Accessible Version

OFFSHORE OIL AND 

GAS RESOURCES

Actions Needed to 

Better Protect Against 

Billions of Dollars in 

Federal Exposure to 

Decommissioning 

Liabilities

Report to Congressional Requesters

December 2015

GAO-16-40

United States Government Accountability Office
United States Government Accountability Office

Highlights of GAO-16-40, a report to 

congressional requesters

December 2015

OFFSHORE OIL AND GAS RESOURCES

Actions Needed to Better Protect Against Billions of 

Dollars in Federal Exposure to Decommissioning 

Liabilities

Why GAO Did This Study

Oil and gas produced on federal leases 

in the Gulf of Mexico are important to 

the U.S. energy supply. Historically, 

most offshore production was in 

shallow water, but more than two-thirds 

of the more than 5,000 active oil and 

gas leases in the Gulf are now located 

in deep water. When oil and gas 

infrastructure is no longer in use, 

Interior requires lessees to 

decommission it so that it does not 

pose safety and environmental 

hazards. Decommissioning can include 

plugging wells and removing platforms, 

which can cost millions of dollars. 

Interior requires lessees to provide 

bonds or other financial assurances to 

demonstrate that they can pay these 

costs; however, if lessees do not fulfill 

their decommissioning obligations, the 

federal government could be liable for 

these costs.

GAO was asked to review Interior’s 

management of liabilities from offshore 

oil and gas production. This report 

examines Interior’s (1) procedures for 

overseeing decommissioning and 

estimating its costs, (2) procedures for 

obtaining financial assurances for 

these liabilities, and (3) challenges 

managing these liabilities. GAO 

reviewed agency regulations and 

procedures and interviewed officials 

from Interior, credit rating agencies, 

academia, and trade associations.

What GAO Recommends

GAO recommends that Interior take 

several steps to improve its data 

system, complete plans to revise its 

financial assurance procedures, and 

revise its cost reporting regulations, 

among other things. Interior concurred 

with GAO’s recommendations.

What GAO Found

The Department of the Interior (Interior) has developed procedures to oversee 

the decommissioning of offshore oil and gas infrastructure and estimate costs 

associated with decommissioning liabilities but has not addressed limitations with 

its system for tracking cost estimates. According to officials, Interior’s procedures 

include (1) identifying and tracking unused infrastructure, (2) reviewing lessee 

plans to decommission infrastructure, and (3) using different cost estimates for 

decommissioning in shallow and deep water. However, inconsistent with internal 

control standards, Interior officials must manually enter cost estimates into 

Interior’s main data system to override inaccurate estimates automatically 

calculated by the system. Without a more accurate data system, Interior does not 

have reasonable assurance that it will consistently estimate the costs associated 

with decommissioning.

Interior’s procedures for obtaining financial assurances for decommissioning 

liabilities pose financial risks to the federal government, and Interior is planning to 

revise its procedures to address these risks but has not finalized its approach. As 

of October 2015, for an estimated $38.2 billion in decommissioning liabilities in 

the Gulf, Interior officials identified about $2.3 billion in liabilities that may not be 

covered by financial assurances. However, these officials were unable to 

determine the extent to which these data were valid due to limitations with 

Interior’s data system, among other things. Of the remaining $35.9 billion in 

decommissioning liabilities, Interior held or required about $2.9 billion in bonds 

and other financial assurances, and had foregone requiring about $33.0 billion in 

bonds for the remaining liabilities. Interior has procedures that allow it to waive its 

requirement for a lessee to provide a bond if the lessee passes a financial 

strength test. Prior GAO work has shown that the use of financial strength tests 

in lieu of bonds poses risks to the federal government. Interior recognizes the 

risks associated with its procedures, and Interior officials stated that they issued 

draft guidance to clarify their procedures in September 2015. Interior has not 

issued any final revisions to its procedures; therefore, it is too soon to evaluate 

the details of these proposed changes. Until Interior improves its ability to obtain 

valid data from its data system and revises and implements its financial 

assurance procedures, the federal government remains at increased risk of 

incurring costs should lessees fail to decommission oil and gas infrastructure.

Interior faces challenges managing potential decommissioning liability. For 

example, until December 2015, Interior did not have a requirement for lessees to 

report on costs associated with decommissioning activities in the Gulf. Instead, 

Interior contracted studies to obtain data on decommissioning costs, but some 

data were decades old. Federal internal control standards call for agencies to 

obtain information from external stakeholders that may significantly affect their 

ability to achieve agency goals. However, in December 2015, Interior issued final 

regulations (proposed in 2009) requiring lessees to report data on most, but not 

all, decommissioning costs to Interior. Unless and until Interior obtains accurate 

and complete data on decommissioning costs, Interior may not have reasonable 

assurance that its cost estimates of decommissioning liabilities in the Gulf are 

accurate, or that it is requiring sufficient amounts of financial assurance based on 

these estimates.

View GAO-16-40. For more information, 

contact Frank Rusco at (202) 512-3841 or 

ruscof@gao.gov.
Letter 1

Page i GAO-16-40 Offshore Oil and Gas Resources

Background 4

Interior Has Procedures to Oversee Decommissioning and 

Estimate Related Costs but Faces Data System Limitations and 

Has Not Documented Some Procedures 15

Interior’s Procedures for Obtaining Financial Assurances for 

Decommissioning Liabilities Pose Risks to the Federal 

Government, and Interior Plans to Revise Them 22

Interior Faces Two Key Challenges Managing Potential 

Decommissioning Liabilities 29

Conclusions 32

Recommendations for Executive Action 33

Agency Comments and Our Evaluation 34

Appendix I: Comments from the Department of the Interior 36

Appendix II: GAO Contact and Staff Acknowledgments 38

Appendix III: Accessible Data 39

Data Tables 39

Agency Comment Letters 45

Tables

Table 1: Bureau of Safety and Environmental Enforcement (BSEE) 

Requirements for Decommissioning Applications for Offshore 

Oil and Gas Infrastructure 16

Table 2: Bureau of Safety and Environmental Enforcement (BSEE) 

Requirements for Reporting on Decommissioning Results for 

Offshore Oil and Gas Infrastructure 17

Data Table for Figure 2: Annual Number of Wells Drilled and Plugged in 

the Gulf of Mexico, 1947-2014 39

Data Table for Figure 3: Annual Number of Structures Installed and 

Removed in the Gulf of Mexico, 1947-2014 41

Data Table for Figure 4: Annual Number of Deepwater Wells Drilled 

and Plugged in the Gulf of Mexico, 1966-2014 43

Data Table for Figure 5: Oil Production in the Gulf of Mexico, 1985-

201444

Contents
Figures

Page ii GAO-16-40 Offshore Oil and Gas Resources

Figure 1: Examples of Oil and Gas Structures in the Gulf of Mexico 7

Figure 2: Annual Number of Wells Drilled and Plugged in the Gulf of 

Mexico, 1947-2014 12

Figure 3: Annual Number of Structures Installed and Removed in the 

Gulf of Mexico, 1947-2014 13

Figure 4: Annual Number of Deepwater Wells Drilled and Plugged in the 

Gulf of Mexico, 1966-2014 14

Figure 5: Oil Production in the Gulf of Mexico, 1985-2014 15

Abbreviations

BOEM Bureau of Ocean Energy Management

BSEE Bureau of Safety and Environmental Enforcement

Gulf Gulf of Mexico

Interior Department of the Interior
TIMS Technical Information Management System

Page iii GAO-16-40 Offshore Oil and Gas Resources

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Page 1 GAO-16-40 Offshore Oil and Gas Resources

441 G St. N.W.

Washington, DC 20548

December 18, 2015

The Honorable Raúl M. Grijalva

Ranking Member

Committee on Natural Resources

House of Representatives

The Honorable Alan Lowenthal

Ranking Member

Subcommittee on Energy and Mineral Resources

Committee on Natural Resources

House of Representatives

The Honorable Peter A. DeFazio

House of Representatives

Oil and gas resources located on federal leases on the outer continental 

shelf are an important component of the nation’s energy supply.1 Wells on 

federal leases on the outer continental shelf accounted for over 16 percent 

of the nation’s crude oil production in 2014 and about 5 percent of natural 

gas production in 2013. The vast majority of this production occurred on 

federal leases in the Gulf of Mexico (Gulf). Historically, most offshore oil 

and gas activities have occurred in shallow water,2 but in recent decades 

these activities have moved into deep water. More than two-thirds of the more 

than 5,000 active oil and gas leases in the Gulf are now located in deep 

water.

The Department of the Interior (Interior) manages oil and gas activities on 

offshore federal leases, including activities associated with thousands of 

wells, platforms, and miles of pipelines on the outer continental shelf. 

When this infrastructure is no longer useful for operations or otherwise 

 

1The outer continental shelf refers to the submerged lands outside the territorial 

jurisdiction of all 50 states, but within U.S. jurisdiction and control. The portion of the North 

American continental edge that is federally designated as the outer continental shelf 

generally extends seaward 3 geographical miles off the coastline to at least 200 nautical 

miles.

2

In this report, unless other specified, we use the term “shallow” water to refer to depths of 

less than 400 feet and “deep” water to refer to depths of greater than 400 feet.

Letter
becomes idle,

Page 2 GAO-16-40 Offshore Oil and Gas Resources

3 or when a lease has been expired for more than 1 year, Interior 

requires oil and gas lessees to decommission it so that it does not pose potential 

safety hazards to marine vessels and environmental hazards to sea life and 

humans.4 Decommissioning refers to the process of plugging wells, removing 

platforms and other structures, removing or cleaning out pipelines, and clearing 

sites of debris. According to Interior estimates, in shallow water, 

decommissioning infrastructure can cost tens of millions of dollars per 

lease, depending on the number of wells and types of structures present. 

In deep water, decommissioning can cost hundreds of millions of dollars

per lease. In addition, infrastructure damaged by hurricanes is 

significantly more expensive to decommission than nondamaged 

infrastructure.

According to Interior’s regulations, all lessees are liable for 

decommissioning costs that accrue during their ownership.5 Before lessees 

drill wells or install platforms and other structures, Interior requires them to 

provide financial assurance to ensure that they are capable of meeting 

their decommissioning obligations. This financial assurance may be in the 

form of a financial asset provided by the lessee, such as a bond, or a 

determination that a lessee has the financial strength and ability to fulfill 

decommissioning obligations. According to Interior officials, the federal 

government has not incurred costs associated with offshore 

decommissioning since 1989, when a lessee declared bankruptcy.6In 

response to this bankruptcy, Interior promulgated regulations in 1993 requiring 

some lessees to provide bonds specifically for offshore decommissioning.7

Nonetheless, Interior refers to oil and gas infrastructure on offshore federal 

leases as potential liabilities because the federal government may have to 

pay for decommissioning if lessees do not.

 

3

Interior refers to wells and platforms as “idle” if they have not been used in the past 5 years for 

oil and gas exploration or development and production activities.

4

For the purposes of this report, we use the term “lessee” to refer to owners of record title and 

owners of operating rights on offshore leases, designated operators acting on behalf of 

record title and operating rights owners, and right-of-way holders. 

5

30 C.F.R. § 250.1701.

6According to Interior officials, this company entered into an agreement to fund two 

decommissioning trusts using cash, services performed, acceptable forms of security, and 

royalty reductions. As part of this agreement, Interior reduced the company’s royalty 

payments by about $13 million, which was spent on decommissioning.

7

30 C.F.R. § 556.53(d).
You asked us to review Interior’s management of potential federal 

liabilities associated with the decommissioning of offshore oil and gas 

infrastructure. This report examines (1) Interior’s procedures for 

overseeing the decommissioning of offshore oil and gas infrastructure 

and estimating costs associated with decommissioning liabilities; (2) 

Interior’s procedures for obtaining financial assurances for 

decommissioning liabilities; and (3) challenges, if any, Interior faces in 

managing potential decommissioning liabilities. We focused our work on 

the Gulf, where most oil and gas infrastructure is located.

To conduct this work, we reviewed Interior’s regulations regarding its 

management of leases for offshore oil and gas production. To examine 

Interior’s procedures for overseeing the decommissioning of offshore oil 

and gas infrastructure and estimating decommissioning costs, we 

interviewed officials from Interior’s Bureau of Safety and Environmental 

Enforcement (BSEE) in their Washington, D.C., headquarters office and 

Gulf regional office in New Orleans, Louisiana, and reviewed and 

summarized relevant BSEE guidance, procedures, and related 

documentation.

Page 3 GAO-16-40 Offshore Oil and Gas Resources

8 We also compared BSEE’s actions to implement its 

procedures to standards for internal control in the federal government.9In 

addition, to better understand the decommissioning process and the costs 

involved, we spoke with a nongeneralizable sample of officials and 

stakeholders from trade associations and academia. We identified these 

officials and stakeholders from our prior work, published academic and 

technical articles, our attendance at a decommissioning conference, and 

interviews with BSEE officials, and we selected them based on their 

knowledge in this area.

To examine Interior’s procedures for obtaining financial assurances for 

decommissioning liabilities, we interviewed officials from Interior’s Bureau 

of Ocean Energy Management (BOEM) in their Washington, D.C., 

headquarters office and Gulf regional office in New Orleans, Louisiana, 

and reviewed and summarized relevant BOEM guidance, procedures, 

and related documentation. We compared actions that BOEM took to 

 

8

For the purposes of this report, we use the term “procedure” to include Interior’s notices to 

lessees, which are supposed to clarify, supplement, or provide more details about 

Interior’s regulations; standard operating procedures; and other related documents 

describing Interior’s processes. See 30 C.F.R. § 250.103.

9GAO, Standards for Internal Control in the Federal Government, GAO/AIMD-00-21.3.1

(Washington, D.C.: November 1999).
implement its procedures to standards for internal control in the federal 

government. In addition, to better understand financial assurance and 

bonding issues, we spoke with a nongeneralizable sample of analysts 

from the three largest credit rating agencies,

Page 4 GAO-16-40 Offshore Oil and Gas Resources

10 officials from bonding 

companies, and stakeholders from trade associations. We identified these 

organizations from our prior work and interviews with BOEM officials and 

selected them based on their knowledge in this area.

To examine challenges Interior faces in managing potential 

decommissioning liabilities, we used the information collected from our 

first two objectives. We also spoke with a nongeneralizable sample of 

stakeholders from trade associations about their views on challenges; we 

identified these stakeholders from our prior work and selected them 

based on their knowledge in this area.

We conducted this performance audit from October 2014 to December

2015 in accordance with generally accepted government auditing 

standards. Those standards require that we plan and perform the audit to 

obtain sufficient, appropriate evidence to provide a reasonable basis for 

our findings and conclusions based on our audit objectives. We believe 

that the evidence obtained provides a reasonable basis for our findings 

and conclusions based on our audit objectives.

This section provides information on (1) the types of wells and structures 

in the Gulf, (2) offshore leasing, (3) financial assurance requirements, (4) 

decommissioning requirements, and (5) oil and gas infrastructure 

installed and removed in the Gulf.

Lessees drill wells to access and extract oil and gas from geologic 

formations. According to an Interior publication, “exploratory” wells are 

drilled in an area with potential oil and gas reserves, while “development” 

wells are drilled to produce oil and gas from a known reserve.11 An 

 

10The three largest credit rating agencies are Moody’s Investors Services, Standard and Poor’s, 

and Fitch Ratings, as reported by the Securities and Exchange Commission.

11According to BSEE officials, lessees sometimes drill other types of wells, such as relief 

wells and core test wells. However, these types of wells represent a very small portion of 

the wells drilled in the Gulf.

Background

Types of Wells and 

Structures in the Gulf
exploratory well may not actually produce any oil or gas, while a successful 

development well produces oil or gas. Wellheads that are located on a fixed 

platform (typically in shallow water) are referred to as “dry tree” wells, and 

wellheads that are located on the seafloor (typically in deep water) are 

referred to as “subsea” or “wet tree” wells.

Offshore oil and gas structures in the Gulf vary in size and complexity. 

The simplest structures are found in shallow water and include caissons 

and well protectors. A caisson is a cylindrical or tapered large diameter 

steel pipe enclosing a well conductor and is the minimum structure for 

offshore development. A well protector provides support to one or more 

wells with no production equipment and facilities. A more complex 

structure in shallow water is a fixed platform, which uses a jacket and 

pilings to support the superstructure, or deck.

Page 5 GAO-16-40 Offshore Oil and Gas Resources

12 The deck is the surface 

where work is performed and provides space for crew quarters, a drilling 

rig, and production facilities. Most of the large fixed platforms have living 

quarters for the crew, a helicopter pad, and room for drilling and 

production equipment.13 A typical platform is designed so that multiple 

wells may be drilled from it. Wells from a single platform may have 

bottom-hole locations many thousands of feet (laterally displaced) from 

the surface location.

Structures in deep water rely on other methods to anchor to the ocean 

floor. For example, a “compliant tower” structure supports the deck using 

a narrow, flexible tower and a piled foundation. According to an industry 

publication, the flexible nature of the compliant tower allows it to 

withstand large wind and wave forces associated with hurricanes. Other 

common deep-water structures include the tension leg platform, floating 

 

12A jacket is a steel structure that rests on the ocean’s floor and has columns, or legs. Pilings are 

driven through the legs of the jacket into the seafloor to hold the jacket in place.

13According to BSEE officials, fixed platforms are typically found in shallow water, but some 

fixed platforms are used in water depths between 400 feet and 1,400 feet.
production system, and spar platform.

Page 6 GAO-16-40 Offshore Oil and Gas Resources

14 Illustrations of these structures are 

shown in figure 1.

 

14A tension leg platform structure supports a floating deck using vertical steel “tendons” or a chain 

and wire system anchored to the seafloor by pilings. A floating production system uses a 

floating, semisubmersible hull equipped with drilling and production equipment. It can be 

anchored in place with a chain and wire system or dynamically positioned using rotating 

thrusters. A spar platform supports a floating deck using a long, slender column that 

extends far below the ocean surface. Vertical steel tendons anchor the column to the 

seafloor (using pilings), and guy-wires extend out diagonally to seafloor anchors for 

horizontal stability.
Figure 1: Examples of Oil and Gas Structures in the Gulf of Mexico

Page 7 GAO-16-40 Offshore Oil and Gas Resources

Management of offshore oil and gas resources is primarily governed by 

the Outer Continental Shelf Lands Act, which sets forth procedures for 

leasing,15 exploration, and development and production of those

resources. The act calls for the preparation of an oil and gas leasing 

 

15For the purposes of this report, we use the term “lease” to include leases, grants of right of way, 

and right of use and easements. 

Offshore Leasing
program designed to meet the nation’s energy needs while also taking 

into account a range of principles and considerations specified by the act.

Specifically, the act provides 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.”

Page 8 GAO-16-40 Offshore Oil and Gas Resources

16

The Outer Continental Shelf Lands Act also requires the Secretary of the 

Interior to prepare a 5-year schedule of proposed lease sales, indicating 

the size, timing, and location of leasing activity as precisely as possible. 

Every 5 years, Interior selects the areas that it proposes to offer for 

leasing and establishes a schedule for individual lease sales. These 

leases may be offered for competitive bidding, and all eligible companies 

are invited to submit written sealed bids for the lease and rights to 

explore, develop, and produce oil and gas resources on these leases. 

These rights last for a set period of time, referred to as the initial period of 

the lease,17 and vary depending on the water depth.18

Historically, Interior’s Minerals Management Service managed offshore 

federal oil and gas activities and collected royalties for all producing 

leases. In May 2010, in an effort to separate major functions of offshore 

oil and gas management, Interior announced the reorganization of the 

Minerals Management Service into the Bureau of Ocean Energy 

Management, Regulation, and Enforcement, responsible for offshore oil 

and gas management, and the Office of Natural Resources Revenue, 

responsible for revenue collections. Subsequently, in October 2011, the 

 

1643 U.S.C. §1344(a)(1).

17If a discovery is made within the initial period of the lease, the lease is extended for as long 

as oil and/or natural gas is produced in paying quantities or approved drilling operations 

are conducted. The term of the lease may also be extended if a suspension of production 

or suspension of operations has been granted or directed.

18In the Gulf, in a notice of sale in 2012, BOEM offered leases with an initial term of 5 years 

extended to 8 years if drilling begins during the initial 5-year period targeting hydrocarbons 

below a depth of at least 25,000 feet subsea for leases in less than 400 meters of water. 

For leases in 400 to 800 meters of water, the initial term was 5 years extended to 8 years 

if drilling begins during the initial 5-year period. For leases in 800 to 1,600 meters of water, 

the initial period was 7 years extended to 10 years if drilling begins during the initial 7-year 

period. For leases in over 1,600 meters of water, the initial period was 10 years.
Bureau of Ocean Energy Management, Regulation, and Enforcement was 

separated into BOEM and BSEE. BOEM oversees resource management 

activities, including preparing the 5-year outer continental shelf oil and 

gas leasing program; reviews oil and gas exploration and development 

plans and environmental studies; and conducts National Environmental 

Policy Act analyses. BSEE oversees operations and environmental 

compliance, including reviewing drilling permits, inspecting offshore 

drilling rigs and production platforms, assessing civil penalties, developing 

regulations and standards for offshore drilling (including those related to 

decommissioning), and ensuring the conservation of natural resources.

The Outer Continental Shelf Lands Act authorizes the Secretary of the 

Interior to promulgate regulations necessary to administer the outer 

continental shelf leasing program, including regulations concerning 

financial assurance. Under this authority, Interior promulgated regulations 

and developed financial assurance procedures to protect the government 

from incurring costs if a lessee fails to meet its lease obligations, including 

its obligation to decommission offshore infrastructure. Under these 

regulations and procedures, BOEM regional directors may require a 

lessee to provide a bond —referred to as a “supplemental bond”—that 

covers the estimated costs of decommissioning for a lease.

Page 9 GAO-16-40 Offshore Oil and Gas Resources

19 BSEE is 

responsible for estimating costs associated with decommissioning liabilities. If a 

lessee is unable to accomplish decommissioning obligations as required, the 

federal government can use the bond to cover decommissioning costs.20

However, if BOEM determines that at least one lessee has sufficient 

 

19To satisfy the requirement to provide bonds, BOEM accepts surety bonds, U.S. Treasury notes, 

and other financial instruments if the government’s interests are protected. A surety bond is 

a third-party guarantee that a lessee purchases from a private insurance company or 

other entity approved by the Department of the Treasury (i.e., listed on Circular No. 570). 

The lessee must pay a premium to the surety company to maintain the bond. 

20In addition to a supplemental bond that may be required from a lessee, under BOEM 

regulations, every offshore oil and gas lease must be covered by a general bond that 

could be used to ensure a lessee complies with regulatory and lease requirements such 

as inspection fees, civil penalties, decommissioning, and rents and royalties. The general 

bond is not relied on to cover oil spill response, because those activities are covered by 

BOEM’s Oil Spill Financial Responsibility regulations (30 C.F.R. § 553) as well as the Oil 

Spill Liability Trust Fund. General bonds vary in amount, from $50,000 to $3 million, 

depending on the geographical area and phase of operation covered by the bond. As of 

June 10, 2015, lessees had provided 604 general bonds with a value of $517 million.

Financial Assurance 

Requirements
financial strength to accomplish decommissioning obligations on the 

lease, BOEM may waive the requirement for a supplemental bond.

Page 10 GAO-16-40 Offshore Oil and Gas Resources

21

Under BOEM and BSEE regulations, lessee liability is “joint and 

several”—that is, each lessee is liable for all decommissioning obligations 

that accrue on the lease during its ownership, including those that 

accrued prior to its ownership but had not been performed. In addition, a 

lessee that transfers its ownership rights to another party will continue to 

be liable for the decommissioning obligations it accrued. According to 

BOEM officials, BOEM ensures that all decommissioning obligations on 

offshore leases are required to be covered by either a supplemental bond 

or a current lessee that has the financial ability to conduct 

decommissioning.

According to Interior regulations, lessees must permanently plug all wells, 

remove all platforms and other structures, decommission all pipelines, 

and clear the seafloor of all obstructions created by the lease and pipeline 

operations when this infrastructure is no longer useful for operations.22

Lessees must also permanently plug wells and remove platforms within 1 year 

after a lease terminates. BSEE refers to infrastructure that is no longer 

useful for operations on active leases as idle infrastructure (or “idle iron”) 

and infrastructure on expired leases as terminated lease infrastructure. In 

general, BSEE’s guidance defines idle infrastructure as follows: 23

 

21Each lease may have numerous lessees that have various rights to the lease, including 

lessees that are record title holders and lessees that are operating rights holders. BOEM 

requires that all lessees agree to one designated operator, and the designated operator 

generally provides BOEM with the required bonding.

22According to BSEE, permanent well abandonment includes installing a surface plug and severing 

the casing at least 15 feet below the mudline, among other requirements. Temporary well 

abandonment includes all plugging and testing requirements imposed by BSEE to 

permanently abandon a well, except a surface plug is not required, and the lessee need 

not sever the casing, remove the wellhead, or clear the site. BSEE regulations also allow 

a lessee to either leave a pipeline in place after performing certain activities (e.g., cleaning 

it and flushing with seawater) or remove it from the seafloor. See 30 C.F.R. § 250.

23Department of the Interior, Notice to Lessees and Operators of Federal Oil and Gas 

Leases and Pipeline Right-of-way Holders in the Outer Continental Shelf, Gulf of Mexico 

OCS Region: Decommissioning Guidance for Wells and Platforms, NTL No. 2010-G05 

(Sept. 15, 2010). This guidance expired Oct. 14, 2013, but BSEE continues to use it.

Decommissioning 

Requirements
· A well is considered idle if it has not been used in the past 5 years for 

operations associated with exploration or development and production 

of oil or gas, and if the lessee has no plans for such operations.

· A platform is considered idle if it has been toppled or otherwise 

destroyed, or it has not been used in the past 5 years for operations 

associated with exploration or development and production of oil or 

gas.

Companies may postpone decommissioning idle wells and platforms to 

defer the cost of removal, increase the opportunity for resale, or reduce 

decommissioning costs through economies of scale and scheduling, 

among other reasons. However, postponing decommissioning can be 

costly because the longer a structure is present in the Gulf the greater the 

likelihood it will be damaged by a hurricane. According to Interior 

documentation, decommissioning a storm-damaged structure may cost 

15 times or more the cost of decommissioning an undamaged structure. 

In 2005, Hurricanes Katrina and Rita destroyed 116 structures and 

significantly damaged another 163 structures and 542 pipelines in the 

Gulf, according to Interior documentation. According to BSEE officials, as 

of April 2015, the Gulf contained 13 destroyed structures with 16 

associated wells.

Storm-damaged or toppled structures present a greater risk to safety and 

require difficult and time-consuming salvage work. After preliminary 

salvage work that can take weeks, divers cut and remove structural 

components while crane assemblies remove the components and place 

them on a barge for transport and disposal. Additionally, when working in 

areas with strong currents and unconsolidated material, coffer dams are 

often constructed on the seabed to prevent material from slumping back

in on the dive crews and equipment.

Figure 2 shows the annual number of wells drilled and plugged in the Gulf 

from 1947 through 2014. During this time period, lessees drilled a total of 

52,223 wells in the Gulf (including 18,447 exploratory wells and 33,776 

development wells) and plugged a total of 29,879 wells (including 4,017 

temporarily abandoned wells and 25,862 permanently abandoned wells).

Page 11 GAO-16-40 Offshore Oil and Gas Resources

Oil and Gas Infrastructure 

Installed and Removed in 

the Gulf
Figure 2: Annual Number of Wells Drilled and Plugged in the Gulf of Mexico, 1947-2014

Page 12 GAO-16-40 Offshore Oil and Gas Resources

Note: Wells drilled include exploratory and development wells. Wells plugged include temporary and 

permanent well abandonments.

Figure 3 shows the annual number of structures installed and removed in 

the Gulf from 1947 through 2014. During this time period, lessees 

installed a total of 7,038 structures in the Gulf. In addition, starting in the 

1970s, lessees began removing structures from the Gulf. Specifically, 

lessees removed a total of 4,611 structures from 1973 through 2014. 

Most of the structures installed and removed were fixed platforms and 

caissons installed in shallow water.
Figure 3: Annual Number of Structures Installed and Removed in the Gulf of Mexico, 1947-2014

Page 13 GAO-16-40 Offshore Oil and Gas Resources

Between the late 1940s and early 1960s, lessees only drilled wells in 

shallow water. However, starting in the mid-1960s, lessees began drilling 

wells in deep water. Figure 4 shows the annual number of wells drilled 

and plugged in deep water in the Gulf from 1966 through 2014. During 

this time period, lessees drilled a total of 6,468 wells (including 

exploratory and development wells) and plugged a total of 2,489 wells 

(including temporary and permanently abandoned wells) in deep water. 

Lessees also installed 112 structures—mostly fixed platforms, spar, 

tension leg platforms, and floating production systems—and removed 19 

structures in deep water during this time period.
Figure 4: Annual Number of Deepwater Wells Drilled and Plugged in the Gulf of Mexico, 1966-2014

Page 14 GAO-16-40 Offshore Oil and Gas Resources

Note: Wells drilled include exploratory and development wells drilled in greater than 400 feet of water. 

Wells plugged include temporary and permanent well abandonments in greater than 400 feet of 

water.

Since 1985, oil production from deepwater wells has increased 

significantly, as shown in figure 5. While the number of wells drilled has 

decreased in recent years, offshore production has increased as lessees 

have drilled wells in deep water that are more productive than wells in 

shallower water. In 2014, over 80 percent of Gulf oil production occurred 

in deep water, up from 6 percent in 1985.24 According to BSEE officials, 

activities in deep water, including drilling and decommissioning, are significantly 

more expensive than those in shallow water because of the technology 

required and challenges associated with deep water, such as very high 

pressures at significant water and well depths.

 

24For these data, Interior defined deep water as depths of greater than 1,000 feet. According to 

Interior’s data, gas production in deep water also increased dramatically over this period, 

from less than 1 percent of total Gulf production in 1985 to over 50 percent in 2014.
Figure 5: Oil Production in the Gulf of Mexico, 1985-2014

Page 15 GAO-16-40 Offshore Oil and Gas Resources

Interior’s BSEE has developed procedures to oversee the 

decommissioning of offshore oil and gas infrastructure and estimate costs 

associated with decommissioning liabilities, but limitations in its data 

system may affect the accuracy and completeness of some cost 

estimates. In addition, BSEE has not documented some of its procedures 

for identifying and tracking infrastructure that needs to be 

decommissioned and for estimating the related costs.

Interior Has 

Procedures to 

Oversee 

Decommissioning 

and Estimate Related 

Costs but Faces Data 

System Limitations 

and Has Not 

Documented Some 

Procedures
Officials in BSEE’s Gulf regional office have developed procedures for 

overseeing the activities of lessees in decommissioning oil and gas 

infrastructure in the Gulf and estimating the costs of doing so, but 

limitations in its data system for estimating costs may affect the accuracy 

and completeness of some cost estimates.

Page 16 GAO-16-40 Offshore Oil and Gas Resources

Under BSEE’s regulations, lessees must apply for approval before 

plugging wells, removing platforms and clearing sites, and 

decommissioning pipelines. According to BSEE regional officials, they 

review applications to ensure that they contain the required information 

(see table 1 below). Once this process is complete, BSEE officials 

approve a lessee’s application, which authorizes the lessee to begin 

decommissioning activities.

Table 1: Bureau of Safety and Environmental Enforcement (BSEE) Requirements for Decommissioning Applications for 

Offshore Oil and Gas Infrastructure

Type of application Description

Plugging wellsaLessees must provide the following information: (1) reason for plugging the well; (2) recent 

well test and pressure data; (3) maximum possible surface pressure; (4) type and weight of 

well-control fluid to be used; (5) description of work; (6) current and proposed well schematic 

and description; and (7) certification by a registered professional engineer of the well 

abandonment design and procedures, and that all plugs meet BSEE requirements.

