

except as provided below, you must 

comply with the requirements of API RP 

2N, Third Edition ‘‘Planning, Designing, 

and Constructing Structures and 

Pipelines for Arctic Conditions’’ 

(incorporated by reference as specified 

in § 250.198), and provide a detailed 

description of how you will utilize the 

best practices included in API RP 2N 

during your exploratory drilling 

operations. You are not required to 

incorporate the following sections of 

API RP 2N into your drilling operations: 

(1) Sections 6.6.3 through 6.6.4; 

(2) The foundation recommendations 

in Section 8.4; 

(3) Section 9.6; 

(4) The recommendations for 

permanently moored systems in Section 

9.7; 

(5) The recommendations for pile 

foundations in Section 9.10; 

(6) Section 12; 

(7) Section 13.2.1; 

(8) Sections 13.8.1.1, 13.8.2.1, 

13.8.2.2, 13.8.2.4 through 13.8.2.7; 

(9) Sections 13.9.1, 13.9.2, 13.9.4 

through 13.9.8; 

(10) Sections 14 through 16; and 

(11) Section 18. 

§ 250.471 What are the requirements for 

Arctic OCS source control and 

containment? 

You must meet the following 

requirements for all exploration wells 

drilled on the Arctic OCS: 

(a) If you use a MODU when drilling 

below or working below the surface 

casing, you must have access to: 

(1) A capping stack, positioned to 

ensure that it will arrive at the well 

location within 24 hours after a loss of 

well control and can be deployed as 

directed by the Regional Supervisor 

pursuant to paragraph (h) of this 

section; 

(2) A cap and flow system, positioned 

to ensure that it will arrive at the well 

location within 7 days after a loss of 

well control and can be deployed as 

directed by the Regional Supervisor 

pursuant to paragraph (h) of this 

section. The cap and flow system must 

be designed to capture at least the 

amount of hydrocarbons equivalent to 

the calculated worst case discharge rate 

referenced in your BOEM-approved EP; 

and 

(3) A containment dome, positioned 

to ensure that it will arrive at the well 

location within 7 days after a loss of 

well control and can be deployed as 

directed by the Regional Supervisor 

pursuant to paragraph (g) of this section. 

The containment dome must have the 

capacity to pump fluids without relying 

on buoyancy. 

(b) You must conduct a monthly 

stump test of dry-stored capping stacks. 

If you use a pre-positioned capping 

stack, you must conduct a stump test 

prior to each installation on each well. 

(c) As required by § 250.465(a), if you 

propose to change your well design, you 

must submit an APM. For Arctic OCS 

operations, your APM must include a 

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reevaluation of your SCCE capabilities 

for any new WCD rate, and a 

demonstration that your SCCE 

capabilities will meet the criteria in 

§ 250.470(f) under the changed well 

design. 

(d) You must conduct tests or 

exercises of your SCCE, including 

deployment of your SCCE, when 

directed by the Regional Supervisor. 

(e) You must maintain records 

pertaining to testing, inspection, and 

maintenance of your SCCE for at least 

10 years and make the records available 

to any authorized BSEE representative 

upon request. 

(f) You must maintain records 

pertaining to the use of your SCCE 

during testing, training, and deployment 

activities for at least 3 years and make 

the records available to any authorized 

BSEE representative upon request. 

(g) Upon a loss of well control, you 

must initiate transit of all SCCE 

identified in paragraph (a) of this 

section to the well. 

(h) You must deploy and use SCCE 

when directed by the Regional 

Supervisor. 

§ 250.472 What are the relief rig 

requirements for the Arctic OCS? 

(a) In the event of a loss of well 

control, the Regional Supervisor may 

direct you to drill a relief well using the 

relief rig described in your APD. Your 

relief rig must comply with all other 

requirements of this part for drilling 

operations, and it must be able to drill 

a relief well under anticipated Arctic 

OCS Conditions. 

