Alaska's North Slope
Requirements for Restoring Lands After Oil Production Ceases Gao ID: GAO-02-357 June 5, 2002This report discusses the nature and extent of dismantlement, removal, and restoration requirements for oil industry activities that are occurring on both federal and state lands located on the North Slope of the state of Alaska. The state of Alaska, which owns the lands where most of the North Slope's current oil production occurs, has adopted general dismantlement, removal, and restoration requirements that contain no specific stipulations on what infrastructure must be removed or to what condition the lands used for oil industry activities must be restored once production ceases. Alaska's requirements are similar to those of some states but less explicit than those of other states, which create a fixed obligation to fully restore the land according to specific requirements. Until the state of Alaska defines the condition in which it would like its lands returned, there is no way to accurately estimate the cost of dismantling and removing the infrastructure and restoring the disturbed land on Alaska's North Slope. Existing financial assurances, such as bonding requirements, ensure the availability of only a small portion of the funds that are likely to be needed to dismantle and remove the infrastructure used for oil industry activities and to restore state-owned lands. Current dismantlement, removal, and restoration requirements and financial assurances for federal lands on the North Slope vary by agency, but are generally insufficient to ensure that any federal lands disturbed by oil industry activities will be restored.
RecommendationsOur recommendations from this work are listed below with a Contact for more information. Status will change from "In process" to "Open," "Closed - implemented," or "Closed - not implemented" based on our follow up work.
Director: Team: Phone:GAO-02-357, Alaska's North Slope: Requirements for Restoring Lands After Oil Production Ceases
This is the accessible text file for GAO report number GAO-02-357
entitled 'Alaska‘s North Slope: Requirements for Restoring Lands After
Oil Production Ceases' which was released on June 5, 2002.
This text file was formatted by the U.S. General Accounting Office
(GAO) to be accessible to users with visual impairments, as part of a
longer term project to improve GAO products' accessibility. Every
attempt has been made to maintain the structural and data integrity of
the original printed product. Accessibility features, such as text
descriptions of tables, consecutively numbered footnotes placed at the
end of the file, and the text of agency comment letters, are provided
but may not exactly duplicate the presentation or format of the printed
version. The portable document format (PDF) file is an exact electronic
replica of the printed version. We welcome your feedback. Please E-mail
your comments regarding the contents or accessibility features of this
document to Webmaster@gao.gov.
This is a work of the U.S. government and is not subject to copyright
protection in the United States. It may be reproduced and distributed
in its entirety without further permission from GAO. Because this work
may contain copyrighted images or other material, permission from the
copyright holder may be necessary if you wish to reproduce this
material separately.
United States General Accounting Office:
GAO:
Report to Congressional Requesters:
June 2002:
Alaska‘s North Slope:
Requirements for Restoring Lands After Oil Production Ceases:
GAO-02-357:
Contents:
Transmittal Letter:
Executive Summary:
Purpose:
Background:
Results in Brief:
Principal Findings:
Recommendations for Executive Action:
Matter for Congressional Consideration:
Agency Comments and GAO‘s Evaluation:
Chapter 1, Introduction:
Alaska‘s North Slope Is a Sensitive Environment:
Oil Industry Activity Occurs Primarily on State-Owned Lands:
Many Entities Benefit from Revenues Generated by Oil Production on the
North Slope:
Dwindling Production Focuses Greater Attention on the Disposition of
Oil Company Infrastructure on the North Slope:
Dismantlement and Removal of Infrastructure and the Restoration of Land
Involves Many Agencies at Multiple Levels of Government:
Objectives, Scope, and Methodology:
Chapter 2, Current DR&R Requirements for Existing Oil Production Are
Very General:
The State of Alaska Determines DR&R Requirements for Existing Oil
Production:
Parties Disagree on Whether State Requirements Should Be More Specific:
Alaska‘s DR&R Requirements Are Similar to Some States‘, but Less
Explicit Than Others‘:
Chapter 3, Actual Cost of DR&R Is Unknown, but Likely to Cost Billions
of Dollars:
Costs Depend on What DR&R Will Be Required, Which is Uncertain:
Oil Company Disclosures Provide Some Indication that DR&R Costs Will
Likely Be in the Billions of Dollars:
Chapter 4, Financial Assurances That Funds Will Be Available for
Projected DR&R Costs Are Limited:
Previously Abandoned Sites on State Land Had Insufficient Financial
Assurances:
Alaska‘s Statewide Bonding Requirements for DR&R Cover Only a Small
Portion of the Potential Liability:
The Corps of Engineers, Local Government, and Alaska Native
Corporations Have Not Required Financial Assurances for DR&R
Activities:
Major Oil Companies Operating on the North Slope Do Not Believe Full
Financial Assurances Are Necessary:
Alaska‘s Bond Amounts Exceed Those of Most of the Other Oil-Producing
States We Reviewed:
Chapter 5, Specific DR&R Requirements and Improved Financial Assurances
Should Be Considered for North Slope Federal Lands:
As Oil Production on State Lands Declines, Development of Federal Lands
Is Being Pursued:
DR&R Requirements for Federal Lands on the North Slope Vary:
Assurances That Funds Will Be Available to Implement Federal DR&R
Requirements Are Limited:
Previously Abandoned Oil Exploration Sites on Federal Lands Remain a
Problem:
DR&R Requirements and Financial Assurances for TAPS and the Mining and
Nuclear Power Industries Are Explicit:
Conclusions:
Recommendations for Executive Action:
Matter for Congressional Consideration:
Agency Comments and Our Evaluation:
Appendixes:
Appendix I: Comparison of Alaska‘s DR&R Requirements and Financial
Assurances with Those of Other Oil-Producing States:
Appendix II: Comments from the Department of the Interior:
Appendix III: Comments from the State of Alaska:
GAO‘s Comments:
Appendix IV: GAO Contacts and Staff Acknowledgments:
GAO Contacts:
Acknowledgments:
Tables:
Table 1: GAO‘s Estimate of North Slope Infrastructure, as of January
2000:
Table 2: North Slope Oil Units, Production, Operator, and Ownership:
Table 3: Number and Status of North Slope Oil Well and Drill Sites, as
of March 28, 2002:
Table 4: State Oil and Gas Well Permitting Surface Restoration
Provisions:
Table 5: State Oil and Gas Lease Surface Restoration Provisions on
State-Owned Lands:
Table 6: State Oil and Gas Well Permitting Financial Assurance
Provisions for Well-plugging and Abandonment:
Table 7: State Oil and Gas Lease Financial Assurance Provisions that
Cover Well-plugging and Abandonment on State-Owned Lands:
Figures:
Figure 1: Map of North Slope Land Ownership:
Figure 2: Prudhoe Bay Oil Production and Support Facilities:
Figure 3: Map of Alaska and the North Slope:
Figure 4: Aerial Photo of Area Surrounding Alpine Oil Field:
Figure 5: Development of North Slope Oil Producing Area in 1999:
Figure 6: Alaska North Slope Oil Production History and Projections:
Figure 7: Alaska Oil and Gas Conservation Commission‘s Location
Clearance Requirements:
Figure 8: Series of Well Sites on Prudhoe Bay Unit and Kuparuk Unit
Well Pads:
Figure 9: Alaska Department of Natural Resources Past and Recent Rights
upon Lease Termination Provisions:
Figure 10: Endicott Production Islands:
[End of section]
United States General Accounting Office:
Washington, D.C. 20548:
June 5, 2002:
The Honorable Richard A. Gephardt:
Minority Leader:
House of Representatives:
The Honorable Nick J. Rahall:
Ranking Minority Member:
Committee on Resources:
House of Representatives:
The Honorable Edward J. Markey:
House of Representatives:
In response to your request, this report discusses the nature and
extent of dismantlement, removal, and restoration requirements for oil
industry activities that are occurring on both federal and state lands
located on the North Slope of the state of Alaska. We include
recommendations to the Secretary of the Interior aimed at ensuring that
such lands managed by the Bureau of Land Management are properly
restored after oil and gas activities cease.
As arranged with your offices, unless you publicly announce its
contents earlier, we plan no further distribution of this report until
30 days after the date of this letter. At that time, we will send
copies to the Secretary of the Interior and to the heads of the Bureau
of Land Management, the Minerals Management Service, and the Fish and
Wildlife Service. We will also send copies to the governor of the state
of Alaska. We will make copies available to others on request.
Please contact me at (202) 512-3841 if you or your staffs have any
questions. Major contributors to this report are listed in appendix IV.
Signed by:
Barry T. Hill:
Director, Natural Resources and Environment:
[End of section]
Executive Summary:
Purpose:
Alaska‘s arctic coastal plain, also referred to as the ’North Slope,“
is a harsh yet sensitive environment that has been a center of
controversy for the United States‘ energy and environmental policy
throughout the past four decades. Since the opening of the 800-mile-
long Trans-Alaska Pipeline in 1977, more than 13 billion barrels of oil
have flowed from thousands of oil wells on the North Slope to
international and domestic markets. During this period, North Slope oil
has contributed about 20 percent of the United States‘ annual domestic
production.
The process of finding and producing oil on the North Slope has required
the build-up of a considerable infrastructure, including thousands of
well sites; hundreds of miles of pipelines, roads, and airstrips; and
numerous oil production facilities and living facilities. Most of this
infrastructure is located on lands owned by the state of Alaska.
However, oil companies and the state are now seeking additional sources
of oil on adjoining federal lands to compensate for declining oil
production on state lands. Eventually, even with additional oil
production from federal lands, production on the North Slope will
decline to the point that operating the Trans-Alaska Pipeline will no
longer be profitable. After that, the oil industry‘s considerable
infrastructure, estimated to be as much as $53 billion, will no longer
be needed. Concerned about whether this infrastructure will be removed
from the North Slope and to what condition the land will be restored
when oil production activities cease, the House Minority Leader, the
Ranking Minority Member of the House Resources Committee, and
Representative Edward Markey asked us to determine:
* the nature and extent of dismantlement, removal, and restoration
requirements for existing oil industry activities on state-owned land on
Alaska‘s North Slope, including how these requirements compare to those
of other oil-producing states;
* whether any cost estimates exist for the dismantlement and removal of
the infrastructure and for the restoration of North Slope state-owned
land;
* what financial assurances the state of Alaska has that funds will be
available to cover the eventual dismantlement, removal, and restoration
costs and how these assurances compare to those of other oil-producing
states; and;
* the nature and extent of dismantlement, removal, and restoration
requirements and financial assurances governing future oil industry
activities on federal lands located on the North Slope and how these
compare with requirements and financial assurances in other related
industries, such as mining and nuclear power.
Background:
Alaska‘s North Slope covers about 89,000 square miles of federal,
state, and native land holdings stretching from the Brooks Range north
to the Arctic Ocean”an area larger than the state of Utah (see figure
1). Currently, most oil production on the North Slope takes place on
state lands in the general vicinity of Prudhoe Bay, which, in 1968, was
the site of the largest oil field ever discovered in North America.
Recently, remote offshore oil production also began in the waters of
the Arctic Ocean north of Prudhoe Bay. The state and the federal
government are jointly responsible for regulating this oil production.
Figure 1: Map of North Slope Land Ownership:
[Refer to PDF for image]
Notes: The areas designated in the map as the National Petroleum
Reserve-Alaska and the Arctic National Wildlife Refuge contain some
Alaska Native lands. Similarly, the area titled ’Mostly State Lands“
also contains some Alaska Native lands. Finally, the area on the far
left portion of the map labeled ’Mostly Native Lands“ also includes
some state and federal lands. The Trans-Alaska Pipeline System (TAPS)
extends from Prudhoe Bay to Valdez, Alaska.
Source: GAO‘s adaptation of a Bureau of Land Management map.
[End of figure]
Active oil exploration is also underway in the federally owned National
Petroleum Reserve-Alaska, a 23-million-acre tract located west of
Prudhoe Bay. The Bureau of Land Management manages the National
Petroleum Reserve-Alaska for both oil resources and natural values. The
Congress has not determined whether to open portions of the federally
owned Arctic National Wildlife Refuge, east of Prudhoe Bay, to oil and
gas development activities. The refuge, which is managed by the U.S.
Fish and Wildlife Service, was created in 1960 and expanded in 1980 to
its present size of 19 million acres”of these, about 8 million acres
have been designated as wilderness. A 1.5-million-acre coastal section
of the refuge was set aside in 1980 for study of its fish and wildlife
resources as well as for possible oil and gas development, but the
Congress would need to specifically authorize oil and gas development
activity.
Oil industry activities in the Arctic require special environmental
considerations because of the extremely cold temperatures and the
sensitive nature of the surface tundra. The peat layer of the tundra,
which is no more than 3 feet thick, consists of soils, plant life, and
ponds. It rests upon permafrost, which may extend down 2,000 feet and
creates an impermeable layer of frozen earth immediately below the thin
active surface layer. Because moisture can‘t penetrate the permafrost,
almost the entire North Slope is a wetland consisting of ponds and
vegetation during the summer that are frozen and snow-covered during
the remainder of the year. According to the Fish and Wildlife Service,
tundra, which supports a wide variety of plants and animals, can be
damaged easily if disturbed and may require decades to recover fully.
Federal, state, and local governments share responsibility for
regulating oil industry activities on the North Slope. The state of
Alaska, which owns the land where most current oil industry activity
occurs, has primary responsibility for establishing requirements for
how these lands will be restored when oil industry activity ceases.
Specifically, two groups are responsible for developing dismantlement,
removal, and restoration requirements: Alaska‘s Department of Natural
Resources, which manages state oil and gas leases, and Alaska‘s Oil and
Gas Conservation Commission, which issues permits for drilling wells on
state, federal, and Alaska Native lands.[Footnote 1] The Alaska
Department of Environmental Conservation and the Alaska Department of
Fish and Game provide additional regulatory guidance. The North Slope
Borough, the area‘s local government, can regulate oil industry
activities on state, native, and municipal lands, including
dismantlement, removal, and restoration requirements, through zoning
ordinances. In addition, local Alaska Native regional and village
corporations control a considerable amount of surface lands and
subsurface mineral rights on the North Slope and can establish
environmental and reclamation requirements through contractual
arrangements made with the oil companies. Finally, the U.S. Army Corps
of Engineers, which issues permits for certain aspects of development on
wetlands and navigable waters regardless of land ownership, also has the
authority to require, through its permit process, the restoration of
the land. Oil industry activities on federal lands located on the North
Slope are primarily regulated by federal land management agencies.
These agencies include the Department of the Interior‘s Bureau of Land
Management, which manages the National Petroleum Reserve-Alaska, and
Interior‘s Mineral Management Service, which oversees oil industry
activities that occur in waters 3 or more miles off the coast. Three
other federal agencies”Interior‘s Fish and Wildlife Service, the
Department of Commerce‘s National Marine Fisheries Service, and the
Environmental Protection Agency”have regulatory authority that may
apply to resources affected by oil industry activities on federal,
state, or private land.
The oil industry and many public landowners use the term ’dismantlement,
removal, and restoration,“ or DR&R, to refer to the dismantlement and
removal of infrastructure and the restoration of the land following the
completion of extraction activities. DR&R can take many forms, from
complete restoration (a natural state approaching original condition) to
some form of enhanced rehabilitation (e.g., providing habitat that
previously did not exist) to simply removing some structures. Oil
exploration, which involves seismic mapping and test wells to measure
potential reserves, requires relatively little permanent infrastructure
and less surface disturbance than production activities. Recently,
exploration on the North Slope has been conducted in the winter using
ice roads and ice drilling pads that melt away after they are used,
although they may still compress the tundra. After oil is found,
production activities involve the development of an extensive
infrastructure. Such infrastructure can include wells to extract the
oil and re-inject byproducts and wastes into subsurface formations;
pipelines and transmission lines for water, gas, oil, fuel, and
electricity; industrial plants to separate the oil from water; housing
and other structures for workers and support services; roads, ports,
and airstrips to access and support the facilities; and the acres of
gravel upon which most of this infrastructure is built (see figure 2).
The costs of constructing this infrastructure and the performance of
any industrial work on the North Slope, including dismantlement,
removal, and restoration activities, exceed similar costs in the rest
of the U.S. because of the North Slope‘s remote location and harsh
climate.
Figure 2: Prudhoe Bay Oil Production and Support Facilities:
[Refer to PDF for image]
This figure is an illustration of the Prudhoe Bay Oil Production and
Support Facilities.
Note: This figure is intended to provide a general depiction of the
production process associated with the Prudhoe Bay complex. Not all
facilities or infrastructure associated with the complex are
illustrated.
Source: GAO‘s adaptation of figures prepared by Phillips Petroleum and
the Alaska Department of Natural Resources.
[End of figure]
Results in Brief:
The state of Alaska, which owns the lands where most of the North
Slope‘s current oil production occurs, has adopted general
dismantlement, removal, and restoration requirements that contain no
specific stipulations on what infrastructure must be removed or to what
condition the lands used for oil industry activities must be restored
once production ceases. Alaska‘s requirements specify that the oil
companies have to return the land to a condition that is satisfactory
to the state”a condition that it has yet to define. The removal of the
infrastructure and restoration of the land is generally not required on
a full scale until most oil and gas production ceases. Other entities,
such as the Corps of Engineers, native landowners, and the local North
Slope Borough, have the authority to impose dismantlement, removal, and
restoration requirements; generally, however, they have not done so.
The Corps prefers the landowner, in this case the state, to retain
primary responsibility for developing dismantlement, removal, and
restoration requirements. Alaska Native landowners and the North Slope
Borough stated that they would generally defer to the state to impose
such requirements. Dismantlement, removal, and restoration requirements
in other oil producing states vary. Alaska‘s requirements are similar
to those of some states but less explicit than those of other states,
which create a fixed obligation to fully restore the land according to
specific requirements.
Until the state of Alaska defines the condition in which it would like
its lands returned, there is no way to accurately estimate the cost of
dismantling and removing the infrastructure and restoring the disturbed
land on Alaska‘s North Slope. Thus far, oil companies are the only
entities to have estimated future dismantlement, removal, and
restoration costs. To comply with generally accepted accounting
principles, oil companies have estimated their future liability based
on several assumptions, including what infrastructure will be removed;
to what condition land will be restored when dismantlement, removal,
and restoration requirements are implemented; and other variables.
However, oil companies stated that without specific state requirements,
these estimates are hypothetical. The companies‘ estimates are also
considered proprietary and are therefore not publicly available.
However, limited information obtained from oil company annual reports,
a tax court case, and other sources indicate that the dismantlement,
removal, and restoration liability for existing oil industry activities
on the North Slope will be in the billions of dollars.
Existing financial assurances, such as bonding requirements, ensure the
availability of only a small portion of the funds that are likely to be
needed to dismantle and remove the infrastructure used for oil industry
activities and to restore state-owned lands. The state of Alaska
requires oil companies to post bonds or other forms of financial
assurance as a condition for obtaining a lease and drilling permits.
Such financial assurances total only about $200,000 for each oil
company‘s statewide drilling operations and $500,000 to cover all of a
company‘s oil and gas leases in the state. These amounts represent a
small fraction of the funds that may be needed for dismantlement,
removal, and restoration of state lands on the North Slope should a
company refuse to or be unable to pay. The local municipality, Alaska
Native landowners, and the Corps of Engineers all have the authority to
impose financial assurance conditions on oil industry activities on the
North Slope, but none has ever done so, preferring to defer this
authority to the state. In the past, when early North Slope oil
exploration and development activities were improperly abandoned, the
state had to assume financial responsibility for the dismantlement,
removal, and restoration of these sites. The oil companies still
operating on the North Slope are assisting the state in cleaning up and
restoring these sites. Although the state has not developed any
estimates of the total cost of this effort, such costs could be
substantial. For example, as part of an agreement between the state and
various oil companies, BP and Phillips Petroleum are spending about $10
million to clean up and restore 14 abandoned North Slope sites.
[Footnote 2] Even though the state of Alaska‘s bonding requirements
ensure only a small portion of the potential cost of cleaning up the
North Slope, when compared to nine other major oil-producing states,
Alaska‘s bonding requirements are generally higher.
Current dismantlement, removal, and restoration requirements and
financial assurances for federal lands on the North Slope vary by
agency, but are generally insufficient to ensure that any federal lands
disturbed by oil industry activities will be restored. As oil
production on state lands declines, oil companies and the state of
Alaska are looking to develop federal lands in order to sustain North
Slope production levels. The Bureau of Land Management, which oversees
the National Petroleum Reserve-Alaska, has an overall restoration goal
of returning the reserve to its previous use, which includes fish and
wildlife habitat, after oil production ceases. However, the Bureau has
yet to develop specific dismantlement, removal, and restoration
requirements for companies to use to meet that goal. On the other hand,
Interior‘s Minerals Management Service has specific dismantlement,
removal, and restoration requirements for offshore drilling in
federally regulated waters. In addition, both agencies have the
authority to require full financial assurances to fund dismantlement,
removal, and restoration. However, where Minerals Management has an
escalating bond structure that considers, among other things, the
future cost of reclamation, the Bureau uses minimum bond amounts that
will only cover a fraction of the funds potentially needed to meet the
future dismantlement, removal, and restoration costs. For example, the
Bureau only requires a company to obtain a $300,000 bond for all leases
the company holds in the National Petroleum Reserve-Alaska. However, in
2001 the Corps approved about $16 million to plug two abandoned wells
and remediate contaminated soil at the two sites that are located in the
National Petroleum Reserve-Alaska. Further, since the Congress is still
considering whether or not to open the Arctic National Wildlife Refuge
to oil and gas activities, no specific restoration goal or
dismantlement, removal, and restoration requirements have been
established for the refuge. In the past, prior to the establishment of
such requirements and financial assurances, many oil exploration wells
drilled by the federal government on federal lands on the North Slope
were improperly plugged and abandoned. According to the Bureau of Land
Management, these wells remain potentially costly environmental
problems. In contrast to the varying federal requirements and financial
assurances for oil industry activities on the North Slope, the Trans-
Alaska Pipeline System and the mining and nuclear power industries have
explicit dismantlement, removal, and restoration requirements that are
set before any industry activities start. In addition, the federal
agencies that regulate these entities require full financial assurance
that funds will be available to meet these requirements.
Principal Findings:
Existing North Slope Oil Industry Activities Are Subject to General
Restoration Requirements:
The state of Alaska‘s dismantlement, removal, and restoration
requirements, which apply to most current oil industry activities on the
North Slope, stipulate that oil companies return the land to a
condition that is satisfactory to the state. Because this requirement
has not been further defined, there is no specific guidance on what
infrastructure needs to be removed and to what condition the land must
be restored. The state may also waive requirements altogether if it
decides that it wants the development to remain in place.
Alaska‘s dismantlement, removal, and restoration requirements are
generally not imposed until all oil production in a unit ceases. To
date, no units on the North Slope have ceased production. As a result,
there is little indication of what DR&R the state will actually require
oil companies to perform. The federal and local governments also affect
DR&R requirements on state-owned lands on the North Slope. However, at
the federal level, Corps of Engineers permits, which are needed for
certain aspects of development on wetlands, stipulate only that
restoration of the area may be required. At the local level, the North
Slope Borough may require a rehabilitation plan for the land before
issuing a development permit, but it has never done so. Although oil
companies accept the state‘s general requirements and like the
flexibility they provide, the companies would prefer more specific
requirements so that they could better estimate their future financial
liabilities and make better cost-based restoration decisions.
Dismantlement, removal, and restoration requirements imposed in other
oil-producing states vary. For example, Alaska‘s requirements mirror
those in Louisiana and Pennsylvania. In contrast, other states, such as
Florida and New Mexico, have more specific requirements that create a
fixed obligation to, among other things, remove all surface material and
structures and fully restore the land according to its original contour
and with native vegetation.
Dismantlement, Removal, and Restoration Is Likely to Be Costly:
Without specific requirements, it is impossible to arrive at any
reasonable estimate of the future cost associated with the
dismantlement and removal of North Slope infrastructure and restoration
of the land. Under generally accepted accounting principles, oil
companies are required to report their DR&R liabilities annually.
However, these estimates are reported in aggregate for worldwide
operations, and specific estimates for the North Slope are not
available to the public. Dismantling and removing more than 30 years‘
worth of accumulated infrastructure”including 224 miles of pipeline;
more than 10,000 acres of gravel pads, roads, and airstrips; and
numerous production facilities and plants”will be an enormous
undertaking, given the North Slope‘s remote location and harsh climate.
Even more problematic will be the efforts to restore the sensitive
arctic tundra, which may take decades to recover. Examining the
increase in Phillips Petroleum‘s liabilities when they acquired
Atlantic Richfield Company‘s assets on the North Slope in 2000 provides
some indication of the magnitude of the oil company‘s potential cost
for cleaning up the North Slope. At the time of the merger, Atlantic
Richfield Company accounted for about 30 percent of the North Slope oil
production. After the acquisition, Phillips increased its worldwide
estimate of total future dismantlement, removal, and restoration costs
by nearly $1.6 billion. This increase was primarily due to Phillips‘s
acquisition of Atlantic Richfield‘s North Slope operations.
Existing Financial Assurances Are Insufficient to Fund the Potential
Cost of Dismantlement, Removal, and Restoration on State-Owned Land:
Oil companies are required to assure the availability of only a small
portion of the funds needed to dismantle and remove existing
infrastructure and restore the lands currently used for oil industry
activities on the North Slope. The state of Alaska requires oil
companies to post bonds for their wells and leases, but the state only
requires each oil company to set aside a maximum of $200,000 for all
its wells and $500,000 for all its oil and gas leases”a fraction of the
potential total dismantlement, removal, and restoration cost. Other
entities, such as the Corps of Engineers, local government, and native
landowners, do not require any assurance that funds will be available
to perform DR&R after oil production ceases. Alaska‘s bonding
requirements are generally higher than eight of the nine other oil-
producing states that we surveyed. Specifically, only California,
Florida, and Michigan have higher bonding requirements than Alaska for
wells, while only California and Pennsylvania require oil companies to
post larger bonds for oil and gas leases than Alaska.
Future Oil Industry Activities on Federal Lands Are Subject to Uncertain
Requirements and Financial Assurances:
Oil companies and the state of Alaska are looking to federal lands for
future oil development on the North Slope. These lands, which include
the National Petroleum Reserve-Alaska, the Outer Continental Shelf, and
the coastal plain of the Arctic National Wildlife Refuge, are managed
by various federal agencies. The agencies have varying requirements and
financial assurances for dismantlement, removal, and restoration
activities. For example, in the National Petroleum Reserve-Alaska, the
Bureau of Land Management has an overall restoration goal of returning
the disturbed land to its previous primary uses as fish and wildlife
habitat and for subsistence use by native villagers; however, it has
yet to develop specific DR&R requirements to implement that goal. In
addition, the Bureau currently uses minimum bond amounts that do not
reflect differences in oil company experience and financial viability
and are unlikely to cover the potential restoration costs that could be
incurred. Further, since the Congress has not yet authorized oil and
gas development in the Arctic National Wildlife Refuge, neither the
Bureau nor the Fish and Wildlife Service”each of which currently has
differing responsibilities for oil and gas activities in refuges”has a
restoration goal for the refuge or any requirements in place to
implement that goal. In addition, neither agency currently requires
bonds in amounts that are sufficient to meet the potential cost of
future restoration. In the past, as a result of inadequate
dismantlement and restoration requirements, about 80 wells drilled on
federal lands in what is now known as the National Petroleum Reserve-
Alaska remain improperly plugged and abandoned. Today, some of these
wells are leaking oil and other substances that could result in an
environmental hazard. Although the total cost of restoring these sites
is unknown, a recent Bureau of Land Management internal working
document estimated that the total cost to plug and abandon these wells
would exceed $100 million. According to the Bureau, federal monies will
be used to restore these sites, because these wells predate the
existence of DR&R requirements.
In contrast to federal lands on the North Slope, dismantlement, removal,
and restoration requirements for the Trans-Alaska Pipeline System and
for the mining and nuclear industries are predetermined and fixed. The
Trans-Alaska Pipeline has mandatory DR&R requirements and fixed
financial arrangements to comply with the requirements, which predate
the pipeline‘s construction. In the mining industries, companies are
typically required to submit abandonment plans and fully ensure that
funds for future reclamation costs will be available through bonds and
other financial arrangements made prior to initiating operations.
Likewise, in the nuclear power industry, power plant licensees are
required to submit abandonment plans and provide full financial
assurance before plant decommissioning begins.
Recommendations for Executive Action:
In order to ensure that the lands of the National Petroleum Reserve-
Alaska are properly restored after oil and gas activities cease, we are
recommending that the Secretary of the Interior instruct the Director
of the Bureau of Land Management to issue specific dismantlement,
removal, and restoration requirements that will allow the Bureau to
meet its overall goal of returning the land to a condition that will
sustain its previous uses including fish and wildlife habitat and
subsistence uses. In addition, we recommend that the Bureau review its
existing financial assurances for oil and gas activities in the
National Petroleum Reserve-Alaska to determine whether they are
adequate to assure the availability of funds to achieve its overall
restoration goal.
Matter for Congressional Consideration:
Any future decision to open additional federal lands, including those on
Alaska‘s North Slope, to oil and gas activities is a public policy
decision that rests with the Congress. In any such decision, one factor
that would be important to consider is the restoration of the land
after oil and gas activities are completed. If the Congress wants to
provide guidance on the condition to which these lands should be
returned following the completion of such activities, it should
consider providing in the authorizing statute:
* a restoration goal that will allow the federal agency or agencies
responsible for developing dismantlement, removal, and restoration
requirements to have a clear understanding of what the Congress wants
achieved; and;
* specific assurances that the federal agency or agencies responsible
for implementing dismantlement, removal, and restoration requirements
will obtain adequate financial assurances that funds will be available
to meet the goal of returning the land to a condition that the Congress
has specified.
Agency Comments and GAO‘s Evaluation:
We provided copies of a draft of this report to the Department of the
Interior and the state of Alaska for their review and comment. The
Department concurred with the findings and recommendations of the
report. The state of Alaska, however, raised concerns about the scope
and appropriateness of the GAO review and disagreed with GAO‘s
recommendations. Specifically, the state commented that it was not aware
of any other circumstances where GAO resources were devoted to the
review of state practices on state lands. GAO often examines state
practices on state lands, especially if federal agencies have a
regulatory role in the state activity or if federal agencies can learn
from state practices. For example, GAO has reviewed the state of
Florida‘s land acquisition program as it relates to the South Florida
Ecosystem Restoration Initiative. In another example, GAO reviewed state
management practices in state-owned parks, wildlife and waterfowl areas,
and forests in New Mexico, North Carolina, and Utah and compared them
to federal practices on federally owned land. Further, for state lands
on Alaska‘s North Slope, federal agencies such as the U.S. Army Corps of
Engineers and the U.S. Fish and Wildlife Service have issued regulations
that can significantly affect the state of Alaska‘s dismantlement,
removal, and restoration requirements. It is within GAO‘s authority and
responsibility to review the federal role with regard to this issue.
The state also commented that by performing this review, GAO was
promulgating a particular political agenda, which also brought into
question its credibility. We strongly disagree. The GAO has a statutory
obligation to fulfill requests from the Congress and its committees. To
effectively accomplish this obligation, GAO prioritizes its work in
accordance with its published congressional protocols. These protocols
state that congressional mandates, senior leader requests, and committee
leader requests receive the highest priority followed by committee
member requests, and then by individual member requests. GAO does not
differentiate between the majority and the minority staff when
implementing these priorities. Congressmen who represent the highest of
these priorities requested this work. To effectively support the
Congress, GAO must be professional, objective, fact-based, nonpartisan,
nonideological, fair, and balanced in all its work. All GAO products and
services must conform to generally accepted and applicable auditing,
accounting, investigative, and evaluation principles and standards. GAO
strives to exercise the independence necessary to guarantee that its
products and work conform to professional standards and the agency‘s
core values of accountability, integrity, and reliability.
The state also disagreed with GAO‘s recommendations to the Department
of the Interior. Specifically, concerning GAO‘s recommendation that the
Bureau of Land Management issue specific dismantlement, removal, and
restoration requirements prior to the initiation of oil production in
the National Petroleum Reserve-Alaska, the state commented that it is
better to address this issue when oil production ceases and the
obligation actually becomes due. Although the state said it is not too
early to think about appropriate requirements, it believes that the
discretion it has to deal with particular dismantlement, removal, and
restoration issues when they are about to occur provides the state with
greater flexibility to respond to changes in such things as technology
and the regulatory environment. GAO does not draw any conclusions nor
make any recommendations concerning the appropriateness or
inappropriateness of the state of Alaska‘s current dismantlement,
removal, and restoration practices for its lands. GAO recognizes that
overall restoration goals such as the Bureau of Land Management‘s goal
of returning the National Petroleum Reserve-Alaska to a condition that
will sustain its previous uses can change. In addition, GAO agrees that
the specific processes used to achieve those goals can change as
technology, science, and circumstances change. However, GAO believes
that for federal lands on Alaska‘s North Slope it is appropriate to
establish overall restoration goals and specific dismantlement,
removal, and restoration requirements prior to oil and gas development
and production activities. Doing so provides all interested parties,
including the Congress, the federal land management agency, the oil
companies, environmental groups, and the public, an opportunity to make
informed decisions about whether they would support such development on
public lands. It also provides oil companies with better information on
what is expected of them, which allows for better planning and
budgeting to achieve restoration.
The state of Alaska commented that it also disagrees with GAO‘s
recommendation on the level of financial assurances that are needed to
ensure that required dismantlement, removal, and restoration activities
take place. The state‘s disagreement appears to be based on a
misinterpretation of GAO‘s recommendation. Specifically, the state
commented that GAO is recommending the level of financial assurance that
should exist for federal lands on the North Slope and that GAO believes
that level should be higher than the financial assurances required by
the state of Alaska for its lands. GAO did not make any determination
of what level of financial assurance should exist to ensure that
restoration occurs on federal lands on the North Slope. Further, GAO
did not make any comparison of the state of Alaska‘s financial
assurances to those of federal agencies that mange land on Alaska‘s
North Slope. GAO found that for the National Petroleum Reserve-Alaska,
the Bureau of Land Management‘s minimum bond amounts are (1) fixed, (2)
do not reflect differences in oil company experience and financial
viability, and (3) would only cover a fraction of the potential future
cost of dismantlement, removal, and restoration. In the context of
these findings, GAO recommends that the Bureau review its existing
financial assurances for oil and gas activities in the National
Petroleum Reserve-Alaska to determine whether they are adequate to
ensure the availability of funds to achieve its overall restoration
goal for the land after oil and gas activities cease. The Department of
the Interior agrees with this recommendation and stated that the
Bureau‘s review will focus on protecting the environment and taxpayers,
should lessees default.
More detailed discussions of the comments from the Department of the
Interior and the state of Alaska are included at the end of chapter 5.
Both the Department and the state also provided clarifications on
several technical points that have been included in the report as
appropriate. The full text of the comments and GAO‘s responses are
included in appendix II for the Department of the Interior and appendix
III for the state of Alaska.
[End of section]
Chapter 1: Introduction:
The North Slope of Alaska”a vast, ecologically sensitive area north of
the Arctic Circle”is home to the largest oil reserve in the United
States. This sparsely settled area consists primarily of public lands
owned by the federal government, state government, and Alaska Native
corporations. To date, oil production activity has occurred mostly on
state land and, to a limited extent, on Alaska Native lands. In the
next couple of years, however, oil industry activity on federal lands
adjacent to the state and Alaska Native corporation lands is expected
to move from the exploration phase to the production phase. As of
January 2002, only two companies”BP and Phillips Petroleum”operate
producing oil fields on the North Slope. Several other large oil
companies, including ExxonMobil, Anadarko, and Chevron, among others,
also have ownership interests in this production under various
collective operating agreements. Since the state lands were opened to
oil industry activities, oil companies, federal, state and local
governments have all shared in the profits. Once oil production ceases,
responsibility for determining to what extent oil companies will have
to dismantle and remove their production facilities and associated
roads, pipelines, and airstrips, and restore the disturbed lands is
generally divided among federal, state, and native entities, depending,
in part, on who owns the land.
Alaska‘s North Slope Is a Sensitive Environment:
Alaska‘s arctic coastal plain, often referred to as the ’North Slope,“
extends from the foothills of the Brooks Range to the Arctic Ocean and
from the Canadian border to Point Hope (see figure 3). Covering
approximately 89,000 square miles, this area is the boundary of the
North Slope Borough”geographically the largest local government unit in
the United States. The North Slope is also one of the least populated
areas in the world, with a total population of about 7,400”of which
almost 70 percent are native Inupiat Eskimo. It is a harsh climate with
winter temperatures as low as –60O Fahrenheit and average annual wind
speeds of 12 to 13 mph. For almost 2 months during the arctic winter,
the sun never rises above the horizon. Snow generally remains on the
ground until the beginning of June and begins accumulating again in
September. Annual precipitation is quite low, averaging less than 5
inches per year.
Figure 3: Map of Alaska and the North Slope:
[Refer to PDF for image]
This figure contains a map of the North Slope with an inset map of
Alaska. The map of the North Slope depicts the Northern margin of the
Brooks Range.
Source: GAO‘s adaptation of a map prepared by the Department of the
Interior‘s Bureau of Land Management.
[End of figure]
The North Slope coastal plain is a vast treeless expanse of tundra
vegetation. Many lakes, streams, and rivers are scattered across this
generally flat terrain, despite the limited precipitation. Because the
entire area is underlain by permafrost (permanently frozen subsoil),
which allows no water absorption, the surface consists mostly of
wetlands (see figure 4). Accordingly, this area provides excellent
habitat for a variety of wildlife, especially large numbers of breeding
migratory birds and caribou that calve on the coastal plain. In
addition, the immediate coastal area is inhabited by an estimated 2,000
polar bears that spend most of their time feeding, resting, and denning
on the drifting ice pack in the Beaufort Sea. Permafrost is vulnerable
to surface disturbance because such disturbance usually results in
thawing and the subsidence and erosion of soil. Damage due to surface
disturbance is very difficult to reverse. In order to prevent thawing
of the permafrost and provide a stable foundation, any development,
such as roads, airstrips, and production facilities, must occur on
gravel fill that is laid down to a depth of about 6 feet.
Figure 4: Aerial Photo of Area Surrounding Alpine Oil Field:
[Refer to PDF for image]
Source: GAO.
[End of figure]
Oil Industry Activity Occurs Primarily on State-Owned Lands:
The current mix of federal, state, and Alaska Native lands on the North
Slope evolved after Alaska achieved statehood in 1959. Before Alaska
obtained statehood, the federal government owned almost all the land.
The Alaska Statehood Act of 1958 gave the new state government the
right to claim land in the newly formed state. In 1964, the state
selected, among other areas, a corridor of federal land on the North
Slope that was about 100 miles wide. On the basis of geophysical
surveys, this land was thought to hold large oil deposits. In 1971,
under the Alaska Native Claims Settlement Act (ANCSA), the Arctic Slope
Regional Corporation (ASRC) claimed surface and subsurface mineral
rights across the North Slope. In addition, eight village corporations
claimed surface lands surrounding their villages. These claims resulted
in Alaska Native corporation lands being scattered across the North
Slope.
Soon after the state made its claims, it opened the North Slope lands to
commercial leasing for oil industry activities. At first, exploration
yielded only dry holes, but in 1968 Atlantic Richfield Company (ARCO)
and Humble Oil (a predecessor of ExxonMobil Corporation) announced a
major oil find in the Prudhoe Bay area of the North Slope. A year
later, the companies announced plans to construct an 800-mile oil
pipeline called the Trans-Alaska Pipeline System (TAPS), which opened
in 1977. The pipeline is used to transport oil from Prudhoe Bay on the
North Slope down the length of the state to Valdez, where it is then
carried by oil tankers to markets primarily in the continental United
States but also to other world markets.
The federal government retained ownership of the land on either side of
the state-owned lands on the North Slope; the National Petroleum
Reserve-Alaska (NPR-A) lies to the west, and the Arctic National
Wildlife Refuge (Arctic Refuge or ANWR) lies to the east. Management of
the NPR-A, originally named the Naval Petroleum Reserve Number 4
Alaska, which is roughly the size of Indiana, was transferred from the
Navy to the Department of the Interior‘s Bureau of Land Management
(BLM) in 1977. In 1980, the Congress granted the Secretary of the
Interior the authority to lease land in the NPR-A for oil and gas
exploration. While the BLM issued some leases in the early 1980s,
almost no exploration occurred. It was not until leases were issued
under the 1998 Integrated Activity Plan/Environmental Impact Statement
that the most current oil exploration in the NPR-A was initiated. In
2001, Phillips Petroleum and Anadarko announced the discovery of likely
commercial quantities of oil in the NPR-A.
The Arctic National Wildlife Refuge was created in 1960, enlarged in
1980, and currently includes 19 million acres. In 1980, the Congress
passed the Alaska National Interest Lands Conservation Act (ANILCA),
which designated about 8 million acres of the Arctic National Wildlife
Refuge as wilderness and as such prohibited oil industry activities.
However, the coastal plain area of the refuge was not designated as
wilderness. This area, known as the ’1002 Area“ after section 1002 of
the Alaska National Interest Lands Conservation Act, was set aside for
special study which would allow the Congress to subsequently decide
whether to permit oil and gas industry activities, designate the area
as wilderness, or make no changes. The Congress is currently debating
the future status of this area.
The extent of North Slope industry activities has grown progressively
since the first oil was discovered there in 1968. Figure 5 shows the
current range of growth, which originally centered on Prudhoe Bay, the
largest oil field (as measured by volume) in North America.[Footnote 3]
As exploration has yielded additional finds, the network of wells,
roads, pipelines, and production facilities has expanded from the
border of the NPR-A almost to the border of the Arctic Refuge. As a
result, state lands on the North Slope now contain a web of industrial
complexes spread across 1,500 square miles of state and native lands.
Figure 5: Development of North Slope Oil Producing Area in 1999:
[Refer to PDF for image]
This figure is a map depicting development of North Slope Oil Producing
Area in 1999, as well as an inset map of Alaska depicting the location
of the area. Specifically noted on the map are:
Tans-Alaska Pipeline;
Roads;
Gathering pipeline;
ANWR;
NPR-A.
Note: The ANWR is an abbreviation for the Arctic National Wildlife
Refuge and NPR-A is an abbreviation for the National Petroleum Reserve-
Alaska.
Source: GAO‘s adaptation of a map prepared by BP.
[End of figure]
A complete inventory of current North Slope infrastructure is not
available. However, using information obtained from BP, the state, and
data in a recent environmental impact statement (EIS), we identified
the following infrastructure of wells, pipelines, roads, and facilities
as presented in table 1 below.
Table 1: GAO‘s Estimate of North Slope Infrastructure, as of January
2000:
Gravel fill[A]: 10,653 acres (excluding the Dalton Highway and reclaimed
and exploratory sites);
Gravel mines[B]: 15 mines covering 1,601 acres;
Roads[B]: 364 miles and 22 river crossings (excluding the Dalton
Highway);
Well pads[C]: 109;
Wells[C]: 3,520 well sites;
Pipelines[B]: 520 miles, excluding TAPS;
Facilities[B]:
* 13 production centers;
* 14 industrial plants;
* 5 docks and causeways.
[A] Aero Map U.S. 1999.
[B] Liberty Draft EIS.
[C] Alaska Oil and Gas Conservation Commission data, December 2001 and
March 2002.
[End of table]
North Slope oil production is organized by units, which are a
collection of leases. Each unit has a cooperative plan for oil
exploration, development, and operation within a geographic area
covering one or more oil fields. The reason for organizing leases owned
by different companies into a unit is to prevent waste and enhance oil
recovery. Within each unit one leaseholder is designated as the unit‘s
operator and is responsible for all oil production activities in the
unit. The operator of a unit conducts oil field operations on behalf of
leaseholders and is responsible for field operations, maintenance, and
any current (but not future) DR&R expenses. As of 2001, two firms”BP
and Phillips Petroleum”were performing most North Slope oil exploration
and production activities.[Footnote 4] These two companies are also the
only two operators of oil-producing units on the North Slope.
ExxonMobil is the operator of the Point Thomson unit, but as of January
2002 that unit was not in production. Table 2 lists the North Slope
units, production,
operator, and ownership interests.
Table 2: North Slope Oil Units, Production, Operator, and Ownership:
Unit: Badami;
1999 Production (thousands of barrels): 1,150;
Unit operator: BP;
2001 Working interest owners (approximate ownership share): BP 70%;
Petrofina 30%.
Unit: Colville River;
1999 Production (thousands of barrels): Production began in 2000;
Unit operator: Phillips Petroleum;
2001 Working interest owners (approximate ownership share): Phillips
Petroleum 78%; Anadarko 22%.
Unit: Duck Island[A] (Eider) (Endicott) (Sag Delta);
1999 Production (thousands of barrels): 15,225;
Unit operator: BP;
2001 Working interest owners (approximate ownership share): BP 68%;
ExxonMobil 21%; Unocal 10%; Others 1%.
Unit: Kuparuk;
1999 Production (thousands of barrels): 95,045;
Unit operator: Phillips Petroleum;
2001 Working interest owners (approximate ownership share): Phillips
Petroleum 55%; BP 39%; Unocal 5%; Others 1%.
Unit: McCovey;
1999 Production (thousands of barrels): Exploration; unit approved in
2000;
Unit operator: Alberta Energy Corporation;
2001 Working interest owners (approximate ownership share): Alberta
Energy Corp. 33.3%; Phillips Petroleum 33.3%; Chevron 33.3%.
Unit: Milne Point;
1999 Production (thousands of barrels): 19,586;
Unit operator: BP;
2001 Working interest owners (approximate ownership share): BP 100%.
Unit: Northstar;
1999 Production (thousands of barrels): Production began in 2001;
Unit operator: BP;
2001 Working interest owners (approximate ownership share): BP 98%;
Murphy 2%.
Unit: Point Thomson;
1999 Production (thousands of barrels): Exploration;
Unit operator: ExxonMobil;
2001 Working interest owners (approximate ownership share): ExxonMobil
37%; BP 32%; Chevron 25%; Phillips Petroleum 5%; Others 1%.
Unit: Prudhoe Bay;
1999 Production (thousands of barrels): 273,243;
Unit operator: BP;
2001 Working interest owners (approximate ownership share): BP 26%;
ExxonMobil 37%; Phillips Petroleum 36%; Others 1%.
Unit: Sakonowyak River;
1999 Production (thousands of barrels): Exploration; unit approved in
2001;
Unit operator: BP;
2001 Working interest owners (approximate ownership share): BP 62%;
Alaska Venture Capital Group 38%.
Unit: SE Delta;
1999 Production (thousands of barrels): Exploration; unit approved in
2001;
Unit operator: Phillips Petroleum;
2001 Working interest owners (approximate ownership share): Phillips
Petroleum 100%.
Unit: Slugger;
1999 Production (thousands of barrels): Exploration; unit approved in
2001
Unit operator: BP;
2001 Working interest owners (approximate ownership share): BP 39%;
Phillips Petroleum 31%; Chevron 30%.
Unit: Total;
1999 Production (thousands of barrels): 404,249.
[A] Ownership of the Duck Island Unit is based on a weighted average of
production from three fields within the unit.
Sources: Alaska Department of Natural Resources, Division of Oil and
Gas, 2000 Annual Report, and oil company data.
[End of table]
Many Entities Benefit from Revenues Generated by Oil Production on the
North Slope:
Federal, state, and local governments as well as the oil companies all
share in the revenues generated by oil production on the North Slope.
The nation has benefited from North Slope oil production in terms of
jobs, corporate taxes, and royalties provided by oil and associated
companies, and a reduction in oil imports and the balance of trade
deficit. One estimate, made by a consulting firm hired by the oil
companies, attributed $40 billion in federal taxes and rents collected
between 1977 and 1999 to North Slope oil production.[Footnote 5]
The state of Alaska collects petroleum-based revenues from North Slope
oil production and transportation in a variety of taxes (principally
corporate income, severance, and property), royalty payments (generally
12.5 percent of the value of the oil), and bonuses and rents from oil
leases.[Footnote 6] Because of the state‘s oil revenues, residents of
Alaska pay no state income tax or state sales taxes. Oil revenues also
fund about 80 percent of the state‘s general fund operating budget. In
addition, in 1980, using mostly oil revenues, the state was able to
establish a permanent fund that provides an annual dividend payment to
every state resident.
The North Slope Borough, the local municipality, also uses revenues from
North Slope oil production to fund its government services. Oil
companies pay nearly all of the borough‘s property taxes and provide
about 60 percent of borough revenues. A recent study developed by the
Bureau of Land Management for the renewal of federal rights-of-way for
the Trans-Alaska Pipeline System (TAPS) estimates that if the pipeline
closed, the borough would lose almost $1.9 billion (1998 dollars) in
property tax revenues for a 30-year period starting in 2004.[Footnote
7]
According to an analysis done by Alaska‘s Department of Revenue, for the
fiscal year period 1988 through 2000 accounting profits (i.e., all
returns on investment) for North Slope oil are split 41.6 percent to
industry, 36.1 percent to the state, and 22.3 percent to the federal
government. A number of other studies support the level of revenues
accumulated by industry, the state, and the federal government.
[Footnote 8] For example, a 1989 state-commissioned study found that
for the period 1969 to 1987 oil companies generated $42.6 billion in
net profits after taxes on total gross revenues of $131 billion from
the production and transportation of North Slope oil. The study
estimated a similar split in accounting profits for this earlier period
of 44 percent for industry, 30 percent to the state, and 26 percent to
the federal government.[Footnote 9]
Dwindling Production Focuses Greater Attention on the Disposition of Oil
Company Infrastructure on the North Slope:
The production of oil on the North Slope peaked in 1988 at 2 million
barrels per day. By 1999, production had fallen to 1.1 million barrels
per day, or about 16 percent of total U.S. production. Total production
on the North Slope through 2000 was 13.3 billion barrels, while another
6.1 to 13.3 billion barrels of technically recoverable oil from known
and undiscovered sources remain on the North Slope, according to the
Department of Energy.[Footnote 10] As a result of declining production
on state lands, efforts to develop federal lands on the North Slope
have intensified.
Overall production on the North Slope will most likely continue to
decline even as new fields are brought on line. According to the U.S.
Department of Energy, most North Slope oil has already been produced.
The remaining life of existing North Slope oil fields will depend
partly on future economic factors. As oil fields age, the per-barrel
cost to extract additional oil increases as each barrel requires
greater effort to extract. Oil companies will continue to produce oil
from a field only as long as it is profitable and will normally stop
producing before an oil field is completely depleted. Because the cost
of transporting oil from the North Slope tends to be higher than oil
produced elsewhere in the United States, North Slope fields must
produce at a lower cost to remain competitive. The amount of oil that
can be produced at a profit, known as proven reserves, integrally
depends on the market price for the oil and its cost to produce. These
two variables, the price and cost, change over time. If the price of
oil increases or new technology makes extraction less costly, the
amount of economically recoverable oil will increase. Conversely, if
the price of oil decreases or the cost of oil production increases, the
amount of economically recoverable oil will decrease.
The Trans-Alaska Pipeline is an additional and unique limiting factor
in the North Slope‘s oil production. TAPS carries all North Slope oil
field production and requires a minimum amount of oil flow to make it
economical to operate. While the exact minimum operating level for TAPS
depends on the mechanics of pumping decreasing quantities of oil through
the pipeline, the cost to operate TAPS, and the market price of oil,
currently the U.S. Department of Energy estimates the volume to be
roughly 300,000 barrels per day. Once North Slope production falls
below the minimum economic operating level, producing oil on the North
Slope will no longer be profitable and TAPS will be shut down. Recent
proposals to build a natural gas pipeline from the North Slope could
additionally extend the projected life of North Slope fields because
many of the existing fields contain considerable natural gas reserves.
In May 2001, the Department of Energy updated its estimates of North
Slope production based on current production, undiscovered reserves, and
future NPR-A production. These estimates exclude any production from
the Arctic Refuge or the development of natural gas reserves. The new
estimates, as shown in figure 6, have North Slope production falling
below the TAPS minimum operating level of 300,000 barrels per day
sometime between 2017 and 2031. In their application for lease renewal,
the owners of TAPS anticipate that the pipeline will operate at least
through 2034.
Figure 6: Alaska North Slope Oil Production History and Projections:
[Refer to PDF for image]
This figure is a multiple line graph depicting the Alaska North Slope
Oil Production history and projections. On the graph, lines represent
the following:
Assumed pipeline minimum;
Producing;
Producing and identified development;
Undiscovered;
NPR-A.
Note: The NPR-A is an abbreviation for the National Petroleum Reserve-
Alaska.
Source: Department of Energy, Energy Information Administration, May
2001.
[End of figure]
Dismantlement and Removal of Infrastructure and the Restoration of Land
Involves Many Agencies at Multiple Levels of Government:
The end of oil and gas production on the North Slope will likely render
much of the current infrastructure of production facilities, pipelines,
and roads unnecessary. Responsibility for regulating and overseeing the
dismantlement and removal of this infrastructure and restoring the land
on which it was built will be the shared responsibility of the state,
federal, and local governments, depending in part on which party owns
the land.
Oil production requires the construction of a considerable
infrastructure of, among other things, drilling pads, production
facilities, pipelines, roads, airstrips, and gravel mines. Because most
of this infrastructure has been built on state lands, the state is
primarily responsible for regulating oil industry activity, including
any requirements for dismantling and removing the infrastructure and
restoring the land after oil production ceases. However, new oil
production in the Arctic Ocean, combined with new oil discoveries in
the NPR-A and the potential opening of the Arctic Refuge to oil
exploration, has elevated the importance of federal jurisdiction on the
North Slope.
Alaska‘s regulation of dismantlement, removal, and restoration for the
North Slope oil industry is principally divided among four state
agencies: the Alaska Oil and Gas Conservation Commission (AOGCC), the
Alaska Department of Natural Resources (ADNR), the Alaska Department of
Environmental Conservation (ADEC), and the Alaska Department of Fish
and Game. The Alaska Oil and Gas Conservation Commission issues
permits for drilling oil wells throughout Alaska, regardless of land
ownership. AOGCC is primarily concerned with maintaining the subsurface
integrity of oil fields during exploration and production and the proper
plugging and abandoning of wells after their use. The Alaska Department
of Natural Resources leases state lands for oil and gas industry
activities and collects royalties on oil and gas production in the
state. Such leases stipulate how the land will be returned to the state
after production ceases. In addition, the Alaska Department of
Environmental Conservation, which regulates waste management practices
at exploration, development, and production facilities on private,
state, and federal lands, and the Department of Fish and Game, which
oversees habitat issues, have a limited and principally advisory role
in regard to DR&R.
Municipal government and Alaska Native corporations also have control
over oil activities on the North Slope. The North Slope Borough, which
encompasses all of the North Slope, has zoning authority over industry
activities on non-federal lands on the North Slope. In addition, the
borough is consulted under the Coastal Zone Management Act for
development on federal lands. Alaska Native regional and village
corporations own significant portions of surface and subsurface rights
on the North Slope. These rights were the result of claims made under
the Alaska Native Claims Settlement Act of 1971. In particular, the
Arctic Slope Regional Corporation, a Fortune 500 Alaska Native
corporation, owns 5 million acres of surface lands and subsurface
mineral rights on the North Slope. In addition, eight Alaska Native
village corporations own surface lands surrounding their villages on
the North Slope. For example, the Kuukpik Village Corporation owns
146,000 acres of surface lands near the village of Nuiqsut on the
Colville River, site of the Alpine oil field (Colville River Unit).
Several federal agencies also have responsibility for regulating oil
activities on the North Slope. The Department of the Interior‘s Bureau
of Land Management (BLM) manages the National Petroleum Reserve-Alaska
and also issues and oversees leases for oil activities on any federal
lands. The Department of the Interior‘s Minerals Management Service
(MMS) regulates oil activities on the Outer Continental Shelf, defined
as 3 or more miles from shore. The U.S. Army Corps of Engineers issues
permits for dredging or fill activities in U.S. waters, including
wetlands. Almost the entire North Slope is designated wetland and,
because gravel underlies most production facilities, airstrips, and
roads, the Corps has a permitting role in basically all oil company
construction activities. Interior‘s Fish and Wildlife Service (FWS),
the Environmental Protection Agency (EPA), and the Department of
Commerce‘s National Marine Fisheries Service (NMFS) can offer advisory
comments to the Corps as part of the permit evaluation process.
Further, the EPA also has veto authority over Corps permits. In
addition, should the Congress decide to authorize oil industry
activities in the Arctic Refuge, the FWS would oversee the issuance of
right-of-way permits, while BLM would issue and oversee the federal
leases. This regulatory construct assumes that the Arctic Refuge would
be managed similarly to other refuges; various bills introduced in the
107th Congress to open the Arctic Refuge to oil and gas development
were unclear on FWS‘s role and regulatory authority.[Footnote 11]
Objectives, Scope, and Methodology:
The Minority Leader of the House of Representatives, the Ranking
Minority Member of the House Resources Committee, and Representative
Edward Markey asked us to examine dismantlement, removal, and
restoration requirements for Alaska‘s North Slope. Specifically, we
agreed to determine:
* the nature and extent of dismantlement, removal, and restoration
requirements for existing oil industry activities on state-owned land on
Alaska‘s North Slope, including how these requirements compare to
those of other oil-producing states;
* whether any cost estimates exist for the dismantlement and removal of
the infrastructure and for the restoration of North Slope state-owned
land;
* what financial assurances the state of Alaska has that funds will be
available to cover the eventual dismantlement, removal, and restoration
costs and how these assurances compare to those of other oil-producing
states; and;
* the nature and extent of dismantlement, removal, and restoration
requirements and financial assurances governing future oil industry
activities on federal lands located on the North Slope and how these
compare with requirements and financial assurances in other related
industries, such as mining and nuclear power.
To determine the nature and extent of federal, state, and local
requirements for dismantling, removing, and restoring existing industry
activities on the North Slope, we met with federal, state, and local
government officials; Alaska Native corporations; oil company
spokesmen; outside experts; and interest groups. We also researched
state and local statutes, regulations, policies, and analyses relating
to DR&R requirements and practices in Alaska. Finally, we visited
Alaska‘s North Slope in July 2001 to examine existing production
facilities and DR&R reclamation projects. To compare Alaska‘s DR&R
requirements to those of other states with oil production, we surveyed
the 10 states, including Alaska, that account for nearly 90 percent of
the domestic oil production in the United States, excluding federal
offshore production.[Footnote 12] For each state, we surveyed the
office that issues permits for drilling oil and gas wells and the
office that manages oil and gas leasing on state-owned lands. We asked
each office to provide information on, among other things, its
requirements for surface restoration.
To determine whether any cost estimates exist for the dismantlement and
removal of infrastructure and restoration of the North Slope, we sought
estimates from officials of federal and state government, oil companies
operating on the North Slope, academicians, and various interest groups,
including conservation and pro-oil development organizations. We also
submitted a formal written request to the oil companies operating on the
North Slope to estimate their future dismantlement, removal, and
restoration liability. In addition, we met with petroleum accountants
and studied financial reporting requirements to understand how oil
company‘s estimate and report their DR&R liability. Finally, we
obtained information on the inventory of oil company assets that
currently exist on the North Slope from oil companies, academics, and
government agencies.
To determine what financial assurances exist that funds will be
available to pay for dismantlement, removal, and restoration costs, we
interviewed and obtained documentation from federal, state, and local
government officials and Alaska Native corporations. We also researched
federal, state, and local statutes, regulations, policies, and analyses
relating to DR&R financial assurance requirements and practices in
Alaska. To compare Alaska‘s financial assurances to those of other
states with oil production, we surveyed the 10 oil-producing states,
including Alaska, that account for nearly 90 percent of domestic oil
production excluding federal offshore production. For each state, we
surveyed the office that issues permits for drilling oil and gas wells
and the office that manages oil and gas leasing on state-owned lands.
We asked each office to provide information on what, if any, financial
assurances it obtains to ensure that funds will be available for
plugging and abandonment of oil and gas wells and surface reclamation.
Finally, to determine what dismantlement, removal, and restoration
requirements and financial assurances exist for federal lands on the
North Slope, we reviewed federal regulations and interviewed officials
in Alaska and Washington, D.C., from the U.S. Army Corps of Engineers;
the Department of the Interior‘s Bureau of Land Management, Minerals
Management Service, and Fish and Wildlife Service; the Environmental
Protection Agency; and the Department of Commerce‘s National Marine
Fisheries Service. We also compared these requirements to reclamation
requirements and financial assurance requirements for the Trans-Alaska
Pipeline System and those found in the hardrock and coal mining
industries and for nuclear power plants. The mining industry is
comparable to the oil industry in that it extracts a nonrenewable
resource from the ground and in so doing requires industrial facilities
to process and deliver these resources. Likewise, we reviewed the
nuclear utility industry because it generates electricity through a
complex infrastructure with a fixed useful life span.
We conducted our work from March 2001 through March 2002 in accordance
with generally accepted government auditing standards.
[End of section]
Chapter 2: Current DR&R Requirements for Existing Oil Production Are
Very General:
The state of Alaska‘s dismantlement, removal, and restoration
requirements, which apply to almost all existing oil production on the
North Slope, offer no specifics on what infrastructure must be removed
or to what condition lands used for oil industry activities must be
restored. Additionally, the Corps of Engineers, the local North Slope
municipality, and native landowners, all of which have authority to
impose DR&R requirements, have for the most part not done so. The
state, the oil industry, and environmental groups disagree about the
benefits and risks associated with the state‘s general requirements.
The state believes that its requirements are sufficient and provide
flexibility, the oil companies like the flexibility but would prefer
more specific guidelines, and environmental groups feel the
requirements are so vague that there is no assurance that any
dismantlement, removal, and restoration will occur. A comparison of
Alaska‘s DR&R requirements to those of nine other oil-producing states
reveals a spectrum of requirements; some states have general
requirements like Alaska‘s, while other states have more explicit
requirements that create a fixed obligation to fully restore the land
according to specific standards.
The State of Alaska Determines DR&R Requirements for Existing Oil
Production:
Because existing oil production activities occur almost entirely on
state lands, the state of Alaska largely determines the requirements for
dismantling and removing the infrastructure and restoring the land
following completion of oil activities. The state‘s requirements are
very general, especially with regard to surface restoration
requirements. Two agencies within the state have the authority to
impose DR&R requirements upon the oil companies”the Alaska Oil and Gas
Conservation Commission and the Alaska Department of Natural Resources.
AOGCC issues permits for drilling oil wells throughout Alaska,
regardless of land ownership. AOGCC is concerned primarily with
maintaining the subsurface integrity of oil fields during exploration
and production and the proper plugging and abandonment of wells after
production ceases. AOGCC regulations impose specific requirements on
oil companies for plugging and abandoning wells, but what will be
required regarding surface restoration beyond the immediate well site
is uncertain. ADNR leases state lands for oil and gas industry
activities and collects royalties on oil and gas production in the
state. ADNR lease agreements contain only general language regarding
DR&R requirements. What specific surface dismantlement, removal, and
restoration will be required is unknown and left to the discretion of
the state. In addition, Alaska‘s Department of Environmental
Conservation has certain statutory responsibilities for preventing air,
land, and water pollution. Therefore, if a site on the North Slope is
contaminated, ADEC requires the polluter to remediate the site. The
Corps of Engineers, which issues permits for certain aspects of
development occurring on both private and public wetlands, also has
only general DR&R requirements as part of its permitting process. The
Corps prefers the landowner to have primary responsibility for
establishing DR&R requirements. Finally, the local municipality and
Alaska Native landowners have authority over existing industry
activities on their lands through zoning and the development of coastal
management plans. However, these entities have largely deferred to the
state to impose DR&R requirements.
DR&R Requirements in State Drilling Permits:
AOGCC drilling permits contain detailed requirements for well-plugging
and abandonment, but provide minimal guidance on surface restoration.
The primary purpose of AOGCC‘s well-plugging and abandonment
regulations are to protect subsurface oil reservoirs and aquifers. An
improperly plugged well could allow oil to escape from one pool to
another, intrude into fresh water supplies, or cause fires or seepage.
AOGCC regulations contain several pages of technical specifications on
plugging a well, which involve setting a series of cement plugs to seal
each stratum.[Footnote 13] As of March 28, 2002, 412 individual well
sites on the North Slope have been plugged and abandoned”most of these
well sites are in the Prudhoe Bay and Kuparuk units or were exploratory
well sites in other units. As of that date, 3,108 well sites remain
active (see table 3).
Table 3: Number and Status of North Slope Oil Well and Drill Sites, as
of March 28, 2002:
Unit: Prudhoe Bay;
Number active well sites: 1,583;
Number of plugged and abandoned well sites: 47;
Total number of well sites: 1,630.
Unit: Kuparuk;
Number active well sites: 1,037
Number of plugged and abandoned well sites: 62;
Total number of well sites: 1,099.
Unit: Milne Point;
Number active well sites: 254;
Number of plugged and abandoned well sites: 4;
Total number of well sites: 258.
Unit: Duck Island;
Number active well sites: 112;
Number of plugged and abandoned well sites: 1;
Total number of well sites: 113.
Unit: Colville River;
Number active well sites: 49;
Number of plugged and abandoned well sites: 0;
Total number of well sites: 49.
Unit: Pt. Thomson;
Number active well sites: 1;
Number of plugged and abandoned well sites: 14;
Total number of well sites: 15.
Unit: Badami;
Number active well sites: 9;
Number of plugged and abandoned well sites: 0;
Total number of well sites: 9.
Unit: Northstar;
Number active well sites: 8;
Number of plugged and abandoned well sites: 0;
Total number of well sites: 8.
Unit: All other units[A];
Number active well sites: 55;
Number of plugged and abandoned well sites: 284;
Total number of well sites: 339.
Totals:
Number active well sites: 3,108;
Number of plugged and abandoned well sites: 412;
Total number of well sites: 3,520.
Unit: Production pads[B];
Number active drill sites: 109;
Abandoned drill sites: 9;
Total drill sites: 109.
Total drill sites:
Number active drill sites: 164;
Abandoned drill sites: 284;
Total drill sites: 448.
[A] Includes exploration wells not on pads.
[B] Wells not included in ’All other units“ are located on 109 pads.
Source: Alaska Oil and Gas Conservation Commission data.
[End of table]
In contrast, AOGCC‘s post-production DR&R requirements for the surface
area of a well site, which are known as location clearance requirements,
are not nearly as specific as its well-plugging provisions. As shown in
figure 7, AOGCC‘s regulations for location clearance require the
operator to remove equipment and other associated infrastructure from
the location, fill and grade all pits, and leave the location in a
clean and graded condition before a well site can be granted final
clearance and the surety bond returned to the owner.[Footnote 14]
AOGCC‘s location clearance provisions are not specific as to the
physical reach of DR&R around the well site”that is, whether it extends
to the general vicinity of the well, to the well pad, or to the entire
oil field. Further, AOGCC regulations defer to the relevant state or
federal land management agency for the appropriate level of
dismantlement, removal, and restoration.
Figure 7: Alaska Oil and Gas Conservation Commission‘s Location
Clearance Requirements:
[Refer to PDF for image]
20 AAC 25.170. Onshore Location Clearance:
(a) At or after the time that a well drilled onshore is abandoned and
before the earlier of one year after well abandonment or the expiration
of the owner's rights in the property,
(1) the operator shall remove the wellhead equipment and casing to a
depth at least three feet below original ground level and install a
well abandonment marker in accordance with 20 AAC 25.120; and;
(2) unless the operator demonstrates to the commission that the surface
owner has authorized a different disposition to facilitate a genuine
beneficial use, the operator shall:
(A) remove all materials, supplies, structures, and installations from
the location;
(B) remove all loose debris from the location;
(C) fill and grade all pits or close them in another manner approved by
the commission as adequate to protect public health and safety; and
(D) leave the location in a clean and graded condition.
[End of figure]
AOGCC location clearance requirements have yet to be tested because the
oil companies have not abandoned all the well sites of any producing
well pads on the North Slope. An AOGCC official stated that location
clearance for a well site is not granted until all the wells on a well
pad are plugged and abandoned.[Footnote 15] However, this official
stated that as of December 2001 there were no instances where all wells
on a production well pad located on the North Slope had been plugged
and abandoned. As a result, AOGCC commissioners stated that they had
not granted location clearances for any producing well sites on the
North Slope. Figure 8 contains photos of producing well pads in the
Prudhoe Bay and Kuparuk units.
Figure 8: Series of Well Sites on Prudhoe Bay Unit and Kuparuk Unit
Well Pads:
[Refer to PDF for image]
Photographs of:
Prudhoe Bay Unit Well Pad;
Kuparuk Unit Well Pad.
Source: GAO.
[End of figure]
DR&R Requirements in State Lease Agreements:
The Alaska Department of Natural Resources administers lease agreements
for oil industry activities on state-owned land in Alaska‘s North Slope.
However, these agreements do not specifically describe DR&R
requirements for the infrastructure and wetlands on which the
infrastructure was built. ADNR has used several different lease forms on
the North Slope. Many producing North Slope leases, including Prudhoe
Bay, used a form [DL-1] that was in use until 1979. The rights upon
termination provisions contained in the original and most current ADNR
Competitive Oil and Gas Leases are similar (see figure 9).[Footnote 16]
Specifically, both leases give the lessee the right to remove from the
leased area all machinery, equipment, tools, and materials. But the
leases also provide that ’when so directed by the state“ or ’at the
option of the state,“ the lessee may leave its infrastructure behind.
While the current lease termination provisions require the lessee to
rehabilitate the leased areas to the ’satisfaction of the state,“ ADNR
has not defined what constitutes the ’satisfaction of the state.“ The
older lease has no specific rehabilitation provisions, stating that the
lessee must ’deliver up said lands in good order and condition.“
Figure 9: Alaska Department of Natural Resources Past and Recent Rights
upon Lease Termination Provisions:
[Refer to PDF for image]
Termination Provisions of a State of Alaska Competitive Oil and Gas
Lease Form #DL-1 (Revised Oct 1963):
36. Rights Upon Termination. Upon the expiration or earlier termination
of this lease as to all or any portion of said lands, Lessee shall have
the privilege at any time within a period of six months thereafter, or
such extension thereof as may be granted Lessor, or removing from said
land or portion thereof all machinery, equipment, tools, and materials
other than improvements needed for producing wells. Any materials,
tools, appliances, machinery, structures, and equipment subject to
removal as above provided which are allowed to remain on said land or
portion thereof shall become the property of Lessor upon expiration of
such period; provided, that Lessee shall remove any and all of such
property when so directed by Lessor. Subject to the foregoing, Lessee
shall deliver up said lands or portion thereof in good order and
condition.
Termination Provisions of State of Alaska's recent Competitive Oil and
Gas Lease Form #DOG 200004:
21. Rights Upon Termination. Upon the expiration or earlier termination
of this lease... to remove from the leased area or portion of the
leased area all machinery, equipment, tools, and materials. Upon the
expiration of that period or extension of that period and at the option
of the state, any machinery, equipment, tools, and materials that the
lessee has not removed from the leased area or portion of the leased
area become the property of the state or may be removed by the state at
the lessee's expense. At the option of the state, all improvements such
as roads, pads, and wells must either be abandoned and the sites
rehabilitated by the lessee to the satisfaction of the state, or be
left intact and the lessee absolved of all further responsibility as to
their maintenance, repair, and eventual abandonment and rehabilitation.
Subject to the above conditions, the lessee shall deliver up the leased
area or those portions of the leased area in good condition.
[End of figure]
In addition to lease agreements, DR&R requirements are also addressed in
unit agreements. The unit agreement contains termination provisions that
are similar to those contained in the state oil and gas lease. For
example, Article 15 of the state‘s standard unit agreement for 2001
reads ’at the option of the State, all improvements such as roads,
pads, and wells must either be abandoned and the sites rehabilitated by
the Unit Operator to the satisfaction of the State, or be left intact
and the Unit Operator absolved of all further responsibilities...“
[Footnote 17] Similarly, the unit agreement states that the
’Unit operator shall deliver up the Unit Area in good condition.“ The
various owners of a unit are responsible for unit-wide DR&R. However,
DR&R requirements are not activated for leases that are organized into a
unit until the unit agreement is terminated, though the unit operator
may voluntarily elect to perform some DR&R prior to termination. An ADNR
official in the Division of Oil and Gas maintained that the state would
not release a unit operator from its unit-wide DR&R obligations until
all leases in the unit expired.
State Pollution Requirements:
In addition to well permit and lease requirements, the state has
established requirements and programs to address air and water
contaminated by pollution. The Alaska Department of Environmental
Conservation is charged with enforcing requirements for such things as
the disposal of drilling mud and cuttings, the flaring of hydrocarbon
gases, the discharge of wastewater, and the cleanup of oil spills.
While many of these responsibilities affect oil company‘s ongoing
activities, ADEC also determines if hazardous substances, including
oil, have contaminated a site following oil industry activities. ADEC
has standards to which a site must be minimally cleaned before it is
considered uncontaminated. For example, ADEC has overseen the cleanup
of oil company reserve pits in which drilling wastes were contained.
DR&R Requirements in the Corps of Engineers Permits:
The U.S. Army Corps of Engineers issues permits to oil companies on the
North Slope. These permits contain very general dismantlement, removal,
and restoration requirements and only rarely contain specific
requirements. Corps permits are issued under a variety of statutes for
actions that affect wetlands or navigable waters whether located on
federal, state, local, native, or private lands.[Footnote 18] Of these
authorities, section 404 of the Clean Water Act, which allows for the
placement of fill or dredged material, such as gravel for the
construction of roads, pads, and airstrips, is the most common type of
permit that the Corps issues in the North Slope. The Corps‘ DR&R
requirements are contained in its permits as a general condition, which
states that upon abandonment, the Corps ’may require restoration of the
area.“[Footnote 19] The level of restoration that may be required is
not specified in Corps regulations nor is it generally specified in the
permit. Corps of Engineers officials noted that Corps permits are
issued for all types of operations involving wetlands throughout the
United States. As such, they indicated that their permits‘ general
restoration language provides more flexibility to adapt the level of
restoration to site-specific needs. Corps officials told us that
specific restoration requirements, such as gravel removal upon
abandonment of a site, are generally not appropriate, but may be
warranted under special circumstances. In these instances, specific
restoration requirements are established as special conditions to the
permit. For example, the permit for the placement of gravel in the
Alpine oil field in the Colville River Unit contains special conditions
specifying areas where the permittee will remove the gravel,
rehabilitate the gravel footprint area, and restore the hydrology of the
project area upon abandonment. For other permits, when special
circumstances do not occur, Corps officials stated that restoration
requirements are better determined at the time of abandonment. The Corps
was unable to determine how many of its more than 1,100 North Slope
permits carried special conditions regarding dismantlement, removal, and
restoration, though officials estimated that less than 1 percent of all
their permits contained such conditions.[Footnote 20]
In addition to the permit itself, the Corps can also incorporate DR&R
requirements into abandonment plans. The Corps requires permit holders
to submit an abandonment plan when an oil company is planning to
abandon a site. As of May 2001, only seven abandonment plans have been
submitted, five of these stemming from offshore oil industry activities.
According to Corps officials, the initial requests for abandonment
plans do not contain minimum restoration requirements. Corps officials
noted, however, that approved plans do contain site-specific restoration
requirements. For abandonment of offshore facilities, such as gravel
islands, removal of gravel would likely only be required if the gravel
were found to be contaminated. For such projects in deep water, the
abandonment requirements call for the removal of gravel bags used for
erosion protection, removal of all hardware, plugging the well, and
allowing the gravel island to erode naturally into the sea.
Corps of Engineers officials stated that the landowners or land manager
should bear the primary responsibility for establishing DR&R
requirements. In the case of current oil production on the North Slope,
the landowner is the state of Alaska. Corps officials state that the
Corps typically works with the state to determine appropriate
dismantlement, removal, and restoration requirements and generally
accepts the state‘s recommendations, provided that important aquatic
resources are protected and there are no overriding factors of national
public interest. For example, the Corps approved the abandonment of
several offshore exploratory islands that were subject to state leases
and state-imposed DR&R requirements. Alaska‘s Department of Natural
Resources established the DR&R requirements for the oil companies:
plugging and abandoning the wells, removing all equipment, and allowing
the gravel islands to erode naturally. If disagreements occur between
the state and the Corps, they are usually resolved at the local level.
However, in most circumstances, the Corps retains the authority to
enforce its permit requirements for a site.
Local and Alaska Native DR&R Requirements:
While the North Slope Borough and two Alaska Native corporations have
the authority to impose DR&R requirements for certain North Slope oil
fields, this authority is not always exercised; when it is, the
requirements that are established vary.[Footnote 21] Specifically, the
North Slope Borough has zoning authority over state and privately owned
lands within its boundaries. The borough‘s Department of Planning and
Community Services is responsible for ensuring proper land use through
the zoning process. While the zoning regulations give the borough the
authority to require a DR&R plan as a condition for project approval,
an official stated that the borough has not required such a plan for
any oil industry activities on the North Slope. Instead, the official
stated, the borough would coordinate with state and federal authorities
to develop dismantlement, removal, and restoration requirements as part
of any abandonment plan.
The Kuukpik Corporation, which represents the Nuiqsut Village, owns a
portion of the surface land on which the Alpine oil field is located
(part of the Colville River Unit). According to the General Manager of
the Kuukpik Corporation, a 1997 surface use agreement between ARCO and
the Kuukpik Corporation requires that all chemicals and wastes, well
fixtures, equipment, fill, pads, roads, grading, and other improvements
be removed and all lands reclaimed and revegetated with native flora.
In implementing this agreement, the operator is to provide Kuukpik with
a plan for reclamation prior to initiating any activities. According to
a Kuukpik official, although the corporation has not yet enforced this
aspect of the agreement, it is confidant that the oil company will meet
its DR&R obligations.
The Arctic Slope Regional Corporation, which shares subsurface rights
with the state of Alaska for certain oil leases, including those in the
Alpine oil field, by statute must defer to the state regarding
termination provisions in the lease agreement. Specifically, the joint
ASRC and ADNR oil and gas lease for the Alpine field states that at the
option of the state, all improvements such as roads, pads, and wells
must be abandoned and the site rehabilitated by the lessee to the
satisfaction of both the state and ASRC. With regard to whether a
lessee satisfactorily completes DR&R, an ASRC official stated that the
lessee would need to satisfy the state, ASRC, and any village
corporations that may have surface ownership.
Parties Disagree on Whether State Requirements Should Be More Specific:
The state of Alaska, oil companies, and environmental groups hold
different opinions on the adequacy of the state‘s current DR&R
requirements. State officials believe that their DR&R requirements are
sufficient and allow for greater flexibility to maximize eventual DR&R
activities. Oil companies operating on the North Slope, while finding
the state requirements to be acceptable, would prefer more specific
guidance that allows them to better plan and estimate their future DR&R
liability. Because the state has not specified what DR&R it will
ultimately require, the oil companies have made different assumptions
on their levels of liability. Finally, representatives from some
environmental groups in Alaska believe that the state requirements are
too vague and could allow the oil companies to walk away from their
responsibilities. The general lack of agreement on what the
requirements should be has led the state to not develop a land use plan
for the North Slope.
State Officials View Alaska‘s DR&R Requirements as Sufficient:
State of Alaska officials, including the Governor‘s Special Counsel,
Alaska‘s Commissioner of Revenue, and the head of the Oil, Gas, and
Mining Section of Alaska‘s Attorney General‘s office, stated that
specific dismantlement, removal, and restoration requirements are not
necessary for the restoration of the North Slope. They maintain that
the DR&R requirements contained in state oil and gas leases are clear
and contractually enforceable. Specifically, one state official
emphasized, the principal requirement to close a lease is to dismantle
and remove structures, equipment, and personal property, and to restore
the land to a condition that is satisfactory to the state. He noted
that this could include returning the site to its original condition.
The oil companies, state officials maintain, have cooperated with the
state to date and have cleaned up some contaminated sites on the North
Slope, even those where others caused the contamination. According to
these state officials, general requirements are preferable to specific
requirements because they provide the state and the oil companies with
more flexibility. Specifically, given the fact that no one can predict
when North Slope oil production will cease, general requirements allow
the state to hold out for new technologies and processes that may
change DR&R requirements. For example, until 1987, it was standard
practice to contain drilling wastes in reserve pits. However, following
a lawsuit by environmental groups, North Slope operators have developed
and adopted a practice of grinding and re-injecting the wastes into the
subsurface, a practice that the state and environmental groups prefer.
Oil Companies Accept the State‘s DR&R Requirements, but Would Prefer
More Specific Guidance:
Oil companies told us they accept the state‘s broad DR&R requirements.
The companies agree that general requirements provide flexibility to 1)
evaluate each site on its own merits and tailor restoration
accordingly, 2) allow for changes in technology that affect how DR&R is
performed, and 3) allow for changes in land use decisions. However, the
two major operators on the North Slope”BP and Phillips Petroleum”also
stated a preference for more specific DR&R guidance and policy from the
state. According to spokesmen from these two companies, more specific
guidance would allow the oil companies to better plan for existing
activities and allow the companies to make better, cost-based
restoration decisions. Currently, the general requirements have
resulted in uncertainty surrounding the issue of how much
infrastructure and gravel will be left in place. For example, an
ExxonMobil spokesman stated that his company currently assumes that
the state will only require a minimal amount of gravel to be removed on
the North Slope; for this reason, the company does not include the cost
of gravel removal when estimating its future DR&R liability. A Phillips
Petroleum spokesman stated that his company assumes that some gravel
will have to be removed, but could not specify how much. Finally, a BP
spokesman stated that his company anticipates leaving some gravel in
place, but also could not disclose the amount. He also stated that the
Endicott Production Islands (Duck Island Unit)”two man-made gravel
islands connected to shore by a 5-mile gravel causeway”would most likely
be left in place and allowed to erode naturally after all the associated
facilities are removed (see figure 10).
Figure 10: Endicott Production Islands:
[Refer to PDF for image]
Photograph of Endicott Production Islands.
Source: Arctic Power.
[End of figure]
Environmental Groups Consider State DR&R Requirements Inadequate:
Environmental groups in Alaska are critical of the state‘s DR&R
requirements because the requirements are, in their view, vague and
indefinite. Officials from the Trustees for Alaska, the Alaska
Conservation Foundation, and the Sierra Club stated that the state‘s
general requirements provide no assurance that DR&R will ever occur.
Some officials believe that the state will waive oil company liability
for performing DR&R on the North Slope in exchange for the production
of oil that is only marginally profitable for the companies. The
officials explained that the state has very little incentive to impose
DR&R costs on the same oil companies that serve as the principal source
of state revenue and payments to state residents. They believe that if
the state must choose between oil companies spending money on
dismantlement, removal, and restoration or spending money on new oil
production, the state will choose new oil production. These groups cite
several historical examples, from the limited environmental review that
took place before the initiation of oil industry activities on the North
Slope to the current need for the state‘s reserve pit cleanup program”
begun only after environmental groups settled a lawsuit with ARCO for
violating the Clean Water Act.
Lack of Specific Requirements Reflects Disagreement within Alaska Over
the Extent of DR&R and the Future Use of the North Slope Land:
The state of Alaska once attempted to develop more specific DR&R
guidance for the North Slope, but internal disagreement over the extent
of restoration, including what gravel should be removed from the land,
derailed those efforts. In the early 1990s, a state-industry task force
was formed to clarify lease-closure policy. The task force recommended
that gravel be allowed to remain at certain sites after lease closure.
The state chose not to adopt this recommendation because Alaska‘s
Department of Fish and Game insisted on the complete removal of all
gravel and restoration of the land to its natural condition.
In addition, the state of Alaska has not developed a land use plan for
the North Slope or identified the condition to which the state would
like its lands returned after oil production ceases. Alaska‘s
Department of Natural Resources‘ Division of Mining, Land, and Water is
responsible for developing land use plans to guide the use,
development, and disposal of state lands. Thus far, a state official
reports, the ADNR has prepared area plans covering roughly 70 percent
of state-owned land. However, according to an official in the Division
of Mining, Land, and Water, there is no land use plan for the North
Slope because its current use, resource development, is the state plan
for the area. Some state and Alaska Native officials have stated that
once oil production ceases, they believe the state should have a long-
term goal of guaranteeing that the North Slope would support wildlife
habitat and native subsistence.
Alaska‘s DR&R Requirements Are Similar to Some States‘, but Less
Explicit Than Others‘:
DR&R requirements in the major oil-producing states vary; some states
have general requirements like Alaska‘s, while others are much more
explicit. We surveyed dismantlement, removal, and restoration
requirements in nine other states: California, Florida, Louisiana,
Michigan, New Mexico, Oklahoma, Pennsylvania, Texas, and Wyoming. In
total, these nine states and Alaska account for nearly 90 percent of
the oil produced in the United States, excluding federal offshore
production. All nine states surveyed have an oil and gas regulatory
structure that is similar to Alaska‘s. Specifically, all 10 states have
one office that regulates oil and gas industry activities at the
wellhead (similar to AOGCC) and another office that manages oil and gas
leases on state-owned lands (similar to ADNR).
All the states we surveyed have specific requirements for plugging and
abandoning oil and gas wells that are similar to Alaska‘s. However,
whether these wellhead requirements contained specific surface
restoration requirements varied. For example, while well-plugging and
abandonment provisions in all the states we surveyed mandated the
removal of surface material and the filling and closure of all holes,
only four states”Florida, Oklahoma, Pennsylvania, and Wyoming”mandated
revegetation of the surface area, while only three states”Florida,
Oklahoma, and Wyoming”mandated returning the site to a natural
condition. Alaska, California, Louisiana, and New Mexico reported no
such requirements.
We found greater variance in the survey responses regarding
dismantlement, removal, and restoration requirements found in state oil
and gas leases. For example, Florida requires a site to be restored to
original condition to the greatest extent practicable. California
reported that specific DR&R requirements are not determined until
completion of an environmental review under the California
Environmental Quality Act. In contrast, New Mexico, Oklahoma,
Pennsylvania, and Wyoming reported that their oil and gas leases have
mandatory requirements to remove surface material, such as equipment,
debris, and structures; close holes; and revegetate the area upon lease
termination. DR&R requirements in Alaska‘s oil and gas leases can
require the lessee to rehabilitate the roads, pads, and wells ’at the
option of the state.“ (See appendix I for additional information on
DR&R requirements in the states we surveyed.)
[End of section]
Chapter 3: Actual Cost of DR&R Is Unknown, but Likely to Cost Billions
of Dollars:
The actual cost to dismantle and remove oil industry infrastructure and
restore the land on Alaska‘s North Slope cannot be determined, but
several indicators show that it is likely to amount to billions of
dollars. Estimating the eventual cost of these actions is complicated
by several factors, including the lack of specific requirements from
the state and uncertain timeframes for restoration. Oil companies
operating on the North Slope are the only entities that have estimated
future dismantlement, removal, and restoration costs. Under generally
accepted accounting principles, companies are required to report their
liabilities annually, but these estimates are reported in aggregate for
worldwide operations and specific estimates for the North Slope are not
available to the public. However, limited information obtained from oil
company annual reports, a tax court case, and other sources indicates
that the current DR&R liability for existing infrastructure on the
North Slope is in the billions of dollars.
Costs Depend on What DR&R Will Be Required, Which is Uncertain:
Oil company spokesmen gave us two reasons that explain why estimating
future DR&R costs for the North Slope is difficult. First, lacking
specific federal, state, and local DR&R requirements, oil companies
must make assumptions about the amount of DR&R they will ultimately be
required to perform. A Phillips Petroleum spokesman pointed out that it
is hard to develop a cost estimate for removing infrastructure when one
does not know what infrastructure will be removed and what will remain
in place. He explained that the state and local governments might
decide to keep some of the infrastructure, such as roads and airstrips,
but that determination has not been made and probably will not take
place until after oil production ceases. Spokesmen from ExxonMobil and
Phillips Petroleum stressed, for example, that estimating future DR&R
costs is dependent upon gravel removal requirements.
Second, the length of time remaining in the life of oil production on
the North Slope”20 to 30 years or more based on estimates of the
economic viability of the North Slope oil fields and the Trans-Alaska
Pipeline System”combined with the potential development of natural gas
production adds further uncertainty to estimating DR&R costs. Spokesmen
from five oil companies that currently have ownership interests in oil
production on the North Slope told us that a number of other factors
could change over time and could also affect their eventual DR&R costs,
including:
* the addition of new infrastructure”wells, pipelines, roads, airstrips,
and production facilities”as development continues;
* dismantlement and removal of some facilities, including the plugging
of wells, before units are abandoned;
* increases in the cost of services such as labor and transportation;
* future market value of useable equipment and scrap material;
* technological advances in drilling, production, and rehabilitation;
* inflation;
* alternative uses for facilities or gravel, such as for natural gas
production; and;
* changes in environmental regulations or abandonment stipulations.
Oil Company Disclosures Provide Some Indication that DR&R Costs Will
Likely Be in the Billions of Dollars:
There is no definitive estimate of the cost of performing DR&R on the
North Slope, but available evidence suggests that the total liability
is in the billions of dollars. Generally accepted accounting principles
require that oil companies estimate their future DR&R liability, but
this liability only needs to be reported on a worldwide basis. Oil
company spokesmen told us that their individual company estimates for
DR&R liabilities on the North Slope were for internal use and not
available to the public. Companies fear that if they make their
internal estimates available, they could someday be used for a purpose
other than the accounting estimates they were intended to be.
Nevertheless, limited financial reporting, a tax court case, and a few
limited studies indicate that the costs are likely to be substantial.
Generally Accepted Accounting Principles Require Estimation of DR&R
Liability:
Generally accepted accounting principles require oil companies to
estimate their future DR&R liability. The Financial Accounting
Standards Board (FASB) and the Securities and Exchange Commission
require oil companies to estimate future DR&R costs in order to
determine annual depreciation and amortization rates.[Footnote 22]
However, accounting principles do not require oil companies to
separately report their DR&R liability for each operation, such as
those on the North Slope. The intent of these principles is to match
DR&R costs with associated oil revenue during the period in which the
oil is produced, rather than when the actual expense is incurred.
[Footnote 23] In contrast, environmental contamination treatment
costs”the costs to remove, contain, neutralize, or prevent existing or
future contamination”are generally expensed in the current period,
rather than capitalized, if the cost is probable and can be
estimated.[Footnote 24]
As a result of the differing treatment of asset retirement costs and a
desire to better disclose liabilities, the Financial Accounting
Standards Board recently issued new rules for disclosing asset
retirement liabilities. For financial statements issued for fiscal
years beginning after June 15, 2002, oil companies will have to report
the discounted amount of their DR&R liability at the time an asset is
placed into service.[Footnote 25] Spokesmen representing oil companies
that operate on the North Slope told us that they were uncertain, at
this time, how this new rule would be implemented or how it would
affect their companies‘ balance sheets.
Oil Company Estimates Are Not Available to the Public:
None of the five oil companies with substantial ownership interests in
current oil production on the North Slope were willing to provide their
estimated DR&R liability for these operations.[Footnote 26] Spokesmen
from these companies stated that their estimates have been calculated
for accounting purposes only and were not intended for public review.
While oil companies publish their worldwide liability estimates, they
are not required to make public regional or field-wide estimates. The
companies were reluctant to provide their accounting estimates for
purposes other than their own internal accounting. The BP spokesmen
stated that any current cost estimates may not be valid with tomorrow‘s
technology, and that costs calculated today represent a set of
assumptions that will probably differ from when the actual costs are
ultimately incurred.
Although no comprehensive estimates are available for future
dismantlement, removal, and restoration costs for the North Slope, there
are a number of indicators that, although not precise, imply that the
order of magnitude of such costs could be in the billions of dollars.
Specifically:
* Phillips Petroleum‘s acquisition of ARCO Alaska increased its total
DR&R liability by $1.6 billion. Phillips Petroleum reported in its 2000
annual report that its acquisition of ARCO Alaska increased its total
estimated future dismantlement, removal, and restoration costs from
$1.0 billion to $2.6 billion. Prior to the merger, ARCO accounted for 30
percent of the North Slope oil production.
* Abandonment costs are a function of construction costs. For the
proposed Liberty offshore project, MMS assumes that abandonment will
cost roughly 5 percent of the original investment cost. With an
estimated investment cost of $500 million, MMS estimated that the
planned Liberty project could eventually cost an estimated $25 million
to abandon. However, the MMS figure excludes gravel and pipeline
removal. In another case, a detailed DR&R study of TAPS estimated that
it will cost $1 billion (1977 dollars) or approximately 11 percent of
the original $9 billion (1977 dollars) construction cost to dismantle
and remove the pipeline and restore the land to a natural condition. A
recent study of oil and gas industry capital investment on the North
Slope from 1968 through 2001 estimated a cumulative investment of $20.6
billion (1977 dollars), which if revalued in 2004 dollars (the earliest
estimated time that major DR&R activities are assumed to begin on the
North Slope) would be $53.6 billion.[Footnote 27] Estimating future
DR&R costs based on this investment level and a DR&R cost percentage
ranging from 5 to 11 percent of the total investment yields a DR&R
estimate of $2.7 billion to $6 billion for existing North Slope
infrastructure (2004 dollars).
* Exxon estimated nearly $1 billion in DR&R costs for oil wells and oil
production equipment and facilities at Prudhoe Bay. In a May 2000 U.S.
Tax Court case, Exxon submitted detailed engineering studies to support
its estimate that future DR&R costs for the Prudhoe Bay Field
infrastructure installed as of 1984 would total $928 million. (Exxon
estimated that its share amounted to 22 percent of this cost based on
its then current ownership percentage of the Prudhoe Bay field.) The
DR&R cost estimate excluded any gravel removal or revegetation costs.
The $928 million included $111.6 million in well-site DR&R costs”$85
million for plugging 645 wells and $26.6 million for closing the pits
next to the wells and cleaning up the 37 well sites. In 1970, the cost
of plugging each well was estimated at $131,976 (1980 dollars). While
the court found the estimated costs of well-plugging and related site
restoration reasonably estimable, the court stated that the estimated
DR&R costs relating to field-wide oil production equipment and
facilities located in the Prudhoe Bay oil field were not sufficiently
fixed and definite to base the tax accruals sought by Exxon. The court
noted that neither the Alaska Oil and Gas Conservation Commission
regulations for the years at issue, nor the particular oil and gas
leases involved, contained express language imposing fixed and definite
DR&R obligations on the oil companies relating to field-wide production
facilities located in the Prudhoe Bay oil field. The court further noted
that Alaska‘s general policy to permit development, while at the same
time insisting that the environment be preserved or, if necessary,
restored to the fullest reasonable extent, did not establish any
specific oil company DR&R obligations with regard to Prudhoe Bay that
could be legally recognized for federal income tax purposes. According
to ExxonMobil spokesmen, the company has already accrued $200 million
in dismantlement, removal, and restoration costs for its North Slope
operations, including its interest in Prudhoe Bay.
[End of section]
Chapter 4: Financial Assurances That Funds Will Be Available for
Projected DR&R Costs Are Limited:
Despite incurring responsibility for some costly dismantlement, removal,
and restorations that resulted from improperly abandoned sites, the
state of Alaska‘s current financial assurances cover only a small
portion of the potential cost of DR&R for existing infrastructure on
the North Slope. In the past, several drilling and service companies
that supported early North Slope oil industry activities went out of
business and improperly abandoned their operations and sites. Without
adequate financial assurances, the state of Alaska was left financially
responsible for the costs of dismantlement, removal, and restoration.
Oil companies currently operating on the North Slope have assisted the
state in this cleanup effort and are spending millions of dollars to
restore some of these abandoned sites. The state is the only entity on
the North Slope that requires oil companies to post bonds for their
activities on state lands. However, the state bond limits are set
without regard to the potential future costs of DR&R. The Corps of
Engineers, the local government, and Alaska Native landowners all have
the authority to impose financial assurances, but have never done so,
preferring to defer to the state. Still, in Alaska, where the cost of
restoration might be significant, bonding requirements are higher than
those of most other oil-producing states that we surveyed.
Previously Abandoned Sites on State Land Had Insufficient Financial
Assurances:
The state of Alaska is faced with a number of improperly abandoned sites
on the North Slope. Most of these sites were the result of early oil
industry activities by various oil companies and oil-related service
companies, some of which have gone out of business. The state has
identified 217 contaminated sites on state-owned North Slope lands;
many sites are the responsibility of various federal agencies based on
activities that occurred before statehood, as well as TAPS-related and
various oil and service companies. Of these, the state has cleaned up
and closed about 25 sites and is working with responsible parties, when
possible, to clean up the rest. The state does not know how many non-
contaminated sites on the North Slope also require DR&R.
The state has sought the assistance of the remaining North Slope oil
companies to help fund and, in some cases, perform the cleanup of
abandoned sites when no responsible party remains. For example, as part
of the BP-ARCO merger, the state obtained an agreement from BP and
Phillips Petroleum to clean up 14 abandoned North Slope sites. These
sites, called ’orphan sites,“ were suspected of being contaminated by
hazardous substances. One of the commitments BP and Phillips Petroleum
made under the agreement was to spend $10 million to assess these 14
sites and clean them up by 2007. Additionally, BP and Phillips
Petroleum agreed to identify, collect, and dispose of abandoned empty
barrels found on the North Slope. According to state officials, the
parties that caused the contamination or left the barrels are either
unknown or unable to clean up the sites. The officials noted that some
of these sites were contaminated and abandoned before environmental
requirements were established and during a period when the state had
little environmental oversight of activities on the North Slope.
Further, in many of these cases, the companies were operating under
state land use permits that contained minimal bonding requirements, not
state oil and gas leases. In these cases, according to these officials,
the state has little recourse against such companies. The state also
asserts that in the absence of its agreement with BP and Phillips
Petroleum, the state would have had to clean up the orphaned sites
using state funds and on a less aggressive schedule. By the end of
2001, the state and the oil companies had inspected the abandoned
contaminated sites, characterized them by type of contamination, and
ranked them by risk priority. The state and the oil companies had also
inventoried several abandoned oil drum sites, and the oil companies had
completed dismantlement, removal, and restoration at five of the orphan
sites.
One example of the dismantlement, removal, and restoration of a site
abandoned on state lands is an area called Service City. Oil field
service companies that operated near Prudhoe Bay used Service City.
Beginning in the mid-1960s, these companies, operating under state
leases, used the site for staging, servicing, and storing oil field
equipment and supplies. By 1986, the area was essentially abandoned,
leaving behind metal buildings, equipment, lead acid batteries, and
tons of other debris and waste. By 1989, the leases for this area were
not active, and some leases were in default for nonpayment of rent. As
a result, the state revoked the area leases in 1990. That same year, BP
took the lead for cleaning up Service City, working under a cooperative
agreement between the state and three oil companies”BP, ARCO, and
ExxonMobil. The cleanup and restoration of Service City is still
ongoing and, according to BP, has already cost about $2 million.
Alaska‘s Statewide Bonding Requirements for DR&R Cover Only a Small
Portion of the Potential Liability:
The state of Alaska‘s bonding requirements”established by the Alaska Oil
and Gas Conservation Commission for well sites and by the Alaska
Department of Natural Resources for oil and gas leases”cover multiple
purposes and if called by the state would only cover a small portion of
the potential total DR&R liability on the North Slope. AOGCC requires
each operator to post a single bond to ensure that every well in the
state is properly drilled, operated, maintained, repaired, and
abandoned. ADNR‘s bonding provisions also allow a company to post a
single bond to ensure its compliance with all lease conditions for all
leases in the state, including provisions for royalty payments to the
state and lease termination provisions. In both cases, the bond amounts
are far less than the cost to reclaim a single well site, let alone all
wells and other existing infrastructure on state-owned land on the
North Slope.
Alaska‘s Well-Site Bonding Requirements:
AOGCC‘s bonding requirements are insufficient to fully cover the cost of
well-plugging and abandonment liabilities on the North Slope. AOGCC
requires a bond of not less than $100,000 to cover a single well, or a
blanket bond of $200,000 covering all of an operator‘s wells in Alaska.
The bond remains in effect until the company abandons all wells covered
by the bond and AOGCC provides final location clearance. According to
its Commissioners, the AOGCC currently has blanket bonds from five
companies to cover all the wells on state-owned land on the North Slope.
With plugging and abandonment costs for a single well running as much as
$250,000, according to a 1991 state of Alaska legislative audit report,
current bonding could fund only a small fraction of plugging and
abandonment costs for all of the wells in the state, let alone the
thousands of wells on the North Slope. The same audit report
recommended that AOGCC increase its bond amounts.[Footnote 28] The
state did not adopt the audit report recommendation, and AOGCC
Commissioners acknowledge that bonding amounts are still inadequate to
fund all well-plugging and abandonment, particularly for companies that
operate many wells under a single blanket bond.[Footnote 29] However,
these officials noted that companies are now required to plug and
abandon wells that are no longer being used on an ongoing basis.
Alaska‘s Oil and Gas Lease Bonding Requirements:
Current ADNR bonding levels are far below the potential cost of
dismantling and removing existing infrastructure and restoring the land
used for oil industry activities on the North Slope. Although ADNR
regulations require a bond of at least $10,000 before oil companies can
commence operations in the state, an ADNR official stated that currently
ADNR requires a $100,000 bond for single well operations. ADNR
regulations also allow a lessee to furnish a statewide bond of $500,000
to cover all of its oil and gas leases in the state. In place of
separate bonds for each lease committed to a unit agreement, ADNR
requires the unit operator to furnish a statewide oil and gas lease
bond of $500,000.
The ADNR can also require an unusual risk bond in addition to single
well and statewide bonding requirements. State of Alaska regulations
provide the ADNR Commissioner with the discretion to require additional
financial assurances based on, among other factors, the degree of risk
involved for the operations proposed or conducted on the lease, which
includes, according to an ADNR Division of Oil and Gas official, the
financial background of the lessee. However, this official told us that
the ADNR has no formal mechanism or procedure in place to
systematically evaluate the creditworthiness of a lessee. ADNR has
required a lessee to post additional financial assurances in two cases.
Specifically, in 1998, the state required XTO Energy (formerly Cross
Timbers Oil Company) to post additional financial assurances before
approving its acquisition from Shell Oil of two offshore oil platforms
in the Cook Inlet.[Footnote 30] Later in 2000, ADNR required an oil
company in bankruptcy proceedings to post a $3.8 million bond prior to
obtaining approval to install a well platform in Cook Inlet.
Although state officials acknowledge that the financial assurances
obtained in oil and gas leases are minimal, they maintain that the
major operators on the North Slope are large corporations with the
capacity to pay their eventual DR&R costs. A state official also noted
that additional financial requirements, such as those imposed by the
state on XTO Energy, might become more common if current leaseholders
sold their interests to smaller companies as oil production on the
North Slope declined. According to a state official, as oil fields age
and oil recovery becomes marginally profitable, it is common practice
in the industry for the large operators to sell their interests to
smaller companies. Since these smaller companies may have fewer
resources to meet existing DR&R liabilities, the official noted that
the state might require additional financial assurances. However, the
state currently has no criteria to determine when additional financial
assurances are needed.
The Corps of Engineers, Local Government, and Alaska Native
Corporations Have Not Required Financial Assurances for DR&R
Activities:
The U.S. Army Corps of Engineers, the North Slope Borough, the Kuukpik
Village Corporation, and the Arctic Slope Regional Corporation have not
required oil companies to provide any financial assurances that funds
will be made available to perform DR&R when oil production ceases on the
North Slope. The Corps may attach financial assurance requirements to
its permits, but it has never done so on the North Slope. According to
the Corps, without specific restoration requirements, it is difficult
to quantify the size of the bond and, further, there is no need to
duplicate bonds required by other agencies. The Corps considers it the
responsibility of the landowner”in this case, the state of Alaska”to
ensure that funds are available to perform DR&R activities. The North
Slope Borough has financial assurance provisions in its zoning
regulations, but the borough‘s Director of Planning and Community
Service stated that they have not specifically required oil companies
to provide surety as a condition for zoning approval. Borough zoning
regulations accept evidence of self-insurance, proof of financial
responsibility, or the existence of sufficient surety filed with
another government entity as fulfilling the borough‘s surety
requirements. The Kuukpik Corporation‘s Surface Use Agreement
with Phillips Petroleum contains a provision that allows the
corporation to require financial assurances such as a performance bond
or letter of credit. However, the General Manager of the Kuukpik
Corporation stated that thus far, he does see a need for bonding since
future DR&R costs are undetermined. The ASRC‘s Director of Lands stated
that he relies on the state of Alaska bonding requirements to ensure
that funds will be available to perform DR&R.
Major Oil Companies Operating on the North Slope Do Not Believe Full
Financial Assurances Are Necessary:
Although the two major oil companies currently responsible for oil
production on the North Slope generally agree that the state‘s existing
bond amounts would not cover the potential cost of future DR&R, they do
not believe that increasing bond amounts is necessary. Spokesmen for BP
and Phillips Petroleum said that their companies would do whatever the
state ultimately decided in terms of DR&R, and both companies plan to
meet or exceed their DR&R obligations. The spokesmen also stated that
their companies have the assets to cover the costs of DR&R. Further,
the Phillips Petroleum spokesman noted that requiring full financial
assurances by increasing bond amounts ignores the fact that the
companies have already accounted for this obligation on their financial
statements. Additionally, spokesmen for both companies stated that all
the North Slope operators are well capitalized and, therefore, the
funding for DR&R is substantiated by the general credit of the
companies and their partners. The Phillips Petroleum spokesman noted
that, for this reason, the state has full assurance that whatever DR&R
is required will occur. A BP spokesman further noted that his company
has to behave in a responsible manner on the North Slope and elsewhere
in order to operate in the United States. Finally, spokesmen for both
BP and Phillips Petroleum added that instead of requiring the companies
to spend money on financial assurance, a more beneficial return for all
parties involved would result from allowing the companies to invest
their resources in more North Slope research”including technology
improvements for future DR&R”and for further exploration and
production.
Alaska‘s Bond Amounts Exceed Those of Most of the Other Oil-Producing
States We Reviewed:
Bond amounts required by Alaska for oil companies operating on the North
Slope are generally higher than those reported by the other nine oil-
producing states we surveyed. Like Alaska, the other nine states have
two offices that require bonding for oil and gas activities. These
states have an office (like Alaska‘s AOGCC) that regulates the
subsurface integrity of the oil or gas field and requires bonding to
ensure that each well is properly plugged and abandoned. Each state
also has another office (like Alaska‘s ADNR) that focuses on the
management of oil and gas leases on state lands, and these offices also
use bonds to ensure compliance with all the provisions of the lease,
including DR&R provisions.
Alaska‘s AOGCC‘s minimum bonding amounts of $100,000 for single well
bonds and $200,000 for statewide blanket bonds are generally higher than
the bonding requirements of the other states we surveyed. Except for
Alaska, Michigan, and Pennsylvania, the other states reported that the
actual amount of a single well bond is determined by the depth of the
well multiplied by an amount that ranged from $1 per foot to $10 per
foot of depth. Three states”California, Florida, and Michigan”reported
having higher blanket bonding levels than Alaska. Specifically,
California has a $1 million blanket bond that covers all of a company‘s
wells in the state, Florida has a $1 million blanket bond that covers a
maximum of 10 wells in the state, and Michigan has a $250,000 blanket
bond. In addition, Louisiana, Michigan, and Texas reported that their
blanket bonding amounts are based in part on the number of wells in the
state.
For oil and gas leases on state lands, only two states”California and
Pennsylvania”have financial assurance amounts greater than Alaska‘s.
California, with only offshore oil and gas leases, reported that current
assurances range up to $1.25 million. Pennsylvania assesses a well-
bonding requirement of up to $100,000 per well, and some of its leases
may contain numerous wells. Florida‘s bond amounts are the same as
Alaska‘s, while three other states”New Mexico, Oklahoma, and
Wyoming”reported having the discretion, like Alaska, to increase
bonding levels on a case-by-case basis. Finally, Texas and Louisiana
reported that they relied on their oil and gas well regulatory agency
for DR&R requirements and thus had no financial assurance provisions in
their oil and gas leases.
[End of section]
Chapter 5: Specific DR&R Requirements and Improved Financial Assurances
Should Be Considered for North Slope Federal Lands:
To date, most North Slope oil production has taken place on state-owned
lands and has, therefore, been subject to state DR&R requirements and
financial assurances. However, as oil production on state lands
declines, oil companies and the state of Alaska are looking to federal
lands”the NPR-A, the Arctic Refuge, and offshore”to maintain North
Slope oil production. Currently, DR&R requirements and financial
assurances for these federal lands vary, depending on the responsible
federal agency. For example, in the NPR-A, where only oil exploration
has occurred, BLM has not yet developed DR&R requirements for oil
production activities to meet its goal of returning disturbed land to
its previous use. Furthermore, although BLM regulations allow for
escalating bond amounts up to the full cost of DR&R, the current bond
amounts in the NPR-A would only cover a fraction of the potential
future DR&R liability. In contrast, for federally regulated offshore
oil activities, MMS has developed explicit DR&R requirements for both
oil exploration and production, and its bond amounts are based on an
escalating scale that depends on, among other things, the estimated
cost of future reclamation. Further, in the Arctic National Wildlife
Refuge, which the Congress is currently considering whether to open to
oil and gas development, no specific restoration goal or DR&R
requirements exist for reclaiming the refuge if oil production occurs,
and existing financial assurances are not adequate to cover the
potential cost of restoration. Historically, oil exploration on federal
lands on the North Slope was conducted through contracting for the
Department of the Navy and the U.S. Geological Survey (USGS). The Navy
exploration predated any DR&R requirements, and financial assurances
were through the federal government. Without DR&R requirements, early
oil exploration activities resulted in improperly abandoned well sites
and unrestored land”two problems that remain to this day.
In contrast to varying federal DR&R requirements and financial
assurances for oil industry activities on the North Slope, the Trans-
Alaska Pipeline System and the hardrock mining, coal mining, and
nuclear power industries have explicit DR&R requirements that are set
prior to the initiation of any activities. In addition, the federal
agencies with regulatory authority over these three sectors require
full assurance that funds will be available to meet these requirements.
As Oil Production on State Lands Declines, Development of Federal Lands
Is Being Pursued:
With oil production declining on state-owned lands, oil companies and
the state of Alaska are seeking to develop production on federally
regulated lands and waters of the North Slope. Three areas under the
jurisdiction of the Department of the Interior are being considered:
the National Petroleum Reserve-Alaska, which is managed by BLM; the
Outer Continental Shelf (OCS), which is managed by MMS; and the coastal
plain of the Arctic Refuge, which is managed by the Fish and Wildlife
Service. The status of oil industry activities in each of these areas
follows.
BLM manages the entire NPR-A, which according to USGS estimates holds
oil reserves of between 800 million and 15.4 billion barrels. Following
the completion of a 1998 Integrated Activity Plan/Environmental Impact
Statement (IAP/EIS) on the potential impact of oil activities in the
northeastern part of the NPR-A, BLM began to lease certain areas for oil
and gas exploration.[Footnote 31] By May 2001, oil companies reported
that they had discovered oil reserves in the NPR-A. The next step in
this process is for the oil companies to submit a production plan.
According to BLM, this may occur as early as 2003. However, before oil
production can begin, BLM must complete another National Environmental
Policy Act (NEPA) analysis, likely an EIS, to assess the environmental
effects of such production.
To date, the only offshore oil production from the Outer Continental
Shelf has occurred at BP‘s Northstar unit, which is located primarily
in state-regulated water. The Northstar field is estimated to contain
175 million barrels of oil. In 1998, BP submitted another development
and production plan to MMS for a proposed offshore project called
Liberty, which would have been located solely in federally regulated
water, 6 miles off of Alaska‘s north coast. BP estimated that the
Liberty field contained 120 million barrels of economically recoverable
oil. However, in January 2002, because of the high cost of developing
the similar Northstar field, BP announced plans to focus its resources
on its core oil production areas closer to Prudhoe Bay and to not
pursue development of the Liberty project as proposed at this time. BP
is re-evaluating alternative development strategies for this area. MMS
officials told us that other oil companies were still examining the
potential for oil exploration projects on the Outer Continental Shelf.
Finally, for the last 40 years, the Congress has been debating opening
the coastal plain of the Arctic Refuge (known as the ’1002 Area“) to
oil and gas exploration. The USGS estimates that federal lands in the
1002 area likely contain between 4.3 billion and 11.8 billion barrels
of technically recoverable oil, not all of which will be economically
recoverable.[Footnote 32]
DR&R Requirements for Federal Lands on the North Slope Vary:
Federal requirements for dismantling and removing oil industry
infrastructure and restoring federal land when production ceases vary
from agency to agency. Although BLM has an overall restoration goal for
the NPR-A, it has specific requirements only for plugging and abandoning
wells. Because only oil exploration activities have occurred in the NPR-
A, BLM has yet to develop DR&R requirements for when oil production
facilities are abandoned. The MMS has specific well-plugging and
abandonment requirements that require the removal of all obstructions
built for offshore oil activities. MMS can make exceptions to these
requirements based on an end-of-the-life project review. For example,
MMS requirements for some site-specific infrastructure, such as buried
pipelines and gravel islands constructed for drilling sites, are not
specified until the end of the field‘s productive life. While the FWS
has a general DR&R policy for oil industry activities in the National
Wildlife Refuge System, specific requirements are developed at
individual refuges. Because oil industry activities are not authorized
in the Arctic Refuge, FWS has not yet developed any DR&R requirements
for the refuge. Finally, the Corps of Engineers, which issues permits
for certain activities that result in the loss of wetlands and for
offshore structures, has the same very general restoration language in
its permits for activities on federal land as it does for those on
state land.
BLM Plans to Develop More Specific DR&R Requirements for the National
Petroleum Reserve-Alaska:
According to BLM‘s Field Manager in Alaska, BLM has an overall
restoration goal of returning any land disturbed by oil industry
activities in the NPR-A to a condition that is similar to its previous
use. To achieve this goal, BLM has developed an overall general oil
field abandonment standard for the northeast NPR-A as part of the
development of an Integrated Activity Plan/Environmental Impact
Statement. In addition, BLM has specific requirements for plugging and
abandoning all types of wells and specific DR&R requirements for oil
exploration activities. However, in the NPR-A, because the only oil-
related activities that have occurred to date involve exploration, BLM
has yet to develop DR&R requirements for oil production activities.
BLM‘s overall restoration goal for the NPR-A is to return the land to a
condition that will support its previous use. In developing its 1998
IAP/EIS for the northeast NPR-A, the BLM identified the previous uses
of the NPR-A to be primarily fish and wildlife habitat and subsistence
use. Specifically, several areas within the northeast NPR-A contain
wildlife habitat that includes important nesting, staging, and molting
habitat for a large number of water birds and shore birds and also
contains caribou calving and insect-relief habitat. The northeast NPR-A
also contains numerous water bodies that provide spawning, migration,
rearing, and over-wintering habitat for both anadromous and resident
species of fish. Fish harvested from these waters are an important
subsistence resource for the Alaska Native residents of Barrow and
Nuiqsut. In addition, residents of Nuiqsut obtain approximately one-
third of their subsistence diet from caribou.
In its 1998 IAP/EIS, BLM also developed a general DR&R standard for oil
industry activities in the northeastern part of the NPR-A. The standard
states that upon field abandonment or expiration of a lease, all
facilities shall be removed and sites rehabilitated to the satisfaction
of BLM. BLM may, however, determine that it is in the public‘s best
interest to retain some or all of the facilities at the site. In
addition, BLM has specific requirements for plugging and abandoning all
wells in the NPR-A, whether they are used for oil exploration
activities or oil production. Currently, the only oil-related activity
occurring in the NPR-A is exploration.
In addition to the general standard for oil field abandonment and
specific requirements for plugging and abandoning wells, BLM has also
developed specific requirements for oil exploration activities in the
NPR-A. For example, BLM requires that all exploration activities occur
during the winter months so that ice pads are used to support
exploration well rigs and ice roads are used to service the well sites.
According to BLM, these requirements limit the impact of exploration
activities on the surface area. Further, at the end of the exploration
season, BLM requires the companies to remove all drilling equipment and
supplies, haul all debris to an approved disposal site, and chip and
scrape ice pads to pick up any spills. Finally, after the ice pads and
ice roads melt in the summer, the companies are required to conduct an
inspection of each location and to pick up any remaining debris.
BLM officials stated that the agency plans to develop specific DR&R
requirements for oil production activities in the NPR-A when oil
companies apply for production permits. According to BLM officials,
once oil companies request production permits, BLM will be required to
conduct another NEPA analysis, likely an EIS. The officials stated they
plan to use the NEPA analysis process to develop specific measures,
including specific DR&R requirements, to mitigate the impact of oil
production activities in the NPR-A and return the land to a condition
that will support its previous use. Specifically, when a company
submits an application for development, BLM requires the applicant to
also submit a surface reclamation plan. Such a plan must be approved by
BLM and is made a condition of the permit. Reclamation of the land may
include reclaiming disturbed areas, reshaping topography, disposing of
waste, and revegetating affected areas. For example, surface
reclamation plans may require the reclamation of well pads by removing
the fill material to the approximate height of the original ground
contours and applying a specific seeding mixture to that land
during a particular time of the year.
Furthermore, BLM‘s current regulations require oil companies to submit
and obtain approval of well-abandonment plans before operators can begin
well-plugging and abandonment activities. Well-abandonment plans not
only address the plugging and abandonment of wells, but also include
plans for removing drilling equipment and reclaiming the disturbed
surface. In May 2001, oil companies conducting exploratory work in the
NPR-A announced their first oil discoveries. According to BLM
officials, the oil companies may submit production plans for these
areas within the next year.
MMS Has Specific DR&R Requirements for Offshore Oil Wells:
MMS has an overall goal of restoring offshore areas used for oil
industry activities to their previous condition. Specifically, MMS
regulations for offshore oil industry activities include specific well-
plugging and abandonment requirements and, for restoration, generally
require the removal of all obstructions in the water. For some site-
specific infrastructure, however, such as buried pipelines and the
gravel used to construct man-made islands, restoration requirements are
not specified until the end of the field‘s productive life.
MMS requires oil companies to submit a notice of intent to abandon a
well before the companies start abandonment operations. The notice must
show the reason for abandonment and include supporting data and a
description of the proposed abandonment work. For well-plugging and
abandonment, MMS regulations generally require that all structures be
removed and all wellheads, casings, and other obstructions be removed to
a depth of at least 15 feet below the seafloor or to a depth approved
by the district supervisor. However, on the North Slope, during the EIS
process for offshore projects, it was determined that specific
restoration requirements for site-specific buried pipelines and man-
made gravel islands used as drilling platforms would be determined
later. Specifically, MMS may allow pipelines to be cleaned and
abandoned in place if they constitute no hazard to navigation and
commercial fishing and do not interfere with other uses of the Outer
Continental Shelf. In addition, where oil companies have constructed
gravel islands in the Beaufort Sea to conduct oil exploration
activities, MMS has allowed these islands to erode naturally, as
opposed to requiring their removal. MMS says that it has consulted with
a federal/state task force that examined the effect of oil exploration
activity on biological resources in the Beaufort Sea. The task force
determined that leaving gravel islands in place is ecologically
preferable to removing them, because it causes the least amount of
disturbance. However, environmental groups and some local inhabitants
are still concerned about the environmental consequences of leaving the
islands in place. Finally, once an oil company completes its well-
plugging and abandonment efforts, MMS requires the lessee to submit a
well-abandonment report describing the manner in which the work was
accomplished and certifying that the area was cleared of all
obstructions. As of September 2001, there have been 30 exploratory
wells drilled in the Beaufort Sea. According to MMS, all 30 wells have
been permanently plugged and abandoned, and the drilling facilities
have been removed.
Initially, all oil-related activity in federally regulated waters off
the North Slope was exploratory. However, in November 2001, BP and the
Department of the Interior announced the first offshore oil production
activity on the North Slope at BP‘s Northstar project. Although the
Northstar facilities are located in state waters, the oil reservoir
extends into federal waters.[Footnote 33] Consistent with its
regulations, MMS will require detailed plans for the plugging and
abandonment of wells on federal leases.
Fish and Wildlife Service DR&R Requirements:
FWS has an overall goal of restoring to their original condition those
wildlife refuges in which oil industry activities occur. Specifically,
FWS has a general policy that requires the removal of all structures
and equipment when oil industry activities cease, as well as the
restoration of the area to its original condition, or as near to it as
possible. FWS does not have more specific restoration requirements for
oil activities that occur in the national wildlife refuge system.
Instead, FWS allows its individual refuge managers to develop more
specific restoration requirements, usually in consultation with BLM;
these requirements are imposed as conditions to BLM leases and permits
and to their own special-use permits and right-of-way permits.
Although oil industry activity is currently not permitted in the Arctic
Refuge, if the Congress were to authorize such activity in a manner
similar to other refuges, both BLM and FWS would manage it.
Specifically, BLM would regulate subsurface activities by issuing
drilling permits and would regulate the drill site surface area by
issuing oil and gas leases in which FWS would provide recommendations
on stipulations for all activities, including DR&R requirements. Under
the National Wildlife Refuge System Administration Act, the Secretary
of the Interior, through the FWS, manages surface activities within
refuges. Specifically, FWS would regulate the surface area not covered
by BLM leases through the issuance of special-use and right-of-way
permits. Special-use permits authorize commercial activities, such as
seismic surveys, in national wildlife refuges. Further, in Alaska,
Title 11 of ANILCA provides for rights-of-way across federal
conservation areas, such as the Arctic Refuge, for transportation and
utility systems.[Footnote 34] Specifically, right-of-way permits are
provided for the construction of such things as roads and pipelines
that are related to the commercial activity. These permits would
contain requirements for restoration, revegetation, and the curtailment
of erosion on the surface of the land. For example, in the Kenai
National Wildlife Refuge in Alaska, a right-of-way permit was required
for the reconstruction of a gravel road. The permit stated that upon
cessation of drilling operations, the company would remove culverts, re-
grade the roadway, and restore the area to its original topography and
drainage patterns.
The Corps‘ DR&R Requirements for Federal Lands:
The U.S. Army Corps of Engineers issues permits to oil companies on the
North Slope that contain very general dismantlement, removal, and
restoration requirements and only rarely contain specific requirements.
The Corps issues permits for certain actions that affect wetlands or
navigable waters regardless of land ownership. The Corps‘ DR&R
requirements are contained in its permits as a general condition that
states that upon abandonment ’restoration of the area may be required.“
This is the same language that is used in all Corps permits, including
those issued for oil industry activities on state-owned lands on the
North Slope.
For federal lands, the Corps‘ position on restoration requirements is
the same as its position on state-owned land; it believes that the
landowner holds primary responsibility for DR&R requirements. In the
case of the NPR-A, the Arctic Refuge, and the Outer Continental Shelf,
the landowner is the responsible federal resource management agency.
The Corps would prefer to accept the federal agencies‘ recommendations
for dismantlement, removal, and restoration of an area, provided that
important aquatic resources are protected and there are no overriding
factors of national public interest. However, the Corps does maintain
the authority to enforce the provisions of its permits if disputes with
the landowner occur.
DR&R Requirements in Current Legislative Proposals:
As of April 2002, the Congress had considered a number of bills and
amendments that would authorize the opening of the Arctic Refuge‘s
coastal plain to oil and gas industry activities.[Footnote 35] In some
cases, the bills and amendments included language that specified the
condition to which the lands used for oil and gas activities should be
returned after oil and gas production ceases. For example, in August
2001, the House of Representatives passed H.R. 4, which authorizes oil
and gas activities in the Arctic Refuge. Concerning land restoration,
H.R. 4 requires reclamation of the land to a condition capable of
supporting the uses which the lands were capable of supporting prior to
any oil exploration, development, or production activities, or, upon
application by the lessee, ’to a higher or better use“ as approved by
the Secretary of the Interior. H.R. 4 also requires the removal of all
oil and gas facilities, structures, and equipment upon completion of
operations. However, the bill also states that the Secretary of the
Interior may exempt from removal those facilities, structures, or
equipment that the Secretary determines would assist in the management
of the Arctic Refuge. A Senate bill and an amendment to open the Arctic
Refuge to oil and gas exploration, S. 388 and S.A. 3132, respectively,
contain a reclamation standard identical to that in H.R. 4.
The inclusion of the phrase ’or to a higher or better use“ to the
surface reclamation goal contained in H.R. 4, S. 388, and S.A. 3132
could compromise the guidance that the land be reclaimed to a condition
capable of supporting its previous use, which is predominantly wildlife
habitat. Under H.R. 4, S. 388, and S.A. 3132, if the lessee requests,
the restoration goal is subject to interpretation by the Secretary of
the Interior on what would be a higher or better use of the land.
According to a November 2001 report by the Congressional Research
Service that discussed legal issues related to proposed drilling in the
Arctic Refuge, under general zoning law, ’higher or better“ uses are
those that ’bring the greatest economic return.“[Footnote 36] As such,
those uses that are ’higher and better“ than undeveloped wildlife
habitat could include many possibilities, such as the development of
the area for tourism.
The reclamation requirements contained in H.R. 4, S. 388, and S.A. 3132
for the Arctic Refuge are similar to the state of Alaska‘s general
requirement for the dismantlement, removal, and restoration of its land
on the North Slope. As previously discussed, this general requirement
has resulted in differing interpretations of what will ultimately be
required in terms of dismantlement, removal, and restoration on the
North Slope by the parties involved. In April 2002, the Senate voted to
block S.A. 3132, which would have authorized drilling for oil and gas
in the Arctic Refuge. However, the Senate and House energy bills must
still be reconciled in conference, where, once again, members of
Congress have the opportunity to reconsider.
Assurances That Funds Will Be Available to Implement Federal DR&R
Requirements Are Limited:
Generally, existing bond amounts for oil industry activities for
federal lands on the North Slope will not cover the potential costs of
eventual dismantlement, removal, and restoration activities. Financial
assurances, such as bonds, can ensure that if a company defaults on a
lease or contract, the obligations will still be completed. The amount
of the financial assurance can be fixed or can vary and be based on,
among other things, such factors as the company‘s experience and
financial viability and the estimated cost of future restoration. While
BLM has some bonding requirements on its land and on FWS refuges, its
$300,000 bond for all leases a company holds in the NPR-A and its
$25,000 amount for a statewide bond on refuges are unlikely to meet all
restoration costs that could be incurred on the lands. Although both
BLM and MMS have the authority to ensure that full funding be available
for restoration activities, only MMS has implemented a general bonding
structure that provides for higher bond amounts as the scope of oil
industry activity increases. The Corps has not required any financial
assurance that funds will be available to conduct DR&R requirements as
part of its permit process on the North Slope.
In the NPR-A, the Bureau of Land Management requires oil companies to
post a bond for oil activities conducted on federally leased land. BLM
bonds are used to ensure compliance with all the terms of the lease,
including the payment of rentals and royalties and the performance of
DR&R. Specifically, BLM requires a minimum bond of $100,000 per lease,
or a $300,000 bond for all leases a company holds in the NPR-A, or a
rider upgrading a nationwide bond to $300,000.[Footnote 37] Currently,
most companies operating in the NPR-A have nationwide bonds; these bond
amounts will only cover a small fraction of the potential future DR&R
liability.
Although BLM has the authority to require full financial assurance to
fund the cost of DR&R, it has not yet done so. According to BLM
officials, its current bond amounts are not intended to cover the full
cost of future restoration activities, but instead serve as an
assurance of performance. Generally, BLM officials in Alaska do not
believe it necessary for major oil companies operating in the NPR-A to
provide full financial assurance that they will comply with their lease
requirements, including DR&R. BLM officials noted that these companies
are large international firms whose future business depends on the
successful completion of all lease requirements and whose total assets
will easily cover the full cost of DR&R. BLM‘s field manager in Alaska
stated that when the companies go from exploration to production in the
NPR-A, BLM plans to determine whether the existing bonding amounts are
adequate. At that time, if BLM deems it necessary, it can increase the
required bond amounts. In addition, this official noted that if a large
company sells its NPR-A interests to a smaller firm, BLM would again
review the need to increase bond amounts.
In national wildlife refuges, BLM also issues leases for oil
exploration, development, and production activities and requires
companies to post a bond. FWS may require additional bonding from
companies operating in a wildlife refuge as part of a right-of-way
permit. Specifically, in wildlife refuges, BLM requires a minimum bond
amount of $10,000 per lease, $25,000 for a statewide bond, or $150,000
for a nationwide bond. In addition, if oil companies‘ activities such
as the construction of roads or pipelines disturb refuge lands outside
the BLM leased area, FWS requires the companies to post bonds as part
of the process to obtain right-of-way permits.[Footnote 38] The amounts
of these bonds vary according to the scope and type of activity. FWS
does not prescribe a set amount for the bond. According to an FWS
official in Alaska, in the limited instances where FWS has required
bonds, the bonds have not exceeded $150,000. FWS officials stated that
they believe neither BLM‘s nor FWS‘s bonding requirements are
sufficient to cover the potential cost of future land restoration.
Some of the bills recently considered by Congress regarding the opening
of the Arctic Refuge to oil and gas development also address the
financial assurance issue. For example, S. 388 included a bonding
requirement to ensure the financial responsibility of the lessee.
Specifically, the Senate bill required the Secretary of the Interior to
establish bonding requirements ’to ensure the complete and timely
reclamation of the lease tract and the restoration of any lands or
surface waters adversely affected by lease operations after the
abandonment or cessation of oil and gas operations on the lease.“ The
bonding arrangement in S. 388 would have been in addition to any
existing bonding requirements that could be applied by the federal
agency or agencies responsible for managing oil industry activities in
the Arctic Refuge. Under S. 388, the Secretary of the Interior, in
accordance with an approved exploration or development and production
plan, would determine the specific amount of the bond or financial
arrangement. In contrast, H.R. 4 didn‘t address financial assurances or
contain provisions for bonding. Under this bill, bonding requirements
for the Arctic Refuge could be the same as those authorized for other
refuges. As previously discussed, requiring the minimum BLM and FWS
bond amounts would not be sufficient to cover the potential cost of
future land restoration.
MMS has the authority to require companies conducting operations in
federally regulated waters to provide full financial assurance that
funds will be available to conduct dismantlement, removal, and
restoration activities. MMS‘s bonding requirements for its offshore
leases on the Outer Continental Shelf are based on an escalating scale
and depend on what activity is occurring. Specifically, MMS regulations
state that every owner of an OCS oil and gas lease must maintain a
$50,000 lease bond or a $300,000 area-wide bond for all oil and gas
leases in the state. The intended purpose of these bonds is to ensure
compliance with all the terms and conditions of the lease. In addition,
if exploration or development and production activities occur, MMS
requires total bond amounts to increase to $200,000 and $500,000,
respectively.[Footnote 39] Furthermore, under MMS regulations, the
regional director has the authority to require additional bonding if a
determination is made that additional financial assurances are needed
to cover potential underpayment of royalties or obligations to remove
infrastructure, such as drilling platforms, and clear the seafloor of
obstructions. According to MMS officials, the complete bonding package
is intended to cover the delinquent royalties, abandonment, and final
site clearance and takes into account, among other things, the company‘s
experience and financial viability, as well as the estimated future
cost of restoration.
Previously Abandoned Oil Exploration Sites on Federal Lands Remain a
Problem:
The history of oil industry activities on federal lands of the North
Slope demonstrates the importance of adequate financial assurances for
the taxpayers. The federal government‘s oil exploration activities on
the North Slope have resulted in its current DR&R responsibility for
many improperly abandoned well sites. These well sites are now commonly
known as legacy wells. Starting in 1945 and continuing through 1981,
the U.S. Navy and the USGS drilled 126 wells in the area now known as
the NPR-A.[Footnote 40] According to BLM, the federal government is
currently responsible for the cleanup of 102 of these wells. Ownership
of the other 24 wells was transferred to the North Slope Borough to
assist in gas production for local use.[Footnote 41] According to BLM,
of the 102 wells, the Navy drilled 76 of them in the 1940s and 1950s,
and drilled a single well in 1975 that was properly plugged and
abandoned. The USGS was responsible for drilling the remaining 25
wells. According to BLM, 3 of the 25 USGS wells have been properly
plugged and abandoned, 1 has not been properly plugged and abandoned,
and USGS is currently using 21 for climate studies. According to USGS,
these study wells are extremely valuable for long-term climate
information and should remain unplugged. As a result of inadequate
dismantlement and restoration requirements, about 80 wells drilled on
federal lands under the federal government‘s direction remain
improperly plugged and abandoned.
The federal government is responsible for cleaning up the improperly
abandoned wells and drill sites. In 1976, the Navy initiated a cleanup
program for its own well sites, which USGS assumed in 1977. In later
years, USGS assumed responsibility for cleaning up both the Navy‘s and
its own sites. Although no precise records exist, during a 7-year
period the agencies collected and removed thousands of tons of debris
and over 50,000 55-gallon drums, at a cost of over $7 million (late
1970s and early 1980s dollars) from NPR-A sites. Additionally, in 1995,
the state‘s Department of Environmental Conservation decided that no
further cleanup work was required on 27 NPR-A drilling waste sites to
reduce their risk to the area‘s surface waters. However, according to
BLM officials, most of the abandoned wells and surrounding sites still
need additional work, including the proper plugging of wells and
restoration of the surface area. The officials also noted that some of
these legacy wells have leaked oil, gas, and other substances, and have
the potential to create a future environmental hazard. However, remote
locations and severe weather make it difficult to access the well sites
and very expensive to reclaim them. For example, in 1999, BLM
authorized a study of the cost to properly plug and abandon 11 Navy
well sites in the Umiat area of the NPR-A. The contractor conducting
the study estimated the cost to be almost $7 million. However, in 2001,
when the Corps of Engineers approved the plugging and surface
remediation of 2 of the 11 Umiat well sites under an existing contract,
the total cost had escalated to about $16 million. According to the
Corps, this cost escalation was caused primarily by increases in the
cost of accessing the area, unanticipated problems with plugging one of
the wells, and an increase in the amount of surface that needed to be
rehabilitated. Further insights on the cost of cleaning up of these old
well sites are provided in a September 2001 BLM draft internal working
document. The document estimates that just plugging the wells in NPR-A
will cost more than $100 million over the course of 10 to 20 years.
Another example of an abandoned site on federal land is at Sagwon,
Alaska. Sagwon served as an oil company aviation base and staging area.
It was built in the 1960s and was used commercially until the mid-1970s.
However, it was not until 1975 that the owner obtained a lease from BLM
to operate an airport on the property. In 1985, after the site had been
abandoned, BLM approached the lessee, asking it to remove roughly 4,500
metal drums and several tons of scrap metal, clean up unused drilling
fluids, and remove other miscellaneous debris left on the site. The
lessee refused and later filed for bankruptcy. In 1993, BLM asked oil
companies that may have used the airfield to help clean up the site. In
response, BP, ARCO, and Alyeska (TAPS‘s operating company) voluntarily
agreed to clean up the 2,500-acre site. According to BP officials, by
the time the cleanup was finished in 2000, it cost $2 million to
complete and required the removal of 138 tons of waste from the site.
Although the surface dismantlement, removal, and restoration is
finished, according to a BLM official, some subsurface issues remain.
DR&R Requirements and Financial Assurances for TAPS and the Mining and
Nuclear Power Industries Are Explicit:
DR&R requirements and financial assurances for similar infrastructure
and other energy-related industries are more explicit than those
applied to the oil industry on the North Slope. The Trans-Alaska
Pipeline System, which is similar in purpose and geography to other oil
industry infrastructure on the North Slope, has DR&R requirements and
fixed financial arrangements. TAPS established these requirements prior
to construction of the pipeline and negotiated the financial
arrangements later. Furthermore, both hardrock and coal mining have
reclamation requirements for surface lands that are determined before
the initiation of any mining activities. Federal regulators also
require mining companies to demonstrate full financial assurance that
these requirements will be met. Finally, decommissioning requirements
for all nuclear power plants are established by federal regulation; the
regulations also require financial assurances sufficient to fully fund
decommissioning.
DR&R Requirements and Financial Assurances for TAPS:
The Trans-Alaska Pipeline System has DR&R requirements contained in the
1974 right-of-way lease agreement between the federal government and the
state of Alaska. Specifically, the 30-year right-of-way lease contains a
stipulation that when the pipeline is no longer used (’completion of
use“) the lessee shall ’promptly remove all improvements and
equipment—and shall restore the land...“[Footnote 42] In general, this
stipulation has been understood to mean the complete dismantlement and
removal of the above-ground portion of the pipeline (the buried portion
of the pipeline would be purged of residue and capped in place) and
associated infrastructure and restoration of the land on which the
pipeline was built. The lease does not provide specific restoration
requirements; instead, it requires the lessee to restore the land to a
condition that is approved by federal and state officers. Even so, the
U.S. Tax Court found in May 2000 that ’in contrast to the generally
vague language of the [state] leases relating to oil company
[dismantlement, removal, and restoration] obligations— language in the
TAPS right of way—is more specific.“[Footnote 43]
Regarding financial assurances, the Federal Energy Regulatory
Commission, which regulates pipeline fees, permits the pipeline owners
(Alyeska) to collect tariffs from pipeline users sufficient to fully
fund eventual DR&R. The amount collected by TAPS‘s owners for DR&R has
varied by year of operation, ranging between $127 million in 1980 and
$2.4 million in 1999, for a total of $1.5 billion in collections
through 1999. The tariffs were last adjusted in 1985 under a settlement
agreement between the TAPS‘s owners, the state of Alaska, and the
Department of Justice.[Footnote 44] The pipeline‘s owners do not have
to place collected funds for DR&R in escrow or any other special
account. Instead, TAPS‘s owners can reinvest those funds as they
choose, but retain a liability to fund DR&R costs. If funds collected
exceed the cost of DR&R, as some assert they will, the owners of the
pipeline may realize additional benefits if they are not required to
refund excess funds collected.
Mining Reclamation Requirements and Financial Assurances:
The federal government requires other extractive industries, such as
hardrock mining and coal mining, to restore surface land that is
disturbed during mining operations and related activities. For example,
both BLM, which regulates hardrock mining on its lands, and Interior‘s
Office of Surface Mining (OSM), which regulates the surface aspects of
coal mining itself or through states with approved programs for
regulation of surface coal on any land, require operators to obtain
approval of their reclamation plans before mining operations can begin.
As part of the approval process, operators are required, by regulation,
to develop a reclamation plan that describes in detail how land that is
disturbed will be restored after mining activities cease. The plan must
describe how the operator will reclaim the land to meet specific
requirements, such as backfilling and grading the mine pit; reshaping
the disturbed land to blend with pre-mining natural topography;
achieving successful revegetation; and removing roads and structures
that are not approved for retention. Mining operators are required to
perform the activities specified in their approved reclamation plan or
face a financial penalty.
Both BLM and OSM require the hardrock and coal mining industries,
respectively, to provide financial assurance sufficient to cover the
full cost of reclamation before mining operations can begin. Under
federal regulations, companies that engage in hardrock mining on BLM
lands or surface coal mining on any lands must submit a cost estimate
for the DR&R activities specified in their reclamation plan before the
start of mining activities. The cost estimate must represent the full
amount that the regulatory authority”BLM, OSM, or state”would need to
reclaim the disturbed area if the mining operator were unwilling or
unable to complete the planned reclamation. The estimate must also
include the regulatory agency‘s cost to contract with a third party to
do the work and administer the contract. Mining operators may provide
financial assurance in many different forms, such as pledged assets of
the operator including cash, certificates of deposit, negotiable bonds,
and investment-grade securities; surety bonds; or irrevocable letters
of credit.
Nuclear Power Decommissioning Requirements and Financial Assurances:
The Nuclear Regulatory Commission, the federal entity that regulates the
nation‘s civilian use of nuclear power and materials, requires its
licensees, as a condition for obtaining a license to operate a nuclear
power plant, to agree to decommission (i.e., clean up) the plant after
operations cease. The commission has specific requirements for
acceptable radiation levels that decommissioning must accomplish. Such
requirements vary depending upon, among other things, the proposed
future use of the land. For example, a decommissioned site may have
unrestricted future use if the residual radiation at the site would not
cause a person to receive a total effective dose equivalent in excess
of 25-millirems of radiation per year after decommissioning, and this
level of reduction is as low as is reasonably achievable.[Footnote 45]
The commission does not require the licensee to submit a
decommissioning plan before obtaining a license. Rather, within 2 years
following permanent cessation of a plant‘s operations, the licensee
must provide the commission with a plan describing the decommissioning
activities that the licensee will perform to meet a radiation standard.
Such activities may include removing the spent nuclear fuel, dismantling
structures containing radioactive materials that were created in the
power-generating process, and removing other materials that were
contaminated during the process. The Nuclear Regulatory Commission does
not release the plant licensee from its liability for the site until
decommissioning is completed and the license is terminated.
Nuclear power plant licensees must also provide financial assurance that
the decommissioning work will be done, and must provide the assurance
before plant decommissioning begins. Beginning at plant licensing, and
at various times throughout a plant‘s operations, the commission
reviews the adequacy of the financial assurance. The financial
assurance amount must be equal to or greater than the amount specified
in the commission‘s regulations; amounts are based on the type of
reactor and its power level. Plant licensees may provide financial
assurance in one or more of the following ways:
* periodic deposits (at least annually) into a trust fund outside of the
owner‘s control;
* prepayment of the entire estimated decommissioning liability into a
trust fund outside of the owner‘s control;
* obtaining a surety bond, insurance, letter of credit, or line of
credit payable to a trust established for decommissioning costs; or;
* guaranteeing the payment of decommissioning costs, provided that the
guarantor (usually an affiliate or parent company of the owner) passes
specific financial tests.
Conclusions:
In the past, the lack of dismantlement, removal, and restoration
requirements and inadequate financial assurances have led to some
improperly abandoned sites and subsequent environmental problems on
both federal and state land located on Alaska‘s North Slope. To date,
most oil production has occurred on state-owned land, and for this
reason the state of Alaska has borne responsibility for cleaning up
these sites when oil companies or their related industries have failed
to do so. However, with oil exploration activities underway in the NPR-
A and on the Outer Continental Shelf, and the Congress currently
debating whether to open the Arctic Refuge‘s coastal plain to oil and
gas development activities, the need for federal dismantlement,
removal, and restoration requirements, and assurances that funds will
be available to implement those requirements, is becoming increasingly
important. Presently, the Bureau of Land Management has not established
specific DR&R requirements for oil production activities in the NPR-A.
In addition, its current minimum bond amounts are fixed, do not reflect
differences in company experience and financial viability, and would
only cover a fraction of the potential future cost of DR&R.
Furthermore, since the Congress has not yet authorized oil and gas
industry activities in the Arctic Refuge, neither the Bureau of Land
Management nor the Fish and Wildlife Service has developed specific
DR&R requirements for the refuge. The Fish and Wildlife Service, like
the Bureau, uses bond amounts that are not sufficient to meet the
potential future cost of restoration. Both agencies need to ensure that
their financial guarantees are adequate in case a company is unwilling
or unable to pay for returning the land to whatever standard has been
established. To do otherwise would leave the taxpayer with an
unacceptable risk.
Paramount to the development of any DR&R requirements should be a
determination of what the ultimate restoration goal of these areas
should be. In the NPR-A, this decision has been made; that is, the
Bureau wants the land returned to a condition that will support its
previous uses, such as fish and wildlife habitat and subsistence use by
Alaska Native villagers. What remains to be done is for the Bureau to
establish specific DR&R requirements that will allow companies to meet
that goal. Should the Congress decide to open the Arctic Refuge to oil
industry activities, it would be important for the Congress to consider
establishing a legislatively mandated restoration goal for the
disturbed area. This would allow the Secretary of the Interior to
establish specific DR&R requirements aimed at meeting that goal. In
turn, specific requirements would provide oil companies with another
piece of information they need to make better investment decisions on
whether the potential benefits of oil industry activities in the Arctic
Refuge are worth the cost. Goals, like all plans, can change over time.
However, if a restoration goal for the Arctic Refuge is not established
before oil exploration begins, there will only be continued debate
similar to that faced by the state of Alaska on its restoration
requirements for state-owned land on the North Slope. In addition,
establishing a mechanism that would ensure that funds were available to
meet those requirements would protect taxpayers, should lessees
default.
Recommendations for Executive Action:
In order to ensure that the lands of the National Petroleum Reserve-
Alaska are properly restored after oil and gas activities there cease,
we are recommending that the Secretary of the Interior instruct the
Director of the Bureau of Land Management to issue specific
dismantlement, removal, and restoration requirements that will allow
the BLM to meet its overall goal of returning the land to a condition
that will sustain its previous uses, including fish and wildlife
habitat as well as subsistence uses. In addition, we recommend that the
BLM review its existing financial assurances for oil and gas activities
in the National Petroleum Reserve-Alaska to determine whether they are
adequate to ensure the availability of the funds needed to achieve its
overall restoration goal.
Matter for Congressional Consideration:
Any future decision to open additional federal lands to oil and gas
activities, including those on Alaska‘s North Slope, is a public policy
decision that rests with the Congress. In making such a decision, one
factor that would be important to consider is the restoration of the
land after oil and gas activities are completed. If the Congress wants
to provide guidance on the condition to which these lands should be
returned following the completion of such activities, it should
consider providing in the authorizing statute:
* a restoration goal that will allow the federal agency or agencies
responsible for developing dismantlement, removal, and restoration
requirements to have a clear understanding of what the Congress wants
achieved, and;
* specific assurances that the federal agency or agencies responsible
for implementing dismantlement, removal, and restoration requirements
will obtain adequate financial assurances that funds will be available
to meet the goal of returning the land to a condition that the Congress
has specified.
Agency Comments and Our Evaluation:
The Department of the Interior agreed with our recommendation that the
Bureau of Land Management issue specific dismantlement, removal, and
restoration requirements that will allow the Bureau to meet its overall
goal of returning the land to a condition that will sustain its
previous uses, including both fish and wildlife habitat and subsistence
uses. The department stated that the Bureau plans to accomplish this by
attaching special stipulations and conditions of approval on a lease-by-
lease basis. The state of Alaska, however, disagreed with this
recommendation. The state commented that dismantlement, removal, and
restoration requirements can be better addressed when oil production
ceases and the obligation actually becomes due. The state believes that
this approach provides greater flexibility and will allow the state to
ultimately issue requirements that reflect changes in, among other
things, technology and the regulatory environment. The state also
commented that our recommendation does not recognize the scope of the
government‘s power to change the regulatory standards it adopts and
ignores the fact that specific standards that seem appropriate today
may not be appropriate at some distant point in the future. We did not
draw any conclusions nor make any recommendations concerning the
appropriateness or inappropriateness of the state of Alaska‘s current
dismantlement, removal, and restoration practices for its lands.
Currently, the state has no restoration goal for its North Slope lands
that have been used for oil and gas activities. Without a restoration
goal, we agree with the state that it would be difficult to issue
specific DR&R requirements. We also acknowledge in our report that
restoration goals and the specific processes used to achieve those
goals can change as technology, science, and circumstances change.
However, the Bureau of Land Management has established a restoration
goal for its lands used for oil and gas activities in the National
Petroleum Reserve-Alaska. That goal is to return the lands to a
condition that will sustain its previous uses, including both fish and
wildlife habitat and subsistence uses. As such, we believe, and the
Department of the Interior concurs, that it is appropriate for the
Bureau to establish specific dismantlement, removal, and restoration
requirements to achieve that goal prior to the initiation of oil
production activities. Doing so will provide the oil companies with
better information on what is expected of them, which will allow them
to make better investment decisions, and if they decide to proceed,
will allow for better planning and budgeting to achieve restoration.
The state of Alaska also commented that it disagrees with GAO that the
Congress, when considering opening additional federal lands to oil and
gas activities, should consider establishing a restoration goal for
that land in the authorizing statute. In general, the state believes
that, as with dismantlement, removal, and restoration requirements,
restoration goals can be better set at some future date closer to the
actual time that oil and gas activities cease. The state points out in
its own comments that both oil companies and environmentalists, two
groups that are usually opposed, would prefer to know what restoration
activities the state has planned for the North Slope because each
currently perceives a risk that their view of the appropriate level of
DR&R may not be adopted by the state in the future. By recommending the
establishment of restoration goals for federal lands prior to the start
of oil and gas activities, it is our intent to alleviate such concerns
and allow all interested parties the opportunity to make informed
decisions on these matters before the land is used. Further,
establishing goals prior to oil and gas activities would provide for
greater transparency and allow for agreements to be reached on what
restoration will be required.
The Department of the Interior also agreed with our recommendation that
the Bureau of Land Management review its existing financial assurances
for oil and gas activities in the National Petroleum Reserve-Alaska to
determine if they are adequate to ensure that funds will be available
to achieve its overall restoration goal. The department stated that
this review would focus on protecting the environment and taxpayers,
should lessees default. The state of Alaska, however, commented that it
disagrees with this recommendation. According to the state, GAO is
suggesting that financial assurances greater than those required by the
state of Alaska should be adopted for federal lands on the North Slope,
even though Alaska‘s bonding requirements are among the highest in the
nation. Our report does not make any comparison of the state of
Alaska‘s financial assurances to those of federal agencies that manage
land on the North Slope. Further, the report does not make any
determination regarding what level of financial assurance should exist.
GAO does report that the Bureau‘s current minimum bond amounts are
fixed, do not reflect differences in oil company experience and
financial viability, and would only cover a fraction of the potential
future cost of DR&R. We also state that the level of financial
assurance required will vary depending on such factors. As a result, we
continue to believe that the Bureau should review its existing
financial assurances for oil and gas activities in the National
Petroleum Reserve-Alaska to determine whether they are adequate to
assure the availability of funds necessary to achieve its overall
restoration goal for the land after oil and gas activities cease.
[End of section]
Appendix I: Comparison of Alaska‘s DR&R Requirements and Financial
Assurances with Those of Other Oil-Producing States:
The following tables summarize information that we collected on DR&R
requirements and financial assurances from 10 oil-producing states,
including Alaska. These 10 states account for nearly 90 percent of the
domestic oil production in the United States, excluding federal offshore
production. The states are Alaska, California, Florida, Louisiana,
Michigan, New Mexico, Oklahoma, Pennsylvania, Texas, and Wyoming. We
selected these states based on U.S. Energy Information Administration
projections of their 1999 oil production and their geographic
diversity.
Table 4 shows that as reported by oil well permitting agencies in each
state, all the states have mandatory surface restoration requirements
for drill sites, such as removing surface material, closing or filling
drill holes, and restoring the contour of the land.
Table 4: State Oil and Gas Well Permitting Surface Restoration
Provisions:
State: Alaska;
Remove surface material: Mandatory;
Remove structures: [Empty];
Close or fill holes: Mandatory;
Restore contour: Mandatory;
Revegetate or reseed: [Empty];
Return to natural state or condition: [Empty].
State: California;
Remove surface material: Mandatory;
Remove structures: Mandatory;
Close or fill holes: Mandatory;
Restore contour: Mandatory;
Revegetate or reseed: [Empty];
Return to natural state or condition: [A].
State: Florida[B];
Remove surface material: Mandatory;
Remove structures: Mandatory;
Close or fill holes: Mandatory;
Restore contour: Mandatory;
Revegetate or reseed: Mandatory;
Return to natural state or condition: Mandatory.
State: Louisiana;
Remove surface material: Mandatory;
Remove structures: Mandatory;
Close or fill holes: Mandatory;
Restore contour: Discretionary;
Revegetate or reseed: [Empty];
Return to natural state or condition: [Empty].
State: Michigan;
Remove surface material: Mandatory;
Remove structures: Mandatory;
Close or fill holes: Mandatory;
Restore contour: Mandatory;
Revegetate or reseed: Discretionary;
Return to natural state or condition: [Empty].
State: New Mexico;
Remove surface material: Mandatory;
Remove structures: Mandatory;
Close or fill holes: Mandatory;
Restore contour: Mandatory;
Revegetate or reseed: [Empty];
Return to natural state or condition: [Empty].
State: Oklahoma;
Remove surface material: Mandatory;
Remove structures: Mandatory;
Close or fill holes: Mandatory;
Restore contour: Mandatory;
Revegetate or reseed: Mandatory;
Return to natural state or condition: Mandatory.
State: Pennsylvania;
Remove surface material: Mandatory;
Remove structures: Mandatory;
Close or fill holes: Mandatory;
Restore contour: Discretionary;
Revegetate or reseed: Mandatory;
Return to natural state or condition: Discretionary.
State: Texas;
Remove surface material: Mandatory;
Remove structures: Mandatory;
Close or fill holes: Mandatory;
Restore contour: Mandatory;
Revegetate or reseed: Discretionary;
Return to natural state or condition: Discretionary.
State: Wyoming;
Remove surface material: Mandatory;
Remove structures: Mandatory;
Close or fill holes: Mandatory;
Restore contour: Mandatory;
Revegetate or reseed: Mandatory;
Return to natural state or condition: Mandatory.
[A] The California Department of Conservation responded to this survey
question by stating ’the site must be cleaned up and restored to as
near its natural state as possible.“
[B] The Florida Department of Environmental Protection stated that
exceptions may be granted on all of these provisions upon request of
the landowner, provided that other natural resources are not
endangered. It also stated that all surface land owned by the state of
Florida is returned to the original condition.
[End of table]
In addition, all states but Alaska reported mandatory requirements to
remove all structures. Other requirements, such as restoring the
surface of the land to a natural state or condition, were less common.
Only three states”Florida, Oklahoma, and Wyoming”reported mandating
restoration of the surface to a natural state or condition.
Table 5 shows a greater variance in surface restoration provisions as
reported by the states‘ oil and gas lease management offices.
Table 5: State Oil and Gas Lease Surface Restoration Provisions on
State-Owned Lands:
State: Alaska;
Remove surface material: Discretionary;
Remove structures: Discretionary;
Close or fill holes: Discretionary;
Restore contour: Discretionary;
Revegetate or reseed: Discretionary;
Return to natural state or condition: Discretionary.
State: California;[A]
Remove surface material: [Empty];
Remove structures: [Empty];
Close or fill holes: [Empty];
Restore contour: [Empty];
Revegetate or reseed: [Empty];
Return to natural state or condition: [Empty].
State: Florida[B];
Remove surface material: [Empty];
Remove structures: [Empty];
Close or fill holes: [Empty];
Restore contour: [Empty];
Revegetate or reseed: [Empty];
Return to natural state or condition: [Empty].
State: Louisiana[C];
Remove surface material: [Empty];
Remove structures: [Empty];
Close or fill holes: [Empty];
Restore contour: [Empty];
Revegetate or reseed: [Empty];
Return to natural state or condition: [Empty].
State: Michigan[D];
Remove surface material: [Empty];
Remove structures: [Empty];
Close or fill holes: [Empty];
Restore contour: [Empty];
Revegetate or reseed: [Empty];
Return to natural state or condition: [Empty].
State: New Mexico;
Remove surface material: Mandatory;
Remove structures: Mandatory;
Close or fill holes: Mandatory;
Restore contour: Mandatory;
Revegetate or reseed: Mandatory;
Return to natural state or condition: [Empty].
State: Oklahoma;
Remove surface material: Mandatory;
Remove structures: Mandatory;
Close or fill holes: Mandatory;
Restore contour: Mandatory;
Revegetate or reseed: Mandatory;
Return to natural state or condition: Mandatory.
State: Pennsylvania;
Remove surface material: Mandatory;
Remove structures: Mandatory;
Close or fill holes: Mandatory;
Restore contour: Discretionary;
Revegetate or reseed: Mandatory;
Return to natural state or condition: [Empty].
State: Texas;
Remove surface material: Mandatory;
Remove structures: Mandatory;
Close or fill holes: Mandatory;
Restore contour: Mandatory;
Revegetate or reseed: [Empty];
Return to natural state or condition: [Empty].
State: Wyoming;
Remove surface material: Mandatory;
Remove structures: Mandatory;
Close or fill holes: Mandatory;
Restore contour: Mandatory;
Revegetate or reseed: Mandatory;
Return to natural state or condition: Mandatory[E].
[A] The California State Lands Commission responded to our survey by
stating that leases that are being abandoned and quit-claimed must
undergo an environmental review under the California Environmental
Quality Act. They added that this review would specify the surface
restoration requirements of the leased lands.
[B] The Florida Department of Environmental Protection cited the
following in response to the survey question: ’After the cessation of
any oil, gas, or mineral lease, the site shall be restored by the lessee
to the original condition to the greatest extent practicable.“ (Florida
Administrative Code, Chapter 18-2.018 (3)8(a))
[C] The Louisiana Department of Natural Resources did not submit a
written response to our survey.
[D] The Michigan Department of Natural Resources responded to this
survey question by citing a provision in the Michigan Oil and Gas lease
that states that ’restoration shall be completed within nine (9) months
of surface disturbance within the premises for well site(s),
pipeline(s), road(s) and other oil and gas development activities
unless otherwise specifically approved in writing by the Lessor‘s
authorized representative. Restoration shall be pursuant to
requirements identified within the Surface Use Permit, easement or
other similar written permission for the development activity.“
[E] The Wyoming Office of State Lands and Investments added that the
site is to be returned to the natural state or condition ’as closely as
possible.“
[End of table]
Specifically, four states”New Mexico, Oklahoma, Pennsylvania, and
Wyoming”reported that their oil and gas leases contain mandatory
requirements to remove surface material and structures, close or fill
holes, and revegetate the area upon lease termination. Four
states”California, Florida, Louisiana, and Michigan”could not describe
their surface restoration provisions in the checklist format we
requested and provided either a written or verbal response. In the case
of California, a California State Land Commission official stated that
specific DR&R requirements are not determined until an environmental
review under the California Environmental Quality Act. Florida reported
that it requires the site to be restored by the lessee to the original
condition to the greatest extent practicable. Alaska reported
discretionary requirements for all the items in the checklist, because
all of its lease termination provisions are at the option of the state.
Table 6 describes the financial assurance provisions each state reported
including in its permits to drill wells.
Table 6: State Oil and Gas Well Permitting Financial Assurance
Provisions for Well-plugging and Abandonment:
State Office or Agency: Alaska; Alaska Oil and Gas Conservation
Commission;
Single wells: Not less than $100,000 to cover a single well;
Blanket provisions: Not less than $200,000 for a blanket bond covering
all wells in the state;
Other: The Commission will allow an amount less than $100,000 if the
operator can demonstrate that well abandonment and location clearance
will cost less than $100,000. The Commission can increase the security
amount, which is at the discretion of the Commissioner.
State Office or Agency: California; Department of Conservation,
Division of Oil, Gas, and Geothermal Resources;
Single wells: Single well bond amounts are based on the depth of the
well as follows: $15,000 for a well up to 5,000 feet deep; $20,000 for
a well 5,000 to 10,000 feet deep; $30,000 for a well 10,000 or more feet
deep;
Blanket provisions: Blanket bond amounts are based on the number of
wells an operator owns, and whether or not idle-well coverage is
provided; $100,000 – for operators with 50 or fewer wells and does not
provide long-term idle-well coverage; $250,000 – for operators with more
than 50 wells and does not provide long-term idle-well coverage; $1
million – Covers all wells and provides long-term idle-well coverage;
Other: Wells idle for 5 years or longer that have been released from
individual or certain blanket bond coverage are subject to one of the
following options: an annual fee, an escrow account, a $5,000 bond, or a
well elimination plan.
State Office or Agency: Florida; Department of Environmental
Protection, Florida Geological Survey;
Single wells: Single well drilling security amounts are based on the
depth of the well: $50,000 for a well up to 9,000 feet deep, or
$100,000 for producer well; $100,000 for a well more than 9,000 feet
deep, or $200,000 for producer well;
Blanket provisions: Each blanket bond may cover up to 10 wells,
regardless of well depth, and is $1,000,000;
Other: The Florida Department of Environmental Protection is authorized
to increase the amount of security based on estimates of potential
liability for damages to persons or property.
State Office or Agency: Louisiana Department of Natural Resources,
Office of Conservation;
Single wells: Single well financial assurance amounts are based on well
depth: $1 per foot for a well up to 3,000 feet deep; $2 per foot for a
well 3,001 to 10,000 feet deep; $3 per foot for a well more than 10,000
feet;
Blanket provisions: Blanket bond amounts depend on the number of wells
covered by the bond: $25,000 for up to 10 wells; $125,000 for 11 to 99
wells; $250,000 for more than 99 wells;
Other: The amount of security may be increased at the discretion of the
Commissioner of Conservation.
State Office or Agency: Michigan Department of Environmental Quality,
Geological Survey Division;
Single wells: Single well financial assurance amounts are determined by
the depth of the well: $10,000 for a well up to 2,000 feet deep;
$20,000 for a well 2,000 to 4,000 feet deep; $25,000 for a well 4,000
to 7,500 feet deep; $30,000 for a well more than 7,500 feet deep;
Blanket provisions: Blanket bond amounts depend on the number and depth
of the wells: $100,000 for up to 100 wells less than 2,000 feet deep;
$200,000 for up to 100 wells 2,000 to 4,000 feet deep; $250,000 with no
limit on the number of wells or their depth;
Other: The Michigan Department of Environmental Quality does not have
the authority to alter the amount of security, but compliance
agreements may require addition bond if the general operations bond is
not adequate to cover plugging and restoration costs of the well plus
other obligations under the compliance agreement. This additional
bonding is not required if the permittee has a $250,000 blanket bond.
State Office or Agency: New Mexico; New Mexico Energy, Minerals and
Natural Resources Department, Oil Conservation Division;
Single wells: The amount of single well financial assurance depends on
the depth and location of the well: Northwest part of New Mexico:
$5,000 for a well less than 5,000 feet deep; $7,500 for a well 5,000 to
10,000 feet deep; $10,000 for a well more than 10,000 feet deep;
Southeast part of New Mexico: $7,500 for a well less than 5,000 feet;
$10,000 for a well 5,000 to 10000 feet $12,500 for a well more than
10,000 feet deep;
Blanket provisions: Blanket financial assurance may be deposited in
lieu of one well financial assurance. Such assurance is in the amount
of $50,000;
Other: None.
State Office or Agency: Oklahoma; Oklahoma Corporation Commission, Oil
and Gas Conservation Division;
Single wells: Single well financial assurance provisions are based on
the total depth of the well at $2 per foot;
Blanket provisions: Blanket assurances are available at $25,000;
Other: The Commission may alter the amount of security depending on the
history of the company and whether they have fines in excess of $2,000.
State Office or Agency: Pennsylvania Department of Environmental
Protection, Bureau of Oil and Gas Management;
Single wells: Single well financial assurance is $2,500;
Blanket provisions: Blanket assurances are $25,000. These financial
assurance provisions only apply to wells drilled after April 17, 1985;
Other: The Pennsylvania Department of Environmental Protection may
revise the amount of security required every 2 years, based on the
projected cost to perform well-plugging.
State Office or Agency: Texas; Railroad Commission of Texas, Oil and Gas
Division;
Single wells: For operators without an organizational form of security,
wells that have been inactive for 36 months must be covered by an
individual bond or letter of credit calculated at $3 per foot of depth
for land wells, $60,000 for bay wells, and $250,000 for offshore wells;
Blanket provisions: An organization may file a single bond, letter of
credit, or cash deposit covering all wells operated by on of two ways:
$2 per foot of aggregate depth for all wells operated by company; or
based on the number of wells: $25,000 for up to 10 wells; $50,000 for
11 to 99 wells; $250,000 for more than 99 wells;
Other: Texas statute also gives the operator the option of filing
financial security as an Unbonded Operator by remitting 12% of the bond
otherwise required (or, alternatively, after qualification and a
hearing at which they show that bonds are not available at reasonable
cost, $1,000). As Unbonded Operators, they are still subject to single-
well bonding requirements.
State Office or Agency: Wyoming; Wyoming Oil and Gas Conservation
Commission;
Single wells: Financial assurances for a single well depend on well
depth at: $10,000 for a well less than 2,000 feet deep; $20,000 for a
well more than 2,000 feet deep;
Blanket provisions: Blanket provisions are available at $75,000;
Other: None.
[End of table]
Specifically, while Alaska reported higher financial assurance
provisions than most of the surveyed states, three states”California,
Florida, and Michigan”reported higher amounts. Eight of the 10 states
we surveyed reported single-well financial assurance provisions based
at least in part on the depth of the well. Pennsylvania and Alaska were
the only two states to report rates not based on well depth. All the
states surveyed included blanket financial assurance provisions, which
covered more than one well, though five states reported that the amount
of financial assurance required is based on the number of wells
covered.
Finally, table 7 shows the financial assurance provisions each state
reported for its oil and gas leases.
Table 7: State Oil and Gas Lease Financial Assurance Provisions that
Cover Well-plugging and Abandonment on State-Owned Lands:
State Office or Agency: Alaska Department of Natural Resources,
Division of Oil and Gas;
Single lease provisions: Before operations commence on oil or gas
lease, a bond in the amount of at least $10,000 must be furnished to
ADNR. ADNR currently requires a $100,000 bond for single-well
operations;
Blanket provisions: $500,000, though the Commissioner may also require
an additional unusual risk bond. For a unit, instead of separate bonds
for each lease, the unit operator must furnish a lease bond of
$500,000;
Other: The Commissioner may require a bond greater than the amount
specified where a greater amount is justified by the nature of the
surface, the uses and improvements on or in the vicinity of the lease,
and the degree of risk involved.
State Office or Agency: California State Lands Commission;
Single lease provisions: Most current offshore state leases were issued
from 1938 to 1968 with initial performance bond requirements of $25,000
for leases issued before 1956 and $50,000 for leases issued after 1957;
Blanket provisions: A California State Land Commission official stated
that California has blanket securities to cover all offshore leases
ranging from $4 million to $45 million to cover the performance of lease
requirements;
Other: None.
State Office or Agency: Florida Department of Environmental Protection,
Division of State Lands;
Single lease provisions: Prior to commencement of drilling, the state
of Florida may require proof of financial responsibility. Currently the
Division of State Lands policy requires a $100,000 surety bond;
Blanket provisions: None;
Other: None.
State Office or Agency: Louisiana Department of Natural Resources,
Office of Mineral Resources, State Mineral Board, Petroleum Lands
Division, Leasing Section;
Single lease provisions: None. Relies on the Louisiana Department of
Natural Resources, Office of Conservation, for financial assurance
provisions;
Blanket provisions: None. Relies on the Louisiana Department of Natural
Resources, Office of Conservation, for financial assurance provisions;
Other: None.
State Office or Agency: Michigan Department of Natural Resources, Land
and Mineral Lease Services;
Single lease provisions: None;
Blanket provisions: The Department of Natural Resources requires a
Lease Performance Bond to ensure compliance with all express and
implied covenants of the lease. The department has a bond schedule that
ties the amount of the bond to the total number of state minerals held
under the lease. The bond schedule is as follows: $10,000 – 0-5,000
acres under lease; $25,000 – 5,001-10,000 acres under lease; $50,000 –
>10,000 acres under lease;
Other: The Department of Natural Resources may increase or decrease the
bonds if the lessee drops state leases to the point that the acreage
held under the lease is less than required for the bond it currently
carries; it can replace the existing lease performance bond in
accordance with the schedule. If the lessee acquires additional state
leases that would push its total acreage under lease to the next
bonding level, it would have to submit a new bond in accordance with
the bonding schedule before it could acquire the additional leases.
State Office or Agency: New Mexico State Land Office, Oil Gas, and
Minerals Division;
Single lease provisions: The State Land Office allows the use of single-
lease bonds of $10,000;
Blanket provisions: The State Land Office allows the use of multi-lease
(blanket) bond of $20,000;
Other: A ’megabond“ in the amount of $25,000 may be used for state
leases for oil and gas, minerals, coal, geothermal resources, or rights-
of-way. The single lease and multilease bonds are minimum amounts and
’are deemed sufficient unless and until the Commissioner determines, or
one or more surface lessees or purchasers show the Commissioner, that
such an amount is not adequate in a given case.“ (State Land Office
Rule 1.016)
State Office or Agency: Oklahoma Commissioners of the Land Office,
Minerals Management Division;
Single lease provisions: None;
Blanket provisions: $10,000 blanket bond or pay into the performance
fund as a one-time payment. The performance fund is based on the
number of leases owned;
Other: On a case-by-case basis, the Commissioners can require more
bonding to cover a major problem.
State Office or Agency: Pennsylvania Department of Conservation and
Natural Resources, Bureau of Forestry, Minerals Section;
Single lease provisions: Well-plugging bond (per well): Well
depth/Minimum Bond 10,000
feet/$100,000; Oil and gas lease bond (per lease) conditioned on the
faithful compliance to all lease terms, including removal of equipment
and well abandonment: $25,000;
Blanket provisions: None.
Other: The surety for both blanket and plugging bonds can be altered by
the terms of the lease agreement if the Department of Conservation
finds that the cost estimates for the actual plugging of any class of
wells are generally exceeding the required security. All Pennsylvania
state oil and gas leases have an inflation clause that allows the
department to inflate the amount of surety required at the rate of
inflation of the ’All Commodities Index“ as published by the federal
Department of Labor. This readjustment period is every 5 years.
State Office or Agency: Texas General Land Office;
Single lease provisions: None. Relies on the Texas Railroad Commission
for financial assurances;
Blanket provisions: None. Relies on the Texas Railroad Commission for
financial assurances;
Other: None.
State Office or Agency: Wyoming Office of State Lands and Investments;
Single lease provisions: At least $10,000 per lease;
Blanket provisions: At least $100,000 blanket bond for all
leases.
Other: The Office of State Lands and Investments has the unilateral
ability to change the amount of security depending on the number and
depth and type of well or exploration activity, surface uses in
conjunction with production, and the observed amount of environmental
responsiveness.
[End of table]
Two states, Texas and Louisiana, reported that their oil and gas leases
did not contain financial assurance provisions that covered DR&R.
Rather, they stated that they relied instead on the well permitting
office in their state for financial assurance that proper DR&R would be
performed. Alaska‘s financial assurances are higher than most of the
states we surveyed except California, Florida, and Pennsylvania. A
California State Lands Commission official stated that while
California‘s performance bonding provisions are not specified in
California statute, the bonding amounts are specified in the oil and
gas lease, which range from $25,000 in earlier leases to $1.25 million
in a later lease. In addition to performance bonds, the California
State Lands Commission can require additional assurance for DR&R, and
these amounts have ranged up to $7.5 million. Florida reported a single
lease provision that matches Alaska‘s at $100,000, but no blanket bond
provision. Finally, Pennsylvania reported a well-plugging bond of
$100,000 per well for well depths in excess of 10,000 feet and an
additional $25,000 bond to ensure dismantlement, removal, and
restoration and cover miscellaneous problems or missed royalty
payments. By comparison, ADNR‘s financial assurances are either a
$100,000 single-lease bond that cover all wells in a lease, or a
$500,000 statewide blanket bond that covers all leases in the state.
[End of section]
Appendix II: Comments from the Department of the Interior:
United States Department of the Interior:
Office Of The Secretary:
Washington, D.C. 20240:
In Reply Refer To: 3100 (310):
May 22, 2002:
Mr. Barry T. Hill:
Director, Natural Resources and Environment:
U.S. General Accounting Office:
441 G Street, Room 2T23:
Washington, D.C. 20548:
Dear Mr. Hill:
Thank you for the opportunity to review and comment on the U.S. General
Accounting Office's (GAO) draft report entitled "Alaska's North Slope:
Requirements For Restoring Lands After Oil Production Ceases (GAO-02-
357)." The Minerals Management Service, the Bureau of Land Management
(BLM) and the Fish and Wildlife Service have all reviewed the report
and either concur with the comments below or had no additional
comments.
The Department of the Interior (DOI) concurs with the GAO's findings
and the recommendation that the BLM issue specific dismantlement,
removal, and restoration requirements that will allow the BLM to meet
its overall goal of returning the land to a condition that will sustain
its previous uses including fish and wildlife habitat, as well as
subsistence uses. The BLM will accomplish this by attaching special
stipulations and conditions of approval on a lease-by-lease basis.
The DOI also concurs with the recommendation that the BLM review its
existing financial assurances for oil and gas activities in the
National Petroleum Reserve-Alaska to determine if they are adequate to
ensure that funds will be available to achieve its overall restoration
goal. This review will focus on protecting the environment and
taxpayers should lessees default.
In regard to the Matter for Congressional Consideration, as you know,
Congress has provided a good foundation to protect Alaska's North Slope
from environmental degradation and to meet both Alaskan Native and
taxpayer concerns. Specific guidance is found in the Federal Land
Policy and Management Act of 1976, the Alaska National Interest Lands
Conservation Act of 1980, and the Naval Petroleum Reserves Production
Act (Public Law 94-258) which authorizes leasing in the National
Petroleum Reserve-Alaska.
Specific editorial comments are listed in the enclosed. If you have any
further questions, please contact, Gene Terland, Acting Associate State
Director, BLM Alaska State Office, at (907) 271-5076, or Jean Fend,
Audit Liaison Officer, BLM Management Systems Group, at (202) 452-5153.
Sincerely,
Signed by:
Robert J. Lamb, for:
P. Lynn Scarlett:
Assistant Secretary:
Policy, Management and Budget:
Enclosure:
U.S. Department of the Interior:
Comments on U.S. General Accounting Office Draft Report, entitled
"Alaska's North Slope: Requirements For Restoring Lands After Oil
Production Ceases"
(GAO-02-357)
In response to the above draft report, the Department of the Interior,
Bureau of Land Management (BLM), offers the following comments:
Technical Comments/Editorial Comments:
Page 9, last paragraph: It could be argued that the current bonding
levels are sufficient to ensure restoration as no industry related
sites on Federal lands have required Federal funds to be expended for
cleanup. Federal funds have been expended on Government legacy wells.
It is correct to state that the financial assurances are insufficient
to pay for future cleanup.
Page 10, line 13: "...cost of reclamation, the Bureau currently uses
fixed bond amounts ...." It would be more accurate to say, "...the
Bureau currently uses a minimum bond amount...
Page 10, line 22: Suggest adding in the words in bold. "In the past,
prior to the establishment of such requirements and financial
assurances, many oil exploration wells drilled by the Federal
Government on Federal lands on the North Slope (referred to as legacy
wells) were improperly plugged and abandoned. According to the Bureau
of Land Management (BLM), these wells potentially remain costly
environmental problems to this day."
Page 13, first full paragraph, line 10: Suggest changing the sentence
to read: "In addition, the Bureau currently uses minimum bond amounts
that ...."
Page 14, 1" partial paragraph, line 3: Suggest changing to read: "In
the past, as a result of inadequate dismantlement and restoration
requirements, about 80 legacy wells drilled on ...."
Page 68, 1' paragraph, line 10: Comment on the sentence that reads
"Furthermore, the current bond amount for the National Petroleum
Reserve-Alaska would only cover a fraction of the potential future DR&R
liability." However, BLM regulations allow for escalating bond amounts
up to the full cost of DR&R.
Page 88, 1st partial paragraph, line 4: Suggest adding the word in bold
type. "In addition, its current minimum bond amounts are fixed ...."
This stresses that flexibility remains an option.
[End of section]
Appendix III: Comments from the State of Alaska:
Note: GAO comments supplementing those in the report text appear at the
end of this appendix.
State of Alaska:
Tony Knowles, Governor:
Department Of Natural Resources:
"Develop, Conserve, and Enhance Natural Resources for Present and
Future Alaskans"
Office Of The Commissioner:
400 Willoughby Avenue:
Juneau, Alaska 99801-1796
Phone: (907) 465-2400:
Fax: (907) 465-3886:
550 West 7th Avenue, Suite 1400:
Anchorage, Alaska 99501-3650:
Phone: (907) 269-8431:
Fax: (907) 269-8918:
May 24, 2002:
Jim Yeager:
Assistant Director:
Natural Resources and Environment:
U.S. General Accounting Office (Room 2964):
441 G St. NW:
Washington DC 20548:
Re: Alaska's Comments on GAO's Draft Report on North Slope Restoration
Requirements, GAO-02-357:
Dear Mr. Yeager:
Alaska Governor Tony Knowles has asked me to respond to the April 25
letter of Director Barry T. Hill, which solicited the State of Alaska's
comments on the draft report entitled ALASKA'S NORTH SLOPE:
Requirements For Restoring Lands After Oil Production Ceases (GAO-02-
357). The State appreciates the opportunity to offer its comments
before the report is issued in final form.
The GAO's investigation of the dismantlement, removal and restoration
(DR&R) standards and practices applicable to Alaska's North Slope
leases was instigated over 13 months ago, at the request of Congressman
Markey of Massachusetts and several other ardent political opponents of
new oil and gas exploration in Alaska. At that time, Governor Knowles
wrote the Comptroller General questioning the investigation's scope and
legitimacy. Several considerations prompted the Governor's April 4,
2001 letter. First, so far as Alaska is aware, the power and resources
of the GAO have never before been devoted to the investigation of State
practices on State lands. Second, for the GAO to accede to such an
unprecedented request when it was tied so obviously to a particular
political agenda seemed to call into question the GAO's credibility.
The Comptroller General sought to allay Governor Knowles' concerns in a
response dated April 13, 2001. While that letter contained inaccurate
assumptions about the role of federal agencies on State lands, and
confused environmental clean up responsibilities with DR&R-a confusion
that persists, unfortunately, in the draft report[Footnote 46] -at
bottom, the Comptroller General justified the investigation on the
basis that information the GAO develops regarding DR&R activities on
State lands "could provide useful lessons learned for consideration in
connection with future development activities" in the Arctic National
Wildlife Refuge (ANWR) and the National Petroleum Reserve-Alaska (NPRA).
In Alaska's view, it is clearly legitimate for the federal government
to look at Alaska's experience before coming to final policy decisions
regarding appropriate DR&R standards on federal lands. There remains,
however, a serious question regarding whether the GAO is the right
federal agency to do the looking.
On the very first page of the draft report, the GAO acknowledges that
the real reason this investigation was begun was not to educate the
federal government about the appropriate DR&R standards to be employed
on federal lands, but rather because several Minority Members of the
House were "concerned about whether this [estimated $53 billion worth
of existing oil and gas] infrastructure will be removed from the North
Slope and to what condition the land will be restored when oil
production activities cease...."
As is evident, the lands on which this infrastructure exists are lands
owned by the State of Alaska that have been expressly set aside by the
State for the purpose of oil and gas exploration and development.
Whether the State will require all traces of oil and gas activity to be
erased from its lands at some indefinite point in the future is, quite
frankly, not a federal concern. Consequently, we believe it would have
been more appropriate for the GAO to respectfully decline the Minority
Members' request, rather than attempt to imbue its investigation with a
legitimate federal purpose.
Nevertheless, the State has devoted substantial resources to assist GAO
staff in its effort to understand past, present, and probable future
oil and gas development activity on the North Slope. As you know, there
has been considerable correspondence between GAO staff and staff of
Alaska's Department of Natural Resources, Department of Environmental
Conservation, Oil and Gas Conservation Commission, and Department of
Law. The State appreciates the effort expended by GAO staff to
understand the nature of oil and gas development on the North Slope,
and believes it did a remarkable job.
Even so, there are several points in the report that, in the State's
view, must be corrected or clarified. In addition, the State has
general comments on the recommendations of the report, which we have
organized into two sections. The first deals with the GAO's
recommendations to the Congress and the Secretary of the Interior
relating to "specific" DR&R requirements. The second deals with the
GAO's recommendations to the Congress and the Secretary regarding
"adequate" financial assurances of DR&R performance. We have attempted
to incorporate our suggestions for correcting or clarifying specific
points at appropriate places in our more general comments on the GAO's
recommendations.[Footnote 47] [See comment 1]
"Specific" DR&R Requirements:
The GAO recommends that the Secretary of the Interior direct the Bureau
of Land Management to promulgate regulations containing "specific" DR&R
requirements that will allow BLM "to meet its overall goal of returning
the land [within the NPRA] to a condition that will sustain its
previous uses including fish and wildlife habitat as well as
subsistence uses." Similarly, it recommends to Congress that, if it is
considering opening additional federal lands to oil and gas activities,
and "wants to provide specific guidance on the condition to which these
lands should be returned," it should consider placing a "specific
restoration goal" in the authorizing statute.
To put it another way, the GAO concludes that it is better to decide
today the specific DR&R requirements to be met 30, 40 or 50 or more
years hence, rather than to address those specific requirements when
the DR&R obligations actually become due. Perhaps that is the best
approach, even in a sparsely populated and relatively new and
undeveloped oil and gas province such as the North Slope, but the GAO
fails to adequately explain why.
The GAO describes the companies' DR&R obligations under the State's
North Slope leases as "general," which is not the whole truth. For
example, the GAO transforms a specific provision in the State's lease,
which requires the lessee to "remove any and all" materials, tools,
appliances, machinery, structures, and equipment from the lease when so
directed by the State, into a statement that "the lessee may leave its
infrastructure behind" if so directed by the State. (Draft report at
41.) Moreover, the GAO repeatedly mischaracterizes the State's DR&R
requirements as the prerogative of the lessees rather than an absolute
duty to the State. For example, at several points the GAO claims that
State standards tell the companies they "should" return the lands to a
condition that is satisfactory to the State, when of course the leases
stipulate that the companies must do so. The GAO also suggests this
requirement is unimportant, because the State has not told the
companies today what it expects of them several decades from now. In
other words, the GAO's "analysis" assumes that its conclusion is
correct-being specific today is better than giving the State absolute
discretion to address the specifics when DR&R becomes due-without an
explanation that justifies that preconception. [See comment 3]
The GAO offers, without critical examination, the viewpoints of two,
usually opposed, groups as support for its recommendation on "specific"
DR&R standards. The first is the view of the industry members doing
business on the North Slope. These industry members allegedly want more
specific DR&R standards so that they may better estimate their future
financial liabilities. The second is the view of environmentalists, who
speculate that future politicians will lack the will to enforce DR&R
standards, or that the DR&R requirements in State leases will be traded
away for additional incremental production. [See comment 4]
Though the GAO believes these groups' views are comparable-and thus
ostensibly justify its conclusion-the underlying intent of each is
actually diametrically opposed. The industry members, of course, would
prefer specific standards that minimize their future liability. The
environmentalists, on the other hand, want standards that reflect their
policy views, regardless of cost. Each perceives a risk that their view
of the appropriate level of DR&R may not be adopted in the future, so
they would like to see it adopted now. This is a perfectly natural
position for both groups to take, but it doesn't follow that adopting
specific DR&R standards today is the best policy choice for government.
Moreover, while government generally cannot require industry to provide
greater DR&R than that stipulated in its lease contract (this is one
critical distinction between traditional DR&R requirements and
environmental clean up requirements), the idea that adopting specific
regulatory standards today provides certainty in the future is not
really true. It ignores the scope of government's power to change the
regulatory standards it adopts. It also ignores that circumstances
change, and that specific standards that seem appropriate today may not
be appropriate at some distant point in the future. [See comment 5]
For example, Alaska could have incorporated into its original leases
and regulations a specific requirement that all gravel used to build
pads to support production facilities be removed from the tundra and
returned to the quarries from which it came. Alaska discovered,
however, that in some cases returning gravel to its quarries might be a
bad idea. One example we shared with GAO staff involved several gravel
quarries that were discovered to provide overwintering habitat for
certain species of fish that are used for subsistence by North Slope
residents. "Restoring" the leases by removing the gravel and filling
these quarries would in fact reduce North Slope subsistence
opportunities. Similarly, there is ample literature documenting caribou
using gravel pads and roads for insect relief, and migratory birds
nesting along man-made impoundments. These uses may not in themselves
determine whether it is a good idea to restore the lands to their prior
condition, but they may be relevant to the State's determination. Both
examples reflect circumstances Alaska could not have reasonably
anticipated when the State's leases were originally drafted.
To be clear, Alaska is not saying that it is too early to think about
appropriate DR&R requirements on federal lands. In fact, to the extent
the GAO's recommendations can be read to suggest that the federal
government should begin thinking about those standards, Alaska
wholeheartedly agrees. Nevertheless, the State does not believe it is
self-evident that it is better to adopt specific standards today for
DR&R activities that may not take place for half a century. On the
contrary, Alaska views the discretion it has-to deal with particular
DR&R issues as those issues arise-to be a significant benefit. Among
other things, it allows the government to make decisions based upon all
the facts, rather than upon assumptions about the future. [See comment
6]
In summary, the draft report offers no facts or analysis supporting a
conclusion that the federal government would be better off limiting its
discretion in the manner the GAO recommends. The State believes that
the draft report supports, at best, a recommendation that the Congress
consider directing the Secretary of the Interior to evaluate whether
adopting specific DR&R requirements is in the best interests of the
United States, and to provide a report of her findings to the Congress
with recommendations for appropriate action. [See comment 7]
"Adequate" Financial Assurances:
The other set of recommendations in the draft report relate to the
financial assurances that need to be in place to ensure the required
level of DR&R actually takes place. In essence, the GAO suggests that
financial assurances far greater than those required by the State
should be adopted for federal lands, even though Alaska's bonding
requirements are among the highest in the Nation. The GAO's analysis
falls short in a number of respects.
The GAO's claim that Alaska's financial assurance requirements are
insufficient to cover anticipated North Slope DR&R costs is not
accurate. The GAO ignores that the real financial assurance of these
obligations comes from the balance sheets of the companies doing
business on the North Slope. Only if you believe that Exxon Mobil
Corporation, British Petroleum, and Phillips Petroleum Company are
likely to simultaneously go bankrupt, or otherwise jointly default on
their lease obligations, at the time the DR&R obligations become due is
there a genuine risk that Prudhoe Bay DR&R obligations will not be met.
It would be economically irrational to fashion federal assurance
provisions on the assumption that something like this will occur. [See
comment 8]
The GAO relies on a number of other faulty factual premises. It states,
for example, that there are "fixed financial arrangements" for the
Trans Alaska Pipeline System, and uses that to suggest that similar
arrangements would be appropriate for production facilities on federal
lands. In fact, the "fixed financial arrangement" to which the GAO
refers is an accounting mechanism embedded in the tariff methodology
for the pipeline. It allows the pipeline owners to collect a stipulated
amount for DR&R in the rates they charge. The GAO fails to acknowledge
that this is effectively no different than the accounting done by the
companies producing oil on the North Slope. These companies record on
their books an estimate of their eventual North Slope DR&R obligations
which, ultimately, will have to be met from the money these companies
have earned producing oil. In both cases, the real guarantee that DR&R
will take place is the financial wherewithal of the companies that are
operating the facilities. [See comment 9]
The GAO also attempts to use the alleged number of "improperly" plugged
and abandoned wells on the North Slope to justify a conclusion that
greater financial guarantees are appropriate. Most of these wells,
however, were plugged in accordance with the standards that existed at
the time. It is not accurate, therefore, to describe them as
"improperly" plugged. Moreover, because most of these wells were
actually drilled by the federal government on federal lands that remain
today in federal ownership, they are not "abandoned" in the usual
sense. In sum, the existence of these old federal wells offers no
support for imposing additional financial assurance provisions on new
federal lessees. [See comment 10]
Further, it is wrong for the GAO to cite problems associated with old
surface use leases, issued to individuals or companies that sought to
provide services to the oil and gas industry, to support its conclusion
about new financial assurance provisions for oil and gas leases. It is
like recommending pesticides for an orange grove today because you saw
worms in apples many years ago. At best, this evidence supports a
reexamination by the federal government of the financial assurance
provisions applicable to surface use leases issued to the service
industry. Because the examples the GAO cites do not involve oil and gas
leases, they do not support its conclusion. [See comment 11]
The real question is not whether the amounts reserved under the State's
or federal government's general bonding requirements are large enough
to cover any conceivable estimate of future DR&R costs, but whether the
assurances given-including contractual commitments-are, under all the
circumstances, adequate. The State acknowledges that there may be times
when bonding beyond the base amount set in State law may be necessary;
but it is better to address such a circumstance with a solution that is
tailored to the problem. For example, there have been several instances
in which the State has refused to allow a company to transfer its
leases to a less financially secure company, until that new company has
provided a bond or other financial assurances sufficient to cover the
full estimated costs of DR&R.[Footnote 48] [See comment 12]
By approaching its bonding requirements this way, the State strikes a
balance that seeks to maximize the benefits of its oil and gas
resources for its citizens. Where there is little risk the lessee will
fail to perform its DR&R obligations, this approach avoids imposing
costs that merely tend to discourage otherwise prudent oil and gas
investments. Where the failure of performance is a significant risk,
however, Alaska does not allow the development to proceed until it
obtains assurances that are sufficient to ameliorate that risk. [See
comment 13]
In short, the GAO's recommendation is not economically rational.
Moreover, the draft report fails to point to any relevant, credible
evidence that supports its recommendation that significant changes to
the federal government's financial assurance requirements for oil and
gas leases are necessary. The State therefore recommends that the GAO
delete those recommendations before issuing its final report. [See
comment 14]
Sincerely,
Signed by:
Pat Pourchot:
Commissioner:
Department of Natural Resources:
cc: John Katz, Dir State And Fed Relations:
David Ramseur, Chief of Staff:
Marty Rutherford, Deputy Commissioner:
Jack Griffin, Assistant Attorney General:
The following are GAO‘s comments on the state of Alaska‘s letter dated
May 24, 2002.
GAO‘s Comments:
1. GAO often examines state practices on state lands, especially if
federal agencies have a regulatory role in the state activity or if
federal agencies can learn from state practices. For example, GAO has
reviewed the state of Florida‘s land acquisition program as it relates
to the South Florida Ecosystem Restoration Initiative (South Florida
Ecosystem Restoration: A Land Acquisition Plan Would Help Identify
Lands That Need to Be Acquired. GAO/RCED-00-84. April 5, 2000). In
another example, GAO reviewed state management practices in state-owned
parks, wildlife and waterfowl areas, and forests in New Mexico, North
Carolina, and Utah and compared them to federal practices on federally
owned land. (Land Ownership: Similarities and Differences in the
Management of Selected State and Federal Land Units. GAO/RCED-97-158.
June 27, 1997). Further, for state lands on Alaska‘s North Slope,
federal agencies such as the U.S. Army Corps of Engineers and the U.S.
Fish and Wildlife Service have issued regulations that can
significantly affect the state of Alaska‘s dismantlement, removal, and
restoration requirements. It is within GAO‘s authority and
responsibility to review the federal role on this issue.
The state also commented that by performing this review, GAO was
promulgating a particular political agenda, which also brought into
question its credibility. We strongly disagree. The GAO has a statutory
obligation to fulfill requests from the Congress and its committees. To
effectively accomplish this obligation, GAO prioritizes its work in
accordance with its published congressional protocols. These protocols
state that congressional mandates, senior leader requests, and
committee leader requests receive the highest priority followed by
committee member requests, and then by individual member requests.
GAO does not differentiate between the majority and the minority staff
when implementing these priorities. Congressmen who represent the
highest of these priorities requested this work. Specifically, House
Minority Leader Richard A. Gephardt; Ranking Minority Member, House
Committee on Resources, Nick J. Rahall; and member of the House
Committee on Resources, Edward J. Markey. To effectively support the
Congress, GAO must be professional, objective, fact-based, nonpartisan,
nonideological, fair, and balanced in all its work. All GAO products
and services must conform to generally accepted and applicable
auditing, accounting, investigative, and evaluation principles and
standards. GAO strives to exercise the independence necessary to
guarantee that its products and work conform to professional standards
and the agency‘s core values of accountability, integrity, and
reliability. It should also be noted that this review draws no
conclusions and makes no recommendations on the appropriateness or
inappropriateness of the state of Alaska‘s current DR&R requirements
for its lands. We used the knowledge gained from the state‘s
experiences on the North Slope to draw conclusions and make
recommendations to federal land managers.
We disagree with the state‘s contention that our report does not draw a
distinction between dismantlement, removal, and restoration
requirements and environmental cleanup. Our report clearly defines
DR&R requirements as the dismantlement and removal of infrastructure
and the restoration of the land following the completion of oil and gas
activities. Our report also distinguishes between the DR&R requirements
imposed by Alaska‘s Department of Natural Resources and Alaska‘s Oil
and Gas Conservation Commission and the requirements for air and water
contaminated by pollution. We note that Alaska‘s Department of
Environmental Conservation enforces these requirements, which include
the cleanup of oil spills. We further distinguish between DR&R
requirements and cleanup of environmental contamination in our analysis
of the costs of DR&R requirements. We acknowledge that in some
instances, especially for orphan well sites located in the National
Petroleum Reserve-Alaska, both DR&R and environmental cleanup are
necessary and discussed together. However, in these cases, we believe
we appropriately characterize the required actions.
2. We agree with the state that the report incorrectly describes Prudhoe
Bay as an area that spreads across 1,500 square miles and contains
Native Corporation lands. We meant this sentence to be a description
of state lands on the North Slope and have changed the report
accordingly.
3. Establishing overall restoration goals and corresponding specific
DR&R requirements prior to development is not an inflexible exercise.
As stated in the report, we recognize that established goals can change
and the process used to achieve those goals can also change as
technology and circumstances change. However, we believe that to
avoid confusion and concerns about what, if anything, might happen to
federal lands used for oil and gas development, it is important to
establish restoration goals and corresponding dismantlement, removal,
and restoration requirements prior to the initiation of such activities.
We believe that such action will provide a number of benefits. First, it
will allow all interested parties, including the Congress, the federal
land management agency, the oil companies, environmental groups, and the
public, to know what is planned for the restoration of the land after
oil and gas activities cease. Such information will allow all interested
parties to make more informed decisions about whether they will support
or carry out such development. Second, oil companies will have better
information on what is expected of them and thus will be better able to
compare the benefits of oil production to the total costs before
deciding whether to make such an investment. If they do decide to
proceed, it will also allow the companies to better plan and budget for
the eventual cost of restoration, which improves the likelihood that
the needed funds will be available. Finally, if there is a public
record of the planned restoration activities, it increases the
likelihood that such restoration will occur or that any modification of
planned restoration is justified.
4. Alaska‘s current lease stipulations, which are reprinted in the
report, state that, at the option of the state, all improvements such
as roads, pads, and wells ’shall“ either be abandoned and the sites
rehabilitated by the lessee to the satisfaction of the state, or left
intact and the lessee absolved of all further responsibility as to
their maintenance, repair and eventual abandonment and rehabilitation.
We did not characterize the obligation of the lessee as optional, but
one that can be waived at the discretion of the state. However, we did
use the word ’should“ to characterize the lessee‘s obligation instead
of the word ’shall.“ We agree with the state that the word ’must“ is a
more appropriate characterization of the state‘s actual use of the word
’shall“ in the lease. Therefore, we have revised the report by
replacing our use of the word ’should“ with the word ’must,“ when
appropriate.
5. We believe that because the state lacks a restoration goal for its
lands on the North Slope and corresponding DR&R requirements, that these
two usually opposed groups”oil companies and environmentalists” are
concerned about what will be required and what will ultimately happen
to the land. By recommending the establishment of restoration goals for
federal lands, and the issuance of specific DR&R requirements to
achieve those goals, it is our intent to alleviate such concerns and
allow all interested parties to make informed decisions on these
matters before the land is used. Establishing goals and requirements
prior to development would provide for greater transparency and would
allow agreements to be reached on what restoration will be required
before the loss of any leverage for ensuring adequate performance.
6. We agree with the state that the development of new technology and
science as well as changing circumstances can cause regulatory agencies
and policymakers to revise their DR&R requirements. However, we do not
agree with the state that these acts are mutually exclusive.
Establishing overall restoration goals and related specific DR&R
requirements prior to development is not the same as dictating the
process used to achieve these goals and requirements. For example, a
goal of returning the land to as near as the original condition as
possible and a corresponding requirement to remove gravel from
abandoned development to achieve that goal does not dictate how that
gravel is to be disposed of. Nor do establishing goals and DR&R
requirements as part of the lease negate the ability of the lessor to
alter those requirements at a later date, if the lease allows for such a
modification.
7. We do not agree with the state. We do not offer any comments, draw
any conclusions, or make any recommendations as to whether the state of
Alaska‘s current DR&R practices are appropriate or inappropriate for
its lands. However, we do believe that for federal lands subject to
federal regulatory authority and responsibility on Alaska‘s North Slope,
it is appropriate to establish restoration goals and DR&R requirements
prior to development for the reasons stated in the report.
8. GAO is not recommending a specific level of financial assurance for
federal lands on the North Slope. Rather, we state, and the Department
of the Interior agrees, that the current financial assurances required
by the Bureau of Land Management for oil and gas activities in the
National Petroleum Reserve-Alaska would only cover a fraction of the
potential future cost of DR&R. For this reason, GAO recommends, and
again the Department of the Interior agrees, that the Bureau should
review its existing financial assurances for the National Petroleum
Reserve-Alaska to determine whether they are adequate to ensure the
availability of funds needed to achieve its overall restoration goal.
9. We believe that the state‘s current bonding requirements are
insufficient to cover the likely eventual cost of DR&R. The state has
agreed with this statement in the past. We recognize in the report that
the state has chosen to place most of its reliance that funds will be
available to perform whatever DR&R requirements the state may
eventually establish on the overall financial condition of the companies
currently operating on the North Slope. However, the state has no
assurance that these firms will continue to operate on the North Slope
or that, once the oil is depleted, they will be as committed to the
state‘s intentions as the state may believe.
10. We agree that the owners of the Trans-Alaska Pipeline System (TAPS)
do not escrow the actual funds collected for DR&R. We did not review
whether requiring this to occur would have been a more appropriate
mechanism for the regulators of the pipeline to employ to ensure that
DR&R requirements are met. However, the state fails to note two very
important differences between the financial assurances that exist for
DR&R requirements for TAPS and the financial assurances that exist
for oil and gas activities on state land on the North Slope. First, the
DR&R requirements for the owners of TAPS are more definite than the
requirements that have yet to be determined for state lands. Second, by
defining these requirements, the owners of TAPS have been able to
create a formula known to all parties for determining an amount to be
collected from the users of the pipeline to meet DR&R requirements.
11. About 100 wells located in the National Petroleum Reserve-Alaska
were drilled by the federal government and are still its
responsibility. BLM, the federal agency responsible for managing the
National Petroleum Reserve-Alaska, has specifically stated that many of
these wells were improperly plugged and may pose an environmental
hazard. These wells, and the risks they represent, provide an important
illustration of the substantial costs involved in attempting to rectify
this problem. For example, in 2001, when the Corps of Engineers
approved the plugging and surface remediation of just two of these well
sites, the total cost was about $16 million. Further, in 2001, BLM
estimated that just properly plugging the abandoned wells in the
National Petroleum Reserve-Alaska would cost more than $100 million
over the course of 10 to 20 years.
12. We believe that abandoned surface leases used to support oil and gas
activities on the North Slope provide another useful illustration of the
costs of cleaning up and restoring such environments. In addition,
because the state had inadequate restoration requirements and financial
assurances in these old leases, they also illustrate the risks involved
in having to correct the problem today.
13. GAO acknowledges in its report that in two instances the state has
sought and obtained additional financial assurances before it would
approve the transfer of a lease to a less financially secure company.
However, as stated in the report, the state currently has no criteria to
determine when additional financial assurances are needed.
14. The state feels that GAO is making a recommendation that will
unnecessarily impede future oil and gas activities on federal lands on
the North Slope. To the contrary, we report that the Minerals
Management Service, which regulates offshore oil industry activities on
federal lands, sets its bond amounts based on an escalating scale that
depends on, among other things, the company‘s experience and financial
viability, as well as the estimated future cost of reclamation. These
requirements have not impeded oil companies from exploring and recently
initiating the production of oil from offshore facilities located in
federally regulated waters. We also report, and the Department of the
Interior agrees, that the current financial assurances required by the
Bureau of Land Management for oil and gas activities in the National
Petroleum Reserve-Alaska are minimum fixed amounts that do not take
into consideration differences in company experience and financial
viability and would only cover a fraction of the potential future cost
of DR&R. As such, we believe that the Bureau should review its existing
financial assurances for the National Petroleum Reserve-Alaska to
determine whether they are adequate to ensure the availability of funds
needed to achieve its overall restoration goal. The Department of the
Interior agreed with this recommendation and stated that the Bureau‘s
review will focus on protecting the environment and taxpayers, should
lessees default.
[End of section]
Appendix IV: GAO Contacts and Staff Acknowledgments:
GAO Contacts:
Barry T. Hill (202) 512-3841:
Jim Yeager (202) 512-6780:
Acknowledgments:
In addition to those named above, Paul Aussendorf, Jose Alfredo Gomez,
Cheryl Pilatzke, and Arvin Wu made key contributions to this report.
[End of section]
Footnotes:
[1] Alaska Native lands include lands deeded to native regional and
village corporations that were created under the Alaska Native Lands
Claim Settlement Act of 1971 as well as individual native land
allotments. These lands include both surface rights and the rights to
subsurface minerals.
[2] The state, BP, and Atlantic Richfield agreed to the ’Charter for
Development of the Alaskan North Slope“ on December 2, 1999. As set
forth in the charter, BP and Atlantic Richfield agreed to sell a
predetermined percentage of their Alaska interests to a third ’qualified
company“ prior to their merger in order to prevent a monopoly and to
ensure continued competition on the North Slope. Phillips Petroleum
purchased the stock of ARCO Alaska, Inc., and, with BP, assumed
responsibility for fulfilling the charter obligations.
[3] An oil field consists of a reservoir of oil in a shape that will
trap hydrocarbons and that is covered by a layer of impermeable or
sealing rock. A field refers to the surface area above the oil
accumulation.
[4] In 1998, BP merged with Amoco and in 2000 merged with ARCO. As part
of the BP-ARCO merger, the U.S. required BP to divest itself of ARCO‘s
Alaska assets. In 2000, Phillips Petroleum acquired ARCO‘s Alaska
assets.
[5] L. Daniel Maxim, Everest Consulting Associates, September 2001, for
the Alaska Oil and Gas Association.
[6] A small portion of Alaska‘s oil and gas revenues comes from the
Cook Inlet area southeast of Anchorage. According to a former
commissioner of the Alaska Department of Natural Resources, 90 percent
of state oil and gas revenues are generated from the North Slope.
[7] When TAPS was constructed, it was granted a 30-year right-of-way
across federal and state lands; the lease will expire in 2004. The BLM
recently initiated development of an EIS as it determines whether to
renew the federal lease.
[8] We did not independently verify the results of any of these
studies.
[9] Ed Deakin, Ph.D., director of the Institute of Petroleum Accounting
at the University of North Texas, conducted the study from 1969 to
1987.
[10] Technically recoverable refers to the amount of oil that can be
extracted using current technology. The economically recoverable amount
is generally less because it considers the market price of oil and the
cost to extract, process, and transport the oil to market, which
generally increases as the recoverable amount declines.
[11] For additional information on oil and gas activities in U.S. Fish
and Wildlife Service refuges, see GAO‘s report U.S. Fish and Wildlife
Service: Information on Oil and Gas Activities in the National Wildlife
Refuge System, [hyperlink, http://www.gao.gov/products/GAO-02-64R]
(Washington, D.C.: Oct. 31, 2001).
[12] The states we surveyed were Alaska, California, Florida,
Louisiana, Michigan, New Mexico, Oklahoma, Pennsylvania, Texas, and
Wyoming.
[13] 20 AAC 25.112 Well-Plugging Requirements.
[14] AOGCC‘s offshore location clearance provisions [20 AAC25.172]
require the removal of all platforms, equipment, casings, and pilings,
unless a state or federal agency approves leaving the platform or
offshore island in place. Depending on whether the well is drilled from
an offshore platform, a mobile structure like a floating drilling
vessel, or an island, the AOGCC requires the operator to remove the
wellhead equipment and casing to a depth of at least 5 feet below the
mudline. For offshore operations on an artificial island or shifting
natural island, AOGCC regulations require the operator to remove the
oil equipment and other associated infrastructure from the location,
fill and grade all pits, and leave the location in a clean and graded
condition.
[15] A well pad is a gravel platform built over the tundra with a
collection of oil wells. Typically associated with producing wells,
early exploratory wells also used gravel platforms.
[16] Two other lease forms, with substantially similar termination
provisions, were used prior to the most current lease form, which was
introduced in 2000.
[17] State Only Royalty Owner Unit Agreement revised April 2001.
[18] Section 404 of the Clean Water Act of 1972; section 10 of Rivers
and Harbors Act of 1899; section 103 of the Marine Protection, Research
and Sanctuaries Act of 1972.
[19] According to the Corps, the current restoration language has been
in effect since 1986; before 1986, Corps permits contained a general
condition stating that a permittee must restore the area to the
satisfaction of the district engineer.
[20] Since 1979, the Corps has issued over 1,100 general and specific
permits for the North Slope and denied 3. According to the Corps, about
half of the gravel that has been used in the North Slope was put in
place prior to 1979, not under Corps permits. In 1979, the Corps‘
Alaska District asserted its regulatory authority to include wet and
moist tundra in Alaska.
[21] Under the 1971 Alaska Native Claims Settlement Act, Congress
granted the Indians, Eskimos, and Aleuts of Alaska title to over 40
million acres of land and nearly $1 billion to settle their claims to
land in Alaska. The ANCSA set up a two-tiered corporate structure and
shareholding to administer settlement benefits. Village corporations
such as the Kuukpik Corporation control the surface estate in land,
while regional corporations such as the Arctic Slope Regional
Corporation control the financial benefits and other lands, both
surface and subsurface.
[22] FASB requires companies using the successful efforts accounting
method to capitalize those costs directly related to producing
properties (Statement of Financial Accounting Standard 19, Dec. 1977).
The Securities and Exchange Commission requires companies using the
full cost accounting method to capitalize all costs incurred in
exploration and development (SEC Regulation S-X, 17 CFR 210.4-10).
[23] For oil companies on the North Slope, this is accomplished through
unit of production amortization. Generally, this means that an oil
company estimates its total future DR&R liability and divides that by
estimated reserves, which yields a per barrel accrual.
[24] Contamination costs include costs resulting from oil spills,
leaking underground tanks, pollution control equipment, site
decontamination, environmental studies, and costs of fines.
[25] Financial Accounting Standards Board, ’Accounting for Asset
Retirement Obligations,“ Statement 143, June 2001.
[26] We contacted three companies that operate North Slope units”BP,
ExxonMobil, and Phillips Petroleum”and two companies that are large
nonoperating interest holders”Anadarko and Chevron.
[27] Based on a time series analysis by Dr. Scott Goldsmith of the
University of Alaska-Anchorage for the TAPS Renewal Environmental
Report. The 2004 revaluation is based on Anchorage Consumer Price Index
for Wage Earners (CPI-W) and is assumed to be the earliest that DR&R
could commence on the North Slope.
[28] State of Alaska Legislature Budget and Audit Committee, Audit
Control Number 08-4393-91, March 11, 1991.
[29] The AOGCC may require bonding levels greater than the minimum
levels of $100,000 for a single well and $200,000 for a statewide bond.
However, an AOGCC official stated that the amount and criteria to
increase these bonding levels are not specified by regulation or by
statute, and AOGCC officials told us that they have not required a
higher amount on the North Slope.
[30] These financial assurances include a $3 million bond to remove the
immediate risk to the state of raising the cash to maintain and operate
the offshore platforms should the lessee declare bankruptcy and a $31
million escrow fund to pay for the actual cost of abandoning the
facilities. Since the existence of proved oil and gas reserves serves
as collateral for the lessee, XTO Energy would not have to start paying
into the escrow account until the value of the proven reserves drops to
a level insufficient to act as collateral for the cost of platform
abandonment.
[31] The Naval Petroleum Reserves Production Act of 1976 gave the
Secretary of the Interior the authority to conduct oil and gas leasing
in the NPR-A. In 1980, the Congress directed the Secretary to undertake
an expeditious program of competitive leasing of oil and gas in the NPR-
A. The most current oil exploration activity is taking place as a
result of BLM‘s 1998 IAP/EIS and Record of Decision. The IAP/EIS
describes the future multiple-use management of 4.6 million acres of
the NPR-A and made about 87 percent of the area available for oil and
gas leasing.
[32] The U.S. Geological Survey also estimates that the entire 1002
area, including Native lands and state offshore lands, contains between
5.7 billion and 16 billion barrels of technically recoverable oil.
[33] While the Northstar facilities are located within the 3-mile state
limit, the field extends across the state/federal boundary. As such,
the field is managed under a joint federal/state unit that includes
both state and federal leases.
[34] If the Congress opens the Arctic Refuge to oil and gas
development, Title 11 of ANILCA also requires the Secretary of the
Interior to grant access rights to Alaska Native inholdings that may be
developed. Such inholdings are located throughout the refuge‘s coastal
plain.
[35] As of February 2002, four bills had been introduced in the 107th
Congress that would open the Arctic National Wildlife Refuge‘s coastal
plain to oil and gas development”H.R. 4, H.R. 39, H.R. 2436, and S.
388. In addition, in April 2002, the Senate considered and rejected an
amendment (S.A. 3132) to the Senate energy bill (S. 517) to open the
Arctic Refuge to oil and gas development. The House and Senate energy
bills will be reconciled in conference committee.
[36] Congressional Research Service, Legal Issues Related to Proposed
Drilling for Oil and Gas in the Arctic National Wildlife Refuge, CRS
Report RL31115 (Washington, D.C.: Nov. 23, 2001).
[37] BLM also requires a bond for geophysical exploration such as
seismic surveys in the National Petroleum Reserve-Alaska. BLM requires
an exploration bond of at least $5,000 for the NPR-A, or a $25,000
statewide exploration bond, or a $50,000 nationwide exploration bond.
[38] FWS also requires special-use permits for commercial activities,
such as seismic surveys, on national wildlife refuges. As part of the
special-use permits, FWS requires a certificate of insurance or the
posting of a bond.
[39] The additional bond for exploration activities is not required if
the lessee maintains an area-wide bond for $1 million. Similarly, an
additional bond for development and production activities is not
required if the lessee maintains a $3 million area-wide bond.
[40] The U.S. Geological Survey wells were drilled under a contract
with Husky Oil Company. Five other wells were drilled in NPR-A, two by
the U.S. Air Force, and three by the North Slope Borough. All five of
these wells are now under the borough‘s jurisdiction.
[41] During early oil and gas exploration in the NPR-A, one of the
discoveries was the Barrow Gas Field, which contained 24 wells.
Ownership of these wells was transferred to the North Slope Borough and
they currently provide gas to the people of Barrow.
[42] Stipulations for the Right of Way Lease for the Trans-Alaska
Pipeline, Section 1.10, May 3, 1974. The current lease is up for
renewal before May 2004.
[43] ExxonMobil Corporation v. Commissioner of Internal Revenue, United
States Tax Court, 114 T.C. 293, May 3, 2000.
[44] The consortium of companies that own TAPS today includes BP
Pipelines (Alaska) Inc., 50.01%; ExxonMobil Pipeline Company, 20.34%;
Amerada Hess Corporation, 1.5%; Phillips Transportation Alaska, Inc.,
23.7%; Unocal Pipeline Company, 1.36%; and Williams Alaska Pipeline
Company, L.L.C., 3.08%.
[45] A millerem, or 1/1000 of a rem, is a measure of radiation
absorption. A rem is a unit of dose equivalent from ionizing radiation
to the total body or any internal organ or organ system.
[46] Generally, DR&R under an oil and gas lease is a contractual term
that addresses the removal of material, equipment and structures
related to oil and gas development after oil and gas operations cease.
It also covers the restoration of the leased land to its original
condition or a condition that is otherwise acceptable to the lessor.
Environmental cleanup, on the other hand, generally refers to
requirements imposed by law to protect health and safety. Lessees must
comply with all applicable environmental laws, regardless of the DR&R
obligations, or the lack of such obligations, under their leases. On
the other hand, the fact a lessee has cleaned up a lease in compliance
with applicable environmental laws does not mean that it has satisfied
its DR&R obligations to the lessor, even where the lessor is the
government. Consequently, the State recommends that the draft report
delete references to "cleanup' activities when it means to address DR&R
requirements.
[47] Several of our comments, however, do not fit neatly into the
discussion of the GAO's recommendations, since they concern statements
by the GAO that have no logical relationship either to those
recommendations or to the alleged purpose for instituting the
investigation in the first instance. For example, the draft report
repeatedly employs anti-development rhetoric, such as the reference at
page 23 to the Prudhoe Bay area as a "web of industrial complexes
spread across 1500 square miles of state and native lands." Putting
aside the GAO's use of the factually meaningless term "web," the entire
Prudhoe Bay Unit-which includes not just Prudhoe Bay, but also the
facilities and infrastructure for the North Prudhoe, West Beach,
Lisburne, Niakuk, Pt. McIntyre, Midnight Sun, and Aurora Participating
Areas-is less than one-third the size quoted. There are, moreover, no
Native Corporation lands in the Unit. The statement preceding this
quote, that exploration has yielded a "network of... roads [that]...has
expanded from the border of the National Petroleum Reserve-Alaska (NPR-
A) to almost the border of the Arctic National Wildlife Refuge," is
also untrue. Fifty or so miles west of Pump Station 1, the Colville
River Unit borders NPR-A, but there are no roads that reach it-unless
you count the ice roads that are used in winter and melt in summer. To
the east, the closest producing unit to ANWR is the Badami Unit, but
it, too, has no roads that reach it. And, from the eastern edge of
Badami, you still have another 20 miles to go before you reach ANWR.
[See comment 2]
Because it is not drawn to scale, the map the GAO offers to show the
extent of North Slope development (draft report at 24) creates another
false impression of that development. When we raised this point
previously with GAO staff, we were told that they could not draw the
roads, pipelines and other North Slope facilities to scale because, it
they did, it would be impossible to see those facilities. That is a
fair point, but it does not explain why the GAO fails to acknowledge
that the map exaggerates the scope of North Slope development. It also
begs the question why the GAO chose to describe the nature of the North
Slope's development the way it did-an impenetrable "web"-as opposed to
something like "a level of development so sparse that a map in this
report drawn to scale would not even show it." Perhaps the report could
be more forthcoming by noting that the map is not to scale, with an
explanation that it is presented solely to show the relative locations
of facilities, and not their size or extent.
The State also questions the purpose of including in the draft report
an incomplete discussion of the State's fiscal regime, the creation of
the State's Permanent Fund, estimates of how much money has been made
by various entities from oil development on State lands, and the like.
It is difficult to fathom, for example, how the existence of a State
sales tax, or lack thereof, is relevant to a federal policymaker's
decision on the appropriate level of DR&R on federal lands. These
portions of the report are unnecessary, and only partially accurate,
and should be deleted.
[48] The GAO cites these examples deep in its draft report, but fails
to acknowledge their significance. In addition, the reference to a $1.8
million bond is incorrect. The correct amount is $3.8 million. Draft
report at 62.
[End of section]
GAO‘s Mission:
The General Accounting Office, the investigative arm of Congress,
exists to support Congress in meeting its constitutional
responsibilities and to help improve the performance and accountability
of the federal government for the American people. GAO examines the use
of public funds; evaluates federal programs and policies; and provides
analyses, recommendations, and other assistance to help Congress make
informed oversight, policy, and funding decisions. GAO‘s commitment to
good government is reflected in its core values of accountability,
integrity, and reliability.
Obtaining Copies of GAO Reports and Testimony:
The fastest and easiest way to obtain copies of GAO documents at no
cost is through the Internet. GAO‘s Web site [hyperlink,
http://www.gao.gov] contains abstracts and full text files of current
reports and testimony and an expanding archive of older products. The
Web site features a search engine to help you locate documents using
key words and phrases. You can print these documents in their entirety,
including charts and other graphics.
Each day, GAO issues a list of newly released reports, testimony, and
correspondence. GAO posts this list, known as ’Today‘s Reports,“ on its
Web site daily. The list contains links to the full-text document
files. To have GAO e-mail this list to you every afternoon, go to
[hyperlink, http://www.gao.gov] and select ’Subscribe to daily E-mail
alert for newly released products“ under the GAO Reports heading.
Order by Mail or Phone:
The first copy of each printed report is free. Additional copies are $2
each. A check or money order should be made out to the Superintendent
of Documents. GAO also accepts VISA and Mastercard. Orders for 100 or
more copies mailed to a single address are discounted 25 percent.
Orders should be sent to:
U.S. General Accounting Office:
441 G Street NW, Room LM:
Washington, D.C. 20548:
To order by Phone:
Voice: (202) 512-6000:
TDD: (202) 512-2537:
Fax: (202) 512-6061:
To Report Fraud, Waste, and Abuse in Federal Programs Contact:
Web site: [hyperlink, http://www.gao.gov/fraudnet/fraudnet.htm]:
E-mail: fraudnet@gao.gov:
Automated answering system: (800) 424-5454 or (202) 512-7470:
Public Affairs:
Jeff Nelligan, managing director, NelliganJ@gao.gov:
(202) 512-4800:
U.S. General Accounting Office:
441 G Street NW, Room 7149:
Washington, D.C. 20548:
