Proposed Final

Outer Continental Shelf

Oil & Gas Leasing Program

2012-2017

June 2012

U.S. Department of the Interior

Bureau of Ocean Energy Management www.boem.gov

iii

Table of Contents 

Abbreviations......................................................................................................................vi

Overview...................................................................................................ix

I. Summary of Decision–Proposed Final Program for 2012-2017..............................1

II. Framework for Formulating the Proposed Final Program for 2012-2017..........25

A. Procedural Requirements......................................................................25

B. Substantive Requirements.....................................................................26

C. Judicial Guidance..................................................................................31

D. Analytic Approach................................................................................31

III. Proposed Final Program Options............................................................................35

A. Size, Timing, and Location Options.....................................................35

Gulf of Mexico Region..................................................................42

Alaska Region................................................................................63

B. Fair Market Value Options....................................................................84

IV. Program Analyses....................................................................................................100

A. Analysis of Energy Needs...................................................................100

B. Analysis of Environmental Concerns..................................................115

C. Comparative Analysis of OCS Planning Areas...................................116

D. Laws, Goals, and Policies of Affected States.....................................188

E. Balancing Considerations under Section 18........................................188

F. Assurance of Fair Market Value..........................................................194

G. Appropriations and Staffing Estimates....................................197

Chart

1: International Crude Oil Prices.......................................................106

Figures

1: Lease Sale Process........................................................................39

2: Components of Net Benefits Analysis.............................................................117

Maps

Map A: Shows the Alaska Program Areas............................................................21

Map B: Shows the Lower 48 State Program Areas...............................................22

Map C: Shows Chukchi Sea Analytical Considerations.................................23

Map D: Shows Beaufort Sea Analytical Considerations...............................24

Map 1: Shows the Alaska Planning Areas with restrictions..................................37

Map 2: Shows the Lower 48 State Planning Areas with restrictions.....................38

Map 3: Shows the Western Gulf of Mexico Program Area...................................48
iv

Map 4: Shows the Central Gulf of Mexico Program Area............................55

Map 5: Shows the Eastern Gulf of Mexico Program Area............................62

Map 6: Shows the Chukchi Sea Program Area......................................................69

Map 7: Shows the Beaufort Sea Program Area.....................................................76

Map 8: Shows the Cook Inlet Program Area.........................................................83

Tables

Table A: Resource Estimates for the 2012-2017 Proposed Final Program..........2

Table B: Proposed Final Program for 2012-2017—Lease Sale Schedule...............4

Table 1: Hurdle Prices.....................................................................91

Table 2: Long-term Assessment of Criteria under 

 Alternative Lease Sale Scenarios...............................................92

Table 3: GOM Rental Rates per Acre or Fraction Thereof...........................96

Table 4: GOM Initial Periods..............................................................97

Table 5: U.S. Energy Consumption 

 (quadrillion British thermal units (Btu))...............................................102

Table 6: U.S. Crude Oil Production (MMbbl of oil per day)..............................102

Table 7: U.S. Natural Gas Production (Trillions of Cubic Feet/Year)................103

Table 8: Petroleum and Natural Gas Production and Consumption 

 by Region in 2010..................................................................................108

Table 9: Results of No Action Alternative (No New Program)..........................111

Table 10: Price Scenarios ...............................................................119

Table 11: Production Estimates at Different Prices....................................121

Table 12: Net Economic Value.........................................................123

Table 13: Environmental and Social Costs..............................................127

Table 14: Net Benefits...................................................................131

Table 15: Summary of Net Benefits Analysis........................................134

Table 16: Valuation (Net Benefits) of Program Alternatives.......................136

Table 17: Grouping of OCS Program Areas by Relative Environmental 

 Sensitivity to Impact as a Measure of Environmental 

 Sensitivity .....................................................................138

Table 18: Ranking of OCS Program Areas by Relative Environmental 

 Sensitivity from Most to Less Sensitive to Impact.......................142

Table 19: ESI Scoring and Respective Descriptions.................................143

Table 20: Relative Environmental Sensitivity to Impact of the 

 OCS Program Areas for Coastal Habitats..................................144

Table 21: Examples of Marine Habitat Components..................................145

Table 22: Marine Habitat Abundance Values.........................................147

Table 23: Relative Environmental Sensitivity to Impact of the 

 OCS Program Areas for Marine Habitats.................................149

Table 24: Relative Environmental Sensitivity to Impact of the 

 OCS Program Areas for Coastal and Marine Birds........................153

Table 25: Relative Environmental Sensitivity to Impact of the 

 OCS Program Areas for Fish................................................155

Table 26: Relative Environmental Sensitivity to Impact of the 

 OCS Program Areas for Marine Mammals...............................158
v

Table 27: Relative Environmental Sensitivity to Impact of the 

 OCS Program Areas for Sea Turtles.......................................161

Table 28: Relative Environmental Sensitivity to Impact of the 

 OCS Program Areas for Marine Fauna....................................162

Table 29: Relative Environmental Sensitivity to Impact of the 

 OCS Program Areas for Marine Productivity..............................164

Table 30: Relative Effects of Climate Change on Environmental 

 Sensitivity of the OCS Program Areas........................................170

Table 31: Appropriations and Staffing Estimates (by Fiscal Year).....................198

Appendix

A: Summary of Comments on the Proposed Program........................................199
vi

Abbreviations

Act Outer Continental Shelf Lands Act

AEO Annual Energy Outlook

ANWR Arctic National Wildlife Refuge

ARRA American Recovery and Reinvestment Act

AWL Areawide Leasing

AWLH Areawide Leasing Half

Bbl barrel

Bbbl billion barrels

BBO billion barrels of oil

BBOE billion barrels of oil equivalent

BEA Bureau of Economic Analysis

BOE barrels of oil equivalent

BOEM Bureau of Ocean Energy Management

BOEMRE Bureau of Ocean Energy Management, Regulation and 

Enforcement

BOP Blowout preventer

BSEE Bureau of Safety and Environmental Enforcement

Btu British thermal unit

CDE Catastrophic Discharge Event

CO2 carbon dioxide

CPA Central Planning Area

CZMA Coastal Zone Management Act

DEP Department of Environmental Protection

DOD Department of Defense

DOE Department of Energy

DOI Department of the Interior

DPP Draft Proposed Program 

E&D Exploration and Development

EFH Essential Fish Habitat

EIA Energy Information Administration

EIS Environmental Impact Statement

EP Exploration Plan

ESA Endangered Species Act

ESI Environmental Sensitivity Index

ESP Environmental Studies Program

ESPIS Environmental Studies Program Information System

FMP Fishery Management Plan

FMV Fair Market Value

FR Federal Register

G&G Geological and Geophysical

GDP gross domestic product

GHG greenhouse gases

GOM Gulf of Mexico

GOMESA Gulf of Mexico Energy Security Act
vii

HAPC Habitat of Particular Concern

IARPC Interagency Arctic Research Policy Committee

IEA International Energy Agency

IPCC Intergovernmental Panel on Climate Change

LADNR Louisiana Department of Natural Resources

LNG liquefied natural gas

Mbbl thousand barrels

MBOE thousand barrels of oil equivalent

Mcf thousand cubic feet

MMbbl million barrels

MMBOE million barrels of oil equivalent

MMPA Marine Mammal Protection Act

MMS Minerals Management Service

MSFCMA Magnuson-Stevens Fishery Conservation and Management 

Act

NAA No Action Alternative

NAAQS National Ambient Air Quality Standards

NAB North Aleutian Basin

NEPA National Environmental Policy Act

NEV Net economic value

NMFS National Marine Fisheries Service

NOAA National Oceanic and Atmospheric Administration

NO2 nitrogen dioxide

NOI Notice of Intent

NPDES National Pollutant Discharge Elimination System

NSV Net Social Value

NTL Notice to Lessees and Operators

N/TS Nomination/Tract Selection

NWR National Wildlife Refuge

OCS Outer Continental Shelf

OECM Offshore Environmental Cost Model

ONRR Office of Natural Resources Revenue

OPEC Organization of Petroleum Exporting Countries

PADD Petroleum Administration for Defense Districts

PEIS Programmatic Environmental Impact Statement

PFP Proposed Final Program

PM10 particulate matter up to 10 micrometers

PP Proposed Program

PSD Prevention of Significant Deterioration

RFI Request for Interest

SEMS Safety and Environmental Management System

SO2 sulfur dioxide

TAPS Trans-Alaska Pipeline System

Tcf trillion cubic feet

TVD SS True Vertical Depth Subsea

UERR Undiscovered Economically Recoverable Resources
viii

U.S. United States

USCG U.S. Coast Guard

USDOC U.S. Department of Commerce

USFWS U.S. Fish & Wildlife Service

USGS U.S. Geological Survey
ix

Overview

Management of the oil and gas resources of the Outer Continental Shelf (OCS) is 

governed by the OCS Lands Act (Act), which sets forth procedures for leasing, 

exploration, and development and production of those resources. Section 18 of the Act 

calls for the preparation of an oil and gas leasing program indicating a five year schedule 

of lease sales designed to best meet the Nation’s energy needs. The Bureau of Ocean 

Energy Management (BOEM) is the bureau within the Department of the Interior (DOI) 

that is responsible for implementing these requirements of the Act related to preparing 

the leasing program. 

BOEM is in the process of preparing a Five Year Program for 2012-2017. This 

document constitutes the Proposed Final Program (PFP), which is the third in a series of 

mandated leasing proposals developed for public review before the Secretary of the 

Interior may take final action to approve the new Five Year Program for 2012-2017. The 

document consists of the parts described below.

• Part I presents a summary of the PFP as decided by the Secretary. It briefly describes 

the location and timing of potential OCS oil and gas lease sales proposed for 2012-

2017, discusses procedures for ensuring the receipt of fair market value (FMV) for 

leases as required by section 18, and provides additional information related to the 

preparation of this PFP.

• Part II describes the framework for developing the new program. It discusses the 

substantive and procedural requirements that are in place for preparing a program 

under section 18 and describes BOEM’s approach to meeting those requirements. 

This includes a discussion of the criteria relating to OCS oil and natural gas resources 

and environmental and social considerations that section 18 requires to be taken into 

account in deciding where and when to propose lease sales. Also included is a 

summary of the judicial history and guidance received from the courts concerning the 

Five Year Program. 

• Part III presents the options that BOEM prepared based on its analysis of the section 

18 criteria. The options form the basis from which the Secretary chooses the PFP for 

2012-2017. Each set of options is prefaced with a brief summary of the relevant 

results of the section 18 analysis, including consideration of the Final Environmental 

Impact Statement (EIS) prepared pursuant to the National Environmental Policy Act 

(NEPA), and consideration of comments that BOEM received from interested and 

affected parties on the November 2011 Proposed Program (PP).

• Part IV presents the detailed section 18 analysis prepared by BOEM to develop the 

options presented to the Secretary.

• Appendix A is a summary of the comments received by BOEM in response to its 

public request for comments on the 2011 PP.

1

I. SUMMARY OF DECISION—PROPOSED FINAL PROGRAM 

FOR 2012-2017

Introduction

This is DOI’s Proposed Final Outer Continental Shelf Oil and Gas Leasing Program for 

2012-2017, which BOEM1 has prepared pursuant to the Act. Under section 18 of the 

Act, the Secretary of the Interior is responsible for preparing and maintaining a schedule 

of proposed OCS oil and gas lease sales determined to “best meet national energy needs 

for the 5-year period following its approval or reapproval,” while also taking into account 

a range of important principles and considerations specified by the Act.2 

Accordingly, the PFP presents the careful balancing necessary to ensure that 

“[m]anagement of the outer Continental Shelf shall be conducted in a manner which 

considers economic, social, and environmental values of the renewable and nonrenewable 

resources contained in the outer Continental Shelf, and the potential impact of oil and gas 

exploration on other resource values of the outer Continental Shelf and the marine, 

coastal, and human environments.”3 The PFP is central to advancing the President’s 

commitment to expanding safe and responsible domestic oil and natural gas production as 

part of a comprehensive, all-of-the-above strategy to meet the Nation’s energy needs. 

This PFP, which follows the January 2009 Draft Proposed Program (DPP) and the 

November 2011 PP, is the third and final proposed document that the DOI will issue in 

connection with establishing the new Five Year OCS Oil and Gas Leasing Program (Five 

Year Program) for 2012 through 2017.4 As required by section 18 of the Act, the PFP 

has been submitted to the President and Congress along with copies of the comments 

received on the PP, transmittal letters to Federal agencies and state governors, and 

responses to recommendations from the governors. The PFP must be submitted to the 

President and Congress for a minimum of 60 days before the Secretary can approve the 

Five Year Program. Assuming the new Five Year Program is approved, the first lease 

sale under the program is scheduled for November of 2012. 

Overview of the Proposed Final Program

This PFP includes fifteen potential lease sales in six planning areas – the Western and 

Central Gulf of Mexico (GOM), the portion of the Eastern GOM not currently under 

Congressional moratorium, and the Chukchi Sea, Beaufort Sea and Cook Inlet planning 

areas offshore Alaska. That portion of the individual planning area that is being 

considered for leasing in a Five Year Program is referred to as the program area. A 

 1 With the exception of publications whose title includes the agency name or as otherwise noted, all 

references in the document to BOEM include its predecessor agencies, the Bureau of Ocean Energy 

Management, Regulation and Enforcement (BOEMRE) and the Minerals Management Service (MMS).

2 43 U.S.C. 1344

3 43 U.S.C. 1344(a)(1)

4 The complete Five Year Program development process is described below in part II of this document.
2

program area can be the entire planning area as in the Cook Inlet offshore Alaska; a small 

portion as in the Eastern GOM; or any size in between. The program also provides for 

the number and timing of sales within and among areas. Maps A and B show the areas 

proposed for leasing (Proposed Final Program Areas). These include the richest and most 

promising areas for oil and gas exploration and development on the U.S. OCS and 

together they include more than 75 percent of the total undiscovered, technically 

recoverable oil and natural gas resources estimated for the entire OCS. The PFP, 

therefore, advances the Administration’s Blueprint for a Secure Energy Future, which

aims to promote the Nation’s energy security and reduce oil imports by a third by 2025 

through a comprehensive national energy policy that includes a focus on expanding safe 

and responsible domestic oil and natural gas production. 

Table A below describes the estimated undiscovered, technically recoverable oil and gas 

resource potential of each of the program areas included for leasing in the PFP.

Table A: Resource Estimates for the 2012-2017 Proposed Final Program5

Program Area

Estimated Undiscovered Technically 

Recoverable Resources 

Oil 

(Bbbl)

Gas

(Tcf)

BOE

(Bbbl)

 Central Gulf6 30.47 130.91 53.76

Chukchi Sea 15.38 76.77 29.04

Western Gulf 12.38 69.45 24.74

Beaufort Sea 8.22 27.64 13.14

Cook Inlet 1.01 1.20 1.23

Eastern Gulf (area not 

under Congressional 

moratorium) 0.25 0.65 0.36

Total Proposed Final 

Program 67.71 306.62 122.27

Total OCS 88.59 398.37 159.49

This PFP also is informed by the experience of the Deepwater Horizon event which 

caused the deaths of 11 workers and resulted in the release of nearly five million barrels 

of oil into the GOM. Since the Deepwater Horizon event, the DOI has raised standards 

for offshore drilling safety and environmental protection in order to both reduce the risk 

 5

Assessment of Undiscovered Technically Recoverable Oil and Gas Resources of the Nation’s Outer 

Continental Shelf, 2011. (2011 Assessment). Resource estimates for oil and barrels of oil equivalent (BOE) 

are expressed in billions of barrels of oil (Bbbl) and estimates for natural gas are expressed in trillions of 

cubic feet (Tcf).

6 A portion of the Central Gulf of Mexico planning area (CPA) and most of the Eastern Gulf of Mexico 

were place under moratoria by the Gulf of Mexico Energy Security Act of 2006 and restricted from leasing 

until 2022. The area restricted is that portion of the Eastern planning area within 125 miles of Florida, all 

areas in the Gulf of Mexico east of the Military Mission Line (86° 41`W longitude), and the area within the 

CPA that is within 100 miles of Florida.
3

of another loss of well control in our oceans and to improve the Federal government’s 

and industry’s ability to respond in the unlikely event of another deepwater blowout and 

major oil spill. While offshore oil and natural gas exploration and development cannot 

be made risk free, these activities can be conducted safely and responsibly, with strong 

regulatory oversight and appropriate measures to protect human safety and the 

environment.

To best achieve the goals of making areas containing the vast majority of offshore oil and 

natural gas resources available for development and ensuring that such development 

occurs safely and in a manner that protects the environment and other ocean resources, 

BOEM has developed a regionally tailored approach to offshore oil and gas leasing. This 

regionally tailored strategy, described in detail below, recognizes that a one-size-fits-all 

approach to offshore leasing is not appropriate. Decisions about the OCS planning areas 

to be considered for potential leasing, as well as decisions about the configuration of 

individual lease sales within a planning area, must be based on the unique combination of 

resource potential, and environmental and social factors specific to individual OCS areas. 

As detailed throughout the PFP, BOEM carefully analyzed and weighed the individual 

factors specified under section 18 of the Act to develop this regionally tailored leasing 

program. Based on this analysis, BOEM has developed the schedule of offshore oil and 

gas lease sales described below. 

In sum, the PFP schedules a total of fifteen potential offshore oil and gas lease sales in six 

OCS planning areas. Twelve of these sales are planned for the Western and Central 

GOM and the portion of the Eastern GOM planning area that was made available for 

leasing under the GOM Energy Security Act (GOMESA) in 2006. Oil and natural gas 

resource potential in the GOM is well-understood and the infrastructure to bring oil and 

natural gas resources to market and to respond in the event of a spill or other emergency 

is mature. 

The PFP also schedules three potential lease sales in planning areas off of the coast of 

Alaska – one each in the Chukchi Sea and Beaufort Sea planning areas that span the 

Alaskan Arctic and one in the Cook Inlet planning area offshore southcentral Alaska. As 

discussed below, these potential lease sales off Alaska are deliberately scheduled late in 

the program to allow for the further development of scientific information regarding the 

oil and gas resource potential in these areas, as well as the sensitive habitats, unique 

conditions and important other uses, including subsistence hunting and fishing, that are 

present in Alaskan waters and must be reconciled with energy resource development. 

North Aleutian Basin (NAB), which includes the rich and vital fishing resources of 

Bristol Bay, was withdrawn from leasing consideration by the President in a statement on 

March 31, 2010. 

Table B below lists the location and timing of the proposed lease sales under the PFP. 
4

Table B: Proposed Final Program for 2012-2017−Lease Sale Schedule

Sale No.* Area Year

229 Western Gulf of Mexico 2012

227 Central Gulf of Mexico 2013

233 Western Gulf of Mexico 2013

225 Eastern Gulf of Mexico** 2014

231 Central Gulf of Mexico 2014

238 Western Gulf of Mexico 2014

235 Central Gulf of Mexico 2015

246 Western Gulf of Mexico 2015

226 Eastern Gulf of Mexico 2016

241 Central Gulf of Mexico 2016

237 Chukchi Sea 2016

248 Western Gulf of Mexico 2016

244 Cook Inlet*** 2016

247 Central Gulf of Mexico 2017

242 Beaufort Sea**** 2017

*As in the PP, the sales are not in numerical order for various reasons. As the 2009 DPP 

encompassed the 2010-2015 time period, many of the sales listed in that document were carryovers 

from the latter part of the Five Year Program for 2007-2012 announced in June 2007. These sales 

were either held, deleted in the December 2010 Revised Program for 2007-2012, or cancelled under 

the pre-sale process. Those numbers are no longer available for use in this program. Other sales 

included in the 2009 DPP are no longer being considered for leasing in this PFP and those sale 

numbers also are not available. 

**Sales in the Eastern GOM would only include those areas that are not currently subject to 

moratorium under GOMESA.

***The Cook Inlet sale is listed as a special interest sale. On March 27, 2012, BOEM issued a 

Request for Interest, with respect to the Cook Inlet planning area. In light of responses to the 

Request, BOEM decided to proceed with the pre-sale process for the Cook Inlet and to place the date 

for a potential lease sale in 2016 to allow time to complete the necessary steps under the Act, 

develop additional resource and environmental information, and conduct analysis under NEPA.

****Beaufort Sea Sale 242 has been postponed from 2015 to 2017 in recognition of the significant 

overlapping of subsistence use, resource distribution, species habitat, and to allow more time to 

analyze and implement our focused leasing strategy in this area.
5

Regionally Tailored Leasing

The PFP is based on section 18 factors that resulted in leasing strategies that are tailored 

to specific planning areas in order to best achieve the dual goals of promoting prompt 

development of the Nation’s oil and natural gas resources and providing the necessary 

protections for the marine, coastal and human environments. The region-specific 

strategies reflected in the PFP’s approach to offshore areas across the OCS are designed 

to take into account current and developing information about resource potential, the 

status of resource development and emergency response infrastructure to support oil and 

gas activities, recognition of regional interest and concerns, and the need for a balanced 

approach to our use of the Nation’s shared natural resources. 

This innovative approach best fulfills DOI’s responsibility under the Act to balance the 

various uses of the ocean resources when making leasing decisions, and advances 

BOEM’s commitment to analyzing each potential action in light of the cumulative effects 

of related activities. Among other things, this Five Year Program establishes and defines 

parameters for application of this region-specific approach throughout the offshore 

leasing cycle prescribed under the Act. 

Below is a discussion regarding the leasing strategy that BOEM has developed with 

respect to each of the planning areas that is included in the PFP, as well as the forwardlooking strategy for potential oil and gas leasing in areas, such as the Mid- and South 

Atlantic planning areas, in which lease sales are not scheduled under the PFP but 

potential future activity is under active evaluation. 

The Gulf of Mexico

The oil and natural gas resource potential of the Western and Central GOM, as well as

that of the portion of the Eastern GOM not subject to the Congressional moratorium and 

made available for leasing by GOMESA, are the best understood of the OCS planning 

areas. The GOM currently supplies more than a quarter of the U.S. domestic oil 

production. Seismic data and other resource evaluations covering the GOM are 

extremely sophisticated, providing industry and BOEM with unparalleled detailed 

geological and geophysical information about the scope and location of oil and natural 

gas prospects in the GOM. Moreover, the existing infrastructure in the GOM to support 

offshore oil and natural gas activity, in terms of developing resources, as well as the 

systems and equipment necessary to respond in the event of an emergency, is mature and 

well developed. 

Therefore, in the Central and Western GOM planning areas, which are the two OCS 

planning areas that combine the most abundant proven and estimated oil and natural gas 

resources as well as broad industry interest and mature infrastructure, the PFP includes 
6

annual areawide sales of all legally available, unleased acreage, as has been the 

traditional leasing model in the GOM.7

 

The PFP also schedules two lease sales in the Eastern GOM planning area. This program 

area encompasses the Sale 224 area, a sale that was mandated by GOMESA and held in 

2008, and a triangular-shaped region to the southeast that is not otherwise restricted. The 

majority of the Eastern GOM, including all acreage east of 86°41’W longitude and areas 

west of that longitude that are within 125 miles of Florida, and a small portion of the 

Central GOM within 100 miles of Florida are subject to Congressional moratorium until 

mid-2022 pursuant to GOMESA. These areas under moratorium are not included in this 

Five Year Program.

In summary, the PFP provides the following schedule for planning areas in the GOM: 

Western GOM: A total of five annual areawide lease sales beginning in the fall of 2012 

that make available all legally available unleased acreage.

Central GOM: A total of five annual areawide lease sales beginning in the spring of 

2013 that make available all legally available unleased acreage.

Eastern GOM: A total of two sales, in 2014 and 2016, in areas of the Eastern GOM not 

currently under Congressional moratorium.

 

Maps 3, 4, and 5 in part III of this document depict the specific GOM program areas 

proposed for lease sales.

Offshore Alaska 

In this PFP, DOI is taking a balanced and careful approach to oil and natural gas leasing 

offshore Alaska. The PFP schedules one potential lease sale each in the Chukchi Sea and

Beaufort Sea planning areas, set late in the schedule established under the Five Year 

Program, 8 as well as one special interest sale in the Cook Inlet planning area if industry 

interest in that planning area remains sufficient to justify consideration of the sale.9

In light of both the significant resource potential that exists in the Alaskan Arctic and the 

substantial environmental challenges and the social and ecological concerns that are 

 7 In response to comments, particularly from the State of Louisiana, a discussion of possible alternatives to 

areawide leasing is included in the fair market value section in part III.B of this document. These 

alternatives may be considered for implementation at the lease sale phase, in the GOM as well as Alaska 

planning areas.

8 Although the State of Alaska disagrees, as indicated in its letter dated February 8, 2012, with scheduling 

lease sales offshore of Alaska later in the Five Year Program, the Governor of Alaska has consistently 

supported sales in the OCS offshore Alaska. Moreover, scheduling oil and natural gas lease sales in the 

Beaufort Sea and Chukchi Sea is consistent with the State’s administration of its offshore oil and gas 

program.

9 On March 27, 2012, BOEM issued a Request for Interest with respect to the Cook Inlet planning area. In 

light of responses to the Request, BOEM decided to proceed with the pre-sale process.
7

present as well, BOEM’s regionally tailored strategy for any future offshore oil and gas 

leasing in the Arctic is markedly different from the traditional areawide leasing model 

applied in the GOM, in which all unleased acreage in the area is typically offered for sale, 

with the exception of limited areas that may be set aside for exclusion; for example, the 

Flower Garden Banks National Marine Sanctuary. 

While this Program begins from the starting point that certain subsets of Arctic areas will 

be excluded because environmental and subsistence conditions strongly weigh in favor of 

keeping them off the table for exploration and development, BOEM’s goal is to reorient 

the process for designing Arctic lease sales away from a model where the full area is 

included, except for specific exclusions. Rather, BOEM is developing a process in which 

it will continue to use incoming scientific information and stakeholder feedback to 

proactively determine, in advance of any potential sale, which specific areas offer the 

greatest resource potential while minimizing potential conflicts with environmental and 

subsistence considerations. This approach is guided by internal best practices from 

developing and implementing a “Smart from the Start” strategy for offshore wind, as well 

as recommendations from the U.S. Geological Survey (USGS) and the National 

Commission on the BP Deepwater Horizon Oil Spill and Offshore Drilling that BOEM 

consider alternatives to areawide leasing, particularly for frontier areas like the Arctic. 

To facilitate this approach, BOEM will carefully consider specific subsets of the broader 

planning area that have the most promising oil and natural gas resource potential, based 

on analysis of geological and geophysical (G&G) data as well as information developed 

through any exploration under existing leases from previous sales. BOEM will further 

refine those areas in order to exclude or protect through mitigation environmentally 

sensitive habitats and subsistence uses based on ongoing scientific study and the 

incorporation of traditional knowledge supplied by Alaskan Natives. 

Significant work must be done in the coming years to further develop and aggregate the 

scientific information and traditional knowledge that will be used to identify areas that 

may be made available for oil and gas leasing in the Chukchi Sea and Beaufort Sea 

planning areas under this targeted leasing model.

First, further scientific study and environmental assessment of the Arctic is necessary. In 

June 2011, USGS issued its Evaluation of the Science Needs to Inform Decisions on 

Outer Continental Shelf Energy Development in the Chukchi and Beaufort Seas, Alaska, 

requested by the Secretary. The report recognizes that a substantial body of scientific 

work and knowledge exists with respect to the Arctic and recommends areas of focus for 

ongoing and future study, as well as further synthesis of existing scientific information 

from various sources within and outside of the government. Moreover, this approach is 

consistent with Executive Order 13580, which was issued by President Obama in July 

2011, and established a high-level Interagency Working Group on Coordination of 

Domestic Energy Development and Permitting in Alaska (Working Group). This 

Working Group is chaired by the Deputy Secretary of the Interior and is focused on 

facilitating coordinated and orderly decision-making in Alaska, including development 

and sharing of scientific information in support of regulatory processes. The Working 
8

Group’s efforts are coordinated with scientific work across the Federal government –

including through the Interagency Arctic Research Policy Committee (IARPC). Notably, 

BOEM currently has ongoing studies that are evaluating, for example, the Hanna Shoal 

habitat in the Chukchi Sea and the subsistence hunting and fishing patterns of Native 

Alaskans from the North Slope communities of Point Hope, Point Lay and Wainwright.10 

Second, planning and designing lease sales in the Chukchi Sea and Beaufort Sea planning 

areas will take into account any information about geology and resource potential that 

may be developed as a result of G&G surveys and exploration under current leases in 

those areas.11 Exploration may provide valuable data for defining the best areas for 

potential development and for assessing reservoir characteristics such as volumes and 

pressures that are central to ensuring that appropriate safety measures and spill response 

resources are in place. Ongoing government, academia, and industry research will 

contribute valuable information and aid in our understanding of sea-ice dynamics, marine 

mammal activity, and a variety of other issues pertaining to the Arctic. Important 

collaborations such as the recent agreement between an oil and gas company and 

National Oceanic and Atmospheric Administration (NOAA) to share industry data with 

that Federal Agency opens the door to new collaborations and data access that will 

further contribute to our collective knowledge. 

Further, as offshore oil and natural gas exploration under existing leases moves forward, 

so too must near- and long-term planning with respect to infrastructure, including spill

response preparedness. Current spill response planning is focused on certain, limited 

near-term proposed drilling operations in the Arctic OCS. Longer term planning and 

infrastructure development are also necessary, particularly if major oil resources are 

found and producers seek to engage in year-round production activities. Longer term 

planning is another major focus of the Working Group. This PFP provides time for 

contingency planning and infrastructure development that is needed to address these 

issues. 

Defining the Targeted Leasing Model for the Alaskan Arctic

This PFP presents BOEM’s current evaluation of a number of different factors that must 

be considered in the design of potential Arctic sales, which include resource potential, 

subsistence use, and environmental conditions. For example, Maps C and D for the 

 10 Map C regarding the Chukchi Sea planning area illustrates the Hanna Shoal regional and core study areas 

and describes the current information regarding subsistence use patterns in the Chukchi Sea, which includes 

primarily existing information for Barrow. BOEM’s Environmental Studies Program (ESP) is planning a 

study (to begin in 2013) to provide updated baseline information concerning subsistence use by Native 

Alaskan communities in the Chukchi Sea, including among other things, resource harvest locations, areas 

of specific harvest intensity, and variation in duration of use.

11 On August 4, 2011, BOEM issued a conditional approval of Shell’s revised exploration plan (EP) for the 

Beaufort Sea to drill up to four exploration wells starting in summer 2012. On December 16, 2011, BOEM 

issued conditional approval of Shell’s revised EP in the Chukchi Sea to drill up to six exploration wells 

beginning in the 2012 drilling season. On March 1, 2012, ConocoPhillips submitted an EP to drill up to 6 

exploration wells, beginning in the summer of 2014, in the Chukchi Sea. BOEM must deem the EP 

complete and then approve the ConocoPhillips EP among approvals from other agencies necessary before 

the company may conduct any operations under the EP.
9

Chukchi Sea and Beaufort Sea planning areas respectively, depict a geospatial analysis of 

several data sources that is being used to assess these various factors and the interplay 

among them. The ultimate goal of using this analytical method is to design potential 

lease sales in the Chukchi Sea and Beaufort Sea planning areas that make significant oil 

and gas resources in defined areas available while minimizing conflicts with other uses of 

the OCS, consistent with BOEM’s mandate under the Act to balance social, economic, 

and environmental considerations. 

With respect to the oil and natural gas resources, the maps differentiate between areas of 

high, medium, and low hydrocarbon potential.12 This data incorporates current 

geophysical, geological, technological, and economic information and employs a 

probabilistic methodology to estimate the undiscovered technically recoverable resources 

of oil and natural gas. Nearly all current and historical leases in these planning areas are 

located in areas defined as having high petroleum potential. 

The maps overlay this resource information with subsistence data obtained through a 

series of socio-economic studies conducted over the past three decades in order to assess 

areas of high, medium, and low subsistence use.13 Further, the maps display important 

environmental information about the Arctic. These include, for example, the critical 

habitat area for the Spectacled Eider. They also include regional and core study areas 

concerning the Hanna Shoal habitat in the northeast Chukchi Sea, where scientific studies 

have documented sustained benthic productivity, accompanied by high concentration of 

water birds, walruses, and whales. BOEM’s ESP is conducting an ongoing study of this 

Hanna Shoal area14 and is initiating a subsistence mapping study focused on the 

communities of Wainwright, Point Lay, and Point Hope that will inform future decisions.

 12 Assessment of Undiscovered Technically Recoverable Oil and Gas Resources of the Nation’s Outer 

Continental Shelf, 2011. 13 BOEM’s ESP sponsored a study, published in 2009 and entitled “Study Report No. 2009-006 

Synthesis: Three Decades of Research on Socio-Economic Effect Related to Offshore Petroleum Development 

in Coastal Alaska” which includes an extensive presentation of data regarding subsistence use patterns of 

Beaufort Sea communities and other issues, collected through a series of community-specific technical studies 

conducted over the course of three decades preceding publication of the report. BOEM is initiating a similar 

study to map subsistence use patterns of Chukchi Sea communities. MMS – now BOEM – originally designed its 

template for subsistence research in the 1980s to provide baseline profiles of communities and areas, covering a 

wide range of topics that collectively described and explained subsistence patterns. These early reports compiled 

information from the literature, augmented with materials from key respondent interviews and the expertise of 

investigators. They provide the baseline and starting point for subsequent, community-specific studies of North 

Slope communities which ESP has continued to support throughout the three-decade period covered by the 2009 

report. BOEM OCS Study 2009-003, “Subsistence Mapping of Nuiqsut, Kaktovik, and Barrow” analyzed social 

science survey data that collected variables of subsistence use such as species harvested, the location and 

frequency of harvest, and areas commonly used by individual hunters. The report aggregated this information to 

present it geospatially as a range of intensity of use. Areas at the higher end of the spectrum are defined for the 

purposes of this map as “high use”, while areas with less intensity but some indication of use are defined as 

“medium use.” BOEM recognizes that these data evolve, and will continue to incorporate new information as it 

becomes available.

14 The main objectives of the current study are to identify and measure important physical and biological 

processes that contribute to the high concentration of marine life in the Hanna Shoal area. BOEM will integrate 

data gained from this study with other relevant Chukchi Sea studies to provide a more complete understanding of 

environmental considerations such as food web dynamics and potential contaminant bioaccumulations.
10

BOEM will continue to expand and refine its analysis over the course of the 

implementation period for this Five Year Program, drawing on a range of information 

sources, including but not limited to: 

• Information gained through any activity on existing leases; 

• Ongoing scientific analysis – including science conducted through BOEM’s ESP 

and drawing from the range of available scientific information – and 

incorporation of traditional knowledge; 

• Information gathered over the course of the pre-lease planning process – as 

discussed below; BOEM is implementing a number of measures to enhance the 

effectiveness and transparency of the pre-lease planning process; and 

• Information gained through consultations and collaborations with other Federal 

agencies such as the NOAA and the U.S. Fish and Wildlife Service (USFWS) as 

well as with Alaska Native groups and communities with traditional knowledge of 

the use of the OCS, the scientific community; industry; and state and local 

governments.

• Information gained through collaboration and coordination with other entities 

such as the North Pacific Research Board and the Arctic Research Council that

are involved in directing, conducting, or prioritizing science in the Arctic. Two 

specific examples include: BOEM is coordinating closely with IARPC and has 

had a role in developing the IARPRC Arctic Research Plan for FY2013-2017 that 

was recently put out for public comment; and BOEM scientists are working with 

the National Science Foundation initiative Arctic Science, Engineering, and 

Education for Sustainability to ensure our science efforts are closely integrated 

and complimentary. 

Building on broad-based analysis at the Five Year Program stage, ongoing analysis will 

support more focused decision-making in the context of defining and planning each of 

the specific lease sales in the Chukchi Sea and Beaufort Sea planning areas. Should the 

Secretary decide to move forward with lease sales, the sale planning stage would include 

a more definitive set of decisions about which blocks to offer, the terms of the sale, and 

specific lease stipulations and conditions. 

In working to finalize this PFP, BOEM has prioritized the development of tools that will 

facilitate the identification and design of this targeted lease sale strategy for areas 

offshore Alaska. As described in greater detail in the Enhancements to the Leasing 

Process section below, a series of new tools will facilitate this ongoing analysis and 

provide increased transparency to the public throughout the implementation of the 

program. 

The Chukchi Sea Planning Area

As mentioned above, the PFP schedules one potential oil and natural gas lease sale in the 

Chukchi Sea planning area in 2016. The PFP maintains a 25-mile nearshore buffer area 

that was excluded in the 2009 DPP. This area was an alternative analyzed in the 2007-

2012 EIS. This area in the Chukchi Sea is excluded in this PFP for the same reasons it
11

was excluded in the 2007-2012 Program, and those reasons are incorporated here by 

reference.15 As BOEM moves forward to define potential areas in the Chukchi Sea 

planning area that may be offered for oil and natural gas leasing, no acreage within this 

25-mile exclusion area may be considered for leasing. 

Moreover, based on current information regarding both resource potential and areas of 

significant subsistence use, the Secretary has decided to remove an additional area north 

of Barrow from consideration in defining any future oil and natural gas lease sale area in 

the Chukchi Sea planning area. As delineated in Map C of the Chukchi Sea planning 

area, this additional deferral area is located north of Barrow and covers approximately 

1,163,409 acres and 208 OCS lease blocks beyond the northern edge of the 25-mile 

exclusion area. 

After evaluating current information regarding resource potential and subsistence use in 

the Chukchi Sea planning area, the Secretary determined that it is appropriate at the PFP 

stage to exclude areas in the Chukchi Sea planning area that (1) involve at least medium 

intensity subsistence use or higher; (2) allow for unencumbered subsistence use; (3) are 

contiguous with and extend the boundary of an existing deferral area16, and (4) do not 

include significant acreage identified as offering high resource potential. Analysis of the 

Chukchi and Beaufort Seas

17 planning areas shows that this portion of the Chukchi Sea 

area described above meets those criteria, and is appropriate for exclusion at the PFP. 

This area does not include any blocks that are currently leased or have been leased in the 

past. While there is a sliver of acreage in this exclusion area that is identified as having 

high resource potential, the sliver does not include significant acreage, and including this 

sliver in the program area would not allow for unencumbered use of the entire medium 

subsistence use area. 

Finally, it is important to note that the study that identified the subsistence use data 

focused on the communities of Barrow, Nuiqsut, and Kaktovik, which accounts for the 

areas of high and medium subsistence use being focused on in areas around those 

communities. At this point, we do not have similarly relevant data around the 

communities of Wainwright, Point Lay, and Point Hope; which necessitates the study 

referenced above that will map subsistence use data in these areas. The additional 

subsistence data made available by this study, along with other analysis, will be 

considered when making future decisions about the size and scope of potential lease 

sales.

 15 As discussed in “Chapter II: Alternatives Including the Proposed Action” of the 2007-2012 

Programmatic EIS.

16 Contiguous, unencumbered subsistence use areas are logistically essential to allow the small vessels used 

by native communities, uninterrupted access to the areas for which their livelihood depends.

17 The existing Barrow subsistence whaling deferral described later covers all full lease blocks that meet the 

criteria listed for exclusion.
12

The Beaufort Sea Planning Area

The PFP schedules one oil and gas lease sale in the Beaufort Sea planning area in 2017. 

As reflected in Map D of the Beaufort Sea planning area, the PFP excludes two 

subsistence whaling deferral areas near Barrow and Kaktovik from leasing. These areas 

in the Beaufort Sea are excluded in this PFP for the same reasons they were excluded in 

the 2007-2012 Program, and those reasons are incorporated here by reference.18 As 

demonstrated on the map, the Beaufort Sea planning area is complex, with significant 

overlap between areas that may offer significant hydrocarbon resource potential and other 

uses, including subsistence hunting and fishing. Therefore, it is necessary to take the 

time available prior to the scheduled potential sale to further analyze the resource 

potential in the area, including consideration of any exploration activity in the Beaufort 

Sea planning area under existing leases, and further develop scientific information and 

incorporate traditional knowledge regarding environmental factors and subsistence uses. 

This ongoing analysis will inform decisions about the configuration of the Beaufort Sea 

planning area lease sale, as well as any specific mitigation measures that may be 

appropriate. 

The Cook Inlet Planning Area

The PFP schedules one special interest sale in the Cook Inlet planning area in 2016. This 

sale was initially scheduled in the PP for 2013, but in light of broad industry interest in 

the planning area, as expressed in response to the RFI that BOEM issued on March 27, 

2012, BOEM has moved this sale to later in the program to accommodate appropriate 

NEPA analysis and planning. At this point, industry has expressed sufficient interest in 

oil and natural gas leasing in the Cook Inlet planning area for BOEM to proceed with 

planning for a potential sale, including conducting an EIS evaluating the potential effects 

on the entire planning area of an oil and natural gas lease sale in the area. 

The Atlantic

This PFP does not schedule lease sales in the North Atlantic, Mid-Atlantic, South 

Atlantic or Straits of Florida planning areas, consistent with the principles of regionally 

tailored leasing that underlie the entire program. While certain Atlantic states are 

supportive of offshore oil and natural gas leasing in the Mid- and South Atlantic planning 

areas, many other Atlantic states expressed concerns about oil and natural gas 

development off their coasts and in neighboring areas. While the DPP issued in January 

2009 included the North, Mid- and South Atlantic planning areas as under consideration 

for potential inclusion in the program, a number of specific considerations, discussed 

below, support the Secretary’s decision in the PP and PFP not to schedule lease sales in 

these areas at this time. Accordingly, BOEM is proceeding with a region-specific 

strategy to address these considerations and support future decision-making regarding 

whether, and if so where, potential offshore oil and gas lease sales in the Mid- and South 

Atlantic planning areas would be appropriate. 

 18 As discussed in “Chapter II: Alternatives Including the Proposed Action” of the 2007-2012 

Programmatic EIS.
13

First, current G&G information regarding oil and natural gas resource potential in the 

Mid- and South Atlantic is based on older data collected in the 1970s and 1980s. 

Tremendous advances in instrumentation and technology for the acquisition and analysis 

of G&G data have been made in the intervening decades. Modern G&G data, including 

seismic surveys and other scientific information, is needed to evaluate the resource 

potential in these areas and to inform decisions about whether and where any leasing 

should take place. Accordingly, BOEM has assigned a high priority to moving forward 

to facilitate resource evaluation in these areas, including conducting a Programmatic EIS 

relating to G&G surveys in the Mid- and South Atlantic planning areas. BOEM issued 

this draft EIS for public comment in March 2012 and expects to complete the EIS in late 

2012 or early 2013, which could mean G&G surveys in the Mid- and South Atlantic may 

move forward as early as 2013. 

Second, there are complex issues relating to potentially conflicting uses, including but not 

limited to those of the Department of Defense (DOD), which must be addressed so that 

any potential future leasing activity in these areas is configured appropriately. For 

example, in response to the 2009 DPP, DOD identified significant conflicts in the 

proposed Sale 220 area offshore of Virginia such that it believed that “no oil and gas 

activity” should be conducted in 72 percent of the proposed sale area and that no 

permanent oil and gas facilities should be located in an additional 5 percent of the 

proposed Sale 220 area.19 DOI respects the military’s mission in protecting the United 

States and will continue to work closely with DOD to understand and deconflict the 

military’s needs in these areas as we consider future energy development in the Mid- and 

South Atlantic planning areas. 

Finally, as DOI moves forward in these areas with facilitating the evaluation of the 

resource potential and deconflicting potential oil and gas activity from other uses, so too 

should longer-term analysis and planning be completed for the infrastructure and 

resources that would be necessary to prepare for such activity. Currently, the Mid- and 

South Atlantic planning areas lack the infrastructure necessary to support oil and gas 

exploration and development, including infrastructure necessary to support exploration

and development activity and for responding to emergencies such as a spill. 

Taken together, these factors supported the Secretary’s decision not to include the Midand South Atlantic planning areas for evaluation at the PP and PFP stage of development

of this Five Year Program. Thus, they may not be considered at this PFP stage, under the 

section 18 winnowing process. However, as summarized above, BOEM is currently 

pursuing a specific strategy to develop modern, robust scientific information about the 

scope and location of potential oil and gas resources in the Mid- and South Atlantic and 

to resolve significant potential conflicts between oil and gas activity and other important 

OCS uses in these areas, including military, fishing, and vessel traffic uses as well as 

environmental and infrastructure concerns. 

 19 September 18, 2009, letter to MMS Director from the Office of the Under Secretary of Defense
14

The Pacific 

The four planning areas off the Pacific coast were not included for potential oil and 

natural gas leasing in the PP, therefore are not available for consideration in this PFP 

under the section 18 winnowing process. This determination was consistent with the 

requirements of section 18 of the Act, which gives priority leasing consideration to areas 

where the combination of previous experience; local, state, and national laws and 

policies; and expressions of industry interest indicate that potential leasing and 

development activities could be expected to proceed in an orderly manner. Consistent 

with the principles of section 18 and the resulting regionally tailored leasing strategy, this 

Five Year Program specifically seeks to provide appropriate weight to the 

recommendations of governors of coastal states and of state and local agencies. The 

exclusion of the Pacific Coast is consistent with the long-standing interests of Pacific 

coast states, as framed in an agreement that the governors of California, Washington, and 

Oregon signed in 2006.20 This agreement expressed the governors’ opposition to oil and 

gas development off their coasts, and these states continued to voice these concerns, 

including in formal comments on the 2009 DPP.

Enhancements to the Leasing Process

BOEM finalized this PFP in a manner that addresses the substantial public input the 

agency received following issuance of the PP in November 2011. BOEM received over 

280,000 written comments, and heard from a range of stakeholders in public hearings that 

were held in the GOM region, Washington D.C., and in Alaska, including in communities 

across the North Slope. Many of the comments focused on BOEM’s approach to leasing 

and generally requested additional spatial deferrals, temporal deferrals and mitigations 

for specific areas in the Arctic and the GOM. As discussed above, while DOI has taken 

action in this PFP with respect to adjusting the subsistence deferral area in the Chukchi 

Sea planning area, the regionally tailored approach to leasing underlying the PFP, as well 

as the multi-staged process under the Act, specifically contemplate further decisionmaking regarding the location and configuration of offshore oil and natural gas lease 

sales, including with respect to potential deferrals and mitigation measures, at later stages 

in the process. 

In light of the many comments requesting deferrals and mitigations and BOEM’s own 

review of its leasing process under the Act, BOEM has developed a range of 

enhancements designed to increase public engagement and transparency with respect to 

leasing decisions to be made after publication of this PFP. These enhancements also 

address numerous comments that focused on the importance of developing a strategic 

approach to leasing on the OCS. Specifically, BOEM has developed tools to increase 

transparency and public dialogue throughout the stages of the leasing process defined by 

the Act in order to ensure that each step in the leasing process provides a meaningful 

opportunity to incorporate feedback and new information. This approach highlights and 

strengthens many important decision points that exist in the leasing process established 

 20 West Coast Governors Agreement on Ocean Health, September 18, 2006
15

by the Act, which begins with the Five Year Program, continues through the planning and 

execution of each individual lease sale, and follows with post-lease planning and 

oversight of operations. 

The multi-staged process under the Act provides many opportunities for BOEM to take 

into account public input and developing scientific information in making determinations 

regarding the timing, geographic location, configuration and specific conditions, 

including mitigation measures, of each lease sale. The tools described below are 

designed to enhance each stage of the process. 

Annual Progress Reports

Beginning with this PFP, BOEM is committing to publish an annual progress report on 

the Five Year Program that includes an opportunity for stakeholders and the public to 

comment on the program’s implementation. Under section 18(e) of the Act, the 

Secretary must review an approved program each year. Historically, this review has been 

an internal process with BOEM reporting to the Secretary any information or events that 

might result in the Secretary’s consideration of a revision to the program. 

This new annual progress report will provide the public an overview of the activities that 

have occurred during the previous year, including but not limited to: 

• Statistics of sales that have occurred in the previous year including the number 

and location of lease blocks and the dollars collected on high bids; 

• An aggregate collection of all newly enacted deferrals and mitigations; 

• A summary of completed and ongoing safety and environmental studies; 

• Regulatory updates; 

• A discussion of any significant new drilling activities; and 

• A summary of any significant incidents. 

The findings of this annual progress report may lead the Secretary to revise the program 

by delaying, cancelling, or reducing the size of scheduled lease sales, which generally 

does not require revision of the Five Year Program under the Act. If any revisions --

such as including new areas for consideration or adding more sales in areas already 

included in the program – are considered significant under the Act, then the full section 

18 process must be followed with respect to those changes, which may result in the 

preparation of a new Five Year Program.

Mitigation Tracking Table

As described above, BOEM may incorporate additional spatial deferrals, temporal 

deferrals, and mitigation measures at a number of different points in the leasing process 

under the Act. BOEM will continue to use new information, including developing 

scientific information, to inform decisions at each successive stage. In some cases, 

BOEM may determine that a certain decision is best suited for a later stage in the process 

once additional information or analysis becomes available. For example, BOEM has a 
16

number of ongoing studies concerning the Chukchi Sea and Beaufort Sea planning areas 

that will be used to help determine the configuration, including potential area exclusions 

in light of environmental concerns or subsistence use, of any lease sales in those areas. 

Many comments on the PP requested specific deferrals and mitigation measures. 

Accordingly, BOEM is establishing a tracking table to provide increased visibility into 

the consideration of these recommendations at each stage of the leasing process. 

Beginning with the Five Year Final EIS, this tool will track the lineage and treatment of 

suggestions for spatial exclusions, temporal deferrals, and mitigation from the Five Year 

Program to the lease sale phase and on to the plan phase. The tracking table will allow 

the public to see how and at what stage of the process their concerns are being 

considered. Thus, the tracking table will increase the public visibility of the iterative and 

progressive nature of the leasing process under the Act. In addition, the tracking table is 

a vehicle for BOEM to provide the public with information about the consideration of 

comments and proposals at multiple decision points in the offshore oil and gas leasing 

process. 

The Pre-Lease Sale Process 

BOEM is taking a number of steps to enhance opportunities for the public to comment 

and provide new information in the pre-lease sale planning process. The first step of the 

pre-lease sale process is the Call for Information (Call) and the Notice of Intent (NOI) to 

prepare an environmental analysis. Historically, the Call has generally asked for industry 

to nominate specific blocks or descriptions of areas within the program area for which 

they have the most interest, while the NOI requests comments on issues that should be 

addressed and alternatives that should be considered. To enhance this step in the prelease sale process and to make it more robust and inclusive, BOEM will implement a 

number of enhancements. 

BOEM will use both the Call and the NOI as vehicles to ask for specific 

recommendations about areas of concern that could warrant consideration for mitigation 

measures or removal from the sale. In the areas of the GOM where BOEM proposes to 

continue with areawide leasing, this information will help to identify specific concerns 

that may demand particularized mitigation measures such as additional lease stipulations. 

In the Arctic, BOEM will use the information gained through this process, in 

combination with resource estimates, information from potential exploratory drilling, 

environmental reviews, and other data, to focus leasing on the most promising tracts, 

while protecting important Arctic habitats and critical subsistence activities. 

This approach to the pre-lease process will complement the tracking table, which BOEM 

will update to indicate where feedback is considered and instances where it has led to a 

specific mitigation measure, or to removal of an area. Within the Call and NOI 

themselves, BOEM will provide a link to a tailored map identifying areas in which 

specific mitigation measures or exclusions have been determined to apply or are under 

consideration. This tailored map will allow the public to view multiple layers of existing 

data and afford the opportunity to provide new data to better inform decision-makers. 
17

See Figure 1 and the more detailed discussion of the lease sale process in part III of this 

document.

Assurance of Fair Market Value

Section 18 requires that the government receive FMV for OCS oil and gas leases. A 

series of decisions related to the timing of a lease sale, the leasing framework, sale terms, 

and bid adequacy provide the foundation for ensuring receipt of FMV. BOEM intends to 

use a two-phase post-sale bid evaluation process that has been in effect since 1983 to 

meet the FMV requirement and will continue to study and evaluate refinements and 

alternative approaches throughout the next Five Year Program. Further, the PFP allows 

BOEM to evaluate alternatives with respect to delaying a sale area, choosing a leasing 

framework, and setting the fiscal terms and conditions by individual lease sale, based on 

the Bureau’s timely assessment of market and resource conditions. Part III.B of this 

document discusses in detail the considerations that go into these decisions. For 

example, certain lease sales conducted during the latter years of the current 2007-2012 

program have incorporated a number of enhanced approaches to ensure FMV and provide 

incentives for diligent development. Examples from the previous program included

adjusting initial lease periods and raising minimum bid requirements based on rigorous 

economic and historical analysis of activity under leases sold at various prices per acre. 

Additional Background Concerning Preparation of the 2012-2017 

Program

Preparation of a new Five Year Program usually takes two and a half to three

years. BOEM began the preparation process for the Five Year Program by publishing a 

Request for Information on August 1, 2008 (73 FR 45065). BOEM then published the 

2009 DPP for a 2010-2015 program and an NOI to prepare an EIS on January 21, 2009 

(74 FR 3631) with the statutory minimum 60-day comment period. On February 10, 

2009, the Secretary extended the 2009 DPP comment period for an additional 180 days to 

September 21, 2009, and personally hosted four public meetings in April 2009, in order 

to provide additional time for input from states, affected communities, and other 

stakeholders. The comments received during the comment period and at the meetings 

were summarized in Appendix A of the PP document. Scoping meetings for the Five 

Year EIS, scheduled to be held during the initial 60-day comment period, were 

postponed. 

In light of the comment period extension and BOEM’s evaluation of existing policies and 

regulations in light of lessons learned from the Deepwater Horizon event on April 20, 

2010, the time period to be covered by the new program shifted from 2010-2015 to 2012-

2017. The 2009 DPP remains as the first of three decision proposals for the 2012-2017 

program; the PP as the second proposal for the 2012-2017 program; and this PFP as the 

third and, assuming final approval by the Secretary, the last proposal for the 2012-2017 

program. If unchanged, this PFP will succeed the current 2007-2012 program, following 

that program’s expiration on June 30, 2012. The 2012-2017 program will be effective on 

the day that the Secretary approves the program, and that date will be no sooner than 60 

days following submission of this PFP to the President and Congress. 
18

The 2009 DPP proposed 31 OCS lease sales in 12 of the 26 OCS planning areas, 

including the three Atlantic planning areas, two of the planning areas offshore Pacific, 

four offshore Alaska, including the NAB – which includes Bristol Bay – in addition to 

the three areas in the GOM included in the PP and PFP. The 2009 DPP contained the 

section 18 analysis on all 26 planning areas. At the PP step, BOEM analyzed six areas, 

pursuant the Act, in the decision document, and, pursuant to NEPA, in the Five Year 

Draft EIS. At this PFP step, there is further analysis of the same six areas in this decision

document and the accompanying Five Year Final EIS. 

On March 31, 2010, President Obama and Secretary Salazar announced a Comprehensive 

Strategy for Offshore Oil and Gas Exploration and Development to strengthen the 

Nation’s energy security and reduce dependence on foreign oil, while protecting 

fisheries, tourism, and areas off U.S. coasts that are not appropriate for development. 

The Secretary announced that scoping for a Five Year EIS would proceed for eight of the 

twelve areas included in the 2009 DPP, including the Beaufort Sea, Chukchi Sea, and 

Cook Inlet off the coast of Alaska; Western, Central, and Eastern GOM; and the Midand South Atlantic. This comprehensive strategy document excluded the North Atlantic, 

the two areas offshore California, and the NAB. At the same time, President Obama 

withdrew the NAB from leasing consideration through June 30, 2017, pursuant to section 

12 of the Act and therefore it was not available for inclusion in the Five Year Program 

under section 18. The decision to exclude the North Atlantic and offshore California was 

made with consideration of comments concerning these areas received on the 2009 DPP. 

The States of Delaware and New Jersey, states adjacent to the North Atlantic, voiced 

their opposition to oil and natural gas activities off their coasts and pointed to state 

policies and initiatives to encourage development of renewable energy sources. In his 

comments on the 2009 DPP, the Governor of California reiterated the state’s longstanding opposition by governors of both parties to new leasing off its coast. That 

position was also presented by the California Coastal Commission, the state agency 

which has regulatory authority, pursuant to the Coastal Zone Management Act (CZMA), 

over Federal activities on the OCS that affect the state’s coastal resources. 

After the President’s March 31, 2010, announcement and in light of the Deepwater 

Horizon event on April 20, 2010, the President and Secretary stressed the need to 

heighten the standards for the safety and environmental responsibility of oil and gas 

operations on the OCS. Recognizing that existing regulations had not kept up with the 

advancements in technology used in deepwater drilling, BOEMRE – now separated into 

two bureaus, BOEM and the Bureau of Safety and Environmental Enforcement (BSEE) –

quickly issued new, rigorous prescriptive regulations that bolstered offshore drilling 

safety and heightened efforts to evaluate and mitigate environmental risks. 

BOEMRE, introduced performance-based workplace safety standards (described below) 

similar to those used by regulators in the North Sea, to make operators responsible for 

identifying and minimizing the risks associated with drilling operations. This included 

the development and implementation of two new rules that raised standards for the oil 

and gas industry’s operations on the OCS.
19

The Drilling Safety rule, issued in October 2010, heightened standards for well design, 

casing and cementing, and well control procedures and equipment, including blowout 

preventers (BOP). This rule requires operators to have a professional engineer certify the 

adequacy of the proposed drilling program. In addition, the new Drilling Safety rule 

requires an engineer to certify that the BOP to be used in a drilling operation meets new 

standards for testing, maintenance, and performance.

The Workplace Safety rule, also issued in October 2010, requires operators to 

systematically identify risks and establish barriers to those risks in order to reduce the 

human and organizational errors that cause many accidents and oil spills. Under the rule, 

operators had to develop a comprehensive Safety and Environmental Management 

System (SEMS) program by November 2011, which identifies the potential hazards and 

risk-reduction strategies for all stages of activity, from well design and construction 

through the decommissioning of platforms. Many companies had developed such SEMS 

programs on a voluntary basis in the past, but many had not. 

In September 2011, BOEMRE published a follow-up proposed rule, “Oil and Gas and 

Sulphur Operations in the Outer Continental Shelf—Revisions to Safety and 

Environmental Management Systems” (SEMS II). The proposed rule includes 

procedures that authorize any employee on a facility to cause work to stop– frequently 

called Stop Work Authority – in the face of an activity or event that poses a threat to an 

individual, to property or to the environment. The proposed rule also establishes 

requirements relating to the clear delineation of who possesses ultimate authority on each 

facility for operational safety; establishes guidelines for reporting unsafe work conditions 

that give all employees the right to report a possible safety or environmental violation and 

to request a BSEE investigation of the facility; and requires third-party, independent 

audits of operators’ SEMS programs. A final rule is expected to publish in 2012. In the 

meantime, in response to several requests, BSEE issued Notices to Lessees (NTL) 2011-

N09 in October 2011, to provide lessees and operators guidance on the development and 

implementation of a SEMS program.

In addition to these important new rules, BOEMRE issued additional guidance to 

operators on complying with existing regulations. NTL 2010-N06 outlines the 

information that must be provided in an operator’s exploration or development plan, 

including a well-specific blowout scenario, a worst-case discharge scenario, and the 

assumptions and calculations behind these scenarios. Operators are required, as 

described in NTL 2010-N06, to revise their oil spill response plans, if necessary, to 

address revised calculation of the worst case discharge potential of proposed wells. 

BOEMRE’s NTL 2010-N10 describes the requirement for a corporate compliance 

statement and review of subsea blowout containment resources for drilling operations 

using a subsea BOP or a surface BOP on a floating facility. To obtain a permit to 

conduct such a drilling operation, operators must demonstrate that they have access to, 

and can deploy, subsea containment resources that would be sufficient to respond 

promptly to a deepwater blowout or other loss of well control. 
20

The Deepwater Horizon event and subsequent requirements described in NTL 2010-N10 

also created new impetus for industry-driven containment technology. For example, the 

offshore oil and natural gas industry has formed two consortia – the Marine Well 

Containment Company and the Helix Well Containment Group – to develop and make 

available to operators subsea containment systems, including capping stacks and systems 

for the capture of flow from a well. BSEE requires all operations covered by NTL-2010-

N10 to demonstrate the ability – in advance of obtaining a drilling permit for each 

individual well – to deploy the systems necessary to respond to a loss of well control. 