(b) When you are drilling below or 

working below the surface casing during 

Arctic OCS exploratory drilling 

operations, you must have access to a 

relief rig, different from your 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. 

(c) Operators may request approval of 

alternative compliance measures to the 

relief rig requirement in accordance 

with § 250.141. 

§ 250.473 What must I do to protect health, 

safety, property, and the environment while 

operating on the Arctic OCS? 

In addition to the requirements set 

forth in § 250.107, when conducting 

exploratory drilling operations on the 

Arctic OCS, you must protect health, 

safety, property, and the environment 

by using the following: 

(a) Equipment and materials that are 

rated or de-rated for service under 

conditions that can be reasonably 

expected during your operations; and 

(b) Measures to address human factors 

associated with weather conditions that 

can be reasonably expected during your 

operations including, but not limited to, 

provision of proper attire and 

equipment, construction of protected 

work spaces, and management of shifts. 

■ 11. Amend § 250.1920 by: 

■ a. Adding a new last sentence to 

paragraphs (b)(5), (c), and (d); and 

■ b. Adding new paragraphs (e) and (f) 

to read as follows: 

§ 250.1920 What are the auditing 

requirements for my SEMS program? 

* * * * * 

(b) * * * 

(5) * * * For exploratory drilling 

operations taking place on the Arctic 

OCS, you must conduct an audit, 

consisting of an onshore portion and an 

offshore portion, including all related 

infrastructure, once per year for every 

year in which drilling is conducted. 

* * * * * 

(c) * * * For exploratory drilling 

operations taking place on the Arctic 

OCS, you must submit an audit report 

of the audit findings, observations, 

deficiencies and conclusions for the 

onshore portion of your audit no later 

than March 1 in any year in which you 

plan to drill, and for the offshore 

portion of your audit, within 30 days of 

the close of the audit. 

(d) * * * For exploratory drilling 

operations taking place on the Arctic 

OCS, you must provide BSEE with a 

copy of your CAP for addressing 

deficiencies or nonconformities 

identified in the onshore portion of the 

audit no later than March 1 in any year 

in which you plan to drill, and for the 

offshore portion of your audit, within 30 

days of the close of the audit. 

(e) For exploratory drilling operations 

taking place on the Arctic OCS, during 

the offshore portion of each audit, 100 

percent of the facilities operated must 

be audited while drilling activities are 

underway. The offshore portion of the 

audit for each facility must be started 

and closed within 30 days after the first 

spudding of the well or entry into an 

existing wellbore for any purpose from 

that facility. 

(f) For exploratory drilling operations 

taking place on the Arctic OCS, if BSEE 

determines that the CAP or progress 

toward implementing the CAP is not 

satisfactory, BSEE may order you to shut 

down all or part of your operations. 

PART 254—OIL-SPILL RESPONSE 

REQUIREMENTS FOR FACILITIES 

LOCATED SEAWARD OF THE COAST 

LINE 

■ 12. The authority citation for 30 CFR 

part 254 continues to read as follows: 

Authority: 33 U.S.C. 1321. 

■ 13. Amend § 254.6 by: 

■ a. Revising the definition of ‘‘Adverse 

weather conditions,’’ 

■ b. Adding a new definition for ‘‘Arctic 

OCS’’ in alphabetical order, and 

■ c. Adding a new definition for ‘‘Ice 

intervention practices’’ in alphabetical 

order. 

§ 254.6 Definitions. 

* * * * * 

Adverse weather conditions means, 

for the purposes of this part, weather 

conditions found in the operating area 

that make it difficult for response 

equipment and personnel to clean up or 

remove spilled oil or hazardous 

substances. These conditions include, 

but are not limited to: Fog, inhospitable 

water and air temperatures, wind, sea 

ice, extreme cold, freezing spray, snow, 

currents, sea states, and extended 

periods of low light. Adverse weather 

conditions do not refer to conditions 

under which it would be dangerous or 

impossible to respond to a spill, such as 

a hurricane. 

Arctic OCS means the Beaufort Sea 

and Chukchi Sea Planning Areas, as 

described in the Proposed Final OCS Oil 

and Gas Leasing Program for 2012–2017 

(June 2012). 

* * * * * 

Ice intervention practices means the 

equipment, vessels, and procedures 

used to increase oil encounter rates and 

the effectiveness of spill response 

techniques and equipment when sea ice 

is present. 

* * * * * 

14. Add § 254.55 to Subpart D to read 

as follows: 

§ 254.55 Spill response plans for facilities 

located in Alaska State waters seaward of 

the coast line in the Chukchi and Beaufort 

Seas. 

Response plans for facilities 

conducting exploratory drilling 

operations from a MODU seaward of the 

coast line in Alaska State waters in the 

Chukchi and Beaufort Seas must follow 

the requirements contained within 

subpart E of this part, in addition to the 

other requirements of this subpart. Such 

response plans must address how the 

source control procedures selected to 

comply with State law will be integrated 

into the planning, training, and exercise 

requirements of §§ 254.70(a), 254.90(a), 

and 254.90(c) in the event that the 

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proposed operations do not incorporate 

the capping stack, cap and flow system, 

containment dome, and/or other similar 

subsea and surface devices and 

equipment and vessels referenced in 

those sections. 

■ 15. Add new subpart E to read as 

follows: 

Subpart E—Oil-Spill Response 

Requirements for Facilities Located on the 

Arctic OCS 

Sec. 

254.65 Purpose. 

254.66 through 254.69 [Reserved] 

254.70 What are the additional 

requirements for facilities conducting 

exploratory drilling from a MODU on the 

Arctic OCS? 

254.71 through 254.79 [Reserved] 

254.80 What additional information must I 

include in the ‘‘Emergency response 

action plan’’ section for facilities 

conducting exploratory drilling from a 

MODU on the Arctic OCS? 

254.81 through 254.89 [Reserved] 

254.90 What are the additional 

requirements for exercises of your 

response personnel and equipment for 

facilities conducting exploratory drilling 

from a MODU on the Arctic OCS? 

Subpart E—Oil-Spill Response 

Requirements for Facilities Located on 

the Arctic OCS 

§ 254.65 Purpose. 

This subpart describes the additional 

requirements for preparing spill 

response plans and maintaining oil spill 

preparedness for facilities conducting 

exploratory drilling operations from a 

MODU on the Arctic OCS. 

§§ 254.66 through 254.69 [Reserved] 

§ 254.70 What are the additional 

requirements for facilities conducting 

exploratory drilling from a MODU on the 

Arctic OCS? 

In addition to meeting the applicable 

requirements of this part, your response 

plan must: 

(a) Describe how the relevant 

personnel, equipment, materials, and 

support vessels associated with the 

capping stack, cap and flow system, 

containment dome, and other similar 

subsea and surface devices and 

equipment and vessels will be 

integrated into oil spill response 

incident action planning; 

(b) Describe how you will address 

human factors, such as cold stress and 

cold related conditions, associated with 

oil spill response activities in adverse 

weather conditions and their impacts on 

decision-making and health and safety; 

and 

(c) Undergo plan-holder review prior 

to handling, storing, or transporting oil 

in connection with seasonal exploratory 

drilling activities, and all resulting 

modifications must be submitted to the 

Regional Supervisor. If this review does 

not result in modifications, you must 

inform the Regional Supervisor in 

writing that there are no changes. The 

requirements of this subsection are in 

lieu of the requirements in § 254.30(a). 

§§ 254.71 through 254.79 [Reserved] 

§ 254.80 What additional information must 

I include in the ‘‘Emergency response 

action plan’’ section for facilities 

conducting exploratory drilling from a 

MODU on the Arctic OCS? 

In addition to the requirements in 

§ 254.23, you must include the 

following information in the emergency 

response action plan section of your 

response plan: 

(a) A description of your ice 

intervention practices and how they 

will improve the effectiveness of the oil 

spill response options and strategies 

that are listed in your OSRP in the 

presence of sea ice. When developing 

the ice intervention practices for your 

oil spill response plan, you must 

consider, at a minimum, the use of 

specialized tactics, modified response 

equipment, ice management assist 

vessels, and technologies for the 

identification, tracking, containment 

and removal of oil in ice. 

(b) On areas of the Arctic OCS where 

a planned shore-based response would 

not satisfy § 254.1(a): 

(1) A list of all resources required to 

ensure an effective offshore-based 

response capable of operating in adverse 

weather conditions. This list must 

include a description of how you will 

ensure the shortest possible transit 

times, including but not limited to 

establishing an offshore resource 

management capability (e.g., sea-based 

staging, maintenance, and berthing 

logistics); and 

(2) A list and description of logistics 

resupply chains, including waste 

management, that effectively factor in 

the remote and limited infrastructure 

that exists in the Arctic and ensure you 

can adequately sustain all oil spill 

response activities for the duration of 

the response. The components of the 

logistics supply chain include, but are 

not limited to: 

(i) Personnel and equipment transport 

services; 

(ii) Airfields and types of aircraft that 

can be supported; 

(iii) Capabilities to mobilize supplies 

(e.g., response equipment, fuel, food, 

fresh water) and personnel to the 

response sites; 

(iv) Onshore staging areas, storage 

areas that may be used en route to 

staging areas, and camp facilities to 

support response personnel conducting 

offshore, nearshore and shoreline 

response; and 

(v) Management of recovered fluid 

and contaminated debris and response 

materials (e.g., oiled sorbents), as well 

as waste streams generated at offshore 

and on-shore support facilities (e.g., 

sewage, food, and medical). 

(c) A description of the system you 

will use to maintain real-time location 

tracking for all response resources while 

operating, transiting, or staging/

maintaining such resources during a 

spill response. 

§§ 254.81 through 254.89 [Reserved] 

§ 254.90 What are the additional 

requirements for exercises of your 

response personnel and equipment for 

facilities conducting exploratory drilling 

from a MODU on the Arctic OCS? 

In addition to the requirements in 

§ 254.42, the following requirements 

apply to exercises for your response 

personnel and equipment for facilities 

conducting exploratory drilling from a 

MODU on the Arctic OCS: 

(a) You must incorporate the 

personnel, materials, and equipment 

identified in § 254.70(a), the safe 

working practices identified in 

§ 254.70(b), the ice intervention 

practices described in § 254.80(a), the 

offshore-based response requirements in 

§ 254.80(b), and the resource tracking 

requirements in § 254.80(c) into your 

spill-response training and exercise 

activities. 

(b) For each season in which you plan 

to conduct exploratory drilling 

operations from a MODU on the Arctic 

OCS, you must notify the Regional 

Supervisor 60 days prior to handling, 

storing, or transporting oil. 

(c) After the Regional Supervisor 

receives notice pursuant to § 254.90(b), 

the Regional Supervisor may direct you 

to deploy and operate your spill 

response equipment and/or your 

capping stack, cap and flow system, and 

containment dome, and other similar 

subsea and surface devices and 

equipment and vessels, as part of 

announced or unannounced exercises or 

compliance inspections. For the 

purposes of this section, spill response 

equipment does not include the use of 

blowout preventers, diverters, heavy 

weight mud to kill the well, relief wells, 

or other similar conventional well 

control options. 

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CHAPTER V—BUREAU OF OCEAN 

ENERGY MANAGEMENT, DEPARTMENT OF 

THE INTERIOR 

PART 550—OIL AND GAS AND 

SULPHUR OPERATIONS IN THE 

OUTER CONTINENTAL SHELF 

■ 16. The authority citation for 30 CFR 

part 550 continues to read as follows: 

Authority: 30 U.S.C. 1751; 31 U.S.C. 9701; 

43 U.S.C. 1334. 

■ 17. Amend § 550.105 by adding new 

definitions for ‘‘Arctic OCS’’ and 

‘‘Arctic OCS conditions’’ in alphabetical 

order to read as follows: 

§ 550.105 Definitions. 

* * * * * 

Arctic OCS means the Beaufort Sea 

and Chukchi Sea Planning Areas, as 

described in the Proposed Final OCS Oil 

and Gas Leasing Program for 2012–2017 

(June 2012). 

Arctic OCS conditions means, for the 

purposes of this part, the conditions 

operators can reasonably expect during 

operations on the Arctic OCS. Such 

conditions, depending on the time of 

year, include, but are not limited to: 

extreme cold, freezing spray, snow, 

extended periods of low light, strong 

winds, dense fog, sea ice, strong 

currents, and dangerous sea states. 

Remote location, relative lack of 

infrastructure, and the existence of 

subsistence hunting and fishing areas 

are also characteristic of the Arctic 

region. 

* * * * * 

■ 18. Amend § 550.200 paragraph (a) by 

adding the term ‘‘IOP’’ in alphabetical 

order: 

§ 550.200 Definitions. 

* * * * * 

(a) * * * 

IOP means Integrated Operations 

Plan. 

* * * * * 

■ 19. Add a new § 550.204 to read as 

follows: 

§ 550.204 When must I submit my IOP for 

proposed Arctic exploratory drilling 

operations and what must the IOP include? 

If you propose exploratory drilling 

activities on the Arctic OCS, you must 

submit an Integrated Operations Plan 

(IOP) to the Regional Supervisor at least 

90 days prior to filing your EP. Your IOP 

must describe how your exploratory 

drilling program will be designed and 

conducted in an integrated manner 

suitable for Arctic OCS Conditions and 

include the following information: 

(a) Information describing how all 

vessels and equipment will be designed, 

built, and/or modified to account for 

Arctic OCS Conditions; 

(b) A schedule of your exploratory 

drilling program, including contractor 

work on critical components of your 

program; 

(c) A description of your mobilization 

and demobilization operations, 

including tow plans suitable for Arctic 

OCS Conditions, as well as your general 

maintenance schedule for vessels and 

equipment; 

(d) A description of your exploratory 

drilling program objectives and 

timelines for each objective, including 

general plans for abandonment of the 

well(s), such as: 

(1) Contingency plans for temporary 

abandonment in the event of ice 

encroachment at the drill site; 

(2) Plans for permanent abandonment; 

and 

(3) Plans for temporary seasonal 

abandonment; 

(e) A description of your weather and 

ice forecasting capabilities for all phases 

of the exploration program, including a 

description of how you would respond 

to and manage ice hazards and weather 

events; 

(f) A description of work to be 

performed by contractors supporting 

your exploration drilling program 

(including mobilization and 

demobilization), including: 

(1) How such work will be designed 

or modified to account for Arctic OCS 

Conditions; and 

(2) Your concepts for contractor 

management, oversight, and risk 

management. 

(g) A description of how you will 

ensure operational safety while working 

in Arctic OCS Conditions, including but 

not limited to: 

(1) The safety principles that you 

intend to apply to yourself and your 

contractors; 

(2) The accountability structure 

within your organization for 

implementing such principles; 

(3) How you will communicate such 

principles to your employees and 

contractors; and 

(4) How you will determine 

successful implementation of such 

principles. 

(h) Information regarding your 

preparations and plans for staging of oil 

spill response assets; 

(i) A description of your efforts to 

minimize impacts of your exploratory 

drilling operations on local community 

infrastructure, including but not limited 

to housing, energy supplies, and 

services; and 

(j) A description of whether and to 

what extent your project will rely on 

local community workforce and spill 

cleanup response capacity. 

■ 20. Revise § 550.206 to read as 

follows: 

§ 550.206 How do I submit the IOP, EP, 

DPP, or DOCD? 

(a) Number of copies. When you 

submit an IOP, EP, DPP, or DOCD to 

BOEM, you must provide: 

(1) Four copies that contain all 

required information (proprietary 

copies); 

(2) Eight copies for public distribution 

(public information copies) that omit 

information that you assert is exempt 

from disclosure under the Freedom of 

Information Act (FOIA) (5 U.S.C. 552) 

and the implementing regulations (43 

CFR part 2); and 

(3) Any additional copies that may be 

necessary to facilitate review of the IOP, 

EP, DPP, or DOCD by certain affected 

States and other reviewing entities. 

(b) Electronic submission. You may 

submit part or all of your IOP, EP, DPP, 

or DOCD and its accompanying 

information electronically. If you prefer 

to submit your IOP, EP, DPP, or DOCD 

electronically, ask the Regional 

Supervisor for further guidance. 

(c) Withdrawal after submission. You 

may withdraw your proposed IOP, EP, 

DPP, or DOCD at any time for any 

reason. Notify the appropriate BOEM 

OCS Region if you do. 

■ 21. Amend § 550.220 by: 

■ a. Revising paragraph (a), and 

■ b. Adding a new paragraph (c). 

§ 550.220 If I propose activities in the 

Alaska OCS Region, what planning 

information must accompany the EP? 

* * * * * 

(a) Emergency Plans. A description of 

your 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, and loss 

of or damage to a support vessel, 

offshore vehicle, or aircraft. 

* * * * * 

(c) If you propose exploration 

activities on the Arctic OCS, the 

following planning information must 

also accompany your EP: 

(1) Suitability for Arctic OCS 

conditions. A description of how your 

exploratory drilling activities will be 

designed and conducted in a manner 

suitable for Arctic OCS conditions and 

how such activities will be managed 

and overseen as an integrated endeavor. 

(2) Ice and weather management. A 

description of your weather and ice 

forecasting and management plans for 

all phases of your exploratory drilling 

activities, including: 

(i) A description of how you will 

respond to and manage ice hazards and 

weather events; 

(ii) Your ice and weather alert 

procedures; 

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Federal Register / Vol. 80, No. 36 / Tuesday, February 24, 2015 / Proposed Rules 9971 

(iii) Your procedures and thresholds 

for activating your ice and weather 

management system(s); and 

(iv) Confirmation that you will 

operate ice and weather management 

and alert systems continuously 

throughout the planned operations, 

including mobilization and 

demobilization operations to and from 

the Arctic OCS. 

(3) Source control and containment 

equipment capabilities. A general 

description of how you will comply 

with § 250.471 of this title. 

(4) Deployment of a relief well rig. A 

general description of how you will 

comply with § 250.472 of this title, 

including a description of the relief well 

rig, the anticipated staging area of the 

relief well rig, an estimate of the time it 

would take for the relief well rig to 

arrive at the site of a loss of well control, 

how you would drill a relief well if 

necessary, and the approximate 

timeframe to complete relief well 

operations. 

(5) Resource-sharing. Any agreements 

you have with third parties for the 

sharing of assets or the provision of 

mutual aid in the event of an oil spill 

or other emergency. 

(6) Anticipated end of seasonal 

operations dates. Your projected end of 

season dates, and the information used 

to identify those dates, for: 

(i) The completion of on-site 

operations, which is contingent upon 

your capability in terms of equipment 

and procedures to manage and mitigate 

risks associated with Arctic OCS 

Conditions; and 

(ii) The termination of drilling 

operations into zones capable of flowing 

liquid hydrocarbons to the surface 

consistent with the relief rig planning 

requirements under § 250.472 of this 

title and with your estimated timeframe 

under paragraph (c)(4) of this section for 

completion of relief well operations. 

[FR Doc. 2015–03609 Filed 2–20–15; 4:15 pm] 

BILLING CODE 4310–VH–4310–MR–P 

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