Oil and Gas and Sulphur Operations on the Outer Continental Shelf-Requirements for Exploratory Drilling on the Arctic Outer Continental Shelf, 9915-9971 [2015-03609]

Agencies

• DEPARTMENT OF THE INTERIOR
• Bureau of Ocean Energy Management
• Bureau of Safety and Environmental Enforcement

[Federal Register Volume 80, Number 36 (Tuesday, February 24, 2015)]
[Proposed Rules]
[Pages 9915-9971]
From the Federal Register Online via the Government Printing Office [www.gpo.gov]
[FR Doc No: 2015-03609]



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Vol. 80

Tuesday,

No. 36

February 24, 2015

Part III





 Department of the Interior





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Bureau of Safety and Environmental Enforcement





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30 CFR Parts 250 and 254





Bureau of Ocean Energy Management

30 CFR Part 550





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Oil and Gas and Sulphur Operations on the Outer Continental Shelf--
Requirements for Exploratory Drilling on the Arctic Outer Continental 
Shelf; Proposed Rule

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

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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.

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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: https://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 https://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;

[[Page 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 (Sec. Sec.  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
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                                       Report to the Secretary
                                       of the Interior, review
            60-Day report               of Shell's 2012 Alaska            MODU               Mobile offshore
                                         offshore oil and gas                                 drilling units
                                         exploration program
----------------------------------------------------------------------------------------------------------------
AIS..................................  Automatic                NARA...................  National Archives and
                                        Identification System.                            Records
                                                                                          Administration.
Alaska OCS...........................  OCS Seaward of the       National Arctic          President's National
                                        State of Alaska.         Strategy.                Strategy for the
                                                                                          Arctic Region issued
                                                                                          May 2013.
ANCSA................................  Alaska Native Claims     NEPA...................  National Environmental
                                        Settlement Act.                                   Policy Act of 1969.
APD..................................  Application for Permit   NOAA...................  National Oceanic and
                                        to Drill.                                         Atmosphere
                                                                                          Administration.
API..................................  American Petroleum       NPDES..................  National Pollutant
                                        Institute.                                        Discharge Elimination
                                                                                          System.
APM..................................  Application for Permit   OCS....................  Outer Continental
                                        to Modify.                                        Shelf.
Arctic OCS...........................  OCS within the Beaufort  OCSLA..................  Outer Continental Shelf
                                        Sea and Chukchi Sea                               Lands Act.
                                        Planning Areas.
ASP..................................  Audit Service Provider.  OMB....................  Office of Management
                                                                                          and Budget.
BOEM.................................  Bureau of Ocean Energy   OPA....................  Oil Pollution Act of
                                        Management.                                       1990.
BOP..................................  Blowout Preventer......  OSRP...................  Oil Spill Response
                                                                                          Plan.
BP...................................  BP Exploration           PPCS...................  Pre-Positioned Capping
                                        (Alaska), Inc..                                   Stack.
BSEE.................................  Bureau of Safety and     PRA....................  Paperwork Reduction
                                        Environmental                                     Act.
                                        Enforcement.
CAP..................................  Corrective Action Plan.  RFA....................  Regulatory Flexibility
                                                                                          Act.
CFR..................................  Code of Federal          RIA....................  Regulatory Impact
                                        Regulations.                                      Analysis.
CWA..................................  Clean Water Act........  RIN....................  Regulation Identifier
                                                                                          Number.
DOCD.................................  Development Operations   ROV....................  Remotely Operated
                                        Coordination Documents.                           Vehicle.
DOI..................................  Department of the        RP.....................  Recommended Practice.
                                        Interior.
DPP..................................  Development and          SCCE...................  Source Control and
                                        Production Plans.                                 Containment Equipment.
EA...................................  Environmental            Secretary..............  Secretary of the
                                        Assessment.                                       Interior.
E.O..................................  Executive Order........  SEMS...................  Safety and
                                                                                          Environmental
                                                                                          Management Systems.
EP...................................  Exploration Plan.......  SIDs...................  Shut-in Devices.
EPA..................................  Environmental            UMRA...................  Unfunded Mandates
                                        Protection Agency.                                Reform Act of 1995.
ESA..................................  Endangered Species Act.  U.S....................  United States.
IC...................................  Information Collection.  USCG...................  U.S. Coast Guard.

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ICAS.................................  Inupiat Community of     USFWS..................  U.S. Fish and Wildlife
                                        the Arctic Slope.                                 Service.
Initial RIA..........................  Initial Regulatory       WCD....................  Worst-Case Discharge.
                                        Impact Analysis.
IOP..................................  Integrated Operations    Working Group..........  Interagency Working
                                        Plan.                                             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.'' 
(https://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/agreement-on-cooperation-on-marine-oil-pollution-preparedness-and-response-in-the-arctic/).

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-Energy-Program/Resource-Evaluation/Resource-Assessment/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-and-Research/Technology-Assessment-Programs/Categories/Arctic-Research/
), and have also evaluated the potential environmental effects of such 
activities (see, e.g., https://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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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.
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    \1\ Tribes, State and local governments, and Federal agencies 
are ``partners.'' ``Stakeholders'' are non-governmental 
organizations, industry, and other entities.
    \2\ This 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.
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    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: https://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

[[Page 9920]]

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

[[Page 9921]]

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 
Sec.  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: https://www.boem.gov/About-BOEM/BOEM-Regions/Alaska-Region/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/BOEM-Regions/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)).
BILLING CODE 4310-VH-4310-MR-P
[GRAPHIC] [TIFF OMITTED] TP24FE15.005


[[Page 9922]]


    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\
---------------------------------------------------------------------------

    \3\ BP has transferred its interests in the Northstar project to 
Hilcorp. Hilcorp is now the operator of that project.
---------------------------------------------------------------------------

    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: https://www.boem.gov/About-BOEM/BOEM-Regions/Alaska-
Region/Environment/Environmental-Analysis/Environmental-Impact-
Statements-and_Major-Environmental-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 Sec.  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

[[Page 9923]]

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\
---------------------------------------------------------------------------

    \4\ BOEM'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).
---------------------------------------------------------------------------

    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 Sec.  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 Sec.  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 
Arctic-specific 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 well-planned, 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

[[Page 9924]]

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 (Sec. Sec.  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 (Sec. Sec.  250.417(c) 
and 250.418(f)); the placement of subsea BOP systems in mudline cellars 
when drilling occurs in areas subject to ice-scouring (Sec.  250.451); 
and emergency plans and critical operations and curtailment procedures 
information in the Alaska OCS Region (Sec. Sec.  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

[[Page 9925]]

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

[[Page 9926]]

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 Sec. Sec.  250.105, 254.6, and 
550.105) and Arctic OCS Conditions (for purposes of proposed Sec. Sec.  
250.105 and 550.105), the Section-by-Section discussion provides an 
explanation of the remainder of BOEM's proposed regulations (i.e., 
proposed Sec. Sec.  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 Sec. Sec.  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 Sec. Sec.  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 (Sec. Sec.  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 Sec. Sec.  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 (Sec.  550.200)
    The acronym ``IOP''--meaning Integrated Operations Plan--would be 
inserted into the proper alphabetical location within existing Sec.  
550.200, for purposes of the IOP provisions at proposed Sec.  550.204, 
as discussed next.
When must I submit my IOP for proposed Arctic exploratory drilling 
operations and what must the IOP include? (Sec.  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 
Sec.  550.204. Operators may also choose to address the requirements in 
Sec. Sec.  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

[[Page 9927]]

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 Sec.  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 Sec.  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.

[[Page 9928]]

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 well-designed, 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

[[Page 9929]]

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-[agrave]-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? (Sec.  550.206)
    DOI recognizes that operators may consider some of the information 
required by proposed Sec.  550.204 to be proprietary or commercial in 
nature. Pursuant to the proposed revisions to Sec.  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? (Sec.  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 Sec.  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

[[Page 9930]]

``vessel, offshore vehicle, or aircraft'' for clarification purposes.
    BOEM next proposes to create a new Sec.  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 performance-based provision at Sec.  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 Sec.  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 Sec.  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 Sec.  550.220(c)(3) and 
the relief well rig description required by proposed Sec.  
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 Sec.  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 Sec.  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 Sec.  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 Sec.  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

[[Page 9931]]

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 on-site 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 Sec.  250.300 
related to preventing discharge of petroleum-based mud and cuttings 
from operations that use petroleum-based mud. For further explanation 
of those provisions, see the discussion under that section.
Definitions (Sec.  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 Sec.  
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,

[[Page 9932]]

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? 
(Sec.  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 Sec.  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 Sec.  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 Sec.  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 Sec.  
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. (Sec.  250.198)
    The proposed rule would add subsection (h)(89) to existing Sec.  
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 Sec. Sec.  
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

[[Page 9933]]

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 https://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: https://publications.api.org.\5\
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    \5\ To 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.
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    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: https://www.iso.org/iso/home/store/catalogue_ics.htm or from commercial vendors.\6\
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    \6\ Copies 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).
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    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/federal-register/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 Sec.  250.198, Documents incorporated by 
reference.
Pollution prevention. (Sec.  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 petroleum-based 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 petroleum-based 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 water-based drilling fluids and drill cuttings, 
subject to effluent limitations and other requirements. Of note, the 
EPA NPDES permits do not allow the discharge of

[[Page 9934]]

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 season-specific 
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? (Sec.  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? (Sec.  250.418)
    BSEE proposes to add a new paragraph (k) to this section, providing 
that the information identified in proposed Sec.  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 Sec.  250.470).
When must I pressure test the BOP system? (Sec.  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

[[Page 9935]]

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 Sec.  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? (Sec.  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 real-time, 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 real-time 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 
Sec. Sec.  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 Sec.  250.470:
Additional Arctic OCS Requirements
What additional information must I submit with my APD for Arctic OCS 
exploratory drilling operations? (Sec.  250.470)
    BSEE proposes to add Sec.  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 Sec.  
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 Sec.  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 Sec.  250.417, but 
rather is designed to make clear that, to satisfy the fitness 
requirements of Sec.  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 Sec.  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

[[Page 9936]]

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., Sec.  
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 ``well-specific'' 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 Sec.  
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 Sec.  250.417(c)(2). That 
phrase refers to ice build-up on the vessel or equipment itself, 
whereas the focus of proposed Sec.  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 Sec.  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 well-established 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

[[Page 9937]]

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 Sec.  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 Sec.  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 Sec.  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

[[Page 9938]]

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/BSEE-Newsroom/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 jack-up 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\
---------------------------------------------------------------------------

    \7\ Copies of ISO 19905-1 may be purchased from ISO on its Web 
site (at https://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.
---------------------------------------------------------------------------

What are the requirements for Arctic OCS source control and 
containment? (Sec.  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 pre-positioned 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

[[Page 9939]]

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 Sec.  
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? (Sec.  
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

[[Page 9940]]

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 performance-based 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 Sec.  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 in-season 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

[[Page 9941]]

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? (Sec.  250.473)
    BSEE proposes to add a new Sec.  250.473 that would require 
performance-based measures in addition to those listed in Sec.  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)).
---------------------------------------------------------------------------

    \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.
---------------------------------------------------------------------------

    BSEE's existing regulation at Sec.  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 Sec.  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 
de-rated 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? (Sec.  
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 Sec.  250.1924 if it were not specifically 
tailored to the Arctic OCS Conditions reasonably anticipated at the 
facility in question.
    Similarly, existing Sec. Sec.  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

[[Page 9942]]

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. (Sec.  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 Sec.  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. (Sec.  
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 Sec. Sec.  254.70(a), 254.90(a), and 254.90(c).

[[Page 9943]]

Subpart E--Oil-Spill Response Requirements for Facilities Located on 
the Arctic OCS

Purpose (Sec.  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 Sec. Sec.  254.66 through 254.69; Sec. Sec.  
254.71 through 254.79; and Sec. Sec.  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? (Sec.  254.70)
    BSEE proposes to add Sec.  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 Sec.  
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 re-establishment 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 
Sec. Sec.  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? (Sec.  254.80)
    BSEE also proposes to create a new Sec.  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

[[Page 9944]]

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 shore-based 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.
---------------------------------------------------------------------------

    \9\ The Unified Command is a response construct under the 
incident command system headed by Federal authorities and 
coordinated with the State and other parties.
---------------------------------------------------------------------------

    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? (Sec.  254.90)
    BSEE proposes to create a new Sec.  254.90 that would require 
operators to incorporate the additional requirements contained within 
proposed Sec. Sec.  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 Sec.  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 Sec.  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 Sec.  
254.90(a) would also require that operators incorporate other proposed 
response plan features from proposed Sec. Sec.  254.70 and 254.80 into 
those activities. As outlined in proposed Sec.  254.90(c), the Regional 
Supervisor

[[Page 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 Sec.  254.42(b)(2).
    Finally, proposed Sec.  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.

[[Page 9946]]

 D. Arctic Exploratory Drilling Process Flowchart

BILLING CODE 4310-VH-; 4310-MR-P
[GRAPHIC] [TIFF OMITTED] TP24FE15.006

BILLING CODE 4310-VH-; 4310-MR-C

[[Page 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 Sec.  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

[[Page 9948]]

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 Sec.  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.
---------------------------------------------------------------------------

    \10\ As 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.
---------------------------------------------------------------------------

    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.
---------------------------------------------------------------------------

    \11\ Although 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.
---------------------------------------------------------------------------

    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,

[[Page 9949]]

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\
---------------------------------------------------------------------------

    \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.
---------------------------------------------------------------------------

    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.
---------------------------------------------------------------------------

    \13\ https://www.boem.gov/EP-PUBLIC-VERSION/.
---------------------------------------------------------------------------

    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

[[Page 9950]]

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
--------------------------------------------------------------------------------------------------------------------------------------------------------
\1\ Standby 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 low-cost 
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\
---------------------------------------------------------------------------

    \14\ We 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.
---------------------------------------------------------------------------

    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\
---------------------------------------------------------------------------

    \15\ The submissions to BOEM under Part 550 of the proposed rule 
do not follow this standard review estimate because these 
submissions would require a more time-intensive review by several 
employees.
---------------------------------------------------------------------------

    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 petroleum-based mud. In addition, these subparagraphs clarify the 
Regional Supervisor's discretionary authority to require operators to 
capture all water-based muds and associated cuttings from Arctic OCS 
exploratory drilling operations after completion of the hole for the 
conductor casing to prevent their discharge into the marine 
environment.
    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

[[Page 9951]]

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 
emergency-response 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)
------------------------------------------------------------------------
                                     10-year average     1-year average
                                      annual costs:      annual costs:
                                      alternative 1      alternative 2
             Provision               (with 7-day BOP     (without 7-day
                                         testing          BOP testing
                                       requirement)       requirement)
------------------------------------------------------------------------
a. Additional Incident Reporting               $5,374             $5,374
 Requirements.....................
b. Additional Pollution Prevention            $13,585            $13,585
 Requirements.....................
c. Additional Requirements for            $24,000,000        $24,000,000
 Securing Wells...................

[[Page 9952]]

 
d. Additional BOP Pressure Testing       $19,2000,000                 $0
 Requirements.....................
e. Real-time Monitoring                    $2,208,000         $2,208,000
 Requirements.....................
f. Additional Information                     $16,771            $16,771
 Requirements for APDs............
g. Incorporation of API RP 2N,                 $9,240             $9,240
 Third Edition....................
h. Additional SCCE Requirements...        $31,471,823        $31,471,823
i. Relief Rig Requirements........        $55,208,133        $55,208,133
j. Additional Auditing                       $249,482           $249,482
 Requirements.....................
k. Real-time Location Tracking               $121,044           $121,044
 Requirements.....................
l. IOP Requirements...............           $125,167           $125,167
m. Planning Information                       $28,702            $28,702
 Requirements to Accompany EPs....
n. Industry Familiarization with                 $313               $313
 the New Rule.....................
    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\
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                               Industry costs:       Industry costs:      Government  costs       Total costs:          Total costs:
                                                alternative 1         alternative 2    ----------------------     alternative 1         alternative 2
                   Year                    --------------------------------------------                      -------------------------------------------
                                                      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
--------------------------------------------------------------------------------------------------------------------------------------------------------
\1\ Totals might not add because of rounding.
\2\ For 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

[[Page 9953]]

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\
---------------------------------------------------------------------------

    \16\ A 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.
---------------------------------------------------------------------------

    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 cost-beneficial). 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
----------------------------------------------------------------------------------------------------------------
                                          Cost of a spill ($ millions)           10-year cost of the rule ($
                                     --------------------------------------               millions)
              Location                                                     -------------------------------------
                                             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
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                                   10-year cost of the rule ($           Break-even  number of days
                                                           Cost of spill per                millions)              -------------------------------------
                         Location                          day  ($ millions) --------------------------------------
                                                                                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 break-even is 
between 6.3 and 6.9 days for the Chukchi Sea and 9.8 and 10.8 days for 
the Beaufort Sea. To provide context, the BOEM Case Study estimates 
that the duration of a catastrophic incident in the Chukchi Sea 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

[[Page 9954]]

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 non-native 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 
Sec.  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            Improves oversight of
 Requirements.                               operations by Federal
                                             agencies.
b. Pollution Prevention Requirements......  Minimizes natural resource
                                             impacts.
c. Additional Requirements for Securing     Reduces risk of a spill.
 Wells.
d. Additional BOP Pressure Testing          Reduces risk of a spill.
 Requirements.
e. Real-time Monitoring Requirements......  Reduces risk of a spill.
f. Additional Information Requirements for  Improves oversight of
 APDs.                                       operations by Federal
                                             agencies.
g. Incorporation of API RP 2N, Third        Reduces risk of a spill.
 Edition.
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              Improves oversight of
 Requirements.                               operations by Federal
                                             agencies.
l. IOP Requirements.......................  Reduces risk of a spill.
m. Planning Information Requirements to     Improves oversight of
 Accompany EPs.                              operations by Federal
                                             agencies.
n. Industry Familiarization with the New    General.
 Rule.
------------------------------------------------------------------------

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

[[Page 9955]]

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.
---------------------------------------------------------------------------

    \17\ See 5 U.S.C. 601.
---------------------------------------------------------------------------

    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.
---------------------------------------------------------------------------

    \18\ See www.boem.gov/uploadedFiles/BOEM/About_BOEM/BOEM_Regions/Alaska_Region/Leasing_and_Plans/Leasing/Alaska_Lease_Holdings_by_Owner_or_Partial_Owner.pdf.
---------------------------------------------------------------------------

    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

[[Page 9956]]

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.
---------------------------------------------------------------------------

    \19\ See the Initial RIA for the proposed rule for details on 
baseline assumptions. We state all costs in 2012 constant dollars.
---------------------------------------------------------------------------

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.
---------------------------------------------------------------------------

    \20\ Totals might not add because of rounding.
---------------------------------------------------------------------------

    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.
---------------------------------------------------------------------------

    \21\ As explained in the initial RIA, proposed Sec.  254.80(c) 
does not require any specific real-time tracking system, so we used 
AIS as a representative system for costs analysis purposes.
---------------------------------------------------------------------------

    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 per-well 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\
---------------------------------------------------------------------------

    \22\ These totals are derived, respectively, as follows: 
($270,000,000 + $1,200,000 + $500,000) and ($160,208 + $160,208 + 
$959 + $1,174 + $5,755).
---------------------------------------------------------------------------

    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.

[[Page 9957]]



                Exhibit 7--Unit Cost of the Proposed Rule by Provision (with No Resource Sharing)
----------------------------------------------------------------------------------------------------------------
                                                                                              Cost per operator
                   Provision                        Cost per rig        Cost per well/APD       (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                         6,000,000  ....................  ....................
 Requirements.................................
e. Real-time Monitoring Requirements..........               690,000  ....................  ....................
f. Additional Information Requirements for                     1,491                 1,305  ....................
 APDs.........................................
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         ....................  ....................                 4,316
 Accompany Eps................................
n. Industry Familiarization with the New Rule.  ....................  ....................                 1,042
                                               -----------------------------------------------------------------
    Total Annual Cost Per Rig/Well/Operator              278,645,016             5,329,610                14,393
     \1\......................................
----------------------------------------------------------------------------------------------------------------
\1\ Totals 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 highest-cost 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 pressure-
testing 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.
---------------------------------------------------------------------------

    \23\ See 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.
---------------------------------------------------------------------------

    Exhibit 8 presents estimates of the total first-year costs to a 
small operator under each scenario and the total first-year 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\
---------------------------------------------------------------------------

    \24\ As 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 8--First-year Costs as a Percentage of Average Annual Revenue
                              per Operator
------------------------------------------------------------------------
                                Total first-year      Total first-year
                                      cost           cost as percent of
          Scenario           ----------------------        revenue
                                                   ---------------------
                                        A            B = A/$45.7 million
------------------------------------------------------------------------
Alternative 1 with No                 $289,318,628                   633
 Resource Sharing of SCCE...
Alternative 2 with No                  283,318,628                   620
 Resource Sharing of SCCE...
Alternative 1 with Resource             19,318,628                    42
 Sharing of SCCE............
Alternative 2 with Resource             13,318,628                    29
 Sharing of SCCE............
------------------------------------------------------------------------

    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

[[Page 9958]]

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
------------------------------------------------------------------------
                              Total annual ongoing  Total annual ongoing
                                      cost           cost as percent of
          Scenario           ----------------------        revenue
                                                   ---------------------
                                        A            B = A/$45.7 million
------------------------------------------------------------------------
Alternative 1 with No                  $19,125,311                    42
 Resource Sharing of SCCE...
Alternative 2 with No                   13,125,311                    29
 Resource Sharing of SCCE...
Alternative 1 with Resource             19,125,311                    42
 Sharing of SCCE............
Alternative 2 with Resource             13,125,311                    29
 Sharing of SCCE............
------------------------------------------------------------------------

    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\
---------------------------------------------------------------------------

    \25\ Conversely, 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.
---------------------------------------------------------------------------

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.
---------------------------------------------------------------------------

    \26\ The proposed revision to 30 CFR 250.300(b) that would 
prohibit the discharge of petroleum-based 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.
---------------------------------------------------------------------------

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 pressure-testing requirement for Arctic 
OCS exploratory drilling operations (in Sec.  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:

[[Page 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 Sec.  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 Sec.  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 Government-to-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.

[[Page 9960]]

    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 Sec.  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 Sec.  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
----------------------------------------------------------------------------------------------------------------
                                                                                          Average
                                              Reporting & Recordkeeping                  number of      Burden
    Citation 30 CFR Part 550 Subpart B               Requirement           Hour burden     annual       hours
                                                                                         responses
----------------------------------------------------------------------------------------------------------------
                                     Arctic Integrated Operations Plan (IOP)
----------------------------------------------------------------------------------------------------------------
New 204\1\................................  For New Arctic OCS                      90            2          180
                                             Exploration Activities:
                                             Submit IOP, including all
                                             required information.
----------------------------------------------------------------------------------------------------------------
                                       Contents of Exploration Plans (EP)
----------------------------------------------------------------------------------------------------------------
206.......................................  General requirements for        Burdens already covered            0
220.......................................   plans..                         under plans in 1010-
                                            Submit Alaska-specific                   0151.
                                             information..
                                                                          --------------------------

[[Page 9961]]

 
Expanded 220..............................  For New Arctic OCS                      15            2           30
                                             Exploration Activities:
                                             Submit required Arctic-
                                             specific information with
                                             EP, including confirmations.
Expanded 220..............................  For Existing Arctic OCS                 30            2           60
                                             Exploration Activities:
                                             Revise and resubmit Arctic-
                                             specific information, as
                                             required.
                                                                          --------------------------------------
    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 non-
hour 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 Sec.  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 Sec.  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 Sec.  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 Sec.  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 Sec.  
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 Sec.  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 Sec.  250.141 (+0 
hours).
    3. Subpart S:
    In Sec.  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 (Sec. Sec.  254.20-29) that is related to the requirements in 
this rulemaking under proposed Sec. Sec.  254.70, 254.80, and 254.90; 
therefore, we believe that the current burden sufficiently covers the

[[Page 9962]]

proposed modifications. We have added a new requirement in Sec.  
254.80(c) for submitting a description of the system used to maintain 
real time monitoring (+12 hours).

                                                  Burden Table
----------------------------------------------------------------------------------------------------------------
                                      Reporting and
Citation 30 CFR parts 250 and 254     recordkeeping        Hour burden      Average number of    Annual burden
                                      requirements                          annual responses         hours
----------------------------------------------------------------------------------------------------------------
                                           30 CFR Part 250, Subpart A
----------------------------------------------------------------------------------------------------------------
188(c); 190......................  NEW--Provide BSEE   Oral 1.5..........  2 notifications...  3.
                                    immediate oral
                                    report of sea ice
                                    movement/
                                    conditions; start
                                    and termination
                                    of ice management
                                    activities; kicks
                                    or unexpected
                                    operational
                                    issues.
188(c); 190......................  NEW--Submit a       Written 4.........  2 reports.........  8.
                                    written report
                                    within 24 hours
                                    after completing
                                    ice management
                                    activities.
                                  ------------------------------------------------------------------------------
 
    Subtotal.....................  ..................  ..................  4 responses.......  11 hours.
----------------------------------------------------------------------------------------------------------------
                                           30 CFR Part 250, Subpart D
----------------------------------------------------------------------------------------------------------------
418..............................  Additional information that is to be submitted with an APD  0.
                                     is covered under the specific requirement listed in this
                                                burden table under 30 CFR 250.470.
452(a), (b)......................  NEW--Immediately    12................  1 transmittal.....  12.
                                    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.
452(b)...........................  NEW--Store and      1.................  2 wells x 138       276.
                                    monitor all                             drilling days =
                                    information                             276.
                                    relating to Sec.
                                     250.452(a); make
                                    data available to
                                    BSEE upon
                                    request.
                                                      ----------------------------------------
452(b)...........................  Store and retain       Burden covered under 30 CFR 250,     0.
                                    all monitoring              Subpart D, 1014-0018.
                                    records per
                                    requirements of
                                    Sec.  Sec.
                                    250.466 and 467.
                                                      ----------------------------------------
470(a); 417; 418.................  NEW--Submit         10................  1 submittal.......  10.
                                    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
                                    Sec.   250.417.
470(b); 418......................  NEW--Submit         4.................  2 each well--       16.
                                    detailed                                underway to
                                    description of                          drilling;
                                    transitioning rig                       drilling to
                                    from being                              underway = 4.
                                    underway to
                                    drilling and vice
                                    versa.
470(b); 418......................  NEW--Submit         2.................  2 submittals......  4.
                                    detailed
                                    description of
                                    any anticipated
                                    repair and
                                    maintenance plans
                                    for the drilling
                                    unit and
                                    equipment.
470(c); 418......................  NEW--Submit well    4.................  2 submittals......  8.
                                    specific drilling
                                    objectives,
                                    timelines, and
                                    updated
                                    contingency plans
                                    etc., for
                                    temporary
                                    abandonment.
470(d); 418......................  NEW--Submit         6.................  1 submittal.......  6.
                                    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.
470(e); 418; 472.................  NEW--Submit a       140...............  1 explanation.....  140.
                                    detailed
                                    description of
                                    compliance with
                                    relief rig plans.

[[Page 9963]]

 
470(f); 471(c); 418..............  NEW--SCCE           60................  2 submittals......  120.
                                    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.
470(g); 418......................  NEW--Submit a       20................  1 submittal.......  20.
                                    detailed
                                    description of
                                    utilizing best
                                    practices of API
                                    RP 2N during
                                    operations.
471(c); 470(f); 465(a)...........  NEW--Submit with    10................  2 submittals......  20.
                                    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 Sec.
                                     250.470(f).
471(e)...........................  NEW--Maintain all   20................  2 records.........  40.
                                    SCCE testing,
                                    inspection, and
                                    maintenance
                                    records for at
                                    least 10 years;
                                    make available to
                                    BSEE upon
                                    request.
471(f)...........................  NEW--Maintain all   20................  2 records.........  40.
                                    records
                                    pertaining to use
                                    of SCCE during
                                    testing,
                                    training, and
                                    deployment
                                    activities for at
                                    least 3 years;
                                    make available to
                                    BSEE upon
                                    request.
                                                      ----------------------------------------
472(c)...........................  Request approval       Burden covered under 30 CFR 250,     0.
                                    for alternative              Subpart A, 1014-0022
                                    compliance for
                                    relief rig
                                    requirements.
                                  ------------------------------------------------------------------------------
    Subtotal.....................  ..................  ..................  297 responses.....  712 hours
----------------------------------------------------------------------------------------------------------------
                                           30 CFR Part 250, Subpart S
----------------------------------------------------------------------------------------------------------------
1920(b), (c), (e)................  ASP audit for High  1 operator x $129,000 audit for high activity = $129,000.
                                    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..
                                                      ----------------------------------------
1920(c)..........................  Submit to BSEE         Burden covered under 30 CFR 250,     0
                                    after completed             Subpart S, 1014-0017.
                                    audit, an audit
                                    report of
                                    findings and
                                    conclusions,
                                    including
                                    deficiencies and
                                    required
                                    supporting
                                    information/
                                    documentation.
                                                      ----------------------------------------
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        Burden covered under 30 CFR 254, 1014-  0.
                                    response plan for                   0007.
                                    OCS facilities
                                    with all
                                    information
                                    required in
                                    regulations and
                                    related
                                    documents.
                                                      ----------------------------------------
80(c)............................  NEW--Submit a       6.................  2 descriptions....  12.
                                    description of
                                    system used to
                                    maintain real-
                                    time location
                                    tracking for all
                                    response
                                    resources.
                                                      ----------------------------------------
90(a)............................  Include in your     Burden covered under 30 CFR 254, 1014-  0.
                                    training and                        0007.
                                    exercise
                                    activities the
                                    requirements of
                                    this section.
                                                      ----------------------------------------

[[Page 9964]]

 
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 Sec.  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

[[Page 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--right-of-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 

0
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.

0
2. Amend Sec.  250.105 by:
0
a. Revising the definition of ``District Manager'' and
0
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:


Sec.  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 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. 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.
* * * * *
0
3. Amend Sec.  250.188 by adding a new paragraph (c) to read as 
follows:


Sec.  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 Sec.  250.190.
0
4. Amend Sec.  250.198 by adding paragraph (h)(89) to read as follows:


Sec.  250.198  Documents incorporated by reference.

* * * * *
    (h) * * *

[[Page 9966]]

    (89) API RP 2N, Third Edition, ``Recommended Practice for Planning, 
Designing, and Constructing Structures and Pipelines for Arctic 
Conditions;'' incorporated by reference at Sec.  250.470(g);
* * * * *
0
5. Amend Sec.  250.300 by revising paragraphs (b)(1) and (b)(2) to read 
as follows:


Sec.  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.
* * * * *
0
6. Amend Sec.  250.402 by adding a new paragraph (c) to read as 
follows:


Sec.  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 down-
hole 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.
0
7. Amend Sec.  250.418 by adding a new paragraph (k) to read as 
follows:


Sec.  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 Sec.  250.470.
0
8. Amend Sec.  250.447 by revising paragraph (b) to read as follows:


Sec.  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
* * * * *
0
9. Add new Sec.  250.452 to read as follows:


Sec.  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 Sec. Sec.  250.466 and 250.467.
0
10. Add new undesignated centered heading ``ADDITIONAL ARCTIC OCS 
REQUIREMENTS'' and Sec. Sec.  250.470 through 250.473 in Subpart D to 
read as follows:

Additional Arctic OCS Requirements


Sec.  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 Sec.  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

[[Page 9967]]

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 Sec.  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 
BOEM-approved EP.
    (e) A detailed description of how you will comply with the 
requirements of Sec.  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 BOEM-approved 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 Sec.  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 Sec.  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.


Sec.  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 Sec.  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

[[Page 9968]]

reevaluation of your SCCE capabilities for any new WCD rate, and a 
demonstration that your SCCE capabilities will meet the criteria in 
Sec.  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.


Sec.  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 Sec.  
250.141.


Sec.  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 Sec.  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.
0
11. Amend Sec.  250.1920 by:
0
a. Adding a new last sentence to paragraphs (b)(5), (c), and (d); and
0
b. Adding new paragraphs (e) and (f) to read as follows:


Sec.  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

0
12. The authority citation for 30 CFR part 254 continues to read as 
follows:

    Authority:  33 U.S.C. 1321.

0
13. Amend Sec.  254.6 by:
0
a. Revising the definition of ``Adverse weather conditions,''
0
b. Adding a new definition for ``Arctic OCS'' in alphabetical order, 
and
0
c. Adding a new definition for ``Ice intervention practices'' in 
alphabetical order.


Sec.  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 Sec.  254.55 to Subpart D to read as follows:


Sec.  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 Sec. Sec.  
254.70(a), 254.90(a), and 254.90(c) in the event that the

[[Page 9969]]

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.
0
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


Sec.  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.


Sec. Sec.  254.66 through 254.69  [Reserved]


Sec.  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 Sec.  254.30(a).


Sec. Sec.  254.71 through 254.79  [Reserved]


Sec.  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 Sec.  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 Sec.  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.


Sec. Sec.  254.81 through 254.89  [Reserved]


Sec.  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 Sec.  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 Sec.  254.70(a), the safe working practices identified in 
Sec.  254.70(b), the ice intervention practices described in Sec.  
254.80(a), the offshore-based response requirements in Sec.  254.80(b), 
and the resource tracking requirements in Sec.  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 Sec.  
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.

[[Page 9970]]

CHAPTER V--BUREAU OF OCEAN ENERGY MANAGEMENT, DEPARTMENT OF THE 
INTERIOR

PART 550--OIL AND GAS AND SULPHUR OPERATIONS IN THE OUTER 
CONTINENTAL SHELF

0
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.

0
17. Amend Sec.  550.105 by adding new definitions for ``Arctic OCS'' 
and ``Arctic OCS conditions'' in alphabetical order to read as follows:


Sec.  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.
* * * * *
0
18. Amend Sec.  550.200 paragraph (a) by adding the term ``IOP'' in 
alphabetical order:


Sec.  550.200  Definitions.

* * * * *
    (a) * * *
    IOP means Integrated Operations Plan.
* * * * *
0
19. Add a new Sec.  550.204 to read as follows:


Sec.  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.
0
20. Revise Sec.  550.206 to read as follows:


Sec.  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.
0
21. Amend Sec.  550.220 by:
0
a. Revising paragraph (a), and
0
b. Adding a new paragraph (c).


Sec.  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;

[[Page 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 Sec.  250.471 of this 
title.
    (4) Deployment of a relief well rig. A general description of how 
you will comply with Sec.  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 Sec.  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