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 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 fig. 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. 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 fig. 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. 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. 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. 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. 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. 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. 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. 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. 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. 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. 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. 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. 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. 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. 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. 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. 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. 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. 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. 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). 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. 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. 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. 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. 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 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 fig. 9). 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.” 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….” 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. 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. 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. 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.” 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. 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. 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. 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. 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 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 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 fig. 10). 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. 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. 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 app. I for additional information on DR&R requirements in the states we surveyed.) 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. 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; alternative uses for facilities or gravel, such as for natural gas changes in environmental regulations or abandonment stipulations. 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 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. 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. 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. 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. 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. 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. 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. 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. 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. 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. 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. 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. 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. However, these officials noted that companies are now required to plug and abandon wells that are no longer being used on an ongoing basis. 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. 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 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. 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. 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. 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. 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. 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. 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. 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 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. Consistent with its regulations, MMS will require detailed plans for the plugging and abandonment of wells on federal leases. 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. 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 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. 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. 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.” 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. 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. 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. 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. 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. 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. 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. 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 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. 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….” 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 leases relating to oil company obligations… language in the TAPS right of way…is more specific.” 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. 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. 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. 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. 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. 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. 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. 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. 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.

Summary: 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. 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.