Reform efforts also have focused on strengthening the institutions responsible for 

managing offshore resources and enforcing compliance with safety standards. On May 

19, 2010, the Secretary signed a Secretarial Order that directed the division of MMS into 

three separate organizations – BOEM, BSEE, and the Office of Natural Resources 

Revenue (ONRR), each with separate and clearly defined missions. Following the 

completion of that reorganization on October 1, 2011, BOEM manages the 

environmentally and economically responsible development of the Nation’s offshore 

resources, including preparation and maintenance of the Five Year Program. BSEE is 

responsible for safety and environmental enforcement of offshore oil and gas operations, 

including permitting and inspections, and ONRR handles revenue collection and 

disbursement. 

In developing the PP and now this PFP, BOEM carefully considered the risks associated 

with oil spills and the measures needed to reduce the likelihood of spill occurrence and to 

mitigate damage in the unlikely event of a blowout. BOEM also considered the 

significant safety and environmental improvements and reforms implemented by BOEM 

and BSEE since the Deepwater Horizon event; as well as improved industry capabilities 

such as the development of subsea containment systems. The Five Year Final EIS 

includes extensive consideration of these reforms, as well as a detailed comparison of 

current standards with previous regulatory requirements. It concludes that the new 

measures create a more robust regulatory system that strikes the right balance so that 

energy development is conducted safely and in an environmentally responsible manner, 

while also being more efficient, transparent, and responsive. For a more detailed 

description of the regulatory, policy, and procedural actions taken since the Deepwater 

Horizon event in order to mitigate risks, see Section IV.A of the Five Year Final EIS for 

the 2012-2017 Program.
21

Map A: Shows the Alaska Program Areas
22

Map B: Shows the Lower 48 State Program Areas
23

Map C: Shows Chukchi Sea Analytical Considerations
24

Map D: Shows Beaufort Sea Analytical Considerations
25

II. FRAMEWORK FOR FORMULATING THE PROPOSED 

FINAL PROGRAM FOR 2012-2017

A. Procedural Requirements 

The development of the PFP is one of several steps in the process of preparing the new 

Five Year Program. This document is the third and, the last proposal of OCS lease sales 

for the 2012-2017 timeframe. Before a new Five Year Program may be approved and 

implemented, BOEM must solicit and consider comments received on a draft proposed 

program, proposed program, and Five Year Draft EIS, and issue a Five Year Final EIS 

and a proposed final program to submit to the President and the Congress for a minimum 

of 60 days. The key steps in preparing a new Five Year Program under section 18 of the 

Act and section 102(2)(C) of NEPA are described below.

Request for Comments and Suggestions

On August 1, 2008, BOEM published in the Federal Register (73 FR 45065) a request 

for comments and information regarding the preparation of a new Five Year Program for 

2010-2015, to commence two years before the expiration of the Five Year Program for 

2007-2012, and announced the start of scoping for the associated EIS. BOEM also sent 

letters to the governors and the heads of interested Federal agencies requesting their input 

by September 15, 2008. 

Draft Proposed Program 

The 2009 DPP included various analyses of the section 18 factors (see parts IV and V of 

the 2009 DPP) and was offered as the initial proposal for the Five Year Program for 

2010-2015. BOEM announced the 2009 DPP and NOI to Prepare an EIS in the Federal 

Register on January 21, 2009, (74 FR 3631) and distributed it to governors, heads of 

interested Federal agencies, and interested and affected parties for a statutorily-mandated 

minimum 60-day comment period. The Secretary later extended the comment period to 

240 days and it closed on September 21, 2009. Extension of the comment period and 

other intervening events precluded an approved program from covering the originallyproposed 2010-2015 time frame. Nonetheless, comments received at the four public 

meetings that the Secretary convened in April 2009 are included in Appendix A of the PP 

decision document.

Proposed Program 

The PP was based on further section 18 analyses and consideration of the comments 

received during the extended comment period on the 2009 DPP. On November 8, 2011, 

BOEM announced the PP, which was published in the Federal Register and submitted, 

along with supporting analyses and a Five Year Draft EIS, to the governors, heads of 

interested Federal agencies, Congress, and other interested and affected parties, on 

November 10, 2011. The 90-day comment period ended on February 8, 2012, during 

which time BOEM received over 280,000 comments. These comments are summarized 

in Appendix A of this document.
26

Proposed Final Program 

The PFP is the third and, absent important Presidential or Congressional input during the 

60 day period, the last of the Secretary’s three proposals and is based on further section 

18 analyses and consideration of the comments received by BOEM concerning the PP. 

BOEM announces the PFP in the Federal Register and submits it to the President and the 

Congress, along with supporting analyses, summaries of any comments received, and an 

explanation of the responses to any recommendations received from state and local 

governments and Federal agencies. BOEM issues a Five Year Final EIS concurrently 

with the PFP.

Program Approval

Sixty days after the PFP is submitted to the President and the Congress, the Secretary 

may approve the new Five Year Program for 2012-2017.

B. Substantive Requirements

Section 18 of the Act sets forth specific principles and factors that guide Five Year 

Program formulation by providing the foundation for BOEM analysis that is used in the 

development of reasonable options for a schedule of proposed lease sales. The Secretary 

may select from these options indicating, as precisely as possible, the size, timing, and 

location of leasing activity determined to best meet national energy needs. A brief 

overview of those section 18 requirements is presented below.

Energy Needs

Section 18(a) states that the purpose of the Five Year Program is to help meet the 

Nation’s future energy needs. Part IV.A of this document presents an analysis of the 

Nation’s anticipated energy needs. The analysis includes discussions of the U.S. 

Department of Energy’s (DOE) projections of national energy needs in the Annual 

Energy Outlook (AEO), the potential contribution of OCS oil and natural gas production 

to meeting those needs, alternatives to OCS production, and considerations relating to 

regional energy needs.

Environmental Considerations, Social and Economic Value

Section 18(a)(1) requires that the Secretary manage the OCS “in a manner that considers 

the economic, social and environmental values of the renewable and nonrenewable 

resources.” The program analyses summarized in part IV of this document are conducted 

to ensure that economic, social and environmental values of the OCS are incorporated as 

important parts of the program’s development. The Act also requires the Secretary to 

consider potential impacts that oil and gas activities could have on other resource values 

of the OCS and on the marine, coastal, and human environments. Part IV.B presents the 

environmental information, including issues and concerns that have been raised by 

commenters, and presents information relating to safe and environmentally sound 

operations, as well as pertinent findings of the Final EIS for the Five Year Program for 

2012-2017 and other relevant NEPA documents. 

Economic Value

Economic value is realized from decades of oil and natural gas activity and production 

that results from activity on leases awarded during the program. There are several 
27

metrics used to calculate economic value, such as net economic value of the extracted oil 

and natural gas resources, employment, wages and income from oil and natural gas 

activity, government receipts of cash bonuses, rentals, royalties and taxes, as well as 

consumer surplus21 related to potentially lower domestic oil and natural gas prices 

resulting from OCS production. Economic values are primarily discussed in the 

Assurance of Fair Market Value Options section in part III and the Comparative Analysis 

of OCS Planning Areas section in part IV of this document.

Social Value

Social value is realized when OCS resources are combined with inputs or processes to 

generate improvements in the lives of people or benefits to society. When OCS resources 

produce the greatest social value, the program is being efficiently managed. Social value 

is negatively impacted (a social welfare loss) when OCS resources are not developed in 

the interest of conservation or when program activities result in costs to society, as from 

the results of air pollution or from a damaging event like an oil spill. Energy substitutes 

for foregone OCS oil and gas production can also cause social welfare losses, resulting 

from such things as spills of imported oil or air pollution from increased onshore 

production. Social values include both economic and environmental values and are 

components of all the substantive requirements analyses prepared for this PFP, but are 

especially relevant in the Comparative Analysis of OCS Planning Areas and Assurance of 

Fair Market Value sections in part IV of this document, as well as in the Five Year Final 

EIS.

Environmental Value

Environmental value is the worth society places on the intrinsic natural capital in the

OCS’s renewable and non-renewable resources. Natural capital, the essential goods and 

services that nature provides, includes marine productivity, quality of aesthetic resources, 

human-ecological connectivity, and air and water quality. The Final EIS for the 2012-

2017 Program considers environmental value in describing the potential impact of oil and 

gas activity on natural capital in the marine, coastal and human environments. In 

addition, the substantive requirements analyses presented herein discuss environmental 

sensitivity, marine productivity, predictive information, and relevant environmental 

impacts and their importance on environmental value. When monetized for the benefitcost analysis in the Comparative Analysis of OCS Planning Areas in part IV of this 

document, by the nature of the unit of measurement, environmental value is expressed in 

terms of social value, but BOEM attempts to capture the full value both by the nature of 

the valuation and by the assessment of environmental value in the other analyses. 

 21 As explained under the Net Benefits heading in part IV of this document, consumer surplus, a standard 

term in economics, represents the difference between the price actually charged for a service or product and

the higher price consumers would be willing to pay for this service or product if they had to. In this 

context, an action or event that lowers the price of a good or service will increase consumer surplus by the 

change in price times the quantity purchased at that lower price.
28

BOEM is supporting ongoing research to consider options and potential new approaches 

to defining and measuring environmental value including innovative ways to assess 

relative environmental sensitivity as called for in section 18 (a)(2)(G) of the Act. 

Findings from new research are not yet available for use in the PFP analysis, but current 

approaches are adequate, and may be enhanced by the use of such findings in the 

preparation of future Five Year Programs.

Factors for Determining Timing and Location of Leasing

Section 18(a)(2) lists eight factors to be considered in deciding the timing and location of 

oil and gas activities among the different areas of the OCS. While some of these factors 

lend themselves to quantification to facilitate comparison among planning areas, others 

do not and need to be considered qualitatively. Each of the eight factors provided in 

18(a)(2)(A) through (H) is listed below along with references to the parts of the PFP 

analysis and the Five Year Final EIS that address them, as appropriate.

(A) Geographical, Geological, and Ecological Characteristics

The main source of information on geographical, geological, and ecological 

characteristics of the OCS planning areas considered in preparing the PFP is the Final 

EIS for the Five Year Program for 2012-2017. Other sources include recent NEPA 

documents prepared for leasing and operational activities; the BOEM 2011 resource 

assessment and associated reports; the MMS cumulative effects report; the 1994 National 

Research Council report concerning information for Alaska OCS decisions; scientific 

study results, which are reported in the ESP information system (database; and any 

information submitted or cited by commenters.

(B) Equitable Sharing of Developmental Benefits and Environmental Risks

Part IV.C briefly analyzes the equitable sharing factor. It discusses the analyses and 

findings of previous Five Year Programs and briefly cites new developments and their 

potential influence on the nature and distribution of benefits and risks associated with the 

size, timing, and location options available for consideration.

Equitable sharing is and has been affected by the long-term withdrawal of and moratoria 

on leasing certain areas. The only existing Congressional moratorium is pursuant to 

GOMESA and the executive withdrawals are for the NAB, offshore Alaska through June 

30, 2017; and National Marine Sanctuaries that are withdrawn indefinitely.

(C) Location with Respect to Regional and National Energy Markets and Needs

Part IV.A analyzes regional and national energy needs. Chapter III of the Five Year 

Final EIS describes the socioeconomic environment for each OCS region, including the 

existing oil and natural gas infrastructure and its relationship to new leasing. Recent 

lease sale EISs and other NEPA documents cited at the end of this part also provide 
29

relevant information relating to regional distribution and processing of OCS oil and 

natural gas.

(D) Location with Respect to Other Uses of the Sea and Seabed

Part IV.C discusses competing uses of the OCS. This summary is based on information 

provided in the Final EIS for the 2012-2017 Program. Other sources include the 1997 

MMS cumulative effects report, recent lease sale EISs and other NEPA documents cited 

above in paragraph (A), ESPIS results, and any information submitted or cited by 

commenters.

(E) Interest of Potential Oil and Gas Producers

Part IV.C describes industry interest as indicated in response to the PP. The discussions 

of size, timing, and location options in part III also include summaries of industry 

interest. Appendix A summarizes all comments received from oil and natural gas 

companies and associations.

(F) Laws, Goals, and Policies of Affected States

The discussions of size, timing, and location options in part III include summaries of the 

relevant laws, goals, and policies – including federally approved coastal zone 

management programs and policies – that any state governments may have identified in 

responding to BOEM requests for comments on the PP. Appendix A summarizes all 

comments received from state governors and Federal and state government agencies.

(G) Environmental Sensitivity and Marine Productivity

Part IV.C analyzes environmental sensitivity and marine productivity for the six areas 

included in the PFP, following the process and format used in the Revised Program for 

2007-2012, in response to the U.S. Court of Appeals for the District of Columbia 

Circuit’s remand decision of April 17, 2009, (Center for Biological Diversity, et al. v. 

Department of the Interior, 563 F.3d 466 (D.C. Cir. 2009)). This expanded analysis 

includes information from NOAA’s Environmental Sensitivity Index (ESI) for 

shoreline/coastal habitats, plus additional information regarding the sensitivity of 

offshore and marine resources. The expanded analysis divides into three components the 

different areas of the OCS that may be affected by oil and natural gas activities − marine 

habitats, marine productivity, and marine fauna (i.e., birds, fish, marine mammals, and 

sea turtles). The expanded analysis also considers sensitivity to oil spills and other 

impacting factors, such as sound and physical disturbance, and increased sensitivity due 

to climate change and ocean acidification.

“Sensitivity” is not a well-defined term in ecology or environmental science. Sensitivity 

can be considered from at least two perspectives: 1) the vulnerability of ecological 

components (such as species) to potential impacts (such as harm to individual animals) 

and 2) an ecosystem’s ability to resist fundamental change and recover from an impact. 
30

Both approaches are valid and provide the information required by section 18 (a)(2)(G), 

but they each focus on different aspects of an ecosystem. While the former vulnerability 

approach or “component response” approach provides a relatively straightforward and 

quantifiable measure of potential impacts, it does not consider the cumulative effect that 

the impacts have on an ecosystem’s ability to resist fundamental, or “state,” change, a 

characteristic known as “resilience”, which is captured in the second approach and would 

focus more on a “system response.” In past analyses, BOEM has focused on a 

vulnerability or component response approach to evaluating sensitivity. The same 

approach is used in the analysis presented in this PFP, but BOEM is also aware of the 

“system response” approach. In an effort to constantly improve the basis for decisionmaking, BOEM is supporting ongoing research to consider options and potential new 

approaches to defining and measuring environmental value including assessments of 

relative environmental sensitivity as called for in section 18 (a)(2)(A) of the Act. 

Findings from the new research and analysis are not yet available for use in the PFP 

analysis, but after appropriate vetting and further consideration, will be considered for 

use in the preparation of future Five Year Programs.

As used in this PFP and the earlier PP, the term “sensitivity,” refers to “sensitivity, as 

measured by indicators of vulnerability to impact.” Hereafter “sensitivity, as measured 

by indicators of vulnerability to impact,” will be indicated by use of the term 

“sensitivity.”

(H)Environmental and Predictive Information

Part IV.B presents an analysis of environmental concerns that references relevant 

information and findings from the Final EIS for the Five Year Program for 2012-2017, 

the most recent lease sale EISs and other NEPA documents, as well as other BOEM 

reports and studies. Part III.A presents selected information and findings from the Five 

Year Final EIS relevant to each PFP area.

Balancing Potential Environmental Damage, Discovery of Oil and Gas, and Adverse 

Impact on the Coastal Zone

Section 18(a)(3) requires the Secretary to render decisions on the timing and location of 

OCS leasing that strike a balance among the potential for environmental damage, the 

potential for discovery of oil and gas, and the adverse impact on the coastal zone. Part 

V.C of the 2009 DPP addressed the balancing requirement by presenting a comparative 

analysis of all 26 planning areas. The PP and this PFP document compare the six areas 

being considered for leasing, which are referred to as “program areas.” 

An important element of the comparative analysis is an estimation of societal net benefits 

for each program area. These are derived by first calculating the value of oil and natural 

gas resources minus the cost to industry and the net environmental and social costs of 

developing those resources. BOEM refers to the results of this analysis as “net social 

value.” Consumer surplus benefits are then added to net social value to produce an 

estimate of net benefits for each program alternative. See the descriptions of the various 
31

types of “value” set out previously in this part. The comparative analysis also ranks the 

program areas according to quantified information relating to environmental sensitivity 

and marine productivity and according to the interest of potential oil and natural gas 

producers. Other section 18(a)(2) factors do not lend themselves as readily to 

quantification and are treated qualitatively. The comparative analysis also examines 

additional qualitative information pertaining to the findings and purposes of the Act, the 

comments and recommendations of interested and affected parties, and other information 

relevant to striking a proper balance under section 18(a)(3).

The Act does not specify what the balance should be or how the factors should be 

weighed to achieve that balance, leaving to the Secretary the discretion to reach a 

reasonable determination under existing circumstances.

Assurance of Fair Market Value 

Section 18(a)(4) requires that leasing activities be conducted “to assure receipt of fair 

market value for the lands leased and the rights conveyed by the Federal Government.” 

Part III.B of this document discusses the different mechanisms BOEM has in place to 

ensure receipt of FMV. 

C. Judicial Guidance

The new Five Year Program will be the eighth prepared by DOI. The first three 

programs prepared and approved under section 18 were challenged in court, in 1980, 

1982, and 1987, as was the current 2007-2012 program. The U.S. Court of Appeals for 

the District of Columbia Circuit decided all of those lawsuits. The new Five Year 

Program is being prepared in accordance with guidance provided in those decisions, 

which are cited below. 

California I [California v. Watt, 688 F.2d 1290 (D.C. Cir. 1981)]; 

California II [California v. Watt, 712 F.2d 584 (D.C. Cir. 1983)]; 

NRDC [Natural Resources Defense Council], et al. v. Hodel, 865 F.2d 288 (D.C. 

Cir. 1988)]; and

CBD [Center for Biological Diversity, et al. v. Department of the Interior, 

563 F.3d 466 (D.C. Cir. 2009)]. 

No lawsuits were filed with respect to the Five Year Programs approved for 1992-1997, 

1997-2002, and 2002-2007.

D. Analytic Approach

The analysis underlying development of the PFP for 2012-2017 considers the size, 

timing, and location of leasing and the provisions for assuring FMV from six program 
32

areas. The 2009 DPP identified program areas for further leasing consideration, 

consisting of all or parts of 12 of the 26 OCS planning areas. See Maps 1 and 2 in part III 

of this document for the OCS planning areas. The PP and this PFP analyses, examines 

and compares six selected areas in light of the criteria of section 18 of the Act. These six 

areas also are analyzed in the EIS for the 2012-2017 Program, prepared pursuant to 

NEPA to assess the effects of the PFP. 

Section 18 factors require balancing by the Secretary. As part of his balancing, the 

Secretary focused on and applied the following guiding principles when according weight 

to section 18 factors and in selecting options for the size, timing, and location of areas 

proposed for leasing in this PFP. 

• Give priority leasing consideration to areas where the combination of previous 

experience; local, state, and national laws and policies; and expressions of 

industry interest indicate that potential leasing and development activities could 

be expected to proceed in an orderly and productive manner.

• For areas with known or anticipated estimated hydrocarbon resources, consider 

leasing if, from a national and regional perspective, anticipated benefits from 

development substantially outweigh estimated environmental risks.

• Use best available data when committing additional acreage to leasing, especially 

where there is insufficient confidence in the ability to avoid or mitigate harm to 

valuable resources and human uses, and enhanced information will allow for 

better decision-making in the next Five Year Program. 

• Seek to accommodate the recommendations of governors of coastal states and of 

state and local agencies.

• Tailor a leasing strategy to specific regions in order to best achieve the dual goals 

of promoting prompt development of the Nation’s oil and natural gas resources 

and ensuring that this development occurs safely and with the necessary 

protections for the marine, coastal and human environments. This region-specific 

approach accounts for such issues as current knowledge of resource potential, 

adequacy of infrastructure including oil spill response capabilities, 

accommodation of regional interest and concerns, and the need for a balanced 

approach to the use of natural resources. 

Development of a new Five Year Program for 2012-2017 is based on analysis of 

information relating to the criteria of section 18 of the Act, which governs preparation 

and maintenance of the Federal offshore oil and natural gas leasing program. The options 

presented in this document have been formulated and selected in light of these principles 

and the factors and elements to be considered and balanced under section 18(a) of the 

Act. Parts III and IV of this document discuss in detail the sources of information and the 

methodologies applied in the PFP analyses. Also, much information is incorporated by 

reference. This information is listed below.
33

Final EIS for the Proposed Program for 2012-2017 (expected July 2012)

Decision Document for the Proposed Program for 2012-2017 (November 2011)

Decision Document for the Revised Program for 2007-2012 (December 2010)

Decision Document for the Draft Proposed Program for 2010-2015 (January 2009) 

Final EIS for the Proposed Final Program for 2007-2012 (April 2007)

Cook Inlet Planning Area Oil and Gas Lease Sales 191 and 199, Final Environmental 

Impact Statement, OCS EIS/EA, MMS 2003-055, Volumes 1-3, 2003

Structure-Removal Operations on the Gulf of Mexico Outer Continental Shelf, 

Programmatic Environmental Assessment, OCS EIS/EA, MMS 2005-013, 2005

Gulf of Mexico Oil and Gas Lease Sales: 2012-2017; Western Planning Area Lease Sales 

229, 233, 238, 246 and 248; Central Planning Area Lease Sales 227, 231, 235, 241, and 

247; Draft Environmental Impact Statement, 2011.

Gulf of Mexico Oil and Gas Lease Sales: 2007-2012; Western Planning Area Sales 204, 

207, 210, 215, and 218; Central Planning Area Sales 205, 206, 208, 213, 216, and 222; 

Final Environmental Impact Statement, MMS 2007-018, 2007

Gulf of Mexico OCS Oil and Gas Lease Sale 216/222; Central Planning Area; Final 

Supplemental Environmental Impact Statement; 2012

Gulf of Mexico OCS Oil and Gas Lease Sale 218; Western Planning Area; Final 

Supplemental Environmental Impact Statement, BOEMRE 2011-034, 2011

Gulf of Mexico OCS Oil and Gas Lease Sales: 2009-2012; Central Planning Area Sales 

208, 213, 216, and 222; Western Planning Area Sales 210, 215, and 218; Final 

Supplemental Environmental Impact Statement, MMS 2008-041, 2008

Gulf of Mexico OCS Oil and Gas Lease Sale 224; Eastern Planning Area; Final 

Supplemental Environmental Impact Statement, MMS 2007-060, 2007

Gulf of Mexico OCS Oil and Gas Lease Sales 189 and 197; Eastern Planning Area; Final 

Environmental Impact Statement, MMS 2003-020, 2003

Accounting for Socioeconomic Change from Offshore Oil and Gas; Cumulative Effects 

on Louisiana’s Parishes; 1969-2000, MMS 2006-030, 2006

Gulf of Mexico OCS Oil and Gas Lease Sale 181; Eastern Planning Area; Final 

Environmental Impact Statement, MMS 2001-051, 2001
34

Site-Specific Environmental Assessment for an FPSO Facility; Site-Specific Evaluation 

of Petrobras America Inc.’s Initial DOCD, N-9015; Cascade-Chinook Project, MMS 

2008-008, 2008

Chukchi Sea Planning Area, Oil and Gas Lease Sale 193 and Seismic Survey Activities 

in the Chukchi Sea, Final Environmental Impact Statement, MMS 2007-026, 2007

Chukchi Sea Planning Area Oil and Gas Lease Sale 193, Final Supplemental 

Environmental Impact Statement, OCS EIS /EA, BOEMRE 2011-041, 2011

Arctic OCS Seismic Surveys- 2006, Programmatic Environmental Impact Statement, 

OCS EIS/EA, MMS 2006-038, 2006

Environmental Assessment—Proposed Oil and Gas Lease Sale 202 Beaufort Sea 

Planning Area, MMS 2006-001, 2006

Alaska Outer Continental Shelf Beaufort Sea Planning Area Oil and Gas Lease Sales 186, 

195, and 202, Final Environmental Impact Statement, OCS EIS/EA, MMS 2003-001, 

2003

Geological and Geophysical Exploration for Mineral Resources on the Gulf of Mexico 

Outer Continental Shelf: Final Programmatic Environmental Assessment, OCS EIS/EA 

MMS 2004-054, 2004 

U.S. Coast Guard Marine Casualty Pollution Investigations, “Oil Spill Compendium 

1973-2004”

EIA Annual Energy Outlook; http://www.eia.doe.gov/oiaf/aeo/index.html

Undiscovered Oil and Gas Resources, Alaska Federal Offshore As of 2006 

Assessment of Undiscovered Technically Recoverable Oil and Gas Resources on the 

Nation’s Outer Continental Shelf, BOEM Fact Sheet RED-2011-01a, 2011

An evaluation of the science needs to inform decisions on Outer Continental Shelf energy 

development in the Chukchi and Beaufort Seas, Alaska. U.S. Geological Survey, 

Circular 1370, 2011

Final Report of the National Commission on the BP Deepwater Horizon Oil Spill and 

Offshore Drilling, 2011

Atlantic OCS Proposed Geological and Geophysical Activities, Mid-Atlantic and South 

Atlantic Planning Areas, Draft Programmatic Environmental Impact Statement, BOEM 

2012-005, 2012
35

III. PROPOSED FINAL PROGRAM OPTIONS

A. Size, Timing, and Location Options

Introduction

This part presents the options from which the Secretary may choose the size, timing, and 

location of leasing activity for 2012-2017. BOEM has formulated these options based on 

its consideration of information relating to the section 18 criteria and based on the results 

of comments and consultation with interested and affected parties. 

The OCS is divided into 26 planning areas, as was addressed in previous proposals. 

NAB, offshore Alaska, is subject to Presidential withdrawal from disposition by leasing 

until after June 30, 2017. Most of the Eastern GOM planning area, including all areas 

east of 86°41’W longitude or located within 125 miles of Florida and a portion of the 

Central GOM planning area within 100 miles of Florida are unavailable for leasing 

consideration until after June 30, 2022, pursuant to GOMESA. These restricted areas are 

not proposed for consideration. 

The 2009 DPP proposed for consideration the NAB (which has since become subject to 

Presidential withdrawal, as discussed above), as well as two areas offshore California and 

three areas in the Atlantic OCS. See the discussion in part I of this document concerning 

those six planning areas, which were not considered for leasing in the PP. Those areas, 

therefore, are not included in this PFP and not analyzed in this document. Under the 

section 18 process, the Secretary winnows the areas for detailed consideration in the PP 

and the PFP. This approach also is consistent with California II, which found that “[i]f 

the Secretary has already determined that no leasing activity will occur in a particular 

area [sic] there is no need to fully evaluate that area.” Maps 1 and 2 show the 26 

planning areas, identifying those areas currently unavailable for leasing. 

The section 18 objectives of formulating a program to “best meet national energy needs” 

and to assure the receipt of FMV for leases and the rights they convey are significant 

determinants of the size, timing, and location options. The analyses of net social benefits 

and the factors specified by section 18(a) (2) provide a sound basis for developing 

options. Those analyses, which are presented in part IV of this document, examine 

economic, social, and environmental values; oil and natural gas resource potential and 

industry interest; distribution of benefits and risks; competing uses of the OCS; regional

energy needs; and the laws, goals, and policies of affected states. By considering that 

information for each area of the OCS available for leasing consideration in the next Five 

Year Program, BOEM is able to weigh different resources, values, and policies in 

formulating reasonable options that can be selected by the Secretary to achieve the 

balance required by section 18(a)(3).
36

To ensure adequate oversight to limit potential environmental damage and adverse 

impacts on the coastal zone, the Secretary decided to continue with his decision in the PP 

to focus on offshore areas that currently have leases and/or exploration, some level of 

support from the adjacent state and local governments, and/or known or anticipated 

hydrocarbon presence. This decision was made for the PP and confirmed in this PFP 

after consideration of the various section 18 factors; such as law, goals, and policies of 

adjacent states, as well as the level of knowledge concerning the potential for recoverable 

oil and gas resources and the environmental and other relevant information needed to 

make informed decisions. 

The removal of the Mid- and South Atlantic planning areas from the scoping process was 

done for a number of reasons. The potential amount and location of oil and natural gas 

resources in the Mid- and South Atlantic planning areas are not known, and the existing 

G&G information is outdated. Modern G&G data, including seismic surveys and other 

scientific information, is needed to evaluate the resource potential in these areas and to 

inform decisions about whether and where any leasing should take place. Accordingly, 

the Secretary is moving forward with an environmental analysis related to potential G&G 

studies to support the evaluation of the oil and natural gas resource potential in these 

areas. This NEPA work will facilitate the studies which potential bidders and the 

government need in order to intelligently engage in lease sale planning. Also relevant to 

the Secretary’s decision not to include the Mid- and South Atlantic planning areas in 

scoping for the Draft EIS and consideration in the Five Year Program was the need to 

resolve conflicts, including those related to national defense. Further, as DOI moves 

forward in these areas with facilitating the evaluation of the resource potential and 

deconflicting potential oil and gas activities from other uses, so too should longer-term 

analysis and planning be completed for the infrastructure and resources that would be 

necessary to prepare for such activity. 

As noted in part I, the 2009 DPP encompassed the 2010-2015 timeframe, while the PP 

and PFP encompass 2012-2017. For that reason, the presentation of the 2009 DPP 

options in this document do not list the sale year, only the total number of sales in the 

2009 DPP for the particular area. The selected comments summarized for each PFP area 

were received during the 90-day comment period on the PP, which closed on February 8, 

2012. In an attempt to be more transparent as to the Secretary’s consideration of 

comments received in making his decision, responses to noteworthy comments also are 

included in this part.
37

Map 1 – Alaska Planning Areas with restrictions
38

Map 2 – Lower 48 State Planning Areas with restrictions
39

Additional Considerations

An important element underlying the determination of the location and size of lease sales 

in a Five Year Program is the configuration of planning areas and program areas for 

leasing consideration. The OCS planning areas initially were established pursuant to the 

Act Amendments of 1978 and have been reconfigured several times over the past 30 

years, most recently to correspond to administrative lines announced in the Federal 

Register in January 2006 and announced in the Draft Proposed Program for 2007-2012 

(February 2006). That portion of the individual planning area that is being considered for 

leasing in a Five Year Program is referred to as the program area. A program area can be 

the entire planning area as in the Cook Inlet offshore Alaska; a small portion as in the 

Eastern GOM; or any size in between. The program also provides for the number and 

timing of sales within and among areas.

The PFP options provide for scheduling lease sales in the Western, Central, and Eastern 

GOM planning areas and the Chukchi Sea, Beaufort Sea, and Cook Inlet planning areas 

offshore Alaska. Each lease sale that is scheduled in the approved Five Year Program for 

2012-2017 will be subject to an established prelease evaluation and decision process in 

which interested and affected parties may participate. That process examines the 

proposed lease sale, starting with the area identified as available for leasing consideration 

in the Five Year Program, and considers reasonable alternative lease sale configurations, 

reductions, and/or restrictions within that area. No sale area may be larger than the Five 

Year Program area. The prelease process leads to the final decision on the terms and 

conditions of each OCS lease sale. Figure 1 provides a schematic rendering of the 

process used for a typical lease sale in any area of the OCS. In some cases, steps may be 

in a different order or even repeated, based on the particular needs of the sale and area. 

Figure 1 is followed by a brief textual description of the process’s multiple steps and 

decision points. 

Figure 1: Lease Sale Process

Call for 

Information

30-day 

comment 

period

Define 

Sale 

Area

Proposed Notice 

of Sale

45-day EIS 

comment 

period

90-day period

60-day 

comment 

period Final 

Notice of 

Sale 

Draft EIS* Final EIS*

Consistency 

Determination(s) Notice of 

Intent to 

Prepare an 

EIS*

30-day 

period

Sale Leases 

Issued 

30-day 

comment 

period 30-day period

Environmental Consultations 
40

• Call for Information and Nominations – Requests comments from the public on 

areas of special concern that should be analyzed. Invites potential bidders to 

nominate areas of interest within program areas identified for leasing 

consideration in the Five Year Program and requests information on 

environmental and other aspects of the program area.

• NOI to Prepare an EIS – Alerts the public that an EIS will be prepared, provides 

description of the proposed action and possible alternatives, and of the scoping 

process including any scheduled meetings for scoping of the NEPA 

document/EIS. Note that sometimes the NOI is published after the Area 

Identification step below.

• Area Identification – Identifies area for proposed action to be analyzed in 

NEPA/EIS document based on information gathered from the Call and the NOI (if 

preceding the Area Identification). Decisions at this step will be made public, 

particularly if there is a change to the area included in the Call and NOI. 

• Draft EIS – Evaluates the potential environmental impacts of proposed action and 

alternatives and the potential effectiveness of mitigating measures.

• Public Review and Comment – Draft EIS is made available for public review for 

at least 45 days.

• Environmental Consultations – Consultations will occur with agencies such as 

USFWS and National Marine Fisheries Service (NMFS). This also includes 

Government-to-Government consultations that are of particular importance in the 

Alaska OCS.

• Final EIS – Incorporates responses to public comments on the Draft EIS and 

presents evaluation of environmental impacts analysis as updated from the Draft 

EIS.

• Consistency Determination – Documents Federal determination on whether the

proposed sale is consistent to the maximum extent practicable with federally 

approved state coastal zone management plan. 

• Proposed Notice of Sale – Provides information to the states and the public on the 

proposed area to be offered and the proposed lease terms and conditions.

• Letters to the Governors – Governors of the affected states are sent copies of the 

Proposed Notice for their review as required under section 19 of the Act.

• Final Notice of Sale – Published a minimum of 30 days before the sale is held. 

Includes date, time and location of the bid opening, blocks offered, and terms and 

conditions of the sale. 
41

• Record of Decision – Records the final decision for the NEPA process regarding 

the selected action, alternatives, environmentally preferable alternatives and 

environmental mitigation, adopted or not. Published a minimum of 30 days 

before the sale is held. 

• Sale – Sealed bids submitted by qualified bidders are opened and read publicly on 

the day of the sale. Bids are checked for technical and legal adequacy to 

determine the high bid that is then subject to further evaluation before a lease may 

be issued.

• Lease Issuance – Follows completion of FMV analysis and review by the 

Department of Justice and Federal Trade Commission.

At the program stage, size, timing, and location options are designed also to mitigate 

drainage to Federal oil and natural gas resources on unleased lands and associated 

revenue losses that could occur as a result of existing or anticipated development activity 

on adjacent state leases. At the lease sale stage, terms and conditions are designed to 

mitigate potential adverse effects of lease activities. Acquisition of new G&G data is 

also a relevant consideration. Finally, the scheduling of lease sales must allow time for 

orderly and deliberate preparation for each sale, including the acquisition and analysis of 

relevant scientific information, and the completion of the prelease and NEPA evaluation 

and decision processes. 

Proposed Final Program Options for Scheduling Lease Sales

This decision document offers options for scheduling lease sales for the six program 

areas. Background information on the history of leasing and related activities in each 

area was included in the 2009 DPP and is not repeated in this document. Summaries of 

the key results of the comparative analysis and the selected comments of interested and 

affected parties with responses to some of the comments as discussed above precede each 

set of lease sale options. The comparative analysis summaries are condensed from part 

IV.C and the comment summaries are adapted from Appendix A. 

A discussion of the individual options follows each set of options. Each leasing option is 

discussed in terms of the anticipated benefits of the proposed leasing and ensuing 

production, as well as the potential environmental impacts that could be expected. As 

explained in part IV.C, the valuation of anticipated production differs from the total net 

benefits analysis in the 2009 DPP. The latter compared the value of all the economically 

recoverable resources available for leasing in each area while the former compares the 

value of only those resources that would reasonably be expected to be discovered and 

produced given the size and timing of the lease sale(s) specified in each option.
42

Relationship of Proposed Final Program Options to the Final EIS 

Alternatives 

The Five Year Final EIS analyzes eight alternatives that correspond to individual lease 

sale options as follows:

• Alternative 1—The Proposed Action (Option 1 for all areas; Option 2 for Eastern 

GOM)

• Alternative 2—Exclude the Eastern GOM from the 2012-2017 program (Option 3)

• Alternative 3—Exclude the Western GOM the 2012-2017 program (Option 2)

• Alternative 4—Exclude the Central GOM from the 2012-2017 program (Option 2)

• Alternative 5—Exclude the Beaufort Sea from the 2012-2017 program (Option 2)

• Alternative 6—Exclude the Chukchi Sea from the 2012-2017 program (Option 2)

• Alternative 7—Exclude the Cook lnlet from the 2012-2017 program (Option 2)

• Alternative 8—No Action (Option 3 for Eastern GOM; Option 2 for all other program 

areas)

GULF OF MEXICO REGION

Draft Proposed Program Decision

The 2009 DPP proposed annual areawide lease sales in the Western and Central GOM 

and three sales in the Eastern GOM, offering all available blocks not covered by leasing 

restrictions and including a 75-mile no-permanent surface structures buffer for a portion 

of the Eastern GOM planning area

22.

Proposed Program Decision

The PP proposed annual areawide lease sales in the Western and Central GOM and two 

sales in the Eastern GOM of all available, unleased acreage in all three areas. The 

majority of the Eastern GOM and a small portion of the Central GOM are unavailable for 

leasing consideration until mid-2022 pursuant to GOMESA.

 22 Much of the 2009 DPP area in the Eastern GOM was and is under leasing restriction pursuant to 

GOMESA. A restricted area may be included on a five year schedule but may not be offered for further 

leasing consideration as long as the restriction remains in effect. The PP and this PFP do not include any 

area in the Eastern or Central GOM that is currently under leasing restriction.
43

Proposed Final Program Options

Western Gulf of Mexico

Key Comparative Results. The net benefits of anticipated production in this PFP area 

are estimated at about $16.81 billion in the low-price case, $49.57 billion in the mid-price 

case, and $82.37 billion in the high-price case. This area ranks as “More Sensitive to 

Impact” as a component of environmental sensitivity, and 4th of 6 for marine 

productivity. 

Selected Comments. The Louisiana Department of Natural Resources (LADNR) 

supports OCS leasing, but thinks that more areas should be considered for leasing than 

the GOM and offshore Alaska. LADNR strongly urges expanded revenue sharing, not 

just for new leasing in the GOM, but also to take into account historical impacts, and not 

just for GOM but also other areas of the OCS. DOE and DOD support the OCS program. 

Several environmental public interest groups opposed any OCS drilling, particularly in 

deep water. Others requested that no sales be held until at least 2014 to allow time for 

BOEM to reconsider its analysis and that there be no drilling until post-Deepwater 

Horizon recommendations have been met. Five companies in the oil and gas industry 

supported the PP which included this area.

Responses. The PFP focuses on areas where there are currently active leases, 

exploration, and/or known or anticipated hydrocarbon potential, like the GOM and 

offshore Alaska. This strategy makes available for development more than 75 percent of 

undiscovered technically recoverable oil and gas resources estimated on the OCS. This is 

part of the Administration’s plan to reduce dependence on imports by a third by 2025. 

While the Secretary appreciates the benefits that could be realized by more expansive 

sharing of OCS revenues, the authority and formulas for such must be provided in 

legislation by Congress. Additionally, DOI has made significant progress in accelerating 

reforms that have improved the safety and environmental protection of the OCS since the 

Deepwater Horizon event, improving both the safety of offshore drilling to reduce the 

risk of another loss of well control in the oceans, and the collective ability to respond to a 

blowout and spill. 

(1) Five areawide sales starting in 2012 of all legally available, unleased acreage in 

the area depicted in Map 3

(2) No sale

Discussion

Option 1 (5 Sales)

Valuation. The net benefits of anticipated production in this PFP area are estimated 

at$16.81 billion in the low-price case, $49.57 billion in the mid-price case, and $82.37

billion in the high-price case. 
44

Environmental Impacts. This option is analyzed in the Final EIS under Alternative 1. 

A summary of the Final EIS findings follows. 

Water Quality—Routine operations that could result in minor to moderate, localized, 

short-term impacts include structure placement and construction (pipelines, platforms) 

and operational discharges (produced water, bilge water, and drill cuttings) and sanitary 

and domestic wastes. Structure placement and removal could increase suspended 

sediment loads, while operational discharges, sanitary and domestic wastes, and deck 

drainage could affect chemical water quality. Compliance with National Pollutant 

Discharge Elimination System (NPDES) permits and U.S. Coast Guard (USCG)

regulations would reduce most impacts of routine operations. The effects of accidental 

oil spills will depend upon material, spill size, location, and remediation activities. Small 

spills would likely result in short-term, localized impacts. Impacts from a large oil spill, 

including those from a very large spill associated with an unlikely Catastrophic Discharge 

Event (CDE), defined as a discharge of a volume of oil into the environment that could 

result in catastrophic effects, could persist for an extended period of time if oil were 

deposited in wetland and beach sediments or low-energy environments because of 

potential remobilization.

Air Quality—Routine operations are expected to result in only minor impacts to air 

quality. Sources of air pollutants such as nitrogen dioxide (NO2), sulfur dioxide (SO2), 

particulate matter of up to 10 micrometers (PM10), and carbon dioxide (CO2),associated 

with OCS oil and gas development include diesel and gas engines, turbines, and support 

vessels. Routine operations would not result in exceeding the National Ambient Air 

Quality Standards (NAAQS) or impact visibility. Increases of ozone, if they occur, 

would be less than 1 percent of total concentrations. Small accidental oil spills could 

have localized and temporary impacts. Pollutant levels from very large spills, including 

accidental spills associated with an unlikely CDE, and associated in situ burning if used, 

would generally be small. Plumes from in situ burning could temporarily degrade 

visibility in Prevention of Significant Deterioration (PSD) Class I areas.

Acoustic Environment—Routine operations could affect ambient noise conditions, and 

impacts to ambient noise levels are expected to be minor to moderate. Noise generating 

sources associated with routine operations include seismic surveys, drilling and 

production, infrastructure placement and removal, and vessel traffic. Depending on the 

source and activity, changes in ambient noise levels could be short-term and localized 

(e.g., from vessel traffic), long-term and localized (from production), or short-term and 

less localized (from seismic surveys). Seismic surveys could result in short-term changes 

in ambient noise levels, but the changes could extend well beyond the survey boundary.

Coastal and Estuarine Habitats—Routine operations would result in minor to moderate 

localized impacts primarily due to facility construction, pipeline trenching and landfalls, 

channel dredging, and vessel traffic. The effects of accidental oil spills will depend on 

the specific habitat affected; the size, location, duration, and timing of the spill; and on 

the effectiveness of spill containment and cleanup activities. Small spills would likely 
45

result in short-term impacts while large spills, including a CDE-level spill, could cause 

both short-term and long-term impacts depending on habitat type and location and 

effectiveness of spill containment and cleanup activities.

Marine Habitats—Routine operations could result in moderate short and long-term 

impacts to benthic and pelagic habitats. Benthic habitat could be disturbed by platform 

and pipeline placement, dredging, and operational discharges, including produced water 

and cuttings. Soft sediment habitats can recover within a few years from most 

disturbances. Existing mitigation measures should eliminate most direct impacts to 

sensitive and protected benthic habitats. Marine benthic habitat could be affected by a 

large oil spill, including a CDE-level spill. Impacts could be long-term and range from 

small to medium, depending on the habitat affected; the size, duration, timing, and 

location of the spill; and the effectiveness of spill containment and cleanup activities. 

Impacts to high density deepwater communities from routine operations and accidental 

spills are unlikely, but may be permanent if they do occur. Major impacts to coral reef 

habitats could occur if the Flower Gardens Banks are heavily oiled and high mortality 

occurs.

Essential Fish Habitat—Routine operations could result in no more than moderate, shortand long-term impacts to essential fish habitat (EFH) and managed species. Existing 

mitigation measures should eliminate most direct impacts to coral EFH. Impacts from 

accidental oil spills, including a CDE-level spill, could be long-term, depending on the 

size, duration, timing, and location of the spill; the habitats affected; and the effectiveness 

of spill containment and cleanup activities. 

Marine Mammals—Impacts to marine mammals from routine operations include noise 

disturbance from seismic surveys, vessels, helicopters, construction and operation of 

platforms, and removal of platforms with explosives; potential collision with vessels; and 

exposures to discharges and wastes. Impacts to cetaceans could range from negligible to 

moderate, with species or stocks inhabiting continental shelf or shelf slope waters most 

likely to be affected. The West Indian manatee and rare or extralimital whale species, 

i.e., those from outside the area, are not likely to be affected. A large accidental oil spill, 

including a CDE-level spill, would have minor to moderate impacts to marine mammals. 

Impacts from spill response activities are expected to be minor. 

Terrestrial Mammals—In the Western GOM, there are no endangered terrestrial 

mammals that would be impacted by the proposed action.

Marine and Coastal Birds—Routine operations may result in negligible to moderate 

localized short-term impacts associated primarily with infrastructure construction, and 

ship and helicopter traffic. Impacts of routine operations to important coastal habitats 

such as nesting areas and overwintering sites could result in greater, more long-term 

impacts should normal breeding and nesting activities be disrupted. Small accidental oil 

spills are expected to have largely local, small effects. Large spills, including a CDElevel spill, may result in long-term and possibly population-level effects. The magnitude 
46

of the effects will depend on the size, duration, and timing of the spill; the species and 

habitats affected; and the effectiveness of spill containment and cleanup activities.

Fish Resources—Negligible to minor impacts to fish, and negligible impacts to 

threatened or endangered fish species are expected from routine operations. A large 

accidental oil spill, including a CDE-level spill, is not likely to result in population-level 

impacts except potentially for spills that significantly affect overfished species and their 

spawning grounds. Oil contacting shoreline areas could result in large-scale lethal and 

long-term sublethal effects on early life stages of some species, but no permanent 

population-level effects are expected.

Reptiles—Routine operations would result in minor to moderate localized impacts to 

marine turtles primarily from seismic exploration, facility construction, pipeline landfalls, 

channel dredging, and vessel traffic. Accidental oil spills could result in large impacts 

depending on the size, location, duration and timing of the spill, and on the effectiveness 

of spill containment and cleanup activities. Small spills would likely result in short-term 

impacts while large spills, including a CDE-level spill, could incur both short-term and 

potentially long-term population-level impacts depending on the species and habitat type 

affected, and on the size and duration of the spill.

Invertebrates and Lower Trophic Levels—Routine operations could result in negligible 

to moderate impacts to primarily benthic invertebrates, primarily from habitat disturbance 

associated with infrastructure placement, and from routine discharges. Recovery could 

be short-term to long-term. Large accidental oil spills, including a CDE-level spill, could 

measurably depress invertebrate populations especially in intertidal areas, but no 

permanent impacts are expected.

Areas of Special Concern—Impacts resulting from routine activities are expected to be 

negligible to moderate because of existing protections and use restrictions. Large 

accidental oil spills, including a CDE-level spill reaching such areas, could negatively 

affect fauna and habitats, individuals fishing for food, commercial or recreational 

fisheries, recreation and tourism, and other uses of these areas. 

Population, Employment and Income—Direct expenditures associated with routine 

operations would result in negligible impacts from small increases in population, 

employment and income in the region over the duration of the leasing period, 

corresponding to less than 1 percent of the baseline. Given existing levels of leasing 

activity, impacts on property values would be negligible. In areas where tourism and 

recreation provide significant employment, accidental oil spills, including a CDE-level 

spill, could result in the short-term loss of employment, income and property values. 

Expenditures associated with spill cleanup activities would create short-term employment 

and income in some parts of the affected coastal region(s).

Land Use and Existing Infrastructure—Negligible to minor impacts on land use, 

development patterns, and infrastructure could result from routine operations. Existing 

infrastructure generally would be sufficient to handle exploration and development 
47

associated with potential new leases. Projected impacts from an accidental oil spill, 

including a CDE-level spill, would likely include stresses of the spill response on existing 

infrastructure, and restrictions of access to a particular area while the cleanup is being 

conducted. Impacts would be expected to be temporary and localized.

Fisheries—Routine operations would have a minor impact on individuals fishing for 

food, the cost of commercial fishing, or on the number of recreational fishing trips, in the 

region over the duration of the leasing period. Large accidental oil spills, including a

CDE-level spill, may have small to medium, short-term impacts on fisheries resources, 

including lethal and sublethal toxic effects on exposed eggs, larvae, juveniles, and adults, 

and small to medium impacts on commercial trawling and recreational charter fishery 

activities and individuals fishing for food. The magnitude and duration of effects will 

depend on the location, size, duration, and timing of the spill; the fisheries affected; and 

the duration and effectiveness of spill containment and cleanup activities.

Recreation and Tourism—Routine operations would produce minor impacts to beach 

recreation, sightseeing, boating, and fishing, while offshore structures would create 

positive impacts to diving and recreational fishing. The impact of an accidental oil spill, 

including a CDE-level spill, on tourism and recreation will depend on the size, location, 

duration, and timing of the spill, as well as on the effectiveness and timeliness of spill 

containment and cleanup activities.

Sociocultural Systems and Environmental Justice—Because of the well developed and 

long established oil and gas industry in the GOM, routine operations are expected to have 

minor impacts on sociocultural systems. Expansion of deepwater development could 

lead to longer offshore work shifts, which could increase stress to workers, families and 

communities. Impacts from accidental oil spills would be small, except in the case of 

very large spills. Very large spills, including a CDE-level spill, may temporarily halt and 

impact economies associated with the oil and gas industry, but also other sectors of the 

economy. Depending on the duration of such halts and the magnitude of economic 

impacts, this could result in social and cultural stress, leading to possible social 

pathologies. Because of the non-coastal location of the majority of low income and 

minority population groups, routine operations are not expected to add additional 

environmental justice concerns and impacts would be negligible. Impacts of accidental 

oil spills, including a CDE-level spill which is not expected, would be minimal.

Archaeological Resources—Impacts could range from negligible to major depending on 

the presence of significant archaeological or historic resources in the area of potential 

effect. Archaeological and historic resources (especially offshore resources), may be 

affected by platform and pipeline construction and by dredging, which could damage or 

destroy affected resources. Onshore impacts (resource damage or loss; visual impacts) 

are possible from pipeline landfall, onshore pipeline, and road construction. Anchor 

drags could affect seafloor resources such as shipwrecks. Most resources are expected to 

be avoided.
48

Map 3 – Western Gulf of Mexico Program Area
49

Option 2 (No Sale)

Valuation. The net benefits of production would be zero since no activity would occur. 

However, foregoing the production anticipated to result from any sales in the Western 

GOM would result in environmental and social costs incurred to obtain the energy 

substitutes, including additional imports of oil and increased onshore production of oil 

and natural gas, among others. 

Environmental Impacts. This option is analyzed in the Final EIS under Alternatives 3 

and 8. A summary of the Final EIS findings follows.

Under this option the potential direct effects of routine operations in the Western GOM 

that are described under the analysis of the proposed action would not occur. No oil 

spills would originate within the Western GOM from new leasing, although marine and 

coastal resources there would be exposed to effects from spills that might originate from 

existing leases and from elsewhere, including the Central GOM. Energy substitutions for 

the foregone hydrocarbon production in the Western GOM would be small to moderate 

and would be accounted for largely by increased import tankering, a considerable 

proportion of which is expected to be destined for terminals in the Western GOM. This 

option would create a discontinuity in the regular occurrence of lease sales in the Western 

GOM that could result in reduced local employment and labor income, as well as 

potential outmigration and reductions in community services. 

Central Gulf of Mexico

Key Comparative Results. The net benefits of anticipated production in the PFP area 

are estimated at about $62.48 billion in the low-price case, $200.16 billion in the midprice case, and $344.60 billion in the high-price case. This area ranks as “Most Sensitive

to Impact” as a component of environmental sensitivity and 3rd of 6 for marine 

productivity. 

Selected Comments. LADNR supports OCS leasing, but thinks that more areas should 

be considered for leasing than the GOM and offshore Alaska. LADNR strongly urges 

expanded revenue sharing, not just for new leasing in the GOM, but should take into 

account historical impacts, and not just for GOM but also other areas of the OCS. The 

Florida Department of Environmental Protection (DEP) was concerned about effects 

from oil and natural gas activities from all of the GOM, not just the Eastern GOM. DOE 

and DOD support the OCS program. Several environmental public interest groups 

opposed any OCS drilling, particularly in deep water. Others requested that no sales be 

held until at least 2014 to allow time for BOEM to reconsider its analysis and that there 

be no drilling until post-Deepwater Horizon recommendations have been met. Five 

companies in the oil and gas industry supported the PP which included this area.

Responses. The PFP focuses on areas where there are currently active leases, 

exploration, and/or known or anticipated hydrocarbon potential, like the GOM and 

offshore Alaska. This strategy makes available for development more than 75 percent of 
50

undiscovered technically recoverable oil and gas resources estimated on the OCS. This is 

part of the Administration’s plan to reduce dependence on imports by a third by 2025. 

While the Secretary appreciates the benefits that could be realized by more expansive 

sharing of OCS revenues, the authority and formulas for such must be provided in 

legislation by Congress. Additionally, DOI has made significant progress in accelerating 

reforms that have improved the safety and environmental protection of the OCS since the 

Deepwater Horizon event, improving both the safety of offshore drilling to reduce the 

risk of another loss of well control in the oceans, and the collective ability to respond to a 

blowout and spill. 

(1) Five areawide sales starting in 2013 of all legally available, unleased acreage in 

the area depicted in Map 4.

(2) No sale

Discussion

Option 1 (5 Sales)

Valuation. The net benefits of anticipated production from the PFP area are estimated at 

about $62.48 billion in the low-price case, $200.16 billion in the mid-price case, and 

$344.60 billion in the high-price case

Environmental Impacts. This option is analyzed in the Five Year Final EIS under 

Alternative 1. A summary of the Five Year Final EIS findings follows. 

Water Quality—Routine operations that could result in minor to moderate, localized, 

short-term impacts include structure placement and construction (pipelines, platforms) 

and operational discharges (produced water, bilge water, and drill cuttings) and sanitary 

and domestic wastes. Structure placement and removal could increase suspended 

sediment loads, while operational discharges, sanitary and domestic wastes, and deck 

drainage could affect chemical water quality. Compliance with NPDES permits and 

USCG regulations would reduce most impacts of routine operations. The effects of 

accidental oil spills will depend upon material, spill size, location, and remediation 

activities. Small spills would likely result in short-term, localized impacts. Impacts from 

a large oil spill, including those from a very large spill associated with an unlikely CDE, 

defined as a discharge of a volume of oil into the environment that could result in 

catastrophic effects, could persist for an extended period of time if oil were deposited in 

wetland and beach sediments or low-energy environments because of potential 

remobilization.

Air Quality—Routine operations are expected to result in only minor impacts to air

quality. Sources of air pollutants (NO2, SO2, PM10, and CO2) associated with OCS oil 

and gas development include diesel and gas engines, turbines, and support vessels. 

Routine operations would not result in exceeding the NAAQS or impact visibility. 

Increases of ozone, if they occur, would be less than 1 percent of total concentrations. 
51

Small accidental oil spills could have localized and temporary impacts. Pollutant levels 

from very large spills, including accidental spills associated with an unlikely CDE, and 

associated in situ burning if used, would generally be small. Plumes from in situ burning 

could temporarily degrade visibility in PSD Class I areas.

Acoustic Environment—Routine operations could affect ambient noise conditions, and 

impacts to ambient noise levels are expected to be minor to moderate. Noise generating 

sources associated with routine operations include seismic surveys, drilling and 

production, infrastructure placement and removal, and vessel traffic. Depending on the 

source and activity, changes in ambient noise levels could be short-term and localized 

(e.g., from vessel traffic), long-term and localized (from production), or short-term and 

less localized (from seismic surveys). Seismic surveys could result in short-term changes

in ambient noise levels, but the changes could extend well beyond the survey boundary.

Coastal and Estuarine Habitats—Routine operations would result in minor to moderate 

localized impacts primarily due to facility construction, pipeline trenching and landfalls, 

channel dredging, and vessel traffic. The effects of accidental oil spills will depend on 

the specific habitat affected; the size, location, duration, and timing of the spill; and on 

the effectiveness of spill containment and cleanup activities. Small spills would likely 

result in short-term impacts while large spills, including a CDE-level spill, could incur 

both short-term and long-term impacts depending on habitat type and location and 

effectiveness of spill containment and cleanup activities.

Marine Habitats—Routine operations could result in moderate short and long-term 

impacts to benthic and pelagic habitats. Benthic habitat could be disturbed by platform 

and pipeline placement, dredging, and operational discharges (produced water and 

cuttings). Soft sediment habitats can recover within a few years from most disturbances. 

Existing mitigation measures should eliminate most direct impacts to sensitive and 

protected benthic habitats. Marine benthic habitat could be affected by a large oil spill, 

including a CDE-level spill. Impacts could be long-term and range from small to 

medium, depending on the habitat affected; the size, duration, timing, and location of the 

spill; and the effectiveness of spill containment and cleanup activities. Impacts to high 

density deepwater communities from routine operations and accidental spills are unlikely, 

but may be permanent if they do occur. Major impacts to coral reef habitats could occur 

if the Flower Gardens Banks are heavily oiled and high mortality occurs.

Essential Fish Habitat—Routine operations could result in no more than moderate, shortand long-term impacts to EFH and managed species. Existing mitigation measures 

should eliminate most direct impacts to coral EFH. Impacts from accidental oil spills, 

including a CDE-level spill, could be long-term, depending on the size, duration, timing, 

and location of the spill; the habitats affected; and the effectiveness of spill containment 

and cleanup activities. 

Marine Mammals—Impacts to marine mammals from routine operations include noise 

disturbance from seismic surveys, vessels, helicopters, construction and operation of 

platforms, and removal of platforms with explosives; potential collision with vessels; and 
52

exposures to discharges and wastes. Impacts to cetaceans could range from negligible to 

moderate, with species or stocks inhabiting continental shelf or shelf slope waters most 

likely to be affected. The West Indian manatee and rare or extralimital whale species, i.e. 

those from outside the area, are not likely to be affected. Meeting the requirements of the 

Endangered Species Act (ESA) and the Marine Mammal Protection Act (MMPA) would 

reduce the likelihood and magnitude of adverse impacts from routine operations to most 

species. A large accidental oil spill, including a CDE-level spill, would have minor to 

moderate impacts to marine mammals; impacts from spill response activities are expected 

to be minor. 

Terrestrial Mammals—The four federally endangered GOM coast beach mice species 

and the federally endangered Florida salt marsh vole and their habitats would not be 

significantly affected by normal operations under the proposed action. Impacts are 

expected to be minimized through appropriate mitigation and the existence of these 

species’ habitats in protected areas. While the habitat of the Florida salt marsh vole could 

be affected by an oil spill, this species and its habitat are located far from areas where oil 

leasing and development may occur under the proposed action. Because of their 

locations on inner dunes, the habitats of the beach mice are unlikely to be affected by an 

accidental offshore oil spill, but the occurrence of a CDE would increase the threat of 

extinction to these species. 

Marine and Coastal Birds—Routine operations may result in negligible to moderate 

localized short-term impacts associated primarily with infrastructure construction, and 

ship and helicopter traffic. Impacts of routine operations on important coastal habitats 

such as nesting areas and overwintering sites could result in greater, more long-term 

impacts should normal breeding and nesting activities be disrupted. Small accidental oil 

spills are expected to have largely local, small effects. Large spills, including a CDElevel spill, may result in large, long-term, and possibly population-level effects. The 

magnitude of the effects will depend on the size, duration, and timing of the spill; the 

species and habitats affected; and the effectiveness of spill containment and cleanup 

activities.

Fish Resources—Negligible to minor impacts to fish and negligible impacts to 

threatened or endangered fish species are expected from routine operations. A large 

accidental oil spill, including a CDE-level spill, is not likely to result in population-level 

impacts except potentially for spills that significantly affect overfished species and their 

spawning grounds. Oil contacting shoreline areas could result in large-scale lethal and 

long-term sublethal effects on early life stages of some species, but no permanent

population-level effects are expected.

Reptiles—Routine operations would result in minor to moderate localized impacts to 

marine turtles primarily due to seismic exploration, facility construction, pipeline 

landfalls, channel dredging, and vessel traffic. Accidental oil spills could result in large 

impacts depending on the size, location, duration and timing of the spill, and on the 

effectiveness of spill containment and cleanup activities. Small spills would likely result 

in short-term impacts while large spills, including a CDE-level spill, potentially could 
53

incur both short-term and long-term population-level impacts depending on the species 

and habitat type affected, and on the size and duration of the spill.

Invertebrates and Lower Trophic Levels—Routine operations could result in negligible 

to moderate impacts to primarily benthic invertebrates, primarily from habitat disturbance 

associated with infrastructure placement and from routine discharges. Recovery could be 

short term to long term. Large accidental oil spills, including a CDE-level spill, could 

measurably depress invertebrate populations especially in intertidal areas, but no 

permanent impacts are expected.

Areas of Special Concern—Impacts resulting from routine activities are expected to be 

negligible to moderate because of existing protections and use restrictions. Large 

accidental oil spills, including a CDE-level spill reaching such areas, could negatively 

affect fauna and habitats, individuals fishing for food, commercial or recreational 

fisheries, recreation and tourism, and other uses of these areas.

Population, Employment and Income—Direct expenditures associated with routine 

operations would result in negligible impacts from small increases in population, 

employment and income in the region over the duration of the leasing period, 

corresponding to less than 1 percent of the baseline. Given existing levels of leasing 

activity, impacts on property values would be negligible. In areas where tourism and 

recreation provide significant employment, accidental oil spills, including a CDE-level 

spill, could result in the short-term loss of employment, income and property values. 

Expenditures associated with spill cleanup activities would create short-term employment 

and income in some parts of the affected coastal region(s).

Land Use and Existing Infrastructure—Negligible to minor impacts on land use, 

development patterns, and infrastructure could result from routine operations. Existing 

infrastructure generally would be sufficient to handle exploration and development 

associated with potential new leases. Projected impacts from an accidental oil spill, 

including a CDE-level spill, would likely include stresses of the spill response on existing 

infrastructure, and restrictions of access to a particular area while the cleanup is being 

conducted. Impacts would be expected to be temporary and localized.

Fisheries—Routine operations would have a minor impact on individuals fishing for 

food, the cost of commercial fishing, or on the number of recreational fishing trips, in the 

region over the duration of the leasing period. Large accidental oil spills, including a

CDE-level spill, may have small to medium, short-term impacts on fisheries resources, 

including lethal and sublethal toxic effects on exposed eggs, larvae, juveniles, and adults, 

and small to medium impacts on commercial trawling and recreational charter fishery 

activities and individuals fishing for food. The magnitude and duration of effects will 

depend on the location, size, duration, and timing of the spill; the fisheries affected; and 

the duration and effectiveness of spill containment and cleanup activities.

Recreation and Tourism—Routine operations would produce minor impacts to beach 

recreation, sightseeing, boating, and fishing, while offshore structures would create 
54

positive impacts to diving and recreational fishing. The impact of an accidental oil spill, 

including a CDE-level spill, on tourism and recreation will depend on the size, location, 

duration, and timing of the spill, as well as on the effectiveness and timeliness of spill 

containment and cleanup activities.

Sociocultural Systems and Environmental Justice—Because of the well developed and 

long established oil and gas industry in the GOM, routine operations are expected to have 

minor impacts on sociocultural systems. Expansion of deepwater development could 

lead to longer offshore work shifts, which could increase stress to workers, families and 

communities. Impacts from accidental oil spills would be small, except in the case of 

very large spills. Very large spills, including a CDE-level spill, may temporarily halt and 

impact economies associated with the oil and gas industry, but also other sectors of the 

economy. Depending on the duration of such halts and the magnitude of economic 

impacts, this could result in social and cultural stress, leading to possible social 

pathologies. Because of the non-coastal location of the majority of low income and 

minority population groups, routine operations are not expected to add additional 

environmental justice concerns and impacts would be negligible. Impacts of accidental 

oil spills, including a CDE-level spill, would be minimal.

Archaeological Resources—Impacts could range from negligible to major depending on 

the presence of significant archaeological or historic resources in the area of potential 

effect. Archaeological and historic resources (especially offshore resources), may be 

affected by platform and pipeline construction and by dredging, which could damage or 

destroy affected resources. Onshore impacts (resource damage or loss; visual impacts) 

are possible from pipeline landfall, onshore pipeline, and road construction. Anchor 

drags could affect seafloor resources such as shipwrecks. Most resources are expected to 

be avoided.

 
55

Map 4 – Central Gulf of Mexico Program Area
56

Option 2 (No Sale)

Valuation. The net benefits of production would be zero since no activity would occur. 

However, foregoing the production anticipated to result from a sale(s) in the Central 

GOM would result in environmental and social costs incurred to obtain the energy 

substitutes, including additional imports of oil and increased onshore production of oil 

and natural gas, among others. 

Environmental Impacts. This option is analyzed in the Five Year Final EIS under 

Alternatives 4 and 8. A summary of the Five Year Final EIS findings follows.

Under this option the potential direct effects of routine operations in the Central GOM 

that are described under the analysis of the proposed action would not occur. No oil 

spills would originate within the Central GOM from new leasing, although marine and 

coastal resources there would be exposed to effects from spills that originated from 

existing leases in the Central GOM or from elsewhere including the Western and Eastern 

GOM. Energy substitutions for the foregone hydrocarbon production in the Central 

GOM would be moderate and would be accounted for largely by increased import 

tankering, a considerable proportion of which is expected to be destined for terminals 

requiring transit through the Central GOM. This option would create a discontinuity in 

the regular occurrence of lease sales in the Central GOM that would result in reduced 

local employment and labor income, as well as potential outmigration and reductions in 

community services. 

Eastern Gulf of Mexico

Key Comparative Results. Given current information, no production is expected from 

the Eastern GOM program area in the low-price case.23 After exploration, however, this 

assessment may change. Therefore, the net benefits of anticipated production in this PFP 

area are estimated at about $2.73 billion in the mid-price case and $5.99 billion in the 

high-price case. The area ranks “Most Sensitive to Impact” as a component of 

environmental sensitivity and 2nd of 6 for marine productivity. 

Selected Comments The Florida DEP was concerned about effects from oil and natural 

gas activities from all of the GOM, not just the Eastern Gulf. DEP requested 

consideration be given to long-term protection of the state’s coastal and marine resources. 

DOE and DOD support the OCS program. However, DOD referred to its concerns 

expressed in April 2010, about areas of the Eastern Gulf and requested early coordination 

on any sales in those areas due to ongoing military testing and training. Several 

environmental public interest groups opposed any OCS drilling, particularly in deep 

 23 If exploration occurs, whether on nearby blocks leased previously or on blocks leased under this 

program, the results could change the ultimate net benefits at any price level. However, exploration 

without eventual production would create negative net benefits (costs only).
57

water and/or in the Eastern Gulf, due to the high risk and low net benefit. Five

companies in the oil and gas industry supported the PP which included this area.

Responses. The relatively small area considered for leasing in the Eastern Gulf is that 

area that is available pursuant to GOMESA, more than 125 miles off the Florida coast 

and west of 86°41’W longitude. DOD and DOI have a long history of successfully 

coordinating dual use of areas of the Eastern Gulf under the 1983 Memorandum of 

Agreement, with early and continuing coordination being the linchpin. DOI has made 

significant progress in accelerating reforms that have improved the safety and 

environmental protection of the OCS since the Deepwater Horizon event, improving both 

the safety of offshore drilling to reduce the risk of another loss of well control in the 

oceans, and the collective ability to respond to a blowout and spill. 

(1) Two sales in 2014 and 2016 in the program area depicted on Map 5.

(2) One sale in 2014 in the program area depicted on Map 5.

(3) No sale

Discussion

Option 1 (2 Sales)

Valuation. Given current information, no production is expected from the Eastern GOM 

program area at the low-price case; therefore net benefits are assumed to be zero. If 

exploration occurs, net benefits could be either negative if no production results, or 

positive if successful exploration leads to production. The net benefits of anticipated 

production from two sales in this PFP area are estimated at about $2.73 billion in the 

mid-price case and $5.99 billion in the high-price case.24

Environmental Impacts. This option is analyzed in the Five Year Final EIS under 

Alternative 1. A summary of the Five Year Final EIS findings follows.

Water Quality—Routine operations are likely to result in small, localized, short-term 

impacts as a result of structure placement and construction (pipelines, platforms) and 

operational discharges (produced water, bilge water, and drill cuttings) and sanitary and 

domestic wastes. Structure placement and removal could increase suspended sediment 

loads, while operational discharges, sanitary and domestic wastes, and deck drainage 

could affect chemical water quality. Compliance with NPDES permits and USCG 

regulations would reduce most impacts of routine operations. The effects of accidental 

oil spills will depend upon material, spill size, location, and remediation activities. Small 

spills would likely result in short-term, localized impacts. Impacts from a large oil spill 

(including those from a very large spill associated with an unlikely CDE, defined as a 

 24 Current information indicates no difference in anticipated production for the Eastern GOM, whether from 

one sale or two sales. However, having two sales on the schedule would allow the Secretary the flexibility 

to adapt to the information available at the time of lease sale decisions. 
58

discharge of a volume of oil into the environment that could result in catastrophic 

effects), could persist for an extended period of time if oil were deposited in wetland and 

beach sediments or low-energy environments because of potential remobilization. 

Air Quality—Routine operations are expected to result in only minor impacts to air 

quality. Sources of air pollutants (NO2, SO2, PM10, and CO2) associated with OCS oil 

and gas development include diesel and gas engines, turbines, and support vessels. 

Routine operations would not result in exceeding the NAAQS or impact visibility. Small 

accidental oil spills could have localized and temporary impacts on marine air quality. 

Pollutant levels from very large spills, including accidental spills associated with an 

unlikely CDE, and associated in situ burning if used, would generally be small. Plumes 

from in situ burning could temporarily degrade visibility in PSD Class I areas.

Acoustic Environment—Routine operations could affect ambient noise conditions, and 

impacts to ambient noise levels are expected to be very small. The small area of the 

Eastern GOM available for leasing would result in the noise generating sources 

associated with routine operations include seismic surveys, drilling and production, 

infrastructure placement and removal, and vessel traffic to be localized and not 

widespread. 

Coastal and Estuarine Habitats—Since all available leases are located 100 or more miles 

offshore from the Florida coast, and all onshore facilities to service the OCS operations 

will be located in ports along the Central GOM coast, routine operations are not expected 

to affect the coastal habitats of the Eastern GOM. The effects of accidental oil spills 

would likely be confined to marine habitats except for large spills, including a CDE-level 

spill that could incur both short-term and long-term impacts depending on habitat type 

and location and effectiveness of spill containment and cleanup activities.

Marine Habitats—Routine operations could result in minor short- and long-term impacts 

to benthic and pelagic habitats. Benthic habitat could be disturbed by platform and 

pipeline placement, dredging, and operational discharges (produced water and cuttings). 

Existing mitigation measures should eliminate most direct impacts to sensitive and 

protected benthic habitats. Marine benthic habitat could be affected by a large oil spill, 

including a CDE-level spill. Impacts could be long-term and range from small to 

medium, depending on the habitat affected; the size, duration, timing, and location of the 

spill; and the effectiveness of spill containment and cleanup activities. 

Essential Fish Habitat —Routine operations would result in minor, short- and long-term 

impacts to EFH and managed species. Existing mitigation measures should eliminate 

most direct impacts to coral EFH should it occur. Impacts from accidental oil spills, 

including a CDE-level spill, could be long-term, depending on the size, duration, timing, 

and location of the spill; the habitats affected; and the effectiveness of spill containment 

and cleanup activities. 

Marine Mammals—Impacts to marine mammals from routine operations include noise 

disturbance from seismic surveys, vessels, helicopters, construction and operation of 
59

platforms, and removal of platforms with explosives; potential collision with vessels; and 

exposures to discharges and wastes. Because of the small area of the Eastern GOM 

available for leasing, impacts to cetaceans would be small and would affect only a small 

area. The West Indian manatee and rare or extralimital whale species, i.e. those from

outside the area, are not likely to be affected. A large accidental oil spill, including a 

CDE-level spill, would have minor to moderate impacts to marine mammals. Impacts 

from spill response activities are expected to be minor. 

Terrestrial Mammals—No endangered terrestrial mammals of the Eastern GOM would 

be impacted by routine activities or small to large oil spills under the proposed action. A 

large accidental oil spill, including a CDE-level spill, could contact areas near coastal 

endangered beach mouse habitats.

Marine and Coastal Birds—Routine operations may result in negligible to moderate 

localized short-term impacts associated primarily with infrastructure installation and ship 

and helicopter traffic within a small area of the Eastern GOM. Impacts of routine 

operations to important coastal habitats such as nesting areas and overwintering sites 

would be small since existing support bases will be used that are located in areas of the 

Central GOM. Small accidental oil spills are expected to have largely local, small 

effects. Large spills, including a CDE-level spill, may result in large, long-term, and 

possibly population-level effects. 

Fish Resources—Negligible impacts to fish and threatened or endangered fish species 

are expected from routine operations. A large accidental oil spill, including a CDE-level 

spill, is not likely to result in population-level impacts except potentially for spills that 

significantly affect overfished species and their spawning grounds. Oil contacting 

shoreline areas could result in lethal and sublethal effects on early life stages of some 

species, but no permanent population-level effects are expected.

Reptiles—Routine operations could result in minor localized impacts to marine turtles 

primarily due to seismic exploration, facility construction, pipelines and vessel traffic. 

Accidental oil spills could result in large impacts depending on the size, location, 

duration and timing of the spill, and on the effectiveness of spill containment and cleanup 

activities. Small spills would likely result in short-term impacts while large spills, 

including a CDE-level spill, potentially could incur both short-term and long-term 

population-level impacts depending on the species and habitat type affected, and on the 

size and duration of the spill.

Invertebrates and Lower Trophic Levels—Routine operations could result in negligible 

to moderate impacts to primarily benthic invertebrates, primarily from habitat disturbance 

associated with infrastructure placement, and from routine discharges. Recovery could 

be short-term to long-term. Large accidental oil spills, including a CDE-level spill, could 

measurably depress invertebrate populations especially in intertidal areas, but no 

permanent impacts are expected.
60

Areas of Special Concern—Impacts resulting from routine activities are expected to be 

negligible to moderate because of existing protections and use restrictions. Large 

accidental oil spills, including a CDE-level spill, reaching such areas could negatively 

affect fauna and habitats, individuals fishing for food, commercial or recreational 

fisheries, recreation and tourism, and other uses of these areas.

Population, Employment and Income—Direct expenditures associated with routine 

operations would result in negligible impacts. Effects are expected to be minimal 

because of the small amount of activity that is projected to occur in the Eastern GOM, 

and the fact that onshore support facilities will be located in ports along the Central 

GOM. In areas where tourism and recreation provide significant employment, accidental 

oil spills, including a CDE-level spill, could result in the short-term loss of employment, 

income and property values. Expenditures associated with spill cleanup activities would 

create short-term employment and income in some parts of the affected coastal region(s).

Land Use and Existing Infrastructure—No impacts to land use, development patterns, 

and infrastructure in the Eastern GOM would occur. Facilities and service bases will be 

located in ports along the Central GOM coast. Employment needs will likely be small 

and supplied by the experienced offshore work force located in all GOM coastal states. 

Projected impacts from an accidental oil spill, including a CDE-level spill, would likely 

include restrictions of access to a particular area while the cleanup is being conducted. 

Impacts would be expected to be temporary and localized.

Fisheries—Routine operations would have a minor impact on fishing, the cost of 

commercial fishing, or on the number of recreational fishing trips, in the region over the 

duration of the leasing period. Large accidental oil spills, including a CDE-level spill, 

may have small to medium, short-term impacts on fisheries resources, including lethal 

and sublethal toxic effects on exposed eggs, larvae, juveniles, and adults, and small to 

medium impacts on commercial trawling and recreational charter fishery activities and 

individuals fishing for food. The magnitude and duration of effects will depend on the 

location, size, duration, and timing of the spill; the fisheries affected; and the duration 

and effectiveness of spill containment and cleanup activities.

Recreation and Tourism—Routine operations would result in minimal impacts to beach 

recreation, sightseeing, boating, and fishing since OCS structures and facilities will be 

located at least 100 miles from the Florida shoreline, and onshore support facilities will 

be located in coastal areas of the Central GOM. Offshore structures would create 

positive impacts to diving and recreational fishing. The impact of an accidental oil 

spill,(including a CDE-level spill, on tourism and recreation will depend on the size, 

location, duration, and timing of the spill, as well as on the effectiveness and timeliness 

of spill containment and cleanup activities.

Sociocultural Systems and Environmental Justice—Because of the well developed and 

long established oil and gas industry in the GOM, routine operations are expected to have 

minor impacts on sociocultural systems. Very large spills, including a CDE-level spill, 

may temporarily halt and impact economies associated with the oil and gas industry, but 
61

also other sectors of the economy. Depending on the duration of such halts and the 

magnitude of economic impacts, this could result in social and cultural stress, leading to 

possible social pathologies. 

Archaeological Resources—Assuming compliance with existing Federal, state, and local 

archaeological regulations and policies, most impacts to archaeological resources 

resulting from routine activities under the proposal will be avoided. Some impacts could 

occur to marine historic and prehistoric archaeological resources from accidental oil 

spills. Although it is not possible to predict the precise numbers or types of sites that 

would be affected, contact with archaeological sites would probably be unavoidable, and 

the resulting loss of information would be irretrievable. 
62

Map 5 – Eastern Gulf of Mexico Program Area
63

Option 2 (1 Sale)

Valuation. The net benefits of anticipated production from one sale in this PFP area are 

estimated at about $2.73 billion in the mid-price case and $5.99 billion in the high-price 

case.25 There is no production anticipated in the low-price case; therefore, net benefits 

are zero.

Environmental Impacts. This option is analyzed in the Final EIS under Alternative 1. 

A summary of the Five Year Final EIS findings follows.

The difference in environmental impacts between one and two sales in the small area 

available for leasing under Alternative 1 is negligible. The expected amount of activities 

and hydrocarbon development represents about 1 percent of the total for the entire GOM. 

These amounts are expected to remain essentially the same for the one and two-sale 

program options. 

Option 3 (No Sale)

Valuation. The net benefits of production would be zero since no activity would occur. 

However, foregoing the production anticipated to result from any sales in the Eastern 

GOM would result in environmental and social costs incurred to obtain the energy 

substitutes, including additional imports of oil and increased onshore production of oil 

and natural gas, among others. 

Environmental Impacts. This option is analyzed in the Five Year Final EIS under 

Alternatives 2 and 8. A summary of the Five Year Final EIS findings follows.

Because of the small area of the OCS that would be removed from leasing under the No 

Sale Option and the small amount of resource potentially expected to occur within this 

area, this option would only slightly reduce risks of oil spill occurrence on the OCS or of 

routine operation effects within the small area

ALASKA REGION

Draft Proposed Program Decision

The 2009 DPP scheduled two sales in the Beaufort Sea, three sales in the Chukchi Sea, 

and two “special interest” sales in Cook Inlet. See the discussion under the Cook Inlet 

Options for a description of the proposed special interest sale process.

 25 Current information indicates no difference in anticipated production for the Eastern GOM, whether from 

one sale or two sales. 
64

Proposed Program Decision 

The PP scheduled one sale each in the Beaufort and Chukchi Seas and one special 

interest sale in the Cook Inlet.

Proposed Final Program Options

Chukchi Sea

Key Comparative Results. The net benefits of anticipated production from this PFP 

area are estimated at $8.07 billion in the low-price case, $39.54 billion in the mid-price 

case, and $161.28 billion in the high-price case. The area ranks as “Less Sensitive to 

Impact” as a component of environmental sensitivity and 5th of 6 for marine productivity. 

Selected Comments. The State of Alaska requested that the sale in the Chukchi Sea not 

be delayed until late in the program as it also delays economic development, jobs, and 

securing energy independence. The Arctic Slope Regional Corporation expressed similar 

concerns. DOE and DOD support the program. The North Slope and Northwest Arctic 

Boroughs, the Inupiat Community of the Arctic Slope, and the Native Village of 

Kotzebue, prefer that the Chukchi Sea be excluded from the program. However, if there 

were a sale proposed, some or all of these Native entities wanted some or all of the 

following: more areas deferred at the five year stage, a more comprehensive and 

coordinated approach to filling information gaps, more realistic scenarios to address the 

effects of a large spill on the communities, and revenue sharing at all stages. Many 

environmental public interest groups expressed the same concerns. Five companies in 

the oil and gas industry supported the PP, which included this area.

Responses. The PFP provides for lease sales in six offshore areas, including the Chukchi 

Sea where there are currently active leases and where there is known or anticipated 

hydrocarbon potential. In Alaska and off its coast, government and industry are actively 

working towards the development of infrastructure, and limited exploration activities that 

may proceed in the near future would help to identify further needs. The program 

schedules one sale in the Chukchi Sea, deliberately set late in the program to allow time 

for further study and infrastructure development. In addition to the 25-mile buffer area 

that has been excluded from leasing in the current 2007-2012 program and throughout 

preparation of this program, the Secretary also has decided at this program stage to 

exclude from leasing a subsistence area in the northeast portion of the program area,

based on current information regarding both resource potential and areas of significant 

subsistence use. Furthermore, as discussed in part I of this document, in an effort to 

increase transparency and accountability in this process, DOI is committing to enhance 

several aspects of the leasing program. This includes publishing a tracking table, starting 

in the Five Year Final EIS, which tracks the lineage and treatment of suggestions for 

spatial exclusions, temporal deferrals, and/or mitigation from the program stage, to the 
65

lease sale, and then to the plans stage. The tracking table in the EIS will be accompanied 

by an online tracking table and interactive, web-based maps. Two deferral suggestions 

often mentioned were Hanna Shoal and a 60-mile coastal buffer. Both of these 

suggestions will be included for later consideration in the tracking table discussed in the 

introduction to this document.

(1) One sale in 2016 in the program area depicted in Map 6

(2) No sale

Discussion

Option 1 (1 Sale)

Valuation. The net benefits of anticipated production in the PFP area are estimated at 

$8.07 billion in the low-price case, $39.54 billion in the mid-price case, and $161.28 

billion in the high-price case 

Environmental Impacts. This option is analyzed in the Five Year Final EIS under 

Alternative 1. A summary of the Five Year Final EIS findings follows. As noted above, 

the single sale for the Chukchi Sea is proposed late in the program in light of the time 

needed to review and analyze new information, including ongoing and future scientific 

studies and the results from any exploration that may occur. Lease-specific decisions, 

including decisions about additional deferral areas and environmental stipulations, will 

address new information, as well as feedback from other Federal agencies, state 

government, native communities, and other stakeholders. 

Water Quality—Routine operations would result in minor to moderate, short-term, 

localized impacts such as disturbing sediments and increasing turbidity near construction 

sites and altering water chemistry from operational discharges. Minor water quality 

impacts could also occur from fluids entrained in ice roads when they break up in the 

spring. Compliance with NPDES permits and USCG regulations would reduce impacts 

of routine operations. The effects of accidental oil spills will depend upon material, spill 

size, location, season, response, and remediation activities. In the presence of cold 

temperatures and ice, cleanup activities would be extremely difficult. Small spills would 

likely result in short-term impacts. Impacts from a large oil spill, including those from a 

very large spill associated with an unlikely CDE, defined as a discharge of a volume of 

oil into the environment that could result in catastrophic effects, could persist for an 

extended period of time if oil were deposited in wetland and beach sediments or lowenergy environments because of potential remobilization. Spills under ice could affect 

water quality for relatively long periods.

Air Quality—Routine operations are expected to result in minor impacts to air quality. 

Routine operations would not result in exceeding the NAAQS in public access areas or 

impact visibility. Smaller oil spills could have localized and temporary impacts. 

Pollutant levels from very large spills, including accidental spills associated with an 
66

unlikely CDE, and associated in situ burning, if used, could be major during the initial 

leak and again during cleanup efforts. Plumes from in situ burning could temporarily 

degrade visibility, but eventually, air quality is expected to return to normal or near 

normal. The long-term air quality effects associated with a spill and cleanup would be 

minor.

Acoustic Environment—Routine operations could affect ambient noise conditions, but 

impacts to ambient noise levels are expected to be minor. Noise generating sources 

associated with routine operations include seismic surveys, drilling and production, 

infrastructure placement and removal, and vessel traffic. Depending on the source and 

activity, changes in ambient noise levels could be short-term and localized (e.g., from 

vessel traffic), long-term and localized (from production), or short-term and less localized 

(from seismic surveys). Seismic surveys could result in short-term changes in ambient 

noise levels, but the changes could extend well beyond the survey boundary.

Coastal and Estuarine Habitats—Routine operations would be expected to result in 

minor to moderate localized impacts primarily due to road and facility construction, and 

vessel traffic. These operations could have a major effect on the local indigenous 

residents most proximate to development if it interferes with their subsistence practices 

for the greater part of a season. The effects of accidental oil spills will depend on habitats 

affected; the size, location, duration and timing of the spill; and on the effectiveness of 

spill containment and cleanup activities. Large, including CDE-level, and small spills, 

could result in long-term and short-term impacts, depending on the habitats affected; the 

duration and size of the spill, and on the effectiveness of spill containment and cleanup 

activities.

Marine Habitats—Routine operations associated with platform and pipeline placement 

could result in moderate and long-term impacts to benthic habitats, primarily soft 

sediments. Accidental releases of oil could be long-term and range from small to 

medium depending on the habitat affected, cleanup method, and the size, duration, 

timing, and location of the spill. Routine operations could result in negligible to minor, 

short-term to long-term impacts to pelagic habitat. The effects of accidental releases of 

oil, including a CDE could result in minor, but long-term impacts to pelagic habitat and 

sea ice habitat, depending on the size, duration, timing, and location of the spill; the 

habitat affected; and the effectiveness of spill containment and cleanup activities. Severe 

winter weather and ice cover may be expected to limit containment and cleanup efforts in 

winter.

Essential Fish Habitat—Routine operations could result in no more than moderate shortand long-term impacts to EFH and managed species. Accidental releases of oil could 

result in moderate and long-term impacts. Impacts from accidental oil spills, including a 

CDE-level spill could be long-term depending on the size, duration, timing, and location 

of the spill; the habitats affected; and the effectiveness of spill containment and cleanup 

activities, which could be hampered by extreme winter conditions and ice cover.
67

Marine Mammals—Collisions with OCS-related vessels may injure or kill some 

individuals, although the incidence of such collisions is expected to be low. Vessels, 

construction of ice roads, on-ice vehicles, and aircraft have been known to temporarily 

disturb some individuals. For example, polar bears may abandon dens. However, these 

effects would likely be short-term and mitigation can reduce the disturbance. Negligible 

to minor impacts to fauna from disturbance or habitat loss from construction and 

operation of onshore pipeline are expected. Disturbance from noise sources is the most 

likely impact. A large oil spill, including a CDE-level spill, in the Arctic, would most 

likely affect marine mammals by oil-contaminated ice leads, polynyas, rookeries, 

beaches, and haulouts. 

Terrestrial Mammals—Impacts to terrestrial mammals from routine operations would be 

negligible to minor. A spill, especially from an onshore pipeline, could contaminate 

habitats used by caribou, grizzly and brown bears, Arctic foxes, and muskoxen. Coastal 

beaches are particularly critical to species including caribou seeking relief from 

mosquitoes. Aircraft overflights could also cause short-term disturbances to terrestrial 

mammals.

Marine and Coastal Birds—Routine operations may result in negligible to moderate 

localized short-term impacts; impacts associated primarily with infrastructure 

construction, and ship and helicopter traffic. Impacts of routine operations to important 

coastal habitats such as nesting areas and overwintering sites could result in greater, more 

long-term impacts should normal breeding and nesting activities be disrupted. Small 

accidental oil spills are expected to have largely local, small effects. Large spills, 

including a CDE-level spill, may result in large, long-term, and possibly population-level 

effects. The actual magnitude of the effects will depend on the size, duration, and timing 

of the spill; the species and habitats affected; and the effectiveness of spill containment 

and cleanup activities. Because of the importance of certain habitat areas for some 

migrating and breeding birds, spills affecting those birds and habitats could result in longterm population-level impacts for some species if the spills affect important nesting 

colonies, migratory staging areas, or wintering grounds.

Fish Resource —Negligible to minor impacts to fish are expected from routine 

operations. The impact magnitude of a large oil spill, including a CDE-level spill, would 

depend on the location, timing, and size of the spill, and the distribution and ecology of 

affected fish species. Oil contacting shoreline areas could result in large-scale lethal and 

long-term sublethal effects on early life stages, but no permanent population-level effects 

are expected. Spills occurring near or under ice could be difficult to clean and may 

persist in the water column and continue to affect fish for an extended period. 

Invertebrates and Lower Trophic Levels—Routine operations could result in negligible 

to moderate impacts to primarily benthic invertebrates. Recovery could be short- to longterm. Large accidental oil spills, including a CDE-level spill, could measurably depress 

invertebrate populations, especially in intertidal areas. Spills occurring under ice would 

result in prolonged exposure of invertebrates and lower trophic level biota. However, no 

permanent impacts are expected.
68

Areas of Special Concern—Impacts resulting from routine activities are expected to be 

negligible to moderate because of the existing protections and use restrictions. Impacts 

from large accidental oil spills, including a CDE-level spill reaching such areas, could 

negatively affect fauna and habitats, subsistence use, commercial or recreational 

fisheries, recreation and tourism, and other uses.

Population, Employment, and Income—Direct expenditures associated with routine 

operations would result in minor impacts from small increases in population, employment 

and income in arctic communities over the duration of the leasing period, corresponding 

to less than 5 percent of the baseline. Expenditures associated with spill cleanup 

activities would create short-term employment and income in some parts of the affected 

coastal region(s).

Land Use and Existing Infrastructure—Routine operations would result in minimal to 

moderate impacts to land use, development patterns, and infrastructure. The construction 

and operation of offshore facilities would expand the area potentially at risk from 

accidental oil spills, along with the requirement to maintain oil-spill response equipment. 

An accidental oil spill, including a CDE-level spill, could alter land use temporarily but 

would not likely result in long-term changes. The magnitude of the impacts would 

depend on the size and location of the spill.

Fisheries—Routine operations would have a minor impact on subsistence fishing over 

the duration of the leasing period. Large accidental oil spills, including a CDE-level 

spill, may have small to medium, short-term impacts on fisheries resources, including 

lethal and sublethal toxic effects on exposed eggs, larvae, juveniles, and adults; and small 

to medium impacts on commercial, recreational, and subsistence fishery activities, such 

as trawling and charter fishing. The magnitude and duration of effects will depend on the 

location, size, duration, and timing of the spill; the fisheries affected; and the duration 

and effectiveness of spill containment and cleanup activities.

Sociocultural Systems and Environmental Justice—Potential impacts of routine 

operations can range from minor to major on sociocultural systems in the Arctic planning 

areas, depending on shore base infrastructure and proximity to existing communities. 

Accidental oil spills, including a CDE-level spill, however, may result in larger impacts, 

especially in the Arctic where impacts to subsistence could result in major impacts to 

affected communities.

Archaeological Resources—Routine operations could affect significant archaeological 

and historic resources especially in offshore locations through construction activities such 

as platform and pipeline construction. Onshore impacts including visual impacts are also 

possible from pipeline landfall, onshore pipeline, and road construction. Impacts could 

range from negligible to major, depending on the presence of significant archaeological 

or historic resources in the area of potential effect. Most resources are expected to be 

avoided. Accidental oil spills, including a CDE-level spill, could impact archaeological 

and historic resources, depending on the spill location, size, and duration, as well on the 

effectiveness and nature of spill containment and cleanup activities.
69

Map 6 – Chukchi Sea Program Area
70

Option 2 (No Sale)

Valuation. The net benefits of production would be zero since no activity would occur. 

However, foregoing the production anticipated to result from a Chukchi Sea sale would 

result in environmental and social costs incurred to obtain the energy substitutes, 

including additional imports of oil and increased onshore production of oil and natural 

gas, among others. This also could affect the long-term viability of the Trans-Alaska 

Pipeline System (TAPS).

Environmental Impacts. This option is analyzed in the Five Year Final EIS under 

Alternatives 6 and 8. A summary of the Five Year Final EIS findings follows.

Under this option the potential direct effects of routine operations in the Chukchi Sea that 

are described under the analysis of the proposed action would not occur. No oil spills 

would originate within the Chukchi Sea from new leasing, although marine and coastal 

environmental resources there could be affected by a spill that originates from existing 

leases in the Chukchi Sea or from the Beaufort Sea. Energy substitutions for the forgone 

hydrocarbon production in the Chukchi Sea under this option could increase tanker 

import spill risks (including the risk of a CDE) in OCS areas along the Pacific, GOM, and 

Atlantic coasts that contain tanker ports and terminals. 

Beaufort Sea

Key Comparative Results. The net benefits of anticipated production in this PFP area 

are estimated at $1.28 billion in the low-price case, $6.14 billion in the mid-price case, 

and $25.71 billion in the high-price case. The area ranks as “More Sensitive to Impact” 

as a component of environmental sensitivity and 6th of 6 for marine productivity. 

Selected Comments. The State of Alaska requested that the sale in the Beaufort Sea not 

be delayed until late in the program as it also delays economic development, jobs, and 

securing energy independence. The Arctic Slope Regional Corporation expressed similar 

concerns. DOE and DOD support the program, but DOD said it might need site-specific 

stipulations at the lease sale stage for radar facilities. The North Slope and Northwest 

Arctic Boroughs, the Inupiat Community of the Arctic Slope, and the Native Village of 

Kotzebue, prefer that the Beaufort Sea be excluded from the program. However, if there 

were sales proposed, some or all of these Native entities wanted some or all of the 

following: more areas deferred at the five year stage, a more comprehensive and 

coordinated approach to filling information gaps, more realistic scenarios to address the 

effects of a large spill on the communities, and revenue sharing at all stages. Many 

environmental public interest groups expressed the same concerns as the Native entities. 

Five companies in the oil and gas industry supported the PP which included this area.

Responses. The PFP provides for lease sales in six offshore areas, including the Beaufort 

Sea, where there are currently active leases and/or exploration and where there is known 
71

or anticipated hydrocarbon potential. In Alaska and off its coast, government and 

industry are actively working towards the development of infrastructure, and limited 

exploration activities that may proceed in the near future would help to identify further 

needs. This program schedules one sale in the Beaufort Sea, deliberately set late in the 

program to allow time for further study and infrastructure development. As discussed in 

part I of this document, in an effort to increase transparency and accountability in this 

process, DOI is committing to enhance several aspects of the leasing program. This 

includes publishing a tracking table, starting in the Five Year Final EIS, which tracks the 

lineage and treatment of suggestions for spatial exclusions, temporal deferrals, and/or 

mitigation from the program stage, to the lease sale, and then to the plans stage. The 

tracking table in the EIS will be accompanied by an online tracking table and interactive, 

web-based maps. Such suggestions, for example, as the request for additional whaling 

deferral areas such as Cross Island will be included for further consideration in the 

tracking table discussed in the introduction to this document.

(3) One sale in 2017 in the program area depicted in Map 7 

(4) No sale

Discussion

Option 1 (1 Sale)

Valuation. The net benefits of anticipated production in the PFP area are estimated at 

$1.28 billion in the low-price case, $6.14 billion in the mid-price case, and $25.71 billion 

in the high-price case. 

Environmental Impacts. This option is analyzed in the Final EIS under Alternative 1. 

A summary of the Final EIS findings follows. As noted above, the single sale for the 

Beaufort Sea is proposed late in the program in light of the time needed to review and 

analyze new information, including ongoing and future scientific studies and the results 

from any exploration that may occur. Lease-specific decisions, including decisions about 

additional deferral areas and environmental stipulations, will address new information, as 

well as feedback from other Federal agencies, state government, native communities, and 

other stakeholders. 

Water Quality—Routine operations would result in minor to moderate, short-term, 

localized impacts such as disturbing sediments and increasing turbidity near construction 

sites and altering water chemistry from operational discharges. Minor water quality 

impacts could also occur from fluids entrained in ice roads when they break up in the 

spring. Compliance with NPDES permits and USCG regulations would reduce impacts 

of routine operations. The effects of accidental oil spills will depend upon material, spill 

size, location, season, response, and remediation activities. In the presence of cold 

temperatures and ice, cleanup activities would be extremely difficult. Small spills would 

likely result in short-term impacts. Impacts from a large oil spill, including those from a 

very large spill associated with an unlikely CDE, defined as a discharge of a volume of 
72

oil into the environment that could result in catastrophic effects, could persist for an 

extended period of time if oil were deposited in wetland and beach sediments or lowenergy environments because of potential remobilization. Spills under ice could affect 

water quality for relatively long periods. 

Air Quality—Routine operations are expected to result in minor impacts to air quality. 

Routine operations would not result in exceeding NAAQS in public access areas or 

impact visibility. Smaller oil spills could have localized and temporary impacts. 

Pollutant levels from very large spills, including accidental spills associated with an 

unlikely CDE, and associated in situ burning if used, could be major during the initial 

leak and again during cleanup efforts. Plumes from in situ burning could temporarily 

degrade visibility, but eventually, air quality is expected to return to normal or near 

normal. The long-term air quality effects associated with a spill and cleanup would be 

minor.

Acoustic Environment—Routine operations could affect ambient noise conditions, but 

impacts to ambient noise levels are expected to be minor. Noise generating sources 

associated with routine operations include seismic surveys, drilling and production, 

infrastructure placement and removal, and vessel traffic. Depending on the source and 

activity, changes in ambient noise levels could be short-term and localized (e.g., from 

vessel traffic), long-term and localized (from production), or short-term and less localized 

(from seismic surveys). Seismic surveys could result in short-term changes in ambient 

noise levels, but the changes could extend well beyond the survey boundary.

Coastal and Estuarine Habitats—Routine operations would be expected to result in 

minor to moderate localized impacts primarily due to road and facility construction, and 

vessel traffic. These operations could have a major effect on the local indigenous 

residents most proximate to development if it interferes with their subsistence practices 

for the greater part of a season. The effects of accidental oil spills will depend on habitats 

affected; the size, location, duration and timing of the spill; and on the effectiveness of 

spill containment and cleanup activities. Large, including a CDE-level, and small spills 

could result in long-term and short-term impacts, depending on the habitats affected; the 

duration and size of the spill, and on the effectiveness of spill containment and cleanup 

activities.

Marine Habitats—Routine operations associated with platform and pipeline placement 

could result in moderate and long-term impacts to benthic habitats, primarily soft 

sediments. Accidental releases of oil could be long-term and range from small to 

medium depending on the habitat affected, cleanup method, and the size, duration, 

timing, and location of the spill. Major impacts to hard-bottom kelp habitat could occur 

if these areas were heavily oiled and high mortality occurs. Routine operations could 

result in negligible to minor, short-term to long-term impacts to pelagic habitat. The 

effects of accidental releases of oil, including a CDE, could result in minor, but long-term 

impacts to pelagic habitat and sea ice habitat, depending on the size, duration, timing, and 

location of the spill; the habitat affected; and the effectiveness of spill containment and 
73

cleanup activities. Severe winter weather and ice cover may be expected to limit 

containment and cleanup in winter.

Essential Fish Habitat—Routine operations could result in no more than moderate shortand long-term impacts to EFH and managed species. Accidental releases of oil could 

result in moderate and long-term impacts. Impacts from accidental oil spills, including a 

CDE-level spill, could be long-term depending on the size, duration, timing, and location 

of the spill; the habitats affected; and the effectiveness of spill containment and cleanup 

activities, which could be hampered by extreme winter conditions and ice cover.

Marine Mammals—Collisions with OCS-related vessels may injure or kill some 

individuals, although the incidence of such collisions is expected to be low. Vessels, 

construction of ice roads, on-ice vehicles, and aircraft have been known to temporarily 

disturb some individuals. For example, polar bears may abandon dens, but these effects 

would likely be short-term and mitigation can reduce the disturbance. Negligible to 

minor impacts to fauna from disturbance or habitat loss from construction and operation 

of onshore pipeline are expected. Disturbance from noise sources is the most likely 

impact. A large oil spill, including a CDE-level spill, in the Arctic would most likely 

affect marine mammals by oil-contaminated ice leads, polynyas, rookeries, beaches, and 

haulouts. 

Terrestrial Mammals—Impacts to terrestrial mammals from routine operations would be

negligible to minor. A spill, especially from an onshore pipeline, could contaminate 

habitats used by caribou, grizzly and brown bears, Arctic foxes, and muskoxen. Coastal 

beaches are particularly critical to species including caribou seeking relief from 

mosquitoes. Aircraft overflights could also cause short-term disturbances to terrestrial 

mammals.

Marine and Coastal Birds—Routine operations may result in negligible to moderate 

localized short-term impacts; impacts associated primarily with infrastructure 

construction, and ship and helicopter traffic. Impacts of routine operations to important 

coastal habitats such as nesting areas and overwintering sites could result in greater, more

long-term impacts should normal breeding and nesting activities be disrupted. Small 

accidental oil spills are expected to have largely local, small effects. Large spills, 

including a CDE-level spill, may result in large, long-term, and possibly population-level 

effects. The actual magnitude of the effects will depend on the size, duration, and timing 

of the spill; the species and habitats affected; and the effectiveness of spill containment 

and cleanup activities. Because of the importance of certain habitat areas for some 

migrating and breeding birds, spills affecting those birds and habitats could result in longterm population-level impacts for some species if the spills affect important nesting 

colonies, migratory staging areas, or wintering grounds.

Fish Resource— Negligible to minor impacts to fish are expected from routine 

operations. The impact magnitude of a large oil spill, including a CDE-level spill, would 

depend on the location, timing, and size of the spill, and the distribution and ecology of 

affected fish species. Oil contacting shoreline areas could result in large-scale lethal and 
74

long-term sublethal effects on early life stages, but no permanent population-level effects 

are expected. Spills occurring near or under ice could be difficult to clean up and may 

persist in the water column and continue to affect fish for an extended period. 

Invertebrates and Lower Trophic Levels—Routine operations could result in negligible 

to moderate impacts to primarily benthic invertebrates. Recovery could be short- to longterm. Large accidental oil spills, including a CDE-level spill, could measurably depress 

invertebrate populations, especially in intertidal areas. Spills occurring under ice would 

result in prolonged exposure of invertebrates and lower trophic level biota. However, no 

permanent impacts are expected.

Areas of Special Concern—Impacts resulting from routine activities are expected to be 

negligible to moderate because of the existing protections and use restrictions. Impacts 

from large accidental oil spills, including a CDE-level spill, reaching these areas could 

negatively affect fauna and habitats, subsistence use, commercial or recreational 

fisheries, recreation and tourism, and other uses.

Population, Employment, and Income—Direct expenditures associated with routine 

operations would result in minor impacts from small increases in population, employment 

and income in Arctic communities over the duration of the leasing period, corresponding 

to less than 5 percent of the baseline. Expenditures associated with spill cleanup 

activities would create short-term employment and income in some parts of the affected 

coastal region(s).

Land Use and Existing Infrastructure—Routine operations would result in minimal to 

moderate impacts to land use, development patterns, and infrastructure. The construction 

and operation of offshore facilities would expand the area potentially at risk from 

accidental oil spills, along with the requirement to maintain oil-spill response equipment. 

An accidental oil spill, including a CDE-level spill, could alter land use temporarily but 

would not likely result in long-term changes. The magnitude of the impacts would 

depend on the size and location of the spill.

Fisheries—Routine operations would have a minor impact on subsistence fishing over 

the duration of the leasing period. Large accidental oil spills, including a CDE-level 

spill, may have small to medium, short-term impacts on fisheries resources, including 

lethal and sublethal toxic effects on exposed eggs, larvae, juveniles, and adults, and small 

to medium impacts on subsistence fishery and other commercial and recreational fishing 

activities, such as trawling and charter fishing. The magnitude and duration of effects 

will depend on the location, size, duration, and timing of the spill; the fisheries affected; 

and the duration and effectiveness of spill containment and cleanup activities.

Sociocultural Systems and Environmental Justice—Potential impacts of routine 

operations can range from minor to major on sociocultural systems in the Arctic planning 

areas, depending on shore base infrastructure and proximity to existing communities. 

Accidental oil spills, including a CDE-level spill; however, may result in larger impacts, 

especially in the Arctic where impacts to subsistence could result in major impacts to 

affected communities.
75

Archaeological Resources—Routine operations could affect significant archaeological 

and historic resources especially in offshore locations through construction activities such 

as platform and pipeline construction. Onshore impacts including visual impacts are also 

possible from pipeline landfall, onshore pipeline, and road construction. Impacts could 

range from negligible to major, depending on the presence of significant archaeological 

or historic resources in the area of potential effect. Most resources are expected to be 

avoided. Accidental oil spills, including a CDE-level spill, could impact archaeological 

and historic resources, depending on the spill location, size, and duration, as well on the 

effectiveness and nature of spill containment and cleanup activities.
76

Map 7 – Beaufort Sea Program Area
77

Option 2 (No Sale)

Valuation. The net benefits of production would be zero since no activity would occur. 

However, foregoing the production anticipated to result from a Beaufort Sea sale would 

result in environmental and social costs incurred to obtain the energy substitutes, 

including additional imports of oil and increased onshore production of oil and natural 

gas, among others. This also could affect the long-term viability of TAPS.

Environmental Impacts. This option is analyzed in the Final EIS under Alternatives 5 

and 8. A summary of the Final EIS findings follows.

Under this option the potential direct effects of routine operations in the Beaufort Sea that 

are described under the analysis of the proposed action would not occur. No oil spills 

would originate within the Beaufort Sea from new leasing, although marine and coastal 

environmental resources there could be affected by a spill that originates from existing 

leases in the Beaufort Sea or from the Chukchi Sea. Energy substitutions for the 

foregone hydrocarbon production in the Beaufort Sea under this option could increase 

tanker import spill risks (including that of a catastrophic discharge event) in OCS areas 

along the Pacific, GOM, and Atlantic coasts that contain tanker ports and terminals.

Cook Inlet

Key Comparative Results. The net benefits for this PFP area are estimated at $1.99 

billion in the low-price case, $4.17 billion in the mid-price case, and $13.98 billion in the 

high-price case. The area ranks as “Less Sensitive to Impact” as a component of 

environmental sensitivity and 1st of 6 for marine productivity. 

Selected Comments. While many commenters were either in favor of or opposed to the 

OCS program as a whole, there was little said about leasing in Cook Inlet. DOD 

requested caution to avoid submarine communications cables. Five companies in the oil 

and gas industry supported the PP which included this area.

Responses. The Cook Inlet is included as a special interest sale. The March 27, 2012, 

Request for Interest resulted in a sufficient expression of interest with respect to the Cook 

Inlet planning area. In light of responses to the Request, BOEM decided to proceed with 

the pre-sale process for the Cook Inlet and to place the date for a potential lease sale in 

2016 to allow time to complete the necessary steps under the Act, develop additional 

resource and environmental information, and conduct analysis under NEPA. 

(1) One special interest sale in 2016 in the program area depicted in Map 8

(2) No sale
78

Discussion

Option 1 (1 Sale)

Valuation. The net benefits of anticipated production for this PFP area are estimated 

$1.99 billion in the low-price case, $4.17 billion in the mid-price case, and $13.98 billion 

in the high-price case. 

Environmental Impacts. This option is analyzed in the Final EIS under Alternative 1. 

A summary of the Final EIS findings follows. 

Water Quality—Normal operations in the Cook Inlet could adversely impact water 

quality. However, because of dilution, settling, and flushing, these impacts are expected 

to be localized and temporary. Similarly, spills to coastal waters could adversely impact 

water quality. The impacts of these spills will be localized and short term, unless chronic 

spills occur in a localized area. Impacts from a large oil spill including those from a very 

large spill associated with an unlikely CDE, defined as a discharge of a volume of oil into 

the environment that could result in catastrophic effects, could persist for an extended 

period of time if oil were deposited in wetland and beach sediments or low-energy 

environments because of potential remobilization. The extent and magnitude of the 

impact would depend on the size, location, and season of the spill. Recovery times could 

be decreased by oil-spill cleanup activities.

Air Quality—Concentrations of NO2, SO2, and PM10 from any routine activities 

associated with the proposed Five Year Program activities in the Cook Inlet would be 

within the applicable maximum allowable increases. The concentrations of NO2, SO2, 

PM10, and CO2 would remain well within the NAAQS. Any air quality impacts from oil 

spills would be localized and of short duration. Pollutant levels from very large spills, 

including accidental spills associated with an unlikely CDE, and associated in situ

burning if used, could be major during the initial leak and again during cleanup efforts. 

For example, plumes from in situ burning could temporarily degrade visibility, but 

eventually, air quality is expected to return to normal or near normal. The long-term 

effects associated with a spill and cleanup would be minor.

Acoustic Environment—Routine operations could affect ambient noise conditions, but 

impacts to ambient noise levels are expected to be minor. Noise generating sources 

associated with routine operations include seismic surveys, drilling and production, 

infrastructure placement and removal, and vessel traffic. Depending on the source and 

activity, changes in ambient noise levels could be short-term and localized (e.g., from 

vessel traffic), long-term and localized (from production), or short-term and less localized 

(from seismic surveys). Seismic surveys could result in short-term changes in ambient 

noise levels, but the changes could extend beyond the survey boundary.

Coastal and Estuarine Habitats—Routine operations would be expected to result in 

minor to moderate localized impacts primarily due to one potential pipeline landfall and 
79

vessel traffic. The effects of accidental oil spills will depend on habitats affected; the 

size, location, duration and timing of the spill; and on the effectiveness of spill 

containment and cleanup activities. Large, including a CDE-level, and small spills could 

result in long-term and short-term impacts, depending on the habitats affected; the 

duration and size of the spill, and on the effectiveness of spill containment and cleanup 

activities.

Marine Habitats—Routine operations associated with platform and pipeline placement 

could result in moderate and long-term impacts to benthic habitats, primarily soft 

sediments. Accidental releases of oil could be long-term and range from small to 

medium depending on the habitat affected, cleanup method, and the size, duration, 

timing, and location of the spill. Routine operations could result in negligible to minor, 

short-term to long-term impacts to pelagic habitat. The effects of accidental releases of 

oil, including a CDE, could result in minor, but long-term impacts to pelagic habitats 

depending on the size, duration, timing, and location of the spill; the habitat affected; and 

the effectiveness of spill containment and cleanup activities. 

Essential Fish Habitat—Routine operations could result in no more than moderate shortand long-term impacts to EFH and managed species. Accidental releases of oil could 

result in moderate and long-term impacts. Impacts from accidental oil spills, including a

CDE-level spill, could be long-term depending on the size, duration, timing, and location 

of the spill; the habitats affected; and the effectiveness of spill containment and cleanup 

activities.

Marine Mammals—Noise, contaminants, human activity, and ship and helicopter traffic 

associated with routine OCS operations in the Cook Inlet could affect marine mammals. 

Noise generated during exploration, construction, and operations may temporarily disturb 

some individuals, causing them to leave or avoid the area, but the effects would likely be 

short-term and not result in population-level effects. While collisions with OCS-related 

vessels may injure or kill some individuals, collisions would be relatively unlikely 

because of the low level of traffic expected from the proposed action. Accidental oil 

spills may result in the direct and indirect exposure of marine mammals and their habitats 

to the oil and subsequent weathering products. The magnitude of effects from accidental 

spills would depend on the location, timing, and volume of the spills; the habitats affected 

by the spills, such as coastal habitats; and the species exposed. The greatest risk to 

marine mammals would be associated with large spills, including a CDE, in coastal 

habitats. Spill cleanup operations could result in short-term disturbance of marine 

mammals in the vicinity of the cleanup activity, while a collision with a cleanup vessel 

could injure or kill the affected individual. Disturbance of adults with young during 

cleanup could reduce survival of the young animals.

Terrestrial Mammals—Construction and normal operations of a potential new onshore 

pipeline landfall could result in short-term and long-term impacts to terrestrial mammals. 

Short-term impacts would be largely behavioral in nature, with affected animals avoiding 

or vacating the construction areas. Similarly, vehicle and aircraft traffic from the 

proposed action in the Cook Inlet could temporarily disturb mammals along pipelines or 

roadways or along flight paths. The disturbance of animals by these activities would be 
80

short-term in nature and not expected to result in population-level effects. In the event of 

an accidental spill, including a CDE, terrestrial mammals may be exposed via ingestion 

of contaminated food, inhalation of airborne oil droplets, and direct ingestion of oil 

during grooming, which may result in a variety of lethal and sublethal effects. However, 

because most spills would be relatively small, less than 50 barrels, relatively few 

individuals would likely be exposed. While some individual, especially oil-sensitive 

species, such as the river otter, may incur lethal effects, population-level impacts would 

not be expected for most species. Cleanup activities could temporarily disturb terrestrial 

mammals in the vicinity of the cleanup operation, causing those animals to move from 

preferred to less optimal habitats, which in turn, could affect the overall condition. Such 

displacement would be limited to only those relatively few animals in the vicinity of the 

cleanup activity, thus would not be expected to result in population-level effects.

Marine and Coastal Birds—Marine and coastal birds may be affected by the construction 

of offshore facilities, by boat and aircraft traffic servicing offshore platforms, and by 

noise and human activities during normal operations and maintenance activities. For 

most routine operations, the primary effect would be the disturbance of birds in the 

vicinity of the operation, causing them to temporarily leave the area. Depending on the 

time of year, construction activities near coastal habitats could disrupt nesting, foraging, 

and overwintering activities of some species, potentially impacting local populations. 

Accidental oil spills, including a CDE, pose the greatest threat to marine and coastal 

birds, affecting both birds and their habitats. Exposed birds may experience a variety of 

lethal or sublethal effects, and the magnitude and ecological importance of any effects 

would depend upon the size and location of the spill, the species and life stage of the 

exposed birds, and the size of the local bird population. Spill cleanup activities may also 

disturb birds in the vicinity of the cleanup, causing them to leave the vicinity of the 

cleanup activity. 

Fish Resources—Fishes could be disturbed and displaced from the immediate vicinity of 

drilling discharges for short time periods. Offshore construction also could temporarily 

disturb and/or displace fishes proximate to the construction activity. Although seismic 

surveys may kill or injure eggs and fry of some fishes, this injury is limited to within 1 or 

2 meters of the airgun-discharge ports. Thus, seismic surveys probably would have no 

appreciable adverse effects on fish subpopulations. Oiled intertidal areas could lead to 

considerable mortality of eggs and juvenile stages of some pelagic species in the affected 

areas. Studies indicate that impacted eggs and juvenile stages could lead to reduced adult 

survival. Eggs and fry of some bentho-pelagic and demersal fishes could experience 

lethal and sublethal effects from oil contact. Although multiple small spills or a single 

large spill, including a CDE, could cause declines of subpopulations of multiple species 

inhabiting the Cook Inlet, it is anticipated that there would be no long-term effects on 

overall fish populations. Accidental oil spills could impact EFH and the species that 

depend upon them. The nature of the impact would be largely dependent on the size of 

spill, location, environmental factors, and uniqueness of the affected EFH. Large spills 

that reach coastal streams and intertidal areas used for spawning by anadromous salmon 

could have more persistent impacts and require remediation.
81

Invertebrates and Lower Trophic Levels—Routine operations during exploration, 

development, and production activities under the proposed action probably would not 

measurably affect local populations of lower trophic-level organisms. In the event of a 

large oil spill, populations of lower trophic-level organisms in pelagic waters would not 

be greatly affected by the spill and associated cleanup activities. However, a large spill 

could contact some shoreline areas in Cook Inlet and lower trophic-level organisms in 

sensitive intertidal and shallow subtidal habitats could experience lethal and sublethal 

effects. 

Areas of Special Concern—No development of onshore facilities is anticipated in the 

Cook Inlet area thereby making impacts from routine OCS operations unlikely in these 

coastal areas. However, offshore construction of pipelines and platforms could have 

temporary effects on wildlife due to noise and activity levels and on scenic values for 

park visitors. It is anticipated that reviews of individual lease sales would minimize the 

potential for impacts from routine operations due to development activities. No OCSrelated development would occur in the Alaska Peninsula Unit of the Alaska Maritime 

National Wildlife Refuge (NWR). Effects from oil spills that occur adjacent to national 

park or NWR boundaries would depend on spill location, spill size, weather conditions at 

the time of the spill, and the effectiveness of cleanup operations. Large oil spills, 

including a CDE, in areas adjacent to the Gulf of Alaska or Alaska Peninsula Units of the 

Alaska Maritime NWR could negatively impact coastal habitats and fauna and could also 

affect subsistence use, commercial or recreational fisheries, and tourism. 

Employment, Population, and Income—Potential effects on population, employment, 

and regional income from routine operations and oil spills are expected to be limited 

except for local effects from a large oil spill.

Land Use and Existing Infrastructure— Routine operations from the proposed action 

would have a low impact on the land use and infrastructure of the affected areas of the 

Cook Inlet. Accidents from the anticipated low level of activity also are expected to have 

minimal impact on land use and infrastructure.

Fisheries—Overall populations of biological resources that serve as the basis for 

commercial fisheries in the Cook Inlet are not expected to be altered by routine 

exploration, development, or production activities conducted as a result of lease sales 

under the proposed action. The level of effects from accidental spills would depend on 

the location, timing, and volume of spills, spill response activities, and other 

environmental factors. Small spills that may occur under the proposed action are unlikely 

to have a substantial effect on commercial fishing. A single large spill could affect a 

small proportion of a given fish population within Cook Inlet, although substantial 

temporary effects on populations could occur if important habitat areas were 

contaminated. Large accidental spills, including a CDE-level spill, may have small to 

medium short-term impacts on fisheries. The effects could be as a consequence of 

reduced catch, loss of gear, or loss of fishing opportunities during cleanup and recovery 

periods
82

Tourism and Recreation—Routine operations would have limited effects on recreation 

and tourism, with potential adverse impacts to sightseeing, boating, fishing, and hiking 

activities. Temporary impacts would occur if a spill reached a recreational-use area. The 

magnitude of these impacts would depend on factors such as the size and location of the 

spill, and it would likely be the greatest if the spill occurred during the peak recreational 

season.

Sociocultural Systems and Environmental Justice—Potential direct and indirect impacts 

on sociocultural systems due to noise, visual, and traffic disturbances, as a result of 

offshore operations for the proposed action, are expected to be limited. The Cook Inlet 

already is experiencing oil and gas development on state lands so the addition of a small 

amount of OCS activity should not disrupt sociocultural systems in the area. Potential 

impacts on sociocultural systems from accidents under the proposed action could range 

greatly, depending on the location and timing of a spill. 

Archaeological Resources—Assuming compliance with existing Federal, state, and local 

archaeological regulations and policies, most impacts to archaeological resources in the 

Alaska region resulting from routine activities under the proposal will be avoided. Some 

impact may occur to coastal historic and prehistoric archaeological resources from 

accidental oil spills. Although it is not possible to predict the precise numbers or types of 

sites that would be affected, contact with archaeological sites would probably be 

unavoidable, and the resulting loss of information would be irretrievable, if spills should 

occur. The magnitude of the impact would depend on the significance and uniqueness of 

the information lost. 
83

Map 8 – Cook Inlet Program Area
84

Option 2 (No Sale)

Valuation. The net benefits of production would be zero since no activity would occur. 

However, foregoing the production anticipated to result from a Cook Inlet sale would 

result in environmental and social costs incurred to obtain the energy substitutes, 

including additional imports of oil and increased onshore production of oil and natural 

gas, among others. 

Environmental Impacts. This option is analyzed in the Final EIS under Alternatives 7 

and 8. A summary of the Final EIS findings follows.

Under this option the potential direct effects of routine operations in Cook Inlet that are 

described under the analysis of the proposed action would not occur. No oil spills would 

originate within the Cook Inlet OCS area; however, there is oil and natural gas activity in 

state waters. Energy substitutions for the foregone hydrocarbon production in the Cook 

Inlet would be small given the limited amounts of hydrocarbons that are expected to be 

developed there. 

B. Fair Market Value Options

Introduction

The Act grants the Secretary the authority to issue leases on the OCS. Section 18(a)(4) of 

the Act states that “[L]easing activities shall be conducted to assure receipt of fair market 

value for the lands leased and the rights conveyed by the Federal Government.” 

Furthermore, the Act states that the OCS is a “vital national reserve held by the Federal 

Government for the public, which should be made 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.” 

The FMV determination, made at the time of lease issuance, is not based on the value of 

the oil and natural gas eventually discovered or produced. Instead it is related to the 

value of the right to explore and, if there is a discovery, to develop and produce 

hydrocarbons. This value therefore is based on the expected, not actual, activities and 

results that are anticipated to occur after the sale. Moreover, this value depends upon the 

conditions imposed on lessees by BOEM, such as diligence and drilling requirements, 

which may restrict lessee flexibility in attaining certain timing milestones and hence have 

a negative effect on expected or actual tract value. Also, this value is based on certain 

assumptions such as expected oil and natural gas prices at the time of sale and not actual 

prices in the future when a discovery is made.

There are several major elements in designing OCS auctions, such as lease sale timing, 

bidding systems, and sale terms and conditions, for assuring that OCS leases are not 

awarded prematurely or for less than FMV. This section discusses important 
85

considerations used to evaluate options under these elements and includes an overview of 

the post-sale OCS bid adequacy process. 

Draft Proposed Program Decision 

The 2009 DPP decision was to set sale terms (called fiscal lease terms in the 2009 DPP) 

using the parameters in place for then-recent sales, subject to sale-by-sale 

reconsideration, and to continue use of the current, two-phased bid adequacy process, 

subject to revision as appropriate.

Proposed Program Decision

The PP decision was the same as the 2009 DPP, but provided more analysis of the 

various terms and how sale-by-sale changes in those terms might affect FMV.

Proposed Final Program Options

Timing of OCS Lease Sales and Related Activities

(1) Evaluate area specific considerations, including a comparison of market prices 

with the hurdle prices for oil and for natural gas set in the Five Year Program

document, to determine if the sale should be held as scheduled. 

(2) Other.

Discussion: The first decision that must be made in the process of providing a solid 

foundation for ensuring receipt of FMV in a lease sale covered by the program is whether 

to include the entire proposed area for sale at the scheduled time or instead, to withhold 

some or all of the area until a later program. The value of the OCS resources can be 

optimized by identifying the most favorable time to sell leases. Because OCS leases have 

fixed initial lease periods, as long as exploration and development is expected to be 

privately profitable, lessees will explore and develop within that initial period. The Act

calls for limited initial periods to serve several purposes, e.g., to accelerate revenue, 

reduce speculation, and others. However, the trade-off involved is that sometimes it 

would be better for the operator to wait longer to explore and develop but it cannot do so 

– for example, if the price of oil or natural gas seems to be trending down but might 

recover later. Thus, it is conceivable that greater benefits could be realized in certain 

cases by waiting longer to lease in the first place. An analogy can be made with bid 

adequacy, which is another FMV process. For many years, the accepted procedure for 

bid adequacy determination has included a delay analysis to estimate whether an 

individual lease that was bid on might attract a higher bid if withheld and reoffered in a 

subsequent sale. Expanding that concept to the level of the Five Year Program employs a 

hurdle-price screen at the program stage to assure that delaying a sale offering would not 

provide greater economic value from all anticipated fields in the program area. A hurdle 

price is defined for present purposes as the oil and gas price above which immediate

exploration of at least one undiscovered prospect as identified by resource assessment is
86

the most profitable option. This definition is explained further below.

The government’s concession to the lessee is a conveyance of offshore oil and natural gas 

exploration and development rights for a limited initial lease period, subject to applicable 

regulatory and statutory requirements. Since future prices, risked resource endowments, 

required capital and operation costs, time needed to explore and delineate, available 

technologies, and the prevailing post-sale regulatory and legal environments are uncertain 

at the time of lease issuance, benefits for decision-making may subsequently be gained 

when uncertainty is reduced through new information or events. This information may 

involve changes in resource prices and expectations, emergence of new technologies, 

imposition of added regulatory and legal requirements, and additional insights on the 

resource endowments. In the last instance, this uncertainty can only be fully resolved 

through the actual leasing and subsequent drilling of OCS acreage, although it also is 

possible to acquire better knowledge about the resource potential and risk from 

monitoring activities on nearby leases. 

The most significant uncertainty to consider in sale planning analysis is the individual 

and aggregate volumes of oil and natural gas present, as well as when these undiscovered 

resources may become producing commercial reserves. These uncertainties are more 

pronounced in relatively less explored OCS areas. To estimate resource potential, BOEM 

uses computer models to calculate probability distributions of undiscovered recoverable 

oil and natural gas. The technically recoverable resource estimates assume that existing 

or reasonably foreseeable recovery technology will be used and operations are not 

constrained by the underlying economics of exploration, development and production. A 

second stage simulates recovery operations with cost estimates and resource price 

assumptions to calculate the economically recoverable resource volumes. The 

economically recoverable resource volumes do not include all the undiscovered resources 

reported as technically recoverable, but rather include those oil and natural gas resources 

judged to be contained in geologic fields whose sizes and locations make them economic 

under contemporary circumstances. 

The uncertainties about the recoverable resource size and location can only be resolved 

by lease acquisition and drilling. Private companies must spend billions of dollars to 

acquire leases and analyze geologic information in their efforts to discover and ultimately 

produce new oil and natural gas reserves that are undiscovered today. 

A good example of how exploration of an OCS province has changed the knowledge of 

resource potential is the GOM, where estimates of undiscovered oil resources have 

increased dramatically since the discovery of major deepwater oil and natural gas fields. 

Even with significant oil and natural gas production since 1975, amounting to nearly 14 

billion barrels of oil (BBO) and 150 trillion cubic feet (tcf) of natural gas, the estimated 

undiscovered technically recoverable GOM oil resources have increased fivefold from 

that time to today and the estimated natural gas resources have more than doubled. In 

deep water, increases in oil and natural gas potential have been facilitated by industry’s 

development of new technology to explore for and extract hydrocarbon resources. In all 
87

water depths, the expansion of offshore infrastructure and new technology has allowed 

industry to produce smaller and more geologically complex reservoirs. 

Exploration also can lead to reduced resource endowment estimates. The Navarin Basin 

in the Alaska OCS is a good example of how exploration can render an area less 

attractive. A resource assessment published in 1985 reported that estimates of mean 

risked oil volumes in the Navarin Basin of 1.30 billion barrels (Bbbl) were much larger 

than the Chukchi Sea’s 0.54 Bbbl. A 1983 lease sale in the Navarin Basin resulted in 163 

tracts being leased for $633 million, followed by 8 exploration wells. None of the wells 

discovered oil or natural gas pools and the subsequent geologic analysis severely 

downgraded the resource potential to 0.13 Bbbl in BOEM’s 2011 Assessment. There has 

been little or no subsequent industry interest in this area. Meanwhile, drilling results in 

the Chukchi Sea in 1990 and 1991, new technologies, and higher oil prices were key 

factors leading to the largest lease sale ever in the Alaska OCS, Chukchi Sea Sale 193, 

with 487 tracts leased for $2.66 billion in 2008. The current risked mean technically 

recoverable resource estimates for the Chukchi Sea increased 30 times over the 1985 

estimate to 15.4 Bbbl of oil and over 25 times to 76.8 tcf of natural gas in this underexplored frontier area. Future exploration in this area will further decrease the 

uncertainties regarding its oil and natural gas resource potential. 

While the value promised by a lease sale is related to the resource endowment 

concentration and composition and the likelihood of drilling a successful well, it also is

associated with forecasts of future oil and natural gas prices. In general, a resource 

holder has some flexibility in conducting exploration or development activities, and the 

value of the resource is likely to be greater when it is optimally managed. In the case of a 

Federal lease, however, the lessee is constrained by the initial period limit. The 

government is not constrained by the limit and it can enhance value by optimal timing of 

the lease offering. Given the significant uncertainty of program area hydrocarbon 

resources as well as the inherent difficulty of accurately forecasting future oil and natural 

gas prices, calculating timing and composition of lease offerings is very difficult. 

However, managing this uncertainty becomes more feasible as resource potential is 

resolved through actual exploration. Moreover, the decisions needed at the Five Year 

Program stage focus on whether and when a particular area should be included in the sale 

schedule rather than the specific composition of the sale areas and the terms attached to 

the blocks to be included. The composition issue, along with the most effective way to 

achieve the desired economic results, is best left to be more fully resolved at the lease 

sale design stage, in part to incorporate the latest and most current information into the 

analysis. 

Accordingly, at the program stage, BOEM’s approach to determining whether an area is 

suitable for exploration and possible development is not based solely on a program area’s 

aggregate resource estimates. Instead, it focuses more broadly on identifying a hurdle 

price below which immediate exploration for any one of a program area’s potential 

undiscovered field sizes, as suggested by available resource assessments, would not 

provide the best value for society. Above the hurdle price, the program area may be 

considered ready for leasing, in conjunction with modification in sale configuration 
88

consistent with other program goals, because there likely exists at least one field whose 

resource endowment and underlying economic value are consistent with inclusion in the 

program’s schedule. This approach reflects the insight that only as resource knowledge 

increases through exploration will BOEM learn more about the entire suite of available 

resources in order to make sound decisions about the composition of program areas along 

with the fiscal terms that should be included in specific future sales, as well as about 

which program areas to include in subsequent Five Year Programs. 

The lease sale design stage involves among other things, deciding whether to hold or 

delay a sale that is included in a Five Year Program, which blocks to offer, setting the 

sale terms, and issuing leases that meet FMV requirements. Deferring these issues to the 

lease sale stage rather than the earlier program formulation stage provides more 

flexibility and allows decisions to be made closer to the time when economic conditions 

that influence sale decisions are better known and somewhat easier to forecast. Once 

leases are issued, BOEM is limited in its authority to mandate delays in activities for 

purely economic reasons as companies have contractual rights related to potential 

development and production within the regulatory framework during their initial lease 

term. 

To formally assess the timeliness of offering program areas at the Five Year Program 

stage, BOEM subjected the assessment of undiscovered fields in each program area to an 

appropriate economic analysis to determine an area “hurdle” weighted average (i.e., 

barrels of oil equivalent (BOE)) price. The hurdle price is equated with the price below 

which delaying exploration for the largest potential undiscovered field in the sale area is 

more valuable than immediate exploration.26 Given that, at the hurdle price, immediate 

exploration for that prospect is optimal, the initial period is not a constraint, and full 

value may be realized by leasing now. By this means, the economic screen indicates 

whether the option value from waiting might exceed the expected value from offering 

any of the area in this Five Year Program. Thus, these hurdle prices will provide the

decision-maker information on whether there are at least some undiscovered field sizes 

which are likely to exist within the program area that are favorable to being leased now, 

assuming the market price is at or above the level of the hurdle price. This approach has 

the advantage of including areas in the Five Year Program which show economic 

promise, while deferring certain timing, composition and sale design decisions to the 

lease sale stage. This approach is a consistent methodology for conducting program area 

evaluations during the Five Year Program stage and avoids having to prematurely 

forecast future prices, cost levels, resource endowments and the state of technology. 

For this PFP, BOEM calculated the hurdle prices for two sample water depths in the 

Central GOM, and for the Chukchi and Beaufort Seas and Cook Inlet, offshore Alaska. 

The largest undiscovered field size deemed likely to be present in each area was selected 

for use in conjunction with cost estimates appropriate for the water depths and field sizes. 

These factors were inputted to an in-house dynamic programming model called WEB2 

 26 All else being equal, the largest field tends to have the highest net value per equivalent barrel of 

resources, making it the least likely field to benefit from a delay in being offered for lease.
89

(When Exploration Begins, version 2). The first column in Table 1 shows the input field 

sizes for each area. 

More specifically, the likely largest undiscovered field was identified using estimates of 

the 2011 Assessment.27 In general, the Assessment addresses undiscovered resources in 

a framework of field size and probability. The field size framework is provided by the 

USGS field size classes, which enables grouping fields. For example, there might be 2 

fields in a range of 2 - 4 million BOE (MMBOE); 3 fields in the next class covering 4 - 6 

MMBOE; and so on. There will be one “largest field” class which typically has a lone 

field in it, and no class of a larger size has any fields. It is that largest field size (assumed 

to be the middle of the class-size range) that was the basis for the hurdle price analysis. 

The reason for focusing on just the largest field is that the decision criterion using the 

hurdle price is intended to avoid the risk of withholding, on economic grounds, an area 

that might have at least one field that ought to be developed immediately. 

Regarding probability, the 2011 Assessment provides estimates of field counts at various 

levels of uncertainty. There are fewer fields estimated at a low level of uncertainty and 

more at a high level of uncertainty. Besides the percentiles, the 2011 Assessment also 

gives estimates at a mean level of uncertainty. This concept is defined in the 2011 

Assessment documentation, and it means roughly a middle level of uncertainty. The 

hurdle price analysis used estimates at the mean probability, an accepted and unbiased 

statistical approach in the presence of uncertainty.

Cost inputs for the WEB2 model came from the commercial FieldPlan modeling system 

and from data collected by BOEM for the socio-economic analysis of the Five Year 

Program (MAG-PLAN). The initial lease period limits and other fiscal terms are 

assumed to continue at current settings. The price model in WEB2 represents the range 

of possible future prices by a specific algorithm that models a so-called mean-reverting 

stochastic process. That means that the change in price from one time to the next is 

random and the probability of a step up or down reflects a tendency for movement toward 

the mean level. The start price for the price process is a single number representing the 

known current price when the lease is initiated. To find the hurdle price, the model is run 

for various start prices, until a start price that implies immediate exploration is found and 

no lower start price does so. The hurdle price is equated to that start price.

The lease operator was modeled as having flexibility to time the investment in 

exploration and separately, any investment in development. Each such decision is based 

on the contrast of the expected current value of the project with exploring or developing 

versus waiting. The operator must, of course, make any decision to explore or develop 

before the initial period limit. If it would be optimal to wait until the end, the operator 

must decide then to act or let the lease expire. Because WEB2 includes a random price 

diffusion process and accounts for the operator’s options to explore or wait and/or 

develop a discovery or wait, it can be called a “real options” model.

 27 http://www.boem.gov/Oil-and-Gas-Energy-Program/Resource-Evaluation/Gulf-OCS-RegionActivities/2011-Atlantic-Outer-Continental-Shelf-Assessment.aspx
90

Table 1 shows the assumptions made about area natural gas-oil ratios for determining the 

hurdle prices along with the oil and natural gas portions that ratio implies. WEB2 then 

estimates the BOE price shown in column 5 below, for which delaying exploration of an 

undiscovered field of the size shown in column 1 is more valuable than immediate 

exploration. The last two columns convert the BOE price to equivalent oil and natural 

gas prices using the natural gas-oil ratio typical of the area and a natural gas-to-oil value 

ratio that combines their thermal and market values. On a thermal basis, 5.62 mcf of 

natural gas provides the same heat content as a barrel of oil. On a market basis, this 

analysis has used oil-natural gas price pairs with a 40-percent economic value of natural 

gas relative to oil. For instance with the mid-price case, oil at $110/ bbl is 14.05 times 

the natural gas price of $7.83/mcf meaning natural gas sells at only (5.62/14.05) 0.4 times 

its relative heat content value. 

In the deepwater Central GOM for example, the natural gas-oil ratio means a BOE 

consists of 72 percent oil and 28 percent natural gas. Since both oil and natural gas will 

be sold but natural gas is only 40 percent as valuable as oil, the oil price equivalent of the 

$13 per BOE hurdle price is determined by dividing it by the 0.722 oil split plus 40 

percent of the 0.278 natural gas split to arrive at $15.60/bbl. At the market price ratio of 

14.05, the corresponding natural gas price is $1.11/mcf. As long as oil and natural gas 

prices are at least this high, WEB2 evaluation indicates that a minimum of one 

undiscovered field in this area is ready for immediate exploration. As oil is more 

valuable than natural gas, the hurdle oil price is lower in the deepwater Central GOM 

than in the shallow water even though the costs are greater and the largest field size is 

smaller. The high natural gas-oil ratio in the shallow water Central GOM means this 

sample field would likely be classified as a natural gas field. Because the hurdle price 

for these two water depths in the Central GOM are safely below all three program price 

cases as well as the current market price, BOEM considers these results to be 

representative of the other GOM program areas. Due to doubts about Arctic natural gas 

reaching a market, the hurdle price for the Chukchi and Beaufort Seas was determined 

using only the oil portion of BOE that will be sold. Cost assumptions were for a 

development that will be able to handle both the oil and natural gas volumes, but the 

natural gas is treated like produced water and not transported to market to be sold. For 

both the Chukchi and Beaufort Seas, BOE hurdle price is then only the oil price for this 

optimal timing analysis. But with higher prices as analyzed in the net benefits analysis in 

part IV of this document, the scenario natural gas price exceeds its transport cost, so 

natural gas will be produced and sold eventually under the program.
91

Table 1: Hurdle Prices

Largest 

Undiscovered 

Field 

(MMBOE)

Natural 

Gas-Oil 

Ratio

Hurdle Price

Oil part 

of Field 

BOE

Natural Gas 

part of Field 

BOE BOE

Oil 

Per

BBL

Natural 

Gas per 

mcf

Shallow Water 

Central GOM

(200 meters)

740 13.98 28.7% 71.3% $10 $17.48 $1.24

Deepwater 

Central GOM

(1200 meters)

670 2.16 72.2% 27.8% $13 $15.60 $1.11

Cook Inlet 175 1.19 82.5% 17.5% $34 $37.98 $2.70

Chukchi Sea 733 

(only oil) $27 $27 *

Beaufort Sea 444 

(only oil)

$37 $37 *

*The natural gas transportation cost exceeds the prorata natural gas hurdle price, meaning oil would have to 

subsidize the sale of natural gas. Instead, the natural gas share of BOE likely would be reinjected.

This analysis indicates that in the Central GOM, current oil price is about six times, and 

in Alaska two times, the amount needed to justify holding a sale purely on the basis of the 

hurdle price criterion. The significant uncertainty surrounding the OCS exploration and 

development economics must be considered in the formulation of decision criteria for 

determining timing for lease issuance. At the lease sale stage, BOEM will compare thencurrent prices to these hurdle prices. If prices have dropped below these hurdle levels, 

BOEM will conduct additional analyses to determine whether or not to hold a sale and 

the specific parameters of that sale. Once the timing screen criteria are met at the Five 

Year Program stage, additional decisions on selected portions of these areas, along with 

appropriate lease terms and conditions, are included in the lease sale stage. This allows 

the more specific decisions to be made when uncertainty is reduced. The hurdle price 

analysis is another element helping ensure the OCS is being managed to generate the 

public’s FMV for OCS resources.

Size of Lease Sale

(1) Assess the effect of recently raised minimum bid-levels within the areawide 

leasing framework before each lease sale to encourage timely leasing of the 

offered blocks 

(2) Other.

Discussion: After an affirmative decision to hold a lease sale, the next decision is 

selection of the leasing framework to be used for the sale. Since 1983, GOM lease sales 

have been conducted under the areawide leasing (AWL) format with, for the most part, 
92

relatively low minimum bid requirements. The State of Louisiana requested on several 

occasions the use of schemes other than AWL, similar to those that were in place prior to 

1983, such as industry nomination/agency tract selection (N/TS), which would tend to 

sell fewer tracts and allow more focused environmental analysis. BOEM contracted for 

an AWL Study evaluating alternative leasing schemes and received the final report in 

2010.28 

The AWL Study simulates OCS activity on leases sold over the next 50 years under the 

status quo leasing system of areawide sales, initially offering 8,000 GOM blocks per 

year, declining thereafter as accumulating information weeds out the barren blocks. The 

status quo is compared to, among other options, two restricted sale sizes - one-half the 

AWL scale (AWL half or AWLH) and an N/TS-scale offering of 400 blocks per year 

similar to sales before AWL. 

Results in Table 229 indicate that N/TS would sacrifice substantial activity for increased 

high bids but would appear to provide little overall fiscal gain, because the loss and delay 

of royalty, rental, and tax30 revenues would offset the higher bonus promised by N/TS 

relative to AWL.

Table 2: Long-term Assessment of Criteria under Alternative Lease Sale Scenarios

Performance Measure (Change from 

baseline offer of 8,000 tracts/year)

Cut Offerings in Half

(offer 4,000 tracts/year)

Pre-1983 Scale

(offer 400 tracts/year)

 Average Annual Tracts Sold -31% -80%

Exploration Wells Drilled -16% -52%

Number of Fields Discovered -7% -28%

Discounted High Bids +9% +39%

Total Production -2% -10%

Expedited (discounted) Production -4% -17%

Discounted Federal Leasing 

Revenues

-1% +5%

Discounted Leasing + Tax Receipts -1% 0%

Coastal State Economic Benefits -9% -34%

State Revenue Sharing (uncapped) 2% +10%

This long-term comparison presumes the same leasing framework will continue to be 

used over each of ten future Five Year Programs thereby incorporating enough time for 

significant evolution in technology, resource estimates and oil prices. Long term trends 

in those fundamental variables dominate the results reported. The model used for the 

AWL Study suggests somewhat smaller activity losses and larger bonus gain over just the 

next Five Year Program from reduced sale sizes. A near-term comparison of AWL and 

N/TS was extracted from one of the study’s sub-models, the Area Model.

 

28 Policies to Affect the Pace of Leasing and Revenues in the Gulf of Mexico, December 2010, BOEMRE 

2011-014, available at boem.gov. http://www.boemre.gov/econ/PDFs/ExternalStudies/2011_014/Part2.pdf

29 This table is extracted from the more extensive table in Ibid, pages 159-164. 30 The effective tax rate in this study is assumed to be one-half the nominal tax rate. 
93

The results of this analysis suggest that the near-term reductions in leases sold, wells 

drilled, and discoveries made under the reduced sale sizes are less severe than the AWL 

Study reports in the long-term. Under N/TS, near-term leases sold would be 75 versus 80 

percent less long term, wells drilled would be 23 percent less near term versus 52 percent 

less long term, and discoveries 10 percent less near term versus 28 percent less long term. 

Under AWLH, near-term leases sold would be 22 versus 31 percent less long term, wells 

drilled 4 versus 16 percent less long term, and discoveries 3 versus 7 percent less long 

term. This disparity is consistent with the notion that in the near term, restricted sale 

sizes have a better chance of including the richer set of undiscovered prospects. In the 

out years when the remaining prospects are less numerous and obvious, the AWL scheme 

increases the chances that someone will acquire an overlooked opportunity not 

recognized by a nomination process driven by consensus expectations.

The increased bonus amounts near term for the AWLH are roughly in line with the long 

term comparison (10 versus 9 percent more long term), but the near term gain of bonus 

under the N/TS framework (115 percent more) is 3 times the proportion shown in the 

long term results (39 percent). This disparity suggests that less aggressive bidding 

competition will be induced by N/TS relative to AWL in the out years after earlier 

activities have reduced the uncertainty about the value of still available tracts. However, 

the long term analysis in the fuller AWL Study finds that offsetting reductions in rentals, 

royalties, and taxes eliminate the net fiscal gain promised by higher cash bonus bids 

under N/TS leasing. There is no obvious reason that a similar proportional offset would 

not occur for the lease subset sold under the next Five Year Program alone.

In summary, the study findings suggest the N/TS framework reduces leasing from the 

AWL framework in about the same proportion near term as long term, drilling and 

discovery by less than half as much near term as long term, and increases aggregate 

bonuses about three times as much near term as long term. However, the AWL Study 

does not justify accepting even the less severe losses associated with a switch to N/TS 

leasing framework for the upcoming Five Year Program in anticipation of generating 

increased fiscal revenue. This is the case because the increase in cash bonus bids per 

block leased under N/TS would be largely offset by fewer blocks leased, less drilling, a 

reduced pace of discovery, lower rentals and royalties, and less annual future production 

of OCS oil and natural gas from newly issued leases.

For the GOM, where there is extensive infrastructure to support the oil and natural gas 

industry as well as a long history of exploration and development, BOEM believes it is 

advantageous to use the relatively flexible AWL model, while employing other tools, like 

minimum bid requirements, to help direct activity towards blocks that are considered to 

be the most valuable and economically mature. Setting a meaningful minimum bid level 

allows the auction market to determine which blocks are perceived to have the lowest 

values, so that the leasing program could make these blocks available in future sales. 

Improved technology would lower exploration and production costs and perhaps reduce 

drilling risks on these blocks. The block values would increase and they could be 

reoffered for sale at a more favorable time for society. 
94

BOEM can set relatively high minimum bid levels to limit the resulting leasing to those 

blocks which the market judges to be favorably valued. Such blocks characteristically 

have an anticipated rate of growth in value less than the equivalently measured 

opportunity cost of holding them unsold. If a block has a perceived economic value less 

than the minimum bid, this will be revealed in the competitive auction market and the 

block will not be leased. So, the minimum bid can be structured specifically to ensure 

that certain blocks whose current value is either unknown or positive, but less than the 

level needed to justify selling at the present time, are in fact retained in the government’s 

inventory. This is one way of ensuring that the blocks which have already matured 

economically are sold first, while those with the highest potential for economic growth 

are retained for a later sale, without actually knowing before a sale which blocks fall into 

each category. This strategy is consistent with the goal of maximizing the economic 

value of OCS resources to the Nation. 

Rather than adjusting the size of the sale from the outset, BOEM will use the minimum 

bid (in conjunction with other fiscal terms) as a way to limit the sale size by allowing the 

market to choose which tracts to lease. BOEM will continue to evaluate the minimum 

bid level to ensure that it helps to maintain competition and to encourage timely leasing 

of offered blocks. The minimum bid is one of several fiscal policy elements of the saleterms decision discussed later in this document. 

Nonetheless, BOEM is exploring options for a more focused approach to leasing than 

AWL in certain instances as discussed in part I of this document. In particular, offshore 

Alaska, the Chukchi Sea and Beaufort Sea program areas are less explored than GOM 

areas and require extensive environmental analysis and coordination with other Federal 

agencies, Alaskan natives, the scientific community, industry, and state and local 

governments before leasing decisions can be made. 

While BOEM has determined that it is appropriate to continue areawide leasing in the 

GOM, as described above, BOEM will not be conducting areawide leasing in the Arctic, 

consistent with rigorous internal analysis as well as a number of outside

recommendations to develop alternative leasing approaches for Arctic areas.31 Rather, 

potential sales are deliberately set late in the five year program schedule to allow for 

further analysis and information-gathering. These would be geographically targeted in 

scope, in order to achieve an appropriate balance between making resources available 

while limiting conflicts with environmentally sensitive areas and subsistence use by 

making certain determinations from the outset about which blocks within the planning 

areas are most suitable for leasing

Sale Terms

 31 Outside groups that have recommended adopting alternatives to areawide leasing for frontier areas like 

the Arctic include the USGS and the National Commission on the BP Deepwater Horizon Oil Spill and 

Offshore Drilling. 
95

(1) Leave current minimum bid levels, rental rates, fixed royalty rates, and lease 

terms as the baseline, subject to sale-by-sale reconsideration. 

(2) Other.

Discussion: After deciding to hold a sale and the framework to be used, the next set of 

decisions deals with the sale terms to be offered, largely the fiscal terms and duration of 

the initial period of the lease. The fiscal terms include an upfront minimum bid level, 

annual rental payments and royalties. All of the financial obligations (bonus payments, 

rentals and royalties) reflect the value of the lessor’s (i.e., Federal government) property 

interest in the leased minerals and are fiscal components of FMV. When determining the 

appropriate lease terms for a sale, BOEM must balance the need to receive FMV with the 

other policy goals in the Act, such as expeditious and orderly development of OCS 

resources. BOEM evaluates sale terms on a sale-by-sale basis and has adjusted them in 

recent sales in response to emerging market conditions, competition, and the prospective 

nature of available OCS acreage. 

In addition, BOEM, jointly with the Bureau of Land Management, recently completed a 

contract with IHS-CERA for a study entitled “Comparative Assessment of the Federal 

Oil and Gas Fiscal Systems.”32 The study compared other countries’ petroleum 

extraction fiscal systems and terms to the U.S. Federal system. Once that study is fully 

assessed, the results and findings should be helpful in informing future decisions about 

whether and how to revise applicable fiscal terms to best balance the objectives of the 

offshore program. 

Minimum Bid

The minimum bid serves as a floor value for acquiring the rights to OCS acreage. 

Historically, its primary utility has been to ensure receipt of FMV on blocks for which 

there is insufficient data to make a tract evaluation, or existing geologic or economic 

potential of the blocks is inadequate to support a positive tract value. The minimum bid 

in the GOM for water depths of 400 meters or deeper was recently increased from $37.50 

to $100 per acre starting with Western GOM Sale 218 held in December 2011. GOM 

minimum bid remains at $25 per acre in water depths less than 400 meters. The most 

recent minimum bids in Alaska were $25 per hectare (about $10 per acre) in the Chukchi 

Sea, Cook Inlet and in Zone B (deeper water areas) of the Beaufort Sea; and $37.50 per 

hectare (about $15 per acre) in Zone A (near shore areas) of the Beaufort Sea. 

As explained above, the minimum bid also can be used to help control the pace of 

leasing, especially under an AWL framework in which many marginally valued blocks 

are offered for sale and, when bid on, tend to receive low winning bids. In such large 

sales, increasing the minimum bid level can have a significant effect on the number of 

blocks leased, but may impact aggregate cash bonuses very little or even cause them to 

increase, since raising the minimum bid level can push low bids to higher levels. 

 32 http://www.boem.gov/Oil-and-Gas-Energy-Program/Energy-Economics/Fair-Market-Value/Fair-ReturnReport.aspx
96

Rentals

During the initial period of a lease and before commencement of royalty-bearing 

production, the lessee pays annual rentals which generally are either fixed or escalating. 

The primary use of escalating rentals is to encourage faster exploration and development 

of leases, and earlier relinquishment when exploration is unlikely to be undertaken by the 

current lessee. Escalating rentals also are used when the initial lease period is extended 

following the spudding of a well, which in some cases must be targeted to be drilled to a 

depth of at least 25,000 feet subsea in the GOM.

The prevailing GOM rental rates are shown in Table 3. Rental rates were last adjusted in 

Central GOM Sale 208, March 2009. Alaska rental rates range from $2.50 to $30.00 a 

hectare (about $1.00 to $12.00 per acre), with escalating rentals used in the last four sales 

(Beaufort Sea Sales 186, 195 and 202 and Chukchi Sea Sale 193).

Table 3: GOM Rental Rates per Acre or Fraction Thereof

Water Depth 

in meters 

Years 1-5 Years 6, 7, and 8+

0 to <200 $7.00 $14.00, $21.00, $28.00

200 to <400 $11.00 $22.00, $33.00, $44.00

400 to <800 $11.00 $16.00

800+ $11.00 $16.00

Rental payments also serve to discourage lessees from purchasing marginally valued 

tracts too soon because companies will be hesitant to pay the annual holding cost to keep 

a low-valued or currently uneconomic lease in their inventory. Rental payments provide 

an incentive for the lessee to timely drill the lease or to relinquish it before the end of the 

initial lease period, thereby giving other market participants an opportunity to acquire 

these blocks. 

Royalties

The government also reserves a royalty interest, which is a share of the value of 

production at the lease, if the lease goes into production. Royalty rates can have a 

significant impact on bidder interest and are a key fiscal parameter in the calculation of 

the underlying economic value for a block. Considered in combination with increased 

resource prices, perceived improvements in discovery and extraction technology, 

especially in deep water, and the competitive market for OCS acreage, BOEM raised 

GOM deepwater royalty rates for new leases from 12.5 to 16.67 percent in 2007, then to 

18.75 percent in 2008. GOM shallow water royalties for new leases increased from 

16.67 to 18.75 percent in 2008. Currently, all COM royalty rates are 18.75 percent. 

Alaska sales have utilized a 12.5 percent royalty rate for the past 30 years. 

Initial Period of the Lease
97

In cases where a high bid meets the FMV requirements, the lease rights are issued to the 

lessee for a limited term called the initial period. The Act sets the initial period at 5

years, or up to 10 years “where the Secretary finds that such longer period is necessary to 

encourage exploration and development in areas because of unusually deep water or other 

unusually adverse conditions....” The initial period promotes expeditious exploration 

while still providing sufficient time to commence development. 

BOEM recently changed the lease terms in the deepwater GOM to account for 

improvements in deepwater technology and the decreased time necessary for exploration 

and infrastructure development. Using shorter initial lease periods for shallower areas 

helps to encourage timely development by providing a built-in incentive for drilling. 

Current GOM initial lease periods are shown in Table 4.

Table 4: GOM Initial Periods

Water Depth

in meters 

Initial Periods

0 to <400 5 years extended to 8 years if a well is spudded during the initial 5-year 

period targeting hydrocarbons below 25,000 feet TVD SS*

400 to <800 5 years extended to 8 years if a well is spudded

during the initial 5-year period

800 to <1,600 7 years extended to 10 years if a well is spudded

during the initial 7- year period

1,600+ 10 years

*Total Vertical Depth Subsea

Lease terms on the Alaska OCS vary by area. Former leases in Cook Inlet had a 5-year 

initial period. In other areas, initial periods are from 8 to 10 years because of the 

historically longer lead times needed for exploration due to seasonal factors such as sea 

ice, remoteness and availability of suitable drilling platforms. 

Bidding Systems

(1) Continue use of a single round sealed bid auction format with a cash-bonus 

competitive bidding system, subject to periodic review. 

(2) Other. 

Discussion: The next step in ensuring FMV is to identify the auction format and 

determine which competitive bidding system to use. The Act requires the use of a sealed 

bid auction format with a single bid variable on tracts no larger than 5,760 acres. The 

Act allows for different competitive bidding variables including royalty rates, bonus bids, 

work commitments, or profit sharing rates. The specific competitive bidding systems 

available under the Act and currently in the regulations in Title 30 of the Code of Federal 

Regulations at 560.110 mostly provide for variations of the cash bonus/royalty rate 

approaches. 
98

In evaluating which competitive bidding terms to use, BOEM considers the goals of the 

Act, the costs and complications of implementing the selected approach, the ability of the 

bidding variables to accurately identify the bidder offering the highest value, and the 

economic efficiency of the selected approach. Some of the alternative approaches, such 

as profit sharing and work commitments, could have beneficial aspects, but they are 

difficult to apply. Profit sharing systems applied to production values could result in 

operators producing closer to the socially optimal output and rates than with royalty 

systems. However, these gains would likely be offset by the need for extensive 

administrative resources to audit and verify the measure of profits. Similarly, work 

commitment bids could be beneficial in identifying which bidder has the most optimistic 

view of geologic prospects. However, this system encourages wasted expenditures, 

especially in new areas where there is little resource knowledge, as well as difficulty in 

identifying, measuring and tracking qualified expenditures. 

When Congress amended the Act in 1978, it instructed DOI to experiment with 

alternative bidding systems for OCS leasing, primarily to encourage participation of 

small companies by reducing upfront costs associated with the traditional cash-bonus bid 

system. DOI used four alternative bidding systems from 1978 through 1982. All the 

tested systems maintained the cash bonus bid, but varied the contingency variable with 

use of a sliding scale royalty which varied depending on the rate of production, a fixed 

net profit share, and a 12.5 and 33 percent royalty rate. These systems were not found to 

enhance program performance compared to the then-prevalent 16.67 percent fixed 

royalty rate system in shallow water. Among other things, they did not increase 

participation by small companies; were significantly more complex to administer; 

distorted bids, which made it more difficult to identify the high bid; and often were not 

beneficial to the taxpayer. As a result, BOEM has chosen to use the cash-bonus bidding 

system subject primarily to a mid-range fixed royalty rate since 1983.

Bid Adequacy Review

(1) Continue use of the current, two-phased bid adequacy process, subject to 

revision as appropriate.

(2) Other.

Discussion: Following a lease sale, the high bids on each block are evaluated to 

determine whether they satisfy the FMV requirements for acceptance. The bid adequacy 

process in use since 1983 evaluates high bids in two phases. The first phase assesses bid 

adequacy and relative block value by applying long-standing rules and procedures to 

determine whether acceptance of the high bids is consistent with the objective of ensuring 

receipt of FMV. The assessments involve consideration of such factors as the number of 

bids received on the block, the distribution of those bids as well as the ranking of high 

bids across blocks, and BOEM’s assessment of the block’s geologic and economic 

viability. If not accepted during this first phase, high bids are evaluated in a second phase 

using detailed analytical assessment procedures to generate an independent evaluation of 

each remaining block’s value. This procedure is employed in conjunction with the 
99

distribution of the losing bids on each block and with an adjustment for the delay cost, if 

any, from not selling the block in the current sale to determine each block’s ultimate 

reservation “price”. This price cannot be lower than the minimum bid level used for all 

blocks within a comparable water depth range. If the high bid does not exceed the 

reservation price, the bid is rejected and the block is available to be reoffered at the next 

lease sale in that area. Thus, BOEM reviews all high bids received and evaluates all 

blocks using some combination of block-specific bidding factors and detailed blockspecific resource evaluation factors to ensure that FMV is received for each OCS lease 

issued. FMV and the bid adequacy process also are discussed in part IV.F of this 

document.
100

IV. PROGRAM ANALYSIS

A. Analysis of Energy Needs 

Introduction

Energy plays a central role in the operation of the U.S. economy. In recent years, 

American consumers spent well over a trillion dollars a year on energy, more than 8 

percent of gross domestic product (GDP). As noted in its report “Annual Energy Review 

2010”33, the Energy Information Administration (EIA) recognizes the United States as a 

world leader in total energy consumption and that it imports almost 30 quadrillion British 

thermal units (Btu) of energy each year to satisfy almost 100 quadrillion Btu of total 

consumption in transportation, industrial, commercial, and residential sectors. Although 

the United States is a leading producer of coal, natural gas, and oil, growing demand for 

energy in developing countries, especially China and India, means that competition for 

limited energy sources may become more intense. EIA predicts costs for imported 

energy will increase in real terms over the coming decades. To address these issues, the 

United States needs to pursue investments in renewable energy technologies and existing 

domestic energy production throughout the United States, both onshore and on the OCS. 

Section 18 of the Act requires the Secretary to formulate an OCS leasing program to 

“best meet national energy needs for the five-year period following its approval or reapproval.” In formulating the program, the Secretary must consider “the location of such 

[OCS oil- and gas-bearing] regions with respect to, and the relative needs of, regional and 

national energy markets.” The long lead times required for OCS oil and natural gas 

leasing and permitting and production activities, along with the extended life of oil and 

natural gas projects, dictate that the analysis of energy needs look at long term 

projections beyond the end of the five-year schedule of sales in the program. The energy 

needs analysis conducted here relies heavily on EIA energy forecasts. These forecasts 

are carried out to 2035, so this contextual analysis uses this shorter period rather than the 

40 to 50 years used for other analyses in this document.

High and volatile energy prices, especially for crude oil, and continued dependence on 

foreign sources, raise important energy policy issues about supply options and their 

effects on the economy and the environment. The following sections discuss national and 

regional energy needs in the presence of a large, continuing gap between domestic energy 

production and consumption; ongoing concern over the amount of U.S. dollars sent 

overseas; and potential supply contributions of OCS production and other sources of 

energy. 

 33 EIA, Annual Energy Review 2011; http://www.eia.gov/totalenergy/data/annual/
101

Forecast of National Energy Needs

Domestic energy security and dependence on unreliable sources of oil imports are key 

topics in the national energy debate, aggravated by a challenging international political 

climate, increasing competition for resources, energy supply instability, and price 

volatility. EIA’s AEO 2012 forecasts changes in domestic energy production, energy 

imports, and energy consumption over 25 years from 2010-2035.34 While there are many 

factors that simultaneously affect such forecasts, the primary engine behind the projected 

changes in domestic production-consumption gaps and import requirements are 

assumptions about economic growth. The average annual GDP growth rate for the U.S. 

economy projected in AEO 2012 is 2.6 percent. Although the decreasing ratio of energy 

expenditures to GDP over time from 7.1 percent in 2012 to 4.4 percent in 2035 reflects an 

extended economic recovery period and declines in energy intensity, uncertain supplies 

could contribute to tight petroleum markets, which could raise oil prices sufficiently to 

cause the energy expenditure rate to creep back up, constraining economic growth. 

In 2010, the United States accounted for approximately 21 percent of the world’s oil and 

22 percent of the world’s natural gas consumption.35 EIA and the International Energy 

Agency (IEA) project the quantity of energy demand in the United States and in the 

world will increase 12 percent and 33 percent36 in the coming decades as a result of 

economic growth in the United States and in developing economies. Depending on 

economic access to non-Organization of Petroleum Exporting Countries (OPEC) 

resources and resulting OPEC price behavior, world crude oil price estimates for 2035 

range from $55 to nearly $200 per barrel (expressed in 2010 dollars). New production 

from domestic areas such as the GOM and Alaska OCS would help meet the continued 

demand for energy and help retain the diversity of supply, helping to mitigate the effects 

of disruptions on imports and cushioning the consequences of hurricanes and other 

disruptive forces on parts of the GOM as well as on refining and processing operations. 

Oil and Natural Gas Production Estimates

Petroleum and natural gas supply nearly 63 percent of the Nation’s energy needs. EIA 

forecasts that net U.S. demand for oil and natural gas will increase over the next two 

decades. EIA projections, shown in Table 5 below, indicate that while the share of 

energy obtained from oil and natural gas decreases slightly, the amount of energy 

obtained from oil and gas increases between 2012 and 2035.37 Accordingly, the 

Nation is projected to continue to rely heavily on oil and natural gas to meet its energy 

needs, even as alternative sources of energy supply an increasing share of our energy.

 34 This analysis uses estimates for energy projections based on the reference case in the AEO 2012 Early 

Release. The following estimates will vary somewhat from those included in the complete AEO that will be 

released later in 2012. 35 BP Statistical Review 2011; 

http://www.bp.com/sectionbodycopy.do?categoryId+75008contentId+7068481 36 IEA, World Energy Outlook 2012; http://www.worldenergyoutlook.org 37 The AEO’s reference case is a policy neutral forecast based on the most likely trajectories for primary 

energy prices, technology adoption, and global economic growth. It incorporates only existing laws, rules 

and regulations, taking into account the effective start and end date of each.
102

Table 5: U.S. Energy Consumption (quadrillion British thermal units (Btu))

2012 2015 2020 2025 2030 2035

Liquid Fuels 

and Other 

Petroleum

36.11 36.89 37.15 37.04 37.31 38.00

(37.3%) (37.8%) (36.8%) (36.0%) (35.4%) (35.2%)

Natural Gas 25.67 25.99 26.13 25.80 26.49 27.11

(26.5%) (26.6%) (25.9%) (25.1%) (25.2%) (25.1%)

Other

35.02 34.78 37.65 40.09 14.49 42.86

(36.2%) (35.6%) (37.3%) (38.9%) (39.4%) (39.7%)

Total 96.80 97.66 100.93 102.93 105.29 107.97

Source: EIA Annual Energy Outlook 2012 (Reference Case) Note: Numbers in parentheses are percentages 

of total. Totals may not sum to column totals due to independent rounding.

Table 6 summarizes EIA’s forecast for U.S. crude oil production from 2012 to 2035.38 It 

shows projected offshore crude oil production in the GOM increasing from 1.5 million 

barrels (MMbbl) per day in 2012 to 1.97 MMbbl in 2020, or a little less than half a 

percent annually. From 2020 to 2030, production would decrease to 1.55 MMbbl but 

would return to 1.64 MMbbl by 2035 as new large development projects are started over 

time. Over this period, GOM production accounts for approximately 25 percent of U.S. 

domestic oil production. 

Table 6: U.S. Crude Oil Production (MMbbl of oil per day)

2012 2015 2020 2025 2030 2035

Gulf of 

Mexico OCS

1.50 1.72 1.97 1.62 1.55 1.64

(25.5%) (27.5%) (29.3%) (25.2%) (24.3%) (26.8%)

Other

4.38 4.54 4.76 4.80 4.82 4.48

(74.5%) (72.5%) (70.7%) (74.7%) (75.7%) (73.2%)

Total 5.88 6.26 6.73 6.42 6.37 6.12

Source: EIA Annual Energy Outlook 2012 (Reference Case) Note: Numbers in parentheses are percentages 

of total. Totals may not sum to column totals due to independent rounding. EIA does not publish Alaska 

OCS numbers separately. 

Overall, total U.S. offshore and onshore crude oil production would increase from 5.88 

MMbbl per day in 2012 to 6.12 MMbbl per day in 2035. Production would be higher in 

the later years of the forecast when real prices are predicted to be higher. The higher 

 38 EIA projections assume that all laws and regulations remain intact, i.e., EIA does not make assumptions 

as to which legal and regulatory proposals will eventually be adopted.
103

levels of production would stem mainly from increased onshore oil production, 

predominately from the application of recent technology advances in the development of 

tight oil resources,39 and the slowing of Alaska’s oil production decline by the 

development of offshore projects. Even with the 5 percent increase in production, 

imported oil will continue to account for a very large share of domestic consumption. 

While EIA projections show a decrease in imports of approximately one half percent per 

year between 2012 and 2035, coupled with a slight increase in domestic production over 

current levels, imports still would supply nearly 40 percent of the liquid fuel used in the 

United States. Projected increases in domestic production, refinery gains, ethanol and 

biodiesel, and liquids from gas, coal, and biodiesel all contribute to the overall gain in 

domestic liquid fuels production by 2035.

Table 7 summarizes EIA’s forecast of U.S. natural gas production from 2012 to 2035. 

The projected large increases in domestic natural gas production come from the 

abundance of discovered and undiscovered shale gas resources in the United States and 

increased exploration and development of these resources. The combination of two 

technologies, horizontal drilling and hydraulic fracturing, has made it economic to 

produce shale gas at today’s prices. These discoveries and technologies have resulted in 

a large expansion of domestic supplies, holding down natural gas prices even as oil prices 

have risen. Shale gas production in the United States grew from 1.0 tcf in 2006 to 4.8 tcf, 

or 23 percent of total U.S. dry natural gas production, in 2010. EIA expects another 

threefold increase by 2035.

Table 7: U.S. Natural Gas Production (Trillions of Cubic Feet/Year)

2012 2015 2020 2025 2030 2035

Gulf of 

Mexico 2.12 2.11 2.63 2.38 2.51 2.60

(9.0%) (8.91) (10.43%) (9.15%) (9.37%) (9.34%)

Other

21.55 21.56 22.58 23.62 24.28 25.24

(91.0%) (91.09%) (89.57%) (90.85%) (90.63%) (90.66%)

Total 23.67 23.67 25.21 26.0 26.79 27.84

Source: EIA Annual Energy Outlook 2012 (Reference Case) Note: Numbers in parentheses are percentages 

of total. Totals may not sum to column totals due to independent rounding. EIA does not publish Alaska 

OCS numbers separately. 

Much of the growth in natural gas production comes from shale plays with high 

concentrations of natural gas liquids and crude oil, which have a higher value in energy 

equivalent terms than dry natural gas. EIA anticipates the United States will become a 

net exporter of liquefied natural gas (LNG) by 2016, exporting as much as 0.74 tcf by 

2035. U.S. net pipeline imports of natural gas, primarily from Canada and Mexico, are 

expected to decline by 15 percent from 2012 to 2035, while pipeline gas exports to 

Mexico would grow by over 400 percent over the same period. This conversion from net 

 39 There are very recent indications that increases in tight oil production, fueled by advances in technology, 

may be greater than anticipated. However, it is too early to determine whether long-term trends may be 

affected.
104

importer to exporter reflects reserve depletion in foreign countries, a growing demand 

from other markets outside of the United States, and an abundant natural gas supply and 

accompanying low prices in the United States. 

The AEO 2012 shows annual offshore natural gas production for the GOM increasing 

from 2.12 tcf to 2.60 tcf over the period studied, representing an increase of a little less 

than 1 percent annually. Unlike onshore production, EIA predicts GOM natural gas 

production will decrease slightly in the intermediate term since many undiscovered 

offshore fields are uneconomic at the natural gas prices projected over the next few years. 

Total offshore natural gas production fluctuates between 2.0 and 2.8 tcf per year over the 

period studied as new large projects directed towards liquids development are started 

over time. While GOM natural gas production thus contributes a small percentage of the 

Nation’s natural gas supplies over the next two decades, it remains an important and 

stable source of domestic natural gas.

EIA expects the Nation to rely on more oil and natural gas to meet its yearly energy 

demands over the next 20 years, even as alternative sources of energy supply an 

increasing share of energy. Estimates by USGS and BOEM indicate the majority of the 

Nation’s remaining oil and natural gas resources lie on Federal OCS and onshore lands. 

Therefore, continued oil and natural gas leasing activity in the GOM, the primary OCS 

region currently available for energy production and development activities, is clearly in 

the national interest. Outside the GOM, the Alaska OCS holds promise and lease sales 

are proposed in the Chukchi Sea, Beaufort Sea, and Cook Inlet program areas. 

Production from other OCS areas also could help meet the country’s energy needs. 

However, after the Deepwater Horizon event and in line with recently implemented 

regulations to minimize the possibility of such events in the future, the Secretary’s 

weighing of section 18 factors results in a cautious approach toward leasing in new areas 

and is reflected in a decision for this upcoming Five Year Program that focuses on 

activities in the GOM and in selected areas of the Alaska OCS.

Meeting Energy Needs

Contribution of OCS Oil 

EIA expects the quantity of petroleum consumed in the United States to grow from 19.04 

MMbbl per day in 2012 to 20.08 MMbbl per day in 2035, an average annual increase of 

about 0.2 percent. This growth would be led by the industrial sector, which would 

increase from around 20 percent of U.S. petroleum consumption in 2012 to over 22 

percent in 2035. The transportation sector will continue to account for the vast majority 

of petroleum consumption, with projections showing that the transportation sector is 

expected to consume nearly 75 percent of petroleum in 2035, a small increase compared 

to 73 percent today, owing to modest projected economic and employment growth, which 

puts downward pressure on vehicle miles traveled. 
105

From a national energy and economic security standpoint,40 OCS production is an 

important part of U.S. efforts to maintain domestic oil supplies to meet domestic demand 

and as a means to reduce exposure to the unpredictability and price volatility of some 

foreign oil sources. In 2012, offshore oil will account for more than 27 percent of 

domestic oil production. The GOM is the second largest supplier of crude oil for the U.S. 

market after Canada, and ahead of Saudi Arabia. From 2000 to 2010, deepwater 

production of oil from the GOM increased by 70 percent,41 from 270 MMbbl per year to 

over 461 MMbbl per year, due mostly to the development of very large fields with high 

flow rates located in over 1,000 feet of water. The increase in deepwater production 

served to mitigate the decline in other categories of domestic production over the same 

10-year period and mitigate its economic effects. This trend should continue, due to high 

levels of leasing activity in GOM deep water. 

According to EIA, imports of crude oil account for 47 percent of domestic liquid fuel 

demand in 2012 but will decline to 37 percent of demand in 2035. In 2011, crude oil 

imports decreased to their lowest level since 1999, down 12 percent from their peak in 

2005. Even with recent decreases in oil imports, their contribution to the U.S. balance of 

payments deficit has been significant and has represented a growing percentage of the 

U.S. balance of payments.42 From 2006 to 2012, the percent of the monthly U.S. goods 

and services trade deficit attributed to petroleum products increased from 34.8 percent in 

January 2006 to over 56 percent in the beginning of 2012.43 Estimates by the Bureau of 

Economic Analysis (BEA) of annual petroleum and petroleum product imports, show the 

export of nearly half a trillion dollars in 2011 from the United States to other countries.44

Although the decline in the U.S. balance of trade from 2001 to 2011 was largely due to 

increased world oil prices, the contribution of a weakening U.S. dollar was also a factor, 

given that oil prices are denominated in dollars.45 As Chart 1 indicates, given a weaker 

dollar, oil prices have risen more rapidly in U.S. dollars than in euros.

 40While oil prices are set on the world market, making it difficult to insulate the Nation’s economy from 

price changes, maintaining secure supplies of petroleum can help discourage temporary supply disruptions 

or threats thereof, and consuming domestic supplies limits the amount of dollars sent overseas, reducing the 

balance of payments deficit.

41 BOEM; http://www.gomr.boemre.gov/homepg/offshore/deepwatr/summary.asp 42 BEA, 2012 (Table 2a); http://www.bea.gov/iTable/iTable.cfm?ReqID=6&step=1 43 United States Census Bureau; http://www.census.gov/foreigntrade/statistics/graphs/PetroleumImports.html

44 BEA, 2012 (Table 2a); http://www.bea.gov/iTable/iTable.cfm?ReqID=6&step=1 45 As the dollar weakened, oil became relatively more expensive to U.S. consumers than to those with 

stronger currencies, resulting in less pressure to reduce demand abroad and greater pressure on available 

world supply than there otherwise would have been. This was another factor contributing to increased 

overall world prices. 
106

Chart 1: International Crude Oil Prices

Source: EIA data at http://www.eia.gov/dnav/pet/pet_pri_spt_s1_a.htm and

http://www.econstats.com/fx/fx_aa1.htm for exchange rates.

Not only did world oil prices increase rapidly through the summer of 2008, but the 

declining value of the dollar exerted additional upward pressure on overall U.S. import 

costs. The dollar amount spent on oil imports for the first 8 months of 2008 surpassed the 

amount spent in all of 2007. Although average prices dropped over 40 percent from 2008 

to 2009, by 2011 world oil prices had risen sharply and EIA price projections over the 

next two decades estimate over $130 dollars per barrel of oil in 2010 dollars. Increased 

world oil prices and increases in crude oil consumption by economies such as those of 

China and India, could have serious effects on the U.S. economy. Domestic production 

of oil, and to a lesser extent natural gas, from the OCS reduces the amount of oil that 

must be imported from abroad, thereby lessening the risk to the U.S. economy posed by 

supply disruptions.

Contribution of OCS Natural Gas

Natural gas consumption has risen significantly over the last decade as new gas-fired 

generation plants have been built and placed into service. The increase in domestic 

demand, as well as plans for LNG exports, raise concerns that the volumes of natural gas 

available from traditional sources —involving both domestic production and imports 

from Canada and Mexico—might not be able to keep pace with growing U.S. use. 

However, significant increases of domestic natural gas production from large shale gas 

plays and production areas with high concentrations of natural gas liquids and crude oil 

alleviate these concerns.46 According to the AEO 2012, natural gas production in the 

 46 The presence of oil and natural gas liquids, which can fetch higher prices in today’s markets, provides 

incentive to pursue these plays even in the face of low natural gas prices.

0

20

40

60

80

100

120

Year

International WTI Crude Oil Prices

Price in U.S. Dollars Price in Euros
107

United States from shale gas resources has increased considerably to meet growing 

demand and will continue to do so in the future. USGS estimates the United States has 

over 482 tcf of unproved technically recoverable resources of shale gas; leading EIA to 

project the United States will become a net exporter of natural gas by 2021. 

In 2010, the Federal OCS supplied about 10 percent47 of annual domestic natural gas 

production and EIA estimates 12 tcf in proven reserves of natural gas in the GOM. Over 

the projected time period, EIA forecasts offshore natural gas production in the GOM to 

fluctuate between 2.0 and 2.8 tcf per year as new large projects directed toward liquids 

development start and replace depletion of other offshore fields. By 2035, OCS 

production will still account for roughly 10 percent of total domestic dry natural gas 

production. While the OCS has large volumes of proven and undiscovered natural gas 

resources, most of the increased domestic natural gas production in the next decade will 

come from onshore areas.

Regional Energy Considerations

Table 8 shows proportional petroleum and natural gas production and consumption by 

region in the United States in 2010. The table also indicates each region’s total energy 

consumption as a percentage of total U.S. energy consumption (2009 figures). One 

noticeable theme is that the East and West Coasts and Midwest consume 75 percent of 

the oil and natural gas used in the United States but supply only about 25 percent of 

domestic oil and natural gas production.

The Federal GOM region has by far the most resource potential of the four OCS regions, 

and it is located such that it can supply oil and gas to the Nation’s top three consuming 

Petroleum Administration for Defense Districts (PADD),48 the East Coast, the Gulf 

Coast, and the Midwest.

The production percentages provide a rough approximation of the distribution of known 

oil and natural gas resources among the country’s PADDs. Of the six PADDs (with 

Alaska as a separate district), the East Coast has the highest consumption but by far the 

lowest production of oil. Its natural gas production, while not the lowest, is well below 

levels in the top three onshore PADDs and the Federal GOM. In BOEM’s 2011 

Assessment, the North Atlantic is the 9th highest-ranked planning area for overall 

resource potential and is 7th for natural gas potential. The Mid-Atlantic is in the top 7-8th

overall and the top 5-6th for natural gas, depending on the price case. The South Atlantic 

is about 15th overall, but like the other Atlantic planning areas, higher for natural gas 

 47 DOI, Office of Natural Resources, 2011; http://www.boemre.gov/stats/PDFs/AnnualPercentage1954-

2010.pdf

48 For this analysis, PADD V is split into the Lower 48 Pacific and Alaska, given how different Alaska’s 

production-consumption relationship is from the remainder of PADD V. It also creates a one-to-one 

relationship between coastal PADDs and the four OCS regions. Hawaii does not have oil or gas 

production, and its energy consumption would not contribute appreciably to Table 8. For the composition 

of each PADD, see the Table 8 notes.
108

potential. Oil production in the Lower 48 Pacific coastal states represents about a third of 

its oil consumption, but its natural gas production is closer to a tenth of 

consumption. The three planning areas off California are among the top ten OCS areas 

for resource potential, with the Southern California planning area falling behind only the 

GOM and Arctic planning areas. All three are more oil prone but have important 

potential for natural gas as well.

Regional production–consumption gaps, proximity to production areas, and existing 

transportation constraints can affect regional prices for petroleum and natural gas 

products. For example, gasoline prices in the Rocky Mountain area were lower than the 

national average for much of 2011. This was due to relatively low crude oil input costs to 

refineries in a region that is fairly self-sufficient in meeting its demand for gasoline and 

other petroleum products. In contrast to the eastern half of the United States, refineries 

within the Rockies supply most of the regional demand. In terms of natural gas, 

geographic price differences for U.S. natural gas can reflect transportation and/or 

transmission constraints between regional markets. Sudden geographic price differences 

that manifest during regional demand disturbances can be indicative of transportation 

and/or transmission constraints in a given market.

Table 8: Petroleum and Natural Gas Production and Consumption 

by Region in 2010

Petroleum Admin 

for Defense 

District (PADD) 

or OCS Region*

Production (MMbbl:MMcf) Consumption Total Energy 

Consumption 

(MMBtu) % 

of U.S. 

Total***

Crude Oil 

% of U.S. 

Total

Natural Gas 

% of U.S. 

Total

Crude Oil 

% of U.S. 

Total

Natural 

Gas % of 

U.S. Total

East Coast 0.38% 4.74% 29.25% 27.67% 31.26%

Midwest 12.31% 11.38% 25.43% 25.95% 29.31%

Gulf Coast 29.46% 50.04% 26.70% 25.96% 20.57%

Federal OCS, 

GOM 27.69% 10.49% 0.00% 0.46%** 0.00%

Rocky Mountain 6.55% 19.59% 3.48% 4.29% 3.86%

Lower 48 Pacific 10.50% 1.14% 15.14% 14.27% 14.33%

Alaska 11.76% 1.64% 0.21%*** 1.40% 0.67%

Federal OCS, 

Pacific 1.06% 0.19% 0.00% 0.00% 0.00%

Federal OCS, 

Alaska 0.30% 0.78% 0.00% 0.00% 0.00%

East Coast (PADD I): Connecticut, Maine, Massachusetts, New Hampshire, Rhode Island, Vermont, 

Delaware, District of Columbia, Maryland, New Jersey, New York, Pennsylvania, Florida, Georgia, North 

Carolina, South Carolina, Virginia, and West Virginia

Midwest (PADD II): Illinois, Indiana, Iowa, Kansas, Kentucky, Michigan, Minnesota, Missouri, Nebraska, 

North Dakota, Ohio, Oklahoma, South Dakota, Tennessee, Wisconsin

Gulf Coast (PADD III): Alabama, Arkansas, Louisiana, Mississippi, New Mexico, and Texas
109

Rocky Mountain (PADD IV): Colorado, Idaho, Montana, Utah, and Wyoming

Pacific (PADD V): Alaska, Arizona, California, Hawaii, Nevada, Oregon, and Washington

*Offshore production in state waters is included with onshore production for each PADD. Federal OCS 

production is not included in the PADDs.

** Natural gas is often used as a fuel in offshore production.

***2009 Data. 2010 State Energy Totals not available at time of document.

Sources:

Oil Production- http://www.eia.gov/dnav/pet/pet_crd_crpdn_adc_mbbl_a.htm

OCS Oil Production - http://www.boemre.gov/stats/OCSproduction.htm

Gas Production - http://www.eia.gov/dnav/ng/ng_prod_sum_a_EPG0_VGM_mmcf_a.htm

OCS Gas Production - http://www.boemre.gov/stats/OCSproduction.htm

Oil Consumption - http://www.eia.gov/dnav/pet/pet_cons_psup_dc_r50_mbbl_a.htm

Gas Consumption - http://www.eia.gov/dnav/ng/ng_cons_sum_dcu_nus_m.htm

Total Energy Consumption – http://www.eia.gov/state/seds/sep_use/notes/use_print2009.pdf

OCS crude oil and natural gas production -

http://www.eoearth.org/files/156001_156100/156002/ocsproduction2010_doi.xls

Petroleum conversion factors -

http://www.eia.gov/kids/energy.cfm?page=about_energy_conversion_calculator-basics#oilcalc

2010, million Btu per barrel (5.8)

Natural gas conversion 

factors: http://www.eia.gov/kids/energy.cfm?page=about_energy_conversion_calculator-basics#oilcalc

2010, Btu per cubic foot (1,025)

In the United States, almost half of the total inter-PADD petroleum product movements 

by pipeline, tanker, or barge in 2011 were from the Gulf Coast (PADD 3), an area with 

significant refining capacity, to the East Coast (PADD 1), a major population center. For 

crude oil, nearly two-thirds (341,576 Mbbl per year) of inter-PADD movements by 

pipeline, tanker, or barge were movements from Gulf Coast (PADD 3) to the Midwest 

(PADD 2). These volumes include crude oil produced in the GOM and imports to the 

Gulf Coast region that move inland to refineries in the Midwest. As pipeline receipts of 

Canadian oil sands crude oil and increased production from North Dakota's Bakken 

formation have bolstered Midwest crude oil supplies in recent years, the volume of crude 

oil moving by pipeline from the Gulf Coast to the Midwest has steadily declined. This 

increase in crude oil to the Midwest from sources other than the GOM has reduced its 

need for crude oil supplies from the Gulf Coast. Still, overall the vast majority of the 

inter-regional crude oil pipeline movements occur among the states of the Midwest, Gulf 

Coast and Rocky Mountain PADDs, with very little crude oil pipeline activity into or out 

of the East and West Coasts. 

Alternatives to the Contribution of OCS Oil and Natural Gas

In the Five Year EIS, the term No Action Alternative (NAA)49 refers to the No Sale 

Option for all program areas. In the NAA, no new OCS leasing would take place for at 

least 5 years and domestic oil and natural gas production would be reduced appreciably 

since replacements for depleting offshore fields would be delayed for at least that long. If 

no OCS oil and gas lease sales were held during the period covered by the new Five Year 

Program, energy markets would find substitutes to satisfy most of the demand that would 

 49 See additional discussion in Net Economic Value section, below.
110

have been met by production resulting from the oil and natural gas resources made 

available by the additional lease sales to be held under the program. In an environment 

of strong worldwide demand for oil and natural gas, a domestic supply cut equivalent to 

the production anticipated to result from a new Five Year Program would lead to a slight 

increase in world oil prices and a relatively larger increase in U.S. natural gas prices. All 

other things being equal, this would lead to a market response providing increases in 

imported oil and natural gas and greater production of domestic onshore oil and natural 

gas, coal, and other energy substitutes. It would lead to a small reduction in the total 

amount of natural gas consumed in the United States, with oil consumption rising 

slightly.50 Most of the foregone production would be replaced by other sources. The net 

result in the United States would be a slight reduction in oil and natural gas consumed, a 

substantial increase in oil imports, and added supplies provided by onshore hydrocarbon 

resources. 

BOEM uses its Market Simulation Model (MarketSim) to estimate the amount and 

percentage of substitutes the economy would adopt should a particular program area not 

be offered for lease. MarketSim is based on authoritative and publicly available estimates 

of price elasticities of supply and demand and substitution effects. Elasticity measures 

the sensitivity of consumers or producers to changes in product price. 

Table 9 demonstrates how energy markets would compensate in the event the NAA were 

implemented. Under the mid-price scenario of $110 per barrel and $7.38 per mcf, 68

percent of the oil and natural gas production foregone from this program would be 

replaced by greater imports, 16 percent by increased onshore production, 5 percent by a 

switch to coal, 3 percent by increased electricity from other sources, 2 percent by a

switch to other energy sources, and 6 percent by a reduction in consumption.51 Without 

the expected production from the Five Year Program, 10 billion BOE (BBOE) over 40 to 

50 years would be deferred and offset by increased supplies from other energy sources. 

These energy sources would increase as follows: oil and natural gas imports by 6.8

BBOE (equal to current U.S. imports for almost 1.5 years), onshore oil and natural gas 

production by 1.6 BBOE (equal to almost half a year of current onshore production), and 

other energy sources by 1.0 BBOE. Consumption of oil and natural gas would be 

expected to decline by 0.6 BBOE (equal to less than 2 months of current U.S. oil and gas 

consumption) spread over the next 40 to 50 years. 

 50 This increase in oil consumption reflects the fact that oil and natural gas are substitutes within the 

industrial sector and, to a lesser extent, the residential and commercial sectors. The loss of a given amount 

of OCS production is likely to result in greater increases in natural gas prices than in oil prices, because the 

price of oil is largely decided in the world market while the price of natural gas is largely set in smaller 

regional markets. Therefore, as natural gas prices increase under the NAA compared to the exploration and 

development (E&D) scenarios due to reduced OCS production, consumption of substitutes, including oil, 

increases. The increase in oil prices under the NAA may cause some offsetting substitution in the opposite 

direction, from oil to natural gas, but the impact of increased natural gas prices is the more dominant of the 

two effects.

51 Total does not sum to 100 percent due to independent rounding and conversion to equivalent units of 

energy (e.g., Btu to BOE).
111

Table 9: Results of No Action Alternative (No New Program)

Energy Sector

Quantity (BBOE)

over 40 years

Percent of

OCS Production 

Replaced

Onshore Production 1.6 16

 Onshore Oil 0.1 1

 Onshore Natural Gas 1.5 15

Imports 6.8 68

 Oil Imports 5.9 60

 Natural Gas Imports 0.9 9

Coal 0.5 5

Electricity from sources other than 

Coal, Oil, and Natural Gas 0.3 3

Other Energy Sources 0.2 2

Reduced Demand 0.6 6

Given its relative ease of transport, oil prices are set on the world market. Natural gas is 

not as easily transported, thus its prices are influenced much more by regional supply. 

Therefore, in the absence of production from a new Five Year Program, U.S. natural gas 

prices would increase proportionally more than oil prices. Based on Marketsim results, 

this would result in substitution away from natural gas and toward oil and other energy 

sources. 

The distribution of reduced consumption and switching to alternative sources by sector 

depends largely on the amount of consumption and relative price elasticities of demand 

across the sectors. The transportation and industrial sectors accounted for almost 95 

percent of U.S. oil consumption (approximately 72 and 23 percent of oil respectively) in 

2010. Residential and commercial consumption accounted for the residual 5 percent. 

Other forms of energy cannot readily substitute for most of the oil and natural gas 

consumed in the transportation and industrial sectors in the near term. In the U.S. 

transportation sector, a decline in oil consumption would likely be the result of a 

reduction in miles traveled and/or the purchase of more fuel efficient vehicles. In 

addition to the modest price increase associated with these scenarios, the cost of 

developing an alternative fuel infrastructure hinders efforts to extend the use of 

alternative transportation fuels, although automobile companies have unveiled and/or 

announced plans for new gasoline-electric hybrid, plug–in hybrid, and electric vehicles. 

A detailed discussion of the model and alternative sources of energy in the context of the 

PFP for 2012-2017 appears in Energy Alternatives and the Environment (BOEM 2012-

021), which can be found with other program documents at http://www.boem.gov.
112

Replacement Energy Sources

Many renewable energy sources will contribute to the future of the United States with an 

increasing emphasis on sources with reduced CO2 emissions-reducing sources. In 

February 2009, with the passage of the American Recovery and Reinvestment Act 

(ARRA), the President pledged over $90 billion to support a wide range of clean energy 

programs. For example, ARRA has funded $2.4 billion for battery and electric drive 

component manufacturing, and for electric drive demonstration and infrastructure. These 

investments already are transforming the advanced vehicle batteries industry in the 

United States.52 In the long run, the electrification of the transportation sector will enable 

the use of electricity generated from renewable energy sources in place of petroleum 

fuels. Investments in the grid included $4.5 billion for Smart Grid investments, 

demonstration projects, and capacity building. The Section 1603 renewable energy grant 

program53, another example of an ARRA investment, has been an essential tool in 

deploying renewable energy resources in the United States over the past 2 years, 

successfully increasing U.S. manufacturing and redirecting investments into renewable 

energy projects. As of the first three months of 2012, over $12 billion had been paid to 

eligible participants.54 This and other investments are intended to ensure that electricity 

generation from non-hydro renewable sources doubles by 2012 from 2008 levels of 126 

billion kilowatt hours (74 MBOE). Moreover, ARRA built on significant Federal 

investment in solar, geothermal, and marine and hydrokinetic renewable energy 

technologies under the Energy Independence and Security Act of 2007.

On a national scale, non-hydro renewable sources supplied about 7 percent of all the 

energy consumed domestically in 2010. This share is expected to reach 10 percent in the 

mid-2020s and grow to 13 percent by the mid-2030s, according to AEO 2012 (Early 

Release). In 2010 and 2011, DOI approved 27 renewable energy projects on public 

lands, including 16 commercial-scale solar energy initiatives, 4 wind projects, and 7 

geothermal plants. On a national scale, renewable sources supplied about 8 percent of all 

the energy consumed domestically in 2010. On the OCS, DOI and BOEM have 

responsibilities for renewable energy projects and other alternative uses of Federal lands 

under the Energy Policy Act of 2005. BOEM has the authority to (1) grant leases, 

easements or rights-of-way for renewable energy-related uses on the OCS and (2) 

monitor and regulate those facilities used for renewable energy production and energy 

support services. The first OCS renewable energy commercial lease was issued in 

October 2010 for the Cape Wind project, offshore Massachusetts. The construction and 

operation plan to develop the 468-megawatt project was approved in April 2011 and 

marks a milestone in the development of OCS renewable energy resources. Secretary 

Salazar’s “Smart from the Start” offshore wind program is intended to identify high-

 52http://www1.eere.energy.gov/vehiclesandfuels/pdfs/merit_review_2011/electrochemical_storage/es098_j

ohnson_2011_o.pdf

53U.S. Department of the Treasury, 2011; http://www.treasury.gov/initiatives/recovery/Pages/1603.aspx 

The 1603 program offers renewable energy project developers cash payments in lieu of investment tax 

credits (ITC). The value of the awards is equivalent to 30% of the project's total eligible cost basis in most 

cases. 54U.S. Department of the Treasury, 2011; http://www.treasury.gov/initiatives/recovery/Pages/1603.aspx
113

potential, low-conflict areas on the Atlantic OCS, near large population centers, where 

BOEM will consider offshore wind leasing as early as the end of 2012.

The alternative energy technologies expected to be deployed on the OCS should continue 

to mature over the next decade and beyond. Environmental and meteorological data 

collection has begun in the Mid-Atlantic OCS for potential wind energy production 

zones. BOEM is actively working with coastal states to share information on potential 

wind energy leasing sites. Federal or state governments might use taxes, subsidies, or 

other tools to incentivize a different mix of energy substitutes. These efforts could help 

offset the failure of the market to reflect all the externalities associated with the use of 

fossil fuels. These policies also could promote investments in renewable energy 

technologies that may not be cost-competitive at current historically low natural gas 

prices, but show promise for future competitiveness under longer-term energy price 

forecasts. Such policies could include renewable energy portfolio standards for 

electricity generation portfolios. 

Despite the increased contributions from alternative and renewable energy sources that 

can be expected over the coming decades, it is important to note three points in relation to 

the decisions at hand. First, natural gas and oil will remain important contributors to the 

energy mix throughout the foreseeable future. Despite advances in alternative-fuel 

vehicles, transportation remains predominately dependent on petroleum, with most of the 

remaining fuel supplied by natural gas, and it accounts for about 72 percent of demand 

for liquid fuels. According to the AEO reference case, these shares and consumption 

levels are unlikely to change appreciably by 2035, although the forecast does indicate that 

dependence on petroleum would fall by about 5 percentage points, in favor of increased 

consumption of other liquid fuels. Until renewable energy sources can supply a much 

larger share of the Nation’s energy, clean-burning natural gas likely will continue to be a 

favored fuel, especially for electricity generation, where it can be used to respond to the 

rapid fluctuations in demand that are inherent in electricity markets. Second, the focus of 

this document is the decision process for the next Five Year Program, as specified by 

section 18 of the Act. Therefore, the analyses that follow are focused on providing 

information that may help the Secretary decide among the options available to him 

through the section 18 process. Third, given the importance of increasing the share of 

renewable energy in fueling the Nation’s economy, most realistic alternatives available to 

build renewable energy production will be advanced regardless of any Five Year Program 

decisions, as evidenced by Secretary Salazar’s energy-related decisions to date. For 

example, he has not delayed or denied any renewable energy projects under his authority 

because of the availability of fossil fuels that could be used instead. Further, even if 

renewable fuels advance much faster than anticipated, OCS oil and natural gas 

production foregone because of a Five Year Program decision would be replaced by fuels 

that would most easily substitute for the same uses in the same geographic areas, and in 

many cases conversion to renewable fuels would require major changes and investments 

in alternate energy infrastructure. 
114

Conclusion

Despite the promise of new sources of energy, America’s reliance on oil and natural gas 

is likely to change only gradually in the near future. Additional reductions in oil 

dependence should come from increases in efficiency, which include Corporate Average 

Fuel Economy (“CAFÉ”) Standards intended to improve the fuel economy of cars and 

light trucks with the goal of doubling efficiency by Model Year 2025. However, even 

increased vehicle fuel efficiency is predicted only to prevent an increase in consumption 

of petroleum products for transportation. Achieving the goal of ample secure, clean, and 

affordable energy will require diligent, concerted efforts on both the supply and demand 

sides of the energy equation. Notwithstanding a national energy policy focus on 

increasing conservation and efficiency to help reduce demand for fossil fuels (i.e., oil, 

natural gas, and coal), production of oil and natural gas, as well as eventually renewable 

energy from the OCS, are key components of a national energy strategy to diversify 

energy sources. Renewable energy sources are attractive for environmental reasons and

potentially to avoid price volatility. Worldwide, government policies and incentives will 

increase the use of renewable energy sources.

In the interim, to help bridge the existing energy gap as the Nation moves towards a more 

sustainable energy future, obtaining sufficient supplies of traditional fuels at reasonable 

prices and continued responsible oil and natural gas development is crucial to the 

economy and energy security. The OCS leasing program helps supply a share of the 

Nation’s energy requirements while reducing the dependence on imported energy by 

identifying key offshore Federal oil and natural gas-bearing regions that best meet the 

Nation’s energy needs. The OCS, and in particular the GOM and the Alaskan Arctic, 

offer ample oil and natural gas resources for the future. Over the next 25 years, offshore 

production is expected to account for roughly 32 percent of total domestic crude oil 

production and 10 percent of total domestic natural gas production. Without the 

program, significant increases in imported oil and onshore production of oil and natural 

gas would be needed to sustain the Nation’s growing energy requirements because 

renewable energy sources and conservation will not achieve the scale necessary to 

materially dent import reliance.

The size, timing, and location of lease sales in the PFP have been selected to help meet 

the needs described above in an efficient and practical manner in light of existing legal 

constraints, local conditions, and other uses of particular parts of the OCS. In the short 

term, the PFP is designed to maximize the potential of the Central and Western GOM, 

which have both the highest economically recoverable resource potential of available 

areas and by far the most developed infrastructure. In the intermediate term, the PFP sets 

in motion further exploration and potential development of undiscovered resources 

offshore Alaska.
115

B. Analysis of Environmental Concerns 

Introduction

 

The Act, as amended, requires consideration of environmental protection in managing the 

Nation’s offshore oil and natural gas resources. The Act’s amendments point to the 

importance of applying safeguards to help limit the risks of environmental damage and to 

protecting the human, marine, and coastal environments. Section 18 of the Act mandates 

that decisions on managing the mineral resources of the OCS strike a proper balance 

between the potential for environmental damage, the potential for discovery of oil and 

natural gas, and the potential for adverse impact on the coastal zone. It is therefore 

important in developing a Five Year Program to solicit comments relating to 

environmental concerns, to consider and analyze carefully the comments received, and to 

make use of that information in the development of the EIS prepared for the program, 

and, ultimately in the development of the program itself.

Environmental Analyses

The Final EIS for the Five Year Program for 2012-2017 has been prepared for the 

Secretary’s consideration and to accompany this document. Preparation of the EIS began 

with publication of an NOI to Prepare an EIS published in the Federal Register (74 FR 

3631) on January 21, 2009. That notice was intended to start the formal scoping process 

by calling for comments and information to be used to determine the scope of the planned 

EIS for the 12 areas in the 2009 DPP. However, scoping was postponed when the 

comment period for the 2009 DPP was extended by 180 days. A second notice was 

published in the Federal Register on April 2, 2010, (75 FR 1628) announcing scoping in 

eight areas as part of the OCS Strategy announced by the President and the Secretary on 

March 31, 2010. In the aftermath of the Deepwater Horizon event on April 20, 2010, 

scoping meetings again were postponed. Following the December 1, 2010, 

announcement of a revised OCS Strategy, a third notice was published in the Federal 

Register on January 4, 2011, (76 FR 376) setting out the schedule for scoping meetings 

and another comment period. The Draft EIS was published with a 60-day comment 

period on November 10, 2011, (76 FR 70156) and analyzed six areas proposed for 

leasing along with seven alternatives. The Final EIS accompanies this document for the 

Secretary’s consideration. See part III of this decision document and Chapter 2 of the 

EIS for descriptions of the proposed action and alternatives. The potential environmental 

impacts that correspond to proposed and alternative lease sale options are summarized 

following each set of options presented in part III of this document. 

There is additional information relating to environmental concerns in the analyses of 

social costs, environmental sensitivity and marine productivity, and other uses of the 

OCS presented in part IV.C below. Also, much pertinent information is available in 

other documents cited and incorporated by reference, listed in part II of this document.
116

C. Comparative Analysis of OCS Planning Areas

This section presents the analyses that compare the volume, size and social value of 

anticipated production from the various program areas included in the PFP decision. The 

analyses address the section 18 criteria that can be quantified as well as some that cannot. 

The domestic benefits and costs of proposed OCS activities are enumerated, as well as 

the costs of providing energy substitutes avoided by implementing the program. Other 

factors such as environmental sensitivity and marine productivity of the areas proposed 

for leasing consideration are addressed more qualitatively. The comparative analysis also 

takes into account comments received, other considerations pursuant to the Act and 

NEPA, and applicable judicial opinions. The Final EIS, published concurrently with this 

document, contains a more extensive description of potential environmental impacts from 

the Five Year Program. 

1. Net Benefits Analysis 

At the draft proposed, proposed, and proposed final program stages in the five year 

program preparation process, BOEM conducts a benefit-cost analysis of the social value 

from anticipated production of oil and natural gas resources expected in each program 

area as a result of the program. The analysis examines the benefits to society from the 

production of oil and natural gas as well as the environmental and social costs associated 

with the anticipated exploration, development, and production activities. The analysis 

also includes estimates of the environmental and social costs associated with those 

activities that would occur when obtaining replacement energy from other sources should 

the No Sale Option be selected in any program area. 

While society continues to receive the benefits from previously leased OCS resources, 

policies relating to their treatment are not subject to this PFP decision. Accordingly, this 

analysis only considers the net benefits from proposed new leasing. Further, the net 

benefits analysis includes information designed to help with decisions about the size, 

timing and location of future Federal lease sales on the OCS, so this analysis only covers 

energy activities under BOEM’s jurisdiction. 

The 2009 DPP decision document provided a comparative analysis of all unleased, 

undiscovered oil and natural gas resources in all 26 OCS planning areas, resulting in the 

“relative ranking” of those planning areas. Consideration of this analysis and of the 

various other factors outlined in part III of the 2009 DPP document, led to the selection 

of the six program areas and the timing of OCS lease sales in the PP. 

The 2011 PP document moved from the relative ranking of all unleased, undiscovered 

economically recoverable resources in the 26 planning areas to the value of anticipated 

production from each program area for the program proposal and for each of the broad 

program alternatives described in the EIS. (See Valuation of Program Alternatives in this 

section.) This analysis is expanded and updated here to provide valuation for the 

Secretary, with estimated net benefits by planning area from anticipated production under 

each of the three resource price cases listed in Table 10. The PFP was updated 
117

significantly from the PP analysis.55 Note that for the purpose of this analysis, each of 

the price cases is conceptually germane beginning only when new production commences 

from the six-area program. Prior to that time, stipulated prices of oil and natural gas have 

no effect on the calculations. Both the PP and this analysis add to the 2009 DPP analysis 

by including the net domestic consumer surplus56 that arises with new leasing. Summing 

the production value and the difference between environmental, social and net domestic 

consumer surplus benefits and losses from exploring each program area instead of the 

most likely energy substitute provides the net benefits shown in Table 16. 

Figure 2 summarizes the components of BOEM’s net benefits analysis. Additional 

information on the methodology and economic assumptions can be found in the 

Economic Analysis Methodology for the Five Year OCS Oil and Gas Leasing Program 

for 2012-2017, (BOEM 2012-022). 

Figure 2: Components of Net Benefits Analysis

Anticipated Production 

from the Program Area x Assumed Price Level = Gross Revenue

Gross Revenue - Private Costs = Net Economic Value (NEV)

NEV -

Environmental and 

Social Costs of Program Proposal

less

Environmental and Social Costs 

of Energy Substitutes (Resulting 

from the No Sale Option)

= Net Social Value (NSV) 

NSV +

Consumer Surplus Benefits

less

Lost Domestic Producer 

Surplus Benefits

= Net Benefits

The net benefits analysis reflects several values derived from economic activity as well as 

the various costs associated with generating that economic value. The net economic 

value (NEV) calculation described below looks at changes in economic activity that can 

 55 See Economic Analysis Methodology (BOEM 2012-022) for more information on changes since the PP. 56 Consumer surplus, a standard term in economics, represents the difference between the amount that 

consumers would be willing to pay and the actual price of goods and services they purchase. In this

context, an action or event that lowers the price of oil and natural gas will increase consumer surplus by the 

change in price summed over the quantity purchased at the original price, plus an increment reflecting the 

sum of consumer surplus benefits from purchasing additional quantity at the lower price. Typically, the 

gains from the added consumer surplus would be substantially reduced by the losses from a decrease in 

producer surplus, i.e., the decrease in economic value to producers receiving a lower product price, leaving 

a relatively small residual net societal benefit. However, since this is focused on net benefits to domestic 

consumers and producers, the producer surplus offset affects only the portion of domestic consumption that 

is produced domestically. Hence, there is no producer surplus decline to offset that portion of consumer 

surplus gain on the aggregate amount of imported oil and natural gas. The result is that in this case the net 

consumer benefits, primarily representing pecuniary gains from reduced market price of imported oil and 

gas, are substantial for the program as a whole. 
118

be measured in several forms, e.g. net value reflected as the sum of commercial income, 

tax receipts, royalties, and other government revenues. Net social value (NSV) is 

measured as NEV less the difference between the social costs of the program option and 

of the No Sale Option. 

Another perspective on social value involves comparison of the benefits of incremental 

employment, labor income, and other such factors with the potential range of costs 

imposed by each EIS alternative. That approach is more appropriate when considering 

impacts from the local or regional perspective and is used in the equitable sharing of 

developmental benefits and environmental risks analysis in section C.4 below. The net 

benefits analysis in this section is approached from the national perspective, which 

provides the Secretary with a clearer picture of the overall balance of benefits and costs 

tied to the program-area-by-program-area decision as to whether to offer the area for 

leasing. 

Gross Revenue

The net benefits analysis begins with the calculation of the gross revenue from the 

production of OCS oil and natural gas anticipated as a result of the Five Year Program. 

Gross revenue equals the anticipated production of each resource multiplied by the 

assumed price level. 

Price Level Assumptions 

Leasing from the 2012-2017 Program is expected to stimulate exploration, development, 

and production activity for approximately 40 years,57 over which time oil prices could 

fluctuate dramatically. Historical oil price volatility has shown that unanticipated market 

and political events, new technologies, weather, geopolitical unrest, or economic changes 

can cause energy price paths to deviate considerably from even the most respected 

forecasts.58 Moreover, use of a trend forecast or fluctuating prices in the analysis would 

make it difficult to separate out the effects of assumed price changes and their timing 

from the resource and cost differences in program areas on the measures of net benefits. 

For these reasons, the PFP analysis includes resource and net benefit estimates evaluated

at each of the three level sets of real price scenarios shown in Table 10. These price 

scenarios are consistent with the ones analyzed in BOEM’s 2011 Assessment.59 Having 

three different sets of flat price cases also allows the decision-maker to more clearly 

identify the extent to which net benefits vary under a wide range of general price levels, 

independent of other input assumptions such as the timing of activities. A real discount 

rate of 3 percent is used in the PFP analysis to aggregate 40 to 50 years of effects at a 

society-wide rate of time preference. 

 57 Some Alaska exploration and development (E&D) scenarios extend to about 50 years because the pace of 

development historically has been slow. However, most of the activity takes place within 40 years of the 

start of activity.

58 The widespread application of technology to extract abundant tight natural gas has recently reduced 

domestic natural gas prices, causing at least a temporary decoupling of oil and natural gas prices. 59 2011 Assessment. RED-2011-01a. 
119

Table 10: Price Scenarios

Oil (per bbl) Natural Gas 

(per mcf)

Low $60 $4.27

Mid $110 $7.38

High $160 $11.39

BOEM has chosen to retain the same price scenarios used previously in the PP decision 

document. Given the major changes in energy-equivalent prices for natural gas and oil in 

recent years, the ratio of the price of natural gas to oil for the same heat content (Btu) 

equivalency factor was reduced for the PP decision document from that used previously 

and in the 2009 DPP decision document. That factor, which was 0.90 in 2005, was 

decreased to 0.60 for the 2009 DPP decision document, and has been further reduced to 

0.40 for the 2011 Assessment and the PP and PFP analyses. For example, an oil price of 

$60 per bbl in the 2009 DPP decision document was associated with a gas price of $6.41 

per mcf, while the same oil price is associated with a natural gas price of $4.27 per mcf in 

the 2011 and 2012 program documents. 

Since these oil and natural gas prices were determined for the 2011 Assessment and for 

the Five Year Program net benefits analyses, the natural gas price has fallen below the 

0.40 ratio, but BOEM has chosen to retain the 0.40 ratio between oil and natural gas 

prices. Low natural gas prices primarily are due to new technology which has increased 

shale gas production and to the continued drilling in shale plays with high concentrations 

of natural gas liquids and crude oil, which have higher energy content than dry natural 

gas.60 The low prices are likely unsustainable over the 40-year period covered by the net 

benefits analysis as market forces cause prices to increase back to equilibrium. On the 

supply side, producers will switch their attention to more oil-prone prospects which will 

create a future upward pressure on natural gas prices via reduced supply. Similarly, 

environmental concerns about hydraulic fracturing (fracking) fluids may put pressure on 

the industry to scale back or even cease the use of fracking technologies to unlock natural 

gas from shale. Because natural gas is relatively less expensive, demand will go up over 

time, gradually causing the price to rise as infrastructure develops to allow for the use of 

natural gas in electricity, transportation, etc., and as capacity develops to export natural 

gas via LNG. Therefore, BOEM has retained the same price scenarios used in the PP 

analysis for this decision. 

Estimates of Hydrocarbon Resources and Anticipated Production

Resource estimates from the 2011 Assessment provide the foundation for this evaluation 

of program areas. The 2011 Assessment considers recent geophysical, geological, 

technological, and economic information and utilizes a probabilistic, geologic-play-based 

approach to estimate the undiscovered technically recoverable resources of oil and 

natural gas for individual plays. This methodology is suitable for both conceptual plays 

 60 2012 AEO Early Release, http://www.eia.gov/forecasts/aeo/er/early_production.cfm
120

where there is little or no specific information available, and for developed plays where 

there are discovered oil and natural gas fields and considerable information is available. 

The 2011 Assessment incorporates significant updates from previous assessments for the 

economic assumptions used to assess the Undiscovered Economically Recoverable 

Resource (UERR) for developing the anticipated production expected from the program 

areas. The most influential change involved incorporating a relationship between oil 

price and development costs in the modeling methodology. Capturing observed 

variations in oil and natural gas exploration and development costs across a wide range of 

oil prices improved BOEM’s confidence in estimating the UERRs from which the 

anticipated production volumes in Table 11 were derived. This fundamental relationship 

was not modeled in previous economic assessments. A cost-price “elasticity factor” was 

defined based on internal analyses that found that a statistically significant relationship 

exists between crude oil price and an index of upstream capital cost. These analyses were 

based in part on indices developed by IHS-CERA, Inc., and were applied to all cost 

components. 

Furthermore, estimates of UERR expected to be available for lease as of the start of the 

program were revised to incorporate recent leasing activity in those planning areas with 

OCS lease sales scheduled in the interim. A description of the methodology and results 

of the 2011 Assessment is available in the 2011 Assessment Fact Sheet at 

www.boem.gov.

Estimates of anticipated production are a subset of the total resource potential and 

provide a more realistic basis for valuation in the program and EIS analyses. Anticipated 

production differs from undiscovered technically and economically recoverable resource 

estimates in that anticipated production only includes oil and natural gas resources that 

are expected to be leased, discovered, developed, and produced as a result of a series of 

lease offerings in the PFP. The cumulative case in the Final EIS uses the full UERR for 

the collective effect of current and future activities resulting from all past, present, and 

future five year programs. 

In the GOM, anticipated production expected to result from sales in this PFP was based 

on historical sale-specific field discovery volumes, production and drilling activity, 

leasing trends, and BOEM’s most recent 10-year GOM production forecast.61 UERR 

estimates from BOEM’s 2011 Assessment provide the upper-limit constraint of the 

production estimates. 2011 Assessment data also was used to segregate anticipated 

production into water-depth categories by applying geologic play-specific resource 

estimates as well as a distribution of available acreage. A significant decline in leasing 

and drilling activity in the shallow water of the Western GOM since 2007 resulted in a 

sizeable reduction relative to past formulations of the anticipated production volumes in 

this area. The anticipated production estimates for the Eastern GOM also incorporated 

new area-specific, subsurface G&G data interpretation.

 61 U.S. Department of Interior, Minerals Management Service, Gulf of Mexico Region. 2009. Gulf of 

Mexico Oil and Gas Production Forecast: 2009-2018. May, 

<http://www.gomr.boemre.gov/PDFs/2009/2009-012.pdf>.
121

In Alaska, many factors influence the development of exploration, development and 

anticipated production scenarios related to the program. In the Alaskan Arctic, oil is the 

priority commodity of interest due to its higher market value and the existing TAPS. 

Accordingly, the scenarios for the Chukchi and Beaufort Seas assume that large oil fields 

will be developed first. Natural gas production is likely to be delayed until oil pools are 

depleted and even then only if a new large-volume transportation system pipeline is built. 

Natural gas is assumed to be utilized as both fuel for facilities and for reservoir pressure 

maintenance through injection to extract more oil. An exception occurs in Cook Inlet 

which has established infrastructure and a nearby market for oil and natural gas 

production. With access to existing infrastructure and a local market, smaller oil or 

natural gas pools could become commercial projects, and natural gas could be produced 

more quickly in Cook Inlet. 

In part due to the differences between mature areas and frontier areas in information and 

historical data, estimates for GOM areas are subject to a smaller range of uncertainty 

compared to those for Alaska OCS areas, especially for the Arctic areas. The estimates 

for the GOM are based on years of experience, while those for the Chukchi and Beaufort

Seas must necessarily rely on key exploration and development assumptions. This is true 

even more for the high-price estimates than for the low-price and mid-price estimates.

Table 11 shows the anticipated production for each program area. 

Table 11: Production Estimates at Different Prices*

Oil (billion barrels)

Natural Gas 

(trillion cubic feet)

BBOE

(billion barrels of oil 

equivalent)

Low 

Price

MidPriceHigh 

Price

Low 

Price

MidPriceHigh 

Price

Low 

Price

MidPriceHigh 

Price

Central 

GOM 2.24 3.77 4.34 9.47 16.41 19.07 3.92 6.69 7.73

Western 

GOM 0.56 0.86 0.97 2.63 4.07 4.59 1.03 1.58 1.79

Eastern 

GOM** 0.00 0.05 0.07 0.00 0.11 0.16 0.00 0.07 0.10

Chukchi 

Sea 0.50 1.00 2.15 0.00 2.50 8.00 0.50 1.44 3.57

Beaufort 

Sea 0.20 0.20 0.40 0.00 0.50 2.20 0.20 0.29 0.79

Cook Inlet 0.10 0.10 0.20 0.00 0.04 0.68 0.10 0.11 0.32

* After publication of the January 2009 DPP decision document, BOEM completed a subsequent resource 

assessment (2011 Assessment) resulting in revised estimates of unleased, undiscovered economically 

recoverable resources. The new estimates are reflected in the anticipated production numbers in this table. 

The low-price case represents a scenario under which inflation-adjusted prices are $60 per barrel for oil and 

$4.27 per mcf for natural gas throughout the life of the program. Prices for the mid-price case are $110 per 

barrel and $7.38 per mcf. Prices for the high-price case are $160 per barrel and $11.39 per mcf.

** Current information does not indicate that the number of sales would affect anticipated production for 

the Eastern GOM. The two-sale option allows the Secretary to consider any new information that might 
122

arise from exploration on existing leases subsequent to his decision on the program, when deciding whether 

to hold a second sale.

Net Economic Value 

Once the gross value of the resources is calculated, the second stage in the net benefits 

analysis calculates the NEV from resources expected to be leased and produced from 

sales in the 2012-2017 Program. NEV is the discounted gross revenue from the produced 

oil and natural gas less the discounted costs of exploring, developing, producing, and 

transporting the oil and natural gas to the market, or the costs required to realize the 

economic value of the resources. NEV estimates for each program area use the same 

schedules of exploration, development, and production activities that are used in the 

environmental and social cost analysis and in the Final EIS. The Federal government, as 

lessor, collects most of NEV as transfer payments in the form of cash bonuses, rentals, 

royalties, and taxes. The lessees, as private firms, retain the remainder of NEV as 

economic profits that may be distributed to shareholders around the country or reinvested 

in exploration and development projects. NEV can be equated to the sum of the present 

values of royalties, rents, bonuses, taxes, and after-tax profits. Based on the calculated 

government share and general estimates of foreign shareholder proportions in foreign 

companies, only 95 percent of the estimate of NEV is used to measure the domestic piece 

of NEV from a program area.62 Table 12 shows the domestic NEV estimates. 

In the low-price case, discovery of sufficient resources to justify production is not 

expected for the Eastern GOM. If companies bid successfully on blocks in the Eastern 

GOM, the government receives the bonus bid and rental revenue. This is a transfer 

payment that would not affect NEV. Successful exploration and production could lead to 

positive NEV, but the more likely result of exploration in the low-price case would seem 

to be dry holes. Without production, companies do not make profit and NEV for the 

Eastern GOM would be negative. In both the mid- and high-price scenarios, production

and positive NEV are predicted. Because no sales can be added to an approved five year 

program, the two-sale option for the Eastern GOM ensures that sales can be held if prices 

remain at current levels or rise even higher. If prices were to fall drastically toward the 

level of the low-price case, the Secretary could reconsider holding both Eastern GOM 

sales. 

 62 This adjustment is discussed in more detail in the Economic Analysis Methodology paper. 
123

 

Table 12: Net Economic Value

Net Economic Value* 

($ billions)

Low 

Price

MidPriceHigh

Price

Central GOM 36.66 153.59 287.16

Western GOM 10.31 38.73 69.56

Eastern GOM

(2 Sales) ** 2.30 5.32

Chukchi Sea 5.02 31.06 135.37

Beaufort Sea 0.14 3.68 16.57

Cook Inlet 1.56 3.71 12.30

All values are discounted at a real discount rate of 3 percent.

*The low-price case represents a scenario under which inflation-adjusted prices are $60 per barrel for 

oil and $4.27 per mcf for natural gas throughout the life of the program. Prices for the mid-price case 

are $110 per barrel and $7.38 per mcf. Prices for the high-price case are $160 per barrel and $11.39 

per mcf.

** Given current information, no production is expected from the Eastern GOM program area at the 

low-price case, whether from one or two sales; therefore NEV is assumed to be zero. If exploration 

occurs, NEV could be either negative if no production results or positive if successful exploration leads 

to production. The estimated value of Eastern GOM resources is highly sensitive to changes in 

information, so placing a second sale on the schedule would provide flexibility to adapt to such 

changes.

Net Social Value 

The third stage in the net benefits analysis is the calculation of NSV from offering a 

program area. NSV equals the NEV less the present value of net environmental and 

social costs anticipated from the program area. Environmental and social costs arise from 

air emissions, oil spills, visual and ecological disturbance, and preemption of other land 

uses during the exploration, development, production, and transportation of OCS oil and 

natural gas resources. Such costs also would arise in the absence of the new OCS 

activity, with added production from replacement fuel sources that the economy will 

demand in any event. In order to calculate the net environmental and social costs, such 

costs are estimated under both the PFP and the No Sale Option and the difference 

assigned to each program area. Table 13 presents the estimates for the environmental and 

social costs associated with the development of resources in the OCS program areas from 

sales in this program and the environmental and social costs of the No Sale Option.63 

Selection of the No Sale Option in all of the program areas is equivalent to the NAA that 

is analyzed in the Final EIS. Choice of the No Sale Option in any or all of the program 

areas means no new leasing would take place in those area(s) for at least 5 years and 

domestic oil and natural gas supply would be reduced. This supply reduction would 

 63Table 3 of the Economic Analysis Methodology paper shows the split of environmental costs and social 

costs for the Central GOM mid-price case. Environmental costs make up approximately 96 percent of total 

program costs and 99 percent of total costs for the No Sale Option. 
124

cause only a small change in hydrocarbon prices so there would be very little decrease in 

the quantity of oil and natural gas demanded.64 Instead, increased imports and domestic 

onshore production as well as fuel switching would ensue to meet continuing domestic 

demand for oil and natural gas products. 

BOEM uses its MarketSim to determine the substitutions for offshore oil and natural gas 

development if one or more areas are excluded from the program.65 Overall, the model 

indicates that if the No Sale Option were selected in each program area, there would be a 

23-percent reduction in OCS production of oil and natural gas over the next 40 to 50 

years. Of this, 60 percent would be replaced by increased oil imports, 9 percent by 

increased natural gas imports; 1 percent by increased onshore oil production; 15 percent 

by increased onshore natural gas production; 5 percent by increased domestic coal 

production; 3 percent by increases in electricity from sources other than oil, coal, and 

natural gas; 2 percent by increases in other energy sources; and 6 percent by a reduction 

in domestic quantity demanded.66 The replacements proportions may vary slightly 

depending on the relative amount of oil and natural gas. 

BOEM uses an updated version of its Offshore Environmental Cost Model (OECM) to 

estimate both the environmental and social costs that would result from OCS activities 

and those costs that would result from selecting the No Sale Option in each program 

area.67 This estimate uses the levels of OCS activity from the exploration and 

development (E&D) scenarios employed in NEV and the Final EIS as well as the energy 

market substitutions from the MarketSim to calculate environmental and social costs.68 

OECM computes69 environmental costs (ecology and air quality) and social costs 

 64Though the change in oil and natural gas prices is small, since these pecuniary gains are derived from 

each unit of domestic consumption, consumer surplus is still quite large. For more information on the 

calculation of consumer surplus, see the Economic Analysis Methodology paper. 65 Industrial Economics, Inc. 2012a. Consumer Surplus and Energy Substitutes for OCS Oil and Gas 

Production: The Revised Market Simulation Model. U.S. Department of the Interior, Bureau of Ocean 

Energy Management. OCS Study BOEM 2012-024. 66 Total does not sum to 100 due to independent rounding and conversion to equivalent units of energy, e.g. 

Btu to BOE. 

67 Industrial Economics, Inc.; Applied Science Associates, Inc.; Northern Economics; and Dr. Nicholas Z. 

Muller. 2012b. Forecasting Environmental and Social Externalities Associated with OCS Oil and Gas 

Development: The Revised Offshore Environmental Cost Model (OECM). U.S. Department of the 

Interior, Bureau of Ocean Energy Management. OCS Study BOEM 2012-025. 68 MarketSim does not include estimates of changes in production from existing OCS leases in response to 

the selection of the No Sale Option for one or more program areas. While this may be considered for future 

versions of the model, any such OCS response effect would depend on numerous factors, such as whether 

the decision was for one or multiple areas, the specific areas to which it applied, companies’ beliefs as to 

whether the decision implied the direction for future programs, and changes in the relative attractiveness of 

opportunities elsewhere for investment as decisions were made. Industry could pursue strategies that create 

short-term and long-term effects with offsetting results. Therefore, it is not even certain that the OCS 

response effect would result in higher production over the period of analysis. 69 OECM also provides a general estimate of greenhouse gas (GHG) emissions from OCS program 

activities and the activities necessary to provide the energy substitutes. Because any effects of GHG 

emissions on climate change would not be affected by location, BOEM hopes eventually to estimate

emissions not only from domestic production but also from overseas production and from supertankers 

carrying oil from the exporting countries overseas to U.S. shores, as well as from tanker emissions in port. 

These emissions calculations are in Table 7 of the Economic Analysis Methodology paper. 
125

(recreation, property values, subsistence harvests, and commercial fishing, in addition to 

costs from activities associated with exploration, development, production, and 

transportation that might occur with new OCS production and its most likely 

replacement. OECM is designed to model the social and environmental impact of 

activities associated with OCS exploration, development, production, and transportation 

as well as typical oil spills that might occur on the OCS. Replacement energy sources 

generate such costs from the added risk of oil spills and additional air emissions with 

increased tanker imports as well as with additional air emissions resulting from increased 

onshore production of oil, natural gas, and other energy sources such as coal.

The model is not designed to represent impacts from catastrophic oil spill events or 

impacts on unique resources such as endangered species. The reasoning behind this 

omission of catastrophic oil spills is explained in the section in this document entitled 

Possibility of Catastrophic Well Blowout or Oil Spill. A discussion of the resources that 

could potentially be affected as a result of a catastrophic spill on the OCS is included in 

the supporting paper, Inventory of Environmental and Social Resource Categories Along 

the U.S. Coast (BOEM 2012-003). Note that OECM-based analysis also omits several 

factors that would disproportionately raise the environmental and social costs of the No 

Sale Option including the environmental and social costs resulting from the substitution 

of coal for natural gas in electricity generation and from a reduction in land and water 

conservation efforts from loss in OCS funding that would attend the No Sale Option.

As shown in Table 13, for every program area, the environmental and social costs of 

relying on the substitute sources of energy under the No Sale option are equal to or 

greater than these costs from producing area resources under the Five Year Program. 

Higher air emission-related costs account for almost all the difference between the 

environmental and social costs for the likely energy market substitutes and these costs 

under the program. When OCS natural gas is not available, replacements come from 

onshore production, which occurs nearer domestic population centers. When OCS oil is 

replaced, it is mostly replaced with added imports which increase air emissions and 

heighten the risk of nearshore tanker spills along U.S. coastal areas receiving the 

imported oil.70 Both circumstances mean air emissions and oil spills have a greater 

impact on health and property values per unit of production than do air emissions and oil 

spills many miles offshore.

This analysis attributes environmental and social costs that would occur without new 

leasing to the subject program area.71 Among other things, this approach allows for 

 70 Note that in the net benefits analysis, half of the oil produced in Alaska is expected to be transported by 

tanker to the continental United States. The air emission and oil spill impacts of this tankering are included 

in the program costs of OECM. 71 The primary purpose of this analysis is to help the Secretary select decision options for each program 

area. Tying benefits and costs to the source program area is a relatively transparent way to represent the 

domestic benefits and costs likely to result from approving each individual program area options rather than 

indivisible packages of options. To do otherwise would result in there being no clear link between the 

cause of the adverse effects (e.g., less OCS production in a specific program area) and the adverse effects 

themselves. For example, foregoing all proposed sales in all program areas would lead to additional 

environmental and social costs from increased tanker traffic along the Mid-Atlantic. However, in a simple 
126

consistent treatment of program area benefits and costs, and thereby provides a 

meaningful framework for the Secretary to make sound program area decisions. In 

practice, the resulting costs would actually be felt in areas that would receive the 

increased imports and host the extra domestic natural gas production. Instead, the costs 

of the energy substitutes are allocated in proportion to the amount of production expected 

from each area in the E&D scenarios. 

A feature of this allocation choice merits comment. Increased onshore production 

replaces most of the natural gas lost under the No Sale Option while added imports 

replace most of the oil lost. Since environmental and social costs from development tend 

to be higher per unit with natural gas replacement sources than with oil replacement 

sources,72 the No Sale Option in natural gas-prone program areas generates higher 

environmental and social costs than in more oil-prone areas. 

Table 13 reports the program environmental and social costs, those costs of the energy 

market substitutes supplied as a result of No Sale Option selections, and the net costs for 

new OCS leasing and production. A more detailed explanation of BOEM’s OECM and 

MarketSim methodology can be found in the Economic Analysis Methodology paper as 

well as the documentation for those models.73

 

table showing costs by locality, it would be impossible to demonstrate how size, timing, and location 

decisions for each program area could contribute to the reduction of costs that would otherwise accrue to 

the Mid-Atlantic coast. 72 This is due primarily to differences in degradation of air quality, because of both the emission rates for 

different sources and the locations of those sources. Per-unit, emissions of unhealthy air pollutants are 

greater from onshore natural gas production than from offshore natural gas production. Dilution rates are 

lower because those emissions are on land, often near population centers, rather than on the open sea. 

While this is true also for onshore oil production, most foregone OCS oil would be replaced instead by 

imports, with all of the production activity and associated environmental and social costs occurring outside 

the United States and thus excluded from this national-perspective analysis. While supertankers bringing 

imported oil to the United States do emit significant levels of pollutants, most of this occurs in foreign ports 

or outside U.S. waters, so the related costs likewise are excluded from the analysis. 73 Industrial Economics, Inc. 2012a. and Industrial Economics, Inc.; Applied Science Associates, Inc.; 

Northern Economics; and Dr. Nicholas Z. Muller. 2012b.
127

Table 13: Environmental and Social Costs*

Environmental and Social Costs

Program No Sale Option** Net

($ billions)

Low 

Price

MidPriceHigh 

Price

Low 

Price

MidPriceHigh 

Price

Low 

Price

MidPriceHigh 

Price

Central 

GOM 3.47 5.94 6.94 10.08 17.43 20.26 -6.61 -11.49 -13.32

Western 

GOM 1.27 1.89 2.13 2.73 4.42 4.76 -1.45 -2.53 -2.63

Eastern 

GOM 

(2 Sale)

*** 0.06 0.07 *** 0.11 0.17 *** -0.05 -0.10

Chukchi 

Sea 0.04 0.08 0.15 0.24 0.43 1.03 -0.20 -0.36 -0.89

Beaufort 

Sea 0.02 0.02 0.03 0.05 0.58 2.30 -0.03 -0.56 -2.27

Cook Inlet 0.01 0.01 0.02 0.03 0.07 0.10 -0.02 -0.07 -0.09

All values are discounted at a real discount rate of 3 percent.

* The low-price case represents a scenario under which inflation-adjusted prices are $60 per barrel for oil and $4.27 per mcf for natural gas throughout the life of 

the program. Prices for the mid-price case are $110 per barrel and $7.38 per mcf. Prices for the high-price case are $160 per barrel and $11.39 per mcf.

** Selection of the No Sale option for any program area would result in greater reliance on other sources of energy (“energy substitutes”) to meet the demand 

that would have been satisfied with OCS oil and natural gas production anticipated from the proposed sale(s) for that area. These energy market substitutes also 

would impose significant costs on society. See discussion above.

*** Given current information, no production is expected from the Eastern GOM program area at the low-price case. Therefore environmental and social costs, 

whether from one or two sales, are assumed to be zero, as are the costs of replacing foregone OCS production with substitute sources of energy. If exploration 

occurs without subsequent production, the costs attributed to the sale(s) would be positive. 
128

Possibility of Catastrophic Well Blowout or Oil Spill

The net benefits analysis does not include estimates of every possible environmental and 

social cost or benefit. One cost not included in the analysis is the cost of a catastrophic 

oil spill.74 Some risks are, by their nature, difficult or impossible to value in monetary 

terms while others could be monetized but for a lack of relevant information. Estimating 

the costs of a potential catastrophic discharge of oil into the marine and coastal 

environment presents difficulties with both information availability and monetization of 

adverse effects. The estimated impacts of a catastrophic spill are not included in the net 

benefits analysis but rather are discussed separately in the Economic Analysis 

Methodology paper.

A catastrophic spill has the potential to damage many categories of resources and the 

impact on these categories could vary greatly depending on the size, timing, and location 

of a spill. Hence, any attempt to quantify a spill based on one set of assumptions may be 

more misleading than informative. The wide and unpredictable nature of the many 

factors that determine the severity of a large oil spill’s impact make efforts to quantify 

expected costs far less reliable than other measures developed in the net benefits analysis. 

Any future large spill could have wildly different characteristics as to location, season, oil 

properties, etc., resulting in vastly different costs. The geographic, geologic, and 

climatological conditions under which an incident occurs could lead to widely different 

impacts. Due to the range of possible circumstances, the costs are not solely a function of 

the quantity of oil released. Therefore, relying on the very limited historical record of 

catastrophic discharges attributable to offshore oil and natural gas projects will not 

produce reliable cost estimates comparable to others in the net benefits analysis.75

In addition to the difficulty in calculating the cost of the potential impacts of a 

catastrophic spill, there are similar difficulties in calculating the risk of a spill. A 

catastrophic spill is possible but not expected from this program. Calculating its 

 74 Because it is from a national perspective, the net benefits analysis does not consider the risks assumed 

by, or imposed on other countries, in the case of transit corridors, if the decision is to not develop domestic 

energy resources. The risks and consequences of a catastrophic accident could be far worse in or near 

countries with looser regulations and/or a lower ability to respond after it occurs.

75 Despite the absence of sufficient data needed to evaluate all aspects of the distribution of large spill sizes 

and frequencies, along with their likely economic consequences, there is no question that the presence of a 

catastrophic discharge of oil, whether resulting from OCS production or from the transportation of 

imported oil because of a decision not to lease, could greatly alter the net benefits of leasing. Hence, the 

Secretary will carefully consider the potential risks posed by each PFP option and by any of the No Sale 

Options, based on the available data and information. Proceeding with the proposed sales increases the risk 

of a catastrophic discharge of oil into the ocean by a smaller percentage. A decision to restrict production of 

domestic offshore resources raises the risk of accidents in the production and transportation of the energy 

sources that would substitute for OCS production, such as increased imports of oil and increased 

production of onshore oil and natural gas, coal, and nuclear power. However, the Secretary, BOEM, and 

BSEE, the agency that exists primarily to prevent such accidents and/or to minimize the effects of any 

accidents, do have the ability to promote safeguards through the intelligent design and rigorous 

enforcement of regulations intended to reduce accidents and prevent the succession of failures of response 

mechanisms necessary for a blowout or other event which may lead to loss of life and/or a major release of 

oil into the ocean.
129

probability is complicated by the fact that empirical evidence only provides a single 

useful data point with respect to Federal offshore activities. During the last 30 years, 

there has been only one such accident due to OCS oil and natural gas activities, the 

Deepwater Horizon event. While the Exxon Valdez accident in 1989 was not related to 

OCS activities, it provides the only other modern data point for events of national 

significance. Since the Deepwater Horizon event, DOI has initiated a major series of 

reforms aimed at preventing future oil spills. These reforms have further reduced the risk 

of a catastrophic spill, although the actual extent of this improvement is difficult to 

determine.76 See the discussion in part I of this document and Section IV.A of the Final 

EIS.

The rarity and unpredictable nature of the many factors that determine the severity of a 

large oil spill’s impact make efforts to quantify expected costs far less meaningful than 

the other measures developed by the OECM and MarketSim analyses. There is no 

question that a large extended discharge of oil resulting from OCS production could 

cause a catastrophic event which would greatly alter the estimate of the net benefits of 

leasing. Because of the extreme rarity of that event, there is only one data point over the 

last 30 years or 6 programs, leading to a miniscule statistical likelihood. Reducing such 

an effect to an expected value, as is done for the other more routine factors evaluated in 

the net benefits analysis, would obscure the consequence of a discrete event like a 

catastrophic spill, should it actually occur. Hence, the possible risks and impacts of a 

catastrophic spill are assessed outside the net benefits analysis. The risks and conditional 

estimates for such an event are dealt with in a separate assessment in the Economic 

Analysis Methodology paper. 

In addition to the efforts in the Economic Analysis Methodology paper to provide some 

very rough quantitative estimates of the potential impacts that might result from a very 

unlikely, but possible, catastrophic release of oil, BOEM has provided the Inventory

paper.77 This paper describes the resources and activities that could be affected by a 

catastrophic spill event in or near each program area whether from OCS oil and natural 

gas activities resulting from the proposed sales or from tankering of imported oil to U.S. 

ports to replace foregone OCS production should the sales not be held. While it is 

unlikely that even a catastrophic spill would destroy all or even most of the value of the 

resources and activities described, the Inventory paper provides information on the 

 76 Improvements in the various containment and response capabilities each independently reduce the 

likelihood of a catastrophic spill. For example, most well blowouts are contained very quickly after they 

occur. A properly-operating BOP can stop the flow almost immediately. One response of the oil and 

natural gas industry to the Deepwater Horizon event has been development of cap-and-contain systems that 

would control a blowout such as the one that occurred. Beyond that, improved response readiness lowers 

the risk that significant quantities of oil would reach vulnerable resources. The industry has made major 

strides, largely adopting the recommendations of the Presidential Commission appointed to investigate the 

causes of the Deepwater Horizon event. Included among recent improvements are enhanced training and 

auditing of procedures, designed to reduce the human-factor risks that are a major causal factor in most 

accidents with catastrophic consequences. 77 This paper is an expansion of what appeared in the PP document as Appendix B, which contained 

information for the Central GOM only. This Inventory paper provides information for the resources and 

activities in and near all six PFP areas.
130

different kinds of effects that might occur in or near one program area rather than in 

another.

Net Benefits

Total net benefits equal NSV plus the net domestic consumer surplus generated by each 

of the program areas. In economic theory, consumer surplus is the difference between 

the maximum amount consumers would be willing to pay for a service or product and the 

amount they actually have to pay in the market. Similarly, producer surplus is the 

difference between the actual amount that producers receive in the market and the 

minimum amount they would be willing to accept. New OCS oil and natural gas 

production increases the supply of oil and natural gas which slightly lowers the price 

consumers pay and the price producers receive. The domestic portion of the change in 

both of these surpluses is accounted for in this analysis.

MarketSim calculates the change in domestic consumer surplus occurring due to the 

increase in OCS oil and natural gas production under this program. This model also 

determines the domestic loss in producer surplus, conceptually equal to lost producer 

profits, on the remaining amount of domestic production and on energy sources that are 

displaced by the new OCS production of oil and natural gas. The difference between the 

gains in consumer surplus and the losses in domestic producer surplus represents the 

change in net consumer surplus. In the case of oil, the change in net consumer surplus 

derives mostly from the lower price of imported oil and natural gas attributable to the 

added OCS production.78 

Though most of the natural gas sold in the United States is produced domestically, the net 

domestic consumer surplus gain from new OCS gas production still is significant because 

of the substantial equilibrium-price reduction it imposes on the import share of total 

domestic natural gas consumption, given that the price for natural gas is based on a 

national rather than a world price. In contrast, new OCS oil leads to a modestly lower 

price spread over the large volume of imported oil that is consumed domestically. Taken 

together, these changes result in a substantial gain for the domestic consumer that far 

exceeds the losses to domestic producers. Additional information on consumer surplus 

can be found in the Economic Analysis Methodology paper. 

The sum of NSV and net domestic consumer surplus benefits constitutes the total 

measurable net benefits associated with the program area resources. These net benefits 

for each program area provide a comprehensive and consistent basis for comparing OCS 

program areas and program options. Table 14 shows the estimates for the components of 

the net benefit analysis for each of the program areas for each of the three price cases. 

 78 The traditional “welfare gain” portion of consumer surplus, i.e., the non-pecuniary portion, is much less 

than 1 percent of the entire change in consumer surplus. For more detailed information on the calculation 

of consumer surplus, see the Economic Analysis Methodology paper. 
131

Table 14: Net Benefits*

Net Social Value Net Domestic 

Consumer Surplus Net Benefits

($ billions)

Low Price Mid-Price High Price Low Price Mid-Price High Price Low Price Mid-Price High Price

Central GOM 43.27 165.08 300.48 19.37 35.14 44.52 62.64 200.23 344.99

Western GOM 11.77 41.26 72.19 5.08 8.32 10.28 16.85 49.59 82.47

Eastern GOM 

(2 Sale)

** 2.35 5.42 ** 0.37 0.58 ** 2.73 6.00

Chukchi Sea 5.22 31.41 136.25 2.66 7.54 25.00 7.88 38.95 161.26

Beaufort Sea 0.18 4.25 18.84 1.03 1.51 5.54 1.20 5.75 24.38

Cook Inlet 1.58 3.77 12.39 0.57 0.59 1.39 2.15 4.37 13.78

All values are discounted at a real discount rate of 3 percent.

* The low-price case represents a scenario under which inflation-adjusted prices are $60 per barrel for oil and $4.27 per mcf for natural gas throughout the life of 

the program. Prices for the mid-price case are $110 per barrel and $7.38 per mcf. Prices for the high-price case are $160 per barrel and $11.39 per mcf.

** Given current information, no production is expected from the Eastern GOM program area at the low-price case, whether from one or two sales; therefore net 

benefits are assumed to be zero. If exploration occurs, net benefits could be either negative—if no production results—or positive—if successful exploration 

leads to production. The estimated value of Eastern GOM resources is highly sensitive to changes in information, so placing a second sale on the schedule would 

provide flexibility to adapt to such changes.
132

Summary Valuation of Program Options’ Benefits and Costs

Table 15 combines the anticipated production and the various net benefit components in 

one place, arranged from the highest valued to the lowest valued area, by OCS region, 

under the mid-price case. The low- and high-price cases yield the same ranking, with one 

exception. Under the low-price case, the net benefits for the Beaufort Sea are lower than 

those for Cook Inlet. 

Leasing any of the program areas is estimated to result in meaningful additional domestic 

production and net economic and societal benefits, with the exception of the Eastern 

GOM in the low-price case. NEV accounts for the bulk of the net social benefits from 

about 60 percent in the low-price case to over 80 percent in the high-price case. The net 

domestic consumer surplus gains represent almost 15 percent of the net social benefits in 

the high-price case and more than 30 percent in the low-price case. 

Given the relatively small proportional increase in worldwide energy production 

associated with the Five Year Program, i.e., an increase of about 0.4 percent over the next 

40 years, it is somewhat surprising that the magnitude of net consumer surplus gains to 

the Nation is so meaningful. However, it can be demonstrated that in the case of oil, 

which generates almost 70 percent of the net consumer surplus gains, the required 

proportional oil price change needed to support these gains, also is about 0.4 percent. 

These findings imply an underlying oil price elasticity of demand of about unity, which is 

both plausible over the long run and consistent with the range of oil price elasticities of 

demand reported in MarketSim documentation.79 

 

Another result worth noting is the significant contribution of natural gas production to net 

consumer surplus gains. The added natural gas is responsible for generating about 30 

percent of the net consumer surplus gains from the Five Year Program, even though only 

15 percent of natural gas is assumed to be represented by imports. Unlike the case of oil, 

the added OCS production of natural gas is projected to have a much more robust effect 

on domestic natural gas prices, i.e., around 5 percent, much larger proportionally than the 

0.4 percent effect on the world price of oil from the added OCS oil production. 

A small but important component of the net benefits, especially in GOM areas, is the 

environmental and social costs avoided by producing from the OCS, rather than from the 

energy substitutes. These societal costs of not approving one or more proposed lease 

sales are largely due to the environmental and social costs associated with the most likely 

substitutes. These include increased oil imports and onshore oil and natural gas 

production, which generate additional air emissions in port and onshore, often in Clean 

Air Act non-attainment areas, and raise the risk of oil spills from tankers. 

There is one option in the PFP that relates to the number of sales in a specific program 

area. That option is to hold only one sale in the Eastern GOM rather than two sales. 

 79 Industrial Economics, Inc. 2012a.
133

Anticipated production is the same between the two options, but there is slightly more 

activity and exploration in the two-sale option. The two-sale option provides flexibility 

within the next 5 years if prices remain at current levels or rise even higher, if new 

technologies emerge, or new discoveries are made in the area. Since there is less activity 

in the one-sale case, environmental and social costs of the program are expected to be 

slightly lower. The net benefits results in Table 15 reflect the two-sale Eastern GOM 

option.
134

Table 15: Summary of Net Benefits Analysis*

Oil 

(BBO)

Natural Gas 

(Tcf) BBOE NEV

Environmental and Social Costs

NSV Net Domestic 

Consumer Surplus

Net 

Program Energy Benefits

Alternatives Net 

$ billions

Central 

GOM

Low 2.24 9.47 3.92 36.66 3.47 10.08 -6.61 43.27 19.37 62.64

Mid 3.77 16.41 6.69 153.59 5.94 17.43 -11.49 165.08 35.14 200.23

High 4.34 19.07 7.73 287.16 6.94 20.26 -13.32 300.48 44.52 344.99

Western 

GOM

Low 0.56 2.63 1.03 10.31 1.27 2.73 -1.45 11.77 5.08 16.85

Mid 0.86 4.07 1.58 38.73 1.89 4.42 -2.53 41.26 8.32 49.59

High 0.97 4.59 1.79 69.56 2.13 4.76 -2.63 72.19 10.28 82.47

Eastern 

GOM

Low 0.00 0.00 0.00 * * * * * * *

Mid 0.05 0.11 0.07 2.30 0.06 0.11 -0.05 2.35 0.37 2.73

High 0.07 0.16 0.10 5.32 0.07 0.17 -0.10 5.42 0.58 6.00

Chukchi 

Sea

Low 0.50 0.00 0.50 5.02 0.04 0.24 -0.20 5.22 2.66 7.88

Mid 1.00 2.50 1.44 31.06 0.08 0.43 -0.36 31.41 7.54 38.95

High 2.15 8.00 3.57 135.37 0.15 1.03 -0.89 136.25 25.00 161.26

Beaufort 

Sea

Low 0.20 0.00 0.20 0.14 0.02 0.05 -0.03 0.18 1.03 1.20

Mid 0.20 0.50 0.29 3.68 0.02 0.58 -0.56 4.25 1.51 5.75

High 0.40 2.20 0.79 16.57 0.03 2.30 -2.27 18.84 5.54 24.38

Cook Inlet

Low 0.10 0.00 0.10 1.56 0.01 0.03 -0.02 1.58 0.57 2.15

Mid 0.10 0.04 0.11 3.71 0.01 0.07 -0.07 3.77 0.59 4.37

High 0.20 0.68 0.32 12.30 0.02 0.10 -0.09 12.39 1.39 13.78

All values are discounted at a real discount rate of 3 percent.

* Note: The low-price case represents a scenario under which inflation-adjusted prices are $60 per barrel for oil and $4.27 per mcf for natural gas throughout the 

life of the program. Prices for the mid-price case are $110 per barrel and $7.38 per mcf. Prices for the high-price case are $160 per barrel and $11.39 per mcf.
135

Valuation of Program Alternatives

While Table 15 shows the estimates of the components of the net benefit analysis for 

each program area in the PFP, Table 16 compares the total estimated net benefits for the 

same options as those that comprise the alternatives analyzed in the Final EIS. The net 

benefits shown for each alternative excludes one of the six program areas and assumes 

that all of the other areas remain in the program. Given that program options reflect 

gains relative to the NAA, the net benefits of the NAA in the Final EIS are the negative 

of those for the program and are not displayed here. See “Relationship of Proposed Final 

Program Options to the Final EIS Alternatives” in part III of this document for a fuller 

description of the program options included in each alternative. 

With the exception noted with Table 15 of the Beaufort Sea and Cook Inlet swapping 

places in the low-price case, the ranking of program options is unaffected by the oil and 

natural gas prices considered. At the beginning of 2012, the market price of oil was close 

to the assumed oil price in the mid-price case, while the market price of natural gas was 

close to the natural gas price in the low-price case. Thus, alternating between either the 

absolute or the relative current product market prices and those sets assumed in the 

analysis should have little if any effect on the relative importance of the options being 

considered.
136

Table 16: Valuation (Net Benefits) of Program Alternatives* 

[All figures in the table are discounted at a real rate of 3 percent and in billions of 2012 dollars]

EIS 

Alternative

Price 

Case*

Net 

Economic 

Value

Environmental 

and Social 

Costs

Net 

Social 

Value

Net 

Consumer 

Surplus

Net 

Benefits 

$ billions

1: Proposed 

Action

Low 53.70 -8.31 62.01 28.72 90.73

Mid 233.08 -15.06 248.13 53.48 301.61

High 526.27 -19.29 545.57 87.30 632.87

2: Exclude 

Eastern GOM

Low 53.70 -8.31 62.01 28.72 90.73

Mid 230.78 -15.00 245.78 53.11 298.89

High 520.95 -19.20 540.15 86.73 626.88

3: Exclude 

Western GOM

Low 43.39 -6.86 50.24 23.63 73.88

Mid 194.34 -12.53 206.87 45.16 252.03

High 456.72 -16.66 473.38 77.03 550.41

4: Exclude 

Central GOM

Low 17.04 -1.70 18.74 9.34 28.09

Mid 79.48 -3.57 83.05 18.34 101.39

High 239.12 -5.97 245.09 42.79 287.88

5: Exclude 

Beaufort Sea

Low 53.56 -8.28 61.84 27.69 89.52

Mid 229.39 -14.50 243.89 51.97 295.86

High 509.71 -17.02 526.73 81.77 608.50

6: Exclude 

Chukchi Sea

Low 48.68 -8.11 56.79 26.06 82.84

Mid 202.02 -14.70 216.72 45.94 262.66

High 390.91 -18.40 409.31 62.30 471.61

7: Exclude 

Cook Inlet

Low 52.14 -8.29 60.43 28.15 88.58

Mid 229.37 -14.99 244.36 52.89 297.25

High 513.97 -19.21 533.18 85.91 619.09

* Note: The low-price case represents a scenario under which inflation-adjusted prices are $60 per barrel 

for oil and $4.27 per mcf for natural gas throughout the life of the program. Prices for the mid-price case 

are $110 per barrel and $7.38 per mcf. Prices for the high-price case are $160 per barrel and $11.39 per 

mcf.

2. Environmental Sensitivity and Marine Productivity 

a. Relative Environmental Sensitivity

1. Introduction

An assessment of “relative environmental sensitivity” is required by section 18 (a)(2)(A) 

of the Act. However, “sensitivity” is not a well-defined term in ecology or environmental 

science. Sensitivity can be considered from at least two perspectives: 1) the 

vulnerability of ecological components (such as species) to potential impacts (such as 

harm to individual animals) and 2) the resilience of an ecosystem or an ecosystem’s 
137

ability to resist fundamental change and recover from an impact. The former 

vulnerability approach is a component response approach and provides a relatively 

straightforward and quantifiable measure of potential impacts. This approach could be 

augmented with consideration of the impacts on an ecosystem’s ability to resist 

fundamental, or “state,” change, a characteristic known as “resilience,” which is a 

“system response.” 

Historically, BOEM has focused on the vulnerability or component response approach. 

This approach provides the analysis and information required by section18(a)(2)(G). But 

with the advent of new technology and new scientific research, BOEM is evaluating 

adding a resilience component to the relative sensitivity analysis. While either of the 

approaches used alone provide valid and adequate information on relative environmental 

sensitivity, developing and implementing an analysis of relative environmental sensitivity 

that combines both of these components could provide an improved assessment of the 

relative sensitivity of areas considered for leasing. BOEM continues to support the 

ongoing research to consider options and potential new approaches to defining and 

measuring environmental sensitivity and will look for ways to incorporate these different 

types of analyses in an effort to continually improve the science used for OCS decisionmaking. This may include components of ecosystem resilience, biodiversity, marine 

productivity and other potential considerations. The results of BOEM’s research will be 

made available to DOI and public stakeholders as soon as it is available. Comments and 

concerns submitted on the analysis in the PP are being considered in the ongoing research 

for the new study and are not addressed in this document.

Therefore, as used in this PFP, the term “sensitivity” refers to “sensitivity, as measured 

by indicators of vulnerability to impact.” Accordingly, “sensitivity, as measured by 

indicators of vulnerability to impact” will be indicated by use of the term “sensitivity.” 

As in the PP, the analysis in this document largely mirrors that found in the 2007-2012 

Revised Program (December 2010) and considers vulnerability of the various 

components of biological marine environment to multiple impact-producing factors, such 

as oil spills, sound and physical disturbance, and increased vulnerability due to climate 

change and ocean acidification. The results are summarized in Table 17 below. Because 

relatively small differences in total scores are not meaningful, this table presents the six 

OCS program areas grouped into three categories of relative vulnerability ranging from 

“most” to “less” vulnerable to OCS oil and natural gas activities. Categorization of an 

OCS program area as “less” vulnerable does not mean that environmental resources of 

that OCS program area are not sensitive, but as a collection are found to be relatively less 

sensitive than other OCS program areas to the types of impacts anticipated from OCS oil 

and natural gas activities. See section 5 below for a detailed explanation of how these 

vulnerability groups were determined. This analysis only considers the six PFP areas 

which are being considered for leasing. 
138

Table 17: Grouping of OCS Program Areas by Relative Environmental Sensitivity 

to Impact as a Measure of Environmental Sensitivity1

Most Sensitive to Impact

Central GOM

Eastern GOM

More Sensitive to Impact 

Beaufort Sea

Western GOM

Less Sensitive to Impact 

Chukchi Sea

Cook Inlet

1 OCS program areas are listed in alphabetical order within each grouping.

2. Methodology

Definitions

The Act and court opinions do not define relative environmental sensitivity, but defer to 

the Secretary’s methodology “so long as it is not irrational.”80 For the purposes of this 

analysis, relative environmental sensitivity is defined as the vulnerability of an OCS 

area’s ecological components (i.e., coastal habitats, marine habitats, marine fauna, and 

marine productivity) to the potential impacts of OCS oil and natural gas activities in 

comparison to the same ecological components in other OCS program areas. This 

analysis also provides a discussion of the increased vulnerability of certain areas due to 

anticipated effects of global climate change.

Coastal and marine environmental resources in and adjacent to the six OCS program 

areas were evaluated in this analysis. “Coastal” is defined as the coastline and 

boundaries of estuarine waters. “Marine” is defined as seaward of the shoreline, and 

includes both state and Federal waters.

OCS Impact Factors Analyzed for Sensitivity

This environmental analysis is based, in large part, on an evaluation of the sensitivity of 

various coastal and marine habitats and biota to accidentally spilled crude oil. Other 

relevant factors, such as sound generated by and physical disturbance from routine OCS 

oil and natural gas activities, were analyzed where appropriate or applicable. This 

analysis assumes these routine activities would be mitigated, to the extent possible, by 

measures in the form of lease stipulations, regulations, and laws to minimize impacts and 

protect marine resources. Monitoring and mitigation measures would be developed 

through consultation and coordination with the NMFS and the USFWS as required by the 

 80 43 U.S.C. §1344(a)(2)(G); Watt I, 668 F.2d 1290, 1320 (D.C. Cir. 1981); Watt II, 712 F.2d 584, 596 

(D.C. Cir. 1983); Center for Biological Diversity v. U.S. Department of the Interior, 563 F.3d 466, 488

(D.C. Cir. 2009).
139

ESA, Magnuson-Stevens Fishery Conservation and Management Act (MSFCMA), and 

MMPA. Biological opinions arising from these consultations identify Reasonable and 

Prudent Measures, Terms and Conditions, and/or Conservation Recommendations that 

can then be applied as lease stipulations.81

Oil Spills

One measure of relative environmental sensitivity is the sensitivity of the various 

ecological components to spilled crude oil. Unlike some assessments in the 

programmatic and sale-specific EISs designed to estimate potential risks from proposed 

oil and natural gas leasing activities, this relative environmental sensitivity analysis does 

not consider risk, nor do the rankings for environmental sensitivity reflect potential risk. 

Analysis of the effects of oil and natural gas activities is left to programmatic, salespecific, and site-specific reviews conducted pursuant to NEPA. The Five Year Final 

EIS, prepared in conjunction with this decision document, describes the biological 

environments of the OCS regions in Chapter III and discusses the potential environmental 

consequences of OCS program activities in Chapter IV. 

Sound

Another measure of relative environmental sensitivity is the sensitivity of marine fauna to 

sound. Seismic surveys, drilling and production activities at OCS facilities, and support 

vessel traffic generate sound that could affect marine resources. This analysis assumes 

that monitoring and mitigation measures, such as the use of independently contracted 

protected species observers to monitor exclusion zones around the source vessels and 

shut down procedures when protected species are within the exclusion zone, would 

continue to be included as lease stipulations to minimize impacts from sound on marine 

resources. Such monitoring and mitigation measures would be developed through 

consultation and coordination with NMFS and USFWS as required by ESA, MSFCMA, 

and MMPA. 

Physical Disturbance

Another measure of relative environmental sensitivity is the sensitivity of various 

ecological components to physical disturbance. Physical disturbance includes bottom 

disturbances from OCS platform and pipeline emplacements, as well as from anchors. 

This analysis assumes that BOEM will continue to require site-specific surveys to assist 

in avoiding direct contact with marine habitats. However, unavoidable or accidental 

disturbances could result in physical destruction and burial of organisms and habitat. 

 81 In Center for Biological Diversity v. U.S. Department of the Interior, 563 F3d 466 (D.C. Cir. 2009), the 

U.S. Court of Appeals for the District of Columbia Circuit upheld “graduated compliance with 

environmental and endangered life standards, [thereby making] ESA requirements more likely to be 

satisfied both in an ultimate and a proximate sense.”
140

Habitats and Biota Analyzed

Distribution, abundance, and environmental sensitivities of four ecological components 

within and on the adjacent coast of each OCS program area are first evaluated based on 

their present condition. Thereafter, climate change effects projected to occur over the life 

of the program are considered in order to adjust for increased sensitivity to oil and natural 

gas activities. While this analysis continues to use NOAA’s ESI data to analyze the 

sensitivity of shoreline or coastal habitats, it does not use those data as a proxy for overall 

marine sensitivity, but separately considers the sensitivity of offshore marine resources. 

BOEM has identified three relevant components of the various areas of the OCS 

biological marine environment that may be affected by oil and natural gas activities: 

marine habitats, marine productivity, and marine fauna (i.e., birds, fish, marine mammals 

and sea turtles).

This analysis is directed at the environmental sensitivity requirement under section 

18)(2)(a)(D) of the Act rather than considering the social value of these habitats and 

biota. The social value, such as subsistence or cultural use, is the analysis under section 

18(2)(a)(D), which is in this document. As an affecting factor, subsistence harvests 

include birds, fish and marine mammals in all coastal areas of Alaska. However, marine 

mammal harvests are managed by NMFS and USFWS within the potential biological 

removal of each stock and U.S. law prohibits any harvesting of sea turtles. Commercial 

fishing and recreational or subsistence harvests of fish and birds are managed within 

sustainable limits under existing laws and are reflected in the abundance levels of these 

resources in each OCS program area. Subsistence harvests, in particular, represent a very 

small amount of the total annual harvest. Therefore, subsistence harvest and other uses of 

the OCS are properly addressed as social values under section 18(a)(2)(D).

Reports, Studies and Data Used

Section 18 (a)(2)(A) of the Act specifies that required analyses, including the relative 

environmental sensitivity analysis, shall be based on a consideration of existing 

information. Earlier relative environmental sensitivity and marine productivity analysis 

relied on only two studies (CSA, 1990 and 1991) and one dataset 

(http://response.restoration.noaa.gov). In contrast, this analysis relies on almost 50 

reports, studies, and datasets (see section 6). 

Qualifications

To facilitate the evaluation of scheduling and preparing for sales in a Five Year Program, 

the OCS is divided into 26 administrative geographical units called planning areas. (See 

Maps 1 and 2 in part III of this document.) The program areas analyzed in this document 

encompass all or parts of the six relevant planning areas. These are areas, rather than 

ecoregions, for which decisions on the size, timing and location of lease sales will be 

made. They do not necessarily correspond to ecosystem boundaries, and sometimes do 

not correspond to geographic areas with which the public is familiar. BOEM expects that 

its future analyses of the relative environmental sensitivity on the OCS, including the 

ongoing research noted in the introduction to this section, are most likely to take 

ecosystem boundaries into consideration. 
141

In this analysis, relative environmental sensitivity is defined as the vulnerability of an 

OCS area’s ecological components, i.e., coastal habitats, marine habitats, marine fauna, 

and marine productivity, to the potential impacts of OCS oil and natural gas activities in 

comparison to the same ecological components in other OCS program areas. Risk, 

likelihood of adverse impact, and amount or size of disturbance is considered in the Five 

Year Final EIS. 

3. Ecological Components

The relative environmental sensitivity ranking of OCS program areas by various 

ecological components is presented in Table 18 from most sensitive to less sensitive to 

impact from OCS oil and natural gas activities. The rankings below are based on scoring 

of the OCS program areas as described later in this section. 

This analysis continues to use NOAA’s ESI data to analyze the sensitivity of coastal 

habitats, thus indirectly including coastal fauna and productivity (see section 3.1). This 

analysis also separately considers marine resources. However, there is not an equivalent 

dataset available for the biological marine environment, so this analysis has identified 

three components to the biological marine environment that may be affected by OCS oil 

and natural gas activities: marine habitats, marine productivity, and marine fauna (i.e., 

birds, fish, marine mammals and sea turtles). 

The potential response of these four ecological components were considered and scored 

separately from the potential effects of oil and natural gas development. This analysis 

does not try to account for the interaction of these components in relation to each other, 

as this would involve a complex, ecosystem-level study, which is beyond the scope of 

this review.
142

Table 18: Ranking of OCS Program Areas by Relative Environmental Sensitivity 

from Most to Less Sensitive to Impact1

Coastal Habitats Marine Habitats Marine Fauna Marine Productivity

Eastern GOM 

Central GOM

Western GOM 

Beaufort Sea 

Cook Inlet 

Chukchi Sea 

Eastern GOM 

Beaufort Sea 

Central GOM 

Western GOM 

Chukchi Sea 

Cook Inlet 

Central GOM 

Eastern GOM 

Western GOM 

Cook Inlet 

Chukchi Sea 

Beaufort Sea 

Cook Inlet

Eastern GOM

Central GOM 

Western GOM 

Chukchi Sea 

Beaufort Sea 

1 Most sensitive areas are at the top of the columns, less at the bottom. 

In the case of ties, OCS program areas were listed in alphabetical order.

3.1 Coastal Habitats

Spilled oil is a major environmental risk from OCS oil and natural gas activities. Coastal 

environmental resources face the most significant environmental consequences from 

contact with spilled oil. Although the occurrence of an OCS oil spill that contacts the 

shoreline would be a rare event, its unlikely occurrence could result in widespread effects 

on biological resources over a large area. Direct contact to coastal biota and habitats 

could result in mortality, weakened populations and habitat degradation. Cleanup and 

restoration activities could result in further disruptions to fauna. Oil that persists in the 

environment after cleanup operations would continue to be rereleased into the 

environment, causing effects over an extended period of time. Examples of the potential 

magnitude and duration of these effects have been documented in studies of major marine 

spills, such as Exxon Valdez (Peterson et al. (2003)), and are being r-evaluated in the 

wake of the 2010 Deepwater Horizon event.

Concerns about oil spill impacts are reflected in the scoping information and public 

comments collected by BOEM during the preparation of EISs. Because oil spill effects 

are the major environmental concern when addressing coastal environments, this analysis 

uses the ESI database developed by NOAA to measure coastal relative environmental 

sensitivity. The ESI shoreline database provides a systematic method for compiling 

standardized data to map shoreline sensitivity to spilled oil. Coastal states and Federal 

agencies, including BOEM, assisted in ESI development efforts and use ESI products. 

The ESI scoring approach has a strong scientific basis, and has been used for oil spill 

response planning for over three decades in the United States and overseas. The ESI 

shoreline database is complete for all coastal states with the exception of Washington, 

Oregon, and Maine. However, not all of this data is needed for this analysis. 

The ESI shoreline type classification uses standardized definitions of shoreline 

characteristics to assign the sensitivity rankings. The shoreline type classification is 

based on factors that include:
143

• Relative exposure to waves and tidal energy;

• Biological productivity and sensitivity of shoreline material;

• Substrate type (grain size, permeability, trafficability, and mobility);

• Shoreline slope;

• Ease of cleanup; and,

• Ease of restoration.

These factors determine how long the oil will persist in the shoreline environment and 

continue to cause potential environmental damage, how much damage may occur to the 

biologic properties of the shoreline substrate, and how much environmental damage may 

result from cleanup and restoration efforts. The sensitivity of many coastal biologic and 

socioeconomic resources to oil spills is determined to a large degree by these factors. 

Each shoreline segment is assigned an ESI score between 1 and 10 in order of increasing 

sensitivity to oil spill. Table 19 provides descriptive information about the types of 

shorelines associated with each score. Comparison of the standardized data over large 

areas reveals patterns in the distribution of the relative environmental sensitivity of 

coastal areas to oil spills. More information on the ESI shoreline can be found at 

http://response.restoration.noaa.gov.

Table 19: ESI Scoring and Respective Descriptions

ESI Score Description

1 Exposed rocky shores; Exposed, solid man-made structures

2 Exposed wave-cut platforms in bedrock, mud, or clay; Exposed scarps and 

steep slopes in clay

3 Fine to medium-grained sand beaches; Scarps and steep slopes in sand

4 Coarse-grained sand beaches

5 Mixed sand and gravel beaches

6 Gravel beaches; Riprap

7 Exposed tidal flats

8 Sheltered rocky shores and sheltered scarps in bedrock, mud, or clay

9 Sheltered tidal flats; Vegetated low banks

10 Salt/brackish-water marshes; Freshwater marshes/swamps; Scrub-shrub 

wetlands; Inundated tundra 

The shoreline analysis that follows is based on all the available digital ESI shoreline data 

from NOAA for the six program areas. These ESI line data sets were aggregated or 

disaggregated as appropriate to represent respective program areas. Each ESI value was 

weighted by the length of its line segment. An average rating for the OCS program area 

was calculated based on the weighted average of the ESI for the coastal areas adjacent to 

the OCS program area. 

The results of this analysis are shown in Table 20, which lists the average ESI shoreline 

scoring by OCS program area in order of decreasing average ESI shoreline sensitivity 

rank. The table ranks OCS program areas with the greatest amounts of sensitive 
144

shorelines, as reflected in high average ESI shoreline sensitivity rank, as being the most 

sensitive.82

High scores at or near a score of 9.0 occur adjacent to the full Eastern and Central GOM 

planning areas, where extensive coastal lowlands made up of wetlands, swamps and other 

sensitive shorelines occur. The program areas considered in this analysis in the Eastern 

GOM and Chukchi Sea are not adjacent to the shoreline. However, their planning area 

ESI values are included in the analysis below. The variation in ESI shoreline sensitivity 

rank used as a measure of coastal environmental sensitivity is the result of geographic 

variations in coastal geologic, biologic, and oceanographic characteristics that affect the 

degree to which oil accumulates and persists in coastal areas. The actual presence or 

occurrence of specific biologic environmental resources is indirectly considered in the 

calculations, because accumulation and persistence of spilled oil would be the primary 

factors for determining impacts to these resources. A program area bordered by a rocky 

coastline would have a lower sensitivity to oil spills because less oil would typically 

accumulate and the oil’s presence in the environment would be relatively short-term. As 

a result the impacts on the affected environmental resources would be less severe than in 

a more sensitive area. 

Table 20: Relative Environmental Sensitivity to Impact of the OCS Program Areas 

for Coastal Habitats

OCS Program Area Average 

ESI Score1

Eastern GOM 9.1

Central GOM 8.9

Western GOM 7.6

Beaufort Sea 7.4

Cook Inlet 5.9

Chukchi Sea 4.9

1 Higher scores indicate greater sensitivity to spilled oil.

3.2 Marine Habitats

Marine habitats are the arrangements of geologic, oceanographic, and biologic features of 

the ocean that combine in characteristic ways to create environments favorable for the 

establishment, flourishing, and continued survival of the flora and fauna of marine and 

ecologically connected coastal areas. 

 82 This method does not give extra weight to areas with smaller amounts of sensitive shoreline based upon a 

sensitive shoreline’s rarity. While that kind of comparative analysis would be possible, it would require 

much more subjectivity and could undermine the agency's best efforts to create as objective an analysis as 

possible in comparing these greatly disparate areas. In addition, because persistence of oil, its penetration 

into shoreline substrate and the difficulty of cleanup are by far the most important factors in determining 

effects to shorelines and their inhabitants, the average sensitivity of an area’s shoreline is the best 

comparative tool for conducting the difficult analysis required.
145

Marine habitats, seaward of the shoreline, are divided into benthic or pelagic categories 

as shown in Table 21. Benthic marine habitats are attached to the seafloor. Some benthic 

features, such as kelp forest, can extend vertically from the seafloor upward to near the 

ocean surface, and downward, in the case of submarine canyons, over a thousand meters 

deep. Pelagic habitats occur within or at the surface of the ocean independent of the 

seafloor. Examples include drifting surface Sargassum vegetation that provides habitat 

for fish and marine reptiles, areas where dynamic ocean circulation processes result in 

high biological productivity, and sea ice. The analysis also includes the presence of 

officially designated Federal marine critical habitats (U.S. Department of Commerce 

(USDOC), NOAA Fisheries, Office of Protected Resources, (2009a); and USFWS, 

(2009b)) and marine sanctuaries (USDOC, NOAA (2009)) as a factor in marine habitat 

scores.

Table 21: Examples of Marine Habitat Components*

Benthic

Marine Habitat 

Type Example OCS Area

Vegetated Big Bend seagrass Eastern GOM

Bottom Relief 

Features Pinnacle trend Central GOM

Coral Reef Florida Keys Straits of Florida

Deep/Cold Water 

Coral

Aleutian Islands Coral 

Gardens Aleutian Arc

Seeps Chemosynthetic 

communities Western GOM

Canyons Baltimore Canyon Mid-Atlantic

Pelagic

Marine Habitat 

Type Example OCS Area

Ice Polynyas Chukchi Sea

Vegetated Floating Sargassum South Atlantic

Oceanic Process Ocean upwelling Central California

Designated Habitat/Sanctuary

Marine Habitat 

Type Example OCS Area

Critical Habitat Polar Bear Chukchi and Beaufort

Seas

Marine Sanctuary Cordell Bank Central California

*Some of component examples are areas that are not included in this PFP, but are included as 

illustrative of the breadth of the analysis only.

The analysis identified the relative abundance of benthic habitats, pelagic habitats, and 

designated habitat/sanctuary areas in each of the six OCS program areas. A relative 

abundance value (i.e., high = 3, moderate = 2, and low = 1) was determined for each 
146

habitat type by the amount and kind of habitat that occurs within each OCS program area. 

(See Table 22.) No abundance value was applied if the habitat was absent from the OCS 

program area. Information sources used to estimate abundance values include published 

reports and publications (for example, Navy (2005, 2006, 2007a, 2007b, 2008a, 2008b 

and 2008c); GeoHab (2008); McGee et al. (2006); Lumsden et al. (2007); and SEAMAP 

(2001)), and internal agency information from environmental documents and data.
147

Table 22: Marine Habitat Abundance Values

Marine Habitat 

Type

Abundance Value Criteria

High (3) Moderate (2) Low (1)

Benthic

Vegetated Widespread occurrence of 

seagrasses extending 

beyond the coastal fringe

Some occurrence of 

seagrasses beyond 

coastal fringe 

Scattered occurrences 

limited to coastal 

fringes

Relief Features Abundant features with 

relief of 100 meters or 

more

Some high relief 

features

Low relief features 

only or scattered 

occurrence of features

Chemosynthetic 

Communities

Likely abundant 

occurrence of features

Likely occurrence of 

features

Unlikely occurrence of 

features

Cold/Deep Coral Extensive occurrence of 

coral and communities 

with reef building coral 

Abundant coral 

organisms but no reef 

building

Occurrence of coral 

organisms

Tropical Coral Extensive development of 

coral communities and 

reefs

Coral communities

occur

Coral organisms occur

Canyons Abundant canyon habitat 

with high relief

Common occurrence 

of canyon habitat, 

some with high relief

Some canyon habitat

Pelagic

Ice Substantial sea and 

landfast ice existing for > 

6 months/year 

Substantial sea and 

landfast ice for < 6 

months/year

Discontinuous or 

scattered ice for < 4 

months/year

Vegetated Widespread occurrence of 

coalesced vegetative mats

Some occurrence of 

floating mats

Scattered occurrences

High 

Productivity 

Resulting from 

Oceanic 

Processes

Widespread occurrence in 

area for much of the year

Some occurrence for 

much of the year; or 

widespread for part of 

the year

Scattered and shortterm occurrences

Benthic habitats are considered predominantly sensitive to bottom disturbances 

associated with anchoring, structure installation and removal, and pipeline installation 

activities. While marine oil spills are unlikely to contact benthic habitats, spills of 

synthetic drilling muds from a platform could settle on benthic habitats (Boland et al. 

(2004)). Physical disruption, destruction, and smothering of benthic habitat from these 

activities could result in long term or permanent impacts because of slow recovery rates 

from physical disturbances. 
148

Pelagic habitats are assumed to be most sensitive to oil spills, as these habitats would be 

exposed at or near the sea surface to open contact from marine spills. Pelagic habitats 

typically are seasonal as their occurrences are related to seasonal properties of the global 

ocean circulation and temperature of the atmosphere. As a result, while the habitat could 

be degraded to the extent of being unavailable or dangerous to the habitat users for the 

remainder of the season, the habitat could return in the next cycle of its occurrence with 

no remnant evidence of the spill. Pelagic habitats also could be sensitive to disturbance 

from nearby normal OCS operations, such as service vessel and helicopter traffic, 

regulated discharges, and sound.

Impact coefficients were developed based on the expected sensitivity of marine habitats 

to oil and natural gas activities. The analysis applies the same degree of sensitivity to 

both the short-term but potentially dramatic impacts to pelagic habitats from oil spills and 

the potentially long-term impacts from bottom disturbances. The highest impact 

coefficient of 4 was used in habitats that span both pelagic and benthic environments, 

such as seagrasses and coral reefs that occur in relatively shallow water and could be 

exposed to impacts from both oil spills and bottom disturbances. The highest impact 

coefficient of 4 also was applied to sea-ice habitat, which, by its physical presence during 

much of the year, would keep the oil more confined and concentrated than what would 

occur in an open-ocean habitat. A slightly lower impact coefficient of 3 was applied to 

floating vegetation, whose habitat value could become degraded through absorption of 

oil, but not bottom disturbance. The lowest coefficient of 2 was applied to the remaining 

habitats.

The presence of marine sanctuaries, critical habitat, and other officially designated and 

protected marine habitat areas in an OCS program area is used as an additional indicator 

of marine habitat sensitivity. Each federally designated area was given a value of 1. 

Examples include designation of critical habitat for the spectacled eider in the Chukchi 

Sea program area (USFWS (2009a)), and designation of polar bear critical habitat in 

Alaska in 2010 (USFWS (2010)). 

The relative sensitivity scores and rankings of each of the six OCS program areas are 

presented in Table 23 below. The scores were calculated by summing the product of 

each benthic and pelagic marine habitat type’s abundance value by each habitat’s 

sensitivity coefficient. An additional value was added to this sum based on the number of 

federally designated areas present in an OCS program area.
149

Table 23: Relative Environmental Sensitivity to Impact, 

of the OCS Program Areas for Marine Habitats

OCS Program Area Score1

Eastern GOM 43

Beaufort Sea 32

Central GOM 32

Western GOM 32

Chukchi Sea 25

Cook Inlet 17

1 Higher scores indicate greater sensitivity to OCS oil and 

natural gas activities.

3.3 Marine Fauna

The ESI shoreline data provide a systematic method for compiling standardized data to 

map shoreline sensitivity to spilled oil. However, there is not an equivalent dataset 

available for the biological marine environment, so this analysis identifies three 

components of the biological marine environment that may be affected by OCS oil and 

natural gas activities: marine habitats, marine productivity, and marine fauna (i.e., birds, 

fish, marine mammals and sea turtles) to create a comparative analysis and to more fully 

account for the biological aspects of the marine environment. 

3.3.1 Birds

This analysis considers the sensitivity of birds to OCS oil and natural gas activities, 

because bird species comprise important and often prominent elements of most coastal 

onshore, nearshore, and offshore biological communities, especially in Alaska (U.S. DOI, 

MMS (2007)). The greatest source of potential harm to coastal and marine birds from 

OCS oil and natural gas activities is from a large oil spill. The relative sensitivity of 

marine and coastal birds within each OCS program area is dependent upon the number of 

birds that could be exposed to a large oil spill. Birds listed as threatened or endangered 

under the ESA are considered more sensitive to a large oil spill. According to the ESA, a 

species is considered endangered if it is in danger of extinction throughout all or a 

significant portion of its range. Marine and coastal birds were considered to primarily 

consist of three species groups--seabirds, waterfowl, and shorebirds. 

The evaluation of the sensitivity of marine and coastal birds was limited to spilled crude 

oil because (1) the different program areas could be evaluated against a common factor, 

in this case, spilled oil, and (2) oil spills, although rare, are anticipated to cause the 

largest, most visible and measurable effects of OCS activities on birds. Adverse effects 

to marine and coastal birds, such as collisions with structures, displacement/disturbance 

from sound and other human activities, and habitat loss from installation of facilities, etc., 

are individually and collectively much smaller than the potential effects from a large 

crude oil spill.
150

Methodology

The following assumptions were included in the analysis.

(1) Spilled oil has not weathered substantially when it contacts bird populations. The 

impacts of spilled oil are reduced substantially by the effects of weathering. By 

eliminating the mitigating effects of weathering in the analysis of environmental 

sensitivity, the adverse effects of spilled oil, both toxicity and coating, are 

maximized. This assumption is conservative and provides an assessment of the

most severe effects of spilled oil.

(2) All of the bird populations within a program area are vulnerable to being 

contacted by spilled oil. Migratory species, which may inhabit the OCS program 

area for only a short period, are assumed to be present and contacted by spilled 

oil. 

(3) Program areas that have little or no shoreline would have a correspondingly 

small coastal bird population. 

(4) In the absence of site-specific information, marine and coastal bird abundance 

and distribution does not change abruptly from one program area to the next. As 

a consequence, the final assessment required interpolation and extrapolation of 

population numbers based on gradients and trends in the best available 

information. There are legitimate reasons why there can be abrupt differences 

between program areas; i.e., where an island group in one OCS program area may 

host millions of breeding seabirds and the adjacent program area, without nesting 

islands, does not support breeding birds.

(5) The best available datasets reflect the current distribution and abundance of 

marine and coastal bird resources

Best available information on marine and coastal birds was reviewed and used to compile 

total numbers of birds according to the OCS program areas. Much of this information 

came from regional waterbird plans that were specific to seabirds, waterfowl, or 

shorebirds. These plans were often step-down plans from larger continental plans that 

focused on bird resources of a particular bio-conservation unit or country. For example, 

the North American Waterbird Conservation Plan (Kushlan et al. (2002)) steps down 

from the Waterbird Conservation for the Americas Plan. Similarly, USFWS has 

completed a Seabird Conservation Plan for the Pacific Region (USFWS, 2005) and a 

draft plan is completed for Alaska (USFWS (2009c)). Information from the scientific 

literature and books also were used as sources of population information for seabirds, 

waterfowl, and shorebirds using the OCS program areas and adjacent coastal areas. 

Information from these data sources was combined to enumerate birds according to 

coastal or marine habitats. Breeding birds and migratory waterfowl and shorebirds were 

considered associated with nearshore coastal habitats. Summer migrants from the 

southern hemisphere make seasonal use of marine habitats. Where two or more OCS 
151

program areas were included in a population estimate, the population was apportioned 

across the OCS program areas unless particular population segments could be attributed 

to a specific OCS program area. Similarly, where population data was based on a 

geographic area that was larger than OCS program areas, such as including non-U.S. 

waters, the population was apportioned to the OCS program areas. 

The total number of marine and coastal birds using an OCS program area is the primary 

determinant in ranking OCS program areas, because the number of birds using an area is 

directly related to the potential magnitude of effects on the bird population as a whole. 

Each OCS program area is assigned two abundance values based on its relative 

abundance of marine and coastal birds. For both coastal and marine birds, an OCS 

program area with relatively low population size is given a value of 1, moderate is given 

a 3, and high is given a 5. The following convention was used, which generally 

corresponds to natural breaks in the distribution of marine and coastal bird numbers:

Low (1) < 250,000 individuals

Moderate (3) > 250,000 to < 2,500,000 individuals

High (5) > 2,500,000 individuals

Both marine and coastal birds in all OCS program areas have an equally high sensitivity 

to oil spills. Therefore, all OCS program areas are assigned a sensitivity value of 5 for 

both marine and coastal birds. 

Threatened and endangered birds are typically perceived to have unique sensitivities to 

adverse effects that could affect the recovery of these species. Therefore, status under the 

ESA was considered a secondary factor for ranking OCS program areas for the relative 

sensitivity of birds to oil and natural gas activities. Each ESA-listed bird species present 

in an OCS program area is given a value of 1.

Each OCS program area’s relative sensitivity score is calculated by summing (1) the 

product of the marine bird abundance and sensitivity values (2) the product of the coastal 

bird abundance and sensitivity values, and (3) the number of ESA-listed species. 

(Marine Abundance Value X Sensitivity Value)

+

(Coastal Abundance Value X Sensitivity Value)

+

Number of ESA-listed species

Results

Population data was compiled on marine and coastal birds for each OCS program area as 

shown in Table 24. However, there were some challenges associated with compiling this 

data. Such challenges include (1) complete datasets were not available for seabirds, 

waterfowl, and shorebirds for all program areas; (2) while some datasets appeared to be 

highly accurate, this accuracy was not fully transferable to this analysis because the 
152

datasets applied to a large geographic area that required subdividing according to country 

and/or program area, which assumed bird resources were evenly distributed; and (3) 

information contained in contemporary conservation plans reported information 

differently, often either as breeding pairs or individuals, but seldom accounting for nonbreeding adult or juvenile bird sub-populations. A few plans also reported population 

data as a term that corresponded to a numeric range. Some of these ranges were wide. In 

such cases, and consistent with a conservative approach, the maximum number of a range 

was used for population estimates. While some inconsistency in the marine and coastal 

bird data sets was noted, this did not prevent the relative comparison of OCS program 

areas as data were combined at a scale that minor differences did not disproportionately 

influence the grouping by abundance, which was the primary factor in determining the 

vulnerability of marine and coastal birds to a large oil spill.
153

Table 24: Relative Environmental Sensitivity to Impact of 

the OCS Program Areas for Coastal and Marine Birds

OCS Program Area Score1 General Abundance 

(coastal/marine) ESA-Listed Species2

Chukchi Sea 32 moderate/moderate STEI, SPEI

Central GOM 23 moderate/low BRPE, LETE, PIPL

Eastern GOM 23 moderate/low BRPE, LETE, PIPL

Western GOM 23 moderate/low BRPE, LETE, PIPL

Beaufort Sea 22 moderate/low STEI, SPEI

Cook Inlet 21 moderate/low STEI 1 The total score was calculated by summing (1) the product of the marine bird abundance and sensitivity 

values (2) the product of the coastal bird abundance and sensitivity values, and (3) the number of ESAlisted species. Higher scores indicate greater sensitivity to OCS oil and natural gas activities. 

2 Birds listed as threatened or endangered: BRPE = Brown Pelican; LETE = Least Tern; PIPL = Piping 

Plover; SPEI = Spectacled Eider; STEI = Steller's Eider.

3.3.2 Fish

This analysis considers the sensitivity of fish to OCS oil and natural gas activities (not 

only to spilled oil, as was done for birds), because most OCS program areas support 

varied and abundant fish and shellfish populations, including threatened and endangered 

species, non-listed species, and fishes and shellfish important to commercial and 

recreational fisheries (U.S. DOI, MMS). The following analysis discusses the relative 

sensitivity of each OCS program area’s estuarine, diadromous and marine fish and 

shellfish to potential negative impacts of OCS oil and natural gas activity. Most OCS oil 

and natural gas activities have the potential to alter fish behavior. There may be physical 

injury of individuals in the immediate vicinity of airguns and death of individuals in the 

immediate vicinity of explosive removals. Pelagic eggs and larval fish would be most 

sensitive to oil spills. This analysis of the sensitivity of fish does not consider sensitivity 

of coastal and marine habitats to OCS oil and natural gas activity, because they are 

discussed in sections 3.1 and 3.2 above, respectively. 

While individual fish may be physically injured or killed in the immediate vicinity of air 

guns, explosive removals or oil spills, OCS oil and natural gas activities are not expected 

to add significantly to the mortality of fish populations. However, individual species 

already at risk, as indicated by the ESA listings or status of U.S. fisheries stocks, may be 

more sensitive to species-level impacts from these activities and events. 

There are estuarine, diadromous and marine fish and shellfish listed as either endangered 

or threatened species under the ESA in three of the six OCS program areas, Central and 

Eastern GOM and Cook Inlet. According to ESA, a species is considered endangered if 

it is in danger of extinction throughout all or a significant portion of its range. A species 

is considered threatened if it is likely to become endangered in the future. The two ESA 

statuses are weighted by severity in Table 25 with individual threatened species assigned 

a value of 5 and individual endangered species assigned a value of 10. 
154

Table 25 shows the number of marine fisheries stocks designated as overfished or subject 

to overfishing. A stock that is overfished has a biomass level below a biological 

threshold. A stock that is subject to overfishing has a fishing mortality or harvest rate 

above the level that provides for the maximum sustainable yield or the largest average 

catch or yield that can continuously be taken from a stock under existing environmental 

conditions. Stocks can be designated in both categories and these two categories are 

weighted equally in this analysis. Each overfished stock or stock that is subject to 

overfishing in an OCS program area is given a value of 1.

This analysis used the weight of commercial landings to estimate relative abundance of 

fish for each OCS program area. The OCS program areas are divided into three 

categories of relative abundance to compensate for any bias in the data caused by timing, 

location, and effort of commercial fishing. The abundance categories used are:

Low (5) < 200 million pounds;

Moderate (25) 200 million to 1 billion pounds; and

High (50) > 1 billion pounds.

Commercial landings provided the most recent and complete dataset for the OCS 

program areas. While stock assessments may be more accurate, they are not available for 

all species and areas, and may not be as recent as the commercial landings data. While 

Alaska accounts for over half of the U.S. commercial landings, those values had to be 

allocated among the 15 Alaskan OCS planning areas (Woodby et al.(2005)). Therefore, 

not every Alaskan OCS program area was given a value of High for relative abundance.

Each OCS program area’s overall score was calculated by adding its relative abundance 

value to the sum of its ESA score and number of stocks subject to overfishing and/or 

overfished. Table 25 presents the relative sensitivity of each OCS program area’s fish 

population to OCS oil and natural gas activities. 
155

Table 25: Relative Environmental Sensitivity to Impact of the 

OCS Program Areas for Fish

OCS Program Area

Total 

Score1

ESA Species2 Stocks Subject 

to Overfishing 

and/or 

Overfished4

Relative 

Abundance 

(Value) Number 5

Endangered

Number 

Threatened Score3

Central GOM 68 0 1 5 13 50

Eastern GOM 34 1 1 15 14 5

Cook Inlet 30 0 1 5 0 25

Western GOM 18 0 0 0 13 5

Beaufort Sea 5 0 0 0 0 5

Chukchi Sea 5 0 0 0 0 5 1 The total score was calculated by adding the abundance value to the sum of the ESA score and number of 

stocks subject to overfishing and/or overfished. Higher scores indicate greater sensitivity to OCS oil and 

natural gas activities.

2 Sources: USDOC, NOAA Fisheries, Office of Protected Resources, 2009b and 2009c. 3 Individual endangered species were given a value of 10 and individual threatened species were given a 

value of 5. The ESA score is the total number of species multiplied by their value. 4 Source: USDOC, NMFS, 2009. 5 Relative abundance: Low (5) = < 200 million pounds, Moderate (25) = 200 million to 1 billion pounds, 

and High (50) = > 1 billion pounds. Sources: USDOC, NOAA Fisheries, Office of Science and 

Technology, 2009; Woodby et al., 2005.

3.3.3 Marine Mammals

As a group, marine mammals include whales, dolphins, porpoises, seals, sea lions, 

walrus, dugongs, manatees, sea otters, and polar bears. Marine mammals are widely 

distributed throughout the world’s oceans and are represented in all OCS program areas. 

Marine mammals can profoundly influence marine ecosystems and are generally 

considered to be good indicators of changes in the marine environment.

The diversity of marine mammal species and their sensitivity to OCS oil and natural gas 

activities vary among OCS program areas. For this analysis, recent marine mammal 

stock assessment reports prepared by the NMFS and USFWS (Angliss et al. (2009); 

Carretta et al. (2009); and Waring et al. (2009)) were used to identify marine mammal 

species present in each OCS program area. Species may occasionally wander beyond the 

ranges identified in the stock assessment reports but this analysis excludes extralimital or 

out-of- area sightings, such as humpbacks in Arctic waters, because of their relative rarity 

and unpredictability. 

Each species in a program area was evaluated with respect to the following factors − the 

species’ listing status, sensitivity to oil spills, and sensitivity to underwater sound. Each 

of these factors was considered equal in importance and values between 0 and 10 were 

assigned to rate sensitivity of each species within each factor. Differences in how a 

species may react to OCS oil and natural gas activities in high human use areas versus 

low human use areas were not evaluated because of the inherent complexity of marine 

mammal behaviors.
156

Listing Status

A marine mammal may be listed as “depleted” under MMPA or “threatened” or 

“endangered” under ESA. For each OCS program area, the listing status of each marine 

mammal species was identified. Recognizing that there are significant differences 

between the definitions of each status, a value of 1 was assigned for marine mammal 

stocks listed as depleted under MMPA, a value of 5 for species listed as threatened under 

ESA, and a value of 10 for species listed as endangered under ESA. Candidate species 

and species petitioned for listing are not given added value because their status is under 

review, and therefore, decisions on listings under ESA are uncertain. 

This analysis includes recently listed species, such as the threatened southern Beaufort 

Sea and Chukchi/Bering Sea stocks of polar bear, thus adding to the value attributed to 

program areas that support these species. Critical habitat for listed species was 

considered in the marine habitat component (section 3.2 above) of this environmental 

sensitivity analysis and is not included in the marine mammal component. 

Sensitivity to Oil Spills

In general, marine mammals are affected by oil spills through direct contact, inhalation, 

or ingestion of oil or oil-tainted prey. Based on mortalities and injuries experienced 

during past oil spill events, marine mammal species, such as sea otters, known to be 

highly susceptible to oil spills, were assigned a value of 10. In this analysis, Arctic 

species with limited access to open ice-free water also were considered highly susceptible 

based on perceived risks associated with these species' inability to avoid extended contact 

with spilled oil in a confined marine environment. All other species were considered less 

susceptible to oils spills and assigned a value of 5. Environmental sensitivity of shoreline 

habitat that some marine mammals may use is captured in the shoreline sensitivity 

analysis.

Sensitivity to Underwater Sound

Exploration for oil and natural gas often requires noise-producing seismic surveys to 

locate and identify key geologic features. Offshore construction activities such as pile 

driving also may introduce sound into the marine environment. Many species of marine 

mammals depend on creation and detection of sound to navigate; find prey, potential 

mates or calves; and avoid danger. 

All marine mammal species have some ability to detect anthropogenic sound, but values 

were assigned differently for species that depend on sound for critical life functions and 

that may be affected by sounds typically associated with OCS oil and natural gas 

activities, than for those species who operate in frequencies outside the normal range of 

sounds created by OCS activities. Species that do not use sound for navigation, 

underwater communication, and/or to find prey/mates were assigned a value of 1. 

Species that use sound for navigation, underwater communication, and/or to find 

prey/mates/offspring at frequencies outside the typical range of offshore development 
157

sound were assigned a value of 5. Species that use sound for navigation, underwater 

communication, and/or to find prey/mates at frequencies within the typical range of 

offshore development sound were assigned a value of 10. The latter includes all deep 

diving cetacean species.

Calculation of OCS Program Area Rankings

For each species a score was calculated by adding the values given for that species’ 

listing status, sensitivity to oil spills, and sensitivity to underwater sound. The resulting 

scores for each species within a program area were added to create an overall score for 

the OCS program area. The OCS program area scores then were ranked according to 

values with higher scores indicating a higher sensitivity

OCS Program Area Rankings with Respect to Marine Mammal Sensitivity

The marine mammal sensitivity methodology described above yields the ranking of OCS 

program areas presented in Table 26.
158

Table 26: Relative Environmental Sensitivity to Impact of the OCS Program Areas for Marine Mammals

OCS 

Program 

Area

Total 

Score1

Number 

of 

Species

Number of 

Species by 

Listing Status

Listing 

Status 

Score2

Number of 

Species by 

Oil Spill 

Sensitivity

Oil Spill 

Sensitivity 

Score3

Number of Species 

by Sound Sensitivity

Sound Sensitivity 

Score3

E T D H M H M L

Eastern 

GOM 255 20 2 0 0 20 0 20 100 7 13 0 135

Central 

GOM 225 18 1 0 0 10 0 18 90 7 11 0 125

Cook Inlet 182 12 4 0 1 41 1 11 65 4 6 1 76

Chukchi 

Sea 180 11 1 1 0 15 8 3 95 3 8 0 70

Western 

GOM 170 13 1 0 0 10 0 13 65 6 7 0 95

Beaufort 

Sea 155 9 1 1 0 15 8 1 85 2 7 0 55

1

The total score was calculated by adding the listing status, oil spill sensitivity, and sound sensitivity scores. Higher scores indicate greater sensitivity to OCS 

oil and natural gas activities.

2

Sum of the products of number of listed species and status value (i.e., endangered (E) = 10, threatened (T) = 5, and depleted (D) = 1). 3

Sum of the products of number of species and sensitivity value (i.e., high (H) = 10, moderate (M) = 5, and low (L) = 1).
159

3.3.4 Sea Turtles

Sea turtles are greatly influenced by ocean temperature, therefore, are not found in all 

OCS program areas. However, all sea turtles are listed as either endangered or threatened 

under ESA. They are considered susceptible to oil and natural gas activities, including 

sensitivity to possible oil spills and possible hearing sensitivity to the low frequency 

sounds generated by exploration, pile driving, and drilling activities. Therefore, sea 

turtles are considered in this analysis.

The diversity of sea turtle species varies among OCS program areas. To identify sea 

turtle species likely to occur in OCS program areas and to determine their relative 

vulnerability, this analysis considered all Recovery Plans, 5-Year Reports for sea turtles, 

published by the NMFS and USFWS, as well as NMFS and USFWS Status Reviews for 

Sea Turtles Listed under the ESA (Plotkin et al. (1995)) and Occurrences of Marine 

Turtles in Alaska Waters: 1960-1998 (Hodge and Wing (2000)). Species found in each 

OCS program area were identified and assigned values for (1) Presence (rare, seasonal, 

year-round); (2) Status (threatened and endangered under ESA); (3) Relative sensitivity 

to oil spills (high); and, (4) Relative sensitivity to underwater sound (medium). Further 

clarification of how values were assigned for each species and how the values were 

combined to rank OCS program areas is provided in the following discussion.

Presence

Sea turtles are found in only some of the OCS program areas and the number of species 

found in any given area varies. The distribution of most species of sea turtle is limited by 

water temperature and varies by season. They are highly migratory and therefore have a 

wide geographic range in tropical, sub-tropical, and temperate waters. 

By default, OCS program areas with more sea turtle diversity may achieve higher scores 

than those with fewer sea turtle species. However, some species may be exceedingly rare 

and others may be year-round residents in an OCS program area. Year-round residents 

may be disproportionately affected by offshore activities and are factored higher. In this 

analysis, species rarely seen in an OCS program area, i.e., an OCS program area that is 

outside the normal range but has a record of sightings, are assigned a value of 1. Species 

with seasonal or occasional visitors are assigned a value of 2. Species with year-round 

residents and areas known for nesting are assigned a value of 3. Program areas with no 

data indicating the presence of sea turtles were not further analyzed and were assigned a 

value of 0.

Status

All sea turtles have a protected status with respect to ESA and the Convention on 

International Trade in Endangered Species. They are either listed as “threatened” or 

“endangered” under ESA. Special consideration is given to these species when planning 

OCS oil and natural gas activities and formal consultations between BOEM and NMFS 

and/or USFWS as may be required by law. At this time, there is no critical habitat for 
160

any sea turtles in any of the OCS program areas. The presence of special status species in 

each OCS program area is important to the decision-making process. Threatened species 

are assigned a value of 5 and endangered species are assigned a value of 10. 

Relative Sensitivity to Oil Spills

This analysis does not attempt to identify all possible interactions that may occur between 

sea turtles and oil. A relative sensitivity to oil spills is assigned based on species biology 

and habitat restrictions. All sea turtles, regardless of species, are considered to be highly 

sensitive to oil spills for several reasons, including their need to be at the surface of the 

water to breathe, migratory nature, relatively slow movement, presence in both deeper 

waters and shallower waters, high susceptibility to oil when it reaches the shore, and 

potential difficulty in detecting and avoiding spilled oil. Therefore, all sea turtle species 

were assigned a high sensitivity of 10 relative to risks from oil spills.

Relative Sensitivity to Underwater Sound

Exploration for oil and natural gas often requires noise-producing seismic surveys to 

locate and identify key geologic features. Offshore construction activities such as pile 

driving also may introduce sound into the marine environment. Data on sea turtle sound 

production and hearing are limited. Based on the structure of the inner ear, there is some 

evidence to suggest that marine turtles primarily hear sounds in the low frequency range 

and that turtles are insensitive to high frequencies. Based on the known data, for the 

purposes of this sensitivity analysis, it is assumed that sea turtles have low frequency 

hearing but possibly lower sensitivity to sounds compared to other fauna. Therefore, 

acoustic impacts to sea turtles were assigned a medium sensitivity of 5 relative to risks of 

acoustic impacts.

Calculation of OCS Program Area Rankings

The following function was used to calculate a value for each sea turtle species within 

each OCS program area:

Presence X (Status + Oil Sensitivity + Sound Sensitivity)

All calculated values were added within an OCS program area to create an overall score 

for that OCS program area.

OCS Program Areas Rankings with Respect to Sea Turtle Sensitivity

The sea turtle sensitivity methodology described above yields the ranking of OCS 

program areas presented in Table 27.
161

Table 27: Relative Environmental Sensitivity to Impact of the 

OCS Program Areas for Sea Turtles

OCS Program Area Score1

Eastern GOM 360

Central GOM 345

Western GOM 345

Chukchi Sea 0

Beaufort Sea 0

Cook Inlet 0

1

Higher scores indicate greater sensitivity to OCS oil and natural gas activities.

3.3.5 Combining Fauna and Ordinal Ranking

Marine fauna is the grouping of birds, fish, marine mammals, and sea turtles. Each fauna 

was considered individually first using the different scoring methods described above. 

The resulting scores were normalized for each fauna as shown in Table 28. 

There are many normalization methods available, but not all are appropriate to apply to 

ordinal data. To create an overall marine fauna rank, the most appropriate method to 

apply to the four subsets of marine fauna scores (i.e., fish, birds, marine mammals, and 

sea turtles) is the min-max normalization method. This method subtracts the minimum 

value of a score subset from each OCS program area value and then divides the 

difference by the range of the subset scores, to transform the data into a new range of 

values within the interval [0,1]. This method was applied to the four score subsets. After 

applying the min-max normalization, the four normalized scores for each OCS program 

area were added to create a total normalized score with a range of [0,4]. The overall 

scores were ordered and ranked to obtain the marine fauna rank presented in Table 28.
162

Table 28: Relative Environmental Sensitivity to Impact of the 

OCS Program Areas for Marine Fauna

OCS Program Areas

Fish Birds Marine Mammals Sea Turtles Total

Normalized 

Score Score Normalized Score Normalized Score Normalized Score Normalized 1

Central GOM 68 0.89 23 0.09 225 0.24 345 0.96 2.18

Eastern GOM 34 0.41 23 0.09 255 0.34 360 1.00 1.84

Western GOM 18 0.18 23 0.09 170 0.05 345 0.96 1.29

Cook Inlet 30 0.35 21 0.03 182 0.09 0 0.00 0.47

Chukchi Sea 5 0.00 32 0.38 180 0.08 0 0.00 0.46

Beaufort Sea 5 0.00 22 0.06 155 0.00 0 0.00 0.06

1Higher scores indicate greater sensitivity to OCS oil and natural gas activities.
163

3.4 Marine Productivity

While marine productivity was considered as a separate factor in previous analyses, it is 

considered as a component of this analysis in order to more fully account for the 

biological aspects of the marine environment.

Productivity is a term used to indicate the amount of plant or animal biomass that is 

produced over a period of time. Primary production is the assimilation of organic carbon 

through photosynthesis. The most common example is simply a plant using energy from 

the sun to make organic matter. It is the basis for growth in most ecosystems. The 

productivity of the marine aquatic community is its capacity to produce food for its 

component species, which thus sets limits on the overall biological production in an 

ecosystem. Primary production in the marine environment is conducted primarily by 

phytoplankton; macroalgae, such as Sargassum or kelp; and submerged aquatic 

vegetation like seagrasses. The rate at which this occurs is based largely on the plants’ 

ability to photosynthesize. The methods of measuring phytoplankton productivity are 

relatively standard and results normally are expressed in terms of chlorophyll-a, or the 

amount of carbon fixed during photosynthesis per square meter of ocean surface per unit 

of time. 

Phytoplankton can occupy all surface waters of an OCS program area and fix carbon, as 

long as sufficient light and nutrients are available. Farther from shore, fewer nutrients, 

primarily of terrestrial origin, are available for use by phytoplankton. Surface mixing due 

to wave action, down-dwelling, fronts, and convergence may push some phytoplankton 

down into the water column where light is insufficient for photosynthesis to occur.

Marine ecosystems can be significantly affected by the rates and magnitude of primary 

production within their boundaries. Any alteration in primary production in an 

ecosystem will have wide-ranging effects on all dependent species and chemical 

processes occurring within the affected system. Having sufficient knowledge of the 

magnitude and rates of primary production within an ecosystem allows for an accurate 

understanding of the overall potential productivity within that system. This knowledge 

may help elucidate the potential effects that altering the base of the food-chain may have 

on dependent species and processes. Therefore, it is important to include estimates of 

primary production in any analysis of environmental sensitivity related to OCS oil and 

natural gas activities. Besides any direct effects of an oil spill on higher trophic levels, 

any anthropogenic alteration of the base of the food-chain, such as spilled oil on the 

surface of the ocean decreasing light penetration, and thus decreasing rates of 

photosynthesis of a system, would necessarily affect the functioning of the system as a 

whole. These effects on primary production would most likely be very short term in 

duration and of low magnitude.

For these reasons, OCS program areas have been ranked for relative sensitivity by their 

areal averaged production, the annual amount of carbon produced per acre of ocean 

surface, rather than metric tons per year, as has been used in the earlier analyses. Areas 

with the highest mean levels of productivity are ranked highest, as the potential loss to 
164

the system would have the greatest effect that is seen as a reduction in the amount of 

biomass the area could support. This method allows for a direct comparison of each OCS 

program area without a bias towards ranking OCS program areas higher due to 

encompassing a larger area. It is important to note that measurements of phytoplankton 

can vary greatly both spatially and temporally, resulting in significant differences in 

measurements within and between OCS program areas. 

As discussed earlier in this section, BOEM continues to evaluate the results from a new 

analysis of OCS marine productivity and will include that updated analysis in the future 

relative sensitivity analyses.

Table 29: Relative Environmental Sensitivity to Impact of 

the OCS Program Areas for Marine Productivity

OCS Program Area Metric 

tons/year

Acres 

(Millions)

Areal Averaged 

Production (Metric 

tons/acre/year)

Cook Inlet 24,152,550 5.36 4.506

Eastern GOM 117,466,816 64.56 1.819

Central GOM 110,234,566 66.45 1.659

Western GOM 31,331,220 28.58 1.096

Chukchi Sea 8,237,533 62.59 0.132

Beaufort Sea 4,591,039 65.08 0.071

Sources: Continental Shelf Associates, 1990 and 1991.

4. Climate Change and Relative Environmental Sensitivity

4.1 Introduction

Climate change trends during the 20th century have been detected on all continents and 

oceans, suggesting noticeable relationships among atmospheric concentrations of 

anthropogenic CO2 and other greenhouse gases, mean global temperature increases, and 

observed effects on physical and biological systems. Climate change effects, including

warming air and water temperatures, rising sea levels, and more intense storms have been 

documented in many U.S. coastal regions. New scientific research shows that oceans 

are beginning to face yet another threat due to global warming-related emissions, a 

process referred to as ocean acidification. Basic ocean chemistry is changing because of 

the uptake of CO2 released by human activities (Feely et al. (2006)). These changes will 

continue to affect the habitats and biota discussed in this environmental sensitivity 

analysis, possibly making them more vulnerable to human activities, such as OCS oil and 

natural gas exploration and development. Climate change is discussed in more detail in 

the Five Year Final EIS. 

This section provides an assessment of climate change effects on the relative 

environmental sensitivity of OCS program areas during the life of the Five Year 

Program. The assessment examines the extent to which rising temperatures, sea-level 

rise, and ocean acidification may affect the environmental sensitivity of different areas 
165

of the OCS, as well as whether meaningful differences in the magnitude of these effects 

occur spatially. The time frame of interest is the period affected by the 2012-2017 

Program, which extends 40 years until approximately 2050. This task is challenging 

because the overall response of the global climate to warming is inherently and 

extremely complex due to a number of positive and negative feedbacks that can have 

strong influence on the climate system (Intergovernmental Panel on Climate Change 

(IPCC (2007)). The responses of physical and biological systems to global climate 

change bring additional complexities because climatic, biologic, and physical processes 

interact in complicated and nonlinear ways that are not fully understood at this time. 

Because of the inherent uncertainty in predicting future events and outcomes, and the 

complexities and incomplete understanding of the underlying science that exists at this 

time, climate change projections must be presented in probabilistic terms. 

IPCC uses a 10-fold likelihood scale ranging from virtually certain (>99 percent 

probability of occurrence) to exceptionally unlikely (<1 percent probability) to define 

consistent terminology for climate change projections. This assessment uses 

assumptions and projections from the IPCC report that are considered at a minimum to 

be likely (>66 percent) to occur, in order to focus on the most likely drivers of climate 

change effects on environmental sensitivity. 

Projections of climate change and its effects generally are more reliable when applied 

to a large area than a smaller area. Currently, it is difficult to model temperature 

changes and the processes that temperature changes spawn, at smaller than continental 

scales (IPCC). Reliable projections are possible for areas the size of the Alaskan Arctic 

or GOM, but in most cases existing information does not support making more detailed 

distinctions at the scale of an individual OCS program area. This assessment uses 

projections and assumptions of climate change and its effects that can be reliably 

applied to large areas, such as the Arctic or GOM. The projected increased sensitivity 

of the larger area is applied to the individual OCS program areas that it contains. 

Reliable projections of effects of climate change on individual, or groups of, species 

usually are made at high levels of generality. IPCC concludes that it is likely (>66 

percent chance of occurrence) that 20 to 30 percent of the plants and animals assessed 

so far are at risk of extinction within the next century. However, it does not indicate 

the specific species or groups of species most at risk. Thomas et al. (2004) suggest that 

up to 37 percent of a sample of land plants and animals could become extinct as a result 

of climate change by 2050, a date encompassing the 40-year life of the 2012-2017 

Program. These large extinction scenarios suggest that effects of climate change on 

species will be pandemic in marine and coastal environments. Research is beginning to 

identify possible climate change effects on specific fauna or groups of fauna. A recent 

report identified marine birds as being particularly susceptible to climate change effects 

compared to other birds (Vié, et al. (2008)), a relevant observation if validated with 

additional research. Generally, however, it is not possible to reliably identify 

individual species or species groups with relatively high extinction risks along with the 

OCS program areas where the extinction risks are relatively higher or lower. An 

exception is the Arctic in Alaska, which the IPCC identifies as an “Especially Affected 
166

Region” because of the projected high rates of warming that will likely result in 

substantial degradation of ice-water habitats that many species, and subsistence hunters, 

depend on. 

4.2 Climate Change Factors Influencing Relative Sensitivity and Marine 

Productivity

Climate change impacts on the ocean’s physical properties, such as temperature, winds, 

precipitation, currents, sea level, salinity, and upwelling, will likely affect both openocean and nearshore ecosystems. Changes to the oceans are expected to cause speciesand community-level shifts that will have consequences for species interaction and may 

ultimately affect ecosystem function. Distribution patterns of southern species may shift 

northward as water temperatures warm, but the colonization of new areas will depend on 

successful dispersal across barriers, such as from one estuary to another. The ability of 

species to adapt to different locations will depend on their ability to find suitable habitat, 

compete with other species for resources and avoid predators. Hence, the fundamental 

structure of complex food webs may change. For example, in some cases climateinduced changes may be positive if they increase habitat for depleted fishery stocks, 

while in other cases changes may be negative if they spread the distribution of invasive 

species or disease-causing microbes. Marine and coastal systems are being affected 

negatively by pollution, overfishing, and other stressors that may act in combination 

with climate change to damage ecosystems. 

4.2.1. Temperature

Global mean surface temperatures have risen by 0.74oC ± 0.18o between 1905 and 2005 

(IPCC). The rate of warming for the past 50 years has been almost double the rate for the 

past 100 years (0.13oC/decade). IPCC projections suggest about a 0.8oC increase in 

temperature during the 40 year life of the Five Year Program. 

Atmospheric warming has not been spatially uniform. In particular, Arctic temperatures 

have increased about twice as much as those in lower latitudes. IPCC predicts that the 

Arctic will continue to warm at a faster rate than elsewhere during the time span covered 

by the life of the 2012-2017 Program. Preferential warming in the Arctic partially is the 

result of the ice-albedo effect. This occurs when highly reflective ice is replaced by less 

reflective water and land surfaces, resulting in more heat being absorbed by the land and 

water rather than being reflected back to the atmosphere. About 80 percent of the 

warmth caused by greenhouse gases has been absorbed in the oceans. Evidence for 

warming is widespread in the upper 700 meters of the global ocean (IPCC). 

IPCC reports that there is “high confidence” that rising ocean temperatures are associated 

with observed changes in marine biological systems. Ocean warming will continue 

during the life of the program proportional to atmospheric warming.
167

Environmental Sensitivity Factors Related to Temperature

Species Composition

Climate variation is a recognized, primary driver of marine ecosystems and associated 

biological resources (USDOC, NOAA Fisheries Service). Effects of warming 

temperatures already have been seen in the form of a northward shift of species, change 

in migration patterns and timing, change in location and timing of reproduction, and 

increased disease. As warming drives changes in timing and geographic ranges for 

marine fauna, it is important to note that entire communities of species do not shift intact. 

Rather, the range and timing of each species within an existing community shifts in 

response to its own sensitivity to climate change, mobility, lifespan, and the availability 

of resources. The speed with which species can shift their ranges is influenced by factors 

including their size and lifespan. All of these variations result in the breakup of existing 

ecosystems and formation of new ones, with uncertain consequences (Karl et al. (2009)). 

While all OCS program areas will be affected by species migrations, the Alaskan Arctic 

likely will be relatively more affected. IPCC concludes that the Arctic is likely (>66 

percent likelihood) especially to be affected by climate change because of the impacts of 

high rates of projected warming on natural systems. 

The most affected OCS program areas include the Chukchi and Beaufort Seas. 

Permafrost thawing

The temperature at the top of the permafrost layer has increased by up to 3o C since the 

1980s in the Arctic (IPCC). In the Alaskan Arctic specifically, the permafrost base has 

been thawing at a rate of up to 0.04 meters per year. Thawing of coastal soils is expected 

to result in more rapid rates of shore erosion. This effect is expected to be compounded 

by reduced duration and extent of shoreline protection provided by landfast ice and more 

exposure to ocean storms. IPCC identifies coasts exposed to the Arctic Ocean, such as 

along the Chukchi and Beaufort Seas, as the most sensitive regions for permafrost 

thermal degradation effects, largely because of erosion issues.

The most affected OCS program areas include the Chukchi and Beaufort Seas.

Sea-Ice Biome

The presence of sea ice and landfast ice in the marine environment of the Arctic and near 

Arctic creates a productive marine-ice biome essential for the flourishing and survival of 

marine animals and the traditional subsistence lifestyle. These environments provide 

hunting, resting, and birthing platforms along the ice-water interface; generate local 

upwelling responsible for high productivity in polynyas; and release large quantities of 

algae growing beneath the ice surface into the food chain at ice melt. IPCC considers it 

likely (>66 percent likelihood) that the Arctic sea-ice biome will be especially affected by 

climate change because of sensitivity to warming.
168

The most affected OCS program areas include the Chukchi and Beaudort Seas. 

Coral bleaching 

Warmer water temperatures cause coral to lose their symbiotic algae, a process called 

bleaching. Intensities and frequencies of bleaching events have increased substantially 

over the past 30 years, leading to the death or severe damage of about one third of the 

world’s shallow water corals (Karl et al). IPCC recognizes warm water corals as a 

resource that is likely (>66 percent likelihood) to be particularly affected by climate 

warming.

The most affected OCS program areas include the Western, Central, and Eastern GOM.

Increases in Major Storm Frequency and Intensity

While stronger storms associated with global warming are likely to affect most coastal 

habitats, this effect is expected to be most evident along the southeast and GOM coasts 

(Karl et al.). Observational evidence for an increase of tropical cyclone activity in the 

Northern Hemisphere Atlantic Ocean since about 1970 also suggests a substantial upward 

trend toward longer lasting and more intense storms (IPCC). IPPC considers it likely 

(>66 percent likelihood) that increased tropical cyclone activity will occur, resulting in 

erosion, flooding, and landscape disruptions that will affect the relative environmental 

sensitivity of coastal and nearshore environmental resources.

The most affected OCS program areas include the Western, Central, and Eastern GOM.

Ocean Dynamics

Warming of the atmosphere and oceans can change the dynamic properties of ocean 

circulation. At this time existing information on climate-change effects on the dynamic 

properties of the ocean does not support a reliable prediction of these effects on the 

relative environmental sensitivity of the different OCS program areas. 

4.2.2. Sea Level

Recent global sea-level rise has been caused by warming-induced thermal expansion of 

the oceans, and accelerated melting of glaciers and ice sheets. Current predictions for 

future sea levels project a rise in sea level from 8 to 24 inches by 2100 (IPCC). The 

amount of relative sea-level rise along different parts of the U.S. coasts depends not only 

on thermal expansion and ice-sheet melting, but also on the changes in elevation of the 

land that occur as a result of subsidence or geologic uplift (Karl et al.). In the past 50 

years, sea level has risen 8 inches or more along some coastal areas of the United States 

and fallen in other locations. 

A recent report (CCSP (2009)) identifies areas along the Atlantic and GOM coasts as 

undergoing relatively rapid inundation and landscape changes because of the 
169

prevalence of low lying coastal lands. The report identified submergence hotspots 

where, because of local subsidence, the rate of rise of sea level relative to the land is 

expected to be higher than in other parts of the area. Sea-level rise hotspots include 

coastal Louisiana adjacent to the Central GOMpProgram area. Because these 

submergence hot spots occur as a result of local geologic factors, it is possible in these 

cases to assign climate change-elevated environmental sensitivity to specific OCS 

program areas.

Rapid submergence of these coastal lands would destabilize ecological and 

socioeconomic uses of the coastal zone through accelerated coastal erosion and the 

movement of marine environments landward over terrestrial landscapes. Coastal 

environmental resources affected this way would be stressed and presumably made 

more sensitive to the impacts from OCS oil and natural gas activities.

The most affected OCS program areas include the Central and Eastern GOM.

4.2.3. Ocean Acidification

Ocean acidification refers to the decrease in the pH of the oceans caused by the uptake of 

CO2 from the atmosphere. Atmospheric CO2 reacts with seawater to form carbonic acid, 

leading to increased acidity in the oceans. The future pH of the ocean is predicted to 

decrease by approximately 0.3 to 0.4 units by the year 2100 (Orr et al. (2005)). Higher 

latitudes will experience the greatest changes and impacts due to the increased solubility 

of CO2 due to generally lower temperature (Karl et al.).

Ocean acidification affects the process of calcification by which living organisms create 

shells and skeletons, with substantial negative consequences for coral reefs, mollusks, 

and some plankton species important to marine and coastal food chains (Karl et al.). As a 

result, marine life that uses calcium carbonate to form protective shells or skeletal 

structures is unable to form these structures or the existing structures dissolve. Current 

evidence indicates that the calcification rates of warm corals will be reduced by 20 to 60 

percent at double pre-industrial atmospheric CO2 concentrations (Kleypas et al. (2006)). 

Potentially affected marine organisms include warm and cold water corals, mollusks and 

calcareous phytoplankton.

IPCC concludes that progressive ocean acidification is expected to have negative impacts 

on marine shell-forming organisms and their dependent species. These effects would be 

relatively higher in cold water areas where sea water can absorb more CO2. 

This assessment, however, does not attribute an effect of acidification to relative 

environmental sensitivity based on the absence of observed effects of acidification on 

ecological resources (IPCC), and uncertainties as to when effects from acidification 

would occur in different ocean areas. 
170

4.3 Effects of Climate Change on Relative Environmental Sensitivity and Marine 

Productivity of OCS Program Areas

Table 30 shows offshore and adjoining coastal areas where factors resulting from climate 

change could increase relative environmental sensitivity to OCS development. For 

example, increased sea-level rise would inundate coastal marshes causing land loss, but 

also expose remaining marshes to greater impacts from oil spills by removing the 

protection of barrier islands. The relative effects of climate change are identified for 

groups of adjacent OCS program areas with similar climatic and ecological 

characteristics compared to other areas. Table 30 lists OCS program areas with effects 

on relative sensitivity from climate change based on the previous section. A high relative 

magnitude of effects from climate change was assigned to OCS program areas in which 

at least three climate-change effects were expected to be greater in relation to other 

program areas. A moderate relative magnitude was given to OCS program areas with 

one to two projected effects. A designation of low relative magnitude does not mean that 

climate-change effects will not occur, but that the magnitude of the effects is not 

expected to be greater in relation to the effects in other OCS program areas. 

Table 30: Relative Effects of Climate Change on Environmental Sensitivity 

of the OCS Program Areas1

Geographic Region/

OCS Program Area Climate Change Effects Relative Magnitude

Arctic

Chukchi Sea Sea-Ice biome; species composition; 

permafrost thawing

High

Beaufort Sea Sea-Ice biome; species composition; 

permafrost thawing

High

North Pacific

Cook Inlet Low

Gulf of Mexico

Central GOM Coral bleaching; increased storms; 

submergence 

High

Eastern GOM Coral bleaching; increased storms; 

submergence 

High

Western GOM Coral bleaching; increased storms Moderate 1 Source: Karl et al., 2009.

Climate Change Sensitivity Coefficients

Table 17 above, presents the OCS program areas grouped into three categories ranging 

from most to less sensitive to impact from OCS oil and natural gas activities and 

considers increased sensitivity due to climate change and ocean acidification. This 

grouping uses a coefficient of 2.0 for high relative magnitude of effects, such as in the 

Alaskan Arctic, to apply to the overall environmental sensitivity. This coefficient is 

based on the temperature increase that has occurred in the Arctic, double that of other 

areas. A linear relationship between temperature increase and environmental sensitivity 
171

in the Arctic is reasonable, because ocean and atmosphere warming there has resulted 

directly in increased sensitivity to the sea-ice biome and permafrost degradation. A 

coefficient of 1.5 is used for OCS program areas that are projected to experience 

moderate relative effects from global warming, a value half way between the value of 1.0 

used for no relative effect of global warming and 2.0 for high relative effect.

5. Conclusion

The above environmental sensitivity analysis considers sensitivity of the biological 

marine environment to multiple impact producing factors, such as oil spills, sound and 

physical disturbance, and increased sensitivity due to climate change and ocean 

acidification. Because relatively small differences suggest a level of precision that is not 

possible for this analysis, Table 17 above, presents the OCS program areas grouped into 

three categories of relative sensitivity ranging from “most” to “less” sensitive to impact 

from OCS oil and natural gas activities. Categorization of an OCS program area as “less” 

sensitive does not mean that environmental resources of that OCS program area are not 

sensitive, but as a collection are found to be relatively less sensitive than other OCS 

program areas to the types of impacts anticipated from OCS oil and natural gas activities. 

To determine this grouping, the scores for each of the four ecological components were 

first normalized to a scale of 0 to 1, and then added together. A coefficient (see section 

4.3) was then applied to the sum of the normalized scores for OCS program areas based 

on the relative level of climate-change effects projected. The sums of the normalized 

scores were ranked from 1 to 6 with and without applying the coefficient for climate 

change. The OCS program areas defined as “more” sensitive had scores equal to or 

greater than the average OCS program area score. The OCS program areas defined as 

“less” sensitive had scores less than the average OCS program area score. 

After incorporation of climate change and ocean acidification, there was no change in the 

relative environmental sensitivity rankings for the OCS program areas that ranked “most” 

sensitive. These OCS program areas also were one or more standard deviations greater 

than the mean OCS program area score. The OCS program areas defined as “more” 

sensitive are less than one standard deviation greater than the mean OCS program area 

score.

Similarly after incorporation of climate change and ocean acidification, there was no 

change in the relative environmental sensitivity ranking for the OCS program areas that 

ranked “less” sensitive. Several OCS program areas, including the Arctic OCS program 

areas, i.e., Chukchi and Beaufort Seas, had a significant increase in their overall 

sensitivity rankings when increased sensitivity due to climate change was considered. 

In California I, the U.S. Court of Appeals for the District of Columbia Circuit held the 

relative environmental sensitivity analysis “must at least attempt to identify those areas 

whose environment and marine productivity are most and least sensitive to OCS 

activity.” In an effort to meet the Court’s requirement, yet avoid the appearance of 

unrealistic preciseness associated with a top to bottom ranking, this analysis, as 
172

summarized in Table 17 above, identifies the OCS program areas “most” relatively 

sensitive to impact from OCS oil and natural gas activities as the Eastern and Central 

GOM. 

• References 

• Arctic Climate Impact Assessment (ACIA). 2005. Arctic Climate Impact 

Assessment: ACIA Scientific Report. Cambridge University Press, Cambridge, 

UK/New York, NY, USA, 1042 pp.

• Angliss, R.P., and B.M. Allen. 2009. Alaska marine mammal stock assessments, 

2008. U.S. Department of Commerce, NOAA Tech. Memo. NMFS AFSC-193, 

258 p.

• Bailey, R.G. 1998. Ecoregions: The Ecosystem Geography of the Oceans and 

Continents. New York: Springer.

• Bakun, A. 1990. Global Climate Change and Intensification of Coastal Ocean 

Upwelling. Science 247: 198-201.

• Barth, J.A., B.A. Menge, J. Lubchenco, F. Chan, J.M. Bane, A.R. Kirincich, M.A. 

McManus, K.J. Nielsen, S.D. Pierce, and L. Washburn. 2007. Delayed upwelling 

alters nearshore coastal ecosystems in the northern California Current. Proc. Natl. 

Ac. Sci., 104(10). 3719-3724.

• Boland G., C. Current, M. Gravois, M. Metcalf, and E. Peuler. 2004. Fate and 

Effects of a Spill of Synthetic-Based Drilling Fluid at Mississippi Canyon Block 

778. OCS Report MMS 2004-039. 18 p.

• California Department of Fish and Game. 2008. Table 15 - Poundage and Value 

of Landings of Commercial Fish Into California By Area – 2007. Available at: 

http://www.dfg.ca.gov/marine/landings07/table15.pdf.

• Carretta, J.V., K.A. Forney, M.S. Lowry, J. Barlow, J. Baker, D. Johnston, B. 

Hanson, M.M. Muto, D. Lynch, and L. Carswell. 2009. U.S. Pacific marine 

mammal stock assessments, 2008. U.S. Department of Commerce, NOAA Tech. 

Memo. SWFSC-434, 316 p.

• Continental Shelf and Associates (CSA). 1990. Comparison of Marine 

Productivity Among Outer Continental Shelf Program areas. U.S. Department of 

Interior, Minerals Management Service. Contract Number 14-35-0001-

30487. Herndon, Virginia 20170. 

• Continental Shelf and Associates (CSA). 1991. Comparison of Marine 

Productivity Among Outer Continental Shelf Program areas: Supplement – An 

Evaluation of Benthic Habitat Primary Productivity. U.S. Department of Interior, 

Minerals Management Service. Contract Number 14-35-0001-30487. Herndon, 

Virginia 20170. 

• Feely, R.A., C.L. Sabine, and V.J. Fabry. 2006. Carbon Dioxide and Our Ocean 

Legacy. Available at: 

http://www.pmel.noaa.gov/pubs/PDF/feel2899/feel2899.pdf.
173

• GeoHab. 2008. GeoHab Conference 2008. Marine Geological and Biological 

Habitat Mapping. Sitka, AK. Available at http://geohab.org/sitka.html.

• Hodge, R. and B.L. Wing. 2000. Occurrences of Marine Turtles in Alaska Waters: 

1960-1998. Herpetological Review. 3(13): 148-151.

• Intergovernmental Panel on Climate Change (IPCC). 2007. Climate Change 2007: 

Impacts, Adaptation and Vulnerability. Contribution of Working Group II to the 

Fourth Assessment Report of the Intergovernmental Panel on Climate Change, 

M.L. Parry, O.F. Canziani, J.P. Palutikof, P.J. van der Linden and C.E. Hanson, 

editors. Cambridge University Press, Cambridge, UK, 976pp. Available at: 

http://www.ipcc-wg2.org/index.html.

• T.R. Karl, T.R, J. M. Melillo, and T.C. Peterson, editors. 2009. Global Climate 

Change Impacts in the United States. Cambridge University Press, New York, 

NY. Available at: http://downloads.globalchange.gov/usimpacts/pdfs/climateimpacts-report.pdf.

• Kleypas, J.A., R.A. Feely, V.J. Fabry, C. Langdon, C.L. Sabine, and L.L. 

Robbins. 2006. Impacts of Ocean Acidification on Coral Reefs and Other Marine 

Calcifiers: A Guide for Future Research, report of a workshop held 18–20 April 

2005, St. Petersburg, FL, sponsored by NSF, NOAA, and the U.S. Geological 

Survey, 88 pp.

• Kushlan, J.A., M.J. Steinkamp, K.C. Parsons, J. Capp, M. Acosta Cruz, M. 

Coulter, I. Davidson, L. Dickson, N. Edelson, R. Elliot, R.M. Erwin, S. Hatch, S. 

Kress, R. Milko, S. Miller, K. Mills, R. Paul, R. Phillips, J.E. Saliva, B. Sydeman, 

J. Trapp, J. Wheeler, and K. Wohl. 2002. Waterbird Conservation for the 

Americas: The North American Waterbird Conservation Plan, Version 1. 

Waterbird Conservation for the Americas. Washington, DC, U.S.A. Available at 

http://www.waterbirdconservation.org/nawcp.html

• Lumsden S., T. Hourigan, A. Bruckner, G. Dorr (eds). 2007. State of Deep Coral 

Ecosystems of the United States. NOAA Technical Memorandum, CRCP-3.

• McGee, L., D. Boelke, D. Stevenson, D. Reid, R. Protecting. 2006. Sensitive 

Deep-Sea Canyon Habitats through Fisheries Management: A Case Study in the 

Northeastern United States. Available at 

http://www.nefmc.org/habitat/managing_fisheries_poster.pdf.

• Orr, J.C. et al. 2005. Anthropogenic ocean acidification over the twenty-first 

century and its impact on calcifying organisms. Nature, vol. 437, pp. 681-686.

• Peterson, C.H., S Rice, J Short, D Esler, J Bodkin, B Ballachey, and D Irons. 

Long-Term Ecosystem Response to the Exxon Valdez Oil Spill. Science 19 

December 2003: Vol. 302. no. 5653, pp. 2082–2086. DOI: 

10.1126/science.1084282. 

• Plotkin, P.T. (Editor). 1995. National Marine Fisheries Service and U. S. Fish and 

Wildlife Service Status Reviews for Sea Turtles Listed under the Endangered 

Species Act of 1973. National Marine Fisheries Service, Silver Spring, Maryland.
174

• Snyder, M.A., L.C. Sloan, N.S. Diffenbaugh, and J.L. Bell. 2003. Future climate 

change and upwelling in the California Current. Geophysical Research Letters. 

Vol. 30, No. 15, 1823, 10.1029/2003GL017647.

• Southeast Area Monitoring and Assessment Program (SEAMAP). 2001. 

Distribution of Bottom Habitats on the Continental Shelf from North Carolina 

through the Florida Keys. Atlantic States Marine Fisheries Commission, 

Washington, D.C.

• Spalding, M.D., H. Fox, G. Allen, N. Davidson, Z. Ferdana, M. Finlayson, B. 

Halpern, M. Jorge, A. Lomabana, K. Lourie, K. Martin, E. McManus, J. Molnar, 

C. Recchia, and J. Robertson. Marine Ecoregions of the World: A 

Bioregionalization of Coastal and Shelf Areas. BioScience, V57 No. 7.

• Thomas C.D., A. Cameron, R.E. Green, M. Bakkenes, L.J. Beaumont, Y.C. 

Collingham, B.F.N. Erasmus, M.F. de Siqueira, A. Grainger, L. Hannah, L. 

Hughes, B. Huntley, A.S. van Jaarsveld, G.F. Midgley, L. Miles, M.A. OrtegaHuerta, T. Peterson, O.L. Phillips, and S.E. Williams. 2004. Extinction Risk from 

Climate Change. Nature, 427, 145-148.

• U.S. Climate Change Science Program (CCSP). 2009. Coastal Sensitivity to SeaLevel Rise: A Focus on the Mid-Atlantic Region. A report by the U.S. Climate 

Change Science Program and the Subcommittee on Global Change Research. 

[James G. Titus (Coordinating Lead Author), K. Eric Anderson, Donald R. 

Cahoon, Dean B. Gesch, Stephen K. Gill, Benjamin T. Gutierrez, E. Robert 

Thieler, and S. Jeffress Williams (Lead Authors)]. U.S. Environmental Protection 

Agency, Washington D.C., USA, 320 pp.

• U.S. Dept. of Commerce. National Marine Fisheries Service (NMFS). 2009. 

Annual Report to Congress on the Status of U.S. Fisheries-2008. Silver Spring, 

MD. Available at http://www.nmfs.noaa.gov/sfa/statusoffisheries/SOSmain.htm. 

• U.S. Dept. of Commerce. National Oceanographic and Atmospheric 

Administration (NOAA). 2009. National Marine Sanctuaries. Internet website: 

http://sanctuaries.noaa.gov/. Accessed on July 24, 2009.

• U.S. Dept. of Commerce. NOAA Fisheries Service. 2009. Climate Change and 

Ocean Productivity. Northwest Fisheries Science Center. Internet 

websitehttp://www.nwfsc.noaa.gov/research/divisions/fed/climatechange.cfm. 

Accessed on June 29, 2009.

• U.S. Dept. of Commerce. NOAA Fisheries. Office of Protected Resources. 2009a. 

Critical Habitat. Internet website: 

http://www.nmfs.noaa.gov/pr/species/criticalhabitat.htm. Accessed on July 24, 

2009.

• U.S. Dept. of Commerce. NOAA Fisheries. Office of Protected Resources. 2009b. 

Marine and Anadromous Fish. Internet website: 

http://www.nmfs.noaa.gov/pr/species/fish/. Accessed on June 8, 2009.
175

• U.S. Dept. of Commerce. NOAA Fisheries. Office of Protected Resources. 2009c. 

Marine Invertebrate and Plant Species Under the Endangered Species Act (ESA). 

Internet website: http://www.nmfs.noaa.gov/pr/species/esa/invertebrates.htm. 

Accessed on June 8, 2009.

• U.S. Dept. of Commerce. NOAA Fisheries. Office of Science and Technology. 

2009. Annual Commercial Landing Statistics. Internet website: 

http://www.st.nmfs.noaa.gov/st1/commercial/landings/annual_landings.html. 

Accessed June 8, 2009.

• U.S. Dept. of the Interior. Minerals Management Service (MMS). 2007. Outer 

Continental Shelf Oil and Gas Leasing Program: 2007-2012—Final 

Environmental Impact Statement. Volumes I-II. U.S. Dept. of the Interior, 

Minerals Management Service, Washington, DC. OCS EIS/EA MMS 2007-003.

• U.S. Department of Navy. 2005. Marine Resources Assessment for the Northeast 

Operating Area. Final Report. Contract Number N62470-02-D-9997.

• U.S. Department of Navy. 2006. Marine Resources Assessment for the Gulf of 

Alaska Operating Area. Final Report. Contract Number N62470-02-D-9997.

• U.S. Department of Navy. 2007a. Marine Resources Assessment for the Gulf of 

Mexico. Final Report. Contract Number N62470-02-D-9997.

• U.S. Department of Navy. 2007b. Marine Resources Assessment for Southeastern 

Florida and the Autec-Andros Area. Final Report. Contract Number N62470-02-

D-9997.

• U.S. Department of Navy. 2008a. Marine Resources Assessment Update for the 

Charleston/Jacksonville Area. Final Report. Contract Number N62470-02-D9997.

• U.S. Department of Navy. 2008b. Marine Resources Assessment for the Southern 

California and Point Mugu Operating Areas. Final Report. Contract Number 

N62470-02-D-9997.

• U.S. Department of Navy. 2008c. Marine Resources Assessment Update for the 

Virginia Capes Operating Area. Final Report. Contract Number N62470-02-D9997.

• U.S. Fish and Wildlife Service (USFWS). 2009a. Endangered Species Act, 

Section 7 Biological Opinion for Beaufort and Chukchi Sea Program Area Lease 

Sales and Associated Seismic Surveys and Exploratory Drilling. September 3.

• U.S. Fish and Wildlife Service (USFWS). 2010. FWS Critical Habitat for 

Threatened & Endangered Species. Internet website: 

http://criticalhabitat.fws.gov/. Accessed July 24, 2009.

• U.S. Fish and Wildlife Service (USFWS). 2009c. Draft Alaska Seabird 

Conservation Plan. U.S. Fish and Wildlife Service, Alaska Region, Migratory 

Bird Management, Non-game Program. 135 pages.
176

• U.S. Fish and Wildlife Service (USFWS). 2005. Seabird Conservation Plan: 

Pacific Region. Regional Seabird Conservation Plan, Pacific Region. U.S. Fish 

and Wildlife Service, Migratory Birds and Habitat Programs, Pacific Region, 

Portland, Oregon. 262 pages. Available at: 

http://www.fws.gov/pacific/migratorybirds/Seabird_Conservation_Plan_Webpage

s/Complete_USFWS_Seabird_Conservation_Plan.pdf.

• Vié, J.-C., C. Hilton-Taylor, and S.N. Stuart, editors. 2009. Wildlife in a 

Changing World – An Analysis of the 2008 IUCN Red List of Threatened 

Species. Gland, Switzerland: IUCN. 180 pp.

• Waring G.T., E. Josephson, C.P. Fairfield-Walsh, and K. Maze-Foley K, editors. 

2009. U.S. Atlantic and Gulf of Mexico Marine Mammal Stock Assessments, 

2008. U.S. Department of Commerce, NOAA Tech Memo NMFS NE-210; 440 p.

• Woodby, D., D. Carlile, S. Siddeek, F. Funk, J.H. Clark, and L. Hulbert. 2005. 

Commercial Fisheries of Alaska. Alaska Department of Fish and Game, Juneau, 

AK. Special Publication No. 05-09. Available at: 

http://www.sf.adfg.state.ak.us/FedAidPDFs/sp05-09.pdf.

3. Industry Interest 

BOEM received comments from 11 energy companies and oil and natural gas trade 

groups and membership organizations in response to the November 2011 PP. Every 

commenter supported leasing in the PP areas. However, the overarching concern was the 

lack of access to other areas, particularly more of the Eastern GOM and the Atlantic. 

Five exploration and development companies submitted comments in response to the 

PP.83 There was little or no differentiation between the areas so all six areas are 

considered to have industry interest from five companies.

4. Equitable Sharing of Developmental Benefits and Environmental Risks 

Introduction

Section 18(a)(2)(B) of the Act requires that the Secretary base the timing and location of 

OCS exploration, production, and development on a consideration of, among other 

factors, “an equitable sharing of developmental benefits and environmental risks among 

the various regions.” Because developmental benefits and environmental risks generally 

accrue outside the regional OCS submerged lands, analysis of these factors usually goes 

beyond the strict requirements of the Act and considers the sharing of benefits and risks 

to the onshore U.S. population, particularly in the coastal areas near producing regions of 

the OCS.

Section 18 requires that the leasing program consider an equitable sharing of 

developmental benefits and environmental risks. The courts, however, have not defined a 

 83 Two subsidiaries of the same parent company submitted similar comments separately.
177

specific standard of equitable sharing that the Secretary is to achieve. As the Court 

recognized in California I and California II, the degree to which a proposed five year 

schedule of lease sales can achieve an equitable sharing of benefits and risks must be 

considered in light of a number of other factors, many of which are not under the control 

of DOI. The equitable sharing analysis is based on considerations that, while somewhat 

general, allow a fairly simple basis for judging the implications of programmatic 

decisions on the equitable sharing of developmental benefits and environmental risks. 

The Secretary considers equitable sharing of developmental benefit and environmental 

risks among the regions, as described in this analysis, in the process of deciding whether 

to include any or all of the available program areas in the PFP. 

Methodology

The equitable sharing analysis uses a regional economic-impact approach rather than the 

national benefit-cost approach used in estimating the net benefits of the program 

proposal. Economic impact analysis and benefit-cost analysis offer two means of 

estimating benefits and costs, both of which provide valuable information for the Five 

Year Program decision. Both are reasonable approaches to estimating social value and 

social costs, but the numbers they generate are not the same, as they represent different 

aspects of economic activity. The effects measured in a benefit-cost analysis reflect 

direct first-order real resource market outcomes, such as increased production and the 

accompanying increase in consumer surplus, as well as the costs imposed by the program 

decision. Some factors that often are considered a benefit, such as employment, are 

treated in a benefit-costs analysis as costs paid by society to conduct the activities that 

result in economic value. In contrast, while an economic impact analysis could include 

these output measures as well, it tends to focus upon broad macroeconomic measures, 

such as income, employment, wages, and revenue transfers, as they relate to specific 

industries and geographical locations. As the Secretary must make programmatic 

decisions for the benefit of the Nation as a whole, the benefit-cost approach is more 

appropriate for the net benefits or social value analysis, described earlier in this 

document, which present relative benefits and costs from the national perspective. 

However, for the equitable sharing analysis, it is the relative benefits enjoyed and 

distributed risks borne among geographic regions that are important. In addition, 

residents of local areas tend to view employment as a benefit, often resulting in the flow 

of money into their communities from elsewhere, rather than a cost of producing 

economic value. Therefore, the regional economic impact approach described below is 

used.

Developmental Benefits and Environmental Risks

The nature of developmental benefits and environmental risks associated with the OCS 

oil and natural gas program has been well documented in previous five year program 

analyses. Those analyses concluded that, given the actual geographic distribution of oil 

and natural gas resources among various OCS planning areas, the existence of funds to 

mitigate risks, and the distribution of corporate ownership throughout the country, the 
178

Five Year Program necessarily results in both a concentration of developmental benefits 

and environmental risks in the geographic areas adjacent to OCS oil and natural gas 

activity areas and also a wide distribution of other economic benefits and costs 

throughout the Nation. This analysis describes both phenomena.

Among the benefits accruing primarily to producing regions and nearby onshore areas are 

expenditures on the factors of production which provide direct, indirect, and induced 

employment and regional economic impact. Many of the industries conducting or 

supporting OCS oil and natural gas activities provide employment at higher-than-average 

pay. Employment and expenditures move through the economy with a share of revenues 

accruing to Federal, state, and local governments. Producing regions and nearby onshore 

areas, as well as other coastal areas that are not near OCS oil and natural gas activities,

also benefit from the reduced risk of accidents involving tankers carrying imported oil 

that would be necessary to replace forgone OCS production, should there be no new 

program.

The immediate environmental risks of OCS oil and natural gas activities also are borne 

primarily by producing regions and nearby onshore areas, whether these risks are from 

reasonably foreseeable effects or from a low probability/high consequence accident. 

Environmental threats include risks to the natural capital found in the OCS’s renewable 

and non-renewable resources. Environmental damages could include impacts to marine 

productivity, quality of aesthetic resources, human-ecological connectivity, and air and 

water quality. The Final EIS for the Five Year Program describes in great detail the 

potential risks and impacts of oil and natural gas activity on the marine, coastal, and 

human environment. Further, BOEM has included an initial effort to extrapolate possible 

costs from unlikely, but plausible, catastrophic spill events in the Economic Analysis 

Methodology paper and has published the Inventory paper, which provides a separate 

inventory of activities and resources in and near each program area that could be affected 

by routine operations and/or a catastrophic spill event. The Inventory paper can be used 

to help weigh the potential risks faced in and near producing regions. 

Economic Impact, Employment, and Social Benefits near OCS Activities

As in previous Five Year Programs, this analysis examines the distribution of 

developmental benefits among coastal regions84 near program areas proposed for OCS 

lease sales as well as to the rest of the United States. The regions examined in this 

analysis are: 

• Alaska;

• Other Pacific states;

 84 This analysis uses regional groupings that are very similar to the PADDs, which provide regional 

groupings of states that track closely with the four OCS “regions,” although all inland states are grouped 

together as the Rest of the United States. While Florida is a GOM coast state, it is adjacent to both the 

GOM and Atlantic OCS regions and is the most distant of GOM states from OCS activities and the PFP 

areas. Alaska is considered separately as it is adjacent to its own OCS region and is quite different from the 

other Pacific states in terms of energy production, population, and other characteristics. 
179

• Alabama, Mississippi, Louisiana, and Texas; 

• Florida; and

• Rest of the United States 

Positive economic and fiscal effects from routine activities as a result of the program 

include employment, labor income, corporate and employee income taxes, and property 

taxes related to both offshore and onshore infrastructure. BOEM used its recently 

updated regional economic impact models, collectively called MAG-PLAN, to estimate 

the relative economic effects on each of these regions that might result under the Five 

Year Final EIS alternatives. MAG-PLAN estimates reflect the fact that OCS oil and 

natural gas activities have sizable economic effects outside the nearby coastal areas. 

Companies do business with suppliers throughout the country and the world, and offshore 

workers usually work shifts of 1 to 4 weeks, alternating with the same periods off duty, 

allowing them to commute long distances. MAG-PLAN also estimates spending in the 

rest of the world, but those estimates are not used in this analysis.

The analysis has determined that the PFP would have its greatest economic effect in the 

states adjacent to, and/or near the Central and Western GOM. The states of Alabama, 

Mississippi, Louisiana and Texas would receive most of the employment and personal 

income directly generated by activities anticipated to result from the PFP, as well as a 

huge share of the employment and income generated by vendors, suppliers and employee 

households. In addition, as required by GOMESA, these four states, adjacent to 

producing areas, will receive a 37.5-percent share of lease revenues from selected areas 

in the Eastern and Central GOM planning areas through FY 2016, and from leases issued 

after 2016 throughout the GOM program areas thereafter, subject to a $500 million per 

year cap ($375 million to above states and $125 million to the Land and Water 

Conservation Fund (LWCF)) through 2055 in the additional areas (see “OCS Impact 

Assistance and Revenue Sharing Benefits,” below). Also, as required by section 8(g) of 

the Act, a 27-percent share of all Federal OCS revenues, i.e., bonus bids, rentals, and 

royalties, from leases within three miles of state waters will be provided to the adjacent 

state.

According to MAG-PLAN Alaska, the state would receive as much as 5-to-10 percent of 

the expected employment and labor income benefits generated by activities resulting 

from the PFP. The per capita share of these developmental benefits is greater for Alaska 

with its smaller population than for the states along the GOM coast. To the extent that 

Alaska continues to develop the means to supply the goods and services needed for 

offshore oil and natural gas activities, the state would be expected to increase its share of 

the developmental benefits flowing from the new Five Year Program and subsequent 

programs resulting in Alaska OCS lease sales. While Alaska would benefit from its share 

of 8(g) revenues and from tax revenues from companies developing both onshore and 

offshore infrastructure, it also stands to gain indirect revenues. Another benefit would be 

providing sufficient oil production to maintain the TAPS. There is concern that without 

production from new OCS leases that production from existing state projects will 

decrease to the level that it would no longer be sufficient to maintain the TAPS. The vast 

majority of the state’s revenue comes from the oil and natural gas industry and the loss of 
180

this key pipeline would cause devastating economic effects. According to a report by the 

University of Alaska’s Institute for Social and Economic Research, the loss of TAPS 

could cut Alaska’s economy and workforce to half its current size. New oil production 

from the Arctic OCS could extend the life of the pipeline system for decades, facilitating 

revenues from both new OCS production and continuing projects on state lands. 

Florida is estimated to receive much less than 5 percent of the expected employment and 

labor income benefits generated by activities resulting from the PFP. Because no 

nearshore areas directly off the coast of Florida are proposed for leasing, it is not 

expected that much economic activity would occur in Florida. However, there are 

opportunities for Florida industries to benefit from supplying goods and services to the 

OCS industry operating in the Eastern GOM and the eastern portion of the Central GOM. 

Many such opportunities would require investments in related infrastructure. 

Environmental and Social Risks

The environmental and social costs85 expected from leases issued in this program 

primarily impact the adjacent coastal regions for the GOM, the Arctic, and Cook Inlet. 

Just as the producing GOM states receive the majority of the benefits, not coincidentally;

these states are expected to face the most environmental risks as well. In addition to 

bearing most of the environmental costs, the adjacent states bear the brunt of downturns 

in the oil and natural gas industry which can have significant social consequences, as well 

as the costs of developing or improving infrastructure to meet demands for more housing, 

road construction and repair, etc., as the result of increased support activities and 

population. The same increases in activities and population provide increased tax and 

other revenues, but the revenues tend to lag behind costs when there are major increases 

in activity levels. The State of Louisiana commented in several letters to BOEM since 

2006 that the state has supported a great deal of OCS oil and natural gas activity that 

results in disproportionate impacts. These environmental impacts have resulted in coastal 

wetland losses. BOEM has addressed these environmental impacts in the Five Year Final 

EIS. BOEM has also responded to Louisiana’s request to study alternatives to OCS 

areawide leasing that might mitigate the boom and bust cycles of energy development. 

One step taken in part to address these concerns has been to raise the minimum bid to 

$100 per acre for deepwater blocks in the GOM as a way of increasing bids and slowing 

somewhat the pace of leasing. A summary of the detailed analysis of alternative 

approaches to areawide leasing that may serve to further the many goals of the Act can be 

found in this document in the part III discussion on Fair Market Value.

Some effects are mitigated by monetary compensation and other funding. For example, 

the Fishermen’s Contingency Fund compensates U.S. commercial fishermen and other 

eligible citizens and entities for property and economic loss caused by obstructions 

related to oil and natural gas development activities on the OCS. A more visible and 

recent example occurred in the wake of the Deepwater Horizon event, when BP agreed to 

provide $20 billion to a fund that can be used for natural resource damages, state and 

 85 For a discussion of the Offshore Environmental and Social Cost Model, see part IV.C, Comparative 

Analysis of OCS Planning Areas.
181

local response costs, and individual and business claims compensation. In addition, 

fishermen and others were hired to contain oil offshore and clean beaches and wetlands. 

Many of these workers stayed in local hotels and made purchases at other establishments 

along the GOM coast. These financial costs were borne by geographically dispersed 

sources from around the country and the world, in this case. However, as in other such 

large-scale emergency situations, those incurring Deepwater Horizon-related losses were 

not always those receiving the “benefits” of this increased activity and infusion of 

spending. Therefore, it is impossible to assure that the massive number of compensation 

payments—even if adequate in the aggregate—reach the right people and institutions in 

the right amounts, nor does the spread of financial risk negate the reality of localized 

risks, which are described in detail in the Five Year Final EIS.

Although safeguards for both OCS activities and tankers have improved considerably in 

recent years,86 the results of BOEM’s analysis of the energy substitutes show that without 

the Five Year Program, greater social and environmental costs would be imposed on U.S. 

regions other than the GOM coast and Alaska. For example, the Atlantic Coast and 

inland areas would be at risk from the effects of increased tanker traffic transporting 

crude oil imports and increased domestic onshore oil and natural gas production. 

Therefore, regions without OCS areas in this PFP receive benefits because Alaska and the 

GOM region bear the environmental and social costs and risks from this program.

The Atlantic Coast states other than Florida are not near areas proposed for leasing, nor 

are they near oil and natural gas activities in general. These states would not be expected 

to experience noticeable employment or other labor income as a result of the program, 

nor would they face increased environmental risk from the program. On the other hand, 

to the extent that tanker imports into Atlantic ports are reduced by OCS production in the 

GOM, much of which is sent by pipeline to other parts of the country, the Atlantic Coast 

states would enjoy a reduction in the environmental risk of tanker spills and air 

emissions.

Similarly, the West Coast states would not be expected to experience noticeable 

employment or other labor income as a result of the program. However, given its own oil 

and natural gas infrastructure, Southern California could experience some additional 

employment and income. Changes in environmental risk from the program would 

depend upon the extent to which tankers carrying Alaska OCS oil or imported oil, in the 

absence of a new program, provide offsetting risks of spills and emissions. The risk of 

impacts from a tanker spill would, in turn, depend in part on the volume of oil carried by 

tankers. 

 86 After the Deepwater Horizon event, DOI implemented important new regulations to reduce the risk of

such accidents and the possibility that they would result in major releases of oil. Industry took numerous 

actions as well, implementing most of the recommendations of the Presidential Commission appointed to 

investigate the event and find ways to remedy weaknesses in safeguards. 
182

Effects of Program Options on Equitable Sharing

An analysis of the program options shows similar patterns of sharing of economic 

activities. Excluding the Eastern GOM program area from the program would not have 

an appreciable effect on the equitable sharing of development benefits and environmental 

costs, precisely because the program area is so small and is not expected to result in much 

production. Selecting the No Sale Option for the other program areas would affect this 

sharing in rough proportion to the production anticipated from each excluded program 

area. However, within the regions used for this analysis, the specific option would affect 

the local population, whether in terms of reduced benefits and risks (excluding the 

Western and Central GOM) or in terms of foregone benefits and risks avoided (excluding 

the Chukchi Sea, Beaufort Sea, and Cook Inlet). For example, selecting the No Sale 

Option for the Central GOM would shift some of the benefits to onshore energy 

businesses, onshore worker families, and communities where both workers spend their 

money and pay taxes. It would shift some of the environmental risk to the areas where 

onshore energy activities would increase and to coastal areas along tanker routes. 

However, a reasonably large proportion of the additional onshore oil and natural gas (not 

coal, etc.) activity would presumably be in the affected states, and a large proportion of 

additional imports would likely arrive in GOM ports. Selecting the No Sale Options for 

the Chukchi or Beaufort Seas would shift much greater per capita benefits to other 

geographic areas, not only from coastal communities but also from the rest of Alaska, 

where there would be even greater employment from the proposed sales. Lack of new 

production for TAPS could result in closure and a major loss of revenues for the state and 

its citizens. On the other hand, there also would be a major shift of environmental risk to 

other areas, proportionately more so than would result from a No Sale decision for a 

GOM area. Almost all environmental risk would be shifted to other areas, because 

increased oil imports would not go to Alaska ports, and most of the increased onshore 

energy production would presumably occur elsewhere as well. 

Geographically Dispersed Social Benefits and Risks

An important portion of the employment, labor income, and other economic impact 

benefits are shared with the Rest of the United States, which, according to MAG-PLAN 

estimates, would receive approximately a quarter of the total economic impact. (See 

discussion under Economic Impact, Employment, and Social Benefits near OCS 

Activities, above.) Those whose jobs require them to be physically offshore usually work 

extended shifts of 1 to 4 weeks on duty followed by the same period off duty, allowing 

them to commute from hundreds, even thousands, of miles away. In addition, the 

offshore oil and natural gas industry purchases goods and services from a vast network of 

suppliers throughout the country. 

There are, however, other financial aspects of both benefits and risks that are shared 

somewhat widely. Benefits flowing from OCS leasing and corporate income tax 

revenues are widely distributed among the geographic onshore regions of the United 

States. Many billions of dollars of OCS revenue benefits are disbursed annually through 
183

General Fund appropriations for various national functions, as well as through the 

Historic Preservation Fund and the LWCF.

Financial rewards for profitable OCS oil and natural gas operations in the form of stock 

dividends and increased stock values are also broadly distributed, as owners live 

throughout the country. Any benefits of an improved balance of trade or decreased risk 

of supply disruptions that could result from actions by hostile governments or a variety of 

other causes are shared nationally.

The same rationale that holds for the sharing of profits from OCS oil and natural gas 

activity holds for unprofitable ventures. The financial consequences of unprofitable OCS 

oil and natural gas investments are shared by companies and individuals throughout the 

Nation. Some of the financial consequences of environmental risks, e.g., compensation 

by responsible parties for natural resource damages, may also be shared by companies 

and individuals beyond the producing regions mentioned above. Payments for 

remediation, restoration, or lost profits are costs to the Nation's economy, due to the 

necessary diversion of resources from other, "productive" activities, and transfer 

payments that provide the entities impacted by an event compensation for damage or 

losses. Fines and any other payments that are not approximations of lost value are 

transfer payments (merely a transfer of money from one entity to another) and do not 

affect NEV.

OCS Impact Assistance and Revenue Sharing Benefits

Additional benefits to communities proximate to OCS oil and natural gas activities come 

from programs that allocate OCS oil and natural gas revenues to those states and coastal 

political subdivisions near OCS oil and natural gas exploration and development. 

Currently, programs that provide OCS revenues to the coastal producing states include:

1. Section 8(g) revenue sharing provides coastal producing states with 27 percent 

of revenues from all leases within three miles of a state’s submerged lands 

boundary.

2. GOMESA, which provides the States of Alabama, Mississippi, Louisiana, and 

Texas, a 37.5 percent share and LWCF a 12.5 percent share of lease revenues 

from selected areas in the Eastern and Central GOM planning areas through 

2016. Beginning in 2017, GOMESA shares additional lease revenues from 

the Central and Western GOM, limited to $500 million annually ($375 million 

to above states and $125 million to LWCF). Revenues distributed under the 

provisions of GOMESA are intended to help compensate for potential 

negative impacts of OCS activities and are reserved for uses specified in the 

Act, including coastal restoration and protection.

While impact assistance and other such programs provide a share of Federal revenues to 

states adjacent to or near OCS leases to help to mitigate environmental risk, the Secretary 

cannot expand, extend, or otherwise revise the provisions to further the equitable sharing 
184

of the developmental benefits and environmental risks. However, should Congress be 

concerned that existing benefits and impact assistance or revenue sharing provisions do 

not sufficiently compensate states for environmental risks posed by OCS activities; it 

could pass legislation to do so.

Summary and Conclusion

The general findings and conclusions of previous five year program equitable sharing 

analyses are still valid. Some benefits and risks of OCS leasing are shared widely while 

others are concentrated in regions adjacent to areas of OCS oil and natural gas activity. 

The exclusion of most of the Eastern GOM, as well as all planning areas in the Atlantic87

and Pacific OCS regions from Five Year Programs from 1992 to 2007 precluded adjacent 

states and communities from sharing in direct benefits and risks resulting from those 

programs. Since the distribution of benefits associated with factors of production is 

linked significantly to the location of OCS oil and natural gas support industries, which 

exist primarily along the GOM, Southern California, and Alaska coasts, the Secretary’s 

PFP decision on an OCS leasing schedule for the period 2012-2017 is not expected to 

alter substantially the distribution of benefits and risks achieved under previous Five Year 

Programs. The Southern California planning area, which has been excluded from Five 

Year Programs since 1992, no longer receives new direct benefits and risks. While the 

New England and Mid- and South Atlantic states account for more than 25 percent of the 

Nation’s oil and natural gas consumption and for only a small percentage of its 

production, the Atlantic is the only one of the four OCS regions without any oil and 

natural gas activities. 

Federal leasing revenues that traditionally accrue to adjacent onshore areas, including 

those distributed pursuant to 8(g) and GOMESA, help to compensate the producing 

regions for the costs and environmental risks of OCS oil and natural gas activities. 

Additionally, measures such as the implementation of new lease stipulations and 

operating regulations remain available to reduce the risks borne by the affected areas.

Given the GOMESA moratorium in most of the Eastern GOM and a small portion of the 

Central GOM within 100 miles of Florida, as well as the exclusion the Atlantic and 

Pacific OCS regions from leasing in this PFP, the employment and revenues generated 

and shared by the program, and the additional effort to mitigate risks, are the best attempt 

at achieving an equitable sharing of benefits and risks among all OCS regions.

5. Other Uses of the OCS 

Section 18(a)(2)(C) requires the Secretary to examine the location of areas considered for leasing

with respect to other uses of the resources and space within those areas. Other uses of the OCS 

 87 While there was a small Mid-Atlantic program area in the Five Year Program for 2007-2012, the MidAtlantic sale was cancelled pursuant to the pre-sale process. However, in March 2012, BOEM published a 

Draft EIS for G&G activities in the Mid- and South Atlantic planning areas, covering seismic and other 

offshore surveys, to lay the groundwork for possible Atlantic sales in future programs. The Final G&G EIS 

is scheduled for completion later in 2012 or early 2013.
185

that could affect or be affected by oil and natural gas leasing and ensuing activities are described 

below. 

The following types of uses are addressed:

• Subsistence Hunting and Fishing Activities;

• Commercial Fishing;

• EFH and Habitat Areas of Particular Concern (HAPC) [pursuant to section 

303(a)(7) of the MSFCMA, as amended and implementing regulations];

• Other Areas of Special Concern (onshore and offshore areas designated for 

special uses and protections, such as parks and sanctuaries);

• Tourism and Recreation;

• Military Operating Areas (GOM);

• Liquefied Natural Gas (LNG) (GOM); and

• Non-energy Marine Mineral Activities (GOM)

The information presented below summarizes detailed regional descriptions of the 

environment that are included in the Five Year Program EIS. The discussion of options 

in part III of this document includes pertinent summaries including “other uses” 

comments. Comments that BOEM received are summarized in Appendix A.

Gulf of Mexico Region

Commercial Fishing: GOM fisheries are very important to the economies of adjacent 

coastal states. GOM commercial fisheries include nearly 100 species from 33 families. 

Menhaden is the most important finfish harvested, followed by nine other species of 

significant value. Shrimp is the most important shellfish, along with various oyster, 

lobster, and crab species. Louisiana ranked first among GOM states in total commercial 

fisheries landed, followed by Mississippi, Texas, Florida’s west coast, and Alabama.

EFH and Habitat Areas of Particular Concern: Approximately 33 percent of the 

species managed by the GOM Fisheries Management Council have been selected for 

EFH designation. They include invertebrate and reef fish species, red drum and other 

coastal pelagic species, and highly migratory species such as swordfish, tuna, and shark. 

Within the Central and Western GOM, several individual reefs and banks located 

offshore the Louisiana-Texas border have been designated HAPCs by the Council 

(NMFS 2010a; Table 3.7.4-3; Figure 3.7.2-1). HAPCs in the Eastern GOM that could be 

affected by oil spills in the GOM include the Florida Middle Grounds, Madison-Swanson 

Marine Reserve, Pulley Ridge, and Tortugas North and South Ecological Reserve. The 

HAPC for bluefin tuna is located west of 86°W and seaward of the 100 meter (328 foot) 

isobath, extending from the isobath to the Exclusive Economic Zone, the limit of U.S. 

jurisdiction (Atlantic Bluefin Tuna Status Review Team, 2011). 

Other Areas of Special Concern: Special areas in the GOM include a national marine 

sanctuary, national park units, NWRs, a national estuarine research reserve, and national 

estuary program areas. The Flower Garden Banks National Marine Sanctuary covers a 
186

124-square kilometer area located 177 miles offshore within the Western GOM. National 

park units along the GOM coast that are adjacent to areas considered for leasing include 

Jean Lafitte National Historic Park and Preserve in Louisiana, Padre Island National 

Seashore off Texas, and Gulf Islands National Seashore off Mississippi and Alabama. 

There are 28 NWRs located along the coast from Texas to Alabama. The Weeks Bay 

National Estuarine Research Reserve encompasses a small estuary in the vicinity of 

Mobile Bay adjacent to the Central GOM. National estuary program areas include the 

Galveston Bay and Corpus Christi Bay systems in Texas and the Barataria-Terrebonne 

Estuarine Complex and Lake Pontchartrain Basin in Louisiana.

Tourism and Recreation: The northern GOM coastal zone is one of the major 

recreational regions of the United States, particularly in connection with marine fishing 

and beach-related activities. The shorefronts along the GOM states offer a diversity of 

natural and developed landscapes and seascapes. The coastal beaches, barrier islands, 

estuarine bays and sounds, river deltas, and tidal marshes are extensively and intensively 

used for recreational activity by residents and tourists from throughout the Nation, as well 

as from foreign countries. Publicly owned and administered areas, such as national 

seashores, parks, beaches, and wildlife lands: as well as specially designated preservation 

areas, such as historic and natural sites and landmarks, wilderness areas, wildlife 

sanctuaries, and scenic rivers, attract residents and visitors throughout the year. 

Commercial and private recreational facilities and establishments, such as resorts, 

marinas, amusement parks, and ornamental gardens, also serve as primary interest areas 

and support services for people who seek enjoyment from the recreational resources 

associated with the GOM.

Military: GOM is the most important over-water testing and training area in the United 

States, with areas designated for air-to-surface and air-to-missile testing, surface vessel 

testing, and training for air, surface, mine, and submarine operations. Areas used by the 

military include the Corpus Christi Operating Area off Texas for mine warfare and 

aircraft carrier landing training; New Orleans Operating Area off Louisiana for naval live 

firing maneuvers; and Pensacola Operating Area off Alabama and Florida for aircraft 

carrier landing training, naval vessel shakedown testing, and live firing exercises. DOI 

and DOD coordinate activities and reduce use conflicts according to procedures 

established in a longstanding Memorandum of Agreement.

Liquefied Natural Gas (LNG): Natural gas is liquefied to concentrate a much greater 

volume of product in a given space to facilitate storage and transportation. In the GOM, 

LNG terminals have been planned, approved and built on the OCS. These facilities 

offload LNG from tankers into the existing offshore natural gas pipeline system. 

Currently, more than ten of these facilities are at the planning or permitting stages. The 

Gulf Gateway facility began operation 116 miles off the coast of Louisiana in 2005.

Non-energy Marine Mineral Activities: Several minerals in the northcentral GOM 

have the potential to be developed. Two salt and sulfur operations exist on the OCS 

offshore Louisiana and other deposits are known to occur in the northcentral GOM. 

Sand deposits located in Federal waters in the Ship Shoal area off Louisiana are being 
187

considered for use in restoring barrier islands to protect the state's coastal wetlands. 

Sands in Federal and state waters off Mississippi and Alabama have the potential to be 

developed for glass production and for coastal restoration uses including beach 

replenishment.

Alaska Region

Subsistence: Subsistence activities have value to the culture, lifestyle, society, economy, 

and communities in northern Alaska. Subsistence activities in the Beaufort Sea marine 

and coastal areas focus on the bowhead whale, caribou, freshwater and ocean fish, ducks 

and geese, and bearded seals. Species hunted for subsistence in the Chukchi Sea area 

include bowhead whale, beluga whale, caribou, seal, walrus, polar bear, fish, duck, and 

goose. Bowhead whaling is the single most valued activity in the North Slope 

subsistence economy today. Widely varying subsistence patterns in the vicinity of Cook 

Inlet reflect the area's diverse population. Generally, the inhabitants of small traditional 

villages harvest saltwater and freshwater fish and small sea mammals in the summer and 

fall, moose in the fall, and invertebrates and some sea mammals year round. In the larger 

industrial communities, people generally fish in the summer and hunt in the fall, and 

fewer households partake in subsistence activities. 

Commercial Fishing: Commercial fishing, which occurred only infrequently and on a 

very small scale in the past, does not currently occur in the Arctic program areas. 

Therefore, published fish stock assessments and monitoring data do not exist for those 

areas. Commercial fishing is an important segment of the local economy of the Cook 

Inlet region, focusing mainly on salmon and to a lesser degree on crab, shrimp, and 

halibut.

EFH and Habitat Areas of Particular Concern: An EFH has been designated in all 

offshore Alaska areas that are proposed for leasing. Fishery Management Plans (FMP) in 

the Arctic exist for arctic cod, saffron cod, and snow crab. In the Chukchi Sea and 

Beaufort Sea areas, essential habitat has been established for all five salmon species. The 

Stefansson Sound Boulder Patch in the Beaufort Sea is a designated HAPC. Several 

HAPCs are located in the Cook Inlet. The FMPs in Cook Inlet cover the Gulf of Alaska 

groundfish, scallops, and salmon. 

Other Areas of Special Concern: All of the areas proposed for leasing off Alaska are 

adjacent to coastal portions of national parks or NWRs. The Beaufort Sea program area 

is adjacent to the Arctic NWR (ANWR) and the Chukchi Sea program area is located off 

the Chukchi Sea Unit of the Alaska Maritime NWR. The Cook Inlet program area is near 

Lake Clark National Park and Preserve and the Katmai National Park and Preserve is 

located on the eastern shore of the Shelikof Strait, the southern portion of the program 

area.

Tourism and Recreation: In the Chukchi Sea and Beaufort Sea areas, recreation 

activities take place mainly in the summer and include fishing, boating, hunting, hiking, 

sightseeing, camping, and picnicking. Most nonresident activity is by tour groups that 
188

visit Barrow and Deadhorse where lodging is available. Hikers and river rafters also visit 

ANWR. The Cook Inlet area offers abundant high quality tourist and recreation 

resources that attract numerous state, national, and international visitors. Additional 

information relating to tourism and recreation in Alaska is available in the Five Year 

Final EIS description of areas of special concern.

Military: Although there are military use areas within the Alaska Region, OCS oil and 

natural gas leasing and related activities are not expected to interfere with military

operations.

Non-energy Marine Mineral Activities: There is no current development of offshore 

non-energy minerals in any of the Alaska OCS program areas under consideration for oil 

and natural gas leasing. There are sand and gravel deposits in the Beaufort Sea, but their 

value as a construction material is not known.

D. Laws, Goals, and Policies of Affected States 

BOEM asked the governors of affected states to identify laws, goals, and policies of their 

states as relevant matters for consideration in the PFP. No specific identification was 

provided for any of the program areas included in this program. 

E. Balancing Considerations under Section 18 

Section 18(a)(3) of the Act requires the Secretary to “select the timing and location of 

leasing, to the maximum extent practicable, so as to obtain a proper balance between the 

potential for environmental damage, the potential for the discovery of oil and gas, and the 

potential for adverse impact on the coastal zone.” Striking this balance based on a 

consideration of the principles and factors enumerated in section 18(a) is a matter of 

judgment for which no ready formula exists. Section 18 requires the consideration of a 

broad range of principles and factors rather than imposing an inflexible formula for 

making decisions. Thus, previous Five Year Programs have scheduled as many as 37 

lease sales in 22 planning areas and as few as 16 sales in 6 planning areas. 

Some of the factors that section 18 specifies for consideration can be quantified, such as 

resource potential, and are embodied in the benefit-cost analysis that has been developed. 

Others are not as readily quantifiable and have therefore been described qualitatively. 

For example, environmental considerations such as aesthetics or concerns for certain 

species are extremely difficult to translate into relevant economic estimates. In order to 

provide the Secretary full and appropriate information for the PFP decision, this 

document is supplemented by relevant NEPA documents and other analyses that present 

information relating to such environmental factors and other qualitative considerations. 

The information provided in these separate documents and analyses, which is 

summarized in part II of this document, is incorporated by reference in this discussion.

As discussed in part I of this document, the 2009 DPP proposed sales in 12 of the 26 

OCS planning areas, including the 3 Atlantic planning areas, 2 of the planning areas 
189

offshore California and NAB, offshore Alaska, in addition to the 6 areas that were 

included in the PP. 

In deciding to reduce the number of planning areas included in the PP and retain those 

areas in this PFP, the Secretary performed the section 18(a)(3) balancing, informed by a 

consideration of the factors listed in section 18(a)(2). The factors listed in section 

18(a)(2) were addressed in the 2009 DPP with respect to each of the 12 originallyproposed planning areas. The 2009 DPP’s consideration of one of those factors, relative 

environmental sensitivity, section 18(a)(2)(G), was limited to shoreline areas, but this 

level of analysis was deemed insufficient by the U.S. Court of Appeals for the District of 

Columbia Circuit in Center for Biological Diversity v. DOI, 563 F.3d 466 (D.C. Cir. 

2009). On remand in that case, which concerned the 2007-2012 Program, the 

environmental sensitivity analysis was augmented to include an analysis of the entire 

OCS domain with respect to all 26 planning areas, including all 12 planning areas 

originally proposed for the then-2010-2015 program. That augmented environmental 

sensitivity analysis was utilized in developing the PP and consequently, this PFP, and is 

incorporated herein by reference. 

Based on the incorporated consideration of the section 18(a)(2) factors, including the 

augmented environmental sensitivity analysis, the Secretary undertook the balancing 

required by section 18(a)(3). Section 18(a)(3) requires the balancing of the potential for 

environmental damage, the potential for the discovery of oil and gas, and the potential for 

adverse impact on the coastal zone, and this balancing must take into account the factors 

enumerated in section 18(a)(2). As noted earlier, the Secretary applied the following 

guiding principles in conducting this balancing and selecting options for the size, timing, 

and location of areas proposed for leasing in this PFP.

• Give priority leasing consideration to areas where the combination of previous 

experience; local, state, and national laws and policies; and expressions of 

industry interest indicate that potential leasing and development activities could 

be expected to proceed in an orderly manner;

• For areas with oil and natural gas activity and/or known estimated hydrocarbon 

resources, consider leasing if, from a national and regional perspective, 

anticipated benefits from development substantially outweigh estimated 

environmental risks;

• For areas with unknown or uncertain hydrocarbon resources, consider deferring if 

enhanced information is likely to become available that will allow for better 

decision-making in subsequent Five Year Programs;

• Seek to accommodate the recommendations of governors of coastal states and of 

state and local agencies;

• Time sales in frontier areas to make use of information from exploration on 

existing leases in order to 1) minimize impacts to the environment and coastal 

areas; 2) evaluate monitoring data; 3) better assess infrastructure needs; 4) 
190

enhance financial return in future lease sales; and 5) better define areas of greatest 

interest to industry.

As a result of applying these principles, the PFP includes the six areas that were included 

in the PP. In accordance with the Act, the Secretary may not add areas or sales that were 

not included in the prior proposal without redoing the section 18 process. Therefore, the

15 sales in 6 areas that were included in the PP are the maximum that the Secretary may 

consider at this stage. 

With respect to the Atlantic planning areas, in comments on the 2009 DPP, the States of 

Delaware and New Jersey, adjacent to the Mid-Atlantic and North Atlantic

planning areas, respectfully voiced their opposition to oil and natural gas activities off 

their coasts and pointed to state policies and initiatives to move to renewable energy 

sources. Although the States of South Carolina and Georgia voiced support for leasing at 

the 2009 DPP stage and the Commonwealth of Virginia strongly objected to the area off 

its coast being deleted from the PP, the potential amount and location of oil and natural 

gas resources in the Mid- and South Atlantic planning areas are limited. Seismic surveys 

in these areas were recorded in the 1980’s. There have been significant advances in

techniques and analysis since then. New seismic data is needed to much more accurately 

define where hydrocarbon resources may be. Accordingly, the Secretary is not including 

these two areas in this Five Year Program. Instead, he is moving forward with an 

environmental analysis for potential G&G studies to support conventional and renewable 

energy planning, and inform future decisions regarding leasing, in these areas. 

With respect to California, in his comments on the 2009 DPP, the Governor of California 

reiterated that state’s long-standing opposition expressed by governors of both parties to 

new leasing off its coast. This position also is presented by the California Coastal 

Commission, the state agency with regulatory authority over Federal activities on the 

OCS that affect the state’s coastal resources pursuant to CZMA.

Because the GOM continues to be the region with the highest potential production on the 

OCS and has existing infrastructure and oversight capacity to limit potential 

environmental damage and adverse impacts on the coastal zone, the Secretary is 

including in the Five Year Program, the Western and portions of the Central and Eastern 

GOM that are not under Congressional moratorium or otherwise unavailable. In their 

comments on the PP, both industry and the State of Louisiana reiterated their support for 

including GOM program areas for leasing consideration. However, they and various 

non-energy industry commenters expressed their disappointment that more areas of the 

OCS were not included. The State of Florida expressed its concern that activities 

anywhere in the GOM could impact its coastline.

In the Arctic planning areas, the program takes a cautious approach by scheduling lease 

sales late in the program to allow for scientific and environmental studies, public 

meetings, and additional studies on oil spill response capabilities in the Arctic, as well as 

to allow time for activity performed pursuant to existing leases to generate information. 

In light of both the significant resource potential that exists in the Alaskan Arctic and the 

substantial environmental challenges and the social and ecological concerns that are 
191

present as well, BOEM’s regionally tailored strategy for any future offshore oil and 

natural gas leasing in the Arctic is markedly different from the traditional areawide 

leasing model applied in the GOM, in which all unleased acreage in the area is typically 

offered for sale, with the exception of limited areas that may be set aside for exclusion. 

DOI also intends to utilize the pre-sale process to focus the areas to be offered in the 

Arctic to those with greatest resource potential and the least potential for impacts on other 

resources and uses of the areas. While the Five Year Program areas include the majority 

of the two Arctic planning areas, it is anticipated that the area that will be ultimately 

offered in a lease sale will be reduced as appropriate. The State of Alaska supported 

leasing activity in the Arctic but is concerned that delaying the sales will not help the 

state and national economy. There is strong industry interest in oil and natural gas 

activity based on known seismic data and existing production from the state/Federal unit 

in the Beaufort Sea that is supported by existing infrastructure. While there is no existing 

production in the Chukchi Sea, hydrocarbons were discovered in the past but determined 

to be uneconomic to develop and produce at the time. Furthermore, industry interest was 

evident in the historically high level of bidding in Chukchi Sea Sale 193. Pending final 

approvals, exploration activity could occur in these areas as early as the summer of 2012. 

Of course, should it become evident that exploration and development cannot occur in a 

way that does not harm the environment; the Secretary has the discretion to postpone or 

cancel a lease sale as appropriate to address these concerns. 

The Cook Inlet is included as a special interest sale. An initial Request for Interest was 

published on March 27, 2012. Comments received have resulted in sufficient interest to 

warrant BOEM’s decision to proceed with the next steps in the pre-lease process. The 

sale date has been moved to 2016 to allow time to complete the necessary steps to a sale.

In summary, after a thorough consideration of all the factors enumerated in section 

18(a)(2) and a section 18(a)(3) balancing informed by this consideration, the Secretary 

again has decided to include six planning areas, or parts thereof, in the PFP−the Western 

and available parts of the Central and Eastern GOM; and the Cook Inlet, and the Chukchi

and Beaufort Seas, offshore Alaska. 

Judicial Guidance

The U.S. Court of Appeals for the D.C. Circuit has elaborated in great detail on the 

statutory criteria for the balancing decision required by section 18(a)(3). Pertinent 

excerpts from the Court’s opinions stemming from litigation concerning previous Five 

Year Programs are presented below.

The Court has stated the following concerning the weight to be accorded the three 

elements of section 18(a)(3).

That the Act has an objective—the expeditious development of OCS 

resources—persuades us to reject petitioners’ view that the three

elements in section 18(a)(3) are “equally important” and that no factor is 

“inherently more important than another.” The environmental and 
192

coastal zone considerations are undoubtedly important, but the Act does 

not require they receive a weight equal to that of potential oil and gas 

discovery. A balancing of factors is not the same as treating all factors 

equally. The obligation instead is to look at all factors and then balance 

the results. The Act does not mandate any particular balance, but vests 

the Secretary with discretion to weigh the elements so as to “best meet 

national energy needs.” The weight of these elements may well shift 

with changes in technology, in environment, and in the Nation’s energy 

needs, meaning that the proper balance for 1980-1985 may differ from 

the proper balance for some subsequent five-year period. (California I, 

668 F.2d at 1317)

The following three statements of the Court pertain to the analysis of the section 18 factors 

and the Secretary’s discretion in weighing the results of that analysis:

(1) The Act recognized the difficult burden the Secretary must shoulder 

by stating that the selection of timing and location of leasing must strike 

the proper balance “to the maximum extent practicable.” The Secretary 

must evaluate oil and gas potential, which can be quantified in monetary 

terms, in conjunction with environmental and social costs, which do not 

always lend themselves to direct measurement. Because of this, they 

must be considered in qualitative as well as quantitative terms.

Although the secretarial discretion we have described is broad, as a result 

of both the general wording of the statute and the nature of the task the 

Secretary is asked to perform, the Secretary’s discretion is not 

unreviewable. The policies and purposes of the Act provide standards by 

which we may determine whether the Secretary’s decision was arbitrary, 

irrational, or contrary to the requirements of the Act. To do so, we 

consider “whether the decision was based on a consideration of the 

relevant factors and whether there has been a clear error of judgment.” 

(California I, 668 F.2d at 1317)

(2) In deciding whether to include an area, the Secretary weighed 

qualitative factors as well as quantitative factors. The Secretary listed 

among qualitative factors “national security, industry interest, and 

equitable sharing of development costs and benefits.” The OCSLA 

specifically directs the Secretary to weigh such qualitative factors in his 

balance.

Taking qualitative factors into account implies that the inclusion of areas 

with a calculated NSV of zero may nonetheless be compatible with 

section 18(a)(3). (NRDC, 865 F.2d at 307)

(3) The Secretary must make a good-faith effort to balance 

environmental and economic interests. So long as he proceeds 
193

reasonably, however, his decisions warrant our respect. (NRDC, 865 

F.2d at 308-309)

Other Considerations

Other relevant considerations that have implications for balancing environmental and 

socioeconomic issues and concerns with potential benefits of OCS activity are discussed 

in this document, the Final EIS prepared for the Five Year Program for 2012-2017, and in 

other referenced documents. Such considerations are summarized below.

Findings and Purposes of the OCS Lands Act. Title I of the Act Amendments of 1978 

sets forth a number of findings and purposes with respect to managing OCS resources. 

Those principles generally pertain to recognizing national energy needs and related 

circumstances and addressing them by developing OCS oil and natural gas resources in a 

safe and efficient manner that provides for environmental protection; fair and equitable 

returns to the public; state and local participation in policy and planning decisions; and 

resolution of conflicts related to other ocean and coastal resources and uses.

Industry Interest. Interest, as indicated in the comments responding to the 2011 PP, is 

summarized above. Industry interest is a key criterion for deciding whether to propose an 

area for a lease sale. However, it is not the sole and absolute indicator of the potential of 

an area to contribute oil and natural gas resources for regional and national use. 

Therefore, as with all of the balancing information discussed in this part, industry interest 

should be weighed with other considerations in deciding where and when to propose 

OCS leasing. The presentation of size, timing, and location options in part III of this 

document includes discussions of industry interest along with other significant 

considerations. Summaries of all industry comments are provided in Appendix A to this 

document.

Information Incorporated by Reference. Documents pertaining to geographical, 

geological, and ecological characteristics, to local and national energy markets and needs, 

and to environmental and predictive information, as cited in part II of this document, are 

incorporated by reference. 

Issues Raised in Comments. Comments received in response to the PP are summarized 

in Appendix A. Those that correspond more specifically to program options are 

summarized in part III of this document, along with responses to selected comments and 

recommendations. 

Conclusions

OCS holds vast potential for discovery and production of oil and natural gas, as outlined 

in previous sections above. In frontier areas such as the Arctic, further exploration would 

assist in the evaluation of the extent of natural gas and oil resources. In designing the 

PFP, BOEM has relied on the best available environmental and hydrocarbon resource 

assessment information. The potential for environmental damage and the potential 
194

effects on the coastal zone of the respective areas considered for leasing are analyzed in 

the Five Year Final EIS for the 2007-2012 Program, which has been incorporated by 

reference. The potential for safe and environmentally sound resource development and 

the extent of the Nation’s energy needs outweigh the risk and likelihood of significant 

environmental damage, particularly when comparing the consequences of certain energy 

substitutes88 to a regular and dependable leasing program on the OCS. At the same time, 

this PFP seeks to accommodate the recommendations of state and local governments and 

the policies of affected jurisdictions. All of these factors are reflected in the size, timing, 

and location of lease sales in this Five Year Program.

F. Assurance of Fair Market Value 

The Act grants the Secretary the authority to issue leases on the OCS. Section 18(a)(4) of 

the Act states that “[L]easing activities shall be conducted to assure receipt of fair market 

value for the lands leased and the rights conveyed by the Federal Government.” 

Furthermore, the Act states that the OCS is a “vital national reserve held by the Federal 

Government for the public, which should be made 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.” 

The FMV determination, made at the time of lease award, is not based on the value of the 

oil and natural gas eventually discovered or produced. Instead it is related to the value of 

the right to explore for and, if there is a discovery, to develop and produce hydrocarbons. 

Therefore, this value is based on the expected, not actual, activities and results that are 

anticipated to occur after the sale. Moreover, this value depends upon the conditions 

imposed on lessees by BOEM and BSEE, such as diligence and drilling requirements, 

which may restrict lessee flexibility in attaining certain timing milestones and hence have 

a negative effect on expected or actual tract value.

There are several major elements in designing OCS auctions such as lease sale timing, 

bidding systems, and sale terms and conditions, for assuring that OCS leases are not 

awarded prematurely or for less than FMV. This section discusses important 

considerations used to evaluate options under these elements and includes an overview of 

the post-sale OCS bid adequacy process. Part III.B of this document discusses in greater 

detail the pre- and post-sale measures taken to assure receipt of FMV for OCS leases as 

required by section 18(a)(4) of the Act.

The Five Year Program includes general provisions for assuring the receipt of FMV. 

Those provisions include determining on a sale-by-sale basis whether or not to hold a 

sale, the leasing framework, the sale terms, and the bid adequacy procedures for the postsale assessment of blocks receiving bids. Additionally, BOEM and BSEE enforcement of 

laws, regulations, and lease terms assure conservation of resources through diligent 

development of leases. 

 88 Among these are increases in imported oil, onshore oil and natural gas production, and coal used to 

generate electricity. See analysis of Net Environmental and Social Costs.
195

Optimal Timing

Part III.B of this document, Fair Market Value Options, includes the approach that 

BOEM will employ at the lease sale stage to determine whether or not the timing is 

favorable to hold a program area lease sale. This approach will help ensure that FMV is 

received by postponing leasing in areas where there may be greater value in waiting. If 

the analysis shows that timing may not be right, BOEM will evaluate alternatives 

including sale cancellation.

Leasing Framework

As discussed in part III.B, based on reviews of the results of the AWL Study that focuses 

on the GOM, BOEM plans to continue using areawide leasing but will periodically 

evaluate fiscal terms to ensure the set of terms selected furthers the goals of the Act, with 

emphasis on timely leasing and drilling, meeting the Nation’s energy needs through 

efficient resource recovery, and obtaining FMV for the sale of lease rights for drilling and 

extraction. BOEM will continue to review actual sale results including tracts sold, 

bonuses offered, number of bids on the offered tracts, and the extent of company 

competition to determine if changes are needed in the composition and size of the lease 

sale to better provide for FMV and to make any changes to the leasing framework that 

would be beneficial to the program and the public. 

Sale Terms

One of the key components in the government’s receipt of FMV for OCS resources is the 

setting of the fiscal terms and length-of-lease initial periods for each sale, as described in 

part III.B of this document. Before each sale, BOEM evaluates these terms and considers 

whether to incrementally adjust them based on emerging market conditions, competition, 

and the prospective nature of available OCS acreage. For example, the royalty rate has 

been raised twice for GOM leases in recent years to capture a greater portion of revenue 

as oil and natural gas prices have risen substantially above levels that prevailed for 

virtually all previous years. Escalating rentals have been implemented recently for leases 

in GOM and Alaska for the Chukchi and Beaufort Seas to encourage timely exploration 

and development or earlier relinquishment. The length of the initial lease period for 

GOM leases recently has been changed in water depths of 400 to 1,600 meters to reflect 

the shorter time deemed necessary to explore for economic prospects. Most recently, the 

minimum bid was increased in the deepwater GOM to account for increases in oil prices 

and to encourage optimal timing of leasing for those blocks. 

Following sales, the bidding is analyzed to determine whether or not the changes have 

impeded competition for leases and to see if additional changes or adjustments are 

necessary. Periodic evaluation of sale terms allows BOEM the opportunity to adjust 

them if market conditions warrant a change. The practice of making incremental 

adjustments allows BOEM to evaluate the results of a lease sale held with new sale terms 

and further refine terms if necessary in future sales without incurring undue risk to the 
196

program. Each of the sale terms contributes to the assurance of FMV for the public’s 

resources. 

Block Evaluation and Bid Adequacy

The Five Year Program includes a two-phase post-sale evaluation process for 

determining bid adequacy, as discussed in part III.B of this document. The current form 

of the bid evaluation procedures was instituted in 1983 in conjunction with the 

implementation of the AWL policy, but is dynamic and has undergone several 

refinements to address FMV concerns as conditions changed. The last significant 

revision to these procedures was published in the Federal Register on July 12, 1999 (64 

FR 37560). Since then, minor changes have been made to the bid adequacy process such 

as adjusting the water depth categories used in the analysis. BOEM continues to look for 

opportunities to improve the process and has supported a major refinement in the tract 

evaluation model used in bid adequacy that is well underway. Moreover, in 

implementing the new Five Year Program, there may be revisions made to the OCS bid 

adequacy procedures or their underlying components such as the tract evaluation model 

to incorporate knowledge gained from experience using the procedures, or to 

accommodate structural changes to the leasing process or sale terms. 

BOEM reviews all high bids received to help ensure that those accepted will represent 

FMV for the lease block. If a high bonus bid does not satisfy any of the required bid 

adequacy conditions, the bid is rejected. If a block is rejected, it may be reoffered at the 

next scheduled lease sale in that area. From 2005 to 2008, more than half of the tracts 

with bids rejected through bid adequacy received acceptable high bids when reoffered in 

a subsequent sale. Moreover, rejection of a high bid under the existing BOEM bid 

adequacy procedures consistently has resulted in significantly higher bids in subsequent 

sales for the same blocks, even when those blocks that did not receive subsequent bids 

are included in the calculation.

In GOM from 1984 through 2010, BOEM rejected total high bids of $597 million on 

blocks that were reoffered and then drew high bids of $1.565 billion, typically within 1 

year, for a total net gain of $968 million or an increase of 162 percent. These results 

indicate that BOEM’s bid adequacy assessments and procedures have performed well in 

identifying blocks with high bids below FMV. With the possibility of bid rejection from 

the government and competition from other bidders, lease sale participants are 

encouraged to submit bids that will exceed the government’s reservation price. When 

bids exceed the reservation price, the government is confident it is receiving FMV. 

Look-back studies show that the majority of OCS leases with economic hydrocarbon 

discoveries were assigned a positive value at the time of sale. However, BOEM has 

issued leases on blocks with subsequent material discoveries where the bid evaluation’s 

value was not positive at the time of the sale and the lease was awarded for close to the 

minimum bid. In these cases, BOEM has documented that either new information 

became available after the lease was awarded, prompting a company to drill a specific 

target different than what was originally evaluated, or the internal evaluation of the 
197

potential hydrocarbon accumulation target did not coincide with that of the lessee 

company. In those cases where new information became available after the lease was 

awarded, the information tends to be either new or reprocessed geophysical data 

unavailable at the time of sale, or new subsurface well data acquired as a result of drilling 

on a nearby lease that may indicate the possibility of material hydrocarbon deposits on 

the subject lease. Since it is quite common for exploration companies to acquire new or 

reprocessed geophysical data on leases after award but prior to exploratory drilling, these 

look-back studies identify a well that has been drilled to a target that is not coincident 

with the target that was sometimes evaluated pre-sale.

Conclusion

BOEM evaluates market conditions, available resources, bidding patterns, and the status 

of production on OCS acreage when establishing terms and conditions for each lease sale. 

As presented in part III.B of this document, changes to sale terms, including the fiscal 

terms, bidding systems, and FMV procedures, are considered on a sale-by-sale basis to 

ensure new information is included and FMV is received. If BOEM changes the sale 

terms, bidding system, or bid adequacy procedures, any such changes are announced to 

the public and industry through the Proposed Notice of Sale or other notification in the 

Federal Register, typically prior to the Final Notice of Sale.

G. Appropriations and Staffing Estimates 

Section 18(b) of the Act requires that the leasing program include estimates of the 

appropriations and staff needed to obtain information for preparing the program, to 

analyze and interpret data and information, to conduct environmental studies and prepare 

EISs, and to supervise operations pursuant to the leases that will be issued. 

Table 31 presents the appropriations and staffing estimates associated with the PFP for 

2012-2017.
198

TABLE 31: Appropriations and Staffing Estimates (by Fiscal Year)

[Funding estimates are in thousands of dollars; staffing estimates are in full-time equivalent positions.]

FY 2013 FY 2014 FY 2015 FY 2016 FY 2017

Activities Funds Staff Funds Staff Funds Staff Funds Staff Funds Staff

1 $17,190,000 98 $17,493,800 98 $17,803,676 98 $18,119,750 98 $18,442,145 98

2 $8,990,000 58 $9,169,800 58 $9,353,196 58 $9,540,260 58 $9,731,065 58

3 $28,600,000 120 $28,972,000 120 $29,351,440 120 $29,738,469 120 $30,133,238 120

4 $1,550,000 10 $3,320,100 21 $5,160,384 32 $7,072,951 43 $9,059,957 54

(1) Resource Information [section 18(b)(1)]

(2) Exploration Data and Other Information [section 18(b)(2)]

(3) Environmental Studies and EIS Preparation [section 18(b)(3)]

(4) Supervise Operations [section 18(b)(4)]
199

Appendix A

Summary of Comments to November 20, 2011, Federal Register Notice Concerning 

the Proposed Five Year OCS Oil and Gas Leasing Program for 2012-2017

Introduction

Section 18 of the Act, 43 U.S.C. 1344, requires DOI to prepare a five year OCS oil and 

gas leasing program. As an intermediate step in the preparation of the Five Year Program 

for 2012-2017, BOEM issued a Federal Register Notice soliciting comments on the 

Proposed Program. This appendix is a summary of comments received in response to 

that notice. Submittals have been condensed to express summaries of all ideas and 

recommendations received by category. Commenter categories are listed below along 

with the number of comments received in that category. The Summary of Comments by 

commenter category follows.

Number of Comments by Category

Governors, State-level Elected Officials, and State Agencies 9

Local Governments, Tribes, and Alaska Native Corporations 5

Members of Congress and Federal Agencies 12

Environmental and Other Public Interest Organizations 18

Oil and Gas Companies and Associations and Related Industry 14

Non-Energy Industry Businesses, Associations and Groups 13

General Public 280,118

Total 280,189

Summary of Comments

Governors, State-level Elected Officials, and State Agencies

Alaska Department of Natural Resources states that the State remains a strong proponent 

of timely decision-making and development of the OCS. The State requests that the 

Beaufort and Chukchi Seas sales not be delayed until as late in the program as it delays 

economic development and jobs and securing energy independence. The State objects to 

the moratoria in Bristol Bay. The historical basis for earlier moratoria was a vessel spill 

22 years ago. Federal and state laws are more rigorous now. Also, to correspond with 

the OCS lease sale that had been scheduled in that area, the State instituted an onshore 

leasing program that is now fruitless. The State provided specific technical comments on 

the PP as well as comments on the three technical documents.

Alaska State Representative urges BOEM to move forward with the program but is 

discouraged by the permitting delays and regulatory uncertainty. A robust 2012-2017 

program must ensure that lessees have the capacity to explore and develop in a timely 

manner.
200

Florida Department of Environmental Protection says that the State remains concerned 

about effects of oil and gas activities in the GOM and requests that consideration be 

given to long-term protection of Florida’s sensitive coastal and marine resources. 

Deepwater Horizon showed that accidental spills can affect Florida’s resources. Safety 

and environmental protection must be paramount.

Louisiana Department of Natural Resources states that the State supports exploration and 

development throughout the OCS, not just the GOM and Alaska, to meet domestic 

energy demand and safeguard energy and economic security. While favoring OCS 

leasing, the State points out that it has been impacted over time without commensurate 

mitigation. BOEM must compensate the State by addressing cumulative and secondary 

impacts. Revenue sharing should take into account historical impacts, not just new 

production as under GOMESA. Revenue sharing with coastal states that facilitate 

drilling off their coasts benefits all and some states might reconsider their opposition.

North Carolina State Senator is disappointed that the Atlantic leasing areas are absent 

from the program as technically and economically recoverable resources have been 

identified and industry interest is evident. The last Atlantic lease was offshore North 

Carolina and companies have applied for G&G permits in the Atlantic. The economy 

depends on the millions of jobs generated directly and indirectly by offshore energy 

production, including agribusiness, the State’s Number 1 industry.

Virginia Governor wrote two letters requesting reconsideration of the decision not to 

include the Mid-Atlantic, specifically offshore Virginia, from the 2012-2017 program. 

The decision ignores the support from Virginia’s citizens and state and Federal 

leadership, the potential for jobs and billions in revenue, and the Administration’s support 

as recently as March 2010. There have been great advances since Deepwater Horizon to 

be confident in safe and responsible energy development. He also states that 

development can occur without interference with other important activities and is 

working with DOD and others to protect national security operations as has been done in 

the Gulf, and important commercial activities.

Virginia Department of Mines, Minerals, and Energy asks Interior to reconsider the 

decision to exclude Virginia. Sale 220 was included in the 2007-2012 program and no 

conditions have changed to justify the omission. Including the sale could create 

thousands of jobs, expand the coastal economy, and develop critical domestic energy 

resources.

Virginia State Delegate expresses his disappointment that the program did not include 

areas of the Atlantic, Pacific, and most of the Eastern GOM.

Southern States Energy Board, represented by the Governors of Oklahoma and Virginia, 

states that the proposed plan limits the Nation’s ability to respond to growing demand and 

economic threats. It does not meet the section 18 requirement of a schedule to best meet 
201

the Nation’s energy needs. The Board urges reconsideration of the exclusion of the 

Eastern Gulf and the Mid- and South Atlantic.

Local Governments, Tribes, and Alaska Native Corporations

Arctic Slope Regional Corporation is concerned that cutting back on the number of lease 

sales and pushing the timing of the sales to the end of the five year period in the Beaufort 

and Chukchi Seas, is erecting unnecessary barriers to the development of domestic 

energy resources. The Corporation believes BOEM did not adequately consider the 

economic impact of reducing the number of lease sales scheduled for Alaska OCS, citing 

the PP societal costs, Table 8 model, and economic analysis in the PP. It urges BOEM to 

consider revising the PP consistent with the framework in the 2009 DPP, with respect to 

development of oil and gas resources in Alaska OCS.

Inupiat Community of the Arctic Slope wants the Beaufort and Chukchi Seas excluded 

from the 2012-17 program. The Community feels the PP does not address catastrophic 

effects of a large spill on communities. Additionally, if there is a sale, they want BOEM 

to include deferral areas to protect subsistence activities such as bowhead whale hunting, 

have more serious consideration provided for air and water pollution, and conduct an 

environmental justice analysis. They feel the potential damage to the environment and 

subsistence culture far outweigh the potential benefits of additional lease sales.

Native Village of Kotzebue is concerned that the PP has not addressed the need of 

Federal agencies (especially USCG and NOAA) to have sufficient resources to oversee 

lease activity in the frontier area of the Chukchi Sea, the challenges on oil spill response 

along the coast of the Chukchi Sea, and a discussion of lessons learned from Deepwater 

Horizon. The Village requests that BOEM consider narrowing the areal focus in known 

sensitive areas, important migratory corridors and important subsistence use areas, 

including larger deferral areas between leases and shore. While noting it appears a fait 

accompli that the Chukchi Sea will be included in the program, the Village hopes the 

Secretary and BOEM recognize their decisions are the main line of defense against undue 

harm caused by carrying out an active Arctic OCS development program.

North Slope Borough restates their opposition to offshore oil and gas leasing and 

operations in Arctic waters. The Borough prefers that BOEM exclude the Beaufort and 

Chukchi Seas. If leasing continues, they request that BOEM change their approach in 

each planning stage. Additionally, they would like BOEM to add deferral areas in the 

Beaufort Sea in the area adjacent to the Nuiqsut subsistence whaling base of Cross Island, 

along with excluding the eastern, central, and western areas of the Beaufort Sea that are 

essential to subsistence whaling. The Borough wants the coastal buffer in Chukchi Sea 

expanded to 60 miles and a deferral area added around Hannah Shoal. They cite NMFS's 

reasoning on this subject. They request BOEM attempt to achieve a balance between 

risks and benefits, implement a mitigation system that requires lessees to gather targeted 

data over multiple years in a specific area and implement realistic oil spill response 

demonstrations, if not in the five year, these should be considered in specific arctic lease 

sales.
202

Northwest Arctic Borough does not believe it is appropriate to include the Chukchi and 

Beaufort Seas in the five year leasing program. They are concerned about the 

disproportionate economic, environmental, social and cultural risks. There is a need for a 

comprehensive and coordinated approach to filling critical information gaps for the 

Arctic offshore areas as well as institution of revenue sharing for all phases of oil and gas

development, and for oil and gas operators be subject to best pollution control 

technology. There is a need for realistic scenarios for the potential distribution of oil 

from large spill, adequate USCG presence in the Arctic and marine pilots to be licensed 

by the state on vessels. They request concurrent comment periods with EIS and PP. 

Members of Congress and Federal Agencies

Alaska and Louisiana Senators express support for new and expanded access to the OCS, 

including offshore Virginia. Significant regulatory action taken by DOI and actions 

taken by industry to restore confidence mean it is time to move forward with access to 

new areas.

Louisiana Senator comments that the PP falls short of the section 18 requirement that a 

schedule “best meet national energy needs for the five year period following its 

approval....” He questions how eliminating acreage in the Atlantic, Eastern GOM, 

Southern California, and North Aleutian Basin, Alaska, and going from about 5 sales per 

year as in the 2009 DPP to 2.5 meet this requirement. This program is a barrier to new 

jobs and ignores the Nation’s energy and economic needs.

Virginia Senators strongly support inclusion of the areas off the coast of Virginia and 

want to revise the map of the Mid-Atlantic to more accurately reflect Virginia’s 

resources. Development of OCS resources with revenue sharing with states would attract 

jobs, boost domestic energy production, and provide funding for state priorities.

8 Virginia Representatives convey their disappointment that Virginia is not included. 

They comment that it ignores the legal requirement to consider the “laws, goals, and 

policies of affected states...,” describe the history of Virginia’s support for leasing off the 

coast, and state that it will now be years before the thousands of jobs and economic 

contribution from activity.

64 Representatives from 20 states support the decision for no development in the Atlantic 

and Pacific, but they are concerned about additional leasing in the Arctic. They question 

excluding the Atlantic for lack of infrastructure and spill preparedness but not the Arctic. 

They list five things needed before including the Arctic—prioritize protections for 

important areas using adequate science; adopt new regulations on spill response and 

planning standards; develop and have adequate response plans, methods and equipment 

by companies and Federal agencies; implement a scientific plan with recommendations 

from USGS report; and test and prove effectiveness of equipment in Arctic conditions
203

182 Representatives from 41 states express strong support for consideration of new and 

expanded areas to bring jobs, energy and revenue to the Treasury. This is the first 

program since the Presidential and Congressional moratoria were lifted in 2008, in 

anticipation of new access after three-quarters of the OCS had been off limits for 30 

years. Given the regulatory changes and actions by industry since Deepwater Horizon, it 

is time to move ahead with new access to American resources rather than continuing 

overreliance of foreign sources of energy.

Department of Energy commented that the PP is consistent with the Administration's 

Blueprint for a Secure Energy Future. DOE supports DOI's proposal to continue the 

annual offering of all acreage in the Central and Western GOM, as well as the proposal to 

pursue leasing on the OCS in Alaska. DOE recommends that DOI include projections of 

technology advancement in its consideration of the technical, economic and 

environmental feasibility of producing OCS resources during the program’s duration.

Department of Defense’s assessment of GOM program areas is unchanged from its 

previous assessment in April 2010. However, DOD requests early coordination on any 

lease sale due to ongoing testing and training in those areas. In the Beaufort Sea, DOD 

may request site specific stipulations for lease blocks in the vicinity of three air defense 

radar sites: Point Barrow, Olkitok and Barter Island. For Cook Inlet, DOD requests 

careful consideration to avoid commercial submarine communications cables.

National Oceanic and Atmospheric Administration supports deferring sales in the 

Chukchi and Beaufort Seas until late in the program to provide a chance for further 

scientific study and assessment and looks forward to working with BOEM on the 

research that will support future decision-making. NOAA believes that recognition of 

sensitive and protected marine habitats (specifically Hanna Shoal in the Chukchi Sea) 

should be considered at the five year program stage rather than waiting until the lease 

sale stage. Furthermore, they have endorsed deferral of blocks in the Chukchi within 60 

miles of the coast at the program stage. NOAA believes that early decisions on deferral 

areas would not only help protect sensitive environments and species, but would help 

industry by setting clear expectations about where exploration and development can 

occur and would allow them to focus their resources. NOAA does not believe that it is 

clear if rules were considered to require corporations to have plans in place for 

environmental cleanup in case of an oil spill cannot be contained. Even with new 

safeguards, there is always a chance that capping or other containment will not be 

successful. Therefore, environmental and health concerns should be developed as part of 

the worst case scenario. 

Departments of State and Transportation and DOI’s National Park Service reviewed the 

document and had no comments.

Environmental and Other Public Interest Organizations

Alaska Eskimo Whaling Commission says that the Five Year Program must comply with 

the MMPA's provisions to protect Alaska subsistence activities, including a complete 
204

revision or deletion of the modeling performed for subsistence. BOEM must ensure no 

immitigable impacts will occur. Currently, it is not a measure of replacement cost, but 

relocation cost. It ignores the social costs of relocating communities. OECM fails to 

account for costs to subsistence activities. There is a need to update and revise the 

environmental sensitivity analysis for the Arctic, especially regarding marine mammals 

and marine productivity as the analysis fails to include several Arctic species. Additional 

deferral areas and additional time to identify specific deferral areas to protect subsistence 

are needed. They propose deferral areas 20 miles east of Cross Island in the Beaufort Sea 

and increasing the 25-mile buffer in the Chukchi Sea. Ecosystem-based planning is 

needed to address conflicts between offshore oil and gas and subsistence uses. There is a 

need to work more closely with Alaska Native organizations.

Alaska Wilderness League, Alaska’s Big Village Network, Center for Biological 

Diversity, Center for Water Advocacy, Defenders of Wildlife, Eyak Preservation 

Council, National Resources Defense Council, Northern Alaska Environmental Center, 

Pacific Environment, Republicans for Environmental Protection, Sierra Club, The 

Wilderness Society, and the World Wildlife Fund U.S. Arctic Field Program believe 

BOEM should improve interagency coordination of analysis and permitting of oil and gas 

projects and leasing should be based on science-based decision-making. Require that 

Shell obtain the proper permits from the U.S. Environmental Protection Agency prior to 

drilling in the Arctic and require it demonstrate it can clean up a worst-case spill in bad 

weather. The Godafoss spill in Norway demonstrates that oil cleanup in Arctic waters is 

not yet feasible. Address comments received from local Arctic communities in the EIS 

document, such as deferrals for Nuiqsut hunters. Include an alternative for "no arctic 

leasing" in the EIS. Fill in data gaps contained in EIS for marine mammals, fish, and 

birds. Implement recommendations contained in post-Macondo reports. Include effects 

of leasing on climate change and ocean acidification. Improve modeling of economic 

costs of leasing and alternatives.

Alaska Wilderness League, Eyak Preservation Council, Center for Biological Diversity, 

Northern Alaska Environmental Center, Defenders of Wildlife, Resisting Environmental 

Destruction on Indigenous Lands, Natural Resources Defense Council, The Wilderness 

Society, Pacific Environment, Ocean Conservation Research, Sierra Club, and the World 

Wildlife Fund U.S. Arctic Field Program ask BOEM to postpone all further Arctic lease 

sales, not just scale them back. This is based on the extreme sensitivity of the Arctic 

environment, inadequate scientific data, and inadequate spill response capability. No oil 

and gas activities should be permitted in the Arctic until the United States undertakes a 

careful examination of the Deepwater Horizon disaster; gathers missing scientific data 

regarding wildlife and ecosystems; proves that oil spill response technology can work in 

the Arctic; puts in place a comprehensive plan and infrastructure to respond to a well 

blowout or other large spill; and actually implements the recommendations in the postMacondo reports. The PP moves forward with leasing in the Arctic despite large 

information gaps; failure to consider indirect, synergistic, interrelated, and cumulative 

impacts; inaccuracies in weighing environmental values; opaque reasoning on 

assumptions made; oil spill modeling that fails to consider the likelihood of oil reaching 

the species on their most important habitats; erroneous assumption of uniform 
205

distribution of environmental sensitivity risks; failure to consider an ecosystem's ability 

to recover from an impact in the environmental sensitivity analysis; and failure to 

incorporate a discussion of the impacts of an onshore pipeline and other terrestrial 

operations on wildlife, habitat, and people. BOEM should include more middle-ground 

alternatives in the PP, as listed alternatives focus too heavily on leasing extremes. Net 

Public Benefits analysis is flawed because the public-benefit side is dominated by private 

industry profits, private benefits should not be included; and both sides of the analysis 

overlook true social and environmental values of the "no action" alternative and the 

devastating externalities of leasing in the Arctic. PP balancing was too heavily weighted 

on one or two factors with no effective balancing discussion.

Center for Regulatory Effectiveness recommends (1) the use of PAMGUARD as part of 

the protected species observer program; (2) that the Five Year Final EIS should reflect 

the conclusion that seismic does not adversely affect marine mammals under current 

BOEM regulations; (3) any new seismic regulations issued by BOEM require a new 

proposed Information Collection Request; and (4) Coastal and Marine Spatial Planning

(CMSP) violates the Act. CMSP requires that all ocean uses be considered equally, while 

the Act requires BOEM to give more weight to the development of oil and gas.

Center of Sustainable Economy critiques the Net Public Benefits (NPB) analysis 

incorporated in the PP. NPB presents a biased characterization and analysis of the no 

action alternative that significantly understates its economic and social value; 

overestimates program benefits by including private profits, relying on unwarranted 

assumptions about the effects of OCS oil and gas supplies on prices and by failing to 

account for final petroleum product exports; underestimates program costs by excluding 

costs of public subsidies, ecosystem service damages and carbon emissions damage; and 

fails to model the effects of a wide range of policy interventions that affect program 

economics.

Consumer Energy Alliance urges BOEM to ensure that the PP moves forward with all 15 

proposed lease sales in a timely manner. The Alliance also expresses disappointment in 

the Department’s decision to not include lease sales in areas of the Mid- and South 

Atlantic in the PP.

Institute for 21st Century Energy feels that the PP fails to allow for expeditious and 

orderly development of the OCS, but encourages DOI to finalize the program quickly and 

not constrain the scope of the potential leasing areas further. Lease sales should give 

preference to areas with highest potential for resource development. Once finalized, the 

Institute recommends immediately revising the program by scoping additional areas, 

including those proposed in the 2010-2015 DPP.

Institute for Policy Integrity advocates revising the PP analysis to account for the option 

value of offshore resources, which takes into account the potential value of postponing a 

decision to lease an area until later when more information may be available. When 

evaluating the costs and benefits of opening lands for leasing, the value of delay can be 

estimated and included as a cost of opening new lands for leasing. During the bid 
206

adequacy process, the government can also set a higher reservation price, reflecting the 

option value of the land.

International Fund for Animal Welfare opposes lease sales in the Beaufort and Chukchi 

Seas, and encourages the agency to consider no sales in these areas. Their concerns 

include climate change projections of more storms of increasing strength in the Beaufort 

and Chukchi Seas that would overlap with the exploration or drilling season; harm to 

marine mammals from increased noise from seismic surveys and vessel traffic; and the 

lack of proven technologies and techniques for oil spill response and cleanup in Arctic 

waters. If BOEM decides to move forward with OCS oil and gas development, long-term 

extractive projects must be coupled with long-term industry-funded species monitoring 

programs and a rapid review process for Arctic research to develop more concrete 

mitigation strategies. 

Marine Conservation Institute commends the Obama Administration’s 2010 decision to 

exclude Bristol Bay from the PP. Oil and gas deposits in Bristol Bay are projected to 

yield just $7.7 billion in revenue over 25 to 40 years, far less than the $80 billion that a 

sustainable commercial fishing industry could generate during the same period.

Natural Resources Defense Council requests that the PP and its underlying NEPA 

documentation be substantially revised to remedy factual and analytical errors; Arctic 

lease sales be removed from the program entirely; and no new drilling be authorized 

anywhere on the OCS until recommendations of the National Commission and other 

post-BP Deepwater Horizon expert bodies have been fully implemented. The PP fails to 

meet section 18 requirements. Specifically, it fails to develop a leasing program that will 

best meet national energy needs; fails to consider a range of social, environmental, and 

renewable resource values contained in the OCS; fails to incorporate sufficient current 

and detailed information about ecological conditions, national policy commitments, and 

impacts of new oil and gas exploration; is based on an inadequate NEPA documentation; 

and suffers from other significant methodological errors.

National Audubon Society, Ocean Conservancy, Oceana, and Pew Trust urge BOEM to 

modify PP and Draft EIS to ensure lease sales are held consistent with stated 

commitments of DOI leadership: Expand and increase deferrals for areas known to be 

important for subsistence or ecological reasons, and create a deferral committee of 

experts to recommend leasing deferrals; terminate areawide lease sales in favor of a more 

targeted approach; make lease sales contingent on an integrated scientific research and 

monitoring program; make future Arctic sales contingent upon effective oil spill response 

capability; change the Draft EIS to include an additional alternative that excludes both 

the Beaufort and Chukchi Seas; include effects in climate change and ocean acidification 

in the EIS; and give local communities a more meaningful opportunity to express 

opinions.

Nature Conservancy urges BOEM to align the PP with recommendations of The White 

House Council on Environmental Quality's Interagency Ocean Policy Task Force, 

including the use of Coastal Marine Spatial Planning. The proposed delay in Arctic 
207

planning area sales until 2015-16 is the minimum amount of time to allow for proper 

planning and consideration of ecosystem impacts, spill response, and the requirement for 

consultation with the Inupiat Nation. It supports a 2000-foot buffer around biologically 

sensitive areas in the GOM and recommends excluding the Eastern GOM for the duration 

of the program due to high risk and relatively low net benefit. It supports the exclusion 

of Atlantic and Pacific.

Ocean Conservation Research asks that BOEM limit the EIS exclusively to exploration 

because of a lack of understanding of the technologies. It recommends the "no action 

alternative" be selected.

Oceana recommends scheduling no lease sales in GOM until at least 2014, and 

scheduling no lease sales in the Chukchi and Beaufort Seas. BOEM must fundamentally 

reconsider the manner in which it estimates the costs and benefits of program 

alternatives, because it currently overstates the potential benefits of the PP and does not 

effectively account for the impact of a catastrophic spill. Oceana submitted an appendix 

on marine mammals, as well as several attachments: 1) an attachment co-authored by 

multiple groups (Oceana, Alaska’s Big Village Network, Center for Biological Diversity, 

Center For Water Advocacy, Defenders of Wildlife, Gulf Restoration, Network, Ocean 

Conservation Research, Southern Environmental Law Center, Sierra Club) discussing 

continuing shortcomings in offshore regulation and safety measures, 2) an attachment 

discussing how the Draft EIS is inadequate and violates NEPA, and 3) an attachment by 

the Center for Sustainable Economy offering a critique of the Net Public Benefits 

analysis used in the PP.

Pew Trust pointed out a number of inconsistencies between the PP and public statements 

of BOEM officials such as consideration of additional subsistence deferrals. Officials 

publicly stated that BOEM is undertaking a new approach for leasing in the Arctic that 

would shift away from areawide leasing in frontier areas such as the Arctic. However, 

the PP retains the option of conducting areawide leasing in Beaufort and Chukchi Seas. 

Surfrider Foundation strongly supports the Department’s decision to exclude the Atlantic 

and Pacific coasts from the PP. It is concerned with any Alaska sales given the likely 

challenges with spill prevention and response in the harsh and remote marine 

environment off Alaska, particularly the Arctic Ocean. It generally agrees with 

concentrating GOM sales in the Western and Central planning areas but opposes issuing 

lease sales in the Eastern GOM.

World Society for the Protection of Animals and Whale and Dolphin Conservation 

Society express concerns that impacts upon marine mammals are not adequately 

measured, weighed, or considered. The PP does not address potential threats to marine 

mammals in the Arctic and GOM, which include oil spills, noise and vessel strikes. 

There was no apparent consideration of climate change or ocean acidification as required 

in response to the Court’s remand decision (D.C. Cir. 2009). They believe that the PP 

may not satisfy NEPA requirements.
208

Oil and Gas Companies and Associations and Related Industry

Alaska Oil and Gas Association urges BOEM to move forward with the five year 

program, including the three sales on Alaska's OCS. The Association does not agree with 

BOEM's characterization in the PP of CMSP as a "national zone plan", and opposes 

inclusion of any deferral areas in PP, stating they should be addressed at lease sale stage. 

Additionally, it notes that Alaska's OCS is one of the most studied and understood oil and 

gas basins in the world, BOEM has appropriately considered impacts to resources, and 

urges BOEM to involve stakeholders in their efforts.

American Petroleum Institute supports moving forward with 2012-2017 PP and urges 

BOEM to expeditiously finalize the program. It argues there is no consistent rationale 

why the Pacific and Mid-Atlantic areas are excluded. The argument of military concerns 

in the Atlantic conflicting with oil and gas activities seems more spurious considering the 

OCS wind energy leasing programs planned offshore in Virginia, Maryland, New Jersey 

and Delaware. It states that the PP is overly constrained and fails to take advantage of 

enormous benefits documented in the program analysis and has short circuited the ability 

of the Nation to make informed decisions regarding energy security. It urges BOEM to 

begin work immediately on a new more robust five year program that will include OCS 

areas in Atlantic, Pacific and Eastern GOM.

Arkema supports BOEM's Five Year 2012-2017 PP, implemented quickly and 

responsibly. In addition, they support inclusion of "Made in America" requirements as a 

part of a lease. Arkema strongly urges BOEM to increase the pace of permitting to the 

maximum extent possible.

ATP Oil & Gas Corporation is disappointed that the new OCS five year plan restricts oil 

and gas exploration, due to undue influence by 2010’s Deepwater Horizon event. The PP 

is unnecessarily restrictive and should be amended to include frontier areas prior to its 

finalization. ATP requests BOEM provide a more robust rationale for expanding the 

areas open to OCS mineral development. 

ConocoPhillips is pleased the PP includes 15 lease sales distributed among 6 OCS 

planning areas. However, they believe BOEM should expand the areas offered for 

leasing to include additional blocks in the Eastern GOM and additional areas in the 

Alaska and Atlantic Regions. ConocoPhillips’ continued commitment to the OCS will 

largely depend on the extent to which BOEM's Oil and Gas Leasing Program makes high 

potential areas available for leasing.

International Association of Geophysical Contractors urges BOEM to expand the 

potential lease sale areas to include all areas of the OCS, in particular, the Atlantic and all 

of the Eastern GOM. They recommend that the final Five Year Leasing Program clearly 

provide for and facilitate new seismic data acquisition and subsequent analysis of the 

natural gas and oil potential of the OCS.
209

Independent Petroleum Association of America urges BOEM to finalize the 2012-2017 

program as soon as possible and not further reduce the scope of the PP. The Association 

is disappointed that the PP does not include the broadest area of the OCS as possible and 

fails to include new opportunities to expand offshore oil and natural gas in highly 

prospective areas, including offshore Virginia. Additionally, the PP directly contradicts 

the impression the President gave the American people in the recent State of the Union 

Address [January 2012] and fails to meet the intent of the Act to provide the energy 

Americans need. They urge BOEM to begin work immediately to develop a new five 

year program that includes the Atlantic, Pacific, all of the Arctic, and the remainder of the 

Eastern GOM. 

Louisiana Oil & Gas Association urges BOEM to enact the 2012-2017 PP without delay 

and further narrowing of the scope of proposed lease sales. The Association further urges 

BOEM to increase the pace of permitting to meet and eventually surpass historic levels 

and heed Virginia's desire for oil and gas development off its coast.

National Ocean Industries Association recognizes the PP must proceed but is 

disappointed to see there will be no lease sale proposed offshore Virginia and with the 

lack of access to new areas in the PP. It states that BOEM's decision not to move ahead 

with new access to the OCS lacks justifiable policy rationale. It asks BOEM to proceed 

without further reducing available areas, nor designated lease sales; and that the 

alternative with the highest level of potential for development be selected. Additionally, 

it urges BOEM to immediately begin work on a revision to the program by scoping at 

least those areas that were considered in the 2010-2015 DPP released in January 2009.

Shell Exploration & Production Company calls on Interior to finalize 2012-2017 five 

year program quickly so leasing can continue, and urges that work on new more robust 

five year program including additional areas in Atlantic, Pacific, and Eastern GOM begin 

immediately. Shell is disappointed with the Secretary's decision on December 1, 2010, to 

remove high potential areas from program without performing statutorily-mandated 

analysis and his rationale to limit areas in the program to GOM and Alaska without 

taking PP fiscal and employment benefit analysis into consideration. Additionally, Shell 

notes the PP approach to leasing in Alaska ignores the potential loss of benefits and that

there was no discussion on the economic impacts related to not having a sale in Alaska. 

It questions how BOEM will balance analysis of areawide leasing preferences with tract 

selection offerings in the Arctic; and why Deepwater Horizon is used to justify 

limitations in frontier areas in lieu of the September 14, 2011 BOEMRE/USCG report 

that revealed no issues that would pose different risks in frontier area. Shell suggests the 

OCS Scientific Committee review results of climate change impacts on environmental 

sensitivity analysis.

Shell Upstream Americas provided most of the same comments as Shell Exploration & 

Production Company with additional page-by-page detailed comments.

Statoil supports the overall program and encourages BOEM to expeditiously finalize the 

program to allow continued leasing in 2012 and beyond. Additionally, they note focused 
210

leasing in Alaska makes it difficult to comment. However, they are willing to share 

expertise with BOEM and relevant stakeholders on technological and environmental 

challenges in Arctic. BOEM should revise the PP to allow for additional sales in both 

Beaufort and Chukchi Seas and extend the term of OCS leases in the Arctic as current 

terms do not provide sufficient time to evaluate and explore resource potential.

Stone Energy urges BOEM to approve the Five Year Program for 2012-2017 with 

maximum access possible. They are disappointed that the PP does not include the 

broadest area of OCS possible and especially the omission of a lease sale offshore 

Virginia. It urges BOEM to not further reduce the scope of the PP.

TGS-NOPEC Geophysical Company urges BOEM not to reduce the scope of proposed 

lease sales in the PP and increase the pace of permitting to meet, and eventually surpass, 

historic levels

Non-Energy Industry Businesses, Associations and Groups

American Chemistry Council states that abundant and affordable supplies of natural gas 

are critical to the industry’s ability to create jobs and to successfully compete in the 

global economy and urges BOEM to reconsider its 2012-2017 program and include lease 

sales in planning areas that were included in the 2009 DPP.

American Farm Bureau Federation urges BOEM not to reduce the scope of proposed 

lease sales in the PP and increase the pace of permitting to meet, and eventually surpass, 

historic levels. It further urges BOEM and DOI to heed Virginia’s desire for oil and gas 

development off its coast and to identify opportunities to move such policy forward.

American Forest & Paper Association states that demand for natural gas will grow 

rapidly in the coming years in many sectors of the U.S. economy. The Administration 

has either developed many of these measures or supported them. The Association urges 

BOEM to significantly revise the program to at least include the lease sales in planning 

areas that were included in the 2009 DPP.

Associated Industries of Florida urges BOEM not to reduce the scope of proposed lease 

sales in the PP and increase the pace of permitting to meet, and eventually surpass, 

historic levels.

Georgia Chamber of Commerce urges BOEM to not further reduce the scope of proposed 

lease sales in the PP and to increase the pace of permitting to meet, and eventually 

surpass historic levels.

Louisiana Chemical Association urges BOEM not to reduce the scope of proposed lease 

sales in the PP and increase the pace of permitting to meet, and eventually surpass, 

historical levels. It further urges BOEM and DOI to heed Virginia’s desire for oil and 

gas development off its coast and to identify opportunities to move such policy forward.
211

Manufacture Alabama! urges BOEM not to reduce the scope of proposed lease sales in 

the PP and increase the pace of permitting to meet, and eventually surpass, historical 

levels. It further urges BOEM and DOI to heed Virginia’s desire for oil and gas 

development off its coast and to identify opportunities to move such policy forward.

North Carolina Chamber of Commerce urges BOEM to enact the PP and increase the 

pace of permitting to meet, and eventually surpass, historic levels.

New Tech Global urges BOEM not to reduce the scope of proposed lease sales in the PP 

but to increase the pace of permitting to meet, and eventually surpass, historic levels.

North Carolina Farm Bureau Federation asks BOEM to expand the score of the PP to 

provide relief to North Carolina’s farming families from increasing production costs.

Pennsylvania Manufacturers’ Association urges BOEM not to reduce the scope of 

proposed lease sales in the PP and increase the pace of permitting to meet, and eventually 

surpass, historical levels. It further urges BOEM and DOI to heed Virginia’s desire for 

oil and gas development off its coast and to identify opportunities to move such policy 

forward.

PPG Industries urge BOEM not to reduce the scope of proposed lease sales in the PP but 

to increase the pace of permitting to meet, and eventually surpass, historic levels.

Tidewater Inc. urges BOEM not to reduce the scope of proposed lease sales in the PP but 

to increase the pace of permitting to meet, and eventually surpass, historic levels.

General Public

More than 280,000 comments were received from private citizens regarding the Five 

Year Program for 2012-2017. The overwhelming majority were comments submitted 

through various public interest groups. Most were from environmental-oriented 

organizations. There was particular concern about oil and gas activities in the Alaskan 

Arctic areas of the Beaufort and Chukchi Seas. Citing the Deepwater Horizon event, 

there was apprehension about the ability to respond to an oil spill anywhere in the OCS, 

but particularly in the remote Arctic. Commenters favoring the program were 

disappointed that more areas were not available, citing the need for jobs, boosts to the 

economy, a reduced reliance on imported oil, and national security.

The Department of the Interior Mission

As the Nation's principal conservation agency, the Department of the Interior has responsibility 

for most of our nationally owned public lands and natural resources. This includes fostering 

sound use of our land and water resources; protecting our fish, wildlife, and biological diversity; 

preserving the environmental and cultural values of our national parks and historical places;

and providing for the enjoyment of life through outdoor recreation. The Department assesses

our energy and mineral resources and works to ensure that their development is in the best 

interests of all our people by encouraging stewardship and citizen participation in their care.

The Department also has a major responsibility for American Indian reservation communities

and for people who live in island territories under U.S. administration.

The Bureau of Ocean Energy Management Mission

The Bureau of Ocean Energy Management (BOEM) manages the exploration and development 

of the nation's offshore resources. It seeks to appropriately balance economic development, 

energy independence, and environmental protection through oil and gas leases, renewable 

energy development and environmental reviews and studies.