Removing platforms or other facilities Lessees must provide the following information: (1) identification and description of the 

structure to be removed; 2) description of vessel(s) used to remove structure; (3) 

identification of purpose for removing structure; (4) description of removal method (e.g., 

explosives); (5) plans for transportation and disposal or salvage of removed platform; (6) if 

available, results of any recent biological surveys conducted in vicinity of structure; (7) and 

plans to protect archaeological and sensitive biological features during removal operations, 

among other things.

Decommissioning pipelines If decommissioning a pipeline in place, lessees must submit information on the proposed 

decommissioning procedures and the length of the segment to be decommissioned and left 

in place, among other things. If removing a pipeline, lessees must submit information on the 

proposed removal procedures and length of segment to be removed, among other things.

Source: GAO analysis of BSEE documentation. | GAO-16-40

a

BSEE has established requirements for an application to permanently plug a well and to temporarily 

abandon a well. This table reflects requirements for an application to permanently plug a well.

After lessees complete all planned decommissioning, they are required to 

report to BSEE on the outcome of these activities so that BSEE may 

verify that all their decommissioning obligations have been met, including 

clearing the seafloor around wells, platforms, and other facilities. 

BSEE Has Procedures to 

Oversee 

Decommissioning and 

Estimate Costs, but Data 

System Limitations May 

Affect the Accuracy and 

Completeness of Some 

Cost Estimates

Procedures for Overseeing 

Decommissioning
According to BSEE regional officials, they review lessee reports on 

decommissioning activities to ensure that the results are consistent with 

the information presented as part of the application process. Table 2 

summarizes BSEE’s reporting requirements related to the results of 

decommissioning activities.

Table 2: Bureau of Safety and Environmental Enforcement (BSEE) Requirements for Reporting on Decommissioning Results 

Page 17 GAO-16-40 Offshore Oil and Gas Resources

for Offshore Oil and Gas Infrastructure

Type of report Description

Plugging wells Lessees must submit a report within 30 days after plugging a well. This report must 

include the following information: (1) information included with request submitted before 

permanently plugging the well along with a final well schematic; (2) description of plugging 

work; (3) nature and quantities of material used in plugs; and (4) description of methods 

used for casing removal (including information on explosives, if used), among other 

things.

Removing platforms or other facilities Lessees must submit a report within 30 days after removing a platform or other facility. 

This report must include the following information: (1) summary of removal operations 

including completion date; (2) description of any mitigation measures taken; and (3) 

signed statement certifying that the types and amounts of explosives used in removing the 

platform were consistent with those set forth in the approved removal application.

Decommissioning pipelines Lessees must submit a report within 30 days after decommissioning a pipeline. This report 

must include the following information: (1) summary of the decommissioning operation 

including completion date; (2) description of any mitigation measures taken; and (3) 

signed statement certifying that the pipeline was decommissioned according to the 

approved application. 

Clearing sites around wells, platforms, 

and other facilities

Lessees must verify that a site is clear of obstructions within 60 days of plugging a well or 

removing a platform or other facility. Lessees then must submit a report within 30 days 

after verifying site clearance to certify to BSEE that all site clearance activities are 

completed. For wells, this report must include the following information: (1) signed 

certification that the well site area is cleared of all obstructions; (2) date the verification 

work was performed and the vessel used; (3) extent of the area surveyed; (4) survey 

method used; and (5) results of the survey, among other things. For platforms and other 

facilities, this report must include the following information: (1) letter (signed by the lessee) 

certifying that the platform or area is cleared of all obstructions and that a company 

representative witnessed the activities; (2) letter (signed by contractor) certifying that it 

cleared the platform or area of all obstructions; (3) date that work was performed and 

vessel used; (4) extent of area surveyed; (5) survey method used; and (6) survey results, 

among other things.

Source: GAO analysis of BSEE documentation. | GAO-16-40

According to BSEE regional officials, during the process of reviewing 

lessee reports, BSEE may issue a notice of an “incident of 

noncompliance” in cases where lessees have not provided all of the 

required information or when lessee activities are not consistent with 

BSEE regulations. If BSEE officials determine that the violation is not 

severe or threatening, they will issue a “warning” notice that requires the 

lessee to correct the violation within a specified period of time. If BSEE 
officials determine that the violation is more serious, they will issue a 

“shut-in” notice that requires the lessee to correct the violation before 

resuming activities. In addition, BSEE officials can assess a civil penalty 

of up to $40,000 per violation per day if the lessee fails to correct the 

violation in the period of time specified in the notice, or if the violation 

resulted in a threat of serious harm to human life or damage to the 

environment.

In addition to reviewing lessee applications and reports, the BSEE Gulf 

region identifies and tracks idle and terminated lease infrastructure. 

According to BSEE regional officials, the BSEE Gulf region began 

identifying and tracking idle lease infrastructure in 2010 and currently 

updates a list of this infrastructure on an annual basis. BSEE began 

identifying and tracking terminated lease infrastructure prior to 2010, 

according to BSEE regional officials. At the beginning of each calendar 

year, BSEE regional officials obtain data from Interior’s main data 

system—the Technical Information Management System (TIMS)—on 

wells and structures on leases that meet the criteria for idle and 

terminated lease infrastructure.

Page 18 GAO-16-40 Offshore Oil and Gas Resources

25 Based on these data, BSEE sends a list of 

idle and terminated lease infrastructure to each lessee, requesting a 

decommissioning plan and schedule for decommissioning the lessee’s 

inventory. According to BSEE regional officials, BSEE works with lessees 

to verify the accuracy of their inventory of idle and terminated lease 

infrastructure, and BSEE tracks lessees’ progress in meeting their 

schedules.26

According to BSEE regional officials, BSEE estimates the costs 

associated with decommissioning liabilities by counting the number and 

types of wells, pipeline segments, and structures on a lease and using 

 

25According to the Federal IT Dashboard, TIMS is a computerized information system that 

automates many of the business and regulatory functions of BSEE and BOEM. TIMS 

enables staff of the regional and headquarters offices of both BSEE and BOEM to share 

and combine data; create and print maps; standardize processes, forms, and reports; and 

promote the electronic submission of data.

26According to BSEE data, lessees have made progress in decommissioning idle 

infrastructure in the Gulf. Specifically, in 2010, there were 3,233 idle wells and 617 idle

platforms in the Gulf and, as of June 15, 2015, there were 1,082 idle wells and 245 idle 

platforms in the Gulf.

Procedures for Estimating 

Costs
data on the water depth associated with this infrastructure.

Page 19 GAO-16-40 Offshore Oil and Gas Resources

27 Using these 

data, BSEE then calculates the costs associated with (1) plugging and abandoning 

wells, (2) removing platforms and other structures, (3) decommissioning 

pipelines, and (4) clearing debris from the site.

In general, the cost to plug wells and remove structures increases as the 

water depth increases. For example, according to BSEE’s current 

methodology, its estimate of the cost to plug a dry tree well attached to a 

fixed structure in shallow water is $150,000, while its estimate of the cost 

to plug a subsea well in deep water is a minimum of about $21 million. 

Likewise, BSEE’s estimates of the costs to remove fixed platforms in 

shallow water range from approximately $85,000 to $4.6 million, while its 

estimate of the cost to remove a floating structure (and associated 

equipment) in deep water is a minimum of $30 million.

According to BSEE regional officials, a number of events can trigger 

BSEE’s review of the costs associated with decommissioning liabilities on 

a lease. Examples of these events include the following:

· BSEE determines that a lessee is planning a potential sale or 

acquisition of leases.

· BOEM or BSEE detect indications of financial stress for a lessee.

· BOEM requests a review of a pending request for lease assignment 

and bond cancellations.

· A lessee requests a review from BSEE when some but not all 

infrastructure is decommissioned on a lease.

BSEE enters and stores its cost estimates of decommissioning liabilities 

in TIMS. However, according to BSEE regional officials, TIMS is limited in 

its ability to accurately and completely record cost estimates of 

decommissioning liabilities, as follows:

· TIMS contains three data fields to record cost estimates for each 

offshore lease—one for estimates of the cost of removing existing 

structures, one for estimates of the cost of plugging existing wells, and 

one for estimates of the cost of clearing debris from sites. TIMS uses 

algorithms developed in the 1990s to calculate cost estimates for 

 

27The BSEE Gulf regional office established a Decommissioning Support Section in 

December 2013 to estimate costs associated with decommissioning liabilities in the Gulf. 

Prior to that date, BSEE officials in other sections within the Gulf regional office were 

assigned the responsibilities associated with estimating these costs.
each of these data fields. However, BSEE officials said that the cost 

estimates are too low compared to BSEE’s current estimates. For 

example, TIMS calculates the cost to plug a well is $100,000, 

regardless of water depth or the type of well, while BSEE estimates 

the cost to plug a subsea well in deep water is approximately $21 

million.

· TIMS does not contain separate data fields for recording the 

estimated cost to plug a planned well (as opposed to an existing well) 

or to decommission pipelines. BSEE officials said that both of these 

costs are important to consider and to estimate a lessee’s potential 

decommissioning liability.

Because of these limitations, BSEE regional officials said that, in 2009, 

they began investing more time and resources into manually updating 

cost estimates of decommissioning liabilities in TIMS. Currently, BSEE 

officials use separate spreadsheets—containing updated methodologies 

for estimating costs in shallow and deep water—to estimate costs to 

decommission leases. They then manually enter the cost estimates into 

TIMS using separate data fields entitled “adjusted decommissioning 

liability” for each type of cost estimate; for example, plugging wells, 

removing structures, and site clearance. In addition, they add estimated 

costs for (1) plugging planned wells into the “adjusted decommissioning 

liability” data field for existing wells and (2) decommissioning pipelines 

into the “adjusted decommissioning liability” data field for site clearance. 

Once they enter these data, TIMS automatically populates the date of that 

entry into an “updated” data field.

According to BSEE regional officials, they have manually entered updated 

cost estimates for most leases in the Gulf. Specifically, as of July 8, 2015, 

BSEE officials said that they had entered updated cost estimates for 

3,460 (86 percent) of the 4,021 leases in the Gulf with decommissioning 

liabilities. BSEE officials characterized their efforts to update cost 

estimates as an “ongoing process” and said that their activities related to 

cost estimating have increased dramatically over the past decade. 

Officials said that while there was no set time frame by which they plan to 

update cost estimates for all the leases in the Gulf, the number of leases 

changes over time, and BSEE prioritizes its efforts on those leases that 

BOEM and BSEE determine pose higher financial risk.

BSEE regional officials told us that Interior is transitioning to a new data 

system (the National Consolidated Information System) to manage 

offshore oil and gas activities and that BSEE plans to use the new data 

system to improve how decommissioning liabilities are calculated and 

Page 20 GAO-16-40 Offshore Oil and Gas Resources
recorded. However, officials were unable to provide details on how the 

new data system will address the existing data limitations in TIMS or 

when they expect to implement these improvements in the new data 

system. Internal control standards in the federal government call for 

agencies to ensure that all transactions and events are completely and 

accurately recorded.

Page 21 GAO-16-40 Offshore Oil and Gas Resources

28 Without the ability to completely and accurately 

record data on decommissioning costs, some of BSEE’s estimates of 

decommissioning liabilities may not be complete or accurate, and BOEM 

may not have reasonable assurance that it is requiring sufficient amounts 

of financial assurance based on BSEE’s estimates.

BSEE officials in the Gulf regional office told us BSEE does not have 

documented procedures for identifying and tracking idle and terminated 

lease infrastructure or finalized documented procedures for estimating 

costs associated with decommissioning liabilities. Specifically, BSEE 

regional officials told us the bureau did not have documentation, such as 

standard operating procedures or operating manuals that described their 

process for identifying and tracking infrastructure. BSEE regional officials 

provided draft documentation outlining their approach to estimating costs 

associated with plugging wells, removing structures, and 

decommissioning pipelines; however, they told us that these documents 

had not been finalized and were a “work in progress.” According to these 

officials, these documents replace an older policy manual and were 

developed in 2014 after BSEE established the Decommissioning Support 

Section within the Gulf regional office.29

In addition, BSEE’s draft documents outlining its approach to estimating 

the costs of decommissioning liabilities do not address how BSEE 

regional officials plan to periodically assess the methodology for 

estimating costs, as recommended by an internal Interior review. 

Specifically, in fiscal year 2009, Interior conducted an internal review of its 

procedures related to its financial accountability and risk management 

program. In an internal report,30 Interior stated that program officials 

 

28GAO/AIMD-00-21.3.1.

29Department of the Interior, Minerals Management Service, Policy Manual Part 640.1 - Financial 

Accountability and Risk Management (FARM) Program (Washington, D.C.: July 22, 2008).

30Department of the Interior, Minerals Management Service, Offshore Energy and Minerals 

Management, Supplemental Bonding Process, Fiscal Year 2009 Internal Control Review

[publication date not listed].

BSEE Does Not Have 

Finalized, Documented 

Procedures for Identifying 

and Tracking Infrastructure 

That Needs to Be 

Decommissioned or for 

Estimating Costs
estimated costs using data that had not been updated in over 14 years. 

The report recommended that the program develop and implement a 

formal policy to review and revise all assessments at least once every 5 

years for all regions.

Page 22 GAO-16-40 Offshore Oil and Gas Resources

31 It also recommended that program officials consider 

adjusting assessments to reflect the cost of inflation during the period between 

the 5-year updates. To date, BSEE regional officials have not developed and 

implemented formal procedures addressing these recommendations.

Internal control standards in the federal government call for agencies to 

clearly document internal controls, and the documentation should appear 

in management directives, administrative policies, or operating manuals.32

According to BSEE regional officials, they plan to establish documented 

procedures to identify and track idle and terminated lease infrastructure 

and estimate costs, but have not done so due to competing priorities, 

among other reasons. Without finalized, documented procedures, BSEE 

does not have reasonable assurance that it will consistently conduct such 

activities in the future, which could limit the effectiveness of Interior’s 

oversight of the decommissioning process and its ability to obtain 

sufficient financial assurances to cover decommissioning liability.

Interior’s procedures for obtaining financial assurances for offshore 

decommissioning liabilities pose financial risks to the federal government. 

Officials from Interior’s BOEM told us that the bureau plans to revise its 

procedures that determine how much financial assurance a lessee must 

provide, and that they expect these procedures to reduce the risk that the 

government could incur costs associated with decommissioning.

 

31In keeping with this recommendation, BSEE’s Pacific regional office customarily prepares a 

decommissioning cost report every 5 years to determine estimated decommissioning costs 

for its region and to support decisions regarding bonding requirements.

32GAO/AIMD-00-21.3.1.

Interior’s Procedures 

for Obtaining 

Financial Assurances 

for Decommissioning 

Liabilities Pose Risks 

to the Federal 

Government, and 

Interior Plans to 

Revise Them
BOEM’s procedures for obtaining financial assurances for offshore 

decommissioning liabilities pose financial risks to the federal government 

in three ways. First, as of October 2015, according to BOEM officials, 

BOEM had identified approximately $2.3 billion in decommissioning 

liabilities in the Gulf that may not be covered by financial assurances but 

was unable to determine in a timely manner the extent to which these 

liabilities were valid. Specifically, after identifying data on potentially 

uncovered decommissioning liabilities in TIMS, BOEM officials analyzed 

these data over several months to determine their validity. That is, BOEM 

officials tried to determine the extent to which these liabilities were 

accurate and the extent to which valid liabilities were covered by financial 

assurances. BOEM officials told us that, based on their analyses, some of 

the $2.3 billion in decommissioning liabilities may be valid and uncovered 

by financial assurances.

Page 23 GAO-16-40 Offshore Oil and Gas Resources

33

However, according to BOEM officials, they were unable to quantify how 

much of the $2.3 billion in decommissioning liabilities were valid and 

uncovered by financial assurances due to limitations with the TIMS data 

system and inaccurate data, among other things. For example, BOEM 

officials stated that existing reports generated by the TIMS data system 

did not provide all the necessary information for determining the validity of 

data on decommissioning liabilities and financial assurances. As a result, 

officials said that they had to create new reports to access additional data 

stored in TIMS, and that these efforts were time consuming. In addition, 

BOEM officials said that they identified leases that did not have wells or 

platforms but for which TIMS contained estimates of decommissioning 

liabilities. BOEM officials said that data associated with these 

decommissioning liabilities may not be valid but that they would need to 

consult with BSEE officials to determine their validity, which would take 

additional time.

BOEM officials stated that, in order to determine the validity of the data in 

TIMS, they plan to consult with BSEE officials and continue to analyze 

relevant data. Once they have determined the validity of the data, they 

said that they will take steps to obtain financial assurances for any 

 

33For example, according to BOEM officials, BSEE recently began updating its estimates of 

decommissioning liabilities associated with pipelines in the TIMS data system. As a result, 

BOEM officials said that data associated with these decommissioning liabilities may be 

valid.

BOEM’s Procedures for 

Obtaining Financial 

Assurances for 

Decommissioning 

Liabilities Pose Risks to 

the Federal Government
uncovered decommissioning liabilities. However, officials were unable to 

provide details on how or when they planned to address existing 

limitations with the TIMS data system or determine the accuracy of data 

on decommissioning liabilities. Internal control standards in the federal 

government call for agencies to ensure that pertinent information is 

identified, captured, and distributed in a form and time frame that permits 

people to perform their duties efficiently.

Page 24 GAO-16-40 Offshore Oil and Gas Resources

34 Without timely access to valid 

data on decommissioning liabilities in the Gulf and associated financial 

assurances, BOEM does not have reasonable assurance that it has sufficient 

financial assurances in place, putting the federal government at risk.

Second, under BOEM’s procedures, less than 8 percent of estimated 

decommissioning liabilities in the Gulf are covered by financial assurance 

mechanisms such as bonds. Specifically, as of October 2015, according 

to BOEM officials, for an estimated $38.2 billion in decommissioning 

liabilities in the Gulf, BOEM held or required about $2.9 billion in bonds

and other financial assurances.35 For $33.0 billion in decommissioning 

liabilities, BOEM waived 47 lessees from the requirement to provide 

supplemental bonds based on BOEM’s reviews of the lessees’ financial 

strength, according to BOEM officials.36, 37

Under BOEM’s current financial assurance procedures,38 each offshore 

lease with a decommissioning liability must be covered by a supplemental 

 

34GAO/AIMD-00-21.3.1.

35As of October 2015, BOEM held about $1.8 billion in bonds (including supplemental and 

general bonds) and about $500 million in trust agreements. In addition, BOEM had issued 

letters requiring lessees to provide about $600 million in financial assurances.

36For the purposes of ensuring that there is at least one responsible party with the 

financial ability to fulfill lease decommissioning obligations, BOEM attributes all lease 

decommissioning liabilities to any waived lessee on a lease (even if other responsible 

parties are present on the lease). The waived lessee is, with all other lessees, jointly and 

severally liable for decommissioning and relies on its financial strength to secure the costs 

of this decommissioning, on behalf of all the jointly and severally liable parties. 

37Under Interior regulations, regional directors may determine that a supplemental bond is 

necessary to ensure compliance with a lessee’s obligations. According to Interior officials, 

supplemental bonding becomes a requirement once the regional director determines that it is 

necessary.

38Department of the Interior, Minerals Management Service, Notice to Lessees and Operators of 

Federal Oil, Gas, and Sulfur Leases and Pipeline Right-of-way Holders in the Outer Continental 

Shelf: Supplemental Bond Procedures, NTL No. 2008-N07 (Aug. 28, 2008).
bond unless BOEM determines that a lessee has the financial ability to 

fulfill its decommissioning obligations. BOEM staff evaluate the financial 

ability of a lessee to fulfill its decommissioning obligations by means of a 

financial strength test. BOEM’s financial strength test requires a lessee to 

meet the following criteria:

· provide an independently audited financial statement indicating a net 

worth greater than $65 million;

· possess a total decommissioning liability (as determined by BSEE) of 

less than or equal to 50 percent of its audited net worth;

· possess total company liabilities of no more than 2 to 3 times the 

value of the adjusted net worth;

Page 25 GAO-16-40 Offshore Oil and Gas Resources

39, 40 and

· demonstrate reliability, as shown by a record of compliance with laws, 

regulations and lease terms, among other factors.

If a lessee passes the financial strength test by demonstrating its financial 

ability to pay for decommissioning on its leases, BOEM waives its 

requirement for the lessee to provide supplemental bonds. Other 

responsible parties on the lease will also be waived from the requirement 

to provide supplemental bonds.41 According to BOEM officials, BOEM 

waives these parties as well because the waived lessee could be held responsible 

if another party on a lease does not fulfill its decommissioning obligations. 

In addition, a waived lessee may provide financial assurance in the form 

 

39Adjusted net worth includes a percentage of a lessee’s proven oil and gas reserves added to a 

lessee’s audited net worth. BOEM varies the total liability ratio it will accept based on adjusted net 

worth—for example, a lessee with between $65 million and $100 million in adjusted net 

worth can possess total lessee liabilities of no more than 2 or 2.5 times its adjusted net 

worth, depending on the size of the company’s potential decommissioning liability.

40Alternatively, BOEM allows a lessee to use a substitute criterion—the lessee must 

demonstrate that it produces in excess of an average of 20,000 barrels of oil equivalent 

per day on its leases. However, according to BOEM officials, of the 51 waived lessees 

only 1 or 2 chose to use this alternative criterion.

41In addition to bonds required by BOEM, some lessees that transfer leases or rights may require 

the party acquiring the lease to provide a surety bond. This bond protects the transferring party 

from paying decommissioning costs it may be liable for if the purchasing party is unable to 

fulfill its decommissioning obligations. According to BOEM officials, these bonds are 

generally not reported to BOEM, and BOEM does not consider them as financial 

assurance because BOEM is not a beneficiary of such bonds. 
of a corporate guarantee of the lease obligations of a lessee on another 

lease.

Page 26 GAO-16-40 Offshore Oil and Gas Resources

42

After BOEM waives a lessee from the requirement to provide 

supplemental bonding, it monitors the financial strength of the lessee to 

ensure it continues to pass BOEM’s financial strength test. BOEM 

conducts quarterly financial reviews for the first 2 years after a lessee 

receives a waiver and then an annual review thereafter.43 In addition, on a 

weekly basis, BOEM compares the decommissioning obligations (as 

determined by BSEE) of all waived lessees with the financial information 

provided by lessee audited financial statements.44 If BOEM finds that a 

lessee no longer passes its financial strength test, BOEM will conduct a 

more in-depth review of a lessee’s financial status by reviewing financial 

statements, credit ratings, and other financial information. BOEM may 

also conduct an unscheduled financial review if: (1) BSEE revises its 

estimate of a lessee’s decommissioning liability, (2) a lessee’s financial 

status changes as reported by credit rating agencies, or (3) a lessee does 

not pay the required royalties to the federal government. According to 

BOEM officials, these reviews could cause BOEM to revoke a lessee’s 

waiver from the requirement to provide supplemental bonding. For 

example, in May 2015, BOEM revoked the waiver of one lessee and, 

according to BOEM officials, the waived lessee and related parties could 

be required to provide as much as $1 billion in supplemental bonds.45

Our prior reports have found that the use of financial strength tests and 

corporate guarantees in lieu of bonds poses financial risks to the federal 

government. Specifically, we found, in August 2005, that the financial 

assurance mechanisms that impose the lowest costs on the companies 

using them— such as financial strength tests and corporate guarantees—

 

42According to BOEM officials, nearly all corporate guarantees are between parent companies and 

subsidiaries.

43These reviews evaluate the same criteria that BOEM officials used during the initial financial 

strength test.

44As part of these reviews, BOEM determines whether the waived lessee has the ability to pay for 

all decommissioning costs on leases where the lessee is an owner.

45In cases where BOEM revokes a lessee’s waiver from the requirement to provide 

supplemental bonding, the lessee or other responsible parties on a lease or recipients of 

corporate guarantees would be required to provide supplemental bonds to cover 

decommissioning obligations that are no longer covered by a waiver or guarantee. 
also typically pose the highest financial risks to the government entity 

accepting them.

Page 27 GAO-16-40 Offshore Oil and Gas Resources

46 In that report, we found that, if a company passes a financial 

strength test but subsequently files for bankruptcy or becomes insolvent, the 

company in essence is no longer providing financial assurance because it 

may no longer have the financial capacity to meet its obligations. Such 

financial deterioration can occur quickly. While companies no longer 

meeting the financial test are to obtain other financial assurance, they 

may not be able to obtain or afford to purchase it. In addition, in May 

2012, we found that, according to the Bureau of Land Management and 

the Environmental Protection Agency, corporate guarantees are 

potentially risky because they are not covered by a specific financial asset 

such as a bond.47 BOEM’s use of the financial strength test and corporate 

guarantees in lieu of bonds raises the risk that the federal government 

may have to pay for offshore decommissioning if lessees do not.

The third way BOEM’s procedures pose financial risks to the federal 

government is that BOEM’s financial strength test relies on measures that 

may not provide an accurate indication of a lessee’s ability to pay for 

decommissioning. As described above, BOEM uses net worth (from a 

lessee’s audited financial statements) as a key measure in its financial 

strength test. However, according to representatives from credit rating 

agencies we spoke to, net worth provides limited value to assess a 

company’s financial strength and ability to pay future liabilities. 

Specifically, these representatives said that net worth is “backward 

looking” and can be skewed by the volatile nature of commodity prices, 

among other factors. Credit rating agencies use financial measures that 

emphasize the evaluation of cash flow, such as debt-to-earnings and 

debt-to-funds from operations to evaluate whether a company will be able 

to pay its liabilities. Without the use of similar measures in its financial 

assessments, BOEM may not have reasonable assurance that the 

lessees it waives from the requirement to provide supplemental bonds 

have the financial abilities to fulfill decommissioning obligations, which 

may increase the financial risk to the government.

 

46GAO, Environmental Liabilities: EPA Should Do More to Ensure That Liable Parties 

Meet Their Cleanup Obligations, GAO-05-658 (Washington, D.C.: Aug. 17, 2005).

47GAO, Phosphate Mining: Oversight Has Strengthened, but Financial Assurances and 

Coordination Still Need Improvement, GAO-12-505 (Washington, D.C.: May 4, 2012).
According to BOEM officials, BOEM recognizes the financial risks 

associated with its current financial assurance procedures and plans to 

revise its procedures to reduce risk. Specifically, BOEM officials told us 

that BOEM’s planned revisions would eliminate the use of financial 

strength tests to completely waive lessees from the requirement to 

provide supplemental bonding. Instead, BOEM plans to conduct financial 

reviews of lessees’ financial status and, based on those reviews, assign 

lessees an amount of credit that may be used to reduce required bonding 

associated with decommissioning liabilities on leases. Lessees would be 

able to apportion this credit to leases, in coordination with other 

responsible parties on those leases, to ensure that lease 

decommissioning liabilities are fully covered by apportioned credit or 

supplemental bonds. As part of BOEM’s financial review of lessees, these 

officials told us that BOEM plans to use criteria that emphasize the use of 

measures such as cash flow and company liquidity while deemphasizing 

the use of net worth. In addition to these planned revisions, in August 

2014, BOEM announced its intent to update its regulations and program 

oversight for offshore financial assurance requirements.

Page 28 GAO-16-40 Offshore Oil and Gas Resources

48 BOEM solicited 

stakeholder comments in response to this proposal and has held industry forums 

to discuss potential changes to its financial assurance regulations and 

procedures.

According to BOEM officials, if BOEM were to use these criteria as part of 

its financial strength test, some of the lessees currently waived from the 

requirement to provide supplemental bonds could lose their waivers. 

BOEM officials also stated that, if the revised procedures are 

implemented as planned, lessees could be required to provide several 

billion dollars in additional supplemental bonds. BOEM officials told us 

they plan to update the bureau’s financial assurance procedures in late 

2015 or early 2016. In commenting on a draft of this report, Interior 

officials stated that on September 22, 2015, BOEM issued proposed 

guidance to clarify its financial assurance procedures. However, it is too 

soon to evaluate the specific details of BOEM’s proposed changes to its 

financial assurance procedures because BOEM has not issued any final 

revisions to its procedures. Until BOEM revises and implements new 

procedures, the federal government remains at greater risk of incurring 

 

4879 Fed. Reg. 49027 (Aug. 19, 2014). According to BOEM officials, BOEM expects to 

promulgate these new regulations in 2017.

BOEM Plans to Revise Its 

Procedures to Reduce 

Financial Risks
costs should lessees fail to decommission offshore oil and gas 

infrastructure as required.

Interior faces two key challenges managing potential decommissioning 

liabilities. First, BSEE does not have access to all relevant data from 

lessees on costs associated with decommissioning activities in the Gulf. 

Second, BOEM’s requirements for reporting the transfers of lease rights 

may impair its ability to manage decommissioning liabilities.

Page 29 GAO-16-40 Offshore Oil and Gas Resources

BSEE does not have access to all relevant current data on costs 

associated with decommissioning activities in the Gulf. Internal control 

standards in the federal government call for agencies to obtain 

information from external stakeholders that may significantly affect their 

abilities to achieve agency goals.49 Obtaining accurate and complete 

information on the decommissioning costs is critical to Interior being able to 

achieve its goals. Specifically, BSEE needs accurate and complete 

information on decommissioning costs to estimate decommissioning 

liabilities in the Gulf, and BOEM relies on BSEE’s estimates to ensure 

that it is requiring sufficient amounts of financial assurance to cover 

decommissioning liabilities. 

However, BSEE generally has not had access to current data on 

decommissioning costs. Prior to December 2015, under BSEE’s 

regulations, lessees were not required to report costs associated with 

decommissioning activities to BSEE. According to BSEE regional officials, 

data on decommissioning costs were considered proprietary, and 

companies generally did not share this information with BSEE. Instead, 

BSEE regional officials relied on other sources of data—some of which 

are decades old and, as a result, likely inaccurate—to estimate costs 

associated with decommissioning liabilities. According to BSEE regional 

officials, their estimates for decommissioning liabilities in shallow water 

 

49GAO/AIMD-00-21.3.1.

Interior Faces Two 

Key Challenges 

Managing Potential 

Decommissioning 

Liabilities

BSEE Does Not Have 

Access to All Relevant

Data on Decommissioning 

Costs
were based on data provided by the oil and gas industry in 1995.

Page 30 GAO-16-40 Offshore Oil and Gas Resources

50 For 

decommissioning liabilities in water depths of 400 to 1,400 feet, their 

estimates were based on information in a 2009 report that Interior 

contracted.51 For decommissioning liabilities for subsea wells, BSEE 

officials said that they had developed their own models for estimating 

costs based on an analysis of a variety of factors, such as the daily cost 

of hiring a vessel in the Gulf to plug wells.

During the course of our audit, BSEE regional officials told us that they 

planned to improve this process and the resulting data by issuing a 

regulation requiring such data to be submitted. Specifically, Interior issued 

a proposed rule in May 2009 to establish new requirements for lessees to 

submit expense information on costs associated with plugging and 

abandonment, platform removal, and site clearance.52 In December 2015, 

BSEE issued a final rule establishing these requirements.

53 However, according 

to BSEE regional officials, the rule does not require lessees to submit 

expense information on costs associated with decommissioning pipelines, 

and officials were unable to provide details as to when or whether BSEE 

would issue a new rule to require the reporting of such costs. Unless and 

until BSEE obtains all relevant cost data, BSEE may continue to use 

outdated information to assess decommissioning liabilities. Without 

access to accurate and complete information on decommissioning costs, 

BSEE may not have reasonable assurance that its estimates of 

decommissioning liabilities in the Gulf are accurate, and BOEM may not 

have reasonable assurance that it is requiring sufficient amounts of 

financial assurance based on BSEE’s estimates.

 

50BSEE officials told us that they are preparing to request proposals to fund a new study to 

evaluate the costs associated with structure removal in shallow water in the Gulf and have 

proposed studies to evaluate costs associated with pipeline decommissioning and well 

plugging in shallow water.

51Proserv Offshore, Gulf of Mexico Deep Water Decommissioning Study: Final Report, 

prepared for Interior’s Minerals Management Service (Houston, Tex: October 2009).

5274 Fed. Reg. 25177 (May 27, 2009).

5380 Fed. Reg. 75806 (Dec. 4, 2015) (effective Jan. 4, 2016).
The absence of a clear deadline for reporting transfers of rights to lease 

production revenue may impair BOEM’s ability to manage 

decommissioning liabilities. Under BOEM’s financial assurance 

procedures, BOEM must obtain accurate information on a lessee’s 

financial status to determine whether the lessee has sufficient financial 

strength to meet its decommissioning obligations, and BOEM may waive 

its requirement for the lessee to provide supplemental bonds based on 

this information. However, the transfer of rights to a lease may affect a 

lessee’s financial status. For example, lessees may transfer lease 

ownership and the right to operate on a lease, which also obligates the 

new owner to decommission infrastructure on the lease. Under Interior 

regulations, these transfers must be approved by BOEM.

Page 31 GAO-16-40 Offshore Oil and Gas Resources

54

Lessees can also transfer rights to lease production revenue.

55 Transfers 

of these revenue rights generally allow the receiving party to obtain a portion of 

the revenue from oil and gas production over a period of time and the 

lessee, in turn, is paid in advance of production. The more revenue rights 

a lessee transfers to other parties, the less revenue the lessee has to 

cover its other obligations, including decommissioning. However, unlike 

transfers of lease ownership and operating rights, transfers of revenue 

rights do not obligate the new owner to decommission, and lessees are 

not required to obtain BOEM’s approval for these transfers. BOEM 

requires lessees to report these transfers, but its regulations do not 

establish a clear deadline for the reporting.56 As a result, BOEM is not 

always aware of such transfers in a timely manner.

For example, in one recent case, a waived lessee that had previously 

transferred most of its revenue rights to other parties subsequently 

declared bankruptcy. BOEM was unaware of these transfers until 

bankruptcy court proceedings. Had BOEM been aware of these transfers 

during its weekly review of the waived lessee, it could have revoked the 

lessee’s waiver if it determined the lessee no longer passed the financial 

 

5430 C.F.R. § 556.64(a).

55For the purposes of this report, we use the term “revenue rights” in place of “overriding 

royalty interests” and “payments out of production.”

56The regulations at 30 C.F.R. § 556.64 establish a 90-day deadline for the reporting of transfers of 

interest but do not define the term "interest." In discussions with BOEM officials in the Gulf 

regional office, BOEM officials did not interpret these regulations as imposing a reporting 

deadline for transfers of lease production revenue.

Absence of a Clear 

Reporting Deadline for 

Transfers of Revenue 

Rights May Impair 

BOEM’s Ability to Manage 

Decommissioning 

Liabilities
strength test. Consequently, BOEM then could have required the lessee

or its co-lessees to provide supplemental bonds to cover its 

decommissioning obligations. In this case, the transfer of revenue rights 

left the lessee with insufficient assets to pay all of its liabilities during 

bankruptcy, including decommissioning. Though other lessees were held 

liable for decommissioning costs under joint and several liability, the 

government was at increased risk of incurring costs if the other lessees 

had been unwilling or unable to perform decommissioning. 

BOEM officials told us that they created an internal group to help improve 

BOEM’s knowledge of revenue rights transfers and the effect of transfers 

on a lessee’s financial status. In commenting on a draft of this report, 

BOEM officials stated that they believe that current regulations could be 

interpreted as imposing a reporting deadline but recognize the need to 

clarify the regulations. Without a clear reporting deadline, lessees have 

little incentive to report revenue rights transfers to BOEM in a timely 

manner, and this could limit BOEM’s ability to effectively evaluate a 

lessee’s financial strength.

Decommissioning offshore oil and gas infrastructure is expensive and 

poses potential financial liabilities to the federal government. BSEE 

officials in the Gulf region have developed procedures for reviewing idle 

and terminated lease infrastructure to ensure that this infrastructure is 

decommissioned. In addition, in December 2015, BSEE issued final 

regulations (proposed in 2009) requiring lessees to report 

decommissioning costs directly to BSEE. However, several problems 

remain. First, BSEE’s recent regulations do not require lessees to report 

costs associated with decommissioning pipelines. Unless and until BSEE 

obtains all relevant cost data, it may continue to use outdated data to 

assess decommissioning liabilities. Second, limitations of Interior’s 

current data system restrict BSEE’s ability to record estimates of 

decommissioning costs, and it is unclear how BSEE’s new data system 

will address these limitations or when it will be available. Without access 

to complete data on decommissioning costs, and without the ability to 

accurately and completely record data in Interior’s main data system, 

BSEE does not have reasonable assurance that its estimates of 

decommissioning liabilities in the Gulf are accurate, and BOEM may not 

have reasonable assurance that it is requiring sufficient amounts of 

financial assurance based on BSEE’s estimates. Third, BSEE does not 

have finalized, documented procedures for identifying and tracking idle 

and terminated lease infrastructure and estimating decommissioning 

liabilities. Without such documented procedures, BSEE does not have 

Page 32 GAO-16-40 Offshore Oil and Gas Resources

Conclusions
reasonable assurance that it will consistently conduct such activities in 

the future, which could limit the effectiveness of BSEE’s oversight of the 

decommissioning process.

Moreover, while BOEM is taking important steps to ensure that the 

financial assurance procedures used by the federal government are 

reducing the government’s exposure to decommissioning costs by 

updating its procedures to assess the financial strength of lessees, we 

continue to have three concerns. First, BOEM identified roughly $2.3 

billion in decommissioning liabilities in the Gulf that may not be covered 

by financial assurances but was unable to determine the extent to which 

these liabilities were valid after several months of analysis due to 

limitations with the TIMS data system and inaccurate data. As a result, it 

is unclear whether BOEM has obtained sufficient financial assurances to 

cover decommissioning liabilities in the Gulf. Without timely access to 

valid data on decommissioning liabilities and associated financial 

assurances, BOEM cannot ensure that it has sufficient financial 

assurances in place, putting the federal government at financial risk. 

Second, to date BOEM has not taken concrete steps to revise its current 

procedures. As a result, it is unclear whether BOEM’s planned revisions 

will improve its procedures and the extent to which these revisions will 

increase the amount of bonding that lessees provide. Until BOEM revises 

its financial assurance procedures, the federal government remains at 

increased risk of incurring costs should lessees fail to decommission oil 

and gas infrastructure. Third, BOEM is not always aware when lessees 

transfer rights to lease production revenue. While BOEM’s current 

regulations require lessees to report such transfers, these regulations do 

not clearly establish a deadline for reporting. Without a clear reporting 

deadline, lessees have little incentive to report revenue rights transfers to 

BOEM in a timely manner, and this could limit BOEM’s ability to 

effectively evaluate a lessee’s financial strength.

To improve the effectiveness of Interior’s oversight of the 

decommissioning process, we recommend that the Secretary of the 

Interior direct BSEE to establish documented procedures for identifying 

and tracking idle and terminated lease infrastructure.

To better ensure that the government obtains sufficient financial 

assurances to cover decommissioning liabilities in the event of lessee 

default, we recommend that the Secretary of the Interior take the 

following six actions:

Page 33 GAO-16-40 Offshore Oil and Gas Resources

Recommendations for 

Executive Action
· Ensure that BSEE collects all relevant data associated with 

decommissioning from lessees.

· Direct BSEE to establish documented procedures for estimating 

decommissioning liability.

· Develop a plan and set a time frame to ensure that Interior’s data 

system for managing offshore oil and gas activities includes 

processes to accurately and completely record estimated 

decommissioning liabilities.

· Develop a plan and set a time frame to ensure that Interior’s data 

system for managing offshore oil and gas activities will be able to 

identify, capture, and distribute data on decommissioning liabilities 

and financial assurances in a timely manner.

· Ensure that BOEM completes its plan to revise its financial assurance 

procedures, including the use of alternative measures of financial 

strength.

· Revise BOEM’s regulations to establish a clear deadline for the 

reporting of transfers to require that lessees report the transfer of 

rights to lease production revenue.

We provided a draft of this report to Interior for review and comment.

Interior provided written comments, which are reproduced in appendix I, 

and generally agreed with our findings and concurred with our 

recommendations.

As agreed with your offices, unless you publicly announce the contents of 

this report earlier, we plan no further distribution until 30 days from the 

report date. At that time, we will send copies of this report to the 

appropriate congressional committees, the Secretary of the Interior, and 

other interested parties. In addition, this report will be available at no 

charge on the GAO website at http://www.gao.gov.

If you or your staff members have any questions about this report, please 

contact me at (202) 512-3841 or ruscof@gao.gov. Contact points for our 

Offices of Congressional Relations and Public Affairs may be found on 

the last page of this report. GAO staff members who made major 

contributions to this report are listed in appendix II.

Page 34 GAO-16-40 Offshore Oil and Gas Resources

Agency Comments 

and Our Evaluation
Frank Rusco

Director, Natural Resources and Environment

Page 35 GAO-16-40 Offshore Oil and Gas Resources
Appendix I: Comments from the Department of 

the Interior

Page 36 GAO-16-40 Offshore Oil and Gas Resources

Appendix I: Comments from the Department

of the Interior
Appendix I: Comments from the Department of 

the Interior

Page 37 GAO-16-40 Offshore Oil and Gas Resources
Page 38 GAO-16-40 Offshore Oil and Gas Resources

Frank Rusco, (202) 512-3841 or ruscof@gao.gov

In addition to the individual named above, Christine Kehr (Assistant 

Director), Jason Holliday, and David Messman made key contributions to 

this report. Also contributing to this report were Philip Farah, Cindy 

Gilbert, Paul Kinney, Risto Laboski, Alison O’Neill, and Barbara 

Timmerman.

Appendix II: GAO Contact and Staff 

Acknowledgments

GAO Contact

Staff 

Acknowledgments
Page 39 GAO-16-40 Offshore Oil and Gas Resources

Data Table for Figure 2: Annual Number of Wells Drilled and Plugged in the Gulf of Mexico, 

1947-2014

Year Wells drilled Wells plugged

"1947" 5 3

"1948" 19 3

"1949" 32 8

"1950" 34 9

"1951" 4 2

"1952" 20 3

"1953" 22 4

"1954" 82 22

"1955" 172 41

"1956" 255 73

"1957" 399 103

"1958" 280 62

"1959" 331 73

"1960" 429 98

"1961" 498 91

"1962" 551 162

"1963" 615 175

"1964" 745 190

"1965" 840 200

"1966" 927 329

"1967" 947 327

"1968" 1034 290

"1969" 905 283

"1970" 937 319

"1971" 883 398

"1972" 906 342

"1973" 888 356

"1974" 862 420

"1975" 898 392

"1976" 1157 388

"1977" 1326 362

"1978" 1259 393

"1979" 1287 352

"1980" 1309 351

"1981" 1352 383

Appendix III: Accessible Data

(361609)

Data Tables
Page 40 GAO-16-40 Offshore Oil and Gas Resources

Year Wells drilled Wells plugged

"1982" 1339 349

"1983" 1247 556

"1984" 1470 546

"1985" 1315 548

"1986" 774 445

"1987" 939 350

"1988" 1078 645

"1989" 1049 580

"1990" 1148 646

"1991" 826 665

"1992" 605 471

"1993" 998 549

"1994" 1115 509

"1995" 1167 428

"1996" 1253 610

"1997" 1461 748

"1998" 1145 460

"1999" 1038 536

"2000" 1379 661

"2001" 1262 613

"2002" 943 521

"2003" 895 681

"2004" 916 645

"2005" 813 516

"2006" 772 564

"2007" 617 930

"2008" 567 834

"2009" 321 1137

"2010" 254 1243

"2011" 266 1277

"2012" 358 1218

"2013" 353 1231

"2014" 330 1160
Page 41 GAO-16-40 Offshore Oil and Gas Resources

Data Table for Figure 3: Annual Number of Structures Installed and Removed in the Gulf of 

Mexico, 1947-2014

Year Installed Removed

"1947" 2

"1948" 4

"1949" 9

"1950" 7

"1951" 4

"1952" 6

"1953" 8

"1954" 22

"1955" 29

"1956" 42

"1957" 51

"1958" 83

"1959" 85

"1960" 111

"1961" 108

"1962" 128

"1963" 91

"1964" 129

"1965" 131

"1966" 117

"1967" 133

"1968" 113

"1969" 117

"1970" 118

"1971" 101

"1972" 145

"1973" 97 1

"1974" 59 5

"1975" 103 36

"1976" 116 29

"1977" 114 17

"1978" 168 26

"1979" 176 35

"1980" 173 36

"1981" 167 24
Page 42 GAO-16-40 Offshore Oil and Gas Resources

Year Installed Removed

"1982" 196 15

"1983" 174 38

"1984" 225 53

"1985" 214 55

"1986" 113 34

"1987" 117 23

"1988" 165 100

"1989" 197 93

"1990" 176 108

"1991" 153 117

"1992" 92 105

"1993" 122 172

"1994" 174 125

"1995" 132 118

"1996" 154 120

"1997" 145 178

"1998" 143 76

"1999" 110 145

"2000" 150 143

"2001" 159 109

"2002" 98 122

"2003" 118 169

"2004" 125 194

"2005" 115 123

"2006" 120 116

"2007" 88 159

"2008" 79 153

"2009" 32 232

"2010" 30 218

"2011" 17 293

"2012" 11 285

"2013" 16 222

"2014" 11 189
Page 43 GAO-16-40 Offshore Oil and Gas Resources

Data Table for Figure 4: Annual Number of Deepwater Wells Drilled and Plugged in the Gulf 

of Mexico, 1966-2014

Year Wells drilled Wells plugged

"1966" 1 1

"1967" 0 0

"1968" 4 1

"1969" 6 3

"1970" 3 3

"1971" 0 1

"1972" 6 4

"1973" 12 11

"1974" 25 19

"1975" 41 24

"1976" 48 42

"1977" 30 27

"1978" 18 9

"1979" 62 24

"1980" 86 15

"1981" 78 22

"1982" 71 22

"1983" 82 30

"1984" 163 65

"1985" 213 89

"1986" 155 67

"1987" 158 38

"1988" 235 83

"1989" 219 53

"1990" 211 71

"1991" 158 57

"1992" 97 15

"1993" 104 23

"1994" 138 34

"1995" 146 29

"1996" 215 37

"1997" 270 80

"1998" 258 67

"1999" 239 68

"2000" 298 76
Page 44 GAO-16-40 Offshore Oil and Gas Resources

Year Wells drilled Wells plugged

"2001" 346 88

"2002" 285 56

"2003" 242 74

"2004" 235 90

"2005" 190 70

"2006" 224 54

"2007" 203 71

"2008" 176 93

"2009" 157 108

"2010" 70 101

"2011" 81 98

"2012" 143 139

"2013" 131 115

"2014" 135 122

Data Table for Figure 5: Oil Production in the Gulf of Mexico, 1985-2014

Year Deepwater Production Shallow Water Production

"1985" 21.0538 329.291

"1986" 19.0771 336.465

"1987" 17.0709 310.497

"1988" 12.9846 288.222

"1989" 10.0076 270.71

"1990" 12.142 262.446

"1991" 22.8868 271.887

"1992" 37.2951 267.57

"1993" 36.7699 271.826

"1994" 41.8032 272.293

"1995" 55.2009 289.874

"1996" 72.2131 296.656

"1997" 108.515 303.108

"1998" 159.233 285.054

"1999" 225.09 270.082

"2000" 271.144 251.886

"2001" 315.392 243.397

"2002" 348.566 219.312
Page 45 GAO-16-40 Offshore Oil and Gas Resources

Year Deepwater Production Shallow Water Production

"2003" 350.149 211.272

"2004" 347.954 187.402

"2005" 325.578 141.347

"2006" 341.294 130.723

"2007" 328.133 139.875

"2008" 312.732 110.688

"2009" 457.549 112.753

"2010" 460.647 105.979

"2011" 378.423 103.276

"2012" 367.757 97.2466

"2013" 361.588 97.2551

"2014" 415.872 94.1071

United States Department of the Interior

OFFICE OF THE SECRETARY

Washington, DC 20240

NOV 30 2015

Mr. Frank Rusco 

Director

Natural Resources and Environment 

Government Accountability Office 441 G Street, NW

Washington, DC 20548

Agency Comment 

Letters

Text of Appendix I: 

Comments from the 

Department of the Interior

Page 1
Page 46 GAO-16-40 Offshore Oil and Gas Resources

Dear Mr. Rusco:

Thank you for the oppo1tunity to review and comment on the Government 

Accountability Office (GAO) draft report entitled, Offshore Oil and Gas 

Resources -Actions Needed to Better Protect Against Billions of Dollars in 

Federal Exposure to Decommissioning Liabilities (GA0-16-40). Thank you 

also for incorporating the technical edits we recommended in our letter 

dated October 13, 2015.

The Department of the Interior (Department) generally agrees with the 

findings and concurs with the recommendations directed to the Bureau of 

Ocean Energy Management (BOEM) and the Bureau of Safety and 

Environmental Enforcement (BSEE). The Department is implementing 

GAO's recommendations to document procedures, improve its data 

system, and revise financial assurance procedures and regulations.

BOEM is updating its financial assurance requirements for Outer 

Continental Shelf (OCS) leases and facilities to mitigate risks associated 

with decommissioning liability. BOEM's goal is to ensure the taxpayer 

never has to pay to decommission an OCS facility. Updating the financial 

assurance policies will better reflect current business practices and the

increased cost of decommissioning OCS facilities.

On September 22, 2015, BOEM issued proposed guidance to clarify 

procedures for oil and gas companies operating on the OCS. Specifically, 

the guidance contains updated financial criteria for determining a lessee's 

ability to meet its financial obligations, including decommissioning 

liabilities, in whole or part, and the potential need for additional security. 

BOEM will no longer consider the combined financial strength and 

reliability of co-lessees or operating rights holders when determining a 

lessee's ability to carry out its obligations with respect to 

decommissioning.

BOEM intends to update its data system and create comprehensive 

procedures designed to decrease risks to taxpayers while providing 

industry flexibility to negotiate adaptive solutions and utilize tailored 

financial plans to meet financial assurance needs. Next year, BOEM 

expects to publish a Notice to Lessees and Operators, which will clarify 

the process BOEM will use to develop tailored plans and financial 

assurance requirements.

In the draft rep01i, GAO states that BOEM regulations do not include a 

deadline by which filings of transfer of revenue interests must be 

submitted to BOEM. BOEM believes that its regulation found at 30 CFR 
Page 47 GAO-16-40 Offshore Oil and Gas Resources

section 556.64(a)(2) requiring submittal of the creation or transfer of an 

interest

within 90 days of the last date that a party executes the transfer 

agreement could be interpreted to impose such a deadline. Nonetheless, 

BOEM is working to finalize a leasing rule that will clarify the deadline.

In recent years, BSEE has made considerable progress in improving its 

capabilities with regard to estimating decommissioning costs for OCS 

facilities in the Gulf of Mexico. Over the past few years, BSEE has 

updated cost data, revised estimation methodologies, begun 

consolidating decommissioning-related activities into a single program 

office, worked to develop new regulations, and generated thousands of 

updated decommissioning cost estimates for offshore wells and 

structures, which greatly reduced BSEE's backlog of leases requiring an 

updated estimate.

Despite these improvements, BSEE acknowledges that more needs to be 

done. BSEE intends to continue to focus on systematizing the process of 

updating decommissioning estimates and finalizing policy and procedures 

related to estimating decommissioning costs and overseeing idle 

infrastructure. BSEE's upcoming rule, Oil and Gas and Sulphur 

Operations in the Outer Continental Shelf-Decommissioning Costs, will 

require the submission of summary decommissioning expenditures from 

operators, greatly improving the bureau's ability to ensure that estimates 

reflect actual decommissioning costs. BSEE recently received approval 

from the Office of Management and Budget, and anticipates publishing 

the rule in the Federal Register soon.

Once the final rule is effective, BSEE will begin collecting expenditure 

data on decommissioning activities as early as 120 days after the 

effective date. As data are collected, BSEE will review and analyze the 

submissions to revise current cost data and estimation techniques, and 

develop algorithms that will automatically generate more reliable 

decommissioning cost estimates for wells and structures on leases. Until 

that time, BSEE will continue to use existing estimation techniques, where 

cost estimates must be built for each lease. Additionally, BSEE will seek 

available opportunities to refine cost data. BSEE is currently working 

toward procuring contracted services to improve data quality related to 

costs associated with decommissioning fixed structures in under 400 feet 

of water. BSEE plans to undertake additional research on 

decommissioning costs in the current fiscal year.

Page 2
Page 48 GAO-16-40 Offshore Oil and Gas Resources

Enclosed are a few additional general and technical comments for your 

consideration when finalizing the report. If you have any questions about 

this response, please contact Andrea Nygren, BOEM Audit Liaison 

Officer, at 202-208-4343, or Linh Luu, BSEE Audit Liaison Officer, at 202-

208-4120.

Sincerely,

Janice M. Schneider

Assistant Secretary

Land and Minerals Management 